-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Ctu3NImeBxDyJg3LItuwp67oU3tAm6FBZrE9WrDiKnN0gfLEiqP3xQQ/idovF3Le vV4KsQZW9MmD2EYSjW4lNQ== 0001015402-05-002279.txt : 20050506 0001015402-05-002279.hdr.sgml : 20050506 20050506155103 ACCESSION NUMBER: 0001015402-05-002279 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20050331 FILED AS OF DATE: 20050506 DATE AS OF CHANGE: 20050506 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BRIGHAM EXPLORATION CO CENTRAL INDEX KEY: 0001034755 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 752692967 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 000-22433 FILM NUMBER: 05807942 BUSINESS ADDRESS: STREET 1: 6300 BRIDGE POINT PARKWAY STREET 2: BLDG 2 SUITE 500 CITY: AUSTIN STATE: TX ZIP: 78730 BUSINESS PHONE: 5124273300 MAIL ADDRESS: STREET 1: 6300 BRIDGE POINT PARKWAY STREET 2: BLDG 2 SUITE 500 CITY: AUSTIN STATE: TX ZIP: 78730 10-Q 1 body.txt BRIGHAM EXPLORATION COMPANY 10-Q 3-31-2005 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (D) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 2005 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 of (Primary Standard Industrial (I.R.S. Employer 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 May 3, 2005 42,489,396 ================================================================================
BRIGHAM EXPLORATION COMPANY FIRST QUARTER 2005 FORM 10-Q REPORT TABLE OF CONTENTS ----------------- PAGE ---- PART I - FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS Consolidated Balance Sheets - March 31, 2005 and December 31, 2004 . . . . . . . . . . . . . . 1 Consolidated Statements of Operations - Three months ended March 31, 2005 and 2004 . . . . . . 2 Consolidated Statement of Changes in Stockholders' Equity - Three months ended March 31, 2005. 3 Consolidated Statements of Cash Flows - Three months ended March 31, 2005 and 2004 . . . . . . 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 . . . . . . . . . . . . . . . . . . 27 ITEM 4. CONTROLS AND PROCEDURES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 PART II - OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS. . . . . . . . . . . . . . . . . . 29 ITEM 3. DEFALTS UPON SENIOR SECURITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. . . . . . . . . . . . . . . . . . . . . . 29 ITEM 5. OTHER INFORMATION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 ITEM 6. EXHIBITS AND REPORTS OF FORM 8-K . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
PART I- FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS
BRIGHAM EXPLORATION COMPANY CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA) (UNAUDITED) MARCH 31, DECEMBER 31, 2005 2004 -------------- -------------- ASSETS Current assets: Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4,641 $ 2,281 Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16,761 17,573 Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 449 239 Other current assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 673 901 -------------- -------------- Total current assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22,524 20,994 -------------- -------------- Oil and natural gas properties, net (full cost method). . . . . . . . . . . . . . . . . . . . . . 279,424 261,979 Other property and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,171 1,209 Deferred loan fees. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,020 1,745 Other noncurrent assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 700 380 -------------- -------------- Total assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 305,839 $ 286,307 ============== ============== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 17,849 $ 22,465 Royalties payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,442 6,072 Accrued drilling costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,152 6,099 Participant advances received . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,684 3,633 Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,389 2,225 -------------- -------------- Total current liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37,516 40,494 -------------- -------------- Senior credit facility. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38,100 21,000 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, 485,379 and 475,986 shares issued and outstanding at March 31, 2005 December 31, 2004, respectively. . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,708 9,520 Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,772 9,031 Other noncurrent liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,040 2,986 Commitments and contingencies (Note 4) Stockholders' equity: Common stock, $.01 par value, 50 million shares authorized, 43,373,199 and 43,231,499 shares issued and 42,154,822 and 42,034,351 shares outstanding at March 31, 2005 and December 31, 2004, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 434 432 Additional paid-in capital. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 176,266 175,270 Treasury stock, at cost; 1,218,377 and 1,197,148 shares at March 31, 2005 and December 31, 2004, respectively. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,897) (4,707) Unearned stock compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,003) (1,570) Accumulated other comprehensive income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . (499) (503) Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17,402 14,354 -------------- -------------- Total stockholders' equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 186,703 183,276 -------------- -------------- Total liabilities and stockholders' equity . . . . . . . . . . . . . . . . . . . . . . . . $ 305,839 $ 286,307 ============== ==============
The accompanying notes are an integral part of these consolidated financial statements. 1
BRIGHAM EXPLORATION COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER SHARE DATA) (UNAUDITED) THREE MONTHS ENDED MARCH 31, -------------------------- 2005 2004 ------------ ------------ RESTATED Revenues: Oil and natural gas sales. . . . . . . . . . . . . . . $ 16,703 $ 16,819 Other revenue. . . . . . . . . . . . . . . . . . . . . 43 1 ------------ ------------ 16,746 16,820 ------------ ------------ Costs and expenses: Lease operating. . . . . . . . . . . . . . . . . . . . 2,218 1,409 Production taxes . . . . . . . . . . . . . . . . . . . 802 863 General and administrative . . . . . . . . . . . . . . 1,098 1,220 Depletion of oil and natural gas properties. . . . . . 6,453 5,124 Depreciation and amortization. . . . . . . . . . . . . 182 181 Accretion of discount on asset retirement obligations. 39 37 ------------ ------------ 10,792 8,834 ------------ ------------ Operating income . . . . . . . . . . . . . . . . 5,954 7,986 ------------ ------------ Other income (expense): Interest income. . . . . . . . . . . . . . . . . . . . 39 14 Interest expense, net. . . . . . . . . . . . . . . . . (741) (782) Other income (expense) . . . . . . . . . . . . . . . . (531) 127 ------------ ------------ (1,233) (641) ------------ ------------ Income before income taxes . . . . . . . . . . . . . . . 4,721 7,345 ------------ ------------ Income tax expense: Current. . . . . . . . . . . . . . . . . . . . . . . . - - Deferred . . . . . . . . . . . . . . . . . . . . . . . (1,673) (2,420) ------------ ------------ (1,673) (2,420) ------------ ------------ Net income . . . . . . . . . . . . . . . . . . . . . . . $ 3,048 $ 4,925 ============ ============ Net income per share available to common stockholders: Basic. . . . . . . . . . . . . . . . . . . . . . . . . $ 0.07 $ 0.13 ============ ============ Diluted. . . . . . . . . . . . . . . . . . . . . . . . $ 0.07 $ 0.12 ============ ============ Weighted average shares outstanding: Basic. . . . . . . . . . . . . . . . . . . . . . . . . 42,124 39,166 ============ ============ Diluted. . . . . . . . . . . . . . . . . . . . . . . . 43,166 40,211 ============ ============
The accompanying notes are an integral part of these consolidated financial statements. 2
BRIGHAM EXPLORATION COMPANY CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (IN THOUSANDS) (UNAUDITED) ACCUMULATED COMMON STOCK ADDITIONAL UNEARNED OTHER --------------------------- PAID IN TREASURY STOCK COMPREHENSIVE SHARES AMOUNTS CAPITAL STOCK COMPENSATION INCOME (LOSS) ------------ ------------- -------------- -------------- -------------- --------------- Balance, December 31, 2004 43,231 $ 432 $ 175,270 $ (4,707) $ (1,570) $ (503) Comprehensive income: Net income - - - - - - Unrealized gain (losses) on cash flow hedges - - - - - (609) Tax benefits related to cash flow hedges - - - - - (3) Net losses included in net income - - - - - 616 Comprehensive income Exercises of employee stock options 77 1 250 - - - Vesting of restricted stock 65 1 (1) - - - Issuance of restricted stock - - 602 - (602) - Tax benefit from the exercise of stock options - - 145 - - - Repurchases of common stock - - - (190) - - Amortization of unearned stock compensation - - - - 169 - ------------ ------------- -------------- -------------- -------------- --------------- Balance, March 31, 2005 43,373 $ 434 $ 176,266 $ (4,897) $ (2,003) $ (499) ============ ============= ============== ============== ============== =============== TOTAL RETAINED STOCKHOLDERS' EARNINGS EQUITY ------------- --------------- Balance, December 31, 2004 $ 14,354 $ 183,276 Comprehensive income: Net income 3,048 3,048 Unrealized gain (losses) on cash flow hedges - (609) Tax benefits related to cash flow hedges - (3) Net losses included in net income - 616 --------------- Comprehensive income 3,052 Exercises of employee stock options - 251 Vesting of restricted stock - - Issuance of restricted stock - - Tax benefit from the exercise of stock options - 145 Repurchases of common stock - (190) Amortization of unearned stock compensation - 169 ------------- --------------- Balance, March 31, 2005 $ 17,402 $ 186,703 ============= ===============
The accompanying notes are an integral part of these consolidated financial statements. 3
BRIGHAM EXPLORATION COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS) (UNAUDITED) THREE MONTHS ENDED MARCH 31, -------------------------- 2005 2004 ------------ ------------ RESTATED(1) Cash flows from operating activities: Net income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 3,048 $ 4,925 Adjustments to reconcile net income to cash provided by operating activities: Depletion of oil and natural gas properties . . . . . . . . . . . . . . . . . . . . 6,453 5,124 Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . 182 181 Interest paid through issuance of additional mandatorily redeemable preferred stock 188 175 Amortization of deferred loan fees and debt issuance costs. . . . . . . . . . . . . 126 192 Market value adjustment for derivative instruments. . . . . . . . . . . . . . . . . 606 (127) Accretion of discount on asset retirement obligations . . . . . . . . . . . . . . . 39 37 Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,673 2,420 Other noncash items . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 - Changes in assets and liabilities: Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 812 (2,672) Other current assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85 2,704 Accounts payable. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,616) (2,570) Royalties payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,630) 843 Participant advances received . . . . . . . . . . . . . . . . . . . . . . . . . . (949) (557) Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . 226 (2,017) Other noncurrent assets and liabilities . . . . . . . . . . . . . . . . . . . . . (11) (64) ------------ ------------ Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . 6,244 8,594 ------------ ------------ Cash flows from investing activities: Additions to oil and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . (20,738) (17,135) Additions to other property and equipment . . . . . . . . . . . . . . . . . . . . . . . . (65) (129) (Increase) Decrease in drilling advances paid . . . . . . . . . . . . . . . . . . . . . . 159 207 ------------ ------------ Net cash used by investing activities . . . . . . . . . . . . . . . . . . . . . (20,644) (17,057) ------------ ------------ Cash flows from financing activities: Increase in senior credit facility. . . . . . . . . . . . . . . . . . . . . . . . . . . . 17,100 10,200 Deferred loan fees paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (401) (11) Proceeds from exercise of employee stock options. . . . . . . . . . . . . . . . . . . . . 251 310 Repurchases of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (190) (156) ------------ ------------ Net cash provided by financing activities . . . . . . . . . . . . . . . . . . . 16,760 10,343 ------------ ------------ Net increase in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . 2,360 1,880 Cash and cash equivalents, beginning of year. . . . . . . . . . . . . . . . . . . . . . . . 2,281 5,779 ------------ ------------ Cash and cash equivalents, end of period. . . . . . . . . . . . . . . . . . . . . . . . . . $ 4,641 $ 7,659 ============ ============
