-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, F64BgvgVq4hOod7yVAPjrarqYpTVLuV3ty4ylZT7p/Odo5ROjJHqmS590Bckdx1H DQVAJAxIlUCXdPC/Gi4ArQ== 0001015402-04-003392.txt : 20040816 0001015402-04-003392.hdr.sgml : 20040816 20040813173140 ACCESSION NUMBER: 0001015402-04-003392 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20040630 FILED AS OF DATE: 20040816 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BRIGHAM EXPLORATION CO CENTRAL INDEX KEY: 0001034755 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 752692967 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 000-22433 FILM NUMBER: 04975538 BUSINESS ADDRESS: STREET 1: 6300 BRIDGE POINT PARKWAY STREET 2: BLDG 2 SUITE 500 CITY: AUSTIN STATE: TX ZIP: 78730 BUSINESS PHONE: 5124273300 MAIL ADDRESS: STREET 1: 6300 BRIDGE POINT PARKWAY STREET 2: BLDG 2 SUITE 500 CITY: AUSTIN STATE: TX ZIP: 78730 10-Q 1 doc1.txt ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended June 30, 2004 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from __________ to __________ Commission File Number: 000-22433 Brigham Exploration Company (Exact name of registrant as specified in its charter) Delaware 1311 75-2692967 (State of other jurisdiction (Primary Standard Industrial (I.R.S. Employer of incorporation or organization) Classification Code Number) Identification Number) 6300 Bridge Point Parkway, Building 2, Suite 500, Austin, Texas 78730 (Address of principal executive offices) (512) 427-3300 (Registrant's telephone number, including area code) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12 b-2 of the Act). Yes [ ] No [X] Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Class Outstanding ----- ----------- Common Stock, par value $.01 per share as of August 13, 2004 41,985,615 ================================================================================ Brigham Exploration Company Second Quarter 2004 Form 10-Q Report TABLE OF CONTENTS ----------------- Page ---- PART I - FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS Consolidated Balance Sheets - June 30, 2004 and December 31, 2003. . . . . . . . . . . . . . . . . . . . . . . . . . 1 Consolidated Statements of Operations - Three and six months ended June 30, 2004 and 2003 . . . . . . . . . . . . . 2 Consolidated Statement of Stockholders' Equity - Six months ended June 30, 2004. . . . . . . . . . . . . . . . . . . . . 3 Consolidated Statements of Cash Flows - Six months ended June 30, 2004 and 2003. . . . . . . . . . . . . . . . . . . . . . . 4 Notes to the Consolidated Financial Statements. . . . . . . . . 5 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS . . . . . . . . . . . . . . 14 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. . 31 ITEM 4. CONTROLS AND PROCEDURES. . . . . . . . . . . . . . . . . . . . . . 32 PART II - OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS . . . . . . . . . . . . . . . . . . . . . . . . .33 ITEM 2. CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES. . . . . . . . . . . . . . . . . . .33 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS. . . . . .33 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K. . . . . . . . . . . . . . . .35 SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .36
BRIGHAM EXPLORATION COMPANY CONSOLIDATED BALANCE SHEETS (in thousands, except share data) (unaudited) June 30, December 31, 2004 2003 ------------ -------------- ASSETS (Unaudited) Current assets: Cash and cash equivalents $ 11,111 $ 5,779 Accounts receivable 14,972 11,143 Deferred income taxes 842 307 Other current assets 738 3,606 ------------ -------------- Total current assets 27,663 20,835 ------------ -------------- Oil and natural gas properties, net (full cost method) 226,715 197,311 Other property and equipment, net 1,195 1,219 Deferred income taxes - 1,890 Deferred loan fees 2,128 2,501 Other noncurrent assets 562 460 ------------ -------------- Total assets $ 258,263 $ 224,216 ============ ============== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable $ 19,240 $ 19,806 Royalties payable 7,505 5,280 Accrued drilling costs 5,270 3,916 Participant advances received 698 1,179 Other current liabilities 3,553 5,398 ------------ -------------- Total current liabilities 36,266 35,579 ------------ -------------- Senior credit facility 36,700 19,000 Senior subordinated notes 20,000 20,000 Series A Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and redemption value, 2,250,000 shares authorized, 457,397 and 439,722 shares issued and outstanding at June 30, 2004 and December 31, 2003, respectively 9,148 8,794 Deferred income taxes 3,844 - Other noncurrent liabilities 3,017 2,498 Commitments and contingencies Stockholders' equity: Preferred stock, $.01 par value, 10 million shares authorized, of which 2,250,000 and 1,000,000 shares are designated as Series A and Series B, respectively - - Common stock, $.01 par value, 50 million shares authorized, 40,526,893 and 40,246,729 shares issued and 39,345,541 and 39,086,096 shares outstanding at June 30, 2004 and December 31, 2003, respectively 405 402 Additional paid-in capital 152,241 151,263 Treasury stock, at cost; 1,181,352 and 1,160,633 shares at June 30, 2004 and December 31, 2003, respectively (4,562) (4,402) Unearned stock compensation (1,881) (1,816) Accumulated other comprehensive income (loss) (1,012) (1,040) Retained earnings (Accumulated deficit) 4,097 (6,062) ------------ -------------- Total stockholders' equity 149,288 138,345 ------------ -------------- Total liabilities and stockholders' equity $ 258,263 $ 224,216 ============ ==============
The accompanying notes are an integral part of these consolidated financial statements. 1
BRIGHAM EXPLORATION COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per share data) (unaudited) Three Months Ended Six Months Ended June 30, June 30, -------------------------------------- 2004 2003 2004 2003 -------- -------- -------- -------- Revenues: Oil and natural gas sales $17,916 $12,127 $34,735 $26,766 Other revenue 41 43 42 81 -------- -------- -------- -------- 17,957 12,170 34,777 26,847 -------- -------- -------- -------- Costs and expenses: Lease operating 1,305 1,270 2,714 2,244 Production taxes 896 806 1,759 1,744 General and administrative 1,199 1,187 2,419 2,326 Depletion of oil and natural gas properties 5,623 3,799 10,503 7,901 Depreciation and amortization 184 160 365 257 Accretion of discount on asset retirement obligations 40 37 77 71 -------- -------- -------- -------- 9,247 7,259 17,837 14,543 -------- -------- -------- -------- Operating income 8,710 4,911 16,940 12,304 -------- -------- -------- -------- Other income (expense): Interest income 15 7 29 28 Interest expense (854) (1,224) (1,636) (2,506) Other income (expense) (118) (281) 9 (170) -------- -------- -------- -------- (957) (1,498) (1,598) (2,648) -------- -------- -------- -------- Income before income taxes and cumulative effect of change in accounting principle 7,753 3,413 15,342 9,656 -------- -------- -------- -------- Income tax expense: Current - - - - Deferred (2,683) - (5,183) - -------- -------- -------- -------- (2,683) - (5,183) - -------- -------- -------- -------- Income before cumulative effect of change in accounting principle 5,070 3,413 10,159 9,656 Cumulative effect of change in accounting principle - - - 268 -------- -------- -------- -------- Net income 5,070 3,413 10,159 9,924 Less accretion and dividends on redeemable preferred stock - 1,028 - 2,023 -------- -------- -------- -------- Net income available to common stockholders $ 5,070 $ 2,385 $10,159 $ 7,901 ======== ======== ======== ======== Net income per share available to common stockholders: Basic Income before cumulative effect of change in accounting principle $ 0.13 $ 0.12 $ 0.26 $ 0.39 Cumulative effect of change in accounting principle - - - 0.01 -------- -------- -------- -------- $ 0.13 $ 0.12 $ 0.26 $ 0.40 ======== ======== ======== ======== Diluted Income before cumulative effect of change in accounting principle $ 0.13 $ 0.10 $ 0.25 $ 0.29 Cumulative effect of change in accounting principle - - - 0.01 -------- -------- -------- -------- $ 0.13 $ 0.10 $ 0.25 $ 0.30 ======== ======== ======== ======== Weighted average shares outstanding: Basic 39,287 20,087 39,261 19,898 ======== ======== ======== ======== Diluted 40,391 30,037 40,354 32,090 ======== ======== ======== ========
The accompanying notes are an integral part of these consolidated financial statements. 2
BRIGHAM EXPLORATION COMPANY CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (in thousands) (unaudited) Accumulated Retained Common Stock Additional Unearned Other Earnings --------------------- Paid In Treasury Stock Comprehensive (Accumulated Shares Amounts Capital Stock Compensation Income (Loss) Deficit) ----------- --------- -------- ---------------- -------------- --------------- ---------- Balance, December 31, 2003 40,247 $ 402 $151,263 $ (4,402) $ (1,816) $ (1,040) $ (6,062) Comprehensive income: Net income - - - - - - 10,159 Unrealized gain (losses) on cash flow hedges - - - - - (16) - Tax provisions related to cash flow hedges - - - - - (16) - Net losses realized and included in net income - - - - - 60 - Comprehensive income Exercises of employee stock options 208 2 596 - - - - Issuance of restricted stock - - 514 - (514) - - Vesting of restricted stock 72 1 (1) - - - - Forfeitures of restricted stock - - (131) (4) 131 - - Repurchases of common stock - - - (156) - - - Amortization of unearned stock compensation - - - - 318 - - ----------- --------- -------- --------------- -------------- --------------- ---------- Balance, June 30, 2004 40,527 $ 405 $152,241 $ (4,562) $ (1,881) $ (1,012) $ 4,097 =========== ========= ======== ================ ============== =============== ========= Total Stockholders' Equity ------------- Balance, December 31, 2003 $ 138,345 Comprehensive income: Net income 10,159 Unrealized gain (losses) on cash flow hedges (16) Tax provisions related to cash flow hedges (16) Net losses realized and included in net income 60 ------------- Comprehensive income 10,187 Exercises of employee stock options 598 Issuance of restricted stock - Vesting of restricted stock - Forfeitures of restricted stock (4) Repurchases of common stock (156) Amortization of unearned stock compensation 318 ------------- Balance, June 30, 2004 $ 149,288 =============
The accompanying notes are an integral part of these consolidated financial statements. 3
BRIGHAM EXPLORATION COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands) (unaudited) Six Months Ended June 30, -------------------- 2004 2003 --------- --------- Cash flows from operating activities: Net income $ 10,159 $ 9,924 Adjustments to reconcile net income to cash provided by operating activities: Depletion of oil and natural gas properties 10,503 7,901 Depreciation and amortization 365 257 Interest paid through issuance of additional senior subordinated notes - 585 Interest paid through issuance of additional mandatorily redeemable preferred stock 354 - Amortization of deferred loan fees and debt issuance costs 383 533 Market value adjustment for derivative instruments 60 170 Accretion of discount on asset retirement obligations 77 71 Cumulative effect of change in accounting principle - (268) Deferred income taxes 5,183 - Changes in operating assets and liabilities: Accounts receivable (3,829) 2,310 Gas imbalance receivable - (2,669) Other current assets 2,911 1,903 Accounts payable (566) (3,603) Royalties payable 2,225 1,968 Participant advances received (481) (616) Gas imbalance liability - 5,639 Other current liabilities (1,902) (549) Other noncurrent assets and liabilities (92) (38) --------- --------- Net cash provided by operating activities 25,350 23,518 --------- --------- Cash flows from investing activities: Additions to oil and natural gas properties (38,072) (18,841) Proceeds from sale of oil and natural gas properties - 352 Additions to other property and equipment (172) (209) Decrease (Increase) in drilling advances paid 137 (516) --------- --------- Net cash used by investing activities (38,107) (19,214) --------- --------- Cash flows from financing activities: Increase in senior credit facility 19,700 - Repayment of senior credit facility (2,000) (7,000) Deferred loan fees paid and equity costs (53) (985) Proceeds from exercise of employee stock options 598 594 Repurchases of common stock (156) - --------- --------- Net cash provided (used) by financing activities 18,089 (7,391) --------- --------- Net increase (decrease) in cash and cash equivalents 5,332 (3,087) Cash and cash equivalents, beginning of year 5,779 15,318 --------- --------- Cash and cash equivalents, end of period $ 11,111 $ 12,231 ========= =========
