================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2004 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from __________ to __________ Commission File Number: 000-22433 BRIGHAM EXPLORATION COMPANY (Exact name of registrant as specified in its charter) DELAWARE 1311 75-2692967 (State of other jurisdiction (Primary Standard Industrial (I.R.S. Employer of incorporation or organization) Classification Code Number) Identification Number) 6300 BRIDGE POINT PARKWAY, BUILDING 2, SUITE 500, AUSTIN, TEXAS 78730 (Address of principal executive offices) (512) 427-3300 (Registrant's telephone number, including area code) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12 b-2 of the Act). Yes [X] No [ ] Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. CLASS OUTSTANDING ----- ----------- Common Stock, par value $.01 per share 42,313,625 as of November 5, 2004 ================================================================================ BRIGHAM EXPLORATION COMPANY THIRD QUARTER 2004 FORM 10-Q REPORT TABLE OF CONTENTS ----------------- PAGE ---- PART I - FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS Consolidated Balance Sheets - September 30, 2004 and December 31, 2003 . . . . . . . . . . . . . 1 Consolidated Statements of Operations - Three and nine months ended September 30, 2004 and 2003. 2 Consolidated Statement of Stockholders' Equity - Nine months ended September 30, 2004. . . . . . 3 Consolidated Statements of Cash Flows - Nine months ended September 30, 2004 and 2003. . . . . . 4 Notes to the Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . 5 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK . . . . . . . . . . . . . . . . . . 32 ITEM 4. CONTROLS AND PROCEDURES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 PART II - OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS. . . . . . . . . . . . . . . . . . 34 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 SIGNATURES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 BRIGHAM EXPLORATION COMPANY CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA) (UNAUDITED) SEPTEMBER 30, DECEMBER 31, 2004 2003 --------------- -------------- ASSETS (Unaudited) Current assets: Cash and cash equivalents $ 8,951 $ 5,779 Accounts receivable 11,191 11,143 Deferred income taxes 1,188 307 Other current assets 1,179 3,606 --------------- -------------- Total current assets 22,509 20,835 --------------- -------------- Oil and natural gas properties, net (full cost method) 245,312 197,311 Other property and equipment, net 1,114 1,219 Deferred income taxes - 1,890 Deferred loan fees 1,937 2,501 Other noncurrent assets 597 460 --------------- -------------- Total assets $ 271,469 $ 224,216 =============== ============== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable $ 16,557 $ 19,806 Royalties payable 5,894 5,280 Accrued drilling costs 6,519 3,916 Participant advances received 551 1,179 Other current liabilities 4,512 5,398 --------------- -------------- Total current liabilities 34,033 35,579 --------------- -------------- Senior credit facility 23,500 19,000 Senior subordinated notes 20,000 20,000 Series A Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and redemption value, 2,250,000 shares authorized, 466,599 and 439,722 shares issued and outstanding at September 30, 2004 and December 31, 2003, respectively 9,332 8,794 Deferred income taxes 5,871 - Other noncurrent liabilities 3,269 2,498 Commitments and contingencies Stockholders' equity: Preferred stock, $.01 par value, 10 million shares authorized, of which 2,250,000 shares are designated as Series A and zero and 1,000,000 shares are designated as Series B, at September 30, 2004 and December 31, 2003, respectively - - Common stock, $.01 par value, 50 million shares authorized, 43,152,893 and 40,246,729 shares issued and 41,971,535 and 39,086,096 shares outstanding at September 30, 2004 and December 31, 2003, respectively 432 402 Additional paid-in capital 174,432 151,263 Treasury stock, at cost; 1,181,358 and 1,160,633 shares at September 30, 2004 and December 31, 2003, respectively (4,562) (4,402) Unearned stock compensation (1,722) (1,816) Accumulated other comprehensive income (loss) (1,698) (1,040) Retained earnings (Accumulated deficit) 8,582 (6,062) --------------- -------------- Total stockholders' equity 175,464 138,345 --------------- -------------- Total liabilities and stockholders' equity $ 271,469 $ 224,216 =============== ============== <FN> The accompanying notes are an integral part of these consolidated financial statements. 1 BRIGHAM EXPLORATION COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER SHARE DATA) (UNAUDITED) THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------ ----------------------- 2004 2003 2004 2003 ----------- ----------- ----------- ---------- Revenues: Oil and natural gas sales $ 17,240 $ 13,181 $ 51,975 $ 39,947 Other revenue 27 32 69 113 ----------- ----------- ----------- ---------- 17,267 13,213 52,044 40,060 ----------- ----------- ----------- ---------- Costs and expenses: Lease operating 1,648 1,793 4,362 4,037 Production taxes 675 553 2,434 2,297 General and administrative 1,304 1,094 3,723 3,420 Depletion of oil and natural gas properties 5,871 3,952 16,374 11,853 Depreciation and amortization 179 192 544 449 Accretion of discount on asset retirement obligations 40 39 117 110 ----------- ----------- ----------- ---------- 9,717 7,623 27,554 22,166 ----------- ----------- ----------- ---------- Operating income 7,550 5,590 24,490 17,894 ----------- ----------- ----------- ---------- Other income (expense): Interest income 26 8 55 36 Interest expense (872) (1,271) (2,508) (3,777) Other income (expense) (168) (80) (159) (250) ----------- ----------- ----------- ---------- (1,014) (1,343) (2,612) (3,991) ----------- ----------- ----------- ---------- Income before income taxes and cumulative effect of change in accounting principle 6,536 4,247 21,878 13,903 ----------- ----------- ----------- ---------- Income tax expense: Current - - - - Deferred (2,051) - (7,234) - ----------- ----------- ----------- ---------- (2,051) - (7,234) - ----------- ----------- ----------- ---------- Income before cumulative effect of change in accounting principle 4,485 4,247 14,644 13,903 Cumulative effect of change in accounting principle - - - 268 ----------- ----------- ----------- ---------- Net income 4,485 4,247 14,644 14,171 Less accretion and dividends on redeemable preferred stock - 904 - 2,927 ----------- ----------- ----------- ---------- Net income available to common stockholders $ 4,485 $ 3,343 $ 14,644 $ 11,244 =========== =========== =========== ========== Net income per share available to common stockholders: Basic Income before cumulative effect of change in accounting principle $ 0.11 $ 0.16 $ 0.37 $ 0.54 Cumulative effect of change in accounting principle - - - 0.01 ----------- ----------- ----------- ---------- $ 0.11 $ 0.16 $ 0.37 $ 0.55 =========== =========== =========== ========== Diluted Income before cumulative effect of change in accounting principle $ 0.11 $ 0.13 $ 0.36 $ 0.42 Cumulative effect of change in accounting principle - - - 0.01 ----------- ----------- ----------- ---------- $ 0.11 $ 0.13 $ 0.36 $ 0.43 =========== =========== =========== ========== Weighted average shares outstanding: Basic 41,227 21,210 39,921 20,340 =========== =========== =========== ========== Diluted 42,340 30,751 41,078 32,406 =========== =========== =========== ========== <FN> The accompanying notes are an integral part of these consolidated financial statements. 2 BRIGHAM EXPLORATION COMPANY CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (IN THOUSANDS) (UNAUDITED) ACCUMULATED RETAINED COMMON STOCK ADDITIONAL UNEARNED OTHER EARNINGS ---------------- PAID IN TREASURY STOCK COMPREHENSIVE (ACCUMULATED SHARES AMOUNTS CAPITAL STOCK COMPENSATION INCOME (LOSS) DEFICIT) ------ -------- ------------ ---------- -------------- --------------- -------------- Balance, December 31, 2003 40,247 $ 402 $ 151,263 $ (4,402) $ (1,816) $ (1,040) $ (6,062) Comprehensive income: Net income - - - - - - 14,644 Unrealized gain (losses) on cash flow hedges - - - - - (1,217) - Tax provisions related to cash flow hedges - - - - - 354 - Net losses realized and included in net income - - - - - 205 - Comprehensive income Issuance of common stock 2,599 26 22,106 - - - - Exercises of incentive stock options 235 3 681 - - - - Issuance of restricted stock - - 514 - (514) - - Vesting of restricted stock 72 1 (1) - - - - Forfeitures of restricted stock - - (131) (4) 131 - - Repurchases of common stock - - - (156) - - - Amortization of unearned stock compensation - - - - 477 - - ------ -------- ------------ ---------- -------------- --------------- -------------- Balance, September 30, 2004 43,153 $ 432 $ 174,432 $ (4,562) $ (1,722) $ (1,698) $ 8,582 ====== ======== ============ ========== ============== =============== ============== TOTAL STOCKHOLDERS' EQUITY --------------- Balance, December 31, 2003 $ 138,345 Comprehensive income: Net income 14,644 Unrealized gain (losses) on cash flow hedges (1,217) Tax provisions related to cash flow hedges 354 Net losses realized and included in net income 205 --------------- Comprehensive income 13,986 Issuance of common stock 22,132 Exercises of incentive stock options 684 Issuance of restricted stock - Vesting of restricted stock - Forfeitures of restricted stock (4) Repurchases of common stock (156) Amortization of unearned stock compensation 477 --------------- Balance, September 30, 2004 $ 175,464 =============== <FN> The accompanying notes are an integral part of these consolidated financial statements. 3 BRIGHAM EXPLORATION COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS) (UNAUDITED) NINE MONTHS ENDED SEPTEMBER 30, ----------------------- 2004 2003 ----------- ---------- Cash flows from operating activities: Net income $ 14,644 $ 14,171 Adjustments to reconcile net income to cash provided by operating activities: Depletion of oil and natural gas properties 16,374 11,853 Depreciation and amortization 544 449 Interest paid through issuance of additional senior subordinated notes - 888 Interest paid through issuance of additional mandatorily redeemable preferred stock 538 161 Amortization of deferred loan fees and debt issuance costs 574 809 Market value adjustment for derivative instruments 227 250 Accretion of discount on asset retirement obligations 117 110 Cumulative effect of change in accounting principle - (268) Deferred income taxes 7,234 - Changes in operating assets and liabilities: Accounts receivable (48) 1,565 Gas imbalance receivable 2,435 (5,537) Other current assets (8) 1,344 Accounts payable (3,249) (777) Royalties payable 614 934 Participant advances received (628) (1,355) Gas imbalance liability (2,064) 7,275 Other current liabilities 327 588 Other noncurrent assets and liabilities (126) (35) ----------- ---------- Net cash provided by operating activities 37,505 32,425 ----------- ---------- Cash flows from investing activities: Additions to oil and natural gas properties (61,160) (30,356) Proceeds from sale of oil and natural gas properties - 1,183 Additions to other property and equipment (186) (247) Decrease (Increase) in drilling advances paid (137) 18 ----------- ---------- Net cash used by investing activities (61,483) (29,402) ----------- ---------- Cash flows from financing activities: Proceeds from the issuance of common stock, net of issuance costs 22,132 40,000 Increase in senior credit facility 28,000 - Repayment of senior credit facility (23,500) (47,000) Deferred loan fees paid (10) (985) Proceeds from exercise of incentive stock options 684 660 Repurchases of common stock (156) - ----------- ---------- Net cash provided (used) by financing activities 27,150 (7,325) ----------- ---------- Net increase (decrease) in cash and cash equivalents 3,172 (4,302) Cash and cash equivalents, beginning of year 5,779 15,318 ----------- ---------- Cash and cash equivalents, end of period $ 8,951 $ 11,016 =========== ========== <FN> The accompanying notes are an integral part of these consolidated financial statements. 4 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) 1. ORGANIZATION AND NATURE OF OPERATIONS Brigham Exploration Company ("Brigham"), a Delaware corporation formed on February 25, 1997, explores and develops onshore domestic oil and natural gas properties using 3-D seismic imaging and other advanced technologies. Brigham focuses its exploration and development of onshore oil and natural gas properties primarily in the onshore Gulf Coast, the Anadarko Basin, and West Texas. 