(1) Only individual line items in cash flows from operating activities have been restated. Total cash flows from operating, investing and financing activities were unaffected. 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 is a Delaware corporation formed on February 25, 1997 for the purpose of exchanging its common stock for the common stock of Brigham, Inc. and the partnership interests of Brigham Oil & Gas, L.P. (the "Partnership"). Hereinafter, Brigham Exploration Company and the Partnership are collectively referred to as "Brigham." Brigham, Inc. is a Nevada corporation whose only asset is its ownership interest in the Partnership. The Partnership was formed in May 1992 to explore and develop onshore domestic oil and natural gas properties using 3-D seismic imaging and other advanced technologies. Since its inception, the Partnership has focused its exploration and development of oil and natural gas properties primarily in the onshore Texas Gulf Coast, the Anadarko Basin and West Texas. 2. BASIS OF PRESENTATION The accompanying unaudited 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 unaudited consolidated financial statements are presented in accordance with the requirements of Form 10-Q and do not include all disclosures normally required by accounting principles generally accepted in the United States of America. 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 2004 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). 5 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) Had compensation cost for Brigham's stock options been determined based on the fair market value at the grant dates of the awards consistent with the methodology prescribed by SFAS 123 as amended by SFAS 148, Brigham's net income (loss) and net income (loss) per share for the three month periods ended March 31, 2005 and 2004 would have been the pro forma amounts indicated below:
THREE MONTHS ENDED MARCH 31, ----------------------------- 2005 2004 -------------- ------------- (In thousands, except per share amounts) Net income, as reported (as restated for 2004) . . . . . . . . . . $ 3,048 $ 4,925 Add back: Stock compensation expense previously included in net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111 121 Effect of total employee stock-based compensation expense, determined under fair value method for all awards. . . . . . . (361) (345) -------------- ------------- Pro forma. . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,798 $ 4,701 ============= ============= Net income per share: Basic, as reported . . . . . . . . . . . . . . . . . . . . . . . $ 0.07 $ 0.13 Basic, pro forma . . . . . . . . . . . . . . . . . . . . . . . . 0.07 0.12 Diluted, as reported. . . . . . . . . . . . . . . . . . . . . $ 0.07 $ 0.12 Diluted, pro forma. . . . . . . . . . . . . . . . . . . . . . 0.06 0.12
3. RESTATEMENT Brigham utilizes the full cost method of accounting for its proved oil and natural gas properties included in the consolidated financial statements. During March 2005, in conjunction with preparation of the financial statements for the year ended December 31, 2004, management evaluated the manner in which Brigham historically accounted for depletion expense associated with our oil and natural gas properties. Historically, Brigham had calculated a depletion rate at the end of each period within the year based on its updated reserve estimate. This depletion rate had then been retroactively applied to year-to-date production with the adjustment to previously recorded depletion expense recorded in the current quarter. Brigham determined that the revised depletion rate should have been applied on a prospective basis to production in the most current quarterly period only. As a result, depletion of oil and natural gas properties for the three months ending March 31, 2004, has been restated. The information in the quarterly financial statement information below represents only those consolidated statements of operations line items affected by the restatement (in thousands).
THREE MONTHS ENDED MARCH 31, 2004 ---------------------------- AS REPORTED RESTATED ------------- ------------- Consolidated Statements of Operations: Depletion of oil and natural gas properties. . . . . . . . . . $ 4,880 $ 5,124 Deferred income tax benefit (expense). . . . . . . . . . . . . (2,500) (2,420) Net income (loss) available to common stockholders . . . . . . 5,089 4,925 Net income (loss) per share available to common stockholders: Basic. . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.13 $ 0.13 ============= ============= Diluted. . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.13 $ 0.12 ============= =============
6 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) 4. 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. The Petition claimed Massey furnished defective casing to Brigham, which ultimately led to the casing failure of its 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. The amount of the settlement reduced capitalized well cost. In addition, Massey agreed to drop its $445,819 counterclaim. On October 8, 2002, relatives of a contractor's employee filed a wrongful death action against Brigham and three other contractors in the District Court of Matagorda County, Texas in connection with the employee's death on Brigham's Burkhart #1-R location. On March 23, 2004, a jury determined that Brigham had no liability in the accidental death of the contractor's employee. The trial judge, however, granted plaintiffs' motion for a new trial. Brigham expects the new trial to take place in June 2005. Brigham believes it has adequate insurance to cover any potential damage award (subject to a $5,000 deductible). At this point in time, Brigham cannot predict the outcome of this case. 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, claiming that contractor breached its contract with Brigham and negligently performed services on the well. Brigham believes the contractor's actions damaged Brigham by approximately $650,000. The contractor counterclaimed, claiming it is entitled to recover approximately $315,000. In April 2004, the parties settled the case, resulting in a payment by the contractor to its co-participants and Brigham of $325,000. In addition, the contractor dropped its counterclaim. Based on the amount of the settlement, the additional costs that were covered by insurance, and the insurer being subrogated to Brigham's claim, Brigham did not receive any incremental recovery as a result of the settlement. Prior to drilling, the operator of the Stonehocker #1 well disputed Brigham's ownership in the well. In March 2003, a Motion to Determine Election was filed with the Oklahoma Corporation Commission. In January 2004, an Administrative Law Judge with the Oklahoma Corporation Commission ruled in Brigham's favor. The operator of the Stonehocker #1 appealed the ruling and the Appellate Referee with the Oklahoma Corporation Commission affirmed the original ruling in March 2004. The full Commission Panel reviewed the reports of the Referee and the original Administrative Law Judge and affirmed those rulings. The operator then filed an appeal with the Oklahoma Supreme Court. In January 2005, the parties settled the dispute. The operator agreed to recognize Brigham's full interest in the Stonehocker well, and also agreed to reverse certain charges made under the operating agreements of six additional wells in which Brigham owns an interest. A company that relinquished its ownership interest in the Nold #1S well as a result of a non-consent election in the re-completion of the well asserted that it did not relinquish its entire interest, but rather became subject only to a 400 percent payout provision. In November 2003, this company filed a lawsuit in the District Court of Brazoria County, Texas, against Brigham for breach of contract. If the suit was successful, it could have resulted in a judgment of as much as $700,000. In April 2004, Brigham settled the case, agreeing to pay the company $350,000 in return for the company's assignment of all its right, title and interest in the unit for the 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 7 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) asserted a counterclaim against Brigham for alleged tortuous interference with an existing business relationship between the company and its employee. In April 2004, Brigham settled the case. The company agreed not to compete against Brigham in a specified area for two years, assigned Brigham a small overriding royalty in three tracts, paid Brigham $50,000, and dropped its counterclaim. As of March 31, 2005, there are no known environmental or other regulatory matters related to Brigham's operations that are reasonably expected to result in a material liability to Brigham. Compliance with environmental laws and regulations has not had, and is not expected to have, a material adverse effect on Brigham's financial position, results of operations or cash flows. 5. EARNINGS PER COMMON SHARE Basic earnings per share (EPS) is computed by dividing net income (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is computed by dividing net income by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include stock options and restricted stock. The number of potential common shares outstanding relating to stock options and restricted stock is computed using the treasury stock method. The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three months ended March 31, 2005 and 2004 are as follows (in thousands):
THREE MONTHS ENDED MARCH 31, ------------------------ 2005 2004 ----------- ----------- Weighted average common shares outstanding - basic. . . . . . . . . . . 42,124 39,166 Plus: Potential common shares Stock options and restricted stock. . . . . . . . . . . . . . . . . . 1,042 1,045 ----------- ----------- Weighted average common shares outstanding - diluted. . . . . . . . . . 43,166 40,211 =========== =========== Stock options excluded from diluted EPS due to the anti-dilutive effect 717,500 61,000 =========== ===========
6. 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. 8 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) Brigham reports average oil and natural gas prices and revenues including the net results of hedging activities. The following table sets forth Brigham's oil and natural gas prices including and excluding the hedging gains and losses and the increase or decrease in oil and natural gas revenues as a result of the hedging activities for the three month periods ended March 31, 2005 and 2004:
THREE MONTHS ENDED MARCH 31, ---------------------------- 2005 2004 ------------- ------------- NATURAL GAS Average price per Mcf as reported (including hedging results) $ 5.80 $ 5.69 Average price per Mcf realized (excluding hedging results). . $ 5.80 $ 5.79 Increase (decrease) in revenue (in thousands) . . . . . . . . $ (10) $ (216) OIL Average price per Bbl as reported (including hedging results) $ 43.74 $ 30.84 Average price per Bbl realized (excluding hedging results). . $ 48.33 $ 34.01 Increase (decrease) in revenue (in thousands) . . . . . . . . $ (541) $ (505)
Ineffectiveness associated with Brigham's derivative commodity instruments designated as cash flow hedges is included in other income (expense). The following table provides a summary of the impact on earnings from ineffectiveness (in thousands):
THREE MONTHS ENDED MARCH 31, --------------------------- 2005 2004 ------------- ------------ Increase (decrease) in earnings due to ineffectiveness $ (616) $ 127
NATURAL GAS AND CRUDE OIL DERIVATIVE CONTRACTS CASH-FLOW HEDGES Brigham's cash-flow hedges consisted of costless collars (purchased put options and written call options). The costless collars are used to establish floor and ceiling prices on anticipated future oil and natural gas production. There were no net premiums received when Brigham entered into these option agreements. Derivative positions included written put options that are not designated as hedges and are reflected at fair value on the balance sheet. These positions were entered into in conjunction with a costless collar to offset the cost of other option positions that are designated as hedges. At each balance sheet date, the value of derivatives not qualifying as hedging contracts is adjusted to reflect current fair value and any gains or losses are recognized as other income (expense). At March 31, 2005 and 2004, the fair value of these derivatives included in other current liabilities was approximately $23,000 and $0, respectively. For the three months ended March 31, 2005, and 2004, other income (expense) included approximately $10,000 and $0, respectively, in non-cash gains related to changes in the fair values of these derivative contracts. 9 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) The following table reflects open commodity derivative contracts at March 31, 2005, the associated volumes and the corresponding weighted average NYMEX reference price.