The accompanying notes are an integral part of these consolidated financial statements 4 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited) 1. ORGANIZATION AND NATURE OF OPERATIONS Brigham Exploration Company ("Brigham"), a Delaware corporation formed on February 25, 1997, explores and develops onshore domestic oil and natural gas properties using 3-D seismic imaging and other advanced technologies. Brigham focuses its exploration and development of onshore oil and natural gas properties primarily in the onshore Gulf Coast, the Anadarko Basin, and West Texas. 2. BASIS OF PRESENTATION The accompanying consolidated financial statements include the accounts of Brigham and its wholly-owned subsidiaries, and its proportionate share of assets, liabilities and income and expenses of the limited partnerships in which Brigham, or any of its subsidiaries, has a participating interest. All significant intercompany accounts and transactions have been eliminated. The accompanying consolidated financial statements are unaudited, and in the opinion of management, reflect all adjustments that are necessary for a fair presentation of the financial position and results of operations for the periods presented. All such adjustments are of a normal and recurring nature. The results of operations for the periods presented are not necessarily indicative of the results to be expected for the entire year. The unaudited consolidated financial statements should be read in conjunction with Brigham's 2003 Annual Report on Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. STOCK BASED COMPENSATION Brigham accounts for employee stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees". Accordingly, Brigham has adopted the disclosure-only provisions of Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123") as amended by SFAS 148. Had compensation cost for Brigham's stock options been determined based on the fair market value at the grant dates of the awards consistent with the methodology prescribed by SFAS 123, as amended by SFAS 148, Brigham's net income and net income per share for the three and six month periods ended June 30, 2004 and 2003 would have been the pro forma amounts indicated below:
Three Months Ended Six Months Ended June 30, June 30, ----------------------------------- 2004 2003 2004 2003 ------- ------- -------- ------- (In thousands, except per share amounts) Net income available to common stockholders - basic: As reported $5,070 $2,385 $10,159 $7,901 Add back: Stock compensation expense previously included in net income 116 3 237 6 Effect of total employee stock-based compensation expense, determined under fair value method for all awards (647) (117) (991) (159) ------- ------- -------- ------- Pro forma $4,539 $2,271 $ 9,405 $7,748 ======= ======= ======== =======
5
BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited) Three Months Ended Six Months Ended June 30, June 30, ----------------------------------- 2004 2003 2004 2003 ------- ------- -------- ------- (In thousands, except per share amounts) Net income available to common stockholders - diluted: As reported $5,070 $3,062 $10,159 $9,696 Add back: Stock compensation expense previously included in net income 116 3 237 6 Effect of total employee stock-based compensation expense, determined under fair value method for all awards (647) (117) (991) (159) ------- ------- -------- ------- Pro forma $4,539 $2,948 $ 9,405 $9,543 ======= ======= ======== ======= Net income per share: Basic: As reported $ 0.13 $ 0.12 $ 0.26 $ 0.40 Pro forma 0.12 0.11 0.24 0.39 Diluted: As reported $ 0.13 $ 0.10 $ 0.25 $ 0.30 Pro forma 0.11 0.10 0.23 0.30
3. COMMITMENTS AND CONTINGENCIES Brigham is, from time to time, party to certain lawsuits and claims arising in the ordinary course of business. While the outcome of lawsuits and claims cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial condition, results of operations or cash flows of Brigham. On November 20, 2001, Brigham filed a lawsuit in the District Court of Travis County, Texas, against Steve Massey Company, Inc. ("Massey"). The Petition claims Massey furnished defective casing to Brigham, which ultimately led to the casing failure of the Palmer 347 #5 well and the loss of the Palmer #5 as a producing well. In 2004, the parties settled the case on terms favorable to Brigham. Brigham received approximately $440,000 as a result of this settlement, which reduced capitalized well costs. In addition, Massey dropped its $445,819 counterclaim. On July 11, 2002, an employee of a contractor on Brigham's Burkhart #1-R location, Matagorda County, Texas, was involved in a fatal accident. The United States Department of Labor Occupational Safety & Health Administration conducted an inspection and, in October 2003, Brigham settled all issues resulting from that inspection for $70,000. On October 8, 2002, relatives of the contractor's employee filed a wrongful death action in the district court for Matagorda County, Texas, against Brigham and three of Brigham's contractors in connection with his accidental death. Plaintiffs were seeking unspecified actual and punitive damages. On March 23, 2004, a jury determined that Brigham had no liability in the accidental death of the contractor's employee. The plaintiffs have filed a motion for a new trial, which the trial judge has taken under advisement. In September 2002, Brigham filed suit in the district court of Matagorda County, Texas, against one of its contractors in connection with the drilling of the Burkhart #1-R well. The suit claims that the contractor breached its contract with Brigham and negligently performed services on the well, resulting in damages of approximately $650,000. The contractor filed a counterclaim for the recovery of approximately $315,000. The parties settled the case in April 2004 resulting in a payment by the contractor to Brigham and its co-participants. In addition, the contractor dropped its counterclaim. Based on the amount of the settlement, the 6 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited) additional costs that were covered by insurance, and the insurer being subrogated to Brigham's claim, Brigham's incremental recovery as a result of the settlement was diminimus. The operator of the Stonehocker #1 disputed Brigham's ownership interest in the well. In January 2004, the Oklahoma Corporation Commission ruled in favor of Brigham. The operator of the Stonehocker #1 appealed the ruling and the Oklahoma Corporation Commission affirmed its original ruling in March 2004. The operator has appealed the ruling to the Oklahoma Supreme Court. A working interest owner that relinquished its ownership interest in the Nold #1S well as a result of a non-consent election in the re-completion of the well asserted that it did not relinquish its entire interest, but rather became subject only to a 400 percent payout provision. In November 2003, the working interest owner filed a lawsuit against Brigham for breach of contract. In April 2004, the parties negotiated a settlement that resulted in Brigham making a payment of approximately $390,000 to the working interest owner in exchange for an assignment of any interest owned by the working interest owner in this well. In December 2003, Brigham filed a lawsuit in the United States District Court for the Western District of Texas against another company and a former employee concerning the defendants' misappropriation of Brigham's trade secrets and breach of confidentiality obligations. Defendants denied any wrongdoing and asserted a counterclaim against Brigham for alleged tortuous interference with an existing business relationship between the company and its employee. The parties settled the lawsuit in April 2004 on terms favorable to Brigham. The settlement resulted in a $50,000 payment to Brigham, a small overriding royalty interest assignment to Brigham in three tracts and an agreement to not compete in specific areas covered by the confidential information. In addition, the other company has dropped its counterclaim against Brigham. 4. NET INCOME PER SHARE Basic earnings per share are computed by dividing net income available to common stockholders by the weighted average number of common shares outstanding for the period. The computation of diluted net income per share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that would then share in the earnings of Brigham. The following table reconciles the numerators and denominators of the basic and diluted earnings per common share computations for net income available to common stockholders for the three and six months ended June 30, 2004 and 2003:
Three Months Ended Six Months Ended June 30, June 30, ---------------------------------- 2004 2003 2004 2003 ------- ------- ------- ------- (In thousands, except per share amounts) Basic EPS: Income (loss) available to common stockholders before cumulative change in accounting principle $ 5,070 $ 2,385 $10,159 $ 7,633 Cumulative change in accounting principle - - - 268 ------- ------- ------- ------- Income (loss) available to common stockholders $ 5,070 $ 2,385 $10,159 $ 7,901 ======= ======= ======= ======= Common shares outstanding 39,287 20,087 39,261 19,898 ======= ======= ======= ======= Basic EPS Income (loss) available to common stockholders before change in accounting principle $ 0.13 $ 0.12 $ 0.26 $ 0.39 Cumulative change in accounting principle - - - 0.01 ------- ------- ------- ------- $ 0.13 $ 0.12 $ 0.26 $ 0.40 ======= ======= ======= =======
7
BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited) Three Months Ended Six Months Ended June 30, June 30, ---------------- ---------------- 2004 2003 2004 2003 ------- ------- ------- ------- (In thousands, except per share amounts) Diluted EPS: Income (loss) available to common stockholders before cumulative change in accounting principle $ 5,070 $ 2,385 $10,159 $ 7,633 Cumulative change in accounting principle - - - 268 ------- ------- ------- ------- Income (loss) available to common stockholders 5,070 2,385 10,159 7,901 Adjustments for assumed conversions: Dividends and accretion on mandatorily redeemable preferred stock (1) - 677 - 1,795 ------- ------- ------- ------- Income (loss) available to common stockholders before change in accounting principle-diluted 5,070 3,062 10,159 9,428 Cumulative change in accounting principle - - - 268 ------- ------- ------- ------- Income (loss) available to common stockholders-diluted $ 5,070 $ 3,062 $10,159 $ 9,696 ======= ======= ======= ======= Common shares outstanding 39,287 20,087 39,261 19,898 Effect of dilutive securities: Warrants - 459 - 600 Mandatorily redeemable preferred stock - 8,966 - 11,071 Stock options 1,104 525 1,093 521 ------- ------- ------- ------- Potentially dilutive common shares 1,104 9,950 1,093 12,192 ------- ------- ------- ------- Adjusted common shares outstanding diluted 40,391 30,037 40,354 32,090 ======= ======= ======= ======= Diluted EPS Income (loss) available to common stockholders before change in accounting principle $ 0.13 $ 0.10 $ 0.25 $ 0.29 Change in accounting principle - - - 0.01 ------- ------- ------- ------- $ 0.13 $ 0.10 $ 0.25 $ 0.30 ======= ======= ======= ======= (1) The amount of dividends included in dividends and accretion on mandatorily redeemable preferred stock includes only the dividends paid in kind on the $40 million of mandatorily redeemable preferred stock (2.0 million shares) that were issued with warrants whose exercise price is payable in either cash or in shares of mandatorily redeemable preferred stock.