2. BASIS OF PRESENTATION The accompanying consolidated financial statements include the accounts of Brigham and its wholly-owned subsidiaries, and its proportionate share of assets, liabilities and income and expenses of the joint operations in which Brigham, or any of its subsidiaries, has a participating interest. All significant intercompany accounts and transactions have been eliminated. The accompanying consolidated financial statements are unaudited, and in the opinion of management, reflect all adjustments that are necessary for a fair presentation of the financial position and results of operations for the periods presented. All such adjustments are of a normal and recurring nature. The results of operations for the periods presented are not necessarily indicative of the results to be expected for the entire year. The unaudited consolidated financial statements should be read in conjunction with Brigham's 2003 Annual Report on Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. STOCK BASED COMPENSATION Brigham accounts for employee incentive stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees". Accordingly, Brigham has adopted the disclosure-only provisions of Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123") as amended by SFAS 148. Had compensation cost for Brigham's stock options been determined based on the fair market value at the grant dates of the awards consistent with the methodology prescribed by SFAS 123, as amended by SFAS 148, Brigham's net income and net income per share for the three and nine month periods ended September 30, 2004 and 2003 would have been the pro forma amounts indicated below: THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------- -------------------------- 2004 2003 2004 2003 ------------ ----------- ------------- ----------- (in thousands, except per share amounts) Net income available to common stockholders - basic: As reported $ 4,485 $ 3,343 $ 14,644 $ 11,244 Add back: Stock compensation expense previously included in net income 103 5 340 10 Effect of total incentive stock-based compensation expense, determined under fair value method for all awards (916) (98) (1,908) (279) ------------ ----------- ------------- ----------- Pro forma $ 3,672 $ 3,250 $ 13,076 $ 10,975 ============ =========== ============= =========== 5 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------- -------------------------- 2004 2003 2004 2003 ------------ ----------- ------------- ----------- (in thousands, except per share amounts) Net income available to common stockholders - diluted: As reported $ 4,485 $ 4,032 $ 14,644 $ 13,959 Add back: Stock compensation expense previously included in net income 103 5 340 10 Effect of total incentive stock-based compensation expense, determined under fair value method for all awards (916) (98) (1,908) (279) ------------ ----------- ------------- ----------- Pro forma $ 3,672 $ 3,939 $ 13,076 $ 13,690 ============ =========== ============= =========== Net income per share: Basic: As reported $ 0.11 $ 0.16 $ 0.37 $ 0.55 Pro forma 0.09 0.15 0.33 0.54 Diluted: As reported $ 0.11 $ 0.13 $ 0.36 $ 0.43 Pro forma 0.09 0.13 0.32 0.42 3. COMMITMENTS AND CONTINGENCIES Brigham is, from time to time, party to certain lawsuits and claims arising in the ordinary course of business. While the outcome of lawsuits and claims cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial condition, results of operations or cash flows of Brigham. On November 20, 2001, Brigham filed a lawsuit in the District Court of Travis County, Texas, against Steve Massey Company, Inc. ("Massey"). The Petition claims Massey furnished defective casing to Brigham, which ultimately led to the casing failure of the Palmer 347 #5 well and the loss of the Palmer #5 as a producing well. In 2004, the parties settled the case on terms favorable to Brigham. Brigham received approximately $440,000 as a result of this settlement, which reduced capitalized well costs. In addition, Massey dropped its $445,819 counterclaim. On July 11, 2002, an employee of a contractor on Brigham's Burkhart #1-R location, Matagorda County, Texas, was involved in a fatal accident. The United States Department of Labor Occupational Safety & Health Administration conducted an inspection and, in October 2003, Brigham settled all issues resulting from that inspection for $70,000. On October 8, 2002, relatives of the contractor's employee filed a wrongful death action in the district court for Matagorda County, Texas, against Brigham and three of Brigham's contractors in connection with his accidental death. Plaintiffs were seeking unspecified actual and punitive damages. On March 23, 2004, a jury determined that Brigham had no liability in the accidental death of the contractor's employee. The plaintiffs filed a motion for a new trial. In late October 2004, the judge granted plaintiffs a new trial. Brigham has not recorded a contingent liability for this suit. In September 2002, Brigham filed suit in the district court of Matagorda County, Texas, against one of its contractors in connection with the drilling of the Burkhart #1-R well. The suit claims that the contractor breached its contract with Brigham and negligently performed services on the well, resulting in damages of approximately $650,000. The contractor filed a counterclaim for the recovery of approximately $315,000. The parties settled the case in April 2004 resulting in a payment by the contractor to Brigham and its co-participants. In addition, the contractor dropped its counterclaim. Based on the amount of the settlement, the 6 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) additional costs that were covered by insurance, and the insurer being subrogated to Brigham's claim, Brigham's incremental recovery as a result of the settlement was diminimus. The operator of the Stonehocker #1 disputed Brigham's ownership interest in the well. In January 2004, the Oklahoma Corporation Commission ruled in favor of Brigham. The operator of the Stonehocker #1 appealed the ruling and the Oklahoma Corporation Commission affirmed its original ruling in March 2004. The operator has appealed the ruling to the Oklahoma Supreme Court. A working interest owner that relinquished its ownership interest in the Nold #1S well as a result of a non-consent election in the re-completion of the well asserted that it did not relinquish its entire interest, but rather became subject only to a 400 percent payout provision. In November 2003, the working interest owner filed a lawsuit against Brigham for breach of contract. In April 2004, the parties negotiated a settlement that resulted in Brigham making a payment of approximately $390,000 to the working interest owner in exchange for an assignment of any interest owned by the working interest owner in this well. In December 2003, Brigham filed a lawsuit in the United States District Court for the Western District of Texas against another company and a former employee concerning the defendants' misappropriation of Brigham's trade secrets and breach of confidentiality obligations. Defendants denied any wrongdoing and asserted a counterclaim against Brigham for alleged tortuous interference with an existing business relationship between the company and its employee. The parties settled the lawsuit in April 2004 on terms favorable to Brigham. The settlement resulted in a $50,000 payment to Brigham, a small overriding royalty interest assignment to Brigham in three tracts and an agreement to not compete in specific areas covered by the confidential information. In addition, the other company has dropped its counterclaim against Brigham. 4. NET INCOME PER SHARE Basic earnings per share are computed by dividing net income available to common stockholders by the weighted average number of common shares outstanding for the period. The computation of diluted net income per share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that would then share in the earnings of Brigham. The following table reconciles the numerators and denominators of the basic and diluted earnings per common share computations for net income available to common stockholders for the three and nine months ended September 30, 2004 and 2003: THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ----------------------- ------------------------- 2004 2003 2004 2003 ----------- ---------- ------------ ----------- (in thousands, except per share amounts) Basic EPS: Income (loss) available to common stockholders before cumulative change in accounting principle $ 4,485 $ 3,343 $ 14,644 $ 10,976 Cumulative change in accounting principle - - - 268 ----------- ---------- ------------ ----------- Income (loss) available to common stockholders $ 4,485 $ 3,343 $ 14,644 $ 11,244 =========== ========== ============ =========== Common shares outstanding 41,227 21,210 39,921 20,340 =========== ========== ============ =========== Basic EPS Income (loss) available to common stockholders before change in accounting principle $ 0.11 $ 0.16 $ 0.37 $ 0.54 Cumulative change in accounting principle - - - 0.01 ----------- ---------- ------------ ----------- $ 0.11 $ 0.16 $ 0.37 $ 0.55 =========== ========== ============ =========== 7 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ----------------------- ------------------------- 2004 2003 2004 2003 ----------- ---------- ------------ ----------- (in thousands, except per share amounts) Diluted EPS: Income (loss) available to common stockholders before cumulative change in accounting principle $ 4,485 $ 3,343 $ 14,644 $ 10,976 Cumulative change in accounting principle - - - 268 ----------- ---------- ------------ ----------- Income (loss) available to common stockholders 4,485 3,343 14,644 11,244 Adjustments for assumed conversions: Dividends and accretion on mandatorily redeemable preferred stock (1) - 689 - 2,715 ----------- ---------- ------------ ----------- Income (loss) available to common stockholders before change in accounting principle-diluted 4,485 4,032 14,644 13,691 Cumulative change in accounting principle - - - 268 ----------- ---------- ------------ ----------- Income (loss) available to common stockholders-diluted $ 4,485 $ 4,032 $ 14,644 $ 13,959 =========== ========== ============ =========== Common shares outstanding 41,227 21,210 39,921 20,340 Effect of dilutive securities: Warrants - - - 402 Mandatorily redeemable preferred stock - 8,966 - 11,071 Stock options 1,113 575 1,157 593 ----------- ---------- ------------ ----------- Potentially dilutive common shares 1,113 9,541 1,157 12,066 ----------- ---------- ------------ ----------- Adjusted common shares outstanding diluted 42,340 30,751 41,078 32,406 =========== ========== ============ =========== Diluted EPS Income (loss) available to common stockholders before change in accounting principle $ 0.11 $ 0.13 $ 0.36 $ 0.42 Change in accounting principle - - - 0.01 ----------- ---------- ------------ ----------- $ 0.11 $ 0.13 $ 0.36 $ 0.43 =========== ========== ============ =========== (1) The amount of dividends included in dividends and accretion on mandatorily redeemable preferred stock includes only the dividends paid in kind on the $40 million of mandatorily redeemable preferred stock (2.0 million shares) that were issued with warrants whose exercise price is payable in either cash or in shares of mandatorily redeemable preferred stock. Options and warrants to purchase 656,000 shares and 2.1 million shares of common stock were outstanding but not included in the calculation of diluted earnings (loss) per share for the three months ended September 30, 2004 and 2003, respectively, and options and warrants to purchase 676,000 shares and 12,000 shares of common stock were outstanding but not included in the calculation of diluted earnings (loss) per share for the nine months ended September 30, 2004 and 2003, respectively, because the effects would have been antidilutive. 