NOTIONAL AMOUNT --------------- NYMEX DERIVATIVE GAS OIL REFERENCE SETTLEMENT PERIOD INSTRUMENT HEDGE STRATEGY (MMBTU) (BARRELS) PRICE - -------------------------- -------------- -------------- --------------- --------------- --------------- COSTLESS COLLARS 04/01/05 - 06/30/05. . . Purchased put Cash flow 318,500 $ 5.00 Written call Cash flow 318.500 7.40 04/01/05 - 06/30/05. . . Purchased put Cash flow 11,830 $ 29.00 Written call Cash flow 11,830 36.00 04/01/05 - 06/30/05. . . Purchased put Cash flow 91,000 $ 4.00 Written call Cash flow 91,000 5.40 04/01/05 - 06/30/05. . . Purchased put Cash flow 45,500 $ 4.25 Written call Cash flow 45,500 4.52 04/01/05 - 06/30/05. . . Purchased put Cash flow 6,825 $ 23.00 Written call Cash flow 6,825 26.45 04/01/05 - 10/31/05. . . Purchased put Cash flow 420,000 $ 5.45 Written call Cash flow 420,000 8.00 THREE WAY COSTLESS COLLARS 07/01/05 - 10/31/05. . . Purchased put Cash flow 400,000 $ 6.00 Written call Cash flow 400,000 7.20 Written put Undesignated 400,000 5.00 07/01/05 - 12/31/05. . . Purchased put Cash flow 30,000 $ 40.00 Written call Cash flow 30,000 53.00 Written put Undesignated 30,000 30.00 11/01/05 - 03/31/06. . . Purchased put Cash flow 250,000 $ 6.75 Written call Cash flow 250,000 8.80 Written put Undesignated 250,000 5.50
The following table reflects commodity derivative contracts entered subsequent to March 31, 2005, the associated volumes and the corresponding weighted average NYMEX reference price.
NOTIONAL AMOUNT --------------- NYMEX DERIVATIVE GAS OIL REFERENCE SETTLEMENT PERIOD INSTRUMENT HEDGE STRATEGY (MMBTU) (BARRELS) PRICE - -------------------------- -------------- -------------- --------------- --------------- --------------- THREE WAY COSTLESS COLLARS 06/01/05 - 03/31/06. . . Purchased put Cash flow 60,000 $ 48.00 Written call Cash flow 60,000 60.70 Written put Undesignated 60,000 38.00 07/01/05 - 10/31/05. . . Purchased put Cash flow 240,000 $ 7.00 Written call Cash flow 240,000 7.76 Written put Undesignated 240,000 5.75 11/01/05 - 03/31/06. . . Purchased put Cash flow 350,000 $ 8.00 Written call Cash flow 350,000 9.75 Written put Undesignated 350,000 6.50
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 10 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) exchanged for the contract, the interest rate swap contract is entered into with a major financial institution in order to minimize Brigham's counterparty credit risk. The interest rate swap contract is designated as cash flow hedges against changes in the amount of future cash flows associated with Brigham's interest payments on variable-rate debt. The effect of this accounting on operating results is that interest expense on a portion of variable-rate debt being hedged is recorded based on fixed interest rates. At March 31, 2005, Brigham had an interest rate swap contract to pay a fixed-rate of interest of 7.61% on $20.0 million notional amount of senior subordinated notes. The $20.0 million notional amount of the outstanding contract matures in March 2009. As of March 31, 2005, approximately $481,000 of unrealized gains are included in accumulated other comprehensive income (loss) on the balance sheet which represents the fair value of the interest rate swap agreement as of that date. The fair value of the interest rate swap contract is based on quoted market prices and third-party provided calculations, which reflect the present values of the difference between estimated future variable-rate receipts and future fixed-rate payments. The fair value of hedging and interest rate swap contracts is reflected on the consolidated balance sheets as detailed in the following table. The current asset and liability amounts represent the fair values expected to be included in the results of operations for the subsequent year (in thousands).
MARCH 31, ------------------------ 2005 2004 ----------- ----------- Other current liabilities. . . . . . . . $ (1,808) $ (3,111) Other noncurrent liabilities . . . . . . - (374) Other noncurrent assets. . . . . . . . . 482 3 ----------- ----------- Net fair value of derivative contracts $ (1,326) $ (3,482) =========== ===========
7. ASSET RETIREMENT OBLIGATIONS Brigham has asset retirement obligations associated with the future plugging and abandonment of proved properties and related facilities. The fair value of a liability for an asset retirement obligation is recorded 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 no assets that are legally restricted for purposes of settling asset retirement obligations. The following table summarizes Brigham's asset retirement obligation transactions recorded in accordance with the provisions of SFAS 143 during the three months ended March 31, 2005 and 2004 (in thousands):
THREE MONTHS ENDED MARCH 31, --------------------------- 2005 2004 ------------ ------------- Beginning asset retirement obligations. . . . . . . . . $ 2,896 $ 2,320 Liabilities incurred for new wells placed on production 26 101 Liabilities settled . . . . . . . . . . . . . . . . . . - (36) Accretion of discount on asset retirement obligations . 39 37 ------------ ------------- $ 2,961 $ 2,422 ============ =============
11 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) 8. INCOME TAXES Realization of deferred tax assets associated with (i) net operating loss carryforwards ("NOLs") and (ii) existing temporary differences between book and taxable income is dependent upon generating sufficient taxable income within the carryforward period available under tax law. Management believes that it is more likely than not that capital loss carryforwards of approximately $1.8 million may expire unused and, accordingly, has established a valuation allowance of $0.6 million. The components of deferred income tax assets and liabilities are as follows (in thousands):
MARCH 31, DECEMBER 31, 2005 2004 ------------- -------------- Deferred tax assets Current: Unrealized hedging losses. . . . . . . . . . $ 268 $ 271 Derivative assets. . . . . . . . . . . . . . 196 11 ------------- -------------- Current . . . . . . . . . . . . . . . . . 464 282 ------------- -------------- Non-current: Net operating loss carryforwards . . . . . . 38,600 36,743 Capital loss carryforwards . . . . . . . . . 634 634 Stock compensation . . . . . . . . . . . . . 761 816 Asset retirement obligations . . . . . . . . 1,036 1,014 Other. . . . . . . . . . . . . . . . . . . . 31 31 ------------- -------------- Gross non-current . . . . . . . . . . . . 41,062 39,238 Valuation allowance . . . . . . . . . . . (634) (634) ------------- -------------- Non-current. . . . . . . . . . . . . . 40,428 38,604 ------------- -------------- Gross deferred tax assets . . . . . 40,892 38,886 ------------- -------------- Deferred tax liabilities Current: Derivative liabilities . . . . . . . . . . . - (28) Gas imbalances . . . . . . . . . . . . . . . (15) (15) ------------- -------------- Current . . . . . . . . . . . . . . . . . (15) (43) ------------- -------------- Non-current: Depreciable and depletable property. . . . . (51,163) (47,635) Other . . . . . . . . . . . . . . . . . . (37) - ------------- -------------- Non-current . . . . . . . . . . . . . . . (51,200) (47,635) ------------- -------------- Gross deferred tax liabilities . . . . (51,215) (47,678) ------------- -------------- Total deferred tax asset (liability). . . . . . . $ (10,323) $ (8,792) ============= ============== Reflected in the accompanying balance sheets as: Current deferred income tax asset . . . . . . . $ 449 $ 239 Non-current deferred income tax liability . . . (10,772) (9,031) ------------- -------------- $ (10,323) $ (8,792) ============= ==============
At March 31, 2005, Brigham has regular tax NOLs of approximately $110.3 million and has approximately $96.6 million of alternative minimum tax ("AMT") NOLs available as a deduction against future taxable income. The NOLs expire from 2012 through 2025. The value of these NOLs depends on the ability of Brigham to generate taxable income. In addition, at March 31, 2005, Brigham has capital loss carryforwards of approximately $1.8 million that expire in varying years through 2007. 12 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) Brigham believes an Internal Revenue Code Sec. 382 ownership change may have occurred in March 2001, as a result of a potential 50% change in ownership among its 5% shareholders over a three-year period. The minimum amount of the limitation approximates $5.2 million annually, which can be increased by recognized Built-in-Gains over five years following the ownership change. Management believes that the limitation will not have a material impact on the utilization of its NOL's. 9. ACCOUNTING PRONOUNCEMENTS In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123R, "Share-Based Payment" (SFAS 123R), which is a revision of SFAS 123 and supersedes APB Opinion No. 25. SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be valued at fair value on the date of grant, and to be expensed over the applicable vesting period. Pro forma disclosure of the income statement effects of share-based payments is no longer an alternative. In addition, companies must also recognize compensation expense related to any awards that are not fully vested as of the effective date. Compensation expense for the unvested awards will be measured based on the fair value of the awards previously calculated in developing the pro forma disclosures in accordance with the provisions of SFAS 123. The effective date of SFAS 123R is the first reporting period beginning after June 15, 2005, which is the third quarter 2005 for calendar year companies, although early adoption is allowed. However, on April 14, 2005, the Securities and Exchange Commission (SEC) announced that the effective date of SFAS 123R will be suspended until January 1, 2006, for calendar year companies. Brigham is currently assessing the impact of adopting SFAS 123R to its consolidated financial statements. In March 2005, the FASB issued FASB Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations" (FIN 47), which clarifies the impact that uncertainty surrounding the timing or method of settling an obligation should have on accounting for that obligation under SFAS No. 143. FIN 47 is effective no later than the end of the fiscal year ending after December 15, 2005, or December 31, 2005 for calendar year companies. Brigham does not expect the adoption of FIN 47 to have a material impact on its consolidated financial statements. In September 2004, the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin 106 (SAB 106) which provides guidance regarding the interaction of SFAS 143 with the calculation of depletion and the full cost ceiling test of oil and gas properties under the full cost accounting rules of the SEC. The adoption of SAB 106 did not have a material effect on Brigham's consolidated financial position, results of operations or cash flows. 