Options and warrants to purchase 1,000 shares and 2.1 million shares of common stock were outstanding but not included in the calculation of diluted earnings (loss) per share for the three months ended June 30, 2004 and 2003, respectively, and options and warrants to purchase 21,000 shares and 13,000 shares of common stock were outstanding but not included in the calculation of diluted earnings (loss) per share for the six months ended June 30, 2004 and 2003, respectively, because the effects would have been antidilutive. 8 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited) 5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES Brigham utilizes various commodity swap and option contracts to (i) reduce the effects of volatility in price changes on the oil and natural gas commodities it produces and sells, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure it can execute at least a portion of its capital spending plans. Brigham reports average oil and natural gas prices and revenues including the net results of hedging activities. The following table sets forth Brigham's oil and natural gas prices including and excluding the hedging gains and losses and the increase or decrease in oil and natural gas revenues as a result of the hedging activities for the three and six month periods ended June 30, 2004 and 2003:
Three Months Six Months Ended June 30, Ended June 30, ------------------------------------- 2004 2003 2004 2003 ------- -------- -------- -------- NATURAL GAS Average price per Mcf as reported (including hedging results) $ 5.90 $ 4.72 $ 5.80 $ 5.12 Average price per Mcf realized (excluding hedging results) $ 6.19 $ 5.60 $ 6.00 $ 6.40 Decrease in revenue (in thousands) $ (644) $(1,341) $ (860) $(3,847) OIL Average price per Bbl as reported (including hedging results) $33.05 $ 27.45 $ 31.88 $ 28.39 Average price per Bbl realized (excluding hedging results) $37.81 $ 29.52 $ 35.79 $ 31.37 Decrease in revenue (in thousands) $ (670) $ (370) $(1,175) $(1,198)
For the three months ended June 30, 2004 and 2003, ineffectiveness associated with Brigham's derivative commodity instruments designated as cash flow hedges decreased earnings by approximately $0.2 million and $0.2 million, respectively. For the six months ended June 30, 2004 and 2003, ineffectiveness associated with Brigham's derivative commodity instruments designated as cash flow hedges decreased earnings by approximately $0.1 million and $0.1 million, respectively. These amounts are included in other income (expense). NATURAL GAS AND CRUDE OIL DERIVATIVE CONTRACTS The following table summarizes the hedging contracts to which Brigham was a party at June 30, 2004, the total natural gas and crude oil production volumes subject to those contacts and the weighted average NYMEX reference price for those volumes:
SWAPS COLLARS -------------------- --------------------------- WEIGHTED WEIGHTED AVERAGE ---------------- AVERAGE FLOOR CEILING VOLUMES PRICE VOLUMES PRICE PRICE -------- --------- -------- --------- ----- NATURAL GAS (MMbtu) ($/MMbtu) (MMbtu) ($/MMbtu) Quarter Ended: September 30, 2004 138,000 4.180 722,200 4.613 6.476 December 31, 2004 92,000 4.360 586,100 4.746 6.690 March 31, 2005 - - 517,500 4.663 7.100 June 30, 2005 - - 455,000 4.725 6.712 CRUDE OIL (Bbls) ($/Bbl) (Bbls) ($/Bbl) Quarter Ended: September 30, 2004 13,800 23.91 48,760 26.34 32.20 December 31, 2004 9,200 23.80 34,260 26.68 31.71 March 31, 2005 - - 27,450 25.56 30.18 June 30, 2005 - - 18,655 26.80 32.51
9 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited) INTEREST RATE SWAP Periodically, Brigham may use interest rate swap contracts to adjust the proportion of its total debt that is subject to variable interest rates. Under such an interest rate swap contract, Brigham agrees to pay an amount equal to a specified fixed-rate of interest for a certain notional amount and receive in return an amount equal to a variable-rate. The notional amounts of the contract are not exchanged. No other cash payments are made unless the contract is terminated prior to maturity. Although no collateral is held or exchanged for the contract, the interest rate swap contract is entered into with a major financial institution in order to minimize Brigham's counterparty credit risk. The interest rate swap contract is designated as a cash flow hedge against changes in the amount of future cash flows associated with Brigham's interest payments on variable-rate debt. The effect of this accounting on operating results is that interest expense on a portion of variable-rate debt being hedged is recorded based on fixed interest rates. At June 30, 2004, Brigham had an interest rate swap contract to pay a fixed-rate of interest of 8.76% on $20.0 million notional amount of senior subordinated notes. The $20.0 million notional amount of the outstanding contract matures in March 2009. As of June 30, 2004, approximately $0.4 million of unrealized gains are included in accumulated other comprehensive income (loss) on the balance sheet and the fair value of the interest rate swap agreement represents approximately $0.2 million of other noncurrent assets. The fair value of the interest rate swap contract is based on quoted market prices and third-party provided calculations, which reflect the present values of the difference between estimated future variable-rate receipts and future fixed-rate payments. FAIR VALUES The fair value of hedging and interest rate swap contracts is reflected on the consolidated balance sheets as detailed in the following table. The current asset and liability amounts represent the fair values expected to be included in the results of operations for the next twelve months.
JUNE 30, ------------------ 2004 2003 -------- -------- (In thousands) Other current liabilities $(2,198) $(2,734) Other noncurrent liabilities (237) (276) Other current assets - 133 Other noncurrent assets 242 - -------- -------- $(2,193) $(2,877) ======== ========
6. ASSET RETIREMENT OBLIGATIONS On January 1, 2003, Brigham adopted the provisions of Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"). SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. Brigham has asset retirement obligations associated with the future plugging and abandonment of proved properties and related facilities. Prior to the adoption of SFAS 143, Brigham assumed salvage value approximated plugging and abandonment costs. As such, estimated salvage value was not excluded from depletion and plugging and abandonment costs were not accrued for over the life of the oil and gas properties. The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment to record (i) a $1.4 million increase in the carrying values of proved properties, (ii) a $0.8 million decrease in accumulated 10 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited) depletion of oil and natural gas properties and (iii) a $1.9 million increase in noncurrent abandonment liabilities. The net impact of items (i) through (iii) was to record a gain of $0.3 million as a cumulative effect adjustment of a change in accounting principle in Brigham's consolidated statements of operations upon adoption on January 1, 2003. Brigham has no assets that are legally restricted for purposes of settling asset retirement obligations. The following table summarizes Brigham's asset retirement obligation transactions recorded in accordance with the provisions of SFAS 143 during the three and six months ended June 30, 2004:
Three Months Ended Six Months Ended June 30, June 30, 2004 2003 2004 2003 ------- ------ ------- ------ (In thousands) Beginning asset retirement obligations $2,422 $1,965 $2,320 $1,931 Liabilities incurred for new wells placed on production 235 60 336 60 Liabilities settled (32) - (68) - Accretion of discount on asset retirement obligations 40 37 77 71 ------- ------ ------- ------ Ending asset retirement obligations $2,665 $2,062 $2,665 $2,062 ======= ====== ======= ======
7. INCOME TAXES The provision for income taxes was computed in accordance with Interpretation No. 18 of Accounting Principles Board Opinion (APB) No. 28 on reporting taxes for interim periods and accordingly was based on the projection of total 2004 pretax income. Interpretation No. 18 of APB 28 provides that interim income taxes should be computed using the projected effective tax rate on the total projected pretax income for the year. At June 30, 2004, management believes that Brigham will (i) begin to utilize net operating losses (NOLs) and (ii) have reversals of existing temporary differences between book and taxable income sufficient to result in a deferred tax liability at year-end 2004. Management also believes that it is more likely than not that capital loss carryforwards of approximately $1.8 million may expire unused and, accordingly, has established a valuation allowance of $0.6 million. The components of deferred income tax assets and liabilities are as follows:
June 30, December 31, 2004 2003 -------- ------------ (In thousands) Deferred tax assets Current: Net operating loss carryforwards $ - $ 451 Unrealized hedging losses 545 - Derivative assets 297 - -------- ------------ 842 451 -------- ------------
11 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
JUNE 30, DECEMBER 31, 2004 2003 --------- ---------- (In thousands) Non-current: Net operating loss carryforwards 37,639 34,409 Capital loss carryforwards 634 634 Stock compensation 925 818 Unrealized hedging losses - 561 Derivative assets - 276 Asset retirement obligations 933 812 Preferred stock dividends as interest expense 243 119 Other 27 27 --------- --------- Non-current 40,401 37,656 --------- --------- 41,243 38,107 --------- --------- Deferred tax liabilities Current: Gas imbalances - (144) Non-current: Depreciable and depletable property (43,423) (35,132) Other (188) - --------- --------- Non-current (43,611) (35,132) --------- --------- (43,611) (35,276) --------- --------- Net deferred tax assets (liabilities) (2,368) 2,831 Valuation allowance (634) (634) --------- --------- $ (3,002) $ 2,197 ========= =========
At June 30, 2004, Brigham has regular tax NOLs of approximately $107.5 million. Additionally, Brigham has approximately $93.3 million of alternative minimum tax ("AMT") NOLs available as a deduction against future taxable income. The NOLs expire from 2012 through 2024. The value of these NOLs depends on the ability of Brigham to generate taxable income. In addition, at June 30, 2004, Brigham has capital loss carryforwards of approximately $1.8 million that expire in varying years through 2007. Brigham believes it has a $4.5 million annual limitation on the utilization of certain of its NOLs under Internal Revenue Code Section 382 due to a potential 50% change in ownership among its 5% shareholders over a three-year period. 8. ACCOUNTING PRONOUNCEMENTS Statement of Financial Accounting Standards No. 141, "Business Combinations" (SFAS 141) and Statement of Financial Accounting Standards, No. 142, "Goodwill and Intangible Assets" (SFAS 142) were issued by the Financial Accounting Standards Board (FASB) in June 2001 and became effective for Brigham on July 1, 2001 and January 1, 2002, respectively. SFAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. Additionally, SFAS 141 requires companies to disaggregate and report separately from goodwill certain intangible assets. SFAS 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under SFAS 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment. Historically, Brigham, like many other oil and gas companies, has included these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves as part of the oil and gas properties, even after SFAS 141 and 142 became effective. 12 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited) On April 30, 2004 the FASB staff issued FASB Staff Position (FSP) SFAS 141-1 and 142-1, "Interaction of FASB Statements No. 141, Business Combinations, and No. 142, Goodwill and Other Intangible Assets, and Emerging Issues Task Force (EITF) Issue No. 04-2, Whether Mineral Rights Are Tangible or Intangible Assets" and the guidance in the FSP shall be applied to the first reporting period after April 29, 2004. Under the FSP certain use rights may have characteristics of tangible assets, thus Brigham will continue to classify its oil and gas leaseholds as tangible oil and gas properties. In July 2004, the FASB issued proposed FASB Staff Position (FSP) FAS 142-b, "Application of FASB Statement No. 142, Goodwill and Other Intangible Assets to Oil and Gas Producing Entities." This proposed FSP confirms the Staff's position that SFAS No. 142 did not change the balance sheet classification or disclosure requirements for drilling and mineral rights of oil and gas producing entities that are within the scope of SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." Brigham classifies the cost of oil and gas drilling and mineral rights as properties and equipment, which is consistent with SFAS No. 19 and proposed FSP FAS 142-b. 9. SUBSEQUENT EVENT During July 2004, Brigham completed the sale of 2,300,000 shares of its common stock under a universal shelf registration statement declared effective by the Securities and Exchange Commission in June 2004. Net proceeds from the equity offering of approximately $19.5 million were used to repay outstanding borrowings under the senior credit facility. The balance of the senior credit facility at August 12, 2004 is $19.2 million. Brigham plans to reborrow the repaid amounts under the senior credit facility as necessary to fund future exploration and development activities and for general corporate purposes. 