8 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) 5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES Brigham utilizes various commodity swap and option contracts to (i) reduce the effects of volatility in price changes on the oil and natural gas commodities it produces and sells, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure it can execute at least a portion of its capital spending plans. Brigham reports average oil and natural gas prices and revenues including the net results of hedging activities. The following table sets forth Brigham's oil and natural gas prices including and excluding the hedging gains and losses and the increase or decrease in oil and natural gas revenues as a result of the hedging activities for the three and nine month periods ended September 30, 2004 and 2003: THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------ ----------------------- 2004 2003 2004 2003 ----------- ----------- ----------- ---------- NATURAL GAS Average price per Mcf as reported (including hedging results) $ 5.44 $ 5.27 $ 5.68 $ 5.17 Average price per Mcf realized (excluding hedging results) $ 5.62 $ 5.72 $ 5.87 $ 6.16 Decrease in revenue (in thousands) $ (390) $ (738) $ (1,250) $ (4,584) OIL Average price per Bbl as reported (including hedging results) $ 36.82 $ 28.08 $ 33.51 $ 28.31 Average price per Bbl realized (excluding hedging results) $ 42.50 $ 30.30 $ 38.01 $ 31.08 Decrease in revenue (in thousands) $ (843) $ (356) $ (2,018) $ (1,554) For the three months ended September 30, 2004 and 2003, ineffectiveness associated with Brigham's derivative commodity instruments designated as cash flow hedges decreased earnings by approximately $146,000 and $80,000, respectively. For the nine months ended September 30, 2004 and 2003, ineffectiveness associated with Brigham's derivative commodity instruments designated as cash flow hedges decreased earnings by approximately $206,000 and $250,000, respectively. These amounts are included in other income (expense). 9 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) NATURAL GAS AND CRUDE OIL DERIVATIVE CONTRACTS CASH-FLOW HEDGES Brigham's cash-flow hedges consisted of fixed-price swaps and costless collars (purchased put options and written call options). The fixed-price swap agreements are used to fix the prices of anticipated future oil and natural gas production. The costless collars are used to establish floor and ceiling prices on anticipated future oil and natural gas production. There were no net premiums received when Brigham entered into these option agreements. As of September 30, 2004, Brigham had entered into derivative contracts that qualify as cash flow hedges with respect to future production as follows: 2004 2005 -------- -------------------------------------- FOURTH FIRST SECOND THIRD FOURTH QUARTER QUARTER QUARTER QUARTER QUARTER -------- -------- -------- -------- -------- NATURAL GAS SWAPS: Volumes (MMbtu). . . . . . 92,000 - - - - Average price ($per MMBtu) $ 4.360 $ - $ - $ - $ - NATURAL GAS COLLARS: Volumes (MMbtu). . . . . . 726,100 727,500 455,000 - - Average price ($per MMBtu) Floor. . . . . . . . . . . $ 5.065 $ 5.164 $ 4.725 $ - $ - Ceiling. . . . . . . . . . 6.873 7.256 6.712 - - CRUDE OIL SWAPS: Volumes (Bbls) . . . . . . 9,200 - - - - Average price ($per Bbl) . $ 23.80 $ - $ - $ - $ - CRUDE OIL COLLARS: Volumes (Bbls) . . . . . . 34,260 27,450 18,655 - - Average price ($per Bbl) Floor. . . . . . . . . . . $ 26.38 $ 25.56 $ 26.80 $ - $ - Ceiling. . . . . . . . . . 31.71 30.18 32.51 - - As of September 30, 2004, Brigham's derivative positions included an option contract that is not designated as a hedge. This contract was entered into to offset the cost of other options that are designated as hedges. 2004 2005 -------- -------------------------------------- FOURTH FIRST SECOND THIRD FOURTH QUARTER QUARTER QUARTER QUARTER QUARTER -------- -------- -------- -------- -------- NATURAL GAS WRITTEN PUTS: Volumes (MMbtu). . . . . . 140,000 210,000 - - - Average price ($per MMBtu) $ 5.500 $ 5.500 $ - $ - $ - Derivative instruments not qualifying as hedging contracts are recorded at fair value on the balance sheet. At each balance sheet date, the value of derivatives not qualifying as hedging contracts is adjusted to reflect current fair value and any gains or losses are recognized as other income or expense. At September 30, 2004 and 2003, the fair value of these derivatives included in other current liabilities was approximately $22,000 and $0, respectively. For the three and nine months ended September 30, 2004, and 2003, other income (expense) included approximately $21,000 and $0, respectively, in non-cash losses related to changes in the fair values of these derivative contracts. There were no cash settlement payments made by Brigham to the counterparty for the three and nine months ended September 30, 2004 and 2003. 10 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) INTEREST RATE SWAP Periodically, Brigham may use interest rate swap contracts to adjust the proportion of its total debt that is subject to variable interest rates. Under such an interest rate swap contract, Brigham agrees to pay an amount equal to a specified fixed-rate of interest for a certain notional amount and receive in return an amount equal to a variable-rate. The notional amounts of the contract are not exchanged. No other cash payments are made unless the contract is terminated prior to maturity. Although no collateral is held or exchanged for the contract, the interest rate swap contract is entered into with a major financial institution in order to minimize Brigham's counterparty credit risk. The interest rate swap contract is designated as a cash flow hedge against changes in the amount of future cash flows associated with Brigham's interest payments on variable-rate debt. The effect of this accounting on operating results is that interest expense on a portion of variable-rate debt being hedged is recorded based on fixed interest rates. At September 30, 2004, Brigham had an interest rate swap contract to pay a fixed-rate of interest of 8.76% on $20.0 million notional amount of senior subordinated notes. The $20.0 million notional amount of the outstanding contract matures in March 2009. As of September 30, 2004, approximately $79,000 of unrealized losses are included in accumulated other comprehensive income (loss) on the balance sheet and the fair value of the interest rate swap agreement represents approximately $191,000 of other noncurrent liabilities. The fair value of the interest rate swap contract is based on quoted market prices and third-party provided calculations, which reflect the present values of the difference between estimated future variable-rate receipts and future fixed-rate payments. FAIR VALUES The fair value of commodity hedging and interest rate swap contracts is reflected on the consolidated balance sheets as detailed in the following table. The current asset and liability amounts represent the fair values expected to be included in the results of operations for the next twelve months. SEPTEMBER 30, -------------------- 2004 2003 --------- --------- (in thousands) Other current liabilities $ (2,970) $ (1,134) Other noncurrent liabilities (428) (136) Other current assets - 91 Other noncurrent assets 3 12 --------- --------- $ (3,395) $ (1,167) ========= ========= 6. ASSET RETIREMENT OBLIGATIONS On January 1, 2003, Brigham adopted the provisions of Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"). SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. Brigham has asset retirement obligations associated with the future plugging and abandonment of proved properties and related facilities. Prior to the adoption of SFAS 143, Brigham assumed salvage value approximated plugging and abandonment costs. As such, estimated salvage value was not excluded from depletion and plugging and abandonment costs were not accrued for over the life of the oil and gas properties. The estimated liability is based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells, estimates as to the cost to plug and abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest 11 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) rate of 7.5%. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, changes in the risk-free interest rate or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment to record (i) a $1.4 million increase in the carrying values of proved properties, (ii) a $0.8 million decrease in accumulated depletion of oil and natural gas properties and (iii) a $1.9 million increase in noncurrent abandonment liabilities. The net impact of items (i) through (iii) was to record a gain of $0.3 million as a cumulative effect adjustment of a change in accounting principle in Brigham's consolidated statements of operations upon adoption on January 1, 2003. Brigham has no assets that are legally restricted for purposes of settling asset retirement obligations. The following table summarizes Brigham's asset retirement obligation transactions recorded in accordance with the provisions of SFAS 143 during the three and nine months ended September 30, 2004: THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ----------------------- ---------------------- 2004 2003 2004 2003 ----------- ---------- ----------- --------- (in thousands) Beginning asset retirement obligations $ 2,665 $ 2,062 $ 2,320 $ 1,931 Liabilities incurred for new wells placed on production 58 82 394 142 Liabilities settled (24) - (92) - Accretion of discount on asset retirement obligations 40 39 117 110 ----------- ---------- ----------- --------- Ending asset retirement obligations $ 2,739 $ 2,183 $ 2,739 $ 2,183 =========== ========== =========== ========= 7. INCOME TAXES The provision for income taxes was computed in accordance with Interpretation No. 18 of Accounting Principles Board Opinion (APB) No. 28 on reporting taxes for interim periods and accordingly was based on the projection of total 2004 pretax income. Interpretation No. 18 of APB 28 provides that interim income taxes should be computed using the projected effective tax rate on the total projected pretax income for the year. At September 30, 2004, management believes that Brigham will (i) begin to utilize net operating losses (NOLs) and (ii) have reversals of existing temporary differences between book and taxable income sufficient to result in a deferred tax liability at year-end 2004. Management also believes that it is more likely than not that capital loss carryforwards of approximately $1.8 million may expire unused and, accordingly, has established a valuation allowance of $0.6 million. The components of deferred income tax assets and liabilities are as follows: SEPTEMBER 30, DECEMBER 31, 2004 2003 -------------- -------------- (in thousands) Deferred tax assets Current: Net operating loss carryforwards $ - $ 451 Unrealized hedging losses 914 - Derivative assets 274 - -------------- -------------- 1,188 451 -------------- -------------- 12 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) SEPTEMBER 30, DECEMBER 31, 2004 2003 --------------- -------------- (in thousands) Non-current: Net operating loss carryforwards 35,614 34,409 Capital loss carryforwards 642 634 Stock compensation 680 818 Unrealized hedging losses - 561 Derivative assets - 276 Asset retirement obligations 958 812 Preferred stock dividends as interest expense 307 119 Other 27 27 --------------- -------------- Non-current 38,228 37,656 --------------- -------------- 39,416 38,107 --------------- -------------- Deferred tax liabilities Current: Gas imbalances - (144) Non-current: Depreciable and depletable property (43,279) (35,132) Other (186) - --------------- -------------- Non-current (43,465) (35,132) --------------- -------------- (43,465) (35,276) --------------- -------------- Net deferred tax assets (liabilities) (4,049) 2,831 Valuation allowance (634) (634) --------------- -------------- $ (4,683) $ 2,197 =============== ============== At September 30, 2004, Brigham has regular tax NOLs of approximately $101.8 million. Additionally, Brigham has approximately $87.6 million of alternative minimum tax ("AMT") NOLs available as a deduction against future taxable income. The NOLs expire from 2012 through 2024. The value of these NOLs depends on the ability of Brigham to generate taxable income. In addition, at September 30, 2004, Brigham has capital loss carryforwards of approximately $1.8 million that expire in varying years through 2007. Brigham believes it has a $4.5 million annual limitation on the utilization of certain of its NOLs under Internal Revenue Code Section 382 due to a potential 50% change in ownership among its 5% stockholders over a three-year period. 8. ISSUANCE OF COMMON STOCK During July and August 2004, Brigham completed the sale of 2,598,500 shares of its common stock under a universal shelf registration statement declared effective by the Securities and Exchange Commission in June 2004. Net proceeds from the stock sale of approximately $22.1 million were used to repay outstanding borrowings under the senior credit facility. Brigham plans to reborrow the repaid amounts under the senior credit facility as necessary to fund future exploration and development activities and for general corporate purposes. 