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 2004 Annual Report on Form 10-K, and analyzes the changes in the results of operations between the three month period ended March 31, 2005, and the comparable period of 2004. For definitions of commonly used gas and oil terms as used in this Form 10-Q, please refer to the "Glossary of Oil and Gas Terms" provided in our 2004 Annual Report on Form 10-K. OVERVIEW OF FIRST QUARTER 2005 The price of natural gas during the first quarter 2005 remained relatively high to historical prices due to forecasts for continued production declines, increasing natural gas demand and similarly high crude oil prices, which limits fuel-switching flexibility. The average sales price that we received for our natural gas sales in the first quarter 2005 was $5.80 per Mcf. The price of oil also remained high relative to historical prices during the first quarter 2005. The average sales price that we received for oil in the first quarter of 2005 was $48.33. For the quarter ended March 31, 2005, we spent $23.9 million in net capital expenditures for oil and natural gas activities. Our production for the first quarter 2005 was 30 MMcfe/d compared to 33.9 MMcfe/d in the first quarter last year. The decrease in production is primarily due to natural decline of existing production and the lack of significant wells reaching total depth and coming on line during the quarter to materially contribute to production. Net income for the first quarter 2005 was $3 million, or $0.07 per diluted share, on total revenues of $16.7 million. This compares to reported net income of $4.9 million, or $0.12 per diluted share on revenue of $16.8 million in the first quarter last year. The decrease in net income was primarily due to a decrease in production combined with increases in our costs for production, depletion and a non-cash loss related to the ineffective portion of our cash flow hedges. Net cash provided by operating activities, after a $6.1 million reduction of changes in our working capital and other items, funded approximately 30% of our capital expenditures. We borrowed an additional $17.1 million under our senior credit facility to fund the increase in capital expenditures. At March 31, 2005, we had $4.6 million in cash, total assets of $305.8 million and a debt to capitalization ratio of 27%. 14 CAPITAL COMMITMENTS 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. Our capital expenditure program includes the following: - cost of acquiring and maintaining our lease acreage position and our seismic resources; - cost of drilling and completing new oil and natural gas wells; - cost of installing new production infrastructure; - cost of maintaining, repairing and enhancing existing oil and natural gas wells; - cost related to plugging and abandoning unproductive or uneconomic wells; and, - indirect costs related to our exploration activities, including payroll and other expenses attributable our exploration professional staff. The table below summarizes our budgeted capital expenditures, the amount spent through March 31, 2005 and the amount of our 2005 budget that remains to be spent.
AMOUNT SPENT THROUGH AMOUNT 2005 BUDGET 03/31/2005 REMAINING (1) -------------- -------------- -------------- (IN THOUSANDS) Drilling . . . . . . . . . . $ 70,308 $ 17,458 $ 52,850 Net land and seismic . . . . 13,065 4,815 8,250 Capitalized interest and G&A 6,184 1,601 4,583 Asset retirement obligation. - 26 - Other assets . . . . . . . . 615 65 550 -------------- -------------- -------------- Total. . . . . . . . . . . . $ 90,172 $ 23,965 $ 66,233 ============== ============== ==============
- ------------ (1) Calculated as the amount budgeted for 2005 less amount spent through March 31, 2005. The capital that funds our drilling activities is allocated to individual prospects based on the value potential of a prospect, as measured by a risked net present value analysis. We start each year with a budget and reevaluate this budget monthly. The primary factors that impact this value creation measure include forecasted commodity prices, drilling and completion costs, and a prospect's risked reserve size and risked initial producing rate. Other factors that are also monitored throughout the year that influence the amount and timing of all our budgeted expenditures include the level of production from our existing oil and natural gas properties, the availability of drilling and completion services, and the success and resulting production of our newly drilled wells. The outcome of our monthly analysis results in a reprioritization of our exploration and development well drilling schedule to ensure that we are optimizing our capital expenditure plan. For 2005, we currently plan to spend approximately $34.7 million, or 38% of our total budgeted capital expenditures to drill 17 exploratory wells and to drill and complete wells that were in progress at December 31, 2004. We believe that we possess a multi-year inventory of exploratory drilling prospects, the majority of which have been internally generated by our staff. As a consequence and considering the results that we have achieved in recent years, we expect that we will continue to emphasize our prospect generation and drilling strategy as our primary means of creating value for our stockholders. Due to our exploratory drilling success, over the last five years, a growing percentage of our capital expenditures have been allocated to the development of past field discoveries. For 2005, we currently plan to spend approximately $35.6 million, or 39% of our total budgeted capital expenditures on development activities, which include the drilling of 20 development wells. We currently plan to allocate approximately $26.5 million of this capital to develop our proved undeveloped reserves at December 31, 2004. For 2005, we expect to spend approximately $13.1 million or 14% of our total capital expenditures on land and seismic activities. 15 Additionally, we currently plan to capitalize approximately $6.2 million of our forecasted total general and administrative cost and forecasted interest in 2005. The final determination with respect to our 2005 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. Statements in this section include forward-looking statements. See "- Forward-Looking Statements." SENIOR CREDIT FACILITY As of March 31, 2005, we had $38.1 million in borrowings outstanding under our senior credit facility. During the first quarter of 2005 we borrowed an additional $17.1 million of additional debt under our senior credit facility. During the first quarter 2005, we utilized approximately 47% of our available borrowing base, compared to 38% in the first quarter last year. Borrowings outstanding under our senior credit facility at April 28, 2005, were $43.6 million. Pursuant to our senior credit agreement, we are required to maintain a current ratio of at least 1 to 1 and an interest coverage ratio for the four most recent quarters of at least 3 to 1. Our current ratio at March 31, 2005 and interest coverage ratio for the twelve-month period ending March 31, 2005, were 1.6 to 1 and 18.4 to 1, respectively. As of March 31, 2005, and for the twelve-month period then ended, we were in compliance with all covenant requirements in connection with our senior credit facility. SENIOR SUBORDINATED NOTES As of March 31, 2005, we had $20 million of senior subordinated notes outstanding. Pursuant to our subordinated note agreement, we are required to maintain a current ratio of at least 1 to 1, an interest coverage ratio for the four most recent quarters of at least 3 to 1 and a Total Calculated NPV to Total Debt Ratio of 1.5 to 1. Our current ratio at March 31, 2005, interest coverage ratio for the twelve-month period ending March 31, 2005, and Total Calculated NPV to Total Debt Ratio were 1.6 to 1, 18.4 to 1 and 3.4 to 1, respectively. At March 31, 2005, and for the twelve-month period then ended, we were in compliance with all covenant requirements in connection with our senior subordinated notes. MANDATORILY REDEEMABLE PREFERRED STOCK As of March 31, 2005, we had $9.7 million in mandatorily redeemable Series A preferred stock outstanding, which is held by merchant banking funds managed by affiliates of CSFB Private Equity. During the first quarter of 2005 we issued 9,393 shares of additional shares of preferred stock to satisfy our first quarter 2005 dividend requirements. Brigham's ability to pay the mandatorily redeemable Series A preferred stock dividends by issuing additional shares of preferred stock expires on October 31, 2005. CAPITAL RESOURCES We intend to fund our remaining 2005 capital expenditure program