13 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following updates information as to our financial condition provided in our 2003 Annual Report on Form 10-K, and analyzes the changes in the results of operations between the three and six month periods ended June 30, 2004, and the comparable period of 2003. For definitions of commonly used oil and gas terms as used in this Form 10-Q, please refer to the "Glossary of Oil and Gas Terms" provided in our 2003 Annual Report on Form 10-K. OVERVIEW OF FIRST SIX MONTHS OF 2004 For the quarter and six month period ended June 30, 2004, our net capital expenditures for oil and natural gas activities were $22.6 million and $39.6 million, respectively. Our drilling capital expenditures alone for the second quarter 2004 were up approximately 150% over the amount we spent in the second quarter of last year. For the six months ended June 30, 2004, our net capital expenditures for oil and natural gas activities are up approximately 120% when compared to the first six months of last year. Our operating performance for the second quarter and first six months of 2004 was highlighted by record high production of 34.4 MMcfe/d and 34.1 MMcfe/d, respectively. This represents a 19% growth in production over the amount we produced in the second quarter of 2003 and a 13% increase over the amount we produced in the first six months of 2003. The increase in our production is primarily the result of the increase in drilling capital expenditures during the fourth quarter of last year and the first six months of 2004. Net income to common stockholders for the second quarter 2004 was $5.1 million, or $0.13 per diluted share, on total revenues of $18 million. This compares to reported net income of $2.4 million, or $0.10 per diluted share on total revenues of $12.2 million in the second quarter last year. For the six month period ended June 30, 2004, our reported net income to common stockholders is $10.2 million, or $0.25 per diluted share, on total revenues of $34.8 million. This compares to reported net income of $7.9 million, or $0.30 per diluted share, on revenue of $26.8 million for the first six months of last year. Net cash provided by operating activities funded approximately 67% of our capital expenditures. We borrowed an additional $19.7 million in additional debt under our senior credit facility to fund the bulk of our remaining capital expenditures. As of June 30, 2004, we repaid $2 million of the additional amount borrowed during the first six months on 2004. At June 30, 2004, we had $11.1 million in cash, total assets of $258.3 million and a debt to total capitalization ratio of 31%. OUTLOOK FOR THE REMAINDER OF 2004 On July 23, 2004, we sold 2,300,000 shares of our common stock under a universal shelf registration statement declared effective by the Securities and Exchange Commission in June 2004. We received net proceeds of approximately $19.5 million and used the net proceeds from the offering to repay outstanding indebtedness under our senior credit facility. "Net proceeds" is the amount we received after paying the underwriting discount and other expenses related to offering. We intend to reborrow the repaid amount to fund future exploration and development activities, including taking advantage of opportunities to retain larger working interests in wells and in 3-D seismic programs and for general corporate purposes. 14 Also on July 23, 2004, we announced that we had increased our 2004 capital expenditure budget approximately 13% to $89.9 million, up from our previously announced 2004 capital expenditure budget of $79.4 million. The following table presents our original capital budget for 2004 and our recently announced revised capital budget for 2004.
Revised Original 2004 2004 Budget Budget % Change ------- ------- --------- (in thousands) Drilling. . . . . . . . . . . . . . . . . . . . . . . . . . $68,483 $61,432 11% Land and G&G. . . . . . . . . . . . . . . . . . . . . . . . 15,075 11,973 26% Capitalized interest and G&A. . . . . . . . . . . . . . . . 5,851 5,535 6% ------- ------- Net capital expenditures on oil and gas activities . $89,409 $78,940 13% Other property and equipment. . . . . . . . . . . . . . . . 473 473 - ------- ------- Total revenue from the sale of oil and natural gas . $89,882 $79,413 13% ======= =======
Revised 2004 Budget Overview Approximately $41.1 million, or 60%, of the budgeted drilling capital expenditures from our revised 2004 budget will be allocated to drill 23 wells in our onshore Texas Gulf Coast region. For 2004, our drilling activities in our onshore Gulf Coast region will be focused on the Vicksburg and Frio Trends where we will drill ten development wells with an average working interest of 63% and 13 exploratory wells with an average working interest of 63%. Of the wells budgeted for 2004, eleven wells had reached total depth as of June 30, 2004. In the Vicksburg, we are currently budgeted to spend approximately $18.4 million to drill three development wells with an average working interest of 56% and three exploration wells with an average working interest of 68%. As of June 30, 2004, three of the wells in our revised 2004 budget had reached total depth and one well was drilling. We currently plan to spud the remaining two Vicksburg wells in our 2004 drilling program in the third and fourth quarter of this year. For the Frio we are currently budgeted to spend approximately $22.4 million to drill seven development wells with an average working interest of 66% and ten exploration wells with an average working interest of 65%. As of June 30, 2004, eight of the wells in our revised 2004 budget had reached total depth. We currently plan to spud seven of the remaining Frio wells in the third quarter of this year and the remaining two wells in the fourth quarter. Approximately $25.2 million, or 37%, of the budgeted drilling capital expenditures from our revised 2004 budget will be allocated to drill 39 wells in our Anadarko Basin region. The majority of our drilling capital allocated to our Anadarko Basin region will be focused on the Hunton/Arbuckle, Springer Channel and Springer Bar Trends. For 2004, we currently plan to drill 34 development wells with an average working interest of 23% and five exploratory wells with an average working interest of 17% in our Anadarko Basin region. Of the wells currently budgeted for 2004, 14 had reached total depth as of June 30, 2004. We are currently budgeted to spend approximately $12.8 million to drill three Hunton/Arbuckle development wells with an average working interest of 73%. As of June 30, 2004, we had one well drilling and currently plan to spud one well in both the third and fourth quarter of this year. For the Springer Channel we are currently budgeted to spend approximately $4.5 million to drill seven development wells with an average working interest of 41% and four exploratory wells with an average working interest of 16%. As of June 30, 2004, five of the wells in our revised 2004 budget had reached total depth and two wells were drilling. We currently plan to spud three of the remaining Springer Channel wells in our 2004 drilling program in the third quarter and one well in fourth quarter of this year. 15 For the Springer Bar we are currently budgeted to spend approximately $3.3 million to drill ten development wells with an average working interest of 10%. As of June 30, 2004, three of the wells in our revised 2004 budget had reached total depth and one well was drilling. We currently plan to spud four of the remaining Springer Bar wells in our 2004 drilling program in the third quarter and two wells in fourth quarter of this year. Additional budgeted capital expenditures for the Anadarko Basin region includes $1.8 million to drill 13 development wells in the granite wash formation with and average working interest of 11%. As of June 30, 2004, five of the wells in our revised 2004 budget had reached total depth. We currently plan to spud four of the remaining wells in the third quarter of 2004 and four wells in the fourth quarter. We have also budgeted $2.8 million to drill a Grady County Bromide test with a 29% working interest, a combined Hunton/Springer Channel test with a 17% working interest and for other various drilling activities. As of June 30, 2004, the Bromide test had reached total depth and the combined Hunton/Springer Channel test was planned for an August 2004 spud. Approximately $2.2 million, or 3%, of the budgeted drilling capital expenditures from our revised 2004 budget will be allocated to drill three exploratory wells in our West Texas region with an average working interest of 74%. We currently plan to spud two of these wells in the third quarter of 2004 and one well scheduled for the fourth quarter. Approximately 17% of our revised capital expenditure budget will be used to fund land and seismic acquisitions in an effort to add to our inventory of drilling projects in current focus plays. We believe that our cash on hand at June 30, 2004, net cash provided by operating activities, net proceeds from our sale of common stock in July 2004 and the remaining availability under our senior credit facility will fund our spending for the remainder of the year. Our estimated net capital expenditures for 2004 represent an increase of approximately 91% over the amount that we spent in 2003. The final determination with respect to our 2004 budgeted expenditures will depend on a number of factors, including: - commodity prices; - production from our existing producing wells; - the results of our current exploration and development drilling efforts; - economic and industry conditions at the time of drilling, including the availability of drilling equipment; and - the availability of more economically attractive prospects. There can be no assurance that the budgeted wells will, if drilled, encounter commercial quantities of natural gas or oil. 16 CAPITAL COMMITMENTS Net cash provided by operating activities and additional borrowings from our senior credit were our primary sources of cash during the first six months of 2004. This cash was used to fund the costs associated with drilling, land acquisition and 3-D seismic acquisition, processing and interpretation. We believe our cash on hand at the end of the second quarter 2004, net cash provided by operating activities, the net proceeds from our sale of common stock in July 2004 and the remaining availability under our senior credit facility will be sufficient to fund our budgeted capital expenditures for the remainder of 2004. Capital Expenditures The timing of most of our capital expenditures is discretionary because we have no material long-term capital expenditure commitments. Consequently, we have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. The table below lists our capital expenditures for the first six months of 2004 and 2003.
SIX MONTHS ENDED JUNE 30, ------------------------------ 2004 2003 % Change ------- ------------- ------ (in thousands) Drilling . . . . . . . . . . . . . . . . . . . . . . . . . $31,190 $ 12,669 146% Land and G&G . . . . . . . . . . . . . . . . . . . . . . . 5,221 2,138 144% Capitalized interest and G&A . . . . . . . . . . . . . . . 3,161 3,160 0% ------- ------------- Net capital expenditures on oil and gas activities. $39,572 $ 17,967 120% Other property and equipment . . . . . . . . . . . . . . . 172 209 (18%) ------- ------------- Net capital expenditures. . . . . . . . . . . . . . $39,744 $ 18,176 119% ======= =============
Liquidity and Capital Resources Cash flows from operating activities During the first six months of 2004, net cash provided by operating activities and additional borrowings from our senior credit facility were our primary source of cash. This cash was used to fund the costs associated with drilling, land acquisition and 3-D seismic acquisition, processing and interpretation.