9. ACCOUNTING PRONOUNCEMENTS In September 2004, the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin No. 106. This pronouncement will require companies that use the full cost method for accounting for their oil and gas producing 13 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) activities to include an estimate of future asset retirement costs to be incurred as a result of future development activities on proved reserves in their calculation of depreciation, depletion and amortization. This pronouncement will also require these companies to exclude any future cash outflows associated with settling asset retirement liabilities from their full cost ceiling test calculation. This standard will also require these companies to disclose the impact of their asset retirement obligations on their oil and gas producing activities, ceiling test calculations and depreciation, depletion and amortization calculations. Brigham will adopt the provisions of this pronouncement in the fourth quarter of 2004 and is currently evaluating the impact, if any, on our consolidated financial statements. 14 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following updates information as to our financial condition provided in our 2003 Annual Report on Form 10-K, and analyzes the changes in the results of operations between the three and nine month periods ended September 30, 2004, and the comparable periods of 2003. For definitions of commonly used oil and gas terms as used in this Form 10-Q, please refer to the "Glossary of Oil and Gas Terms" provided in our 2003 Annual Report on Form 10-K. OVERVIEW OF FIRST NINE MONTHS OF 2004 For the quarter and nine-month periods ended September 30, 2004, our net capital expenditures for oil and natural gas activities were $24.4 million and $64 million, respectively. Our drilling capital expenditures alone for the third quarter 2004 were up approximately 122% over the amount we spent in the third quarter of last year. For the nine months ended September 30, 2004, our net capital expenditures for oil and natural gas activities are up approximately 126% when compared to the first nine months of last year. Our operating performance for the third quarter and first nine months of 2004 was highlighted by production of 34 MMcfe/d and 34.1 MMcfe/d, respectively. This represents a 17% growth in production over the amount we produced in the third quarter of 2003 and a 15% increase over the amount we produced in the first nine months of 2003. The increase in our production is primarily the result of the increase in drilling capital expenditures during the fourth quarter of last year and the first nine months of 2004. Net income to common stockholders for the third quarter 2004 was $4.5 million, or $0.11 per diluted share, on total revenues of $17.3 million. This compares to reported net income of $3.3 million, or $0.13 per diluted share on total revenues of $13.2 million in the third quarter last year. For the nine month period ended September 30, 2004, our reported net income to common stockholders was $14.6 million, or $0.36 per diluted share, on total revenues of $52 million. This compares to reported net income of $11.2 million, or $0.43 per diluted share, on revenue of $40.1 million for the first nine months of last year. Net cash provided by operating activities funded approximately 61% of the cash used in our capital expenditure program during the first nine months of 2004. During the third quarter of 2004, we sold 2,598,500 shares of our common stock under a universal shelf registration statement declared effective by the Securities and Exchange Commission in June 2004. Net proceeds from the stock sale were approximately $22.1 million and were used to repay outstanding indebtedness under our senior credit facility. "Net proceeds" is the amount we received after paying the underwriting discount and other expenses related to offering. We intend to reborrow the repaid amount to fund future exploration and development activities, including taking advantage of opportunities to retain larger working interests in wells and in 3-D seismic programs and for general corporate purposes. At September 30, 2004, we had $9 million in cash, total assets of $271.5 million and a debt to total book capitalization ratio of 23%. 15 OUTLOOK FOR THE REMAINDER OF 2004 ESTIMATED ORIGINAL 2004 2004 SPENDING BUDGET % CHANGE ---------- --------- --------- (IN THOUSANDS) Drilling . . . . . . . . . . . . . . . . . . . . . . . $ 69,280 $ 61,432 13% Land and G&G . . . . . . . . . . . . . . . . . . . . . 16,589 11,973 39% Capitalized interest and G&A . . . . . . . . . . . . . 6,085 5,535 10% --------------------- Net capital expenditures on oil and gas activities $ 91,954 $ 78,940 16% Other property and equipment . . . . . . . . . . . . . 474 473 0% --------------------- Net capital expenditures . . . . . . . . . . . . . $ 92,428 $ 79,413 16% ===================== Current Estimated Capital Expenditures for 2004 Approximately $40.2 million, or 58%, of our estimated drilling capital expenditures for 2004 will be allocated to drill 23 wells in our onshore Texas Gulf Coast region. For 2004, our drilling activities in our onshore Gulf Coast region will be focused on the Vicksburg and Frio Trends where we will drill 11 development wells with an average working interest of 61% and 12 exploratory wells with an average working interest of 68%. Of the wells we currently plan to drill in 2004, 14 of the wells had reached total depth as of September 30, 2004. In the Vicksburg, we currently estimate that we will spend approximately $19.4 million to drill four development wells with an average working interest of 51% and three exploration wells with an average working interest of 71%. As of September 30, 2004, four of the wells budgeted for 2004 had reached total depth and one well was drilling. We currently plan to spud the remaining two Vicksburg wells in our 2004 drilling program in the fourth quarter of this year. In the Frio, we currently estimate that we will spend approximately $20.7 million to drill seven development wells with an average working interest of 66% and nine exploration wells with an average working interest of 67%. As of September 30, 2004, ten of the wells in budgeted for 2004 had reached total depth and one was drilling. We currently plan to spud the remaining five Frio wells in the fourth quarter of this year. Approximately $26.8 million, or 39%, of our currently estimated drilling capital expenditures for 2004 will be allocated to drill 37 wells in our Anadarko Basin region. The majority of our drilling capital allocated to our Anadarko Basin region will be focused on the Hunton/Arbuckle, Springer Channel and Springer Bar Trends. For 2004, we currently plan to drill 30 development wells with an average working interest of 29% and seven exploratory wells with an average working interest of 16% in our Anadarko Basin region. Of the wells currently plan to drill in 2004, 24 had reached total depth as of September 30, 2004. We currently estimate that we will spend approximately $13.1 million to drill two Hunton/Arbuckle development wells with an average working interest of 96%. As of September 30, 2004, one well had reached total depth and we expect to spud the remaining well in the fourth quarter of this year. For the Springer Channel, we currently estimate that we will spend approximately $4.7 million to drill seven development wells with an average working interest of 41% and five exploratory wells with an average working interest of 18%. As of September 30, 2004, nine of these wells had reached total depth of which three were completing and one well was drilling. We currently plan to spud the remaining two wells in the fourth quarter of this year. For the Springer Bar, we currently estimate that we will spend approximately $2.3 million to drill seven development wells with an average working interest of 12%. As of September 30, 2004, one well was drilling and four wells, of which two were completing, had reached total depth. We currently plan to spud the remaining three wells in the fourth quarter of this year. 16 Additional estimated capital expenditures for the Anadarko Basin region in 2004 includes $4 million to drill 13 development wells in the granite wash formation with and average working interest of 22%. As of September 30, 2004, eight of these granite wash wells reached total depth and two were drilling. We currently plan to spud the remaining two wells in the fourth quarter. We also plan to spend $2.5 million to drill two Grady County Bromide tests with an average working interest of 16%, a combined Hunton/Springer Channel test with a 17% working interest and for other various drilling activities. As of September 30, 2004, one of the Bromide tests and the combined Hunton/Springer Channel test had reached total depth. The other Bromide test was drilling at September 30, 2004. We currently plan to spend approximately $2.3 million, or 3%, of our estimated 2004 drilling capital expenditures, to drill two exploratory wells in our West Texas region with an average working interest of 94%. As of September 30, 2004, one well had reached total depth and was completing. The other well was drilling at the end of the third quarter. Approximately 18% of current estimated 2004 capital expenditures will be used to fund land and seismic acquisitions in an effort to add to our inventory of drilling projects in current focus plays. We believe that our cash on hand at September 30, 2004, net cash provided by operating activities, net proceeds from our sale of common stock in July and August 2004 and the remaining availability under our senior credit facility will fund our spending for the remainder of the year. Our estimated net capital expenditures for 2004 represent an increase of approximately 96% over the amount that we spent in 2003. The final determination with respect to our 2004 budgeted expenditures will depend on a number of factors, including: - commodity prices; - production from our existing producing wells; - the results of our current exploration and development drilling efforts; - economic and industry conditions at the time of drilling, including the availability of drilling equipment; and - the availability of more economically attractive prospects. There can be no assurance that the budgeted wells will, if drilled, encounter commercial quantities of natural gas or oil. 17 CAPITAL COMMITMENTS Net cash provided by operating activities, net proceeds from the sale of common stock and additional borrowings from our senior credit facility were our primary sources of cash during the first nine months of 2004. This cash was used to fund the costs associated with drilling, land acquisition and 3-D seismic acquisition, processing and interpretation. We believe our cash on hand at the end of the third quarter 2004, net cash provided by operating activities, net proceeds from our sale of common stock in July and August 2004 and the remaining availability under our senior credit facility will be sufficient to fund our budgeted capital expenditures for the remainder of 2004. Capital Expenditures The timing of most of our capital expenditures is discretionary because we have no material long-term capital expenditure commitments. Consequently, we have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. The table below lists our capital expenditures for the first nine months of 2004 and 2003. NINE MONTHS ENDED SEPTEMBER 30, ---------------------------------------- 2004 2003 % CHANGE ---------- -------------- ------------ (IN THOUSANDS) Drilling . . . . . . . . . . . . . . . . . . . . . . . $ 48,638 $ 20,542 137% Land and G&G . . . . . . . . . . . . . . . . . . . . . 10,749 3,135 243% Capitalized interest and G&A . . . . . . . . . . . . . 4,595 4,622 (1%) Proceeds from the sale of oil and gas properties . . . - (23) (100%) -------------------------- Net capital expenditures on oil and gas activities $ 63,982 $ 28,276 126% Other property and equipment . . . . . . . . . . . . . 