and contractual commitments through cash flows from operations, borrowings under our senior credit facility and, if required, alternative financing sources. Our primary sources of cash during the first quarter 2005 were net cash provided by operations and additional 16 borrowings under our senior credit facility. We made aggregate cash payments of $691,000 for interest in the first quarter of 2005. NET CASH PROVIDED BY OPERATING ACTIVITIES Net cash provided by operating activities is a function of the prices that we receive from the sale of oil and natural gas, which are inherently volatile and unpredictable, gains or losses related to the settlement of derivative contracts, production, operating cost and our cost of capital. Our asset base, as with other extractive industries, is a depleting one in which each Mcf of natural gas or barrel of oil produced must be replaced or our ability to generate cash flow, and thus sustain our exploration and development activities, will diminish. Net cash provided by operating activities during the first quarter 2005, after a $6.1 million reduction of changes in our working capital and other items, funded 30% of our net cash used by investing activities compared to 50% in the first quarter of 2004. SENIOR CREDIT FACILITY As of March 31, 2005, the unused committed borrowing capacity available under our senior credit facility was $30.4 million. During the first quarter of 2005, our borrowing base for our senior credit facility was redetermined. Effective May 2, 2005, our borrowing base increased from $68.5 million to $72 million. The future amounts of debt that we borrow under our senior credit facility is dependent primarily on net cash provided by operating activities, proceeds from other financing activities and proceeds generated from asset dispositions. We strive to manage the borrowings outstanding under our senior credit facility in order to maintain excess borrowing capacity. ACCESS TO CAPITAL MARKETS We currently have an effective universal shelf registration statement covering the sale, from time to time, of our common stock, preferred stock, depositary shares, warrants and debt securities, or a combination of any of these securities. In July 2004, we sold 2,598,500 shares of our common stock under the universal shelf registration statement. Following this sale, our remaining capacity under the shelf registration statement is approximately $176.9 million. However, our ability to raise additional capital using our shelf registration statement may be limited due to overall conditions of the stock market or the oil and natural gas industry. 17 RESULTS OF OPERATIONS Comparison of the three-month periods ended March 31, 2005 and 2004 PRODUCTION VOLUMES
THREE MONTHS ENDED MARCH 31, ----------------------------------------------- 2005 % CHANGE 2004 -------------- --------------- -------------- Oil (MBbls). . . . . . . . . . . . 118 (26%) 160 Natural gas (MMcf) . . . . . . . . 1,994 (5%) 2,093 Total (MMcfe)(1) . . . . . . . . . 2,700 (11%) 3,050 Average daily production (MMcfe/d) 30.0 33.9
- ------------ (1) Mcfe is defined one million cubic feet equivalent of natural gas, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. Our net equivalent production volumes for the first quarter of 2005 were 2.7 Bcfe (30 MMcfe/d) compared to 3.1 Bcfe (33.9 MMcfe/d) in the first quarter of 2004. The decrease in our production volumes was due to natural decline of existing production and the lack of significant wells reaching total depth and coming on line during the quarter to materially contribute to production. Natural gas represented 74% of our first quarter 2005 production volumes compared to 69% in the first quarter of last year. HEDGING RESULTS The following table shows the type of derivative commodity contracts, the volumes, the weighted average NYMEX reference price for those volumes, and the associated gain /(loss) upon settlement of those contracts for the periods indicated.
THREE MONTHS ENDED MARCH 31, --------------------------------------------------- 2005 % CHANGE 2004 ---------------- --------------- ---------------- OIL SWAPS Volumes (Bbls) . . . . . . . . . . . . . . . - (100%) 29,575 Average swap price ($per Bbl). . . . . . . . $ - (100%) $ 25.35 Gain /(loss) upon settlement ($in thousands) $ - (100%) $ (290) OIL COLLARS Volumes (Bbls) . . . . . . . . . . . . . . . 27,450 (40%) 45,500 Average floor price ($per Bbl) . . . . . . . $ 25.56 11% $ 23.00 Average ceiling price ($per Bbl) . . . . . . $ 30.18 (1%) $ 30.43 Gain /(loss) upon settlement ($in thousands) $ (541) 152% $ (215) TOTAL OIL Volumes (Bbls) . . . . . . . . . . . . . . . 27,450 (63%) 75,075 Gain /(loss) upon settlement ($in thousands) $ (541) 7% $ (505) NATURAL GAS SWAPS Volumes (MMbtu). . . . . . . . . . . . . . . - (100%) 295,750 Average swap price ($per MMbtu). . . . . . . $ - (100%) $ 4.96 Gain /(loss) upon settlement ($in thousands) $ - (100%) $ (216) NATURAL GAS COLLARS Volumes (MMbtu). . . . . . . . . . . . . . . 727,500 33% 546,000 Average floor price ($per MMbtu) . . . . . . $ 5.16 25% $ 4.13 Average ceiling price ($per MMbtu) . . . . . $ 7.26 (14%) $ 8.43 Gain /(loss) upon settlement ($in thousands) $ (10) NM $ - TOTAL NATURAL GAS Volumes (MMbtu). . . . . . . . . . . . . . . 727,500 (14%) 841,750 Gain /(loss) upon settlement ($in thousands) $ (10) (95%) $ (216)
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 cash flow hedge accounting treatment under SFAS 133. 18 We utilize commodity swap, collar, three way costless 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. The effective portions of changes in the fair values of our derivative commodity contracts that qualify for cash flow 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 these derivative contracts add volatility to our reported stockholders' equity until the contract is settled or is terminated. Gains or losses related to the settlement and the changes in the fair values of our derivative commodity contracts that do not qualify for cash flow hedge accounting treatment under SFAS 133 are recognized in other income (expense). COMMODITY PRICES AND REVENUES The following table shows our revenue from the sale of oil and natural gas for the periods indicated.
THREE MONTHS ENDED MARCH 31, --------------------------------------------------- 2005 % CHANGE 2004 ---------------- --------------- ---------------- (IN THOUSANDS, EXCEPT PER UNIT MEASUREMENTS) REVENUE FROM THE SALE OF OIL AND NATURAL GAS: Oil sales. . . . . . . . . . . . . . . . . . . . . . $ 5,689 5% $ 5,427 Gain (loss) due to hedging . . . . . . . . . . . . . (541) 7% (505) ---------------- ---------------- Total revenue from the sale of oil . . . . . . . . $ 5,148 5% $ 4,922 Natural gas sales. . . . . . . . . . . . . . . . . . $ 11,565 (5%) $ 12,113 Gain (loss) due to hedging . . . . . . . . . . . . . (10) (95%) (216) ---------------- ---------------- Total revenue from the sale of natural gas . . . . $ 11,555 (3%) $ 11,897 Oil and natural gas sales. . . . . . . . . . . . . . $ 17,254 (2%) $ 17,540 Gain (loss) due to hedging . . . . . . . . . . . . . (551) (24%) (721) ---------------- ---------------- Total revenue from the sale of oil and natural gas $ 16,703 (1%) $ 16,819 AVERAGE PRICES: Oil sales price (per Bbl). . . . . . . . . . . . . . $ 48.33 42% $ 34.01 Gain (loss) due to hedging (per Bbl) . . . . . . . . (4.59) 45% (3.17) ---------------- ---------------- Realized oil price (per Bbl) . . . . . . . . . . . $ 43.74 42% $ 30.84 Natural gas sales price (per Mcf). . . . . . . . . . $ 5.80 0% $ 5.79 Gain (loss) due to hedging (per Mcf) . . . . . . . . (0.00) (100%) (0.10) ---------------- ---------------- Realized natural gas price (per Mcf) . . . . . . . $ 5.80 2% $ 5.69 Natural gas equivalent sales price (per Mcfe). . . . $ 6.39 11% $ 5.75 Gain (loss) due to hedging (per Mcfe). . . . . . . . (0.20) (17%) (0.24) ---------------- ---------------- Realized natural gas equivalent (per Mcfe) . . . . $ 6.19 12% $ 5.51 ================ ================
2005 TO 2004 --------- CHANGE IN REVENUE FROM THE SALE OF OIL Price variance impact. . . . . . . . . . . . . $ 1,686 Volume variance impact . . . . . . . . . . . . (1,424) Cash settlement of hedging contracts . . . . . (36) --------- Total change . . . . . . . . . . . . . . . . $ 226 ========= CHANGE IN REVENUE FROM THE SALE OF NATURAL GAS Price variance impact. . . . . . . . . . . . . $ 20 Volume variance impact . . . . . . . . . . . . (568) Cash settlement of hedging contracts . . . . . 206 --------- Total change . . . . . . . . . . . . . . . . $ (342) =========
Our revenues from the sale of oil and natural gas for the first quarter of 2005 decreased by 1% when compared to revenues in first quarter of 2004. The change in revenues was due to the following: 19 - An decrease in production volumes for the quarter resulted in a $2 million decrease in revenues from the sale of oil and natural gas; - A 42% increase in the sales price we received from the sale oil and a slight increase in sales price we received from the sale of natural gas partially offset the decrease due to lower production by $1.7 million; and, - A 24% decrease in losses from the cash settlement of derivative commodity contracts also partially offset the decrease in revenue due to a decrease in production. Other revenue. Other revenue relates to fees that we charge other parties who use our gas gathering systems that we own to move their production from the wellhead to third party gas pipeline systems. Other revenue for the first quarter of 2005 was $43,000 compared to $1,000 in the first quarter last year. Costs related to our gas gathering systems are recorded in lease operating expenses. OPERATING COSTS AND EXPENSES Production costs. Production costs include lease operating expenses and production taxes.
