-----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, VB2fJlfcJXS4GYBag233DVJz+DS+xLiEE/VmJU3EbSqc2Qsiv7kXg0CgAe4COjHA REKEb8vEKZlCdGfHuuVPjg== 0000950129-03-004701.txt : 20030918 0000950129-03-004701.hdr.sgml : 20030918 20030918154728 ACCESSION NUMBER: 0000950129-03-004701 CONFORMED SUBMISSION TYPE: 424B1 PUBLIC DOCUMENT COUNT: 1 FILED AS OF DATE: 20030918 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: 424B1 SEC ACT: 1933 Act SEC FILE NUMBER: 333-105943 FILM NUMBER: 03901251 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 424B1 1 h06625b1e424b1.txt BRIGHAM EXPLORATION COMPANY - REG.NO. 333-105943 FILED PURSUANT TO RULE 424(b)(1) REGISTRATION NO. 333-105943 9,000,000 SHARES (BRIGHAM EXPLORATION COMPANY LOGO) COMMON STOCK $5.85 PER SHARE - -------------------------------------------------------------------------------- Brigham Exploration Company is offering 7,000,000 shares of common stock and the selling stockholders' identified in this prospectus are offering 2,000,000 shares of common stock. The common stock is listed on the Nasdaq National Market under the symbol "BEXP." On September 17, 2003, the last reported sale price of the common stock on the Nasdaq National Market was $5.98 per share. INVESTING IN THE COMMON STOCK INVOLVES RISKS. SEE "RISK FACTORS" BEGINNING ON PAGE 9.
PER SHARE TOTAL ----------- ----------- Price to the public......................................... $5.850 $52,650,000 Underwriting discount....................................... 0.351 3,159,000 Proceeds to Brigham Exploration Company..................... 5.499 38,493,000 Proceeds to the selling stockholders........................ 5.499 10,998,000
We and some of our selling stockholders have granted an over-allotment option to the underwriters. Under this option, the underwriters may elect to purchase a maximum of 1,350,000 additional shares (384,090 shares from us and 965,910 shares from the selling stockholders) within 30 days following the date of this prospectus to cover over-allotments. - -------------------------------------------------------------------------------- NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR DETERMINED IF THIS PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. CIBC WORLD MARKETS RAYMOND JAMES JOHNSON RICE & COMPANY L.L.C. The date of this prospectus is September 17, 2003. [INSIDE FRONT COVER.] MAP SHOWING OUR THREE CORE AREAS. TABLE OF CONTENTS
PAGE ---- Prospectus Summary.......................................... 1 Risk Factors................................................ 9 Forward-Looking Statements.................................. 18 Use of Proceeds............................................. 19 Selling Stockholders........................................ 20 Capitalization.............................................. 21 Price Range of Common Stock and Dividend Policy............. 22 Selected Consolidated Financial Data........................ 23 Management's Discussion and Analysis of Financial Condition and Results of Operations................................. 25 Business and Properties..................................... 46 Management.................................................. 61 Description of Capital Stock................................ 64 Underwriting................................................ 68 Legal Matters............................................... 70 Experts..................................................... 70 Where You Can Find More Information......................... 71 Glossary of Certain Oil and Gas Terms....................... 72 Index to Financial Statements............................... F-1 Appendix A-1 to Prospectus.................................. A-1
i [THIS PAGE INTENTIONALLY LEFT BLANK] ii PROSPECTUS SUMMARY This summary highlights certain material information contained or incorporated by reference in this prospectus. You should carefully read the entire prospectus and the documents incorporated by reference in this prospectus. Unless the context otherwise requires, all references to "Brigham," "we," "us," and "our" refer to Brigham Exploration Company and its subsidiaries. The term "you" refers to a prospective investor. We have included definitions of technical terms and abbreviations important to an understanding of our business under "Glossary of Certain Oil and Gas Terms" beginning on page 72. ABOUT US We are an independent exploration, development and production company that utilizes 3-D seismic imaging and other advanced technologies to systematically explore for, develop and produce domestic onshore oil and natural gas reserves. We focus our activities in provinces where we believe 3-D seismic technology can be used effectively to maximize our return on invested capital by reducing drilling risk. Our exploration and development activities are concentrated in three provinces: the onshore Texas Gulf Coast, the Anadarko Basin and West Texas. At December 31, 2002, we had estimated proved reserves of 121.1 Bcfe, of which 82% was natural gas, with an estimated SEC PV-10% value of $307 million, and we operated approximately 61% of this value. Since our inception in 1990, we have evolved from a pioneering, 3-D seismic-driven exploration company to a balanced exploration and development company, with technical and operational expertise and a strong production base. Furthermore, we have generated a multi-year inventory of exploration prospects which, due to our recent field discoveries, are complemented by a multi-year inventory of development locations. From our inception through December 31, 2002, we have drilled approximately 555 wells, consisting of approximately 431 exploratory and 124 development wells, with an aggregate completion rate of 68% and an average all-sources finding cost of $1.35 per Mcfe. In 2002, we spent $27.7 million in capital expenditures on oil and gas activities and achieved an all-sources finding cost of $1.36 per Mcfe. Additionally, we successfully completed 22 of 24 wells drilled in 2002, replacing 206% of our 2002 production. To further capitalize on our multi-year inventory of exploration and development prospects, we currently plan to accelerate our drilling program and significantly increase our capital expenditures in 2003 to approximately $55 million, representing a 97% increase over 2002 spending. In addition, we currently plan to spend approximately $81 million in capital expenditures in 2004. Since 1999, we have discovered five significant new fields: the Home Run, Triple Crown, Floyd Fault Block and Providence Fields, all located in the onshore Texas Gulf Coast, and the Mills Ranch Field located in the Anadarko Basin. Due in part to these field discoveries, we believe we have a multi-year inventory of approximately 150 potential development drilling locations of which approximately 46 are expected to be drilled over the next 18 months. In 2001 and 2002, we spent approximately 56% of our drilling expenditures on development drilling, and we estimate that approximately 56% of our total 2003 and 2004 drilling expenditures will fund development drilling. We believe our substantial development drilling activities complement our exploration activities and contribute to more consistent operating and financial performance. We believe that our utilization of large-scale 3-D seismic surveys and related technology in our core provinces allows us to create and maintain a multi-year inventory of high quality exploration prospects and provides us with the opportunity to enhance our exploration success and efficiently deploy our capital. As of December 31, 2002, we had accumulated approximately 8,854 square miles (5.7 million acres) of 3-D seismic data. Utilizing our 3-D seismic database, our highly skilled technical staff is continually adding to and refining our inventory of drilling locations. As a result, we have generated a multi-year inventory of exploratory drilling locations and expect to drill approximately 43 of these locations within the next 18 months. We internally generate substantially all of our prospects without reliance on third party 1 generated opportunities, which usually involve the payment of consideration over and above the costs incurred to generate and drill the prospect. From inception we have internally generated in excess of 95% of our prospects, which we believe is a distinguishing characteristic for our company. BUSINESS STRATEGY Our business strategy is to create stockholder value by growing reserves, production volumes and cash flow through exploration and development drilling in areas where we believe our operations will likely result in a high return on our invested capital. Key elements of our business strategy include: - focus on core provinces and trends; - internally generate inventory of high quality exploratory prospects; - capitalize on exploration successes through development of field discoveries; - accelerate drilling of our prospect inventory; and - enhance returns through operational control. Through the execution of this business strategy, we have achieved the following results over the three years ended December 31, 2002: - increased our estimated net proved reserves from 84 Bcfe at December 31, 1999 to 121.1 Bcfe at December 31, 2002, for a three-year compound annual growth rate of 13%; - increased our average daily production volumes from 17.4 MMcfe/d for the year ended December 31, 1999 to 27.8 MMcfe/d for the year ended December 31, 2002, for a three-year compound annual growth rate of 17%; - realized all-sources finding cost for the three-year period ended December 31, 2002 of $1.31 per Mcfe; and - increased our operating income from $3.6 million for the year ended December 31, 2000 to $9.4 million for the year ended December 31, 2002. CORE EXPLORATION AND DEVELOPMENT PROPERTIES For the three-year period ended December 31, 2002, we completed 73 wells (26.4 net) in 84 attempts for a completion rate of 87% and an average all-sources finding cost of $1.31 per Mcfe. Set forth in the table below is a summary of our oil and natural gas reserves at December 31, 2002 and average daily production for the year ended December 31, 2002, followed by a summary of our recent activity and planned future activity in our core provinces.
YEAR ENDED DECEMBER 31, 2002 AT DECEMBER 31, 2002 ------------------------- ----------------------------------------------------------- DRILLING AVERAGE PRODUCTIVE CAPITAL DAILY PROVED SEC % WELLS 3-D SEISMIC EXPENDITURES PRODUCTION RESERVES PV-10% NATURAL ----------- DATA PROVINCE (MILLIONS) (MMCFE/D) (BCFE) (MILLIONS) GAS GROSS NET (SQ. MILES) - -------- ------------ ---------- -------- ---------- ------- ----- --- ----------- Texas Gulf Coast..... $13.3 14.7 65.4 $181.3 84% 53 14.7 2,686 Anadarko Basin....... 5.5 7.1 46.0 102.0 94% 110 27.2 2,197 West Texas/Other..... 1.0 6.0 9.7 24.1 17% 94 26.6 3,971 ------------ --------- -------- ---------- ----- --- ----------- Total.............. $19.8 27.8 121.1 $307.4 82% 257 68.5 8,854 ============ ========= ======== ========== ===== === ===========
Texas Gulf Coast The onshore Texas Gulf Coast is a high-potential, multi-pay, predominantly natural gas producing province. We believe our exploration approach and our staff's extensive experience in this area provide us with significant competitive advantages. During the three years ended December 31, 2002, we completed 2 36 wells (11.8 net) in 40 attempts for a completion rate of 90% and added an estimated 43.1 Bcfe in estimated proved reserves. For 2003, we intend to focus our drilling activity in this province on the development of our Home Run, Triple Crown and Floyd Fault Block field discoveries in the Vicksburg trend, the testing of high reserve potential fault blocks adjacent to these fields, the development of our Providence Field in the Frio trend and the continued drilling of our 3-D delineated exploration inventory in the Frio trend. During 2003, we expect to spend approximately $28 million to drill 24 wells in the onshore Texas Gulf Coast, compared to 10 wells drilled in 2002. Approximately 44% percent of these capital expenditures are budgeted for development drilling, with the remainder allocated towards exploration drilling. Anadarko Basin The Anadarko Basin is a prolific natural gas producing province that we believe offers a combination of lower risk, lower potential exploration and development opportunities in shallower horizons as well as higher risk, higher potential opportunities in deeper sections. During the three years ended December 31, 2002, we completed 26 wells (8.8 net) in 31 attempts for a completion rate of 84% and added an estimated 19.2 Bcfe in proved reserves. For 2003, we intend to focus our drilling activity in this province on our 3-D delineated exploration and development inventory in the Springer and Hunton trends. During 2003, we expect to spend approximately $12 million to drill 23 wells in the Anadarko Basin compared to seven wells drilled in 2002. Approximately 72% percent of these capital expenditures are budgeted for development drilling, with the remainder allocated towards exploration drilling. West Texas West Texas is predominantly an oil producing province with generally longer-lived reserves than those of the onshore Texas Gulf Coast. In West Texas, we have conducted our exploration activities in various carbonate reservoirs, including the Canyon Reef and Fusselman formations in the Horseshoe Atoll trend and the Canyon Reef of the Eastern Shelf. During the three years ended December 31, 2002, we completed 11 wells (5.8 net) in 13 attempts for a completion rate of 85% and added an estimated 6.1 Bcfe in proved reserves. For 2003, we intend to focus our drilling activities on our 3-D delineated exploration and development inventory in the Canyon Reef and Fusselman formations of the Horseshoe Atoll trend. During 2003, we expect to spend approximately $2 million to drill six wells in West Texas, compared to seven wells drilled in 2002. Approximately 59% of these capital expenditures are budgeted for development drilling, with the remainder allocated towards exploration drilling. OUR EXECUTIVE OFFICES Our executive offices are located at 6300 Bridge Point Parkway, Building Two, Suite 500, Austin, Texas 78730 and our telephone number is (512) 427-3300. Information contained on our website, www.bexp3d.com, is not part of this prospectus. 3 THE OFFERING Common stock offered by us...................... 7,000,000 shares(a) Common stock offered by the selling stockholders.................................... 2,000,000 shares(b) Common stock to be outstanding after this offering........................................ 27,569,452 shares(a),(c),(d) Use of proceeds................................. We intend to use the proceeds from this offering to accelerate our exploration and development activities and for general corporate purposes. Pending such use, we intend to use the net proceeds to repay outstanding indebtedness under our senior credit facility. We intend to re-borrow under our senior credit facility to fund costs as they are incurred. See "Use of Proceeds." Nasdaq National Market Symbol................... BEXP - --------------------------- (a) Does not include 384,090 shares that may be sold upon exercise of the underwriters' over-allotment option granted by us. (b) Does not include 965,910 shares that may be sold upon exercise of the underwriters' over-allotment option granted by the selling stockholders. (c) Based on shares outstanding as of September 17, 2003. The shares of common stock to be outstanding after this offering also does not include 11,070,780 shares issuable upon the exercise of outstanding warrants as described below: - 6,666,667 shares are issuable upon exercise of outstanding warrants with an exercise price of $3.00 per share and expiring October 2010. - 2,105,263 shares are issuable upon exercise of outstanding warrants with an exercise price of $4.35 per share and expiring March 2011. - 2,298,850 shares are issuable upon exercise of outstanding warrants with an exercise price of $4.35 per share and expiring December 2012. (d) Does not include 1,997,800 shares of our common stock reserved for issuance upon the exercise of options and vesting of restricted shares previously granted. Unless otherwise stated, all information contained in this prospectus assumes no exercise of the over-allotment option granted to the underwriters. RISK FACTORS You should consider carefully the "Risk Factors" beginning on page 9 of this prospectus before making an investment in our common stock. 4 SUMMARY HISTORICAL FINANCIAL DATA This section presents our summary historical financial data. You should read carefully the consolidated financial statements included in this prospectus, including the notes to the consolidated financial statements. The summary historical consolidated financial data is not intended to replace the consolidated financial statements. We derived the statement of operations data and statement of cash flows data for the years ended December 31, 2002, 2001 and 2000, and balance sheet data as of December 31, 2002 and 2001 from the audited financial statements included in this prospectus. We derived the balance sheet data as of December 31, 2000 from audited consolidated financial statements that are not included in this prospectus. We derived the statement of operations data and statement of cash flows data for the six months ended June 30, 2003 and 2002 and the balance sheet data as of June 30, 2003 and 2002 from the unaudited consolidated financial statements included in this prospectus.
SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, ------------------------------ ------------------- 2002 2001 2000 2003 2002 -------- -------- -------- -------- -------- (unaudited) (in thousands) STATEMENT OF OPERATIONS DATA: Revenues: Oil and natural gas sales............. $ 35,100 $ 32,293 $ 19,143 $ 26,766 $ 15,203 Other revenue......................... 76 255 69 81 27 -------- -------- -------- -------- -------- Total revenues..................... 35,176 32,548 19,212 26,847 15,230 -------- -------- -------- -------- -------- Costs and expenses: Lease operating....................... 3,759 3,486 2,139 2,244 1,667 Production taxes...................... 1,977 1,511 1,786 1,744 852 General and administrative............ 4,971 3,638 3,100 2,326 2,682 Depletion of oil and natural gas properties......................... 14,594 13,211 7,920 7,901 6,531 Depreciation and amortization......... 440 677 620 257 204 Accretion of discount on asset retirement obligation.............. - - - 71 - -------- -------- -------- -------- -------- Total costs and expenses........... 25,741 22,523 15,565 14,543 11,936 -------- -------- -------- -------- -------- Operating income...................... 9,435 10,025 3,647 12,304 3,294 -------- -------- -------- -------- -------- Other income (expense): Interest expense...................... (6,238) (6,681) (9,906) (2,506) (3,070) Interest income....................... 119 264 108 28 93 Other income (expense)................ (310) 8,080 (9,504) (170) (169) Debt conversion expense............... (630) - - - - Gain on refinancing of debt........... - - 32,267 - - -------- -------- -------- -------- -------- Total other income (expense)....... (7,059) 1,663 12,965 (2,648) (3,146) -------- -------- -------- -------- --------
5
SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, ------------------------------ ------------------- 2002 2001 2000 2003 2002 -------- -------- -------- -------- -------- (unaudited) (in thousands, except per share information) Income before income taxes and cumulative effect of change in accounting principle.................. $ 2,376 $ 11,688 $ 16,612 $ 9,656 $ 148 Income tax benefit (expense)............ - - - - - -------- -------- -------- -------- -------- Income before cumulative effect of change in accounting principle..... 2,376 11,688 16,612 9,656 148 Cumulative effect of change in accounting principle.................. - - - 268 - -------- -------- -------- -------- -------- Net income............................ 2,376 11,688 16,612 9,924 148 Preferred dividend and accretion........ 2,952 2,450 275 2,023 1,419 -------- -------- -------- -------- -------- Net income (loss) available to common stockholders....................... $ (576) $ 9,238 $ 16,337 $ 7,901 $ (1,271) ======== ======== ======== ======== ======== Net income (loss) per share Basic................................. $ (0.04) $ 0.58 $ 1.01 $ 0.40 $ (0.08) Diluted............................... (0.04) 0.44 1.01 0.30 (0.08) Weighted average shares outstanding Basic................................. 16,138 15,988 16,241 19,898 16,027 Diluted............................... 16,138 28,205 16,241 32,090 16,027 STATEMENT OF CASH FLOWS DATA: Net cash provided (used) by: Operating activities.................. $ 28,973 $ 18,922 $ (4,635) $ 23,518 $ 10,056 Investing activities.................. (27,206) (33,571) (26,071) (19,214) (13,193) Financing activities.................. 8,439 18,924 28,801 (7,391) 3,725
AT DECEMBER 31, AT JUNE 30, ------------------------------ ------------------- 2002 2001 2000 2003 2002 -------- -------- -------- -------- -------- (unaudited) (in thousands) BALANCE SHEET DATA: Cash and cash equivalents............... $ 15,318 $ 5,112 $ 837 $ 12,231 $ 5,700 Oil and natural gas properties, net..... 164,980 151,891 129,490 177,306 158,314 Total assets............................ 202,059 173,075 146,911 210,670 183,821 Long-term debt.......................... 81,797 91,721 82,000 75,382 96,218 Series A preferred stock, mandatorily redeemable............................ 19,540 16,614 8,558 21,144 18,033 Series B preferred stock, mandatorily redeemable............................ 4,777 - - 5,196 - Total stockholders' equity.............. 61,749 49,601 34,757 70,639 46,708
6 SUMMARY RESERVE AND PRODUCTION DATA The following table sets forth summary information concerning our estimated proved oil and gas reserves at December 31, 2002, 2001 and 2000 based on reports prepared by Cawley, Gillespie & Associates, Inc., our independent petroleum consultants. The SEC PV-10% and the Standardized Measure attributable to our proved reserves, shown below, use prices and costs in effect as of December 31 of the year for which such information is presented. For more information regarding our oil and natural gas reserves, please read "Business and Properties--Oil and Natural Gas Reserves."
AT DECEMBER 31, ------------------------------ 2002 2001 2000 -------- -------- -------- ESTIMATED NET PROVED RESERVES(a): Natural gas (MMcf).......................................... 99,428 88,594 78,167 Oil (MBbls)................................................. 3,607 3,748 2,870 Natural gas equivalent (MMcfe)............................ 121,070 111,081 95,388 SEC PV-10% (in thousands)................................... $307,374 $146,807 $497,666 Standardized Measure (in thousands)......................... $239,698 $120,924 $359,228 PRICES USED IN CALCULATING ESTIMATED VALUE OF PROVED RESERVES: Natural gas (per Mcf)....................................... $ 4.74 $ 2.57 $ 10.42 Oil (per Bbl)............................................... $ 31.25 $ 19.84 $ 26.83 OTHER RESERVE DATA: Three-year average all-sources finding cost (per Mcfe)...... $ 1.31 $ 1.00 $ 1.57 Three-year average reserve replacement rate................. 261% 340% 406% Proved developed reserves (MMcfe)........................... 56,141 54,287 50,083
The following table sets forth summary information concerning our production results and operating costs for the years ended December 31, 2002, 2001 and 2000 and for the six month periods ended June 30, 2003 and 2002.
SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, ------------------------- ---------------- 2002 2001 2000 2003 2002 ------ ------ ------ ------ ------ (unaudited) NET PRODUCTION VOLUME: Natural gas (MMcf)........................... 5,791 6,766 4,431 3,000 2,844 Oil (MBbls).................................. 701 468 362 402 315 Total (MMcfe).............................. 9,996 9,573 6,600 5,412 4,733 AVERAGE PRE-HEDGE SALES PRICES: Natural gas (per Mcf)........................ $ 3.33 $ 4.29 $ 4.06 $ 6.40 $ 2.91 Oil (per Bbl)................................ 25.17 24.38 29.47 31.37 22.97 Weighted Average (per Mcfe)................ 3.70 4.22 4.34 5.88 3.28 AVERAGE POST-HEDGE SALES PRICES: Natural gas (per Mcf)........................ $ 3.21 $ 3.11 $ 1.94 $ 5.12 $ 2.92 Oil (per Bbl)................................ 23.55 24.05 29.17 28.39 21.95 Weighted Average (per Mcfe)................ 3.51 3.37 2.90 4.95 3.21 COSTS AND EXPENSES PER MCFE: Lease operating.............................. $ 0.38 $ 0.36 $ 0.32 $ 0.41 $ 0.35 Production taxes............................. 0.20 0.16 0.27 0.32 0.18 General and administrative................... 0.50(b) 0.38 0.47 0.43 0.57(c) Depletion of oil and natural gas properties................................. 1.46 1.38 1.20 1.46 1.38 (Notes on following page)
7 - --------------------------- (a) In accordance with applicable requirements of the Securities and Exchange Commission, estimates of our net proved reserves and future net revenues are made using sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation). Estimated quantities of net proved reserves and future net revenues therefrom are affected by oil and natural gas prices, which have fluctuated widely in recent years. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond our control. The reserve data set forth in this table represents only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geologic interpretation and judgment. As a result, estimates of different engineers, including those used by us, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing oil and natural gas prices, operating costs and other factors. The revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. See "Risk Factors--We are subject to uncertainties in reserve estimates and future net cash flows" and "Business and Properties--Oil and Natural Gas Reserves." (b) Includes a charge for non-cash compensation expense of $596,000 ($0.06 per Mcfe) related to vesting of options by an officer who left Brigham. (c) Includes a charge for non-cash compensation expense of $596,000 ($0.13 per Mcfe) related to vesting of options by an officer who left Brigham. 8 RISK FACTORS You should carefully consider the following risk factors, in addition to the other information set forth in this prospectus, before purchasing shares of our common stock. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock. This investment includes a high degree of risk. 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. Our outstanding long-term debt was $75.7 million as of July 31, 2003. In addition, as of July 31, 2003, we had additional $15.5 million of availability under our senior credit facility. Our level of indebtedness will have several important effects on our operations, including those listed below. - We will dedicate a significant portion of our cash flow from operations to the payment of interest on our indebtedness and to the payment of our other current obligations, and will not have these cash flows available for other purposes. - The covenants in our credit facilities limit our ability to borrow additional funds or dispose of assets and may affect our flexibility in planning for, and reacting to, changes in business conditions. - Our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes may be impaired. - We may be more vulnerable to economic downturns and our ability to withstand sustained declines in oil and natural gas prices may be impaired. - Since our indebtedness is subject to variable interest rates, we are vulnerable to increases in interest rates. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Quantitative and Qualitative Disclosures about Market Risk--Interest Rate Risk." - Our flexibility in planning for or reacting to changes in market conditions may be limited. We may incur additional debt in order to fund our exploration and development activities. A higher level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and reduce our level of indebtedness depends on future performance. General economic conditions, oil and gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flow to pay the interest on our debt, and future working capital, borrowings and equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital. In addition, under the terms of our senior credit facility, our borrowing base is subject to semi-annual redeterminations based in part on prevailing oil and natural gas prices. In the event the amount outstanding exceeds the redetermined borrowing base, we could be forced to repay a portion of our borrowings. We may not have sufficient funds to make such payments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. WE HAVE SUBSTANTIAL CAPITAL REQUIREMENTS FOR WHICH WE MAY NOT BE ABLE TO OBTAIN ADEQUATE FINANCING. We make and will continue to make substantial capital expenditures in our exploration and development projects. Without additional capital resources, our drilling and other activities may be limited and our 9 business, financial condition and results of operations may suffer. We may not be able to secure additional financing on reasonable terms or at all, and financing may not continue to be available to us under our existing or new financing arrangements. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources." 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 revenues, operating results and future rate of growth depend highly upon the prices we receive for our oil and natural gas production. Historically, the markets for oil and natural gas have been volatile and are likely to continue to be volatile in the future. Market prices of oil and natural gas depend on many factors beyond our control, including: - worldwide and domestic supplies of oil and natural gas; - the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; - political instability or armed conflict in oil-producing regions; - the price and level of foreign imports; - the level of consumer demand; - the price and availability of alternative fuels; - the availability of pipeline capacity; - weather conditions; - domestic and foreign governmental regulations and taxes; and - the overall economic environment. We cannot predict future oil and natural gas price movements. During 2002, the high and low settlement prices for oil on the NYMEX were $32.72 per Bbl and $17.97 per Bbl, and the high and low settlement prices for natural gas on the NYMEX were $5.34 per MMBtu and $1.91 per MMBtu. Significant declines in oil and natural gas prices for an extended period may have the following effects on our business: - limit our financial condition, liquidity, ability to finance planned capital expenditures and results of operations; - reduce the amount of oil and natural gas that we can produce economically; - cause us to delay or postpone some of our capital projects; - reduce our revenues, operating income and cash flow; and - reduce the carrying value of our oil and natural gas properties. OUR HEDGING TRANSACTIONS COULD REDUCE REVENUES IN A RISING COMMODITY PRICE ENVIRONMENT OR EXPOSE US TO OTHER RISKS. In an attempt to reduce our sensitivity to energy price volatility, we use hedging arrangements that generally result in a fixed price or a range of minimum and maximum price limits over a specified time period. Hedging contracts limit the benefits we would otherwise realize if actual prices rise above the contract price. Our hedging arrangements expose us to the risk of financial loss in certain circumstances. For example, if we do not produce our oil and natural gas reserves at rates equivalent to our hedged position, we would be required to satisfy our obligations under hedging contracts on potentially unfavorable terms without the ability to hedge that risk through sales of comparable quantities of our own production. This situation occurred during portions of 2000, due in part to our sale of certain producing reserves in mid-1999. As a 10 result, our cash flow was reduced by approximately $1.0 million in 2000, which represents 52% of the net decrease in cash and cash equivalents. Additionally, because the terms of our hedging contracts are based on assumptions and estimates of numerous factors such as cost of production and pipeline and other transportation and marketing costs to delivery points, substantial differences between the hedged prices and our actual results could harm our anticipated profit margins and our ability to manage the risk associated with fluctuations in oil and natural gas prices. We also could be financially harmed if the counter parties to our hedging contracts prove unable or unwilling to perform their obligations under such contracts. Additionally, in the past, some of our hedging contracts required us to deliver cash collateral or other assurances of performance to the counter parties in the event that our payment obligations exceeded certain levels. Future collateral requirements are uncertain but will depend on arrangements with our counter parties and highly volatile natural gas and oil prices. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Critical Accounting Policies--Derivative Instruments and Hedging Activities" and "Management's Discussion and Analysis of Financial Condition and Results of Operations--Quantitative and Qualitative Disclosures About Market Risk." EXPLORATORY DRILLING IS A SPECULATIVE ACTIVITY THAT MAY NOT RESULT IN COMMERCIALLY PRODUCTIVE RESERVES AND MAY REQUIRE EXPENDITURES IN EXCESS OF BUDGETED AMOUNTS. Our future rate of growth depends highly upon the success of our exploratory drilling program. Exploratory drilling involves a higher risk that we will not encounter commercially productive natural gas or oil reservoirs than developmental drilling. We cannot predict the cost of drilling, and we may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including: - unexpected drilling conditions; - pressure or irregularities in formations; - equipment failures or accidents; - adverse weather conditions; - compliance with governmental requirements; and - shortages or delays in the availability of drilling rigs and the delivery of equipment. We may not be successful in our future drilling activities because even with the use of 3-D seismic and other advanced technologies, exploratory drilling is a speculative activity. We could incur losses because our use of 3-D seismic data and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies. Even when fully utilized and properly interpreted, our 3-D seismic data and other advanced technologies only assist us in identifying subsurface structures and do not indicate whether hydrocarbons are in fact present in those structures. In addition, such seismic interpretations are not substantiated without drilling which may even invalidate previously accepted interpretations, require more processing and/or interpretation expense or condemn an area. Because we interpret the areas desirable for drilling from 3-D seismic data gathered over large areas, we may not acquire option and lease rights until after the seismic data is available and, in some cases, until the drilling locations are also identified. We may never lease, drill or produce oil or natural gas from these or any other potential drilling locations. We may not be successful in our drilling activities, our overall drilling success rate for activity within a particular province may not be maintained, and our completed wells may not ultimately produce our estimated economically recoverable reserves. Unsuccessful drilling activities could result in a significant decline in our production and revenues and materially harm our operations and financial condition by reducing our available cash and resources. 11 WE ARE SUBJECT TO VARIOUS OPERATING AND OTHER CASUALTY RISKS THAT COULD RESULT IN LIABILITY EXPOSURE OR THE LOSS OF PRODUCTION AND REVENUES. Our operations are subject to hazards and risks inherent in drilling for and producing and transporting oil and natural gas, such as: - fires; - natural disasters; - formations with abnormal pressures; - blowouts, cratering and explosions; and - pipeline ruptures and spills. Any of these hazards and risks can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our properties and the property of others. See "Business and Properties--Operating Hazards and Uninsured Risks." WE MAY NOT HAVE ENOUGH INSURANCE TO COVER ALL OF THE RISKS WE FACE, WHICH COULD RESULT IN SIGNIFICANT FINANCIAL EXPOSURE. We maintain insurance coverage against some, but not all, potential losses in order to protect against the risks we face. We may elect not to carry insurance if our management believes that the cost of insurance is excessive relative to the risks presented. If an event occurs that is not covered, or not fully covered, by insurance, it could harm our financial condition and results of operations. In addition, we cannot fully insure against pollution and environmental risks. See "Business and Properties--Operating Hazards and Uninsured Risks." WE CANNOT CONTROL THE ACTIVITIES ON PROPERTIES WE DO NOT OPERATE AND ARE UNABLE TO ENSURE THEIR PROPER OPERATION AND PROFITABILITY. We do not operate all of the properties in which we have an interest. For the three years ending December 31, 2002, we operated 47 of the 84 wells in which we have an interest. As a result, we have limited ability to exercise influence over operations for these properties. The failure of an operator of our wells to adequately perform operations, or an operator's breach of the applicable agreements, could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator's: - timing and amount of capital expenditures; - expertise and financial resources; - inclusion of other participants in drilling wells; and - use of technology. 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. The marketability of our production depends in part upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. We generally deliver natural gas through gas gathering systems and gas pipelines that we do not own under interruptible or short term transportation agreements. Under the interruptible transportation agreements, the transportation of our gas may be interrupted due to capacity constraints on the applicable system, for maintenance or repair of the system, or for other reasons as dictated by the particular agreements. Our ability to produce and market natural 12 gas on a commercial basis could be harmed by any significant change in the cost or availability of such markets, systems or pipelines. LOWER OIL AND NATURAL GAS PRICES MAY CAUSE US TO RECORD CEILING LIMITATION WRITE-DOWNS WHICH WOULD REDUCE OUR STOCKHOLDERS' EQUITY. We use the full cost method of accounting for costs related to our oil and gas properties. Accordingly, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under full cost accounting rules, the net capitalized cost of oil and gas properties may not exceed a "ceiling limit" that is based upon the present value of estimated future net revenues from proved reserves, discounted at 10%, plus the lower of the cost or fair market value of unproved properties. If net capitalized costs of oil and gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a "ceiling limitation write-down." This charge does not impact cash flow from operating activities, but does reduce our stockholders' equity. The risk that we will be required to write down the carrying value of our oil and gas properties increases when oil and gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves. Once incurred, a write-down of oil and gas properties is not reversible at a later date. WE HAVE HAD OPERATING LOSSES IN THE PAST AND MAY NOT BE PROFITABLE IN THE FUTURE. We may not be profitable in the future. At June 30, 2003, we had an accumulated deficit of $14.4 million and total stockholders' equity of $70.6 million. We have recognized the following annual net losses since 1997: $1.1 million (including a net $1.2 million non-cash deferred income tax charge incurred in connection with our conversion from a partnership to a corporation) in 1997, $33.3 million (including a $25.9 million non-cash writedown in the carrying value of our oil and natural gas properties) in 1998, $21.6 million (including a $12.2 million non-cash loss on the sale of oil and natural gas properties) in 1999, and $15.7 million in 2000. See "Selected Consolidated Financial Data." OUR FUTURE OPERATING RESULTS MAY FLUCTUATE AND SIGNIFICANT DECLINES IN THEM WOULD LIMIT OUR ABILITY TO INVEST IN PROJECTS. Our future operating results may fluctuate significantly depending upon a number of factors, including: - industry conditions; - prices of oil and natural gas; - rates of drilling success; - capital availability; - rates of production from completed wells; and - the timing and amount of capital expenditures. This variability could cause our business, financial condition and results of operations to suffer. In addition, any failure or delay in the realization of expected cash flows from operating activities could limit our ability to invest and participate in economically attractive projects. THE FAILURE TO REPLACE RESERVES IN THE FUTURE WOULD ADVERSELY AFFECT OUR PRODUCTION AND CASH FLOWS. In general, production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves and production will decline as reserves are produced. Our future oil and natural gas production depends highly upon our ability to economically find, develop or acquire reserves in commercial quantities. In addition, 13 approximately 54% of our total estimated proved reserves at December 31, 2002 were undeveloped. Recovery of such reserves will require significant capital expenditures and successful drilling operations. The business of exploring for or developing reserves is capital intensive. Reductions in our cash flow from operations and limitations on or unavailability of external sources of capital may impair our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves. In addition, our future exploration and development activities may not result in additional proved reserves, and we may not be able to drill productive wells at acceptable costs. WE ARE SUBJECT TO UNCERTAINTIES IN RESERVE ESTIMATES AND FUTURE NET CASH FLOWS. There is substantial uncertainty in estimating quantities of proved reserves and projecting future production rates and the timing of development expenditures. No one can measure underground accumulations of oil and natural gas in an exact way. Accordingly, oil and natural gas reserve engineering requires subjective estimations of those accumulations. Estimates of other engineers might differ widely from those of our independent petroleum engineers. Accuracy of reserve estimates depends on the quality of available data and on engineering and geological interpretation and judgment. Our independent petroleum engineers may make material changes to reserve estimates based on the results of actual drilling, testing, and production. As a result, our reserve estimates often differ from the quantities of oil and natural gas we ultimately recover. Also, we make certain assumptions regarding future oil and natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. See "Business and Properties--Oil and Natural Gas Reserves." As of December 31, 2002, approximately 62% of our proved reserves were either proved undeveloped or proved non-producing. Moreover, some of the producing wells included in our reserve report had produced for a relatively short period of time at December 31, 2002. Because most of our reserve estimates are without the benefit of a lengthy production history and are calculated using volumetric analysis, those estimates are less reliable than estimates based on a lengthy production history. Volumetric analysis involves estimating the volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure based on seismic analysis. The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas and oil reserves. In accordance with the requirements of the Securities and Exchange Commission, we base the estimated discounted future net cash flows from our proved reserves on prices and costs on the day of estimate. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as: - actual prices we receive for oil and natural gas; - the amount and timing of actual production; - supply and demand for oil and natural gas; - limits or increases in consumption by gas purchasers; and - changes in governmental regulations or taxation. The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows in compliance with the Securities and Exchange Commission reporting requirements may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general. 14 WE FACE SIGNIFICANT COMPETITION, AND MANY OF OUR COMPETITORS HAVE RESOURCES IN EXCESS OF OUR AVAILABLE RESOURCES. We operate in the highly competitive areas of oil and natural gas exploration, exploitation, acquisition and production. We face intense competition from a large number of independent, technology-driven companies as well as both major and other independent oil and natural gas companies in a number of areas such as: - seeking to acquire desirable producing properties or new leases for future exploration; - marketing our oil and natural gas production; and - seeking to acquire the equipment and expertise necessary to operate and develop those properties. Many of our competitors have financial and other resources substantially in excess of those available to us. This highly competitive environment could harm our business. See "Business and Properties--Competition." WE ARE SUBJECT TO VARIOUS GOVERNMENTAL REGULATIONS AND ENVIRONMENTAL RISKS WHICH MAY CAUSE US TO INCUR SUBSTANTIAL COSTS. Our business is subject to laws and regulations promulgated by federal, state and local authorities, including the Federal Energy Regulatory Commission, the Environmental Protection Agency, the Texas Railroad Commission, the Texas Commission on Environmental Quality and the Oklahoma Corporation Commission, relating to the exploration for, and the development, production and marketing of, oil and natural gas, as well as safety matters. Legal requirements are frequently changed and subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. We may be required to make significant expenditures to comply with governmental laws and regulations. Our operations are subject to complex federal, state and local environmental laws and regulations, including the Comprehensive Environmental Response, Compensation and Liability Act, the Resource Conservation and Recovery Act, the Oil Pollution Act of 1990 and the Clean Water Act. Environmental laws and regulations change frequently, and the implementation of new, or the modification of existing, laws or regulations could harm us. The discharge of natural gas, oil, or other pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties and may require us to incur substantial costs of remediation. See "Business and Properties--Governmental Regulation" and "Business and Properties--Environmental Matters." OUR BUSINESS MAY SUFFER IF WE LOSE KEY PERSONNEL. If we lose the services of our key management personnel or technical experts or are unable to attract additional qualified personnel, our business, financial condition, results of operations, development efforts and ability to grow could suffer. We have assembled a team of geologists, geophysicists and engineers who have considerable experience in applying 3-D seismic imaging technology to explore for and to develop oil and natural gas. We depend upon the knowledge, skill and experience of these experts to provide 3-D seismic imaging and to assist us in reducing the risks associated with our participation in oil and natural gas exploration and development projects. In addition, the success of our business depends, to a significant extent, upon the abilities and continued efforts of our management, particularly Ben M. Brigham, our Chief Executive Officer, President and Chairman of the Board. We have an employment agreement with Mr. Brigham, but do not have an employment agreement with any of our other employees. See "Business and Properties-- Exploration and Development Staff" and "Management." 15 YOU MAY SUFFER SUBSTANTIAL DILUTION UPON THE EXERCISE OF OUTSTANDING WARRANTS AND OPTIONS AND VESTING OF RESTRICTED STOCK. We have granted a significant number of warrants and options to purchase shares of our common stock and shares of restricted common stock. Upon the exercise of these warrants and options, and upon the vesting of restricted common stock, your percentage ownership in the Company will be diluted and the price per share of our common stock may decline. After this offering, 27,953,542 shares of common stock will be outstanding assuming the underwriters' over-allotment option is exercised in full (27,569,452 shares if the underwriters' over-allotment option is not exercised). In addition, we have issued warrants to purchase up to 11,070,780 shares of common stock, we have granted options to purchase up to 1,647,800 shares of common stock and we have issued 350,000 shares of unvested restricted common stock. Under our long-term incentive plans, we may issue up to an additional 1,689,027 shares of common stock (or options to purchase shares of common stock) assuming this offering and underwriters' over-allotment option is exercised in full. Nearly all of our outstanding warrants and options are exercisable at prices below the current market price of our common stock. OUR SHARES THAT ARE ELIGIBLE FOR FUTURE SALE MAY HAVE AN ADVERSE EFFECT ON THE PRICE OF OUR COMMON STOCK. Sales of substantial amounts of common stock, or a perception that such sales could occur, could adversely affect the market price of the common stock and could impair our ability to raise capital through the sale of our equity securities. The 9,000,000 shares offered hereby will be eligible for immediate sale in the public market without restriction. This risk is compounded by the fact that a substantial portion of our common stock is owned by a relatively few number of individuals or entities. For example, as of July 31, 2003, our directors, executive officers and 10% or greater stockholders, and certain of their affiliates, beneficially owned approximately 52% of our outstanding common stock. In addition, one of our stockholders, together with its affiliates, owns warrants to purchase 11,070,780 shares of common stock at a weighted average exercise price of $3.54 per share. In addition, this stockholder and other stockholders have the right to demand that we file a registration statement under the Securities Act covering the sale of all or any part of their common stock. See "Description of Capital Stock--Warrants." CERTAIN OF OUR AFFILIATES CONTROL A MAJORITY OF OUR OUTSTANDING COMMON STOCK, WHICH MAY AFFECT YOUR VOTE AS A STOCKHOLDER. As of July 31, 2003, our directors, executive officers and 10% or greater stockholders, and certain of their affiliates beneficially owned approximately 52% of our outstanding common stock. In addition, one of our stockholders, together with its affiliates, owns warrants to purchase 11,070,780 shares of common stock at a weighted average exercise price of $3.54 per share. Accordingly, these stockholders, as a group, will be able to control the outcome of stockholder votes, including votes concerning the election of directors, the adoption or amendment of provisions in our certificate of incorporation or bylaws, and the approval of mergers and other significant corporate transactions. The existence of these levels of ownership concentrated in a few persons makes it unlikely that any other holder of common stock will be able to affect our management or direction. These factors may also have the effect of delaying or preventing a change in our management or voting control. CERTAIN ANTI-TAKEOVER PROVISIONS MAY AFFECT YOUR RIGHTS AS A STOCKHOLDER. Our certificate of incorporation authorizes our Board of Directors to issue up to 10 million shares of preferred stock without stockholder approval and to set the rights, preferences and other designations, including voting rights, of those shares as the Board of Directors may determine. In addition, our outstanding Series A and Series B preferred stock, our senior credit facility and our senior subordinated notes contain terms restricting our ability to enter into change of control transactions, including requirements to redeem or repay the Series A and Series B preferred stock, our senior credit facility and our senior subordinated notes upon a change in control. These provisions, alone or in combination with the 16 other matters described in the preceding paragraph may discourage transactions involving actual or potential changes in our control, including transactions that otherwise could involve payment of a premium over prevailing market prices to holders of our common stock. We are also subject to provisions of the Delaware General Corporation Law that may make some business combinations more difficult. See "Description of Capital Stock." THE MARKET PRICE OF OUR STOCK IS VOLATILE. The trading price of our common stock and the price at which we may sell securities in the future is subject to large fluctuations in response to any of the following: - limited trading volume in our stock; - changes in government regulations, quarterly variations in operating results; - our involvement in litigation; - general market conditions; - the prices of oil and natural gas; - announcements by us and our competitors; - our liquidity; - our ability to raise additional funds; and - other events. See "Price Range of Common Stock and Dividend Policy." 17 FORWARD-LOOKING STATEMENTS This prospectus and the documents incorporated by reference in this prospectus contain forward-looking statements within the meaning of the federal securities laws. These forward-looking statements include, among others, the following: - our growth strategies; - our ability to successfully and economically explore for and develop oil and gas resources; - anticipated trends in our business; - our future results of operations; - our liquidity and ability to finance our exploration and development activities; - market conditions in the oil and gas industry; - our ability to make and integrate acquisitions; and - the impact of governmental regulation. These statements may be found under "Prospectus Summary," "Risk Factors," "Use of Proceeds," "Management's Discussion and Analysis of Financial Condition and Results of Operation" and "Business and Properties." Forward-looking statements are typically identified by use of terms such as "may," "will," "expect," "anticipate," "estimate" and similar words, although some forward-looking statements may be expressed differently. More specifically, our forward-looking statements include: - estimates of the wells we expect to drill included in "Business and Properties" and elsewhere in this document; - amounts we expect to re-borrow under our senior credit facility included in "Use of Proceeds," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and elsewhere in this document; and - statements regarding our 2003 and 2004 Capital Expenditure Program included in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and elsewhere in this document. You should be aware that our actual results could differ materially from those contained in the forward-looking statements. You should consider carefully the statements under "Risk Factors" and other sections of this prospectus, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. 18 USE OF PROCEEDS We estimate that we will receive net proceeds of approximately $37,993,000 from the sale of 7,000,000 shares of our common stock in this offering. If the underwriters fully exercise the over-allotment option, we will receive net proceeds of approximately $40,105,111 from the sale of 7,384,090 shares of our common stock. "Net proceeds" is what we expect to receive after paying the underwriting discount and other expenses of the offering. We will not receive any proceeds from the sale of shares by the selling stockholders pursuant to this prospectus. We intend to use the proceeds from this offering to accelerate our exploration and development activities and for general corporate purposes. Pending such use, we intend to use the net proceeds to repay outstanding indebtedness under our senior credit facility. As of July 31, 2003, $53 million was outstanding under our senior credit facility, which had an average interest rate of approximately 3.4% and matures in March 2006. In addition to using cash from operations to fund our accelerated program, subject to satisfaction of conditions precedent under our senior credit facility, through 2004 we have currently budgeted to re-borrow approximately $20 million under our senior credit facility to fund costs as they are incurred. See "Forward-Looking Statements," "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources--Senior Credit Facility." 19 SELLING STOCKHOLDERS The following table provides information regarding the beneficial ownership of our common stock held by the selling stockholders as of July 31, 2003.