186 247 (25%) -------------------------- Net capital expenditures . . . . . . . . . . . . . $ 64,168 $ 28,523 125% ========================== LIQUIDITY AND CAPITAL RESOURCES Cash flows from operating activities During the first nine months of 2004, net cash provided by operating activities, net proceeds from the sale of common stock and additional borrowings from our senior credit facility were our primary source of cash. This cash was used to fund the costs associated with drilling, land acquisition and 3-D seismic acquisition, processing and interpretation. NINE MONTHS ENDED SEPTEMBER 30, -------------------------------------- 2004 2003 % CHANGE ---------- ------------- ----------- (IN THOUSANDS) Net cash provided by operating activities $ 37,505 $ 32,425 16% The 16% increase in net cash provided by operating activities is primarily related to the following: - - An increase in oil and natural gas sales resulted in a $9.1 million increase in net cash provided by operating activities. - - An increase in revenue due to a decline in losses from the settlement of derivative contracts resulted in a $2.9 million increase in net cash provided by operating activities. These increases were partially offset by the following: - - The repayment of accounts payable in excess of collections of accounts receivable reduced net cash provided by 18 operating activities by $4.1 million. - - The settlement of the gas imbalance with our industry participant in our Diablo project reduced net cash provided by operating activities by $1.4 million. - - An increase in production costs and general and administrative expenses reduced net cash provided by operating activities by $765,000. - - A decrease in royalties payable of $320,000. Working capital is the amount by which current assets exceed current liabilities. It is normal for us to report a working capital deficit at the end of a period. These deficits are primarily the result of accounts payable related to lease operating expenses, exploration and development costs, liabilities related to derivative contracts and royalties payable. Settlement of these payables will be funded by cash flows from operations or, if necessary, by additional borrowing under our senior credit facility. At September 30, 2004, we had a working capital deficit of $11.5 million compared to a working capital deficit of $14.7 million at December 31, 2003. Current liabilities at September 30, 2004, included a liability of $3 million related to the fair value of our open derivative contracts. Cash flows from financing activities Common stock transactions - ------------------------- - - During the third quarter 2004, we sold 2,598,500 shares of our common stock under a universal shelf registration statement declared effective by the Securities and Exchange Commission in June 2004. We received net proceeds of approximately $22.1 million and used the net proceeds from the offering to repay outstanding indebtedness under our senior credit facility. "Net proceeds" is the amount we received after paying the underwriting discount and other expenses related to offering. - - We issued 126,600 shares of common stock and received $310,000 in net proceeds related to the exercise of employee and director stock options in the first quarter of 2004, issued 81,481 shares of common stock and received $288,000 in net proceeds in the second quarter of 2004 and issued 27,500 shares of common stock and received $86,000 in net proceeds in the third quarter 2004. - - During January and June of 2004, we acquired 19,596 and 821 shares of our common stock, respectively, from certain employees to satisfy tax-withholding obligations associated with the vesting of stock grants. The transferred shares were valued at fair market value as of the date of surrender. - - In September 2003, we sold 7,384,090 shares of common stock and received $40 million in net proceeds. The net proceeds from the sale were used to increase the amount of capital spent on our exploration and development activities. Pending such use, the net proceeds were used to repay $40 million of the borrowings outstanding under our senior credit facility. - - We issued 171,800 shares of common stock and received $432,000 in net proceeds related to the exercise of employee and director stock options in the first quarter of 2003, issued 52,793 and received net proceeds of $162,000 in the second quarter of 2003 and issued 25,042 shares of common stock and received net proceed of $66,000 in the third quarter of 2003. - - In the first quarter of 2003, we issued 248,028 unregistered shares of our common stock to a group of institutional investors. The shares were issued to the group in connection with the cashless exercise of warrants that it owned and we received no proceeds from the exercise of the warrants. - - In June 2003, we issued 408,928 and 206,982 unregistered shares of our common stock to the Bank of Montreal and Soci t G n rale, respectively. We received no proceeds from the exercise of these warrants as both parties elected to execute a cashless exercise of the warrants. Both parties sold the shares from this exercise in our common stock sale in September 2003. We received no proceeds from the sale. Senior credit facility - ---------------------- Future outstanding balances under our senior credit facility are dependent primarily on our level of capital expenditures, net cash provided by operating activities and the proceeds from other financing activities. Our committed borrowing capacity under our senior credit facility at September 30, 2004, was $23.5 million, with a $68.5 million borrowing base that is subject to adjustment on the basis of the present value of estimated future net cash flows from proved oil and gas reserves (as determined by the lender's petroleum engineer). Our unused committed borrowing base capacity under our senior credit facility was $44.5 million at November 5, 2004. During the first nine months of 2004 we borrowed $28 million of additional debt from our senior credit facility to fund our working capital obligations and capital expenditures and repaid $23.5 million. During the first nine 19 months of 2003, we repaid $47 million of the debt outstanding under our senior credit facility and paid $985,000 in fees related to our new credit facility that was put in place in March 2003. Our current ratio, as defined by the senior credit facility, at September 30, 2004 and interest coverage ratio for the twelve-month period ending September 30, 2004, were 2 to 1 and 13.7 to 1, respectively. As of September 30, 2004, we were in compliance with the covenants of our senior credit facility. Senior subordinated notes - ------------------------- Our current ratio, as defined by the senior credit facility, at September 30, 2004 and interest coverage ratio for the twelve-month period ending September 30, 2004, were 2 to 1 and 13.7 to 1, respectively. Our ratio of risked net present value (as defined) discounted at 9% to total debt at June 30, 2004, was 2.3 to 1, and was in compliance with the subordinated notes covenant that requires us to maintain a ratio of 1.5 to 1. As of September 30, 2004, we were in compliance with the covenants of our senior subordinated notes. RESULTS OF OPERATIONS Comparison of the three and nine month periods ended September 30, 2004 and 2003 Production. THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, ----------------------------------------- ----------------------------------------- 2004 2003 % CHANGE 2004 2003 % CHANGE ---------- ------------- -------------- ---------- ------------- -------------- Oil (MBbls). . . . . . . . . . . . . 148 160 (7%) 449 562 (20%) Natural gas (MMcf) . . . . . . . . . 2,167 1,648 31% 6,506 4,648 40% Natural gas equivalent (MMcfe) . . 3,057 2,608 17% 9,199 8,019 15% Average daily production (MMcfe/d) 34.0 29.0 17% 34.1 29.7 15% % Natural gas. . . . . . . . . . . 71% 63% 71% 58% The increase in our production volumes was due to organic production growth from wells that we drilled and completed in the fourth quarter of 2003 and the first nine months of 2004. New production related to these recently completed wells was partially offset by the natural decline of existing production. Revenues from the sale of oil and natural gas. Reported revenues from the sale of oil and natural gas are based on the market price we receive for our commodities, adjusted for marketing charges and the results from the settlement of our derivative commodity contracts that have been designated as cash flow hedges under SFAS 133. We utilize fixed price swaps, costless collars, three way costless collars and floor contracts to (i) reduce the effect of price volatility on the commodities that we produce and sell, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure we can execute at least a portion of our capital spending plans. See "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for a list of our open derivative commodity contracts at September 30, 2004." The effective portions of changes in the fair values of our derivative commodity contracts that are designated as cash flow hedges is recorded as increases or decreases to stockholders' equity until the underlying contract is settled. Consequentially, these changes could add volatility to our reported stockholders' equity until the contract is settled or is terminated. Derivative commodity contracts that do not meet the hedge criteria of SFAS 133 are not designated as hedges. Gains or losses related to the settlement, the ineffective portion of changes in the fair market value and the changes in the fair values of our derivative commodity contracts that are not designated as cash flow hedges are recognized in other income (expense). 20 The following table presents revenues that we realized from the sale of oil and natural gas during the third quarter and first nine months of 2004 and 2003. THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, ----------------------------------- -------------------------------------- 2004 2003 % CHANGE 2004 2003 % CHANGE --------- ---------- ------------ ---------- ------------ ------------ (IN THOUSANDS) Oil sales . . . . . . . . . . . . . . . . . . . . . . $ 6,304 $ 4,847 30% $ 17,058 $ 17,459 (2%) Loss due to hedging . . . . . . . . . . . . . . . . . (843) (356) 137% (2,018) (1,554) 30% --------- ---------- ------------------------ Total revenues from the sale of oil . . . . . . . . $ 5,461 $ 4,491 22% $ 15,040 $ 15,905 (5%) ========= ========= ======================== Natural gas sales . . . . . . . . . . . . . . . . . . $ 12,169 $ 9,428 29% $ 38,185 $ 28,627 33% Loss due to hedging . . . . . . . . . . . . . . . . . (390) (738) (47%) (1,250) (4,585) (73%) --------- ---------- ------------------------ Total revenues from the sale of natural gas . . . . $ 11,799 $ 8,690 36% $ 36,935 $ 24,042 54% ========= ========= ======================== Oil and natural gas sales . . . . . . . . . . . . . . $ 18,473 $ 14,275 29% $ 55,243 $ 46,086 20% Loss due to hedging . . . . . . . . . . . . . . . . . (1,233) (1,094) 13% (3,268) (6,139) (47%) --------- ---------- ------------------------ Total revenues from the sale of oil and natural gas $ 17,240 $ 13,181 31% $ 51,975 $ 39,947 30% ========= ========= ======================== AVERAGE PRICES: (PER BBL) Oil sales . . . . . . . . . . . . . . . . . . . . . . $ 42.50 $ 30.30 40% $ 38.01 $ 31.08 22% Loss due to hedging . . . . . . . . . . . . . . . . . (5.68) (2.22) 156% (4.50) (2.77) 62% --------- ---------- ------------------------ Realized Oil price. . . . . . . . . . . . . . . . . $ 36.82 $ 28.08 31% $ 33.51 $ 28.31 18% ========= ========= ======================== (PER MCF) Natural gas sales . . . . . . . . . . . . . . . . . . $ 5.62 $ 5.72 (2%) $ 5.87 $ 6.16 (5%) Loss due to hedging . . . . . . . . . . . . . . . . . (0.18) (0.45) (60%) (0.19) (0.99) (81%) --------- ---------- ------------------------ Realized natural gas price. . . . . . . . . . . . . $ 5.44 $ 5.27 3% $ 5.68 $ 5.17 10% ========= ========= ======================== (PER MCFE) Natural gas equivalent sales. . . . . . . . . . . . . $ 6.04 $ 5.47 10% $ 6.01 $ 5.75 5% Loss due to hedging . . . . . . . . . . . . . . . . . (0.40) (0.42) (5%) (0.36) (0.77) (53%) --------- ---------- ------------------------ Realized natural gas equivalent price . . . . . . . $ 5.64 $ 5.05 12% $ 5.65 $ 4.98 13% ========= ========= ======================== Total revenues from the sale of oil and natural gas for the third quarter 2004 were 31% higher than revenues in same period of 2003. The increase was primarily due the following: - - A $2.6 million increase to total revenues from the sale of oil and natural gas due to a 17% increase in production volumes for the third quarter 2004. - - A $1.6 million increase to total revenues from the sale of oil and natural gas due to a 10% increase in the average sales price we received for oil and natural gas. - - A 13% increase in losses related to the settlement of hedging contracts resulted in a $139,000 decrease in total revenues from the sale of oil and natural gas. Total revenues from the sale of oil and natural gas for the first nine months of 2004 were 30% higher than revenues in the same period of 2003. The increase was primarily due to the following: 21 - - An $7.9 million increase to total revenues from the sale of oil and natural gas due to a 15% increase in production volumes during the first nine months of 2004. - - A $1.2 million increase in total revenues from the sale of oil and natural gas due to a 5% increase in the average sales price we received for oil and natural gas during the first nine months of 2004. - - A 47% decrease in losses related to the settlement of hedging contracts resulted in a $2.9 million increase in total revenues from the sale of oil and natural gas. The table below presents our derivative commodity contracts, the volumes, the weighted average NYMEX reference price for those volumes, and the associated gain or loss upon settlement of those contracts during the third quarter and first nine months of 2004 and 2003. THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, --------------------------------------- -------------------------------------- % % 2004 2003 CHANGE 2004 2003 CHANGE -------------- --------- ------------ ----------- ----------- ------------ OIL SWAPS Volumes (Bbls). . . . . . . . . . . 