THREE MONTHS ENDED MARCH 31, ------------------------------------------------- 2005 % CHANGE 2004 --------------- --------------- --------------- (IN THOUSANDS, EXCEPT PER UNIT MEASUREMENTS) PRODUCTION COST: Operating & maintenance. . . . . $ 1,422 39% $ 1,026 Expensed workovers . . . . . . . 524 137% 221 Ad valorem taxes . . . . . . . . 272 68% 162 --------------- --------------- Total lease operating expenses $ 2,218 57% $ 1,409 Production taxes . . . . . . . . 802 (7%) 863 --------------- --------------- Total production expenses. . . $ 3,020 33% $ 2,272 =============== =============== PRODUCTION COST ($PER MCFE): Operating & maintenance. . . . . $ 0.53 56% $ 0.34 Expensed workovers . . . . . . . 0.19 171% 0.07 Ad valorem taxes . . . . . . . . 0.10 100% 0.05 --------------- --------------- Total lease operating expenses $ 0.82 78% $ 0.46 Production taxes . . . . . . . . 0.30 7% 0.28 --------------- --------------- Total production expenses. . . $ 1.12 51% $ 0.74 =============== ===============
Our first quarter 2005 production costs increased by 33% when compared to production costs in the first quarter of 2004. The change in our production cost was due to the following: - An increase in the number of wells we have producing. In the future we anticipate that our total production cost will increase as we add new wells and production facilities and continue to maintain production from existing maturing properties; - An increase in expensed workover cost; - An increase in cost for compressor rental and maintenance, salt water disposal, contract labor and measurement services, treating and miscellaneous operating and maintenance were the primary reasons for the increase in operating and maintenance expenses; - An increase in ad valorem taxes due to higher oil and natural gas prices during 2004; and, - A decrease in production taxes due to a decrease in production volumes that was partially offset by increases in commodity prices. 20 We believe that per unit of production measures are the best way to evaluate our production cost information. We use this information to evaluate our performance relative to our peers and to internally evaluate our performance. For the first quarter of 2005, our unit production cost increased 51% when compared to 2004. The change in our unit production cost was due to the following: - A decline in first quarter 2005 production; - An increase in cost for compressor rental and maintenance, salt water disposal, contract labor and measurement services, treating and miscellaneous operating and maintenance were the primary reason for the increase in operating and maintenance expenses; - An increase in expensed workover cost; and, - Ad valorem taxes increased due to higher oil and natural gas prices during 2004. General and administrative expenses. We capitalize a portion of our general and administrative costs. The costs capitalized represent the cost of technical employees, who work directly on capital projects. An engineer designing a well is an example of a technical employee working on a capital project. The cost of a technical employee includes associated technical organization costs such as supervision, telephone and postage.
THREE MONTHS ENDED MARCH 31, --------------------------------------------------- 2005 % CHANGE 2004 ---------------- --------------- ---------------- (IN THOUSANDS, EXCEPT PER UNIT MEASUREMENTS) General and administrative cost. . . . . . . . $ 2,303 (7%) $ 2,464 Capitalized general and administrative cost. . (1,205) (3%) (1,244) ---------------- ---------------- General and administrative expense . . . . . . $ 1,098 (10%) $ 1,220 ================ ================ General and administrative expense ($per Mcfe) $ 0.41 3% $ 0.40
For the first quarter of 2005, our general and administrative expenses decreased by 10%. The changes in our general and administrative expenses were due to the following: - A decrease in costs for employee payroll and payroll taxes, rent, travel and entertainment and financial reporting; and, - These decreases were partially offset by increases in costs for employee training and continuing education, corporate insurance and director fees and expenses. 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. Our 2004 information pertaining to depletion and accumulated depletion that are part of our net proved oil and natural gas properties has been restated. See "Item 1. Financial Statements-Note 3" for further discussion.
THREE MONTHS ENDED MARCH 31, ------------------------------------------------- 2005 % CHANGE 2004 --------------- --------------- --------------- (RESTATED) (IN THOUSANDS, EXCEPT PER UNIT MEASUREMENTS) Depletion of oil and natural gas properties. . . . . $ 6,453 26% $ 5,124 Depletion of oil and natural gas properties per Mcfe $ 2.39 42% $ 1.68
An increase in our depletion rate resulted in a $1.9 million increase in depletion expense in the first quarter of 2005. This increase was partially offset by a $588,000 decrease to depletion expense due to a decrease in production volumes. 21 Net interest expense. We capitalize interest expense on borrowings associated with major capital projects prior to their completion. Capitalized interest is added to the cost of the underlying assets and is amortized over the lives of the assets.
THREE MONTHS ENDED MARCH 31, --------------------------------------------------- 2005 % CHANGE 2004 ---------------- --------------- ---------------- (IN THOUSANDS) Interest on senior credit facility. . . . . . . . . . $ 323 75% $ 185 Interest on senior subordinated notes . . . . . . . . 378 (14%) 439 Commitment fees . . . . . . . . . . . . . . . . . . . 38 (30%) 54 Dividend on mandatorily redeemable preferred stock. . 188 7% 175 Amortization of deferred loan and debt issuance cost. 126 (34%) 192 Other general interest expense. . . . . . . . . . . . 3 (63%) 8 Capitalized interest expense. . . . . . . . . . . . . (315) 16% (271) ---------------- ---------------- Net interest expense. . . . . . . . . . . . . . . . $ 741 (5%) $ 782 ================ ================ Weighted average debt outstanding . . . . . . . . . . $ 61,505 13% $ 54,671 Average interest rate on outstanding indebtedness(a). 6.1% 6.3%
- ---------- (a) Calculated as the sum of the interest expense on our outstanding indebtedness, commitment fees that we pay on unused borrowing capacity and the dividend on our mandatorily redeemable preferred stock divided by the weighted average debt and preferred stock outstanding for the period. Our net interest expense for the first quarter of 2005 was 5% lower than our net interest expense in the first quarter last year. The following were the primary reasons for the changes first quarter 2005 net interest expense. - - An increase in the interest rate that we paid on borrowings under our senior credit facility during the first quarter 2005. The lower margin that resulted from our January 21, 2005 amended and restated senior credit facility was more than offset by the higher Eurodollar rate in the first quarter of 2005; - - A $5.5 million increase in the average debt outstanding under our senior credit facility in the first quarter of 2005 versus that in the first quarter of 2004; - - A 7% increase in the dividends that we paid on our mandatorily redeemable preferred stock. We issued 9,393 shares of preferred stock to pay these dividends; - - A decrease in the interest rate that we paid on our senior subordinated notes, - - A decrease in deferred loan and debt issuance cost amortized during the first quarter 2005; and, - - A 16% increase in the amount of interest that we capitalized during first quarter of 2005. 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 not designated as cash flow hedges, cash gains (losses) on the settlement of these contracts and non-cash gains (losses) related to charges for the ineffective portions of cash flow hedges. Other income (expense) included:
THREE MONTHS ENDED MARCH 31, ------------------------------------------------- 2005 % CHANGE 2004 ---------------- -------------- --------------- (IN THOUSANDS) Non-cash gain (loss) due to change in fair market value of derivative contracts not designated as cash flow hedges . . . . . $ 10 NM $ - Non-cash gain (loss) for ineffective portion of cash flow hedges. (616) NM 127 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75 NM - ---------------- --------------- Other income (loss) . . . . . . . . . . . . . . . . . . . . . . $ (531) NM $ 127 ================ ===============
22 The following table shows the volumes and the weighted average NYMEX reference price for those volumes for our derivative commodity contracts that we did not designate as cash flow hedges for the periods indicated.
THREE MONTHS ENDED MARCH 31, ------------------------------------------------ 2005 % CHANGE 2004 --------------- -------------- --------------- WRITTEN PUTS Volumes (MMbtu). . . . . . . . . . . . . . . 210,000 NM - Average price ($per MMbtu). . . . . . . . . $ 5.50 NM $ - Gain /(loss) upon settlement ($in thousands) $ - NM $ -
Income taxes: A deferred tax liability or asset is recognized for the estimated future tax effects attributable to (i) NOLs and (ii) existing temporary differences between book and taxable income. Realization of net deferred tax assets is dependent upon generating sufficient taxable income within the carryforward period available under tax law. At March 31, 2005, we recognized a current period net deferred tax liability of $1.5 million due to reversals of our existing temporary differences between book and taxable income resulting mainly from our capital expenditures. The $1.5 million net deferred tax liability consisted of a $1.7 million deferred income tax expense, a $3,000 tax effect of unrealized hedging gains, and a $145,000 credit to equity for the tax benefit from the exercise of stock options. In 2004, we recognized a current year net deferred tax liability of $10.6 million due to reversals of our existing temporary differences between book and taxable income resulting mainly from our capital expenditures. The $10.6 million net deferred tax liability consisted of a $10.9 million deferred income tax expense, a $0.3 million tax effect of unrealized hedging gains, and a $0.6 million credit to equity for the tax benefit from the exercise of stock options. At March 31, 2005, we believe it is more likely than not that capital loss carryforwards of approximately $1.8 million may expire unused and, accordingly, have established a valuation allowance of $0.6 million. ANALYSIS OF CHANGES IN CASH AND CASH EQUIVALENTS The table below summarizes our sources and uses of cash during the periods indicated.