Six months ended June 30, -------------------------------- 2004 2003 % Change ------- ------------- -------- (in thousands) Net cash provided by operating activities. $25,350 $ 23,518 8%
The 8% increase in net cash provided by operating activities is primarily related to the following: - - An increase in oil and natural gas sales resulted in a $5 million increase in net cash provided by operating activities. - - An increase in revenue due to a decline in losses from the settlement of derivative contracts resulted in a $3 million increase in net cash provided by operating activities. These increases were partially offset by the following: - - The repayment of accounts payable in excess of collections of accounts receivable reduced net cash provided by operating activities by $3.1 million. 17 - - The settlement of the gas imbalance with our industry participant in our Diablo project reduced net cash provided by operating activities by $2.6 million. - - An increase in production costs reduced net cash provided by operating activities by $485,000. Working capital is the amount by which current assets exceed current liabilities. It is normal for us to report a working capital deficit at the end of a period. These deficits are primarily the result of accounts payable related to lease operating expenses, exploration and development costs, royalties payable and gas imbalances payable. Settlement of these payables will be funded by cash flows from operations or, if necessary, by additional borrowing under our senior credit facility. At June 30, 2004, we had a working capital deficit of $8.6 million compared to a working capital deficit of $14.7 million at December 31, 2003. Current liabilities at June 30, 2004, included a liability of $2.2 million related to the fair value of our open derivative contracts. Cash flows from financing activities Common stock transactions - ------------------------- - - We issued 126,600 shares of common stock and received $310,000 in net proceeds related to the exercise of employee stock options in the first quarter of 2004 and issued 81,481 shares of common stock and received $288,000 in net proceeds in the second quarter of 2004. - - During January and June of 2004, we acquired 19,596 and 821 shares of our common stock, respectively, from certain employees to satisfy tax-withholding obligations associated with the vesting of stock grants. The transferred shares were valued at fair market value as of the date of surrender. - - We issued 171,800 shares of common stock and received $432,000 in net proceeds related to the exercise of employee stock options in the first quarter of 2003 and issued 52,793 and received net proceeds of $162,000 in the second quarter of 2003. - - In the first quarter of 2003, we issued 248,028 unregistered shares of our common stock to a group of institutional investors. The shares were issued to the group in connection with the cashless exercise of warrants that it owned and we received no proceeds from the exercise of the warrants. - - In June 2003, we issued 408,928 and 206,982 unregistered shares of our common stock to the Bank of Montreal and Soci t G n rale, respectively. We received no proceeds from the exercise of these warrants as both parties elected to execute a cashless exercise of the warrants. Both parties sold the shares from this exercise in our common stock sale in September 2003. We received no proceeds from the subsequent sale. Senior credit facility - ---------------------- Future outstanding balances under our senior credit facility are dependent primarily on our level of capital expenditures, net cash provided by operating activities and the proceeds from other financing activities. Our committed borrowing capacity under our senior credit facility at June 30, 2004, was $80 million, with a $68.5 million borrowing base that is subject to adjustment on the basis of the present value of estimated future net cash flows from proved oil and gas reserves (as determined by the lender's petroleum engineer). Our unused committed borrowing base capacity under our senior credit facility was $31.8 million at June 30, 2004, and $49.3 million at August 12, 2004. Our senior credit facility matures in March of 2006. During the first six months of 2004 we borrowed $19.7 million of additional debt from our senior credit facility to fund our working capital obligations and capital expenditures and repaid $2 million. In July 2004, we used the net proceeds from the sale of common stock to repay $19.5 million of debt outstanding under our senior credit facility. During the first six months of 2003, we repaid $7 million of the debt outstanding under our senior credit facility and paid $985,000 in fees related to our new credit facility that was put in place in March 2003. Our current ratio, as defined by the senior credit facility, at June 30, 2004 and interest coverage ratio for the twelve-month period ending June 30, 2004, were 1.6 to 1 and 11.9 to 1, respectively. As of June 30, 2004, we were in compliance with the covenants of our senior credit facility. 18 Senior subordinated notes - ------------------------- Our current ratio, as defined by the senior subordinated notes, at June 30, 2004 and interest coverage ratio for the twelve-month period ending June 30, 2004, were 1.6 to 1 and 11.9 to 1, respectively. Our ratio of risked net present value (as defined) discounted at 9% to total debt at December 31, 2003, was 2.7 to 1, and were in compliance with the subordinated notes covenant that requires us to maintain a ratio of 1.5 to 1. As of June 30, 2004, we were in compliance with the covenants of our senior subordinated notes. RESULTS OF OPERATIONS Comparison of the three and six month periods ended June 30, 2004 and 2003 Production.
Three months ended June 30, Six months ended June 30, --------------------------- ------------------------- % % 2004 2003 Change 2004 2003 Change ------ ------ ------- ------ ----- ------- Oil (MBbls). . . . . . . . . . . . . . . 141 179 (21%) 300 402 (25%) Natural gas (MMcf) . . . . . . . . . . . 2,246 1,528 47% 4,339 3,000 45% Natural gas equivalent (MMcfe) . . 3,092 2,602 19% 6,142 5,412 13% Average daily production (MMcfe/d) 34.4 28.9 19% 34.1 30.1 13% % Natural gas . . . . . . . . . . 73% 59% 71% 55%
The increase in our production volumes was due to organic production growth from wells that we drilled and completed in the fourth quarter of 2003 and the first six months of 2004. New production related to these recently completed wells was partially offset by the natural decline of existing production. Revenues from the sale of oil and natural gas. Reported revenues from the sale of oil and natural gas are based on the market price we receive for our commodities, adjusted for marketing charges and the results from the settlement of our derivative commodity contracts that qualify for cashflow hedge accounting treatment under SFAS 133. We utilize commodity swap, collar and floor contracts to (i) reduce the effect of price volatility on the commodities that we produce and sell, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure we can execute at least a portion of our capital spending plans. All of our open derivative commodity contracts at June 30, 2004, qualified for cashflow hedge accounting treatment under SFAS 133. The effective portions of changes in the fair values of our derivative commodity contracts that qualify for cashflow hedge accounting treatment under SFAS 133 are recorded as increases or decreases to stockholders' equity until the underlying contract is settled. Consequentially, changes in the effective portions of our derivative commodity contracts that qualify for cashflow hedge accounting treatment under SFAS 133 add volatility to our reported stockholders' equity until the contract is settled or is terminated. Gains or losses related to the settlement, the ineffective portion of changes in the fair market value and the changes in the fair values of our derivative commodity contracts that do not qualify for cashflow hedge accounting treatment under SFAS 133 are recognized in other income (expense). The following table presents revenues that we realized from the sale of oil and natural gas during the second quarter and first six months of 2004 and 2003. 19
THREE MONTHS ENDED, JUNE 30, SIX MONTHS ENDED JUNE 30, ---------------------------- ------------------------- % % 2004 2003 CHANGE 2004 2003 CHANGE -------- -------- ------- -------- -------- ------- (IN THOUSANDS) Oil sales . . . . . . . . . . . . . . . . . . . . . . $ 5,327 $ 5,288 1% $10,754 $12,612 (15%) Loss due to hedging . . . . . . . . . . . . . . . . . (670) (370) 81% (1,175) (1,198) (2%) -------- -------- ------------------ Total revenues from the sale of oil . . . . . . . . $ 4,657 $ 4,918 (5%) $ 9,579 $11,414 (16%) ======== ======== ================== Natural gas sales . . . . . . . . . . . . . . . . . . $13,903 $ 8,550 63% $26,016 $19,199 36% Loss due to hedging . . . . . . . . . . . . . . . . . (644) (1,341) (52%) (860) (3,847) (78%) -------- -------- ------------------ Total revenues from the sale of natural gas . . . . $13,259 $ 7,209 84% $25,156 $15,352 64% ======== ======== ================== Oil and natural gas sales . . . . . . . . . . . . . . $19,230 $13,838 39% $36,770 $31,811 16% Loss due to hedging . . . . . . . . . . . . . . . . . (1,314) (1,711) (23%) (2,035) (5,045) (60%) -------- -------- -------- -------- Total revenues from the sale of oil and natural gas $17,916 $12,127 48% $34,735 $26,766 30% ======== ======== ================== AVERAGE PRICES: (PER BBL) Oil sales . . . . . . . . . . . . . . . . . . . . . . $ 37.81 $ 29.52 28% $ 35.79 $ 31.39 14% Loss due to hedging . . . . . . . . . . . . . . . . . (4.76) (2.07) 130% (3.91) (3.00) 30% -------- -------- ------------------ Realized Oil price. . . . . . . . . . . . . . . . . $ 33.05 $ 27.45 20% $ 31.88 $ 28.39 12% ======== ======== ================== (PER MCF) Natural gas sales . . . . . . . . . . . . . . . . . . $ 6.19 $ 5.60 11% $ 6.00 $ 6.40 (6%) Loss due to hedging . . . . . . . . . . . . . . . . . (0.29) (0.88) (67%) (0.20) (1.28) (84%) -------- -------- ------------------ Realized natural gas price. . . . . . . . . . . . . $ 5.90 $ 4.72 25% $ 5.80 $ 5.12 13% ======== ======== ================== (PER MCFE) Natural gas equivalent sales. . . . . . . . . . . . . $ 6.22 $ 5.32 17% $ 5.99 $ 5.88 2% Loss due to hedging . . . . . . . . . . . . . . . . . (0.43) (0.66) (35%) (0.33) (0.93) (65%) -------- -------- ------------------ Realized natural gas equivalent price . . . . . . . $ 5.79 $ 4.66 24% $ 5.66 $ 4.95 14% ======== ======== ==================
Total revenues from the sale of oil and natural gas for the second quarter 2004 were 48% higher than revenues in same period of 2003. The increase was primarily due the following: - - A $2.9 million increase to total revenues from the sale of oil and natural gas due to a 19% increase in production volumes for the second quarter 2004. - - A $2.5 million increase to total revenues from the sale of oil and natural gas due to a 28% increase in the average sales price we received for oil and an 11% increase in the average sales price we received for natural gas. - - A 23% decrease in losses related the settlement of hedging contracts resulted in a $397,000 increase in total revenues from the sale of oil and natural gas. 20 Total revenues from the sale of oil and natural gas for the first six months of 2004 were 30% higher than revenues in the same period of 2003. The increase was primarily due to the following: - - A $5.4 million increase to total revenues from the sale of oil and natural gas due to a 13% increase in production volumes for first six months of 2004. - - A $432,000 decline in total revenues from the sale of oil and natural gas due to a 6% decline in the average sales price we received for natural gas offset the increase in total revenue from the increase in production. - - A 60% decrease in losses related the settlement of hedging contracts resulted in a $3 million increase in total revenues from the sale of oil and natural gas. The table below presents our derivative commodity contracts, the volumes, the weighted average NYMEX reference price for those volumes, and the associated loss upon settlement of those contracts during the second quarter and first six months of 2004 and 2003.