13,800 55,200 (75%) 63,850 184,125 (65%) Average swap price (per Bbl). . . . $ 23.91 $ 23.77 1% $ 24.77 $ 24.81 (0%) Loss upon settlement (in thousands) $ (275) $ (356) (23%) $ (848) $ (1,157) (27%) OIL COLLARS Volumes (Bbls). . . . . . . . . . . 48,760 - - 144,310 45,250 219% Average floor price (per Bbl) . . . $ 26.43 $ - - $ 24.51 $ 18.00 36% Average ceiling price (per Bbl) . . 32.20 - - 31.09 22.56 38% Loss upon settlement (in thousands) $ (568) $ - - $ (1,170) $ (397) 195% NATURAL GAS SWAPS Volumes (MMbtu) . . . . . . . . . . 138,000 598,000 (77%) 661,250 2,249,500 (71%) Average swap price (per MMbtu). . . $ 4.180 $ 3.867 8% $ 4.555 $ 3.772 21% Loss upon settlement (in thousands) $ (230) $ (738) (69%) $ (836) $ (4,585) (82%) NATURAL GAS COLLARS Volumes (MMbtu) . . . . . . . . . . 722,200 - - 1,777,800 - - Average floor price (per MMbtu) $ 4.613 $ - - $ 4.319 $ - - Average ceiling price (per MMbtu) 6.476 - - 6.847 - - Loss upon settlement (in thousands) $ (160) $ - - $ (414) $ - - NATURAL GAS FLOORS Volumes (MMbtu) . . . . . . . . . . - 460,000 (100%) - 610,000 (100%) Average floor price (per MMbtu) . . $ - $ 4.50 (100%) $ - $ 4.500 (100%) Loss upon settlement (in thousands) $ - $ - - $ - $ - - Other revenue. Fees that we charge other parties who use our two gas gathering systems to move their production from the wellhead to third party gas pipeline systems are recorded as other revenue. These gathering systems are owned by us and located in the Texas Gulf Coast. One of the gathering systems connects a single well and the other connects two wells. Other revenue for the third quarter of 2004 was $27,000 compared to $32,000 in the third quarter last year. Other revenue for the nine months of 2004 was $69,000 compared to $113,000 during the first nine months of 2003. 22 Production cost. Production costs include lease operating expenses and production taxes. The following table presents our production cost for the third quarter and first nine months of 2004 and 2003. THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, ------------------------------------------- ------------------------------------------ % % 2004 2003 CHANGE 2004 2003 CHANGE ------------ ------------- -------------- ----------- ------------- -------------- (IN THOUSANDS) Operating and maintenance expenses $ 1,201 $ 1,061 13% $ 3,248 $ 2,678 21% Workover expenses. . . . . . . . . 278 563 (51%) 617 860 (28%) Ad valorem taxes . . . . . . . . . 169 169 0% 497 499 (0%) ------------ ------------- -------------------------- Lease operating expenses . . . $ 1,648 $ 1,793 (8%) $ 4,362 $ 4,037 8% Production taxes . . . . . . . . . 675 553 22% 2,434 2,297 6% ------------ ------------- -------------------------- Total production cost. . . . . $ 2,323 $ 2,346 (1%) $ 6,796 $ 6,334 7% ============ ============= ========================== (PER MCFE) Operating and maintenance expenses $ 0.39 $ 0.41 (5%) $ 0.35 $ 0.33 6% Workover expenses. . . . . . . . . 0.09 0.22 (59%) 0.07 0.11 (36%) Ad valorem taxes . . . . . . . . . 0.06 0.06 0% 0.05 0.06 (17%) ------------ ------------- -------------------------- Lease operating expenses . . . $ 0.54 $ 0.69 (22%) $ 0.47 $ 0.50 (6%) Production taxes . . . . . . . . . 0.22 0.21 5% 0.26 0.29 (10%) ------------ ------------- -------------------------- Total production cost. . . . . $ 0.76 $ 0.90 (16%) $ 0.73 $ 0.79 (8%) ============ ============= ========================== Lease operating expenses - ------------------------ Lease operating expenses are comprised of several components which include: the cost of labor and supervision to operate the wells and related equipment; repairs and maintenance; related materials, supplies, fuel, and supplies utilized in operating the wells and related equipment and facilities; insurance applicable to wells and related facilities and equipment; workover cost; and ad valorem taxes. Lease operating expenses are driven in part by the type of commodity produced, the level of workover activity and the geographical location of the properties. Oil is inherently more expensive to produce than natural gas. Local taxing authorities such as school districts, cities, and counties or boroughs generally impose the ad valorem taxes we pay. The amount of the tax is based on the value of the property assessed or determined by the taxing authority on an annual basis, and a percent of value. When oil and natural gas commodity prices rise, the value of our underlying property interests increase. This results in higher ad valorem taxes. Lease operating expenses for the third quarter 2004 were 8% lower than lease operating expenses in the third quarter last year. The change was primarily due to the following: - - A decrease in the cost of expensed workovers led to a 51% decrease in workover costs for the third quarter of this year. - - This decrease was partially offset by an increase in our operating and maintenance expenses due to an increase in the number of producing wells. On a unit basis, lease operating expenses for the third quarter 2004 were 22% lower than in the third quarter last year due to the decrease in workover cost and an increase in production volumes. 23 Lease operating expenses for the first nine months of 2004 were 8% higher than lease operating expenses during the first nine months of 2003. The change was primarily due to the following: - - An increase in the number of producing wells in the first nine months of 2004. - - An increase in the amount spent for compressor rental and maintenance and saltwater disposal. - - These increases were partially offset by a decrease in the cost of expensed workovers during the first nine months of 2004. On a unit basis, lease operating expenses for the first nine months of 2004 were 6% lower than our per unit lease operating expenses in the same period of the prior year. The change in our per unit lease operating expense was primarily due an increase in production volumes during the first nine months of 2004 combined with the following: - - A decrease in the cost of expensed workovers during the first nine months of 2004. - - A $0.01 increase in our unit cost for both compressor and rental maintenance and saltwater disposal. Production taxes - ---------------- There are a variety of state and federal taxes levied on the production of our oil and natural gas. These are commonly grouped together and referred to as production taxes. The majority of our production tax expense is based on a percent of gross value at the well at the time the production is sold or removed from the lease. As a result, our production tax expense increases with increases in crude oil and natural gas commodity prices. Historically, taxing authorities have occasionally encouraged oil and gas industry to explore for new oil and natural gas reserves, or develop high cost reserves through reduced tax rates or credits. These incentives have been narrow in scope and short-lived. A small number of our wells currently qualify for reduced production taxes because they are discoveries based on the use of 3-D seismic or high cost wells. An increase in our third quarter 2004 production volumes combined with a 10% increase in the average pre-hedge sales price that we received for our oil and natural gas in the third quarter 2004 were the primary reasons for the increase in production taxes. These increases were partially offset by reduced tax rates or tax credits on certain wells. Production taxes for the third quarter 2004 were 3.7% of revenue from the sale of oil and natural gas before gains and losses due to hedging, compared to 3.9% in the third quarter last year. The increase in production taxes for the first nine months of 2004 was primarily due to an increase in production volumes during the first nine months of 2004. This increase was partially offset by reduced tax rates or tax credits on certain wells. Production taxes for the first nine months of 2004 were 4.4% of revenue from the sale of oil and natural gas before gains and losses due to hedging, compared to 5% in the first nine months of last year. 24 General and administrative expenses. We capitalize a portion of our general and administrative costs. The costs capitalized represent the cost of technical employees, who work directly on capital projects. An engineer designing a well is an example of a technical employee working on a capital project. The cost of a technical employee includes associated technical organization costs such as supervision, telephone and postage. The following table presents general and administrative expenses for the third quarter and first nine months of 2004 and 2003. THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, ----------------------------------------- ------------------------------------------- % % 2004 2003 CHANGE 2004 2003 CHANGE ---------- ------------- -------------- ------------ ------------- -------------- (IN THOUSANDS) General and administrative expenses. $ 1,304 $ 1,094 19% $ 3,723 $ 3,420 9% (PER MCFE) General and administrative expenses. $ 0.43 $ 0.42 2% $ 0.40 $ 0.43 (7%) General and administrative expenses for the third quarter of 2004 were 19% higher than general and administrative expenses in the third quarter last year. The change in our general and administrative expenses for the for the third quarter 2004 was due to the following: - - A 19% increase in payroll and employee benefit expenses net of amounts charged to joint ventures to cover the costs of managing these joint operations represented approximately 35% of the total increase. - - A 162% increase in expenses paid to outside consultants and our independent public accountants. These increases, which were represented approximately 40% of the total increase in our general and administrative expenses, were related to additional costs associated with the implementation of Sarbanes-Oxley Section 404. - - An increase in expenses paid to our external reserve engineers represented approximately 11% of the total increase in our general and administrative expenses. - - These increases were partially offset by a decrease in financial reporting expenses, a decrease in office rent and a decrease in legal fees. General and administrative expenses for the first nine months of 2004 increased by 9% over general and administrative expenses during the first nine months of 2003. The change in our general and administrative expenses for the for the first nine months of 2004 was due to the following: - - An 11% increase in payroll and employee benefit expenses net of amounts charged to joint ventures to cover the costs of managing these joint operations represented approximately 58% of the total increase. - - A 60% increase in expenses paid to our independent public accountants primarily related to additional cost associated with the implementation of Sarbanes-Oxley Section 404 represented approximately 14% of the total increase. - - An increase in expenses paid to our external reserve engineers represented approximately 12% of the total increase in general and administrative expenses. - - An increase in expenses for corporate insurance expense represented approximately 5% of the increase. - - These increases were partially offset by a decrease in cost for financial reporting and fees paid to our directors. 