THREE MONTHS ENDED MARCH 31, --------------------------------------------------- 2005 % CHANGE 2004 ---------------- --------------- ---------------- (RESTATED) (IN THOUSANDS) Net income. . . . . . . . . . . . . . . . . $ 3,048 (38%) $ 4,925 Non-cash items. . . . . . . . . . . . . . . 9,279 16% 8,002 Changes in working capital and other items. (6,083) 40% (4,333) ---------------- ---------------- Cash flows provided by operating activities $ 6,244 (27%) $ 8,594 Cash flows used by investing activities . . (20,644) 21% (17,057) Cash flows provided by financing activities 16,760 62% 10,343 ---------------- ---------------- Net increase in cash and cash equivalents . $ 2,360 26% $ 1,880 ================ ================
ANALYSIS OF NET CASH PROVIDED BY OPERATING ACTIVITIES Net cash provided by operating activities for the first quarter of 2005 was 27% lower than net cash provided by operating activities in the first quarter of 2004. The following were the primary reasons for this change. - - Net cash provided by operating activities decreased by $116,000 due to a decrease in our revenue from the sale of oil and natural gas. This decrease in revenue was due to lower production volumes in the first quarter of 2005. This decrease in revenue was partially offset by an increase in revenue due to an increase in the prices that we received for oil and natural gas and a decrease in losses on the settlement of our derivative contracts; - - An increase in production cost for the first quarter 2005 resulted in a $748,000 decrease in net cash provided by operating activities. This increase in our production cost was partially offset by a $122,000 decrease in our first quarter 2005 general and administrative expenses; 23 - - The collection of accounts receivable in excess of the payment of accounts payable increased net cash provided by operating activities by $1.4 million; - - An increase in royalties paid in the first quarter 2005 when compared to the first quarter of 2004 resulted in a $2.5 million decrease in net cash provided by operating activities; and, - - A decrease in advances paid to us by participants in our 3-D seismic projects and certain wells decreased net cash provided by operating activities by $392,000. WORKING CAPITAL Working capital is the amount by which current assets exceed current liabilities. It is normal for us to report a working capital deficit at the end of a period. These deficits are primarily the result of accounts payable related to lease operating expenses, exploration and development costs, royalties payable and gas imbalances payable. Settlement of these payables will be funded by cash flows from operations or, if necessary, by additional borrowing under our senior credit facility. Our working capital deficit at March 31, 2005 was $15 million compared to a working capital deficit of $19.5 million at December 31, 2004. This deficit included a liability of $1.8 million related to the fair value our derivative contracts. ANALYSIS OF CHANGES IN CASH FLOWS USED IN INVESTING ACTIVITIES
THREE MONTHS ENDED MARCH 31, ------------------------------------------------- 2005 % CHANGE 2004 --------------- --------------- --------------- (IN THOUSANDS) CAPITAL EXPENDITURES FOR OIL AND NATURAL GAS ACTIVITIES: Drilling. . . . . . . . . . . . . . . . . . . . . . . . . $ 17,458 39% $ 12,568 Land and seismic. . . . . . . . . . . . . . . . . . . . . 4,815 71% 2,817 Capitalized cost (1). . . . . . . . . . . . . . . . . . . 1,601 1% 1,587 Asset retirement obligation . . . . . . . . . . . . . . . 26 (74%) 101 --------------- --------------- Total . . . . . . . . . . . . . . . . . . . . . . . . . $ 23,900 40% $ 17,073 =============== ===============
- ------------ (1) For 2005 includes $1.2 million in capitalized general and administrative cost, $315,000 in capitalized interest cost and $81,000 of capitalized stock compensation expense. For 2004 includes $1.2 million in capitalized general and administrative cost, $271,000 in capitalized interest cost and $71,000 of capitalized stock compensation expense. ANALYSIS OF CHANGES IN CASH FLOWS FROM FINANCING ACTIVITIES SENIOR CREDIT FACILITY During first three months of 2005 we borrowed an additional $17.1 million under our senior credit facility and paid $371,000 in fees to amend and restate of our senior credit facility on January 21, 2005. This compares to $10.2 million borrowed under our senior credit facility in the first three months of 2004. SENIOR SUBORDINATED NOTES We paid $30,000 in fees to amend and restate our senior subordinated credit agreement on January 21, 2005. 24
COMMON STOCK TRANSACTIONS SHARES ISSUED NET PROCEEDS -------------- --------------- (IN THOUSANDS) 2005 COMMON STOCK TRANSACTIONS: Exercise of employee stock options 76,700 $ 251 2004 COMMON STOCK TRANSACTIONS: Exercise of employee stock options 126,600 $ 310
OTHER MATTERS Effects of Inflation and Changes in Prices Our results of operations and cash flows are affected by changing oil and gas prices. If the price of oil and natural gas increases (decreases), there could be a corresponding increase (decrease) in revenues as well as the operating costs that we are required to bear for operations. Inflation has had a minimal effect on us. Environmental and Other Regulatory Matters Our business is subject to certain federal, state and local laws and regulations relating to the exploration for and the development, production and marketing of oil and natural gas, as well as environmental and safety matters. Many of these laws and regulations have become more stringent in recent years, often imposing greater liability on a larger number of potentially responsible parties. Although we believe we are in substantial compliance with all applicable laws and regulations, the requirements imposed by laws and regulations are frequently changed and subject to interpretation, and we cannot predict the ultimate cost of compliance with these requirements or their effect on our operations. Any suspensions, terminations or inability to meet applicable bonding requirements could materially adversely affect our financial condition and operations. Although significant expenditures may be required to comply with governmental laws and regulations applicable to us, compliance has not had a material adverse effect on our earnings or competitive position. Future regulations may add to the cost of, or significantly limit, drilling activity. New Accounting Pronouncements In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123R, "Share-Based Payment" (SFAS 123R), which is a revision of SFAS 123 and supersedes APB Opinion No. 25. SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be valued at fair value on the date of grant, and to be expensed over the applicable vesting period. Pro forma disclosure of the income statement effects of share-based payments is no longer an alternative. In addition, companies must also recognize compensation expense related to any awards that are not fully vested as of the effective date. Compensation expense for the unvested awards will be measured based on the fair value of the awards previously calculated in developing the pro forma disclosures in accordance with the provisions of SFAS 123. The effective date of SFAS 123R is the first reporting period beginning after June 15, 2005, which is the third quarter 2005 for calendar year companies, although early adoption is allowed. However, on April 14, 2005, the Securities and Exchange Commission (SEC) announced that the effective date of SFAS 123R will be suspended until January 1, 2006, for calendar year companies. We are currently assessing the impact of adopting SFAS 123R to our consolidated financial statements. In March 2005, the FASB issued FASB Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations" (FIN 47), which clarifies the impact that uncertainty surrounding the timing or method of settling an obligation should have on accounting for that obligation under SFAS No. 143. FIN 47 is effective no later than the end of the fiscal year ending after December 15, 2005, or December 31, 2005 for calendar year companies. We do not expect the adoption of FIN 47 to have a material impact on our consolidated financial statements. In September 2004, the SEC issued Staff Accounting Bulletin 106 (SAB 106) which provides guidance regarding the interaction of SFAS 143 with the calculation of depletion and the full cost ceiling test of oil and gas 25 properties under the full cost accounting rules of the SEC. The adoption of SAB 106 did not have a material effect on our consolidated financial position, results of operations or cash flows. Forward Looking Information We or our representatives may make forward looking statements, oral or written, including statements in this report, press releases and filings with the SEC, regarding estimated future net revenues from oil and natural gas reserves and the present value thereof, planned capital expenditures (including the amount and nature thereof), increases in oil and gas production, the number of wells we anticipate drilling during 2005 and our financial position, business strategy and other plans and objectives for future operations. Although we believe that the expectations reflected in these forward looking statements are reasonable, there can be no assurance that the actual results or developments anticipated by us will be realized or, even if substantially realized, that they will have the expected effects on our business or operations. Among the factors that could cause actual results to differ materially from our expectations are general economic conditions, inherent uncertainties in interpreting engineering data, operating hazards, delays or cancellations of drilling operations for a variety of reasons, competition, fluctuations in oil and gas prices, availability of sufficient capital resources to us or our project participants, government regulations and other factors set forth among the risk factors noted in the description of our business in Item 1 of our Form 10-K report for the year ended December 31, 2004 or in our Management's Discussion Analysis of Financial Condition in Item 7 of our Form 10-K report for the year ended December 31, 2004. All subsequent oral and written forward looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. We assume no obligation to update any of these statements. 26 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, 2004. 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, 2004. DERIVATIVE CONTRACTS The following table reflects open commodity derivative contracts at March 31, 2005, the associated volumes and the corresponding NYMEX reference price.