THREE MONTHS ENDED, JUNE 30, SIX MONTHS ENDED, JUNE 30, ---------------------------- -------------------------- % % 2004 2003 CHANGE 2004 2003 CHANGE --------- --------- ------- ----------- ----------- ------- OIL SWAPS Volumes (Bbls). . . . . . . . . . . 20,475 61,425 (67%) 50,050 128,925 (61%) Average swap price (per Bbl). . . . $ 24.52 $ 25.22 (3%) $ 25.01 $ 25.25 (1%) Loss upon settlement (in thousands) $ (283) $ (226) 25% $ (573) $ (801) (28%) OIL COLLARS Volumes (Bbls). . . . . . . . . . . 50,050 22,750 120% 95,550 45,250 111% Average floor price (per Bbl) . . . $ 24.09 $ 18.00 34% $ 23.57 $ 18.00 31% Average ceiling price (per Bbl) . . 30.60 22.56 36% 30.52 22.56 35% Loss upon settlement (in thousands) $ (387) $ (144) 168% $ (602) $ (397) 52% NATURAL GAS SWAPS Volumes (MMbtu) . . . . . . . . . . 227,500 819,000 (72%) 523,250 1,651,500 (68%) Average swap price (per MMbtu). . . $ 4.252 $ 3.846 11% $ 4.654 $ 3.738 25% Loss upon settlement (in thousands) $ (391) $ (1,341) (71%) $ (607) $ (3,847) (84%) NATURAL GAS COLLARS Volumes (MMbtu) . . . . . . . . . . 509,600 - - 1,055,600 - - Average floor price (per MMbtu) . . $ 4.112 $ - - $ 4.119 $ - - Average ceiling price (per MMbtu) . 5.672 - - 7.100 - - Loss upon settlement (in thousands) $ (253) $ - - $ (253) $ - - NATURAL GAS FLOORS Volumes (MMbtu) . . . . . . . . . . - 150,000 (100%) - 150,000 (100%) Average swap price (per MMbtu). . . $ - $ 4.500 (100%) $ - $ 4.500 (100%) Loss upon settlement (in thousands) $ - $ - - $ - $ - -
Other revenue. Fees that we charge other parties who use our two gas gathering systems to move their production from the wellhead to third party gas pipeline systems are recorded as other revenue. These gathering systems are owned by us and located in the Texas Gulf Coast. One of the gathering systems connects a single well and the other connects two wells. Other revenue for the second quarter of 2004 was $41,000 compared to $43,000 in the second quarter last year. Other revenue for the six months of 2004 was $42,000 compared to $81,000 during the first six months of 2003. 21 Production cost. Production costs include lease operating expenses and production taxes. The following table presents our production cost for the second quarter and first six months of 2004 and 2003.
THREE MONTHS ENDED, JUNE 30, SIX MONTHS ENDED, JUNE 30, ---------------------------- -------------------------- % % 2004 2003 CHANGE 2004 2003 CHANGE ------ ------ ------- ------ ------ ------- (IN THOUSANDS) Operating and maintenance expenses. $1,021 870 17% 2,047 $1,617 27% Workover expenses . . . . . . . . . 118 235 (50%) 339 297 14% Ad valorem taxes. . . . . . . . . . 166 165 1% 328 330 (1%) ------ ------ -------------- Lease operating expenses. . . . . 1,305 $1,270 3% $2,714 $2,244 21% Production taxes. . . . . . . . . . 896 806 11% 1,759 1,744 1% ------ ------ ------ ------ Total production cost . . . . . . $2,201 $2,076 6% $4,473 $3,988 12% ====== ====== ============== (PER MCFE) Operating and maintenance expenses. $ 0.33 $ 0.33 - $ 0.33 $ 0.30 10% Workover expenses . . . . . . . . . 0.04 0.09 (56%) 0.06 0.05 20% Ad valorem taxes. . . . . . . . . . 0.05 $ 0.06 (17%) $ 0.05 $ 0.06 (17%) ------ ------ -------------- Lease operating expenses. . . . . $ 0.42 $ 0.48 (13%) $ 0.44 $ 0.41 7% Production taxes. . . . . . . . . . 0.29 0.31 (6%) 0.29 0.32 (9%) ------ ------ -------------- Total production cost . . . . . . $ 0.71 $ 0.79 (10%) $ 0.73 $ 0.73 0% ====== ====== ==============
Lease operating expenses - ------------------------ Lease operating expenses are comprised of several components which include: the cost of labor and supervision to operate the wells and related equipment; repairs and maintenance; related materials, supplies, fuel, and supplies utilized in operating the wells and related equipment and facilities; insurance applicable to wells and related facilities and equipment; workover cost; and ad valorem taxes. Lease operating expenses are driven in part by the type of commodity produced, the level of workover activity and the geographical location of the properties. Oil is inherently more expensive to produce than natural gas. Local taxing authorities such as school districts, cities, and counties or boroughs generally impose the ad valorem taxes we pay. The amount of the tax is based on the value of the property assessed or determined by the taxing authority on an annual basis, and a percent of value. When oil and natural gas commodity prices rise, the value of our underlying property interests increase. This results in higher ad valorem taxes. Lease operating expenses for the second quarter 2004 were 3% higher than lease operating expenses in the second quarter 2003. The change was primarily due to the following: - - An increase in the number of producing wells during the second quarter 2004 combined with higher cost for compressor rental and maintenance, saltwater disposal, electricity and fuel and contract pumping services resulted in a 17% increase in operating and maintenance expenses. - - This increase was partially offset by a 50% decrease in workover costs. On a per unit basis, lease operating expenses for the second quarter 2004 were 13% lower than in the same period of the prior year due to an increase in production volumes. 22 Lease operating expenses for the first six months of 2004 were 21% higher than lease operating expenses during the first six months of 2003. The change was primarily due to the following: - - An increase in the number of producing wells in the first six months of 2004 combined with higher cost for compressor rental and maintenance, saltwater disposal, electricity and fuel, contract pumping services and overhead resulted in a 27% increase in operating and maintenance expense. - - A 14% increase in workover costs primarily due to workover activity in the first quarter 2004. On a per unit basis, lease operating expenses for the first six months of 2004 were 10% higher than per unit lease operating expenses in the same period of the prior year. The increase in our per unit lease operating expense was primarily due to the following: - - An increase in compressor rental and maintenance expenses and overhead fees resulted in a 10% increase in our per unit operating and maintenance expenses. - - An increase in workover costs primarily related to workovers performed in the first quarter 2004 resulted in a 20% increase in our per unit workover cost for the first six month of 2004. Production taxes - ---------------- There are a variety of state and federal taxes levied on the production of our oil and natural gas. These are commonly grouped together and referred to as production taxes. The majority of our production tax expense is based on a percent of gross value at the well at the time the production is sold or removed from the lease. As a result, our production tax expense increases with increases in crude oil and natural gas commodity prices. Historically, taxing authorities have occasionally encouraged oil and gas industry to explore for new oil and natural gas reserves, or develop high cost reserves through reduced tax rates or credits. These incentives have been narrow in scope and short-lived. A small number of our wells currently qualify for reduced production taxes because they are discoveries based on the use of 3-D seismic or high cost wells. A 17% increase in the average pre-hedge sales price that we received for our oil and natural gas in the second quarter 2004 was the primary reason for the increase production taxes for the second quarter 2004. This increase in production taxes was partially offset by reduced tax rates or tax credits on certain wells. Production taxes for the second quarter 2004 were 4.7% of revenue from the sale of oil and natural gas before gains and losses due to hedging, compared to 5.8% in the second quarter last year. Production taxes for the first six months of 2004 were flat relative to production taxes in the first six months of 2003. Production taxes for the first six months of 2004 were 4.8% of revenue from the sale of oil and natural gas before gains and losses due to hedging, compared to 5.5% in the first six months of last year. 23 General and administrative expenses. We capitalize a portion of our general and administrative costs. The costs capitalized represent the cost of technical employees, who work directly on capital projects. An engineer designing a well is an example of a technical employee working on a capital project. The cost of a technical employee includes associated technical organization costs such as supervision, telephone and postage. The following table presents general and administrative expenses for the second quarter and first six months of 2004 and 2003.
THREE MONTHS ENDED, JUNE 30, SIX MONTHS ENDED, JUNE 30, --------------------------- -------------------------- % % 2004 2003 CHANGE 2004 2003 CHANGE ------ ------ ------- ------ ------ ------- (IN THOUSANDS) General and administrative expenses. $1,199 $1,187 1% $2,419 $2,326 4% (PER MCFE) General and administrative expenses. $ 0.39 $ 0.46 (15%) $ 0.39 $ 0.43 (9%)
General and administrative expenses for the second quarter of 2004 were flat relative to general and administrative expenses in the second quarter last year. An increase in production volumes was the primary reason for the 15% decrease in our second quarter 2004 general and administrative expenses on a per unit basis. General and administrative expenses for the first six months of 2004 increased by 4% over general and administrative expenses during the first six months of 2003. The change in our general and administrative expenses for the for the first six months of 2004 was due to the following: - - An 8% increase in payroll and employee benefit expenses net of amounts charged to joint ventures to cover the costs of managing these joint operations represented 40% of the total increase. - - An increase in expenses for external reserve engineering services and outside legal services represented 19% and 6% of the total increase, respectively. - - Increases in expenses for corporate insurance represented 11% of the total increase, for franchise taxes represented 8% of the total increase and for software maintenance and supply represented 4% of the total increase. - - These increases were partially offset by decrease in a 35% reduction in financial reporting and director fees, a 26% reduction in fees for outside consulting services and a 5% reduction in rent expense. The 9 % decrease in general and administrative expenses on a per unit basis for the first six months of 2004 was due the increase in production volumes for the first six months of 2004. 24 Depletion of oil and natural gas properties. Our full-cost depletion expense is driven by many factors including certain costs spent in the exploration and development of producing reserves, production levels, and estimates of proved reserve quantities and future developmental costs at the end of the year. The following table presents depletion expense for the second quarter and first six months of 2004 and 2003.
THREE MONTHS ENDED, JUNE 30, SIX MONTHS ENDED, JUNE 30, --------------------------- -------------------------- % % 2004 2003 CHANGE 2004 2003 CHANGE ------ ------ ------- ------- ------ ------- (IN THOUSANDS) Depletion of oil and natural gas properties. $5,623 $3,799 48% $10,503 $7,901 33% (PER MCFE) Depletion rate . . . . . . . . . . . . . . . $ 1.82 $ 1.46 25% $ 1.71 $ 1.46 17%
Increased production volumes combined with an increase in our per unit depletion rate resulted in an 48% increase in our second quarter 2004 depletion expense. Higher production volumes accounted for approximately 39% of the increase in depletion expense while a 25% increase in our depletion rate accounted for 61% of the increase. The increase in our depletion rate was primarily the result of increased cost of reserve additions during the first half of 2004. Increased production volumes combined with an increase in our per unit depletion rate resulted in an 33% increase in our depletion expense for the first six months of 2004. Higher production volumes accounted for approximately 41% of the increase in depletion expense while a 17% increase in our depletion rate accounted for 59% of the increase. The increase in our depletion rate was primarily the result of increased cost of reserve additions during the first half of 2004. 25 Net interest expense. We capitalize interest expense on borrowings associated with major capital projects prior to their completion. Capitalized interest is added to the cost of the underlying assets and is amortized over the lives of the assets. The following table presents interest expense for the second quarter and first six months of 2004 and 2003.
THREE MONTHS ENDED, JUNE 30, SIX MONTHS ENDED, JUNE 30, ----------------------------- --------------------------- % % 2004 2003 CHANGE 2004 2003 CHANGE -------- -------- -------- -------- -------- ------- (IN THOUSANDS) Interest on senior credit facility. . . . . . . . . . . . $ 249 $ 509 (51%) $ 434 $ 1,145 (62%) Interest on senior subordinated notes (a) . . . . . . . . 445 597 (25%) 884 1,180 (25%) Commitment fees . . . . . . . . . . . . . . . . . . . . . 53 31 71% 107 35 206% Dividend on Series A mandatorily redeemable preferred stock (b) . . . . . . . . . . . . . . . . . 179 - - 354 - - Amortization of deferred loan and debt issuance cost. . . 191 280 (32%) 383 533 (28%) Other general interest expense. . . . . . . . . . . . . . 6 13 (54%) 14 28 (50%) Capitalized interest expense. . . . . . . . . . . . . . . (269) (206) 31% (540) (415) 30% -------- -------- ------------------ Net interest expense. . . . . . . . . . . . . . . . . . . $ 854 $ 1,224 (30%) $ 1,636 $ 2,506 (35%) ======== ======== ================== Weighted average debt outstanding . . . . . . . . . . . . $62,674 $77,528 (19%) $58,673 $79,504 (26%) Average interest rate on outstanding indebtedness (c) . . 5.9% 5.9% 6.1% 5.9% (a) Interest expense on our senior subordinated notes paid in kind through the issuance of additional debt in lieu of cash. Our option to pay interest in kind on our senior subordinated notes expired in October 2003. . . . . . . . . . . . . . . . . . . $ - $ 299 $ - $ 590 (b) Dividend on Series A preferred stock paid in kind through the issuance of preferred stock in lieu of cash. The dividend on our mandatorily redeemable preferred stock in the second quarter and first six months of 2003 was recorded as dividends in dividends and accretion. Our option to pay dividends in kind on our Series A preferred stock expires in October 2005. . . . . . . . . . . . . . . 179 - 354 - (c) Calculated as the sum of interest expense on outstanding indebtedness, commitment fees and dividend on our Series A mandatorily redeemable preferred stock divided by the weighted average debt and preferred stock outstanding for the period.
Net interest expense for the second quarter 2004 was 30% lower than interest in the same quarter of the prior year. The change in interest expense was primarily due to the following: - - A decrease in outstanding debt drawn under our senior credit facility combined with a decrease in the interest rate that we paid on those outstanding borrowings resulted in a $260,000 decrease in net interest expense. This decrease was offset by a $22,000 increase in the commitment fees paid on the unused portion of our borrowing base. - - A decrease in the amount of subordinated notes outstanding and a decrease in the interest rate paid on our senior subordinated notes resulted in a $152,000 decrease in net interest expense. - - An increase in the amount of interest capitalized. - - These decreases were partially offset by an increase in dividend related to our mandatorily redeemable preferred stock. Upon our adoption of SFAS 150 in July 2003, we reclassified approximately $8 million of our then outstanding mandatorily redeemable Series A and Series B preferred stock, which had no equity conversion 26 features and must be settled with our assets, to long-term debt. As part of this reclassification, we now report the dividends on the mandatorily redeemable preferred stock that was reclassified as interest expense. Prior to this reclassification, the dividend on our mandatorily redeemable preferred stock was reported as dividends in dividend and accretion of mandatorily redeemable preferred stock. Excluding the dividend and weighted average mandatorily redeemable preferred balance outstanding for the second quarter 2004, our average interest rate on outstanding indebtedness was 5.6%. Net interest expense for the first six months of 2004 was 35% lower than interest expense during the first six months of 2003. The change was due to the following: - - A decrease in outstanding debt drawn under our senior credit facility combined with a decrease in the interest rate that we paid on those borrowings resulted in a $711,000 decrease in net interest expense. This decrease was offset by a $72,000 increase in the commitment fees paid on the unused portion of our borrowing base. - - A decrease in the amount of subordinated notes outstanding and a decrease in the interest rate paid on our senior subordinated notes resulted in a $296,000 decrease in net interest expense. - - An increase in the amount of interest capitalized. - - These decreases were partially offset by an increase in dividend related to our manadatorily redeemable preferred stock. Excluding the dividend and weighted average mandatorily redeemable preferred balance outstanding for the first six months of 2004, our average interest rate on outstanding indebtedness was 5.7%. Other income (expense). Other income (expense) primarily includes non-cash gains (losses) resulting from the change in fair market value of oil and gas derivative contracts that did not qualify as hedges, cash gains (losses) on the settlement of these contracts and non-cash gains (losses) related to charges for the ineffective portions of cash flow hedges.
THREE MONTHS ENDED, JUNE 30, SIX MONTHS ENDED, JUNE 30, ------------------------------------ ------------------------------------ % % 2004 2003 CHANGE 2004 2003 CHANGE ----------- ----------- ---------- ----------- ----------- ---------- (IN THOUSANDS) Non-cash loss for ineffective portion of hedges. $ (187) $ (281) (33%) $ (60) $ (170) (65%) Other income . . . . . . . . . . . . . . . . . . 69 - - 69 - ----------- ----------- ----------- ----------- Total other income (expense). . . . . . . . $ (118) $ (281) (58%) $ 9 $ (170) - =========== =========== =========== ===========
Income taxes. Since inception, we have not been required to recognize any current income taxes. Furthermore, we do not expect to recognize significant, if any, current income taxes in 2004. Since inception, we have generated net operating losses (NOLs) due mainly to intangible drilling and other property related deductions, which have exceeded taxable income. Our regular NOLs are $107.5 million, and our alternative minimum tax NOLs are $93.3 million. To date, we have not utilized any of our NOLs. In future periods, our NOLs will be used to offset taxable income. Since 1997 through year-end 2003, we have not been required to recognize any deferred income taxes. Due to the level of projected net income, we expect to evolve from a net deferred tax asset to a net deferred tax liability position. It is management's belief that we will begin to utilize our NOLs and will have reversals of existing temporary differences between book and taxable income such that a net deferred tax liability is expected at year-end 2004, as well as in future years. Accordingly, we recognized deferred tax expense of $5.2 million during the first six months of 2004. 27 Dividends and accretion of mandatorily redeemable preferred stock. We are required to pay dividends on our Series A and were required to pay dividends on our Series B preferred stock prior to its redemption. At our option, these dividends may be paid in cash at a rate of 6% per annum or paid in kind through the issuance of additional shares of preferred stock in lieu of cash at a rate of 8% per annum. We elected to pay dividends in kind in each quarter of 2004 and 2003. Upon our adoption of SFAS 150 in July 2003, approximately $8 million of our then outstanding mandatorily redeemable Series A and Series B preferred stock that must be settled with our assets to long-term debt, was reclassified to long-term debt. As part of the reclassification, the dividend paid on the reclassified amount since July 2003 has been reported as interest expense. In November and December 2003, CSFB Private Equity used a portion of our mandatorily redeemable Series A and Series B preferred stock that it held to pay for the exercise of the associated warrants. We also redeemed the remaining balance of Series B preferred stock that was not used to pay for the exercise. The following table shows the effect for the three and six month periods ended June 30, 2004 and 2003, of the issuance of additional shares of preferred stock in lieu of paying cash dividends.
THREE MONTHS ENDED, JUNE 30, SIX MONTHS ENDED, JUNE 30, ----------------------------- ----------------------------- % % 2004 2003 CHANGE 2004 2003 CHANGE -------- --------- -------- -------- --------- -------- (IN THOUSANDS) Dividends. . . . . . . . . . . . . . . . $ - $ 923 - $ - $ 1,817 - Accretion of redeemable preferred stock. - 105 - - 206 - -------- --------- -------- --------- Total dividends and accretion . . . $ - $ 1,028 - $ - $ 2,023 - ======== ========= ======== ========= Additional preferred shares issued Series A . . . . . . . . . . . . . . . . 8,924 35,905 (75%) 17,675 70,728 (75%) Series B . . . . . . . . . . . . . . . . - 10,197 - - 20,087 -
OTHER MATTERS Effects of Inflation and Changes in Prices Our results of operations and cash flows are affected by changing oil and gas prices. If the price of oil and natural gas increases (decreases), there could be a corresponding increase (decrease) in revenues as well as the operating costs that we are required to bear for operations. Inflation has had a minimal effect on us. Environmental and Other Regulatory Matters Our business is subject to certain federal, state and local laws and regulations relating to the exploration for and the development, production and marketing of oil and natural gas, as well as environmental and safety matters. Many of these laws and regulations have become more stringent in recent years, often imposing greater liability on a larger number of potentially responsible parties. Although we believe we are in substantial compliance with all applicable laws and regulations, the requirements imposed by laws and regulations are frequently changed and subject to interpretation, and we cannot predict the ultimate cost of compliance with these requirements or their effect on our operations. Any suspensions, terminations or inability to meet applicable bonding requirements could materially adversely affect our financial condition and operations. Although significant expenditures may be required to comply with governmental laws and regulations applicable to us, compliance has not had a material adverse effect on our earnings or competitive position. Future regulations may add to the cost of, or significantly limit, drilling activity. 28 New Accounting Pronouncements On April 30, 2004, the Financial Accounting Standards Board (FASB) staff issued FASB Staff Position (FSP) SFAS 141-1 and 142-1, "Interaction of FASB Statements NO. 141, Business Combinations, and No. 142, Goodwill and Other Intangible Assets, and Emerging Issues Task Force (EITF) Issue No. 04-2, Whether Mineral Rights Are Tangible or Intangible Assets" and the guidance in the FSP shall be applied to the first reporting period after April 29, 2004. Under the FSP certain use rights may have characteristics of tangible assets, thus we will continue to classify our oil and gas leaseholds as tangible oil and gas properties. Risk Factors Related to Our Business - - Our level of indebtedness may adversely affect our cash available for operations, thus limiting our growth, our ability to make interest and principal payments on our indebtedness as they become due and our flexibility to respond to market changes. - - We have substantial capital requirements for which we may not be able to obtain adequate financing. - - Oil and natural gas prices fluctuate widely and low prices could have a material adverse impact on our business and financial results by limiting our liquidity and flexibility to accelerate our drilling program. - - Our hedging transactions could reduce revenues in a rising commodity price environment or expose us to other risks. - - Exploratory drilling is a speculative activity that may not result in commercially productive reserves and may require expenditures in excess of budgeted amounts. - - We are subject to various operating and other casualty risks that could result in liability exposure or the loss of production and revenues. - - We may not have enough insurance to cover all of the risks we face, which could result in significant financial exposure. - - We cannot control the activities on properties we do not operate and are unable to ensure their proper operation and profitability. - - The marketability of our natural gas production depends on facilities that we typically do not own or control, which could result in a curtailment of production and revenues. - - Lower oil and natural gas prices may cause us to record ceiling limitation write-downs which would reduce our stockholders' equity. - - We have had operating losses in the past and may not be profitable in the future. - - Our future operating results may fluctuate and significant declines in them would limit our ability to invest in projects. - - The failure to replace reserves in the future would adversely affect our production and cash flows. - - We are subject to uncertainties in reserve estimates and future net cash flows. - - We face significant competition, and many of our competitors have resources in excess of our available resources. - - We are subject to various governmental regulations and environmental risks which may cause us to incur substantial costs. - - Our business may suffer if we lose key personnel. Disclosure Regarding Forward-Looking Statements Statements included in this report which are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), are forward-looking statements. These statements can be identified by the use of forward-looking terminology including "may," "believe," "will," "expect," "anticipate," "estimate," "continue" or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other "forward-looking" information. These forward-looking statements are made based upon management's current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. 29 Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under "Risk Factors Related to Our Business," and elsewhere in this report. You should read these statements carefully because they discuss our expectations about our future performance, contain projections of our future operating results or our future financial condition, or state other "forward-looking" information. You should be aware that the occurrence of any of the events described in "Risk Factors Related to Our Business" and elsewhere in this report could substantially harm our business, results of operations and financial condition and that upon the occurrence of any of these events, the trading price of our common shares could decline. 30 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK The following quantitative and qualitative disclosures about market risk are supplementary to the quantitative and qualitative disclosures provided in our Annual Report on Form 10-K for the fiscal year ended December 31, 2003. As such, the information contained herein should be read in conjunction with the related disclosures in our Annual Report on Form 10-K for the fiscal year ended December 31, 2003. DERIVATIVE CONTRACTS The following table reflects our open natural gas derivative contracts at June 30, 2004, the volumes associated with those contracts and the corresponding weighted average NYMEX reference price by quarter.