25 Depletion of oil and natural gas properties. Our full-cost depletion expense is driven by many factors including certain costs spent in the exploration and development of producing reserves, production levels, and estimates of proved reserve quantities and future developmental costs at the end of the year. The following table presents depletion expense for the third quarter and first nine months of 2004 and 2003. THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, -------------------------------------- -------------------------------------- % % 2004 2003 CHANGE 2004 2003 CHANGE ----------- --------- -------------- ---------------------- -------------- (IN THOUSANDS) Depletion of oil and natural gas properties. $ 5,871 $ 3,952 49% $ 16,374 $ 11,853 38% (PER MCFE) Depletion rate . . . . . . . . . . . . . . . $ 1.92 $ 1.52 26% $ 1.78 $ 1.48 20% Increased production volumes combined with a $0.40 increase in our depletion rate resulted in a 49% increase in our third quarter 2004 depletion expense. Higher production volumes accounted for approximately 36% of this increase while the increase in our depletion rate accounted for 64% of the increase. The increase in our depletion rate was primarily the result of increased cost of reserve additions during the first nine months of 2004. Increased production volumes combined with a $0.30 increase in our depletion rate resulted in a 20% increase in our depletion expense for the first nine months of 2004. Higher production volumes accounted for approximately 39% of the increase while the increase in our depletion rate accounted for the remaining 61%. The increase in our depletion rate was primarily the result of increased cost of reserve additions during the first nine months of 2004. 26 Net interest expense. We capitalize interest expense on borrowings associated with major capital projects prior to their completion. Capitalized interest is added to the cost of the underlying assets and is amortized over the lives of the assets. The following table presents interest expense for the third quarter and first nine months of 2004 and 2003. THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED ---------------------------------------- ----------------------- % 2004 2003 CHANGE 2004 2003 ------------ ---------- -------------- ----------- ---------- (IN THOUSANDS) Interest on senior credit facility. . . . . . . . . . . . $ 215 $ 418 (49%) $ 649 $ 1,563 Interest on senior subordinated notes (a) . . . . . . . . 436 612 (29%) 1,320 1,792 Commitment fees . . . . . . . . . . . . . . . . . . . . . 64 10 540% 171 45 Dividend on mandatorily redeemable preferred stock (b)(c). . . . . . . . . . . . . . . . 184 161 14% 538 161 Amortization of deferred loan and debt issuance cost. . . 191 276 (31%) 574 809 Other general interest expense. . . . . . . . . . . . . . 6 6 0% 20 34 Capitalized interest expense. . . . . . . . . . . . . . . (224) (212) 6% (764) (627) ------------ ---------- ----------------------- Net interest expense. . . . . . . . . . . . . . . . . . . $ 872 $ 1,271 (31%) $ 2,508 $ 3,777 ============ ========== ======================= Weighted average debt outstanding . . . . . . . . . . . . $ 54,508 $ 79,659 (32%) $ 57,275 $ 77,070 Average interest rate on outstanding indebtedness (d) . . 6.6% 6.0% 6.2% 6.2% (a) Interest expense on our senior subordinated notes paid in kind through the issuance of additional debt in lieu of cash. Our option to pay interest in kind on our senior subordinated notes expired in October 2003. . . . . . . . . . . . . . . . . . . . . $ - $ 306 $ - $ 896 (b) Shares of mandatorily redeemable Series A preferred stock issued to satisfy dividends paid in kind. The dividend on our Seri1es A preferred stock in the first two quarters of 2003 was recorded as dividends in dividends and accretion. Our option to pay dividends in kind on our Series A preferred stock expires in October 2005. See further discussion later in net interest expense section and in dividends and accretion section. . . . 9,202 37,024 26,877 107,852 (c) Shares of mandatorily redeemable Series Bpreferred stock issued to satisfy dividends paid in kind. The dividend on our Series B preferred stock in the first two quarters of 2003 was recorded as dividends in dividends and accretion. In the fourth quarter of 2003, CSFB Private Equity used a portion of our mandatorily redeemable Series B preferred stock that it held to pay for the exercise of warrants. We redeemed the remaining balance of Series B preferred stock that was not used to pay for the exercise. See further discussion later in net interest expense section and in dividends and accretion section . . . . . . . . . . . . . . . . . . - 10,086 - 30,603 SEPTEMBER 30, -------------- % CHANGE -------------- Interest on senior credit facility. . . . . . . . . . . . (58%) Interest on senior subordinated notes (a) . . . . . . . . (26%) Commitment fees . . . . . . . . . . . . . . . . . . . . . 280% Dividend on mandatorily redeemable preferred stock (b)(c). . . . . . . . . . . . . . . . 234% Amortization of deferred loan and debt issuance cost. . . (29%) Other general interest expense. . . . . . . . . . . . . . (41%) Capitalized interest expense. . . . . . . . . . . . . . . 22% Net interest expense. . . . . . . . . . . . . . . . . . . (34%) Weighted average debt outstanding . . . . . . . . . . . . (26%) Average interest rate on outstanding indebtedness (d) (a) Interest expense on our senior subordinated notes paid in kind through the issuance of additional debt in lieu of cash. Our option to pay interest in kind on our senior subordinated notes expired in October 2003. (b) Shares of mandatorily redeemable Series A preferred stock issued to satisfy dividends paid in kind. The dividend on our Seri1es A preferred stock in the first two quarters of 2003 was recorded as dividends in dividends and accretion. Our option to pay dividends in kind on our Series A preferred stock expires in October 2005. See further discussion later in net interest expense section and in dividends and accretion section (c) Shares of mandatorily redeemable Series Bpreferred stock issued to satisfy dividends paid in kind. The dividend on our Series B preferred stock in the first two quarters of 2003 was recorded as dividends in dividends and accretion. In the fourth quarter of 2003, CSFB Private Equity used a portion of our mandatorily redeemable Series B preferred stock that it held to pay for the exercise of warrants. We redeemed the remaining balance of Series B preferred stock that was not used to pay for the exercise. See further discussion later in net interest expense section and in dividends and accretion section (d) Calculated as the sum of interest expense on outstanding indebtedness, commitment fees and dividend on our Series A mandatorily redeemable preferred stock divided by the weighted average debt and preferred stock outstanding for the period. 27 Interest expense for the third quarter 2004 was 34% lower than interest expense in the same quarter of the prior year. The change in interest expense was primarily due to the following: - - A decrease in the weighted average debt outstanding under our senior credit facility resulted in a $203,000 decrease in interest expense for the third quarter of 2004. This decrease was offset by a $54,000 increase in the commitment fees we paid on the unused portion of our borrowing base. - - A decrease in the amount of subordinated notes outstanding during the third quarter this year combined with a decrease in the interest rate we paid on our senior subordinated notes resulted in a $176,000 decrease in interest expense. - - An increase in the amount of interest we capitalized. - - An increase in the dividend that we paid on our mandatorily redeemable preferred stock. Interest expense for the first nine months of 2004 was 34% lower than interest expense during the first nine months of 2003. The change was due to the following: - - A decrease in the weighted average debt outstanding under our senior credit facility combined with a decrease in the interest rate that we paid on those borrowings resulted in a $914,000 decrease in interest expense. This decrease was partially offset by a $126,000 increase in the commitment fees that we paid on the unused portion of our borrowing base. - - A decrease in the amount of subordinated notes outstanding combined with a decrease in the interest rate we paid on our senior subordinated notes resulted in a $472,000 decrease in interest expense. - - An increase in the amount of interest we capitalized. - - An increase in the dividend that we paid on our manadatorily redeemable preferred stock. Upon our adoption of SFAS 150 in July 2003, we reclassified approximately $8 million of our then outstanding mandatorily redeemable Series A and Series B preferred stock, which had no equity conversion features and must be settled with our assets, to long-term debt. As part of this reclassification, we now report the dividends on the mandatorily redeemable preferred stock that was reclassified as interest expense. Prior to this reclassification, the dividend on our mandatorily redeemable preferred stock was reported as dividends in dividend and accretion of mandatorily redeemable preferred stock. Other income (expense). Other income (expense) primarily includes non-cash gains (losses) resulting from the change in fair market value of oil and natural gas derivative contracts that were not designated as cash flow hedges, cash gains (losses) on the settlement of these contracts and non-cash gains (losses) related to charges for the ineffective portions of cash flow hedges. THREE MONTHS ENDED SEEMBER 30, NNE MONTHS ENDED SEEMBER 30, -------------------------------------- ------------------------------------ % % 2004 2003 CHANGE 2004 2003 CHANGE ------------ ---------- ------------ ---------------------- ------------ (IN THOUSANDS) Market value adjustment for derivative contracts. $ (167) $ (80) 109% $ (227) $ (250) (9%) Other income. . . . . . . . . . . . . . . . . . . (1) - - 68 - - ------------ ---------- ---------------------- Total other income (expense). . . . . . . . . . $ (168) $ (80) 110% $ (159) $ (250) (36%) ============ ========== ====================== 28 Income taxes. Since inception, we have not been required to recognize any current income taxes. Furthermore, we do not expect to recognize significant, if any, current income taxes in 2004. Since inception, we have generated net operating losses (NOLs) due mainly to intangible drilling and other property related deductions, which have exceeded taxable income. Our regular NOLs are $101.8 million, and our alternative minimum tax NOLs are $87.6 million. To date, we have not utilized any of our NOLs. In future periods, our NOLs will be used to offset taxable income. Since 1997 through the third quarter of 2003, we have not been required to recognize any deferred income taxes. Due to the level of projected net taxable income, we expect to evolve from a net deferred tax asset to a net deferred tax liability position during 2004. It is management's belief that we will begin to utilize our NOLs and will have reversals of existing temporary differences between book and taxable income such that a net deferred tax liability is expected at year-end 2004, as well as in future years. Accordingly, we recognized deferred tax expense of $7.2 million during the first nine months of 2004. Dividends and accretion of mandatorily redeemable preferred stock. We are required to pay dividends on our Series A and were required to pay dividends on our Series B preferred stock prior to its redemption. At our option, these dividends could be paid in cash at a rate of 6% per annum or paid in kind through the issuance of additional shares of preferred stock in lieu of cash at a rate of 8% per annum. We elected to pay dividends in kind in each quarter of 2004 and 2003. Upon our adoption of SFAS 150 in July 2003, approximately $8 million of our then outstanding mandatorily redeemable Series A and Series B preferred stock that must be settled with our assets, was reclassified to long-term debt. As part of the reclassification, the dividend paid on the reclassified amount since July 2003 has been reported as interest expense. In November and December 2003, CSFB Private Equity used a portion of our mandatorily redeemable Series A and Series B preferred stock that it held to pay for the exercise of the associated warrants. We also redeemed the remaining balance of Series B preferred stock that was not used to pay for the exercise. The