NOTIONAL AMOUNT ---------------- NYMEX DERIVATIVE GAS OIL REFERENCE SETTLEMENT PERIOD INSTRUMENT HEDGE STRATEGY (MMBTU) (BARRELS) PRICE - -------------------------- -------------- -------------- --------------- --------------- --------------- COSTLESS COLLARS 04/01/05 - 06/30/05. . . Purchased put Cash flow 318,500 $ 5.00 Written call Cash flow 318.500 7.40 04/01/05 - 06/30/05. . . Purchased put Cash flow 11,830 $ 29.00 Written call Cash flow 11,830 36.00 04/01/05 - 06/30/05. . . Purchased put Cash flow 91,000 $ 4.00 Written call Cash flow 91,000 5.40 04/01/05 - 06/30/05. . . Purchased put Cash flow 45,500 $ 4.25 Written call Cash flow 45,500 4.52 04/01/05 - 06/30/05. . . Purchased put Cash flow 6,825 $ 23.00 Written call Cash flow 6,825 26.45 04/01/05 - 10/31/05. . . Purchased put Cash flow 420,000 $ 5.45 Written call Cash flow 420,000 8.00 THREE WAY COSTLESS COLLARS 07/01/05 - 10/31/05. . . Purchased put Cash flow 400,000 $ 6.00 Written call Cash flow 400,000 7.20 Written put Undesignated 400,000 5.00 07/01/05 - 12/31/05. . . Purchased put Cash flow 30,000 $ 40.00 Written call Cash flow 30,000 53.00 Written put Undesignated 30,000 30.00 11/01/05 - 03/31/06. . . Purchased put Cash flow 250,000 $ 6.75 Written call Cash flow 250,000 8.80 Written put Undesignated 250,000 5.50
The following table reflects commodity derivative contracts entered subsequent to March 31, 2005, the associated volumes and the corresponding weighted average NYMEX reference price.
NOTIONAL AMOUNT ---------------- NYMEX DERIVATIVE GAS OIL REFERENCE SETTLEMENT PERIOD INSTRUMENT HEDGE STRATEGY (MMBTU) (BARRELS) PRICE - -------------------------- -------------- -------------- --------------- --------------- --------------- THREE WAY COSTLESS COLLARS 06/01/05 - 03/31/06. . . Purchased put Cash flow 60,000 $ 48.00 Written call Cash flow 60,000 60.70 Written put Undesignated 60,000 38.00 07/01/05 - 10/31/05. . . Purchased put Cash flow 240,000 $ 7.00 Written call Cash flow 240,000 7.76 Written put Undesignated 240,000 5.75 11/01/05 - 03/31/06. . . Purchased put Cash flow 350,000 $ 8.00 Written call Cash flow 350,000 9.75 Written put Undesignated 350,000 6.50
27 ITEM 4. CONTROLS AND PROCEDURES MATERIAL CONTROL WEAKNESS PREVIOUSLY DISCLOSED In our 2004 Annual Report on Form 10-K, we reported that we did not maintain effective control, as of December 31, 2004, over the accounting for depletion expense and accumulated depletion. This resulted in a material control weakness at December 31, 2004 related to accounting for depletion expense and accumulated depletion. Specifically, our controls related to the preparation and review of the quarterly depletion computations were not adequate to ensure that that the changes in depletion rate estimates used to determine depletion expense and the related accumulated depletion of net proved oil and natural gas properties are only applied prospectively in accordance with accounting principles generally accepted in the United States of America. The remedial actions implemented in the first quarter 2005 related to this material weakness are described below. EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES As of March 31, 2005, 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 CONTROL OVER FINANCIAL REPORTING During the first quarter of 2005, we have taken action to remediate the material weakness identified at December 31, 2004 and update related accounting policies and procedures. Due to such remediation, our depletion rate at each respective period end has been applied to the respective current period production only, as required by accounting principles generally accepted in the United States of America. There were no other 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. 28 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 consolidated financial condition, results of operations or cash flows. ITEM 2. UNREGISTERD SALES OF EQITY SECURITIES AND USE OF PROCEEDS Issuer Purchases of Equity Securities
TOTAL NUMBER OF AVERAGE PRICE PAID PERIOD SHARES PURCHASED PER SHARE - ---------------------------------- ---------------- ------------------- January 1, 2005 - January 31, 2005 21,229 $ 8.93
No purchases were made under a publicly announced plan. ITEM 3. DEFAULTS UPON SENIOR SECURITIES None. ITEM 4. SUBMISSON OF MATTERS TO A VOTE OF SECURITY HOLDERS None. ITEM 5. OTHER INFORMATION None. 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 January 26, 2005 on Form 8-K Item 1.01 Entry into a Material Definitive Agreement and Item 2.03 Creation of a Direct Financial Obligation or an Obligation under and Off-Balance Sheet Arrangement of the Registrant, the Registrant announced that it had amended and restated its senior credit agreement and amended and restated its subordinated notes. (2) Filed January 26, 2005 on Form 8-K Item 2.02 Results of Operation and Financial Condition and Item 9.01 Financial Statements and Exhibits, the Registrant issued a press release to announce discoveries and to provide an operational update. (3) Filed March 3, 2005 on Form 8-K Item 2.02 Results of Operation and Financial Condition, Item. 7.01 Regulation FD Disclosure and Item 9.01 Financial Statements and Exhibits, the Registrant 29 issued a press release to announce its financial results for the quarter and year ended December 31, 2004, its proved reserve volumes at December 31, 2004, its forecasted results for the first quarter 2005 and its forecasted production for the full year 2005. (4) Filed March 4, 2005 a Form 8-K/A to amend the 8-K filed on March 3, 2005 to correct income tax expense for the three month period ended December 31, 2004 contained in the press release attached as an exhibit. (5) Filed March 21, 2005 on Form 8-K Item 2.02 Results of Operation and Financial Condition, Item 4.02 (a) Non-reliance on Previously Issued Financial Statements or a Related Audit Report or Completed Interim Period, Item. 7.01 Regulation FD Disclosure and Item 9.01 Financial Statements and Exhibits, the Registrant issued press release dated March 17, 2005, which announced that it filed with the SEC a Form 12b-25, stating that it requires additional time to revise previously announced results of operations provided in its press release on March 3, 2005, assess the impact that a revision in its methodology for calculating depletion expense will have on its previously issued financial statements and file its 2004 Annual Report on Form 10-K. (6) Filed March 31, 2005 on Form 8-K/A to amend Form 8-K to clarify that the registrant will restate consolidated financial statements for the years 2003 and 2002 filed in its 2004 Annual Report on Form 10-K. Also, with respect to each of the quarterly periods for 2004 and 2003, the registrant will include selected quarter data revised for the change in its depletion expense calculation in the unaudited supplemental quarterly financial information section to be included in its 2004 Annual Report on Form 10-K. Restated quarterly financial statements for the respective 2004 periods will be included in the registrants Forms 10-Q for 2005 for the corresponding periods. 30 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on May 6, 2005. 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 31 EX-31.1 2 ex31_1.txt EXHIBIT 31.1 Exhibit 31.1 CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO RULE 13A-14(a) OF THE SECURITIES EXCHANGE ACT OF 1934 I, Ben M. Brigham, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Brigham Exploration Company; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15e and 15d-15(e)) for the registrant and have: a) Designed such disclosure controls and procedures or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting, which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: May 6, 2005 /s/ BEN M. Brigham --------------------------------------- Ben M. Brigham Chief Executive Officer, President and Chairman of the Board EX-31.2 3 ex31_2.txt EXHIBIT 31.2 Exhibit 31.2 CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO RULE 13A-14(A) OF THE SECURITIES EXCHANGE ACT OF 1934 I, Eugene B. Shepherd, Jr, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Brigham Exploration Company; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15e and 15d-15(e)) for the registrant and have: a) Designed such disclosure controls and procedures or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting, which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: May 6, 2005 /s/ Eugene B. Shepherd, Jr. ------------------------------------------ Eugene B. Shepherd, Jr. Executive Vice President and Chief Financial Officer EX-32.1 4 ex32_1.txt EXHIBIT 32.1 Exhibit 32.1 CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of Brigham Exploration Company (the"Company") on Form 10-Q for the period ending March 31, 2005 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Ben M.Brigham, President, Chief Executive Officer and Chairman of the Board of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated: May 6, 2005 /s/ BEN M. Brigham --------------------------------------------- Ben M. Brigham Chief Executive Officer, President and Chairman of the Board This certification shall not be deemed to be "filed" for the purpose of Section 18 of the Securities Exchange Act of 1934, as amended, and will not be incorporated by reference into any registration statement filed under the Securities Act of 1933, as amended, unless specifically identified therein as being incorporated therein by reference. A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Brigham Exploration Company and will be retained by Brigham Exploration Company and furnished to the Securities and Exchange Commission or its staff upon request. EX-32.2 5 ex32_2.txt EXHIBIT 32.2 Exhibit 32.2 CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of Brigham Exploration Company (the"Company") on Form 10-Q for the period ending March 31, 2005 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Eugene B. Shepherd, Jr., Senior Vice President and Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated: May 6, 2005 /s/ Eugene B. Shepherd, Jr. ---------------------------------- Eugene B. Shepherd, Jr. Executive Vice President and Chief Financial Officer This certification shall not be deemed to be "filed" for the purpose of Section 18 of the Securities Exchange Act of 1934, as amended, and will not be incorporated by reference into any registration statement filed under the Securities Act of 1933, as amended, unless specifically identified therein as being incorporated therein by reference. A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Brigham Exploration Company and will be retained by Brigham Exploration Company and furnished to the Securities and Exchange Commission or its staff upon request. -----END PRIVACY-ENHANCED MESSAGE-----