2004 2005 ---------------- ---------------------------------------- THIRD FOURTH FIRST SECOND THIRD FOURTH QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER ------- -------- -------- -------- -------- --------- NATURAL GAS SWAPS: Volumes (MMbtu). . . . . . 138,000 92,000 - - - - Average price ($per MMBtu) $ 4.180 $ 4.360 $ - $ - $ - $ - NATURAL GAS COLLARS: Volumes (MMbtu). . . . . . 722,200 586,100 517,500 455,000 - - Average price ($per MMBtu) Floor. . . . . . . . . . . $ 4.613 $ 4.746 $ 4.663 $ 4.725 $ - $ - Ceiling. . . . . . . . . . 6.476 6.690 7.100 6.712 - -
The following table reflects our open oil derivative contracts at June 30, 2004, the associated volumes and the corresponding weighted average NYMEX reference price by quarter.
2004 2005 ------------------ -------------------------------------- THIRD FOURTH FIRST SECOND THIRD FOURTH QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER -------- -------- -------- -------- -------- -------- OIL SWAPS: Volumes (Bbls) . . . . . 13,800 9,200 - - - - Average price ($per Bbl) $ 23.91 $ 23.80 $ - $ - $ - $ - OIL COLLARS: Volumes (Bbls) . . . . . 48,760 34,260 27,450 18,655 - - Average price ($per Bbl) Floor. . . . . . . . . . $ 26.34 $ 26.38 $ 25.56 $ 26.80 $ - $ - Ceiling. . . . . . . . . 32.20 31.71 30.18 32.51 - -
31 ITEM 4. CONTROLS AND PROCEDURES EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES As of the end of period covered by this report, our principal executive officer and principal financial officer carried out an evaluation of the effectiveness of our disclosure controls and procedures. Based on their evaluation, they have concluded that our disclosure controls and procedures effectively ensure that the information required to be disclosed in the reports we file with the SEC is recorded, processed, summarized and reported within the time periods specified by the SEC. CHANGES IN INTERNAL CONTROLS There were no changes in our internal controls or in other factors that have materially affected, or are reasonably likely to materially affect, our internal controls subsequent to the date of their evaluation of our disclosure controls and procedures. 32 PART II - OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS As discussed in Note 3 of Notes to the Consolidated Financial Statements included in Part I. Financial Information, Brigham is party to various legal actions arising in the ordinary course of business and does not expect these matters to have a material adverse effect on its financial condition, results of operations or cash flow. ITEM 2. CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES Issuer Purchases of Equity Securities
TOTAL NUMBER OF AVERAGE PRICE PAID PERIOD SHARES PURCHASED PER SHARE - ---------------------------------- ----------------- ----------------------- January 1, 2004 - January 31, 2004 19,596 $ 7.970 June 1, 2004 - June 30, 2004 821 $ 8.560
No purchases were made under a publicly announced plan. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS (a) We held our Annual Stockholders meeting on Thursday, June 3, 2004, in Austin, Texas at 1 p.m. local time. (b) Proxies were solicited by the Board of Directors of Brigham pursuant to Regualtion 14A under the Securities Exchange Act of 1934. There were no solicitations in opposition to the Board of Directors' nominees as listed in the proxy statement and all of such nominees were duly elected. (c) Out of the total 39,625,276 shares of our common stock and outstanding and entitled to vote, 33,064,686 shares were present in person or by proxy, representing approximately 83%. They only matters voted on by our stockholders, as fully described in the definitive proxy materials for the annual meeting, are set forth below. The results were as follows: 1. To elect eight directors to serve until the Annual Meeting of Stockholders in 2005.
NUMBER OF SHARES NUMBER OF SHARES NUMBER OF SHARES WITHHOLDING VOTING FOR ELECTION AS VOTING AGAINST AUTHORITY TO VOTE FOR NOMINEE DIRECTOR ELECTION AS DIRECTOR ELECTION AS DIRECTOR - -------------------- ---------------------- -------------------- --------------------- Ben M. "Bud" Brigham 28,588,524 4,476,162 - David T. Brigham 28,521,124 4,476,162 - Harold D. Carter 27,836,693 5,160,593 - Stephen C. Hurley 32,097,666 967,020 - Stephen P. Reynolds 32,097,666 967,020 - Hobart A. Smith 32,036,066 967,020 - Steven A. Webster 28,423,421 4,476,162 - R. Graham Whaling 32,097,666 967,020 -
2. To approve the appointment of PricewaterhouseCoopers LLP as independent auditors of Brigham for the year ending December 31, 2004. For 32,752,485 Against 263,946 Abstained 48,255 33 3. To consider and vote on a proposal to approve an amendment to the 1997 Incentive Plan to increase the number of shares of common stock available under the Plan. For 18,629,721 Against 8,672,397 Abstained 104,645 Not Voted 5,657,923 34 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits: 31.1 Certification of Chief Executive Officer of the Company pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 31.2 Certification of Chief Financial Officer of the Company pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 32.1 Certification of Chief Executive Officer of the Company pursuant to 18 U.S.C. Sec. 1350 32.2 Certification of Chief Financial Officer of the Company pursuant to 18 U.S.C. Sec. 1350 (b) Brigham Exploration Company filed the following reports on Form 8-K during the quarter covered by this Quarterly Report on Form 10-Q: (1) Filed May 11, 2004 on Item 12, Brigham issued a press release announcing its financial results for the first quarter 2004, and provided its forecast for second quarter 2004 financial results. 35 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on August 13, 2004. BRIGHAM EXPLORATION COMPANY By: /s/ BEN M. BRIGHAM --------------------- Ben M. Brigham Chief Executive Officer, President and Chairman of the Board By: /s/ EUGENE B. SHEPHERD, JR. ------------------------------- Eugene B. Shepherd, Jr. Executive Vice President and Chief Financial Officer 36 EX-31.1 2 doc2.txt EXHIBIT 31.1 Exhibit 31.1 CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO RULE 13a-14(a) OF THE SECURITIES EXCHANGE ACT OF 1934 I, Bud M. Brigham, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Brigham Exploration Company; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15e and 15d-15(e)) for the registrant and have: a) Designed such disclosure controls and procedures or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions and about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting, which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: August 13, 2004 /s/ Bud M. Brigham --------------------------------------- Bud M. Brigham Chief Executive Officer, President and Chairman of the Board EX-31.2 3 doc3.txt EXHIBIT 31.2 Exhibit 31.2 CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO RULE 13a-14(a) OF THE SECURITIES EXCHANGE ACT OF 1934 I, Eugene B. Shepherd, Jr, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Brigham Exploration Company; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15e and 15d-15(e)) for the registrant and have: a) Designed such disclosure controls and procedures or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions and about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting, which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: August 13, 2004 /s/ Eugene B. Shepherd, Jr. ---------------------------------------- Eugene B. Shepherd, Jr. Executive Vice President and Chief Financial Officer EX-32.1 4 doc4.txt EXHIBIT 32.1 Exhibit 32.1 CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of Brigham Exploration Company (the"Company") on Form 10-Q for the period ending March 31, 2004 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Ben M.Brigham, President, Chief Executive Officer and Chairman of the Board of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated: August 13, 2004 /s/ Bud M. Brigham -------------------------------------------------- Bud M. Brigham Chief Executive Officer, President and Chairman of the Board This certification shall not be deemed to be "filed" for the purpose of Section 18 of the Securities Exchange Act of 1934, as amended, and will not be incorporated by reference into any registration statement filed under the Securities Act of 1933, as amended, unless specifically identified therein as being incorporated therein by reference. A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Brigham Exploration Company and will be retained by Brigham Exploration Company and furnished to the Securities and Exchange Commission or its staff upon request. EX-32.2 5 doc5.txt EXHIBIT 32.2 Exhibit 32.2 CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of Brigham Exploration Company (the"Company") on Form 10-Q for the period ending March 31, 2004 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Eugene B. Shepherd, Jr., Executive Vice President and Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated: August 13, 2004 /s/ Eugene B. Shepherd, Jr. ------------------------------- Eugene B. Shepherd, Jr. Executive Vice President and Chief Financial Officer This certification shall not be deemed to be "filed" for the purpose of Section 18 of the Securities Exchange Act of 1934, as amended, and will not be incorporated by reference into any registration statement filed under the Securities Act of 1933, as amended, unless specifically identified therein as being incorporated therein by reference. A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided Brigham Exploration Company and will be retained by Brigham Exploration Company and furnished to the Securities and Exchange Commission or its staff upon request. -----END PRIVACY-ENHANCED MESSAGE-----