following table shows the effect for the three and nine-month periods ended September 30, 2004 and 2003, of the issuance of additional shares of preferred stock in lieu of paying cash dividends. THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, ------------------------------------ ------------------------------------ % % 2004 2003 CHANGE 2004 2003 CHANGE ----------- --------- ------------ ---------------------- ------------ (IN THOUSANDS) Dividends . . . . . . . . . . . . . . . $ - $ 789 - $ - $ 2,606 - Accretion of redeemable preferred stock - 115 - - 321 - ----------- --------- ---------------------- Total dividends and accretion . . . . $ - $ 904 - $ - $ 2,927 - =========== ========= ====================== OTHER MATTERS Effects of Inflation and Changes in Prices Our results of operations and cash flows are affected by changing oil and gas prices. If the price of oil and natural gas increases (decreases), there could be a corresponding increase (decrease) in revenues as well as the operating costs that we are required to bear for operations. Inflation has had a minimal effect on us. Environmental and Other Regulatory Matters Our business is subject to certain federal, state and local laws and regulations relating to the exploration for and the development, production and marketing of oil and natural gas, as well as environmental and safety matters. Many 29 of these laws and regulations have become more stringent in recent years, often imposing greater liability on a larger number of potentially responsible parties. Although we believe we are in substantial compliance with all applicable laws and regulations, the requirements imposed by laws and regulations are frequently changed and subject to interpretation, and we cannot predict the ultimate cost of compliance with these requirements or their effect on our operations. Any suspensions, terminations or inability to meet applicable bonding requirements could materially adversely affect our financial condition and operations. Although significant expenditures may be required to comply with governmental laws and regulations applicable to us, compliance has not had a material adverse effect on our earnings or competitive position. Future regulations may add to the cost of, or significantly limit, drilling activity. New Accounting Pronouncements In September 2004, the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin No. 106. This pronouncement will require companies that use the full cost method for accounting for their oil and gas producing activities to include an estimate of future asset retirement costs to be incurred as a result of future development activities on proved reserves in their calculation of depreciation, depletion and amortization. This pronouncement will also require these companies to exclude any future cash outflows associated with settling asset retirement liabilities from their full cost ceiling test calculation. This standard will also require these companies to disclose the impact of their asset retirement obligations on their oil and gas producing activities, ceiling test calculations and depreciation, depletion and amortization calculations. We will adopt the provisions of this pronouncement in the fourth quarter of 2004 and are currently evaluating the impact, if any, on our consolidated financial statements. Risk Factors Related to Our Business - Our level of indebtedness may adversely affect our cash available for operations, thus limiting our growth, our ability to make interest and principal payments on our indebtedness as they become due and our flexibility to respond to market changes. - We have substantial capital requirements for which we may not be able to obtain adequate financing. - Oil and natural gas prices fluctuate widely and low prices could have a material adverse impact on our business and financial results by limiting our liquidity and flexibility to accelerate our drilling program. - Our hedging transactions could reduce revenues in a rising commodity price environment or expose us to other risks. - Exploratory drilling is a speculative activity that may not result in commercially productive reserves and may require expenditures in excess of budgeted amounts. - We are subject to various operating and other casualty risks that could result in liability exposure or the loss of production and revenues. - We may not have enough insurance to cover all of the risks we face, which could result in significant financial exposure. - We cannot control the activities on properties we do not operate and are unable to ensure their proper operation and profitability. - The marketability of our natural gas production depends on facilities that we typically do not own or control, which could result in a curtailment of production and revenues. - Lower oil and natural gas prices may cause us to record ceiling limitation write-downs which would reduce our stockholders' equity. - We have had operating losses in the past and may not be profitable in the future. - Our future operating results may fluctuate and significant declines in them would limit our ability to invest in projects. - The failure to replace reserves in the future would adversely affect our production and cash flows. - We are subject to uncertainties in reserve estimates and future net cash flows. - We face significant competition, and many of our competitors have resources in excess of our available resources. 30 - We are subject to various governmental regulations and environmental risks which may cause us to incur substantial costs. - Our business may suffer if we lose key personnel. Disclosure Regarding Forward-Looking Statements Statements included in this report which are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), are forward-looking statements. These statements can be identified by the use of forward-looking terminology including "may," "believe," "will," "expect," "anticipate," "estimate," "continue" or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other "forward-looking" information. These forward-looking statements are made based upon management's current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under "Risk Factors Related to Our Business," and elsewhere in this report. You should read these statements carefully because they discuss our expectations about our future performance, contain projections of our future operating results or our future financial condition, or state other "forward-looking" information. You should be aware that the occurrence of any of the events described in "Risk Factors Related to Our Business" and elsewhere in this report could substantially harm our business, results of operations and financial condition and that upon the occurrence of any of these events, the trading price of our common shares could decline. 31 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK The following quantitative and qualitative disclosures about market risk are supplementary to the quantitative and qualitative disclosures provided in our Annual Report on Form 10-K for the fiscal year ended December 31, 2003. As such, the information contained herein should be read in conjunction with the related disclosures in our Annual Report on Form 10-K for the fiscal year ended December 31, 2003. DERIVATIVE CONTRACTS CASH-FLOW HEDGES Our cash-flow hedges consisted of fixed-price swaps and costless collars (purchased put options and written call options). The fixed-price swap agreements are used to fix the prices of anticipated future oil and natural gas production. The costless collars are used to establish floor and ceiling prices on anticipated future oil and natural gas production. There were no net premiums received when we entered into these option agreements. DERIVATIVES NOT DESIGNATED AS HEDGES Our derivative positions included option contracts that are not designated as hedges. These positions were entered into to offset the cost of other option positions that are designated as hedges. NOTIONAL AMOUNT -------------------- NYMEX SETTLEMENT DERIVATIVE HEDGE GAS OIL REFERENCE PERIOD INSTRUMENT STRATEGY (MMBTU) (BARRELS) PRICE - ----------------- ------------- ------------ --------- --------- ---------- 10/01/04-12/31/04 Swap Cash flow 92,000 $ 4.36 10/01/04-12/31/04 Swap Cash flow 9,200 23.80 COSTLESS COLLARS 10/01/04-10/31/04 Purchased put Cash flow 34,100 $ 4.00 Written call Cash flow 34,100 6.83 10/01/04-10/31/04 Purchased put Cash flow 6,200 26.00 Written call Cash flow 6,200 33.50 10/01/04-12/31/04 Purchased put Cash flow 92,000 4.00 Written call Cash flow 92,000 5.62 10/01/04-12/31/04 Purchased put Cash flow 92,000 4.25 Written call Cash flow 92,000 5.51 10/01/04-12/31/04 Purchased put Cash flow 46,000 4.25 Written call Cash flow 46,000 6.05 10/01/04-12/31/04 Purchased put Cash flow 322,000 5.25 Written call Cash flow 322,000 7.41 10/01/04-12/31/04 Purchased put Cash flow 9,200 23.00 Written call Cash flow 9,200 25.39 10/01/04-12/31/04 Purchased put Cash flow 6,900 23.00 Written call Cash flow 6,900 27.30 10/01/04-12/31/04 Purchased put Cash flow 11,960 32.00 Written call Cash flow 11,960 38.15 01/01/05-03/31/05 Purchased put Cash flow 90,000 4.00 Written call Cash flow 90,000 7.25 32 NOTIONAL AMOUNT -------------------- NYMEX SETTLEMENT DERIVATIVE HEDGE GAS OIL REFERENCE PERIOD INSTRUMENT STRATEGY (MMBTU) (BARRELS) PRICE - ----------------- ------------- ------------ --------- --------- ---------- 01/01/05-03/31/05 Purchased put Cash flow 67,500 4.25 Written call Cash flow 67,500 5.90 01/01/05-03/31/05 Purchased put Cash flow 45,000 4.25 Written call Cash flow 45,500 6.50 01/01/05-03/31/05 Purchased put Cash flow 9,000 23.00 Written call Cash flow 9,000 25.07 01/01/05-03/31/05 Purchased put Cash flow 6,750 23.00 Written call Cash flow 6,750 26.90 01/01/05-06/30/05 Purchased put Cash flow 633,500 5.00 Written call Cash flow 633,500 7.40 01/01/05-06/30/05 Purchased put Cash flow 23,530 29.00 Written call Cash flow 23,530 36.00 04/01/05-06/30/05 Purchased put Cash flow 91,000 4.00 Written call Cash flow 91,000 5.40 04/01/05-06/30/05 Purchased put Cash flow 45,500 4.25 Written call Cash flow 45,500 4.52 04/01/05-06/30/05 Purchased put Cash flow 6,825 23.00 Written call Cash flow 6,825 26.45 THREE WAY COSTLESS 11/01/04-3/31/05 Purchased put Cash flow 350,000 $ 6.40 Written call Cash flow 350,000 7.64 Written put Undesignated 350,000 5.50 ITEM 4. CONTROLS AND PROCEDURES EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES As of the end of period covered by this report, our principal executive officer and principal financial officer carried out an evaluation of the effectiveness of our disclosure controls and procedures. Based on their evaluation, they have concluded that our disclosure controls and procedures effectively ensure that the information required to be disclosed in the reports we file with the SEC is recorded, processed, summarized and reported within the time periods specified by the SEC. CHANGES IN INTERNAL CONTROLS There were no changes in our internal controls or in other factors that have materially affected, or are reasonably likely to materially affect, our internal controls subsequent to the date of their evaluation of our disclosure controls and procedures. 33 PART II - OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS As discussed in Note 3 of Notes to the Consolidated Financial Statements included in Part I. Financial Information, Brigham is party to various legal actions arising in the ordinary course of business and does not expect these matters to have a material adverse effect on its financial condition, results of operations or cash flow. ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS None. No purchases were made under a publicly announced plan. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K 31.1 Certification of Chief Executive Officer of the Company pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 31.2 Certification of Chief Financial Officer of the Company pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 32.1 Certification of Chief Executive Officer of the Company pursuant to 18 U.S.C. Sec. 1350 32.2 Certification of Chief Financial Officer of the Company pursuant to 18 U.S.C. Sec. 1350 34 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on November 9, 2004. BRIGHAM EXPLORATION COMPANY By: /s/ BEN M. BRIGHAM ------------------ Ben M. Brigham Chief Executive Officer, President and Chairman of the Board By: /s/ EUGENE B. SHEPHERD, JR. --------------------------- Eugene B. Shepherd, Jr. Executive Vice President and Chief Financial Officer 35