NUMBER OF SHARES OF NUMBER OF SHARES PERCENTAGE COMMON STOCK NUMBER OF SHARES OF COMMON STOCK OF COMMON STOCK BENEFICIALLY OWNED OF COMMON STOCK BENEFICIALLY OWNED BENEFICIALLY OWNED NAME PRIOR TO THE OFFERING BEING OFFERED(A) AFTER THE OFFERING(A) AFTER THE OFFERING(A) ---- --------------------- ---------------- --------------------- --------------------- Bank of Montreal................. 408,928 331,564 77,364 * General Atlantic Partners III, L.P. .......................... 2,679,418 715,758 1,963,660 7.1% GAP-Brigham Partners, L.P. ...... 127,725 34,119 93,606 * GAP Coinvestment Partners II, L.P. .......................... 1,140,962 304,788 836,174 3.0% Shell Capital, Inc. ............. 550,000 445,947 104,053 * Societe Generale................. 206,982 167,824 39,158 * --------------- ------------- --------------- Total.......................... 5,114,015 2,000,000 3,114,015
- --------------------------- * Represents less than 1%. (a) Within 30 days, following the date of this prospectus, pursuant to an over-allotment option, the underwriters may elect to purchase an additional 77,364 shares from Bank of Montreal, 166,499 shares from General Atlantic Partners III, L.P., 7,937 shares from GAP-Brigham Partners, L.P., 70,899 shares from Gap Coinvestment Partners II, L.P., 104,053 from Shell Capital, Inc. and 39,158 from Societe Generale. As part of the over-allotment option to purchase 1,350,000 additional shares granted to the underwriters, the underwriters may elect to purchase up to 500,000 shares from Ben M. Brigham and Anne L. Brigham within 30 days following the date of this prospectus. If the underwriters do not exercise the over-allotment option granted by Mr. and Mrs. Brigham, none of their shares will be included in the offering. Each of the selling stockholders either has or has had a material relationship with us within the past three years. Ben M. Brigham is our Chief Executive Officer, President and Chairman of the Board. Anne L. Brigham was a member of our board of directors from 1990 until May 2003. Bank of Montreal and Shell Capital, Inc. were lenders in our senior credit facility until December 2002. Societe Generale is a lender in our existing senior credit facility. SG Cowen Securities Corporation, an affiliate of Societe Generale, is acting as an underwriter in this offering. See "Underwriting." Stephen P. Reynolds, one of our directors, is a limited partner in GAP-Brigham Partners, L.P. and GAP Coinvestment Partners II, L.P. and served as President of GAP III Investors, Inc., the general partner of General Atlantic Partners III, L.P. and a general partner of GAP-Brigham Partners, L.P. until February 2003. Stephen P. Reynolds disclaims beneficial ownership of shares owned by General Atlantic Partners III, L.P., GAP-Brigham Partners, L.P., and GAP Coinvestment Partners II, L.P. except to the extent of his pecuniary interest therein. General Atlantic Partners III, L.P., GAP-Brigham Partners, L.P. and GAP Coinvestment Partners II, L.P. are under common control with General Atlantic Partners, LLC. Bank of Montreal, General Atlantic Partners III, L.P., GAP-Brigham Partners, L.P., GAP Coinvestment Partners II, L.P., Shell Capital, Inc. and Societe Generale all have boards of directors, committees or other similar governing bodies that have voting and investment power over their securities. No individual has voting or investment power over the securities for any of these entities until the board of directors, committee or other governing body, as applicable, grants such authorization. 20 CAPITALIZATION The table below shows: - our capitalization on June 30, 2003; and - our capitalization on June 30, 2003, on an as adjusted basis, assuming the completion of this offering at the public offering price of $5.85 per share and the use of the net proceeds as described under "Use of Proceeds." You should read this table in conjunction with our consolidated financial statements and related notes that are included in this prospectus.
JUNE 30, 2003 ---------------------- ACTUAL AS ADJUSTED -------- ----------- (in thousands) LONG-TERM DEBT(A): Senior credit facility.................................... $ 53,000 $ 15,007 Senior subordinated notes................................. 22,382 22,382 -------- -------- Total long-term debt................................... 75,382 37,389 Series A Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and redemption value, 2,250,000 shares authorized, 1,835,860 shares issued and outstanding....... 21,144 21,144 Series B Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and redemption value, 1,000,000 shares authorized, 521,313 shares issued and outstanding......... 5,196 5,196 STOCKHOLDERS' EQUITY: Preferred stock, $0.01 par value, 10,000,000 shares authorized, of which 2,250,000 and 1,000,000 shares are designated as Series A and B Preferred Stock, respectively........................................... - - Common stock, $0.01 par value, 50,000,000 shares authorized Actual - 21,706,692 shares issued and 20,562,410 outstanding As adjusted - 28,706,692 shares issued and 27,562,410 outstanding........................................... 217 287 Additional paid in capital................................ 94,104 132,027 Treasury stock, at cost 1,144,282 shares, actual 1,144,282 shares, as adjusted.................................... (4,292) (4,292) Unearned stock compensation............................... (2,163) (2,163) Accumulated other comprehensive income (loss)............. (2,799) (2,799) Accumulated deficit....................................... (14,428) (14,428) -------- -------- Total stockholders' equity............................. 70,639 108,632 -------- -------- Total capitalization................................... $172,361 $172,361 ======== ========
- --------------- (a) As of July 31, 2003, our total long term debt outstanding was $75.7 million, consisting of $53.0 million under our senior credit facility and $22.7 million in senior subordinated notes. 21 PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY Our common stock commenced trading on the Nasdaq National Market on May 8, 1997 under the symbol "BEXP." The following table sets forth the high and low intra-day sales prices per share of our common stock for the periods indicated on the Nasdaq National Market for the periods indicated. The sales information below reflects inter-dealer prices, without retail mark-ups, mark-downs or commissions and may not necessarily represent actual transactions.
HIGH LOW ------ ------ 2001: First Quarter............................................. $5.969 $3.375 Second Quarter............................................ 4.620 3.250 Third Quarter............................................. 5.110 2.500 Fourth Quarter............................................ 3.480 2.280 2002: First Quarter............................................. 3.970 2.360 Second Quarter............................................ 5.350 3.420 Third Quarter............................................. 4.800 3.100 Fourth Quarter............................................ 5.000 3.300 2003: First Quarter............................................. 6.000 4.400 Second Quarter............................................ 5.740 4.500 Third Quarter (through September 17, 2003)................ 6.180 4.750
The closing market price of our common stock on September 17, 2003 was $5.98 per share. As of August 14, 2003, there were an estimated 121 record owners of our common stock. No dividends have been declared or paid on our common stock to date. We intend to retain all future earnings for the development of our business. Our senior credit facility, senior subordinated notes and Series A and Series B preferred stock restrict our ability to pay dividends on our common stock. We are obligated to pay dividends on our Series A and Series B preferred stock. At our option, these dividends may be paid in cash at a rate of 6% per annum or paid in kind through the issuance of additional shares of preferred stock in lieu of cash at a rate of 8% per annum. Our option to pay dividends in kind on our Series A preferred stock expires in November 2005. Our option to pay dividends in kind on our Series B preferred stock expires in December 2007. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources--Series A Preferred Stock", "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources--Series B Preferred Stock" and "Description of Capital Stock." 22 SELECTED CONSOLIDATED FINANCIAL DATA This section presents our selected historical financial data. You should read carefully the consolidated financial statements included in this prospectus, including the notes to the consolidated financial statements. The selected data in this section is not intended to replace the consolidated financial statements. We derived the statement of operations data and statement of cash flows data for the years ended December 31, 2002, 2001 and 2000, and balance sheet data as of December 31, 2002 and 2001 from the audited consolidated financial statements included in this prospectus. We derived the statement of operations data and statement of cash flows data for the years ended December 31, 1999 and 1998 and the balance sheet data as of December 31, 2000, 1999 and 1998 from audited consolidated financial statements that are not included in this prospectus. We derived the statement of operations data and statement of cash flows data for the six months ended June 30, 2003 and 2002 and balance sheet data as of June 30, 2003 and 2002 from the unaudited consolidated financial statements included in this prospectus.
SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, ---------------------------------------------------- ------------------- 2002 2001 2000 1999 1998 2003 2002 -------- -------- -------- -------- -------- -------- -------- (unaudited) (in thousands) STATEMENT OF OPERATIONS DATA: Oil and natural gas sales........... $ 35,100 $ 32,293 $ 19,143 $ 14,992 $ 13,799 $ 26,766 $ 15,203 Other revenues...................... 76 255 69 285 390 81 27 -------- -------- -------- -------- -------- -------- -------- Total revenues.................. 35,176 32,548 19,212 15,277 14,189 26,847 15,230 -------- -------- -------- -------- -------- -------- -------- Lease operating..................... 3,759 3,486 2,139 2,259 2,172 2,244 1,667 Production taxes.................... 1,977 1,511 1,786 968 850 1,744 852 General and administrative.......... 4,971 3,638 3,100 3,481 4,672 2,326 2,682 Depletion of oil and natural gas properties........................ 14,594 13,211 7,920 7,792 8,483 7,901 6,531 Depreciation and amortization....... 440 677 620 526 785 257 204 Capitalized ceiling impairment...... - - - - 25,926 - - Accretion of discount on asset retirement obligation............. - - - - - 71 - Loss on sale of oil and natural gas properties........................ - - - 12,195 - - - -------- -------- -------- -------- -------- -------- -------- Total costs and expenses........ 25,741 22,523 15,565 27,221 42,888 14,543 11,936 -------- -------- -------- -------- -------- -------- -------- Operating income (loss)....... 9,435 10,025 3,647 (11,944) (28,699) 12,304 3,294 -------- -------- -------- -------- -------- -------- -------- Other income (expense) Interest expense.................. (6,238) (6,681) (9,906) (9,697) (5,968) (2,506) (3,070) Interest income................... 119 264 108 176 136 28 93 Other income (expense)............ (310) 8,080 (9,504) (163) - (170) (169) Debt conversion expense........... (630) - - - - - - Gain on refinancing of debt....... - - 32,267 - - - - -------- -------- -------- -------- -------- -------- -------- Total other income (expense).... (7,059) 1,663 12,965 (9,684) (5,832) (2,648) (3,146) -------- -------- -------- -------- -------- -------- --------
23
SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, ---------------------------------------------------- ------------------- 2002 2001 2000 1999 1998 2003 2002 -------- -------- -------- -------- -------- -------- -------- (unaudited) (in thousands, except per share information) Income (loss) before income taxes and cumulative effect of change in accounting principle.............. $ 2,376 $ 11,688 $ 16,612 $(21,628) $(34,531) $ 9,656 $ 148 Income tax benefit (expense)........ - - - - 1,186 - - -------- -------- -------- -------- -------- -------- -------- Income (loss) before cumulative effect of change in accounting principle..................... 2,376 11,688 16,612 (21,628) (33,345) 9,656 148 Cumulative effect of change in accounting principle.............. - - - - - 268 - -------- -------- -------- -------- -------- -------- -------- Net income (loss)............... 2,376 11,688 16,612 (21,628) (33,345) 9,924 148 Preferred dividend and accretion.... 2,952 2,450 275 - - 2,023 1,419 -------- -------- -------- -------- -------- -------- -------- Net income (loss) available to common stockholders........... $ (576) $ 9,238 $ 16,337 $(21,628) $(33,345) $ 7,901 $ (1,271) ======== ======== ======== ======== ======== ======== ======== Net income (loss) per share Basic............................. $ (0.04) $ 0.58 $ 1.01 $ (1.53) $ (2.64) $ 0.40 $ (0.08) Diluted........................... (0.04) 0.44 1.01 (1.53) (2.64) 0.30 (0.08) Weighted average shares outstanding Basic............................. 16,138 15,988 16,241 14,152 12,626 19,898 16,027 Diluted........................... 16,138 28,205 16,241 14,152 12,626 32,090 16,027 STATEMENT OF CASH FLOWS DATA: Net cash provided (used) by: Operating activities.............. $ 28,973 $ 18,922 $ (4,635) $ 2,578 $ 14,774 $ 23,518 $ 10,056 Investing activities.............. (27,206) (33,571) (26,071) 1,644 (86,227) (19,214) (13,193) Financing activities.............. 8,439 18,924 28,801 (4,049) 72,321 (7,391) 3,725
AT DECEMBER 31, AT JUNE 30, ---------------------------------------------------- ------------------- 2002 2001 2000 1999 1998 2003 2002 -------- -------- -------- -------- -------- -------- -------- (unaudited) (in thousands) BALANCE SHEET DATA: Cash and cash equivalents........... $ 15,318 $ 5,112 $ 837 $ 2,742 $ 2,569 $ 12,231 $ 5,700 Oil and natural gas properties, net............................... 164,980 151,891 129,490 112,066 134,317 177,306 158,314 Total assets........................ 202,059 173,075 146,911 125,683 150,516 210,670 183,821 Long-term debt...................... 81,797 91,721 82,000 97,341 94,786 75,382 96,218 Series A preferred stock, mandatorily redeemable............ 19,540 16,614 8,558 - - 21,144 18,033 Series B preferred stock, mandatorily redeemable............ 4,777 - - - - 5,196 - Total stockholders' equity.......... 61,749 49,601 34,757 8,998 24,681 70,639 46,708
24 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS You should read this discussion together with the consolidated financial statements and other financial information included in this prospectus. OVERVIEW From 1990 to 1996 we acquired 3-D seismic data in 28 trends located in seven provinces in seven states. In 1997 and 1998 we invested $64 million in 3-D seismic data and acreage in selected trends where we were experiencing attractive 3-D delineated drilling economics and repeatability. In 1999, we began focusing a higher percentage of our capital expenditures on drilling to monetize the value of our 3-D delineated prospect inventory to provide significant improvement in our financial and operating results. Our business strategy includes the following elements: - focus the majority of capital resources in our five focus trends to generate growth in proved reserves, production volumes and cash flow; - continue to grow our inventory of high potential exploration prospects through our technical staff's internal generation of such prospects utilizing our extensive and expanding inventory of 3-D seismic data; - allocate a high percentage of drilling capital toward the development of our prior discoveries; - accelerate the development of our exploration and development prospect inventory by increasing our drilling expenditures; and - enhance our project returns by attempting to retain operational control over all phases of our exploration and development activities. As a result of this strategy, we have achieved the following results for the three-year period ended December 31, 2002: - increased our estimated net proved reserves from 84 Bcfe at December 31, 1999 to 121.1 Bcfe at December 31, 2002, a three-year compound annual growth rate of 13%; - increased our average daily production volumes from 17.4 MMcfe/d for the year ended December 31, 1999 to 27.8 MMcfe/d for the year ended December 31, 2002, a three-year compound annual growth rate of 17%; - realized all-sources finding cost for the three-year period ended December 31, 2002 of $1.31 per Mcfe; and - increased our operating income from $3.6 million in 2000 to $9.4 million in 2002. CRITICAL ACCOUNTING POLICIES The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment to the specific set of circumstances existing in our business. Compliance with the rules necessarily involves reducing a number of very subjective judgments to a quantifiable accounting entry or valuation. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules is critical. Our critical accounting policies are discussed below. 25 Property and Equipment The method of accounting for oil and natural gas properties is a critical accounting policy because it determines what costs are capitalized, and how these costs are ultimately matched with revenues and expensed. We use the full cost method of accounting for oil and natural gas properties. Under this method substantially all costs associated with oil and natural gas exploration and development activities are capitalized, including costs for individual exploration projects that do not directly result in the discovery of hydrocarbon reserves that can be economically recovered. Payroll, interest, and other internal costs we incur for the purpose of finding hydrocarbon reserves are also capitalized. Full cost pool amounts associated with properties that have been evaluated through drilling or seismic analysis are depleted using the units of production method. The depletion expense per unit of production is the ratio of historical and estimated future development costs to hydrocarbon reserve volumes. Estimation of hydrocarbon reserves relies on professional judgment and use of factors that cannot be precisely determined. Reserve estimates materially different from those reported would change the depletion expense recognized during the reporting period. For the year ended December 31, 2002, our depletion expense per unit of production was $1.46 per Mcfe. A change of 900,000 Mcfe in our estimated net proved reserves at December 31, 2002, would result in a $0.01 per Mcfe change in our per unit depletion expense and a $100,000 change in net income available to common stockholders. To the extent costs capitalized in the full-cost pool (net of depreciation, depletion and amortization and related deferred taxes) exceed the present value (using a 10% discount rate and based on period-end oil and natural gas prices) of estimated future net revenues from proved oil and natural gas reserves plus the capitalized cost of unproved properties, such costs are charged to operations as a reduction of the carrying value of oil and natural gas properties, or a "capitalized ceiling impairment" charge. The risk that we will be required to write down the carrying value of our oil and natural gas properties increases when oil and natural gas prices are depressed, even if the low prices are temporary. In addition, capitalized ceiling impairment charges may occur if we experience poor drilling results or estimations of proved reserves are substantially reduced. A capitalized ceiling impairment is a reduction in earnings that does not impact cash flows, but does impact operating income and stockholders' equity. Once recognized, a capitalized ceiling impairment charge to oil and natural gas properties cannot be reversed at a later date. No assurance can be given that we will not experience a capitalized ceiling impairment charge in future periods. In addition, capitalized ceiling impairment charges may occur if estimates of proved hydrocarbon reserves are substantially reduced or estimates of future development costs increase significantly. See "Risk Factors--Exploratory drilling is a speculative activity that may not result in commercially productive reserves and may require expenditures in excess of budgeted amounts," "Risk Factors--The failure to replace reserves in the future would adversely affect our production and cash flows" and "Risk Factors--We are subject to uncertainties in reserve estimates and future net cash flows." Income Taxes Deferred tax assets are recognized for temporary differences in financial statement and tax basis amounts that will result in deductible amounts and carry-forwards in future years. Deferred tax liabilities are recognized for temporary differences that will result in taxable amounts in future years. Deferred tax assets and liabilities are measured using enacted tax law and tax rate(s) for the year in which we expect the temporary differences to be deducted or settled. The effect of a change in tax law or rates on the valuation of deferred tax assets and liabilities is recognized in income in the period of enactment. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. 26 Estimating the amount of the valuation allowance is dependent on estimates of future taxable income, alternative minimum tax income, and changes in stockholder ownership which would trigger limits on use of net operating losses under Internal Revenue Code Section 382. Revenue Recognition Because revenue is a key component of our results of operations, and we derive revenue primarily from the sale of produced oil and natural gas, our revenue recognition for these sales is significant. We recognize crude oil revenue using the sales method of accounting. Under this method, we recognize revenue when oil is delivered and title transfers. We recognize natural gas revenue using the entitlements method of accounting. Under this method, revenue is recognized based on our entitled ownership percentage of sales of natural gas to purchasers. Gas imbalances occur when we sell more or less than our entitled ownership percentage of total natural gas production. When we receive less than our entitled share, a receivable is recorded. When we receive more than our entitled share, a liability is recorded. Settlements for hydrocarbon sales can occur up to two months after the end of the month in which the oil, gas or other hydrocarbon products were produced. We estimate and accrue for the value of these sales using information available at the time financial statements are generated. Differences are reflected in the accounting period that payments are received from the purchaser. Derivative Instruments and Hedging Activities We use derivative instruments to manage market risks resulting from fluctuations in commodity prices of natural gas and crude oil. We periodically enter into commodity contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of natural gas or crude oil without the exchange of underlying volumes. The notional amounts of these financial instruments are based on expected production from existing wells. We adopted Statement of Financial Accounting Standards No. 133 (SFAS No. 133) on January 1, 2001 in accordance with Financial Accounting Standards Board (FASB) requirements. SFAS No. 133, as amended, establishes accounting and reporting standards for derivative instruments and for hedging activities. All derivative instruments are recorded on the balance sheet at fair value and changes in the fair value of the derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction, and depending on the type of hedge transaction. Our derivative contracts consist primarily of cash flow hedge transactions in which we are hedging the variability of cash flow related to a forecasted transaction. Changes in the fair value of these derivative instruments are reported in other comprehensive income and reclassified as earnings in the period(s) in which earnings are impacted by the variability of the cash flow of the hedged item. We assess the effectiveness of hedging transactions every three months, consistent with documented risk management strategy for the particular hedging relationship. Changes in fair value of ineffective hedges are included in earnings. Use of Estimates The preparation of financial statements in accordance with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect reported assets, liabilities, revenues, expenses, and some narrative disclosures. Hydrocarbon reserves, future development costs, and certain hydrocarbon production expense and revenue estimates are the most critical to our financial statements. 27 New Accounting Pronouncements In June 2001, the FASB issued Statement of Financial Standards No. 143 (SFAS No. 143), "Asset Retirement Obligations" which establishes accounting requirements for retirement obligations associated with tangible long-lived assets including the timing of the liability recognition, initial measurement of the liability, allocation of asset retirement cost to expense, subsequent measurement of the liability and financial statement disclosures. SFAS No. 143 requires that an asset retirement cost be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic, rational method. We adopted this standard as required on January 1, 2003, resulting in a cumulative effect adjustment that (i) increased the carrying value of proved properties by $1.4 million; (ii) decreased accumulated depletion of oil and natural gas properties by $0.8 million; and (iii) increased non-current abandonment liabilities by $1.9 million. The net impact of items (i) through (iii) was a gain of $0.3 million recorded as a cumulative effect adjustment of a change in accounting principle in our consolidated statements of operations upon adoption on January 1, 2003. In April 2002, the FASB issued Statement of Financial Standards No. 145 (SFAS No. 145), "Rescission of FASB statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections." SFAS No. 145 requires, except in the case of events or transactions of a highly unusual and infrequent nature, gains or losses from the early extinguishment of debt to be classified as components of a company's income or loss from continuing operations. Prior to the adoption of the provisions of SFAS No. 145, gains or losses on the early extinguishment of debt were required to be classified in a company's periodic consolidated statements of operations as extraordinary gains or losses, net of associated income taxes, after the determination of income or loss from continuing operations. SFAS No. 145 is effective for fiscal years beginning after May 15, 2002. Due to the requirements of SFAS No. 145, it is less likely that a gain or loss on extinguishment of debt would be classified as an extraordinary item in our results of operations. In May 2003, the FASB issued Statement of Financial Accounting Standards No. 150 (SFAS No. 150), "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity". SFAS No. 150 requires an issuer to classify certain financial instruments, such as mandatorily redeemable preferred stock, as liabilities (or assets in some circumstances). We adopted this standard as required on July 1, 2003. Upon adoption, Series A preferred stock and Series B preferred stock will be reclassified as liabilities on the balance sheet. The combined carrying value of the preferred stock is $26.3 million at June 30, 2003. We are continuing to assess the impact of SFAS No. 150 and may be required to make other adjustments that will have an effect on our consolidated financial position, results of operations or cash flows. RECENT DEVELOPMENTS Statement of Financial Accounting Standards No. 141 (SFAS 141), "Business Combinations" and Statement of Financial Accounting Standards, No. 142 (SFAS 142), "Goodwill and Intangible Assets" were issued by the FASB in June 2001 and became effective for us on July 1, 2001 and January 1, 2002, respectively. SFAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. Additionally, SFAS 141 requires companies to disaggregate and report separately from goodwill certain intangible assets. SFAS 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under SFAS 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment. The appropriate application of SFAS 141 and 142 to oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves is unclear. Depending on how the accounting and disclosure literature is clarified, these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves for both undeveloped and developed leaseholds may be classified separately from oil and gas properties, as intangible assets on our balance sheets. Additional disclosures required by SFAS 141 and 142 would be included in the notes to financial statements. Historically, we, like many other oil and gas companies, have 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. 28 This interpretation of SFAS 141 and 142 would only affect our balance sheet classification of oil and gas leaseholds. Our results of operations and cash flows would not be affected, since these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves would continue to be amortized in accordance with accounting rules for oil and gas companies provided in Statement of Financial Accounting Standards No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." At June 30, 2003 we had undeveloped leaseholds of approximately $4.0 million that would be classified on our balance sheet as "intangible undeveloped leaseholds" and developed leaseholds of an estimated $0.1 million that would be classified as "intangible developed leaseholds" if we applied the interpretation currently being deliberated. This classification would require us to make the disclosures set forth under SFAS 142 related to these interests. We will continue to classify our oil and gas leaseholds as tangible oil and gas properties until further guidance is provided. OFF BALANCE SHEET ARRANGEMENTS We do not currently have any off balance sheet arrangements or other such unrecorded obligations and we have not guaranteed the debt of any other party. COMMODITY PRICING Changes in commodity prices significantly affect our capital resources, liquidity and expected operating results. Price changes directly affect revenues and can indirectly impact expected production by changing the amount of funds available to reinvest in exploration and development activities. The prices we receive for our crude oil production are based on global market conditions. The price we receive for our natural gas production is primarily driven by North American market forces. Oil and gas prices have fluctuated significantly in recent years in response to numerous economic, political and environmental factors. The year 2002 began with a weakened commodity environment and lower prices. However, prices were on an upward trend through the year. Prices are also affected by weather, factors of supply and demand, and commodity inventory levels. During 2002, the high and low settlement prices for oil on the NYMEX were $32.72 per Bbl and $17.97 per Bbl, and the high and low settlement prices for natural gas on the NYMEX were $5.34 per MMBtu and $1.91 per MMBtu. We expect that commodity prices will continue to fluctuate significantly in the future. RESULTS OF OPERATIONS Overview For the six month period ended June 30, 2003, our net income available to common stockholders was $7.9 million, or $0.30 per diluted share, on total revenues of $26.8 million compared to a net loss of $1.3 million, or $0.08 per diluted share, on total revenues of $15.2 million for the six-month period ended June 30, 2002. Net income for the six-month period ended June 30, 2003, included a $268,000 ($0.01 per diluted share) benefit from the cumulative effect of change in accounting principle associated with the adoption of SFAS 143 on January 1, 2003. Net income for the six-month period ended June 30, 2003, also included $170,000 in non-cash losses for ineffective hedging transactions. Net income for the six-months ended June 30, 2002, included a $384,000 non-cash gain related to the change in the fair-market value of derivative contracts that did not qualify for hedge accounting treatment and a cash loss of $559,000 related to the cash settlement of derivative contracts that did not qualify as hedges. For the year ended December 31, 2002, we had a net loss to common stockholders of $576,000, or $0.04 per diluted share, on total revenues of $35.2 million compared to net income of $9.2 million, or $0.44 per diluted share (as restated), on revenue of $32.5 million for the year ended December 31, 2001, and net income of $16.3 million, or $1.01 per diluted share, on revenue of $19.2 million for the year ended 29 December 31, 2000. Our diluted earnings per share for 2001 have been restated (downward) to appropriately reflect the impact of our convertible debt, mandatorily redeemable preferred stock and associated warrants. The revised calculations utilize the "if-converted" method, as the holders can exercise the warrants either by paying cash or tendering the related convertible debt or mandatorily redeemable preferred stock. There is no impact on our previously reported diluted earnings per share data for 2002 or 2000. Net income for 2002 included a $384,000 non-cash gain related to changes in the fair-market value of derivative contracts that did not qualify for hedge accounting treatment. This non-cash gain was partially offset by a $121,000 non-cash loss for ineffective hedging transactions. Net income for 2001 was significantly enhanced by a $9.7 million non-cash gain related to changes in the fair-market value of derivative contracts that did not qualify for hedge accounting treatment. Net income in 2000 was significantly enhanced by a $32.3 million gain on the refinancing of our senior subordinated debt and was partially offset by an $8.9 million non-cash loss related to changes in the fair-market value of derivative contracts that did not qualify for hedge accounting treatment. The following table sets forth certain operating data for the periods presented.
SIX MONTHS YEAR ENDED DECEMBER 31, ENDED JUNE 30, ------------------------------------------- --------------- 2002 2001 2000 1999 1998 2003 2002 ------ ------ ------ ------ ------ ------ ------ NET PRODUCTION VOLUMES: Natural gas (MMcf)................. 5,791 6,766 4,431 4,197 4,269 3,000 2,844 Oil (MBbls)........................ 701 468 362 346 396 402 315 Natural gas equivalent (MMcfe)... 9,996 9,573 6,600 6,270 6,644 5,412 4,733 AVERAGE SALES PRICES(A): Natural gas (per Mcf).............. $ 3.21 $ 3.11 $ 1.94 $ 2.11 $ 2.04 $ 5.12 $ 2.92 Oil (per Bbl)...................... 23.55 24.05 29.17 17.79 12.85 28.39 21.95 Weighted average (per Mcfe)...... 3.51 3.37 2.90 2.39 2.08 4.95 3.21 COSTS AND EXPENSES PER MCFE: Lease operating.................... $ 0.38 $ 0.36 $ 0.32 $ 0.36 $ 0.33 $ 0.41 $ 0.35 Production taxes................... 0.20 0.16 0.27 0.15 0.13 0.32 0.18 General and administrative......... 0.50(b) 0.38 0.47 0.56 0.70 0.43 0.57(c) Depletion of oil and natural gas properties....................... 1.46 1.38 1.20 1.24 1.28 1.46 1.38
- --------------------------- (a) Reflects the effects of our hedging activities. See "--Quantitative and Qualitative Disclosures About Market Risk--Derivative Instruments and Hedging Activities." (b) Includes a charge for non-cash compensation expense of $596,000 ($0.06 per Mcfe) related to vesting of options by an officer who left Brigham. (c) Includes a charge for non-cash compensation expense of $596,000 ($0.13 per Mcfe) related to vesting of options by an officer who left Brigham. Comparison of the six-month periods ended June 30, 2003 and 2002 Production. For the six-month period ended June 30, 2003 compared to the six-month period ended June 30, 2002, our net equivalent production volume increased 14%. Our average net equivalent daily production volumes for the first six months of 2003 were 30.1 MMcfe/d compared to 26.3 MMcfe/d for the same period of 2002. The increase in our production volume was due to production growth from wells that were drilled and completed during late 2002 or the first half of 2003. New production related to these recently completed wells was partially offset by the natural decline of existing production. Natural gas represented 55% of our total production during the first six months of 2003 compared to 60% during the first six months of 2002. Revenue from the sale of oil and natural gas. Revenue from the sale of oil and natural gas for the six-month period ended June 30, 2003, was 76% higher than revenue for the six-month period ended June 30, 30 2002. Higher commodity prices accounted for 79% of this increase and higher production volumes accounted for the remaining 21% of the increase. Revenue from the sale of oil and natural gas for the first six months of 2003 was $26.8 million compared to $15.2 million for the first six months of 2002. Revenue from the sale of oil and natural gas for the first six months of 2003 included a loss of $5.0 million related to the cash settlement of hedging transactions compared to a loss of $303,000 during the first six months of 2002. Production costs. Production costs 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; property taxes and insurance applicable to wells and related facilities and equipment; and severance taxes.
SIX MONTHS ENDED JUNE 30, ------------------ 2003 2002 ------ ------ (unaudited, in thousands) Lease operating expenses, excluding ad valorem taxes........ $1,914 $1,529 Ad valorem taxes............................................ 330 138 ------ ------ Total lease operating expenses............................ 2,244 1,667 Production taxes............................................ 1,744 852 ------ ------ Total production costs............................ $3,988 $2,519 ====== ======
Production costs for the six-month period ended June 30, 2003 increased 58% when compared to the six-month period ended June 30, 2002. - Increases in our lease operating expenses excluding ad valorem taxes represented 26% of this increase. This increase was due to an increase in workover activity during the second quarter 2003. - Increases in our production taxes represented 61% of this increase. The increase in our production taxes was due to higher oil and gas prices. Production taxes for the first six months of 2003 and 2002 were 5.5% of revenues from the sale of oil and gas before hedging effects. - Increases in our ad valorem taxes represented 13% of this increase. General and administrative expenses. General and administrative expenses for the six-month period ending June 30, 2003 were 13% lower than general and administrative expenses during the first six months of 2002. General and administrative expenses for the first six months of 2002 included a charge for non-cash compensation expense of $596,000 related to vesting of options by an officer who left Brigham. Excluding this non-cash charge general and administrative expenses for the first six months of 2003 were 11% higher than general and administrative expenses for the first six months of 2002. Increases in payroll expenses, payroll taxes, employee benefit expenses and director and financial reporting expenses all contributed to the increase in general and administrative expenses during the first six months of 2003. These increases were partially offset by a decrease in property tax. For the six-month period ending June 30, 2003, general and administrative expenses per unit of production were $0.43 per Mcfe compared to $0.57 per Mcfe in 2002. An increase in production volumes resulted in a decrease in our general and administrative expense per unit of production. Depletion of oil and natural gas properties. Depletion expenses for the first six months of 2003 were 21% higher than depletion expenses during the first six months of 2002. Approximately 68% of the increase in our depletion expenses for the first six months of 2003 was due to higher production volumes and approximately 32% of the increase was due to the increase in our depletion rate. The increase in our per unit depletion rate is primarily due to additional future development cost related to our Floyd Fault Block discovery at year end 2002. Interest expense. Interest expense for the six-month period ended June 30, 2003 decreased 18% when compared to interest expense for the same six-month period last year. This decrease in our interest expense was primarily due to a decrease in the amount of borrowings that we had outstanding under our senior credit facility and a decrease in the interest rate on borrowings outstanding under our senior credit 31 facility. This decrease was partly offset by an increase in the interest expense on our subordinated notes facility and an increase in commitment fees paid on unused portion of our senior credit facility.
SIX MONTHS ENDED JUNE 30, --------------------- 2003 2002 --------- --------- (unaudited, dollars in thousands) Interest on senior credit facility.......................... $ 1,145 $ 1,833 Interest on senior subordinated notes(a).................... 1,180 1,076 Commitment fees............................................. 35 3 Amortization of deferred loan and debt issuance cost........ 533 585 Other general interest expense.............................. 28 23 Capitalized interest expense................................ (415) (450) ------- ------- Net interest expense...................................... $ 2,506 $ 3,070 ======= ======= Weighted average debt outstanding........................... $79,504 $95,185 Average interest rate on outstanding indebtedness(b)........ 6.0% 6.2%
- --------------------------- (a) Fifty percent of the interest expense on our senior subordinated notes has been or will be paid in kind. (b) Calculated using the sum of the interest expense on our senior credit facility, senior subordinated notes and commitment fees for the period divided by the average debt outstanding for the period. Other income (expense). Other income (expense) consisted primarily of 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 portion of cash flow hedges. Other income (expense) included:
SIX MONTHS ENDED JUNE 30, ----------------- 2003 2002 ------ ------ (unaudited, in thousands) Non-cash gain (loss) due to the change in the fair market value of derivative contracts that did not qualify as hedges.................................................... $ -- $ 384 Non-cash gain (loss) for ineffective portion of hedges...... (170) Cash settlement of derivatives that did not qualify as hedges.................................................... (559) Other....................................................... -- 6 ----- ----- Total..................................................... $(170) $(169) ===== =====
Dividends and accretion of mandatorily redeemable preferred stock. We are required to pay dividends on our Series A and Series B preferred stock. At our option, these dividends may be paid in cash at a rate of 6% per annum or paid in kind through the issuance of additional shares of preferred stock in lieu of cash at a rate of 8% per annum. We elected to pay dividends in kind during the first six months of 2003 and 32 2002. The following table shows the effect on our balance sheet of the issuance of additional shares of preferred stock in lieu of cash dividends.
SIX MONTHS ENDED JUNE 30, ----------------- 2003 2002 ------- ------- (unaudited, dollars in thousands) Dividends................................................... $1,817 $1,307 Accretion of mandatorily redeemable preferred stock......... 206 112 ------ ------ Total..................................................... $2,023 $1,419 ====== ====== Additional preferred shares issued: Series A.................................................... 70,728 65,342 Series B.................................................... 20,087 --
Comparison of the twelve-month periods ended December 31, 2002, 2001 and 2000 Production. Our net equivalent production volumes for 2002 were 10.0 Bcfe (27.7 MMcfe/d) compared to 9.6 Bcfe (26.6 MMcfe/d) in 2001 and 6.6 Bcfe (18.3 MMcfe/d) in 2000. The increase in production volume was due to production growth from wells that were drilled and completed during the period. New production from these wells was partially offset by the natural decline of existing production. Natural gas represented 58%, 71% and 67% of our total production in 2002, 2001 and 2000, respectively. Revenue from the sale of oil and natural gas. Revenue from the sale of oil and natural gas for 2002 was $35.1 million compared to $32.3 million in 2001 and $19.1 million in 2000. For 2002 compared to 2001, revenue from the sale of oil and natural gas was up $2.8 million or 9%. A 4% increase in our total production volume accounted for $2.6 million of this change and a $0.14 per Mcfe increase in our average realized sales price for oil and natural gas accounted for $232,000 of this change. Revenue from the sale of oil and natural gas in 2002 included a loss of $1.8 million, or $0.19 per Mcfe, related to cash settlements on hedging transactions, compared to a loss of $8.2 million, or $0.85 per Mcfe, related to cash settlements on hedging transactions in 2001. Our average realized sales price for oil and natural gas in 2002 was $3.51 per Mcfe compared to $3.37 per Mcfe in 2001. For 2001 compared to 2000, revenue from the sale of oil and natural gas was up $13.2 million or 69%. A 45% increase in our total production volume accounted for $7.7 million of this change and a $0.47 per Mcfe increase in our average realized sales price for oil and natural gas accounted for $5.5 million of this change. Revenue from the sale of oil and natural gas in 2001 included a loss of $8.2 million, or $0.85 per Mcfe, related to cash settlements on hedging transactions, compared to a loss of $9.5 million, or $1.44 per Mcfe, related to cash settlements on hedging transactions in 2000. Our average realized sales price for oil and natural gas in 2001 was $3.37 per Mcfe compared to $2.90 per Mcfe in 2000. Other revenue. Other revenue was $76,000 in 2002, compared to $255,000 in 2001 and $69,000 in 2000. This revenue relates to billings to other parties who use our two gas gathering systems to move their production from the wellhead to third party gas pipeline systems. These gas gathering systems are owned by us and located in the Texas Gulf Coast. One of the gathering systems connects to a single well and the other connects two wells. Production costs. Production costs 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 33 operating the wells and related equipment and facilities; property taxes and insurance applicable to wells and related facilities and equipment; and severance taxes.
YEAR ENDED DECEMBER 31, ------------------------ 2002 2001 2000 ------ ------ ------ (in thousands) Lease operating expenses, excluding ad valorem taxes....... $3,148 $3,015 $1,886 Ad valorem taxes........................................... 611 471 253 ------ ------ ------ Total lease operating expenses........................... 3,759 3,486 2,139 Production taxes........................................... 1,977 1,511 1,786 ------ ------ ------ Total production expenses........................ $5,736 $4,997 $3,925 ====== ====== ======
For 2002 compared to 2001, total lease operating expenses increased 8%. On a per unit of equivalent production basis, lease operating expenses for 2002 were $0.38 per Mcfe, compared to $0.36 per Mcfe in 2001. The change in our lease operating expense was primarily the result of higher ad valorem taxes due to an increase in 2002 property valuations because of higher average commodity prices during 2001 and higher overall service cost. For 2001 compared to 2000, total lease operating expenses increased 63%. The change in lease operating expenses is primarily due to an increase in the number of producing wells. Lease operating expenses on a per unit of production in 2001 were $0.36 per Mcfe compared to $0.32 per Mcfe in 2000. The increase in our per unit lease operating expense was primarily due to higher overall service cost and higher ad valorem taxes due to an increase in 2001 property valuations because of higher average commodity prices during 2000. Production taxes for 2002 were $2.0 million compared to $1.5 million in 2001 and $1.8 million in 2000. For 2002 compared to 2001, the increase in production taxes was primarily due to a reduction in the number of wells that qualify for severance tax refunds in 2002. Our effective production tax rate in 2002 was 5.4% of pre-hedge oil and natural gas sales revenue, compared to 3.7% in 2001. For 2001 compared to 2000, the decrease in production taxes was primarily related to production tax refunds on wells that qualify for reduced severance tax rates. Our effective production tax rate in 2001 was 3.7% of pre-hedge oil and natural gas sales revenue, compared to 6.2% in 2000. General and administrative expenses. General and administrative expenses for 2002 were $5.0 million, compared to $3.6 million in 2001 and $3.1 million in 2000. For 2002 compared to 2001, general and administrative expenses increased 37%. A charge for non-cash compensation expense of $596,000 related to vesting of options by an officer who left the company accounted for 45% of the total increase in general and administrative expenses. Increases in payroll and benefit expenses represented approximately 20% of the total increase in general and administrative expenses. The increase in payroll and benefit expenses was due to an increase in relocation bonuses, an increase in the cost of employee medical and life insurance and increased salaries. Additionally, an increase in other office expenses accounted for 12% of the increase, an increase in office rent accounted for 6% of the increase and an increase in corporate insurance accounted for approximately 4% of the increase. Our general and administrative expenses on a per unit of production basis for 2002 were $0.50 per Mcfe compared to $0.38 per Mcfe during 2001. The charge for non-cash compensation expense accounted for $0.06 per Mcfe of our 2002 general and administrative expense per unit of production. For 2001 compared to 2000, general and administrative expenses increased 17%. Approximately 70% of this increase was due to an increase in payroll and benefit expenses. The increase in payroll and benefit expenses was due to an increase in employee medical and life insurance, salary increases and the hiring of new employees. Other expenses that contributed to the increase were contract and professional expenses, which accounted for 20% of the increase and increases in other office expenses and public company expenses which were partially offset by a decrease in office equipment rental and maintenance expenses. 34 Increased production volumes during 2001 resulted in a decrease in our general and administrative expense on a per unit of production basis. For 2001, our per unit general and administrative expenses were $0.38 per Mcfe compared to $0.47 per Mcfe during 2000. Depletion of oil and natural gas properties. Depletion of oil and natural gas properties in 2002 was $14.6 million compared to $13.2 million in 2001 and $7.9 million in 2000. For 2002 compared to 2001, a $0.08 increase per Mcfe in our depletion rate accounted for $800,000 of the change and higher production volumes accounted for $584,000 of the change. This increase in our per unit depletion expense was due to additional future development cost related to our Floyd Fault Block Field discovery. For 2001 compared to 2000, depletion expense increased $5.3 million. Increased production volumes accounted for $4.1 million of this increase and a $0.18 increase in our depletion rate accounted for a $1.2 million of the increase. The increase in the depletion rate per unit is primarily due to an increase in the future estimated cost required to fully develop our Home Run Field. Net interest expense. Net interest expense for 2002 was $6.2 million compared to $6.7 million in 2001 and $9.9 million in 2000.
YEAR ENDED DECEMBER 31, --------------------------- 2002 2001 2000 ------- ------- ------- (dollars in thousands) Interest on senior credit facility...................... $ 3,636 $ 5,400 $ 6,266 Interest on senior subordinated notes(a)................ 2,243 1,681 4,061 Commitment fees......................................... 3 29 43 Amortization of deferred loan and debt issuance cost.... 1,191 1,372 1,283 Amortization of debt discount........................... - - 673 Other general interest expense.......................... 44 47 352 Capitalized interest expense............................ (878) (1,848) (2,772) ------- ------- ------- Net interest expense.................................. $ 6,238 $ 6,681 $ 9,906 ======= ======= ======= Weighted average debt outstanding....................... $95,562 $90,646 $97,424 Average interest rate on outstanding indebtedness(b).... 6.2% 7.8% 10.6%
- --------------------------- (a) Includes $1.1 million, $721,000 and $4.6 million in interest expense on our senior subordinated notes that was paid in kind through the issuance of additional debt in lieu of cash for 2002, 2001 and 2000, respectively. (b) Calculated as the sum of interest expense on outstanding indebtedness and commitment fees divided by weighted average debt outstanding for the period. For 2002 compared to 2001, the change in net interest expense was primarily due to a lower average interest rate on outstanding indebtedness during 2002 and to a lesser extent on a decrease in the amount of deferred loan fees amortized. The change in the average interest rate on our outstanding borrowings was due to a decrease in the London Interbank Offered Rate (LIBOR), which is used to determine the interest rate on borrowings outstanding under our senior credit facility. The average interest rate on borrowings outstanding under our senior credit facility during 2002 was 5.0% compared to 7.2% in 2001. At December 31, 2002, the interest rate on borrowings outstanding under our senior credit facility was 4.5%. For 2001 compared to 2000, the change in net interest expense was primarily due to a lower weighted average outstanding debt balance and a lower average interest rate on our outstanding borrowings during 2001. Our repurchase of $51.2 million in subordinated notes in November 2000 that bore annual interest rates of 12% to 14% was the primary reason for the decrease in our weighted average debt balance and lower average interest rate in 2001. A decrease in the average interest rate on borrowings outstanding 35 under our senior credit facility due to a lower LIBOR also contributed to the decrease in our average interest rate. 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. Other income (expense) included:
YEAR ENDED DECEMBER 31, ------------------------- 2002 2001 2000 ----- ------- ------- (in thousands) Non-cash gain (loss) due to change in fair market value of derivative contracts that did not qualify as hedges..... $ 384 $ 9,666 $(8,884) Non-cash loss for ineffective portion of hedges........... (122) - - Cash gain (loss) on settlement of derivative contracts that did not qualify as hedges.......................... (559) (1,492) (620) Gain (loss) on investments................................ 21 (94) - Other..................................................... (34) - - ----- ------- ------- Total................................................... $(310) $ 8,080 $(9,504) ===== ======= =======
Debt conversion expense. Debt conversion expense of $630,000 in 2002 represents the costs and fees we incurred to execute the conversion of $10 million of our senior debt to common stock. Our total outstanding indebtedness at December 31, 2002 was $81.8 million, compared to $91.7 million at December 31, 2001. There were no similar expenses in prior periods. Gain on refinancing of senior subordinated notes. In November 2000, we repurchased all of our debt and equity securities held by affiliates of Enron North America at a substantial discount. With a portion of the proceeds from two new financing transactions, we repurchased all of the Enron Affiliates' interests, which included (i) $51.2 million of senior subordinated notes due 2003 (which bore interest at annual rates of 12% to 14%) and associated accrued interest obligations, (ii) warrants to purchase an aggregate of one million shares of our common stock at $2.43 per share, and (iii) 1,052,632 shares of common stock, for total cash consideration of $20 million. As a result of the repurchase of the senior subordinated notes due 2003 at a discount to the principal amount outstanding, we recorded an extraordinary gain of $32.3 million in the fourth quarter of 2000. There were no similar items during 2002 or 2001. Dividends and accretion of mandatorily redeemable preferred stock. We are required to pay dividends on our Series A and Series B preferred stock. At our option, these dividends may be paid in cash at a rate of 6% per annum or paid in kind through the issuance of additional shares of preferred stock in lieu of cash at a rate of 8% per annum. We elected to pay dividends in kind during the first and second quarters of 2003 and each quarter of 2002 and 2001. The following table shows the effect on our balance sheet for the years ended December 31, 2002, 2001 and 2000 of the issuance of additional shares of preferred stock in lieu of cash dividends.
YEAR ENDED DECEMBER 31, ----------------------------- 2002 2001 2000 -------- -------- ------- (dollars in thousands) Dividends............................................. $ 2,713 $ 2,347 $ 267 Accretion of mandatorily redeemable preferred stock... 239 103 8 -------- -------- ------- Total............................................... $ 2,952 $ 2,450 $ 275 ======== ======== ======= Additional preferred shares issued Series A.............................................. 134,440 117,358 13,334 Series B.............................................. 1,226 - -
36 LIQUIDITY AND CAPITAL RESOURCES Historically, our primary sources of capital have been funds generated by operations, our senior credit and senior subordinated notes facilities, public and private equity financings, reimbursements of prior land and seismic costs by participants in our projects and the sale of interests in projects and properties. Our level of earnings and cash flow depends on market prices that we receive for our oil and natural gas production, our ability to find and produce hydrocarbons and our ability to control and reduce costs. In the current environment of higher commodity prices, there may be increased demand for drilling equipment and services, leases and economically attractive prospects, which then may result in less availability and higher costs for those resources. Also, we may face additional competition from both domestic and international sources of supply, which may exert a downward pressure on the prices we ultimately receive for our products. See also "--Senior Credit Facility." In addition, a significant known trend expected by our management to have an effect on our liquidity is our plan to accelerate our drilling activities. See "--2003 and 2004 Capital Expenditure Program." See also "--Other Matters" for a discussion of other trends that might have an effect on our liquidity. Cash Flows from Operating Activities
SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, ---------------------------- ----------------- 2002 2001 2000 2003 2002 ------- ------- -------- ------- ------- (unaudited) (in thousands) Net cash flow provided (used) by operating activities.............. $28,973 $18,922 $ (4,635) $23,518 $10,056
Net cash provided by operating activities for the first six months of 2003 was $13.4 million higher than net cash provided by operating activities in the first six months of 2002. The increase in net cash provided by operating activities was primarily due to an increase in commodity prices and lower interest expense on our senior credit facility. Our working capital deficit at June 30, 2003, was $7.2 million compared to a working capital deficit of $688,000 at December 31, 2002. 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 exploration and development costs, royalties payable and gas imbalance payables related to production from six wells in the Home Run Field. Settlement of these payables will be funded by cash flows from operations or, if necessary, by draw downs on our senior credit facility. The gas imbalance payables are partially offset by gas imbalance receivables related to four wells in the Triple Crown and Floyd Fault Block Fields. At June 30, 2003, current liabilities included a liability of $2.7 million related to the fair value of hedging contracts which was partially offset by a current asset of $133,000 related the fair value of hedging contracts. For 2002 compared to 2001, net cash provided (used) by operating activities increased $10.1 million. These changes were primarily due to an increase in our post-hedge realized sales prices for oil and natural gas and a decrease in interest expense related to our senior credit facility. These changes were partially offset by increases in our lease operating expenses, production taxes, general and administrative expenses and debt conversion cost. At December 31, 2002 we had a working capital deficit of $688,000 compared to a working capital surplus of $1.7 million at December 31, 2001. The decrease in our working capital position at the year-end 2002 was primarily due to an increase in royalties payable partially offset by an increase in deposits related to derivative contracts. For 2001 compared to 2000, net cash provided (used) by operating activities increased $23.6 million. This increase was primarily the result of an increase in revenue due to higher production volumes and an improved post-hedge realized sales prices for oil and natural gas. This increase was partially offset by an increase in our per unit lease operating expenses. For the year ended December 31, 2001 we had a working 37 capital surplus of $1.7 million compared to a working capital deficit of $7.2 million at December 31, 2000. The increase in our working capital position for the year-end 2001 was primarily due to a $6.3 million decrease in our current liabilities related to fair value adjustments for derivative contracts that did not qualify for treatment as hedges. Cash Flows from Investing Activities
SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, --------------------------- ----------------- 2002 2001 2000 2003 2002 ------- ------- ------- ------- ------- (unaudited) (in thousands) Net cash used by investing activities......................... $27,206 $33,571 $26,071 $19,214 $13,193
The increase in net cash used by investing activities is primarily the result of a 38% increase in capital expenditures for the first six months of 2003 compared to capital expenditures for the first six months of 2002. For 2002 compared to 2001, a 20% decrease in capital spending on exploration and production activities resulted in a $6.4 million decrease in net cash used by investing in 2002. Net cash used by investing activities in 2002 was further reduced by an increase in reimbursements from participants in our projects for prior land and seismic cost. For 2001 compared to 2000, a 23% increase in capital spending on exploration and production activities resulted in a $7.5 million increase net cash used by investing in 2001. We also sold interests in certain 3-D seismic data in 2000 for $3.9 million. Cash Flows from Financing Activities
SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, -------------------------- ---------------- 2002 2001 2000 2003 2002 ------ ------- ------- ------- ------ (unaudited) (in thousands) Net cash provided (used) by financing activities........................... $8,439 $18,924 $28,801 $(7,391) $3,725
During the first six months of 2003 we repaid $7.0 million of borrowings outstanding under our senior credit facility and incurred $985,000 in loan origination fees associated with our new senior credit facility. These amounts were offset by $594,000 in net proceeds from the exercise of employee stock options. During the first six months of 2002 we borrowed an additional $4.0 million in senior subordinated notes and received $107,000 in cash proceeds from the exercise of employee stock options. During the first six months of 2002 we paid $360,000 in fees associated with our senior credit facility and subordinated notes and paid $22,000 in capital lease obligations. Net cash provided by financing activities in 2002 included $4.0 million of additional borrowing under our senior subordinated notes, $9.4 million in net proceeds from the issuance of $10 million in Series B preferred stock and warrants to purchase our common stock and $921,000 in proceeds from the exercise of options and warrants that resulted in the issuance of 376,409 shares of our common stock. These inflows were partially offset by the repayment of $5.0 million of outstanding indebtedness under our senior credit facility and the payment of $684,000 in loan cost. Net cash provided by financing activities in 2001 included $9.0 million of additional borrowing under our senior subordinated notes, $9.8 million of net proceeds from the issuance of $10 million in Series A preferred stock and warrants to purchase our common stock and $252,000 in proceeds from the exercise of options that resulted in the issuance of 97,474 shares of our common stock. 38 Net cash provided by financing activities in 2000 included $19.0 million in additional borrowings under our senior credit facility, $7.0 million of borrowing under our senior subordinated notes, $20.1 million in net proceeds from the issuance of $20.0 million in Series A preferred stock and warrants to purchase our common stock, $4.2 million in net proceeds from the sale of 2.2 million shares of our common stock and the payment of $902,000 in loan cost. These inflows were partially offset by our purchase of $51.2 million of our outstanding subordinated notes and associated accrued interest, warrants to purchase one million shares of common stock at $2.43 per share and 1.1 million shares of our common stock, for total cash consideration of $20.0 million. Capital Expenditures
SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, --------------------------- ----------------- 2002 2001 2000 2003 2002 ------- ------- ------- ------- ------- (unaudited) (in thousands) Drilling............................. $19,800 $27,209 $18,461 $12,683 $ 9,865 Land and geological and geophysical........................ 3,751 2,750 4,585 2,476 1,124 Capitalized general and administrative expenses and interest........................... 5,657 6,050 6,300 3,160 2,582 Proceeds from participants and sales.............................. (1,524) (397) (4,002) (352) (617) ------- ------- ------- ------- ------- Net capital expenditures on oil and gas activities............ 27,684 35,612 25,344 17,967 12,594 Other property and equipment......... 249 241 135 209 183 ------- ------- ------- ------- ------- Total net capital expenditures.................. $27,933 $35,853 $25,479 $18,176 $13,137 ======= ======= ======= ======= =======
2003 and 2004 Capital Expenditure Program Our total net capital spending budget for the third and fourth quarters of 2003 is $37 million and we estimate our capital spending budget for 2004 to be $81 million. The majority of our planned 2003 and 2004 expenditures will be directed toward the drilling of our exploration and development inventory to focus resources on our primary objective of growing production volumes and cash flow. For 2003, we expect to drill 53 (28 development and 25 exploratory) wells with an average working interest of approximately 41%. For 2004, we expect to drill 56 (35 development and 21 exploratory) wells. Capitalizing on our prior discoveries, including the Home Run, Mills Ranch, Triple Crown, Floyd Fault Block and Providence Fields, approximately 56% of our 2003 and 2004 drilling expenditures are allocated to development drilling. Spending will be funded by our cash flow from operations, availability under our senior credit facility, our current cash balance and the proceeds from this offering. In addition to using cash from operations to fund our accelerated program, subject to satisfaction of conditions precedent under our senior credit facility, through 2004 we have currently budgeted to re-borrow approximately $20 million under our senior credit facility to fund costs as they are incurred. Estimated capital expenditures for the second half of 2003 represent an increase of approximately 110% from that of our original 2003 budget and the forecasted expenditures for 2004 represent an increase of approximately 47% from our accelerated 2003 budget. The final determination with respect to drilling those currently budgeted wells may depend on a number of factors, including: - the results of exploration efforts and the review and analysis of our 3-D seismic data; - the availability of sufficient capital resources by us and other participants for drilling prospects; - economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural gas and oil and the availability of drilling equipment; 39 - the availability of leases on reasonable terms for the potential drilling location; and - the availability of more economically attractive prospects. There can be no assurance that the budgeted wells will, if drilled, encounter commercial quantities of natural gas or oil. Statements in this section include forward-looking statements. See "Forward-Looking Statements." Contractual Obligations The following schedule summarizes our known contractual cash obligations at June 30, 2003 and the effect such obligations are expected to have on our liquidity and cash flow in future periods.
PAYMENTS DUE BY YEAR ------------------------------------------------------- TOTAL REMAINDER 2005- 2007 AND OUTSTANDING OF 2003 2004 2006 THEREAFTER ----------- --------- ------ ------- ---------- (in thousands) Senior credit facility(a).......... $ 53,000 $ - $ - $53,000 $ - Senior Subordinated notes(b)....... 22,382 - - 22,382 - Non-cancelable operating leases.... 3,843 481 1,921 1,441 - Mandatorily redeemable, Series A preferred stock(c)............... 36,717 - - - 36,717 Mandatorily redeemable, Series B preferred stock(d)............... 10,426 - - - 10,426 -------- ------- ------ ------- ------- Total contractual cash obligations...................... $126,368 $ 481 $1,921 $76,823 $47,143 ======== ======= ====== ======= =======
- --------------------------- (a) Based on $53 million outstanding and a current interest rate of 3.35%, we would be required to pay $1.8 million in interest per year until our senior credit facility matures. This amount of interest will fluctuate over time as borrowings under our senior credit facility increase or decrease and as the applicable interest rate increases or decreases. (b) Based on $22.4 million outstanding and a current interest rate of 10.75%, we would be required to pay $2.4 million in interest per year until our senior subordinated notes matures. This amount of interest will fluctuate over time as borrowings under our senior subordinated notes increase or decrease. (c) CSFB Private Equity can use $29.2 million of our Series A preferred stock to pay the warrant exercise price to purchase 6,666,667 shares of our common stock for $3.00 per share and 2,105,263 shares of our common stock for $4.35 per share. See "--Series A Preferred Stock." If the average price of our common stock trades above $5.00 per share each day for 60 consecutive trading days, we can require CSFB Private Equity to exercise the warrants to purchase 6,666,667 shares of our common stock for $3.00 per share. If the average price of our common stock trades above $6.525 (150% of the exercise price of the warrants) each day for 60 consecutive trading days, we can require CSFB Private Equity to exercise the warrants to purchase 2,105,263 shares of our common stock for $4.35 per share. If we require CSFB Private Equity to exercise either of these warrants, we will be required to use any cash proceeds from the exercise to retire Series A preferred stock. The Series A preferred stock is redeemable at our option at 100% or 101% of the stated value (depending upon certain conditions) at anytime prior to maturity. (d) CSFB Private Equity can use $10.0 million of our Series B preferred stock to pay the warrant exercise price to purchase 2,298,850 shares of our common stock for $4.35 per share. See "--Series B Preferred Stock." If the price of our common stock averages at least $6.525 (150% of the exercise price of the warrants) over 60 consecutive trading days, we can require CSFB Private Equity to exercise the warrants to purchase 2,298,850 shares of our common stock for $4.35 per share. If we require CSFB Private Equity to exercise these warrants, we will be required to use any cash proceeds from the exercise to retire Series B preferred stock and, provided the exercise price of the warrants is paid solely through delivery of shares of Series B preferred stock, we will be required to retire any Series B preferred stock that remains outstanding. The Series B preferred stock is redeemable at our option at 100% or 101% of the stated value (depending upon certain conditions) at anytime after December 2007. 40 Senior Credit Facility In March 2003, we replaced our then existing senior credit facility with a new senior credit facility that provides for a maximum $80 million in commitments and an initial borrowing base of $70 million and matures in March 2006. However, in the event that our senior subordinated notes are not retired or refinanced prior to July 31, 2005, the senior credit facility will mature on August 31, 2005. Borrowings under our senior credit facility are secured by substantially all of our oil and natural gas properties and other tangible assets and bear interest at either the base rate of Societe Generale or LIBOR, at our option, plus a margin that varies according to facility usage. Interest is paid quarterly. The collateral value and borrowing base are redetermined semi-annually and are based in part on prevailing oil and natural gas prices. If, upon redetermination, our borrowing base decreases, we may have to repay a portion of our borrowings immediately, our access to further borrowings will be reduced, and we may not have the resources necessary to carry out our planned drilling activities. The unused portion of the committed borrowing base is subject to an annual commitment fee of 0.5%. As of July 31, 2003, we had $53 million of borrowings outstanding and $15.5 million of additional borrowing capacity under our senior credit facility. The senior credit facility agreement contains various covenants and restrictive provisions, which limit our ability to incur additional indebtedness, sell properties, purchase or redeem our capital stock, make investments or loans, create liens and make certain acquisitions. Our senior credit facility requires us to maintain a current ratio (as defined) of at least 1 to 1 and an interest coverage ratio (as defined) of at least 3.25 to 1. Should we be unable to comply with these or other covenants, our senior lenders may be unwilling to waive compliance or amend the covenants in the future. In such instance, our liquidity may be adversely affected, which could in turn have an adverse impact on our future financial position and results of operations. If we should fail to perform our obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due and payable. Our current ratio, as defined by the senior credit facility, at June 30, 2003 and interest coverage ratio for the twelve-month period ending June 30, 2003, were 1.2 to 1 and 6.1 to 1, respectively. Senior Subordinated Notes As of July 31, 2003, we had $22.7 million of senior subordinated notes outstanding. The notes bear interest at 10.75% per annum, payable quarterly in arrears on the last day of January, April, July and October, are redeemable at our option for face value at any time and have no principal repayment obligations until maturity in October 2005. Through October 2002, at our option, up to 50% of the interest payments on our senior subordinated notes could be satisfied by payment in kind through the issuance of additional senior subordinated notes in lieu of cash. In December 2002, as part of the exchange of our common stock for warrants and debt conversion rights, we extended our option to satisfy 50% of our interest obligation through the issuance of additional senior subordinated notes through October 2003. As of July 31, 2003, we have exercised this option and have issued approximately $2.7 million in additional senior subordinated notes. As of July 31, 2003, we had no additional borrowing capacity under our senior subordinated notes. The senior subordinated notes are issued pursuant to a senior subordinated notes dated October 31, 2000, which was amended and restated on March 21, 2003. Under the facility, our lender agreed to provide up to $20 million (plus any amount of interest paid in kind) in senior subordinated notes in borrowing increments of at least $1 million. Once borrowings under the senior subordinated notes have been repaid, they cannot be withdrawn. The senior subordinated notes are secured obligations ranking junior to our new senior credit facility and have covenants similar to the new senior credit facility. Series A Preferred Stock We have issued two tranches of mandatorily redeemable Series A preferred stock to merchant banking funds managed by affiliates of CSFB Private Equity (CSFB Private Equity). The first tranche, $20 million, was issued in November 2000 and the second tranche, $10 million, was issued in March 2001. We are required to pay dividends on our Series A preferred stock, based on the stated value of $20.00 per 41 share. 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. Our option to pay dividends in kind expires in November 2005. To date, we have satisfied all of the dividend payments with issuance of additional shares of Series A preferred stock. The Series A preferred stock has a ten-year maturity and is redeemable at our option at 100% or 101% of the stated value per share (depending upon certain conditions) at anytime prior to maturity. As of July 31, 2003 the liquidation value of the Series A preferred stock was $36.7 million including accrued but unpaid dividends. Approximately $6.7 million of the liquidation value represents additional Series A preferred stock issued and accrued to satisfy our dividend payments. In connection with the two tranches of Series A preferred stock, we issued to CSFB Private Equity warrants to purchase our common stock. With the first tranche we issued warrants to purchase 6,666,667 shares of our common stock at an exercise price of $3.00. In the event that the average price of our common stock is above $5.00 per share each day for 60 consecutive days, then the warrants must be exercised if we so require. With the second tranche we issued warrants to purchase 2,105,263 shares of our common stock at an exercise price of $4.75. In connection with the December 2002 Series B preferred stock and warrant offering, the exercise price of the warrants originally issued with the second tranche of Series A preferred stock was reset to $4.35. See "--Series B Preferred Stock." To exercise the warrants, CSFB Private Equity has the option to use either cash or shares of our Series A preferred stock with an aggregate value equal to the exercise price. In the event that the average price of our common stock is above $6.525 (150% of the exercise price of the warrants) each day for 60 consecutive trading days, then the warrants must be exercised if we so require. See "Description of Capital Stock--Preferred Stock--Series A and Series B Preferred Stock." Series B Preferred Stock In December 2002, we issued CSFB Private Equity 500,000 shares of our Series B preferred stock with a stated value of $20.00 per share. Net proceeds from the offering were $9.4 million and were used to reduce borrowings under our senior credit facility and fund our drilling program and working capital requirements. The Series B preferred stock has terms similar to our Series A preferred stock. We are required to pay dividends on our Series B preferred stock, based on the stated value of $20.00 per share. 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. Our option to pay dividends in kind on our Series B preferred stock expires in December 2007. The Series B preferred stock can be redeemed at our option after December 2007 and is mandatorily redeemable in December 2012. See "Description of Capital Stock--Preferred Stock--Series A and Series B Preferred Stock." As of July 31, 2003 the liquidation value of the Series B preferred stock was $10.4 million including accrued but unpaid dividends in kind. Approximately $0.4 million of the liquidation value represents additional Series B preferred stock issued and accrued to satisfy our dividend payments. In connection with the Series B preferred stock offering, we issued to CSFB Private Equity warrants to purchase 2,298,850 shares of our common stock at an exercise price of $4.35 per share. To exercise the warrants, CSFB has the option to use either cash or shares of our Series B preferred stock with an aggregate value equal to the exercise price. In the event that the price of our common stock averages at least $6.525 (150% of the exercise price of the warrants) over 60 consecutive trading days, then the warrants must be exercised if we so require. 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 42 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 are unable to 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. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Derivative Instruments and Hedging Activities We limit our use of derivative instruments principally to commodity price hedging activities, whereby gains and losses are generally offset by price changes in the underlying commodity. Our use of derivative instruments for hedging activities could materially affect our results of operations in particular quarterly or annual periods since such instruments can limit our ability to benefit from favorable oil and natural gas price movements. Commodity Price Risk Our primary commodity market risk exposure is to changes in the prices related to the sale of our oil and natural gas production. The market prices for oil and natural gas have been volatile and are likely to continue to be volatile in the future. We employ established policies and procedures to manage our exposure to fluctuations in the sales prices we receive for our oil and natural gas production using derivative instruments. We believe the use of derivative instruments, although not free of risk, allows us to reduce our exposure to oil and natural gas sales price fluctuations and thereby achieve a more predictable cash flow. While the use of derivative instruments limits the downside risk of adverse price movements, their use may also limit future revenues from favorable price movements. Moreover, our hedging arrangements generally do not apply to all of our production and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our hedges will vary from time to time. The gas derivative transactions are generally settled based upon the average of the reporting settlement prices on the NYMEX for the last three trading days of a particular contract month. The oil derivative transactions are generally settled based on the average reporting settlement prices on the NYMEX for each trading day of a particular calendar month. For the month of December 2002 a $0.10 change in the price per Mcf of gas sold would have changed revenue by $50,000. A $0.70 change in the price per barrel of oil would have changed revenue by $50,000. The table below summarizes our total natural gas production volumes subject to derivative transactions during 2002 and the weighted average NYMEX reference price for those volumes.
NATURAL GAS SWAPS NATURAL GAS CAPS ----------------- ---------------- Volumes (MMbtu)................. 3,358,500 Volumes (MMbtu)................. 1,810,000 Average ceiling price Average price ($/MMbtu)......... $3.132 ($/MMbtu)....................... $2.633
43 The table below summarizes our total crude oil production volumes subject to derivative transactions during 2002 and the weighted average NYMEX reference price for those volumes.
CRUDE OIL SWAPS CRUDE OIL COLLARS --------------- ----------------- Volumes (Bbls).................. 126,500 Volumes (Bbls).................. 204,500 Average price ($/Bbls).......... $25.96 Average price ($/Bbls) Floor......................... $18.00 Ceiling....................... $22.36
As of the date hereof, our oil and gas derivative instruments are comprised of swaps, collars and floors. For swap instruments, we receive a fixed price for the hedged commodity and pay a floating market price, as defined in each instrument, to the counterparty. These instruments are settled monthly. When the floating price exceeds the fixed price for a contract month, we pay the counterparty. When the fixed price exceeds the floating price, the counterparty is required to make a payment to us. We have designated these swap instruments as cash flow hedges designed to achieve a more predictable cash flow, as well as reduce our exposure to price volatility. For collar instruments, we establish a floor and ceiling price on future commodity production. These instruments are settled monthly. When the settlement price for a period is above the ceiling price, we pay the counterparty. When the settlement price for a period is below the floor price, the counterparty is required to pay us. We have designated these collar instruments as cash flow hedges designed to achieve a more predictable cash flow, as well as reduce our exposure to price volatility. For floor instruments, we establish a floor price on future commodity production. When the settlement price for a period is below the floor price, the counterparty is required to pay us. 44 The table below summarizes the derivative contracts that we were a party to at June 30, 2003, the total natural gas and crude oil production volumes subject to those contacts, the weighted average NYMEX reference price for those volumes and the unrealized gain (loss) for those contracts.
SWAPS COLLARS FLOORS --------------------- ----------------------------- ---------------------- WEIGHTED WEIGHTED AVERAGE WEIGHTED UNREALIZED AVERAGE FLOOR CEILING AVERAGE GAIN/ NATURAL GAS VOLUMES SWAP PRICE VOLUMES PRICE PRICE VOLUMES FLOOR PRICE (LOSS) - ----------- -------- ---------- -------- -------- ------- -------- ----------- -------------- (MMbtu) ($/MMbtu) (MMbtu) ($/MMbtu) (MMbtu) ($/MMbtu) (in thousands) Quarter Ended: September 30, 2003... 598,000 $3.867 - $ - $ - 460,000 $4.500 $(905) December 31, 2003.... 414,000 4.039 - - - 460,000 4.500 (604) March 31, 2004....... 295,750 4.963 273,000 4.000 9.900 - - (236) June 30, 2004........ 227,500 4.252 182,000 4.000 5.450 - - (190) September 30, 2004... 138,000 4.180 138,000 4.000 5.390 - - (123) December 31, 2004.... 92,000 4.360 92,000 4.000 5.620 - - (96) March 31, 2005....... - - 90,000 4.000 7.250 - - (3) June 30, 2005........ - - 91,000 4,000 5,400 - - (6)
CRUDE OIL - --------- (Bbls) ($/Bbl) (Bbls) ($/Bbl) (Bbls) ($/Bbl) (in thousands) September 30, 2003... 55,200 $23.77 - $ - $ - - $ - $(321) December 31, 2003.... 41,400 23.21 - - - - - (205) March 31, 2004....... 29,575 25.35 13,650 23.00 27.74 - - (64) June 30, 2004........ 20,475 24.52 9,100 23.00 26.64 - - (40) September 30, 2004... 13,800 23.91 9,200 23.00 25.91 - - (28) December 31, 2004.... 9,200 23.80 9,200 23.00 25.39 - - (15) March 31, 2005....... - - 9,000 23.00 25.07 - - (4)
No derivative contracts have been entered into subsequent to June 30, 2003. Interest Rate Risk We are subject to interest rate risk as borrowings under our new credit facility accrue interest at floating rates based on the lender's base rate or LIBOR. We do not utilize derivative instruments to protect against changes in interest rates on debt borrowings. Based on our $53 million of outstanding borrowings under our senior credit facility as of June 30, 2003, a 1% increase in interest rates on such borrowings would reduce annual cash flow by approximately $530,000. 45 BUSINESS AND PROPERTIES OVERVIEW We are an independent exploration, development and production company that utilizes 3-D seismic imaging and other advanced technologies to systematically explore for and develop domestic onshore oil and natural gas reserves. We focus our activities in provinces where we believe 3-D seismic technology can be used effectively to maximize our return on invested capital by reducing drilling risk and enhancing our ability to grow reserves and production volumes in a cost-effective manner. Our exploration and development activities are concentrated in three provinces: the onshore Texas Gulf Coast, the Anadarko Basin and West Texas. Since our inception in 1990, we have evolved from a pioneering, 3-D seismic-driven exploration company to a balanced exploration and development company with technical and operational expertise and a strong production base. We benefit from our focus in five proven and complementary onshore trends contained within our three core provinces, providing us with diversification in our drilling investments. We believe that our five focus trends provide us with a broad range of risk profiles and reserve potentials for both natural gas and oil prospects and associated geographical and operational diversification. As a result, we are not dependent on our continued drilling success in a single core trend. Instead, in any given year our overall results may be positively impacted by the results in one or several of our focus trends. We believe that this diversification, and our knowledge base in these trends, as demonstrated by our recent track record, is a significant distinguishing factor for us. We have generated a multi-year inventory of exploration prospects which, due to our recent field discoveries, are complemented by a multi-year inventory of development locations. Since our inception through December 31, 2002, we have drilled approximately 555 wells, consisting of approximately 431 exploratory and 124 development wells with an aggregate completion rate of 68% and an average all-sources finding cost of $1.35 per Mcfe. In 2002 we spent $27.7 million in capital expenditures on oil and gas activities and achieved an all-sources finding cost of $1.36 per Mcfe. Additionally, we successfully completed 22 out of 24 wells drilled in 2002 replacing 206% of our 2002 production. To further capitalize on our multi-year inventory of exploration and development prospects, we currently plan to accelerate our drilling program and significantly increase our oil and gas capital expenditures in 2003 to approximately $55 million, representing a 97% increase over 2002 spending. In addition, we currently plan to spend approximately $81 million in capital expenditures in 2004. We have accumulated 3-D seismic data covering approximately 8,854 square miles (5.7 million acres) in over 28 geologic trends in seven provinces and seven states. We focus our 3-D seismic acquisition efforts in and around existing producing fields where we can benefit from the imaging of producing analog wells. These 3-D defined analogs, combined with our experience in drilling over 555 wells in our 3-D project areas, provide us with a knowledge base to evaluate other potential geologic trends, 3-D seismic projects within these trends and prospective 3-D delineated drilling locations. Combining our geologic and geophysical expertise with a sophisticated land effort, we manage the majority of our projects from conception through 3-D acquisition, processing and interpretation and leasing. In addition, we manage the negotiation and drafting of most of our geophysical exploration agreements, resulting in reduced contract risk and more consistent deal terms. Because we generate most of our projects, we can often control the size of the working interest that we retain as well as the selection of the operator and the non-operating participants. Consistent with our business strategy, we have increased the working interest we retain in our projects, based upon capital availability and perceived risk. 46 BUSINESS STRATEGY Our business strategy is to create stockholder value by growing reserves, production volumes and cash flow through exploration and development drilling in areas where we believe our operations will likely result in a high return on our invested capital. Key elements of our business strategy include: - Focus on Core Provinces and Trends. We have accumulated and continue to add to a multi-year inventory of 3-D seismic and geologic data and have developed a strong technical knowledge base in the following geologic trends within our core provinces: the Vicksburg and Frio trends in the onshore Texas Gulf Coast, the Springer and Hunton trends in the Anadarko Basin and the Horseshoe Atoll trend of West Texas. Further, we believe our focus on these five proven onshore trends within our three core provinces provides us with important drilling investment diversification. Since 1999, our drilling success in these trends has resulted in five significant field discoveries and a multi-year inventory of development drilling locations. We plan to focus a majority of our near term capital expenditures in these trends, where we believe our accumulated data and knowledge base provide a substantial competitive advantage. - Internally Generate Inventory of High Quality Exploratory Prospects. We utilize 3-D seismic and other advanced technologies, including computer-aided exploration, to generate and maintain a large multi-year inventory of high quality exploratory prospects. Our highly-skilled staff of eleven geophysicists and geologists generates substantially all of our prospects. We do not rely on third party generated opportunities, which usually involve the payment of consideration over and above the costs incurred to generate and drill the prospect. We believe that our five field discoveries and our history of achieving low all-sources finding costs over the last three, five and seven years, averaging $1.31, $1.46 and $1.35 per Mcfe, respectively, reflect the quality and depth of our 3-D delineated prospect inventory as well our ability to continue to generate such opportunities. - Capitalize on Exploration Successes Through Development of Field Discoveries. From 1990 to 1999, we grew our reserves and production volumes primarily through successful 3-D delineated exploration drilling. Due to our exploratory drilling success and the resulting growth in our inventory of development drilling locations, approximately 56% of our drilling capital expenditures in 2001 and 2002 were developmental. We believe our ability to balance our higher risk exploratory drilling with lower risk development drilling has reduced our risk profile. For 2003 and 2004, we intend to allocate approximately 56% of our total drilling expenditures for development drilling. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--2003 and 2004 Capital Expenditure Program." - Accelerate Drilling of Our Prospect Inventory. To capitalize on our multi-year inventory of exploration and development locations, our goal is to substantially increase our drilling activity in 2003 and 2004. In 2003 we have budgeted $42 million in drilling capital expenditures, representing a 111% increase over amounts spent in 2002. In addition, we have budgeted $65 million in drilling capital expenditures in 2004. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--2003 and 2004 Capital Expenditure Program." - Enhance Returns Through Operational Control. We seek to maintain operational control of our exploration and drilling activities. As an operator, we retain more control over the timing and selection of drilling prospects, which enhances our ability to optimize our finding and development costs and to maximize our return on invested capital. Since we generate substantially all of our projects, we generally have the ability to retain operational control over all phases of our exploration and development activities. As of December 31, 2002, we operated approximately 67% of the SEC PV-10% value of our proved developed reserves. Further, in 2002 we operated 75% of the wells we drilled, representing 79% of our drilling capital expenditures, and expect to operate the majority of the wells planned for 2003 and 2004. 47 PROPERTIES For the three-year period ended December 31, 2002, we completed 73 wells (26.4 net) in 84 attempts for a completion rate of 87% at an all-sources finding cost of $1.31 per Mcfe. Assuming the completion of this offering, we have budgeted approximately $42 million to drill approximately 28 development wells and 25 exploratory wells during 2003. Furthermore, we have budgeted $65 million to drill approximately 35 developmental and 21 exploratory wells in 2004. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--2003 and 2004 Capital Expenditure Program." The following is a summary of our properties by major province as of December 31, 2002, unless otherwise noted:
YEAR ENDED DECEMBER 31, 2002 AT DECEMBER 31, 2002 ------------------------- ----------------------------------------------------------- DRILLING AVERAGE PRODUCTIVE CAPITAL DAILY PROVED SEC % WELLS 3-D SEISMIC EXPENDITURES PRODUCTION RESERVES PV-10% NATURAL ----------- DATA PROVINCE (MILLIONS) (MMCFE/D) (BCFE) (MILLIONS) GAS GROSS NET (SQ. MILES) - -------- ------------ ---------- -------- ---------- ------- ----- --- ----------- Texas Gulf Coast..... $13.3 14.7 65.4 $181.3 84% 53 14.7 2,686 Anadarko Basin....... 5.5 7.1 46.0 102.0 94% 110 27.2 2,197 West Texas/Other..... 1.0 6.0 9.7 24.1 17% 94 26.6 3,971 ------------ --------- -------- ---------- ----- --- ----------- Total.............. $19.8 27.8 121.1 $307.4 82% 257 68.5 8,854 ============ ========= ======== ========== ===== === ===========
TEXAS GULF COAST The onshore Texas Gulf Coast region is a high potential, multi-pay province that lends itself to 3-D seismic exploration due to its substantial structural and stratigraphic complexity. In addition, certain sand reservoirs display seismic "bright spots," which can be direct hydrocarbon indicators and can result in greatly reduced drilling risk. However, "bright spots" are not always reliable as direct hydrocarbon indicators and do not generally assess reservoir productivity. We believe our established 3-D seismic exploration approach, combined with our exploration staff's extensive experience in the Texas Gulf Coast and accumulated knowledge base in this province, particularly given our recent drilling successes, provides us with significant competitive advantages. The majority of our Texas Gulf Coast activity is currently concentrated in the Vicksburg and Frio trends, where we completed eight wells in eight attempts in 2002. Net production from this province for the six months ended June 30, 2003 averaged 19.5 MMcfe/d. Vicksburg Trend Since 1999, our exploration efforts in the Vicksburg trend have been focused in our Diablo Project located in Brooks County in South Texas, where we have approximately 179 square miles of 3-D seismic data. In this area we own a 34% working interest, with a major integrated oil company participant owning the remaining 66%. As of June 30, 2003, we have completed 15 wells in 15 attempts in the Vicksburg trend and generated three significant discoveries at the Home Run Field, the Triple Crown Field, and, recently, the Floyd Fault Block Field. The primary objectives within this area are complex structural features at depths ranging from 9,000 to 14,000 feet. We believe that we have a substantial inventory of proved undeveloped and non-proved Vicksburg drilling locations in our Home Run Field, Triple Crown Field, Floyd Fault Block Field, and other adjacent fault blocks. In our Vicksburg area we invested approximately $7.1 million to drill and complete four wells in 2002 and estimate our 2003 drilling expenditures devoted to this area to be approximately $12 million to drill six development wells and one exploratory well. We expect to direct a significant portion of our future capital expenditures towards proved and non-proved opportunities in this area. Floyd Fault Block. We drilled our Floyd Fault Block discovery, the Sullivan #8, in December 2002. We retained a 34% working and 25% revenue interest in the Sullivan #8, which proves up reserves in one of several fault blocks adjacent to our Home Run and Triple Crown Fields. The Sullivan #8 encountered approximately 172 feet of apparent net pay in several lower Vicksburg pay intervals at depths between 48 12,900 and 13,650 feet. The quantity of pay encountered is approximately three times that encountered in our typical Home Run Field. The Sullivan #8 began producing in March 2003 at a rate of approximately 9.2 MMcf of natural gas and 580 barrels of condensate per day (12.7 MMcfe/d), or approximately 3.2 MMcfe/d net to our 25% revenue interest. In July 2003, production facilities for the Sullivan #8 were expanded. Subsequently the Sullivan #8 produced approximately 10.8 MMcf of natural gas and 620 barrels of oil per day (14.4 MMcfe). From its initial production in March 2003 to late July 2003 the Sullivan #8 produced over 1.4 Bcfe. We estimate that up to nine additional wells will be required for full development of the Floyd Fault Block Field, four of which were classified as proved undeveloped locations at December 31, 2002. We retained a 34% working interest and 25% net revenue interest in the Sullivan #9, the first development well in our Floyd Fault Block Field. The Sullivan #9 encountered approximately 29 feet of net pay, and was successfully completed and fracture stimulated. The Sullivan #9 recently commenced production at an initial rate of approximately 8.0 MMcf of natural gas and 350 barrels of oil per day (10.1 Mmcfe/d), or approximately 2.5 Mmcfe/d net to our revenue interest, with a flowing tubing pressure of approximately 5,500 psi. We expect to drill up to two additional wells within the Floyd Fault Block Field in 2003. Home Run Field & Triple Crown Field. We discovered the Home Run Field in late 1999 and the Triple Crown Field in 2001. As of July 31, 2003, we have drilled and completed 13 consecutive wells in these fields with an average working interest of 37%. During 2002, we drilled and completed three wells in the Home Run Field and expect to drill three wells within the Home Run Field in 2003. We believe that the Home Run and Triple Crown Fields could require up to 35 additional wells for full development, 13 of which were classified as proved undeveloped at December 31, 2002. Adjacent Fault Blocks to Home Run and Triple Crown Fields. We have identified up to 27 additional potential locations in various fault blocks adjacent to our Home Run Field, Triple Crown Field and Floyd Fault Block Field discoveries. During 2003, we anticipate testing at least one of these fault blocks. We believe that all of the adjacent fault blocks are located structurally high to known production established at the adjacent Triple Crown Field. We currently have no reserves booked for the adjacent fault blocks because the productivity of the undrilled fault blocks has not yet been demonstrated. Additional Vicksburg Potential. We continue to generate prospects in the Vicksburg trend, and we recently identified three additional, high potential Vicksburg prospects in the Brooks County area. We could potentially drill the first of these prospects in late 2003. Frio Trend In the Frio trend of the Upper Texas Gulf Coast, we have accumulated an inventory of over 1,172 square miles (750,080 acres) of predominantly non-proprietary 3-D seismic data located primarily in Matagorda and Brazoria Counties in south Texas. Within this trend we are targeting both the shallow non-pressured and the deeper pressured Frio sands. Reservoirs in this trend can display seismic "bright spots", which can be direct hydrocarbon indicators and can result in greatly reduced drilling risk. However, "bright spots" are not always reliable as direct hydrocarbon indicators and do not generally assess reservoir productivity. Since late 2000 we have completed 13 Frio wells in 15 attempts and discovered our highly prolific Providence Field. In our Frio trend area we invested approximately $5.6 million to drill and complete 4 wells in 2002 and estimate our 2003 drilling expenditures to be approximately $15 million to drill three development wells and 12 exploratory wells. Providence Frio Field. We discovered the Providence Field during the fourth quarter of 2001, when we drilled and completed the Staubach #1 well. We own a 34.28% working interest in the Staubach #1 well. Including the Staubach #1 discovery well in 2001, we have now successfully completed five wells in five attempts in the Providence Field with an average working interest of 40%. 49 General Patton Project. In early 2003, we acquired 84 square miles of new proprietary seismic data along the same trend that has provided most of our recent Frio discoveries, including the Providence Field. We sold a 50% working interest in the project to participants on a promoted basis. As a result, we paid 33.3% of the seismic and pre-seismic land costs for our 50% working interest in the project, while also retaining operational control. Our staff recently began interpreting the data and defining drilling prospects and we plan to commence our drilling program in this area during the second half of 2003. The company is currently assembling additional 3-D seismic projects targeting the highly prolific Frio objective. Other Frio. In addition to our ongoing drilling program in the Frio trend, we continue to generate additional drilling inventory from our 3-D seismic database of more than 1,170 square miles in this trend. Historically, approximately 20% of our exploration wells targeted higher risk, higher potential objectives. However, as in recent years, the vast majority of our Frio exploration wells are expected to test relatively lower risk prospects. In recent years these prospects have provided us with high success rates and high rates of return on our drilling capital investments. Other Texas Gulf Coast The Dinn Ranch Field. We own interests in two wells located in Duval County, Texas in the Wilcox trend. The first well, the Lopez #1, has experienced operational difficulties and its completion has been delayed. The second well, the Lopez #3, was producing in February 2003 at a rate of approximately 16.5 MMcf/d of natural gas. We retain a 2% overriding royalty interest in these two wells that convert to working interests at certain payouts. In each of these two wells, we will own a 12.5% working interest at 100% payout, which will increase to a 25% working interest at 200% payout. Payout occurs at that point in time when the net proceeds from the sale of production from the well equals all of the cost and expense incurred in drilling, equipping, testing, completing and operating the well. We expect a third well to spud in early 2004 in which we plan to retain a 25% ground floor working interest. ANADARKO BASIN The Anadarko Basin is located in northwest Oklahoma and the Texas Panhandle. We believe this prolific natural gas producing province offers a combination of lower risk exploration and development opportunities in shallower horizons, as well as higher reserve potential objectives that have been relatively under explored in the deeper sections. We believe our drilling in the Anadarko Basin and West Texas generally provides us with longer life reserves and helps to balance our drilling program in the prolific, but generally shorter reserve life, onshore Texas Gulf Coast province. The stratigraphic and structural objectives in the Anadarko Basin can provide excellent targets for 3-D seismic imaging. In addition, drilling economics in the Anadarko Basin are enhanced by the multi-pay nature of many of these prospects, with secondary or tertiary targets serving as either incremental value or as alternatives in the event the primary target zone is not productive. Our recent activity has been focused primarily in the Springer Channel and Hunton trends. However, given recent successful development wells in a Springer Bar Field, discovered by us in late 2000, we are accelerating our development activity in this field. We completed four wells in six attempts in these trends in 2002. Net production from this province for the six months ended June 30, 2003 averaged 5.8 MMcfe/d. Springer Channel Trend Our 3-D seismic inventory in the Springer Channel trend consists of over 600 square miles (384,000 acres) of 3-D seismic data covering portions of Dewey, Blaine, Canadian, Grady and Caddo Counties, Oklahoma. Our activities in this area target buried fluvial sand channels at depths of 9,000 to 12,000 feet, as well as other secondary objectives. Since 2000, we have completed 13 wells in 15 attempts 50 in the Springer Channel trend. We recently entered into a joint venture encompassing approximately 14,000 gross acres of leasehold, greatly expanding our acreage position in this competitive trend. We retained a 36% working interest in the Bryson #1, which was recently completed in the Springer interval at a depth of approximately 8,800 feet. On July 20, 2003, the Bryson #1 was producing to sales at a rate of approximately 2.5 MMcf of natural gas and 110 barrels of oil per day (3.1 MMcfe/d), or approximately 0.9 MMcfe/d net to our 29% revenue interest, with a flowing tubing pressure of 3,300 psi and additional potential pay intervals remaining behind pipe. We have budgeted approximately $2 million to drill three development wells and three exploratory wells in this trend in 2003. Springer Bar Trend In Grady County, Oklahoma we have approximately 105 square miles (67,264 acres) of 3-D seismic data and together with our participants control over 10,000 leasehold acres in one of the most prolific producing areas of the Anadarko Basin. In 2000, based on our seismic stratigraphic interpretation of this data, we discovered a large Springer Bar field with the successful completion of the Nix #1 in the Britt interval of the Springer formation. In late 2000 we confirmed the field with the Pitchford #1 well, which produced from the same Britt interval at a depth of approximately 14,550 feet. We own a 17.35% working interest in the Nix #1 and a 32.27% working interest in the Pitchford #1. Development of this Springer Bar field slowed in 2001 after several of the development wells produced at rates below expectations. However, activity in the field has been reinvigorated by several recent successful wells. We recently participated in the successful drilling of the McCasland Farms #2, which commenced production in May at an initial rate of approximately 4.5 MMcf of natural gas and 50 barrels of oil per day (4.8 MMcfe/d), or approximately 0.9 MMcfe/d net to our 18.6% revenue interest. We also participated with a 15% working interest in the Stonehocker #1, although the operator is disputing our ownership interest in the well. The Stonehocker #1 began producing to sales in early July at a rate of approximately 7.0 MMcf of natural gas per day, which would be approximately 0.9 Mmcfe/d net to our approximate 12.5% revenue interest. In addition, we are currently participating in an additional development well with a 20% working interest, the Jones #2. We expect to participate in approximately 14 additional wells to further develop this Springer Bar field during the remainder of 2003 and 2004. Previously successful wells in the field have produced at initial rates ranging from 2 to 6 MMcf of natural gas per day, with low production decline rates relative to Texas Gulf Coast wells. Given these recent drilling successes, we are currently budgeting $3 million to drill nine development wells in this area in 2003. Continued success in this area would result in a multi-year development plan. Hunton Trend Our 3-D seismic inventory in the Hunton trend consists of approximately 763 square miles (488,320 acres) of 3-D seismic data covering portions of Wheeler, Hemphill and Roberts Counties, Texas and Beckham County, Oklahoma. The primary exploration targets within this area are high potential, multi-well structural features at depths ranging from 7,500 to 25,000 feet. The trend has historically provided longer life reserves relative to our typical Texas Gulf Coast wells. We have budgeted approximately $3 million to drill three development wells during 2003. Mills Ranch Field. In July 2000, we spud the Mills Ranch #1, which was drilled directionally to a total depth of over 25,000 feet. We operated this well with a 64% working interest. The Mills Ranch #1 paid out its drilling and completion costs during its first year of production, and at year-end 2002 had produced 3.2 Bcfe and was producing approximately 3.2 MMcfe/d. In the third quarter 2002, we began drilling the first offset to this discovery, the Mills Ranch #2. We retained a 64% working interest in the Mills Ranch #2 well. The Mills Ranch #2 encountered the basal Hunton porosity zone approximately 400 feet high to the comparable zone in the discovery well. After running production casing to a depth of approximately 51 23,900 feet, we perforated and stimulated the lower Hunton intervals. The well began producing at an initial rate of approximately 6.7 MMcf of natural gas per day with associated condensate. The upper intervals were then stimulated and commingled into the producing stream, and the recent production rate was approximately 2.0 MMcfe/d on May 29, 2003. We believe that the Mills Ranch Field could require up to four additional wells for full development, two of which were classified as proved undeveloped at December 31, 2002. Other Hunton Trend. We continue generating additional high potential opportunities within the Hunton trend, including prospects with substantial reserve potential in the stratigraphically deeper Arbuckle formation. The Arbuckle is a several thousand-foot carbonate interval that has been productive in a number of high reserve volume fields in the area. However, the presence of a large carbonate Arbuckle interval does not insure the presence of hydrocarbons, which in most cases will be dependent upon the presence of a fault, change in stratigraphy or other hydrocarbon trapping mechanism. The drilling depths for the Arbuckle vary widely within the trend, from as shallow as 10,000 feet to depths as great as 25,000 feet. We have accumulated approximately 2,800 acres of leasehold over a high potential Arbuckle prospect. We operate and retain a 100% working interest in this Arbuckle prospect. WEST TEXAS West Texas is predominantly an oil producing province with generally longer lived reserves than that of the onshore Texas Gulf Coast. Our drilling activity in our West Texas province has been focused primarily in various carbonate reservoirs, including the Canyon Reef and Fusselman formations of the Horseshoe Atoll trend, the Canyon Reef of the Eastern Shelf, and the Mississippian Reef of the Hardeman Basin, at depths ranging from 7,000 to 13,000 feet. Net production from this province for the six months ended June 30, 2003 averaged 4.8 MMcfe/d. Horseshoe Atoll Trend We have an inventory of approximately 778 square miles (497,920 acres) of 3-D seismic data primarily covering portions of Scurry, Howard, Dawson and Borden Counties in the Horseshoe Atoll trend, where we have accumulated substantial experience exploring with 3-D seismic over the last twelve years. In 2002, and in prior years, we frequently sold working interests in our West Texas drilling prospects to industry participants on a promoted basis, which has reduced our drilling risk while also contributing to lower finding costs and higher rates of return. Since 2000, we have completed ten wells in ten attempts in the trend with an average working interest of 43%. For 2003, we have budgeted approximately $2 million to drill two development wells and four exploratory wells. EXPLORATION AND DEVELOPMENT STAFF Our experienced exploration staff includes five geophysicists, six geologists, three computer applications specialists and two geophysical/geological/engineering technicians. Our geophysicists have different but complementary backgrounds, and their diversity of experience in varied geological and geophysical settings, combined with various technical specializations (from hardware and systems to software and seismic data processing), provides us with valuable technical intellectual resources. Our geophysicists and geologists have an average of more than 20 years of experience per person. We assembled our team according to the expertise that these individuals have within producing basins where we focus our exploration and development activities. By integrating both geologic and geophysical expertise within our project teams, we believe we possess a competitive advantage in our exploration approach. Our land department staff includes four landmen with an average of more than 22 years of experience primarily within our core provinces and three lease and division order analysts. Our land department contributed to pioneering many innovations that have facilitated exploration using large 3-D seismic projects. 52 OPERATIONS AND OPERATIONS STAFF In an effort to retain better control of our project timing, drilling and operational costs and production volumes, we have significantly increased the percentage of the wells that we operate in the past several years. We operated 75% of the gross wells and 90% of the net wells that we drilled during 2002, as compared with 10% of the gross wells and 17% of the net wells we drilled during 1996. As a result of our increased operational control in recent years, wells operated by us constituted 67% of the SEC PV-10% value of our proved developed reserves at year-end 2002, as compared to only 5% at year-end 1996. Our operations staff includes five engineers who have drilling, reservoir, environmental and operations engineering experience primarily within our three core provinces. These engineers work closely with our explorationists and are integrally involved in all phases of the exploration and development process, including preparation of pre- and post-drill reserve estimates, well design, production management and analysis of full cycle risked drilling economics. We conduct field operations for our operated oil and natural gas properties through our field production superintendent and third party contract personnel. OIL AND NATURAL GAS RESERVES Our estimated total net proved reserves of oil and natural gas at December 31, 2002, 2001 and 2000 and the present values attributable to these reserves as of those dates were as follows:
AT DECEMBER 31, ------------------------------ 2002 2001 2000 -------- -------- -------- Estimated Net Proved Reserves: Natural gas (MMcf)................................. 99,428 88,594 78,167 Oil (MBbls)........................................ 3,607 3,748 2,870 Natural gas equivalent (MMcfe).................. 121,070 111,081 95,388 Proved developed reserves as a percentage of proved reserves........................................... 46% 49% 52% SEC PV-10% (in thousands)............................ $307,374 $146,807 $497,666 Standardized Measure (in thousands).................. $239,698 $120,924 $359,228 Base price used to calculate reserves(a): Natural gas ($ per Mcf)............................ $ 4.74 $ 2.57 $ 10.42 Oil ($ per Bbl).................................... $ 31.25 $ 19.84 $ 26.83
- --------------------------- (a) These base prices were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate our reserves at these dates. The reserve estimates reflected above were prepared by Cawley, Gillespie & Associates, Inc., our independent petroleum consultants, and are part of reports on our oil and natural gas properties prepared by Cawley, Gillespie. In accordance with applicable requirements of the Securities and Exchange Commission, estimates of our net proved reserves and future net revenues are made using sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation). Estimated quantities of net proved reserves and future net revenues therefrom are affected by oil and natural gas prices, which have fluctuated widely in recent years. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond our control. The reserve data set forth in this prospectus represent only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geologic interpretation and judgment. As a result, estimates of different engineers, including those used by us, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future 53 development and exploration activities, prevailing oil and natural gas prices, operating costs and other factors. The revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. Our estimated net proved reserves have not been filed with or included in reports to any federal agency. See "Risk Factors--We are subject to uncertainties in reserve estimates and future net cash flows." Estimates with respect to net proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations in the estimated reserves that may be substantial. DRILLING ACTIVITIES We drilled, or participated in the drilling of, the following number of wells during the periods indicated:
YEAR ENDED DECEMBER 31, --------------------------------------- 2002(A) 2001(B) 2000(C) ----------- ----------- ----------- GROSS NET GROSS NET GROSS NET ----- --- ----- --- ----- --- Exploratory wells(d): Natural gas.................................. 4 0.9 5 1.6 6 1.9 Oil.......................................... 6 1.9 4 2.6 1 0.8 Non-productive............................... 1 0.7 6 1.3 2 1.0 ----- --- ----- --- ----- --- Total...................................... 11 3.5 15 5.5 9 3.7 ===== === ===== === ===== === Development wells(e): Natural gas.................................. 7 2.4 15 4.6 15 5.8 Oil.......................................... 4 1.7 2 1.1 3 0.7 Non-productive............................... 1 0.3 0 0.0 1 0.8 ----- --- ----- --- ----- --- Total...................................... 12 4.4 17 5.7 19 7.3 ===== === ===== === ===== ===
- --------------------------- (a) Excludes one (0.2 net) development well that is productive but is currently temporarily abandoned. There are no current plans to put this well on production. (b) Excludes one (0.3 net) development well that was temporarily abandoned during drilling due to operational difficulties encountered prior to reaching total depth. We re-entered and completed this temporarily abandoned well during 2002. (c) Excludes one (1.0 net) exploratory well that was temporarily abandoned during drilling due to operational difficulties encountered prior to reaching total depth. We re-entered and completed this temporarily abandoned well during 2001. (d) From January 1, 2003 through July 31, 2003, we drilled or participated in the drilling of eleven (5.1 net) exploratory wells, of which two (0.9 net) are currently drilling, three (1.5 net) are completing, three (1.3 net) were productive and three (1.4 net) were plugged. (e) From January 1, 2003 through July 31, 2003, we drilled or participated in the drilling of nine (3.6 net) development wells, of which one (0.2 net) is currently drilling, three (1.7 net) are completing and five (1.7 net) were productive. We do not own drilling rigs and the majority of our drilling activities have been conducted by independent contractors or industry participant operators under standard drilling contracts. We operated 75% (90% net) of the wells we participated in during 2002. 54 PRODUCTIVE WELLS AND ACREAGE Productive Wells The following table sets forth our ownership interest at December 31, 2002 in productive oil and natural gas wells in the areas indicated.
NATURAL GAS OIL TOTAL ------------ ------------ ------------ PROVINCE: GROSS NET GROSS NET GROSS NET - --------- ----- ---- ----- ---- ----- ---- Texas Gulf Coast............................. 34 10.2 19 4.5 53 14.7 Anadarko Basin............................... 92 22.7 18 4.5 110 27.2 West Texas................................... 13 1.9 81 24.7 94 26.6 ---- ---- ---- ---- ---- ---- Total...................................... 139 34.8 118 33.7 257 68.5 ==== ==== ==== ==== ==== ====
Productive wells consist of producing wells and wells capable of production, including wells waiting on pipeline connection. Wells that are completed in more than one producing horizon are counted as one well. Of the gross wells reported above, two had multiple completions. Acreage Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether or not such acreage contains proved reserves. The following table sets forth the approximate developed and undeveloped acreage that we held a leasehold, mineral or other interest at December 31, 2002:
DEVELOPED UNDEVELOPED TOTAL --------------- --------------- ---------------- PROVINCE: GROSS NET GROSS NET GROSS NET - --------- ------ ------ ------ ------ ------- ------ Texas Gulf Coast................. 9,825 3,582 10,514 4,660 20,339 8,242 Anadarko Basin................... 32,896 12,604 37,234 20,109 70,130 32,713 West Texas....................... 6,894 1,986 9,926 5,040 16,820 7,026 Other............................ 535 160 5,597 2,422 6,132 2,582 ------ ------ ------ ------ ------- ------ Total.......................... 50,150 18,332 63,271 32,231 113,421 50,563 ====== ====== ====== ====== ======= ======
All the leases for the undeveloped acreage summarized in the preceding table will expire at the end of their respective primary terms unless the existing leases are renewed, production has been obtained from the acreage subject to the lease prior to that date, or some other "savings clause" is implicated. The following table sets forth the minimum remaining terms of leases for the gross and net undeveloped acreage:
ACRES EXPIRING --------------- TWELVE MONTHS ENDING: GROSS NET - --------------------- ------ ------ December 31, 2003........................................... 9,014 6,324 December 31, 2004........................................... 27,449 16,001 December 31, 2005........................................... 5,366 5,333 Thereafter.................................................. - - ------ ------ Total..................................................... 41,829 27,658 ====== ======
In addition, as of December 31, 2002 we had lease options to acquire an additional 18,316 gross and 12,656 net acres, all of which expire in 2003. 55 VOLUMES, PRICES AND PRODUCTION COSTS The following table sets forth the production volumes, average prices received before hedging, average prices received after hedging and average production costs associated with our sale of oil and natural gas for the periods indicated.
YEAR ENDED DECEMBER 31, ------------------------ 2002 2001 2000 ------ ------ ------ Production: Natural gas (MMcf)....................................... 5,791 6,766 4,431 Oil (MBbls).............................................. 701 468 362 Natural gas equivalent (MMcfe)........................... 9,996 9,573 6,600 Average sales price per unit: Natural gas revenues (per Mcf)........................... $ 3.33 $ 4.29 $ 4.06 Effects of hedging activities (per Mcf).................. (0.12) (1.18) (2.12) ------ ------ ------ Average price (per Mcf)............................... $ 3.21 $ 3.11 $ 1.94 ====== ====== ====== Oil revenues (per Bbl)................................... $25.17 $24.38 $29.47 Effects of hedging activities (per Bbl).................. (1.62) (0.33) (0.30) ------ ------ ------ Average price (per Bbl)............................... $23.55 $24.05 $29.17 ====== ====== ====== Total natural gas and oil revenues (per Mcfe)............ $ 3.70 $ 4.22 $ 4.34 Effects of hedging activities (per Mcfe)................. (0.19) (0.85) (1.44) ------ ------ ------ Average price (per Mcfe).............................. $ 3.51 $ 3.37 $ 2.90 ====== ====== ====== Average production costs: Lease operating expenses (per Mcfe)................. $ 0.38 $ 0.36 $ 0.32 Production taxes (per Mcfe)......................... $ 0.20 $ 0.16 $ 0.27
COSTS INCURRED The costs incurred in oil and natural gas acquisition, exploration and development activities are as follows:
YEAR ENDED DECEMBER 31, --------------------------- 2002(A) 2001(B) 2000(C) ------- ------- ------- (in thousands) Exploration............................................. $12,693 $18,210 $14,238 Property acquisition.................................... 3,213 3,437 2,540 Development............................................. 13,301 14,353 12,555 Proceeds from participants.............................. (703) (135) (40) ------- ------- ------- Costs incurred........................................ $28,504 $35,865 $29,293 ======= ======= =======
- --------------------------- (a) Excludes $821,000 of proceeds from the sale of interests in properties, projects and prospects in 2002. (b) Excludes $262,000 of proceeds from the sale of interests in properties, projects and prospects in 2001. (c) Excludes $3.9 million of proceeds from the sale of interests in properties, projects and prospects in 2000. Costs incurred represent amounts we incurred for exploration, property acquisition and development activities. Periodically, we receive reimbursement of certain costs from participants in our projects 56 subsequent to project initiation in return for an interest in the project. These payments are described as "Proceeds from participants" in the table above. OIL AND NATURAL GAS MARKET AND MAJOR CUSTOMERS Most of our oil and natural gas production is sold under price sensitive or spot market contracts. The revenues generated by our operations are highly dependent upon the prices of and demand for oil and natural gas. The price we receive for our oil and natural gas production depends upon numerous factors beyond our control, including seasonality, weather, competition, the condition of the United States economy, foreign imports, political conditions in other oil-producing and natural gas-producing countries, the actions of the Organization of Petroleum Exporting Countries, and domestic government regulation, legislation and policies. Decreases in the prices of oil and natural gas could have an adverse effect on the carrying value of our proved reserves and our revenues, profitability and cash flow. Although we are not currently experiencing any significant involuntary curtailment of our oil or natural gas production, market, economic and regulatory factors may in the future materially affect our ability to sell our oil or natural gas production. See "Risk Factors--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" and "Risk Factors--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." For the year ended December 31, 2001, sales to Highland Energy Company and Lantern Petroleum Corporation represented approximately 60% of our oil revenue and 58% of our natural gas revenue. In 2002, in an effort to achieve better price realizations from the sale of our oil and natural gas, we decided to bring our commodities marketing activities in-house, enabling us to market and sell our oil and natural gas to a broader universe of potential purchasers. As a consequence, on March 1, 2002, we ended our oil purchase agreement with Lantern Petroleum and on July 1, 2002, we ended a similar gas sales and purchase arrangement with Highland Energy Company. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations. COMPETITION The oil and gas industry is highly competitive in all of its phases. We encounter competition from other oil and gas companies in all areas of our operations, including the acquisition of seismic and leasing options and oil and natural gas leases on properties to exploration and development of those properties. Our competitors include major integrated oil and natural gas companies and numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of our competitors are large, well established companies with substantially larger operating staffs and greater capital resources than us. Such companies may be able to pay more for seismic and lease options on oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. See "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Risk Factors--We face significant competition and many of our competitors have resources in excess of our available resources" and "Risk Factors--We have substantial capital requirements for which we may not be able to obtain adequate financing." OPERATING HAZARDS AND UNINSURED RISKS Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that new wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net 57 revenues to return a profit after drilling, operating and other costs. The cost and timing of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond our control, including title problems, weather conditions, delays by project participants, compliance with governmental requirements and shortages or delays in the delivery of equipment and services. Our future drilling activities may not be successful and, if unsuccessful, such failure may have a material adverse effect on our business, financial condition or results of operations. See "Risk Factors--Exploratory drilling is a speculative activity that may not result in commercially productive reserves and may require expenditures in excess of budgeted amounts." In addition, use of 3-D seismic technology requires greater pre-drilling expenditures than traditional drilling strategies. Although we believe that our use of 3-D seismic technology will increase the probability of drilling success, some unsuccessful wells are likely, and there can be no assurance that unsuccessful drilling efforts will not have a material adverse effect on our business, financial condition or results of operations. Our operations are subject to hazards and risks inherent in drilling for and producing and transporting oil and natural gas, such as fires, natural disasters, explosions, encountering formations with abnormal pressures, blowouts, cratering, pipeline ruptures and spills, any of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our properties and others. We maintain insurance against some but not all of the risks described above. In particular, the insurance we maintain does not cover claims relating to failure of title to oil and natural gas leases, trespass during 3-D survey acquisition or surface damage attributable to seismic operations, business interruption or loss of revenues due to well failure. Furthermore, in certain circumstances in which insurance is available, we may not purchase it. The occurrence of an event that is not covered, or not fully covered, by insurance could have a material adverse effect on our business, financial condition and results of operations. See "Risk Factors--We are subject to various operating and other casualty risks that could result in liability exposure or the loss of production and revenues" and "Risk Factors--We may not have enough insurance to cover all of the risks we face, which could result in significant financial exposure." EMPLOYEES On July 31, 2003, we had 54 full-time employees. None is represented by any labor union and we believe relations with our employees are good. FACILITIES Our principal executive offices are located in Austin, Texas, where we lease approximately 34,330 square feet of office space at 6300 Bridge Point Parkway, Building 2, Suite 500, Austin, Texas 78730. TITLE TO PROPERTIES We believe we have satisfactory title, in all material respects, to substantially all of our producing properties in accordance with standards generally accepted in the oil and gas industry. Our properties are subject to royalty interests, standard liens incident to operating agreements, liens for current taxes and other inchoate burdens, which we believe, do not materially interfere with the use of or affect the value of such properties. Our senior credit facility and senior subordinated notes are secured by first and second liens, respectively, against substantially all of our oil and natural gas properties and other tangible assets. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources--Senior Credit Facility" and "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources--Senior Subordinated Notes." 58 GOVERNMENTAL REGULATION Our oil and natural gas exploration, production, transportation and marketing activities are subject to extensive laws, rules and regulations promulgated by federal and state legislatures and agencies, including the Federal Energy Regulatory Commission (FERC), the Environmental Protection Agency, the Texas Commission on Environmental Quality (TCEQ), the Texas Railroad Commission and the Oklahoma Corporate Commission. Failure to comply with such laws, rules and regulations can result in substantial penalties. The legislative and regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability. Although we do not own or operate any pipelines or facilities that are directly regulated by FERC, its regulation of third party pipelines and facilities could indirectly affect our ability to transport or market our production. Moreover, FERC has in the past, and could in the future, impose price controls on the sale of natural gas. In addition, we believe we are in substantial compliance with all applicable laws and regulations, however, we are unable to predict the future cost or impact of complying with such laws and regulations because they are frequently amended, interpreted and reinterpreted. The states of Texas and Oklahoma, and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and natural gas. These states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells and the regulation of spacing, plugging and abandonment of such wells. ENVIRONMENTAL MATTERS Our operations and properties are, like the oil and gas industry in general, subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit seismic acquisition, construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and impose substantial liabilities for pollution resulting from our operations. The permits required for many of our operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines or injunction, or both. In the opinion of management, we are in substantial compliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us, as well as the oil and gas industry in general. The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) and comparable state statutes impose strict and arguably joint and several liability on owners and operators of certain sites and on persons who disposed of or arranged for the disposal of "hazardous substances" found at such sites. It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Resource Conservation and Recovery Act (RCRA) and comparable state statutes govern the disposal of "solid waste" and "hazardous waste" and authorize imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of "hazardous substance," state laws affecting our operations impose clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies certain oil field wastes as "non-hazardous," such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements. 59 Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as us, to prepare and implement spill prevention, control countermeasure and response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 (OPA) contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. For onshore and offshore facilities that may affect waters of the United States, the OPA requires an operator to demonstrate financial responsibility. Regulations are currently being developed under federal and state laws concerning oil pollution prevention and other matters that may impose additional regulatory burdens on us. In addition, the Clean Water Act and analogous state laws require permits to be obtained to authorize discharge into surface waters or to construct facilities in wetland areas. The Clean Air Act of 1970 and its subsequent amendments in 1990 and 1997 also impose permit requirements and necessitate certain restrictions on point source emissions of volatile organic carbons (nitrogen oxides "NOX" and sulfur dioxide "SO(2)") and particulates with respect to certain of our operations. We are required to maintain such permits or meet general permit requirements. The Environmental Protection Agency (EPA) and designated state agencies have in place regulations concerning discharges of storm water runoff and stationary sources of air emissions. These programs require covered facilities to obtain individual permits, participate in a group or seek coverage under an EPA general permit. Most agencies recognize the unique qualities of oil and gas exploration and production operations. Both the EPA and TCEQ have adopted regulatory guidance in consideration of the operational limitations on these types of facilities and their potential to emit air pollutants. We believe that we will be able to obtain, or be included under, such permits, where necessary, and to make minor modifications to existing facilities and operations that would not have a material effect on us. 60 MANAGEMENT The following are the members of our Board of Directors and our executive officers.
NAME AGE POSITION - ---- --- -------- Ben M. Brigham....................... 44 Chief Executive Officer, President and Chairman Eugene B. Shepherd, Jr............... 45 Chief Financial Officer David T. Brigham..................... 42 Executive Vice President--Land and Administration and Director A. Lance Langford.................... 41 Senior Vice President--Operations Jeffery E. Larson.................... 44 Senior Vice President--Exploration Harold D. Carter..................... 64 Director Stephen C. Hurley.................... 53 Director Stephen P. Reynolds.................. 51 Director Hobart A. Smith...................... 66 Director Steven A. Webster.................... 51 Director R. Graham Whaling.................... 49 Director
Ben M. "Bud" Brigham has served as our Chief Executive Officer, President and Chairman of the Board since we were founded in 1990. From 1984 to 1990, Mr. Brigham served as an exploration geophysicist with Rosewood Resources, an independent oil and gas exploration and production company. Mr. Brigham began his career in Houston as a seismic data processing geophysicist for Western Geophysical, Inc. a provider of 3-D seismic services, after earning his B.S. in Geophysics from the University of Texas. Mr. Brigham is the brother of David T. Brigham, Executive Vice President--Land and Administration. Eugene B. Shepherd, Jr. has served as Chief Financial Officer since June 2002. Mr. Shepherd has approximately 20 years of financial and operational experience in the energy industry. Prior to joining us, Mr. Shepherd served as Integrated Energy Managing Director at ABN AMRO Bank, a large European bank, where he executed merger and acquisition advisory, capital markets and syndicated loan transactions for energy companies. From July 1998 to August 2000, Mr. Shepherd was an investment banking Director for Prudential Securities Incorporated, where he executed a wide range of transactions for energy companies. Prior to joining Prudential Securities Incorporated, Mr. Shepherd served as an investment banker with Stephens Inc. from 1990 to June 1998 and with Merrill Lynch Capital Markets from 1986 to 1990. Prior to joining Merrill Lynch Capital Markets, Mr. Shepherd worked for over four years as a petroleum engineer for both Amoco Production Company and the Railroad Commission of Texas. He has a B.S. in Petroleum Engineering and an MBA, both from the University of Texas at Austin. David T. Brigham joined us in 1992 and has served as a Director since May 2003, and as Executive Vice President--Land and Administration since June 2002. Mr. Brigham served as Senior Vice President--Land and Administration from March 2001 to June 2002, Vice President--Land and Administration and Corporate Secretary from February 1998 to March 2001, and as Vice President--Land and Legal from 1994 until February 1998 and as Corporate Secretary from March 2001 to September 2002. From 1987 to 1992, Mr. Brigham was an oil and gas attorney with Worsham, Forsythe, Sampels & Wooldridge. Before attending law school, Mr. Brigham was a landman for Wagner & Brown Oil and Gas Producers, an independent oil and gas exploration and production company. Mr. Brigham holds a B.B.A. in Petroleum Land Management from the University of Texas and a J.D. from Texas Tech School of Law. Mr. Brigham is the brother of Ben M. Brigham, Chief Executive Officer, President and Chairman of the Board. A. Lance Langford joined us in 1995 as Manager of Operations and served as Vice President--Operations from January 1997 to March 2001, and has served as Senior Vice President--Operations since March 2001. From 1987 to 1995, Mr. Langford served in various engineering capacities with Meridian Oil Inc., handling a variety of reservoir, production and drilling responsibilities. Mr. Langford holds a B.S. in Petroleum Engineering from Texas Tech University. 61 Jeffery E. Larson joined us in 1997 and was Vice President--Exploration from August 1999 to March 2001, and has been Senior Vice President--Exploration since March 2001. Prior to joining us, Mr. Larson was an explorationist in the Offshore Department of Burlington Resources, a large independent exploration company, where he was responsible for generating exploration and development drilling opportunities. Mr. Larson worked at Burlington from 1990 to 1997 in various roles of increasing responsibility within its exploration department. Prior to Burlington, Mr. Larson spent five years at Exxon as a Production Geologist and Research Scientist. He has a B.S. in Earth Science from St. Cloud State University in Minnesota and a M.S. in Geology from the University of Montana. Harold D. Carter has served as a Director of and consultant to the Company since 1992. Mr. Carter has more than 40 years experience in the oil and gas industry and has been an independent consultant since 1990. Prior to consulting, Mr. Carter served as Executive Vice President of Pacific Enterprises Oil Company (USA). Before that, Mr. Carter was associated for 20 years with Sabine Corporation, ultimately serving as President and Chief Operating Officer from 1986 to 1989. Mr. Carter consults for Associated Energy Managers, Inc. with respect to its Energy Income Fund, L.P. and is a director of Energy Partners Ltd., a publicly traded oil and gas company, and Longview Production Company, a private company. Mr. Carter has a B.B.A. in Petroleum Land Management from the University of Texas and has completed the Program for Management Development at the Harvard University Business School. Stephen C. Hurley has served as a Director of the Company since December 2002. Mr. Hurley is an Executive Vice President of Hunt Oil Company and has served in that capacity since August 2001. Prior to joining Hunt Oil, Mr. Hurley served as Executive Vice President, Chief Operating Officer and a member of the board of directors for Chieftain International, Inc. from September 1995 to August 2001. Mr. Hurley holds a Masters of Science degree in Geology from the University of Arkansas and an advanced degree in business studies from Harvard University. Stephen P. Reynolds has served as a Director of the Company since 1996. Mr. Reynolds served as a special advisor to General Atlantic Partners, LLC and was associated with General Atlantic or its predecessor entities from April 1980 to 2000. Mr. Reynolds is also a limited partner of GAP-Brigham and GAP Coinvestment. He served as President of GAP III Investors, Inc., the general partner of GAP III, and as the general partner of GAP-Brigham until February 2003. Mr. Reynolds holds a B.A. in Economics from Amherst College and a Masters Degree in Accounting from New York University. Hobart A. Smith has served as a director of the Company since December 2002. Mr. Smith has been associated with Smith International, Inc. and its affiliates and predecessors, a products and services supplier to the oil and gas and petrochemical industries, in various capacities since 1965, including Vice President of Customer Relations, Assistant to the President and Vice President of Marketing. Since 1992, Mr. Smith has served as a consultant to Smith International, primarily in Customer Relations and Industry Affairs. Mr. Smith is also a director of Harken Energy Corp., a publicly traded oil and gas company. Mr. Smith has a degree in Business Administration from Claremont-McKenna College. Steven A. Webster has served as a Director of the Company since November 2000. Mr. Webster is the Chairman of Global Energy Partners, a specialty group within CSFB Private Equity that makes investments in energy companies, and has served in that capacity since 2000. From 1998 to 1999, Mr. Webster served as Chief Executive Officer and President of R&B Falcon Corporation, and from 1988 to 1998, Mr. Webster served as Chairman and Chief Executive Officer of Falcon Drilling Corporation, both offshore drilling contractors. Mr. Webster is on the board of directors of Seabulk International, Inc., a publicly traded offshore energy support, transportation and towing company, Carrizo Oil & Gas, Inc., a publicly traded oil and gas exploration and production company, Grey Wolf Inc., a publicly traded land drilling contractor, Camden Property Trust, a publicly traded real estate investment trust, Crown Resources Corporation, a publicly traded precious metals exploration company, and Geokinetics, Inc., a public traded geophysical services provider. Mr. Webster is also on the board of directors of Basic Energy Services, Inc., Consort Group, Ltd., Copano Energy Holdings, LLC, Encore Bancshares, Inc., Frontier Drilling, ASA, Laredo Energy, L.P and Medicine Bow Energy Corp., all privately held companies. In 62 addition, Mr. Webster serves as Chairman of Carrizo Oil & Gas, Crown Resources and Basic Energy. Mr. Webster is the founder and an original shareholder of Falcon Drilling Company, Inc., a predecessor to Transocean, Inc., and is a co-founder and original shareholder of Carrizo Oil & Gas, Inc. Mr. Webster holds a B.S.I.M. from Purdue University and an M.B.A. from Harvard Business School. R. Graham Whaling has served as a Director of the Company since June 2001. Mr. Whaling is currently Chairman, CEO and a director of Laredo Energy, L.P. and has spent his entire career in the energy industry, as a petroleum engineer, an energy investment banker, a chief financial officer and a chief executive officer of energy companies. From May 1999 to May 2001, Mr. Whaling was a Managing Director with a specialty group within CSFB Private Equity that makes investments in energy companies. From May 1998 until May 1999, Mr. Whaling was a Managing Director with Petrie Parkman & Co. Prior to that, Mr. Whaling was the Chief Financial Officer for Santa Fe Energy where he managed the initial public offering and the spin-off of Santa Fe's western division, a company called Monterey Resources. He was its Chairman and Chief Executive Officer until it was acquired by Texaco in 1997. Prior to 1997, Mr. Whaling spent seven years as an investment banker focusing on the energy industry with Lazard Freres & Co. and CS First Boston. Mr. Whaling worked as a petroleum engineer for nine years in the beginning of his career primarily with Ryder Scott Company, an oil and gas-consulting firm. Mr. Whaling is also a director of Basic Energy Services, Inc., a privately held institution. 63 DESCRIPTION OF CAPITAL STOCK The description of our capital stock below is only a summary and is not intended to be complete. For a complete description, please read our certificate of incorporation and bylaws, which have been filed with the Securities and Exchange Commission. GENERAL Our authorized capital stock consists of 50,000,000 shares of common stock, par value $0.01 per share, and 10,000,000 shares of preferred stock, par value $0.01 per share. Pursuant to Certificates of Designations which have been filed with the Secretary of State of Delaware, 2,250,000 shares of our preferred stock have been designated Series A preferred stock and 1,000,000 shares of our preferred stock have been designated Series B preferred stock. As of September 17, 2003, 20,569,452 shares of common stock, 1,835,860 shares of Series A preferred stock and 521,313 shares of Series B preferred stock were outstanding. COMMON STOCK Subject to the preferential rights of any outstanding series of preferred stock, the holders of our common stock are entitled to one vote for each share held of record on all matters submitted to the stockholders. Our certificate of incorporation does not allow the stockholders to take action by written consent with less than unanimous consent. The holders of our common stock are entitled to participate fully in dividends, if any are declared by the Board of Directors out of legally available funds, and in the distribution of assets in the event of liquidation. However, the payment of any dividends and the distribution of assets to holders of our common stock will be subject to any prior rights of outstanding shares of our preferred stock. We have never paid cash dividends on our common stock. The holders of our common stock have no preemptive or conversion rights, redemption rights, or sinking fund provisions. Our common stock is not assessable. PREFERRED STOCK Our Board of Directors may establish, in addition to the Series A and Series B preferred stock, without stockholder approval, one or more classes or series of our preferred stock having the number of shares, designations, relative voting rights, dividend rates, liquidation and other rights, preferences, and limitations that our Board of Directors may designate. The issuance of additional shares of our preferred stock could adversely affect the voting power of the holders of our common stock and restrict their rights to receive payments upon our liquidation. It could also have the effect of delaying, deferring or preventing a change in control of us. Series A and Series B Preferred Stock The Series A and Series B preferred stock have a stated value of $20.00 per share and bear dividends at a rate of 6% per annum if paid in cash or 8% per annum if paid-in-kind through the issuance of additional preferred stock in lieu of cash. At our option, up to 100% of the dividend payments on both the Series A preferred stock (through November 2005) and the Series B preferred stock (through December 2007) can be satisfied through the issuance of paid-in-kind dividends. The Series A preferred stock has a ten-year maturity and is redeemable at our option at 100% or 101% of the stated value per share (depending on certain conditions) at any time prior to maturity in November 2010. The Series B preferred stock has a ten-year maturity and is redeemable at our option at 100% or 101% of the stated value per share (depending on certain conditions) at any time after December 2007 64 and until maturity in December 2012. At maturity, the Series A and Series B preferred stock must be redeemed at 100% of the stated value per share and are not convertible. In the event of a change of control, we must offer to purchase the outstanding Series A and Series B preferred stock at 101% of the stated value plus all accrued and unpaid dividends. In the event of any liquidation, dissolution or winding up, the holders of the preferred stock shall receive a distribution of $20.00 per share plus any accrued and unpaid dividends before any holders of common stock or junior preferred stock receive any dividends. In the event we fail to comply with certain requirements such as failing to pay accrued dividends on time or failing to pay the applicable price for optional (whether or not deemed) or mandatory redemption, the dividend rate will be increased 1% per annum until the event of noncompliance is remedied. The holders of our Series A preferred stock have the right to nominate for election one member to our Board of Directors so long as such holders own at least 10% of the outstanding shares of Series A preferred stock or at least 5% of the outstanding shares of our common stock. The vote of the holders of 75% of the shares of Series A preferred stock is required for us to issue additional shares of Series A preferred stock (except for permitted issuances), the authorization, creation or issuance of any parity security (except for permitted issuances) or the amendment, alteration or repeal of any of the provisions of the Certificate of Incorporation which would adversely affect any right, preference, privilege or voting power of shares of Series A preferred stock. The vote of the holders of 75% of the shares of Series B preferred stock is required for us to issue additional shares of Series B preferred stock (except for permitted issuances), the authorization, creation or issuance of any parity security (except for permitted issuances) or the amendment, alteration or repeal of any of the provisions of the Certificate of Incorporation which would adversely affect any right, preference, privilege or voting power of shares of Series B preferred stock. WARRANTS Series A and Series B Preferred Stock Investor Warrants In November 2000, we issued to the purchasers of our Series A preferred stock, warrants to purchase an aggregate of 6,666,667 shares of our common stock. The warrants have an exercise price of $3.00 per share and must be exercised, if we so require, in the event that the average price of our common stock is above $5.00 per share each day for 60 consecutive trading days. In March 2001, we issued to the purchasers of our Series A preferred stock, warrants to purchase an aggregate of 2,105,263 shares of our common stock. The March 2001 warrants have an exercise price of $4.35 per share. They must be exercised, if we so require, in the event that the average price of our common stock is above $6.525 per share (150% of the exercise price of the warrants) each day for 60 consecutive trading days. In December 2002, in connection with the sale of $10 million in Series B preferred stock, we issued warrants to purchase 2,298,850 shares of our common stock. The warrants have an exercise price of $4.35 per share and must be exercised, if we so require, in the event that the price of our common stock averages at least $6.525 (150% of the exercise price of the warrants) over 60 consecutive trading days. All of the warrants are exercisable at the holders' option at any time and expire ten (10) years from the issuance date. The exercise price of all of the warrants is payable either in cash or in shares of our Series A or Series B preferred stock. If we require exercise of the warrants, and, provided the exercise price of the warrants was paid in cash, proceeds from the exercise of the warrants must be used to fund the redemption of shares of Series A or Series B preferred stock then outstanding, as applicable. Furthermore, if we require the exercise of the December 2002 warrants, and if the exercise price of the warrants is paid solely through delivery of the Series B preferred stock, we will be required to retire any additional Series B preferred stock that remains outstanding. 65 Adjustments. The exercise price and the number of shares of common stock purchasable upon exercise of the warrants are subject to adjustment upon the occurrence of certain events including (i) stock dividends and distributions, (ii) subdivisions and combinations, (iii) certain issuances of common stock, and (iv) issuances of common stock equivalents and convertible securities. In the event of any capital reorganization, reclassifications of the capital stock, any consolidation or merger involving us (where we are not the surviving company or where there is a change or distribution of our common stock), the warrants will thereupon become exercisable only for the number of shares of stock or other securities, assets, or cash to which a holder of the number of shares of our common stock purchasable (at the time of such reorganization, reclassification, consolidation, merger or sale) upon exercise of such warrants would have been entitled upon such reorganization, reclassification, consolidation, merger or sale. Registration Rights. The holders of our warrants can demand that we file a registration statement with the Securities and Exchange Commission if the holders of at least twenty-five percent (25%) of the warrants (or warrant shares) request such registration. Upon such a request, we have ten (10) days to notify all of the holders and they have thirty (30) days to request their securities be included in the registration. We are only required to effect three (3) registrations according to these procedures and, subject to certain conditions, we can defer filing any such registration statement for up to ninety (90) days. In the event we file a registration statement with the Securities and Exchange Commission (other than filing a registration statement relating to an offering to our existing security holders or employees) to register an offering of our common stock for cash, we must give written notice to the holders of our warrants within twenty (20) days of filing such registration with the Securities and Exchange Commission and offer to include the holders' warrants (or warrant shares) in such registration. If a holder desires to include his warrants (or warrant shares) in the registration, he must give notice to us within fifteen (15) days of his receipt of notice and we must then register those warrants (or warrant shares). Under certain circumstances, we could reduce the number of securities each holder intends to register on a pro rata basis to the greatest amount that would not adversely affect the distribution of such securities. Additionally, we can discontinue the registration at any time prior to the effective date. If we receive a request from the holders of 25% of the warrants (or warrant shares) to effect a registration statement on a Form S-3, and the expected offering price to the public of such registration would be equal to or greater than $2,000,000, then we must give notice to the remaining holders within ten (10) days and use our best efforts to effect such a registration. All holders that give notice within thirty (30) days of their receipt of our notice will be included in such a registration statement. We will not be required to effect a registration statement on a Form S-3 if such form is not available for such offering or if we have filed a registration statement on a Form S-3 in the preceding twelve (12) month period pursuant to a request by the holders. Subject to certain conditions, we may delay such a filing for a period of up to ninety (90) days. ANTI-TAKEOVER EFFECTS OF PROVISIONS OF OUR ARTICLES OF INCORPORATION AND BYLAWS Our articles of incorporation, as amended, and our bylaws contain provisions that might be characterized as anti-takeover provisions. These provisions may deter or render more difficult proposals to acquire control of our company, including proposals a stockholder might consider to be in his or her best interest, impede or lengthen a change in membership of the board of directors and make removal of our management more difficult. Removal of Directors; Advance Notice Provisions for Stockholder Nominations Any director may be removed from office only by the affirmative vote of a majority of the then outstanding shares entitled to vote on the matter. Any stockholder wishing to submit a nomination to the board of directors must follow the procedures outlined in our bylaws. 66 Unanimous Consent of Stockholders Required for Action by Written Consent Under our articles of incorporation, as amended, stockholder action may be taken without a meeting only by unanimous written consent of all of our stockholders. Issuance of Preferred Stock As described above, our articles of incorporation authorize the board of directors to issue preferred stock from time to time, in one or more series, and the board of directors, without further approval of the stockholders, is authorized to fix the rights, preferences, privileges and restrictions applicable to each series of preferred stock. The purpose of authorizing the board of directors to determine these rights, preferences, privileges and restrictions is to eliminate delays associated with a stockholder vote on specific issuances. The issuance of any class of preferred stock, including the outstanding shares of Series A or Series B Preferred Stock, while providing flexibility for many corporate purposes, could, among other things, adversely affect the voting power of the holders of our common stock and, under certain circumstances, make it more difficult for a third party to gain control of us. Business Combinations under Delaware law We are a Delaware corporation and are governed by Section 203 of the Delaware General Corporation Law. Section 203 prevents an interested stockholder, which is a person who owns 15% or more of our outstanding voting stock, from engaging in business combinations with us for three years following the time the person becomes an interested stockholder. These restrictions do not apply if: - before the person becomes an interested stockholder, our board of directors approves the transaction in which the person becomes an interested stockholder or the business combination; - upon completion of the transaction that results in the person becoming an interested stockholder, the interested stockholder owns at least 85% of our outstanding voting stock at the time the transaction began, excluding for purposes of determining the number of shares outstanding those shares owned by persons who are directors and also officers and employee stock plans in which employee participants do not have the right to determine confidentially whether shares hold subject to the plan will be tendered in a tender or exchange offer; or - following the transaction in which the person became an interested stockholder, the business combination is approved by our board of directors and authorized at an annual or special meeting of our stockholders, and not by written consent, by the affirmative vote of a least two-thirds of our outstanding voting stock not owned by the interested stockholder. In addition, the law does not apply to interested stockholders who became interested stockholders before our common stock was listed on the Nasdaq National Market. Delaware law defines the term "business combination" to encompass a wide variety of transactions with, or caused by, an interested stockholder, including mergers, asset sales and other transactions in which the interested stockholder receives or could receive a benefit on other than a pro rata basis with other stockholders. This law could have an anti-takeover effect with respect to transactions not approved in advance by our Board of Directors, including discouraging takeover attempts that might result in a premium over the market price for the shares of the common stock. TRANSFER AGENT AND REGISTRAR The transfer agent and registrar for our common stock is American Stock Transfer and Trust Company. 67 UNDERWRITING We and the selling stockholders have entered into an underwriting agreement with the underwriters named below. CIBC World Markets Corp., Raymond James & Associates, Inc., and Johnson Rice & Company L.L.C. are acting as representatives of the underwriters. The underwriting agreement provides for the purchase of a specific number of shares of common stock by each of the underwriters. The underwriters' obligations are several, which means that each underwriter is required to purchase a specified number of shares, but is not responsible for the commitment of any other underwriter to purchase shares. Subject to the terms and conditions of the underwriting agreement, each underwriter has severally agreed to purchase the number of shares of common stock set forth opposite its name below:
UNDERWRITER NUMBER OF SHARES - ----------- ---------------- CIBC World Markets Corp. ................................... 3,250,000 Raymond James & Associates, Inc. ........................... 3,250,000 Johnson Rice & Company L.L.C. .............................. 1,625,000 First Albany Corp. ......................................... 125,000 Hibernia Southcoast Capital................................. 125,000 Huberman Financial, Inc. ................................... 125,000 Petrie Parkman & Co. ....................................... 125,000 Sanders Morris Harris....................................... 125,000 SG Cowen Securities Corporation............................. 125,000 Sterne, Agee & Leach, Inc. ................................. 125,000 --------- Total..................................................... 9,000,000 =========
The underwriters have agreed to purchase all of the shares offered by this prospectus (other than those covered by the over-allotment option described below) if any are purchased. Under the underwriting agreement, if an underwriter defaults in its commitment to purchase shares, the commitments of non- defaulting underwriters may be increased or the underwriting agreement may be terminated, depending on the circumstances. The shares should be ready for delivery on or about September 22, 2003, against payment in immediately available funds. The underwriters are offering the shares subject to various conditions and may reject all or part of any order. The representatives have advised us and the selling stockholders that the underwriters propose to offer the shares directly to the public at the public offering price that appears on the cover page of this prospectus. In addition, the representatives may offer some of the shares to other securities dealers at such price less a concession of $0.2036 per share. The underwriters may also allow, and such dealers may reallow, a concession not in excess of $0.10 per share to other dealers. After the shares are released for sale to the public, the representatives may change the offering price and other selling terms at various times. We and some of the selling stockholders have granted the underwriters an over-allotment option, exercisable for up to 30 days after the date of this prospectus, which permits the underwriters to purchase a maximum of 1,350,000 additional shares (384,090 from us and 965,910 from the selling stockholders) to cover over-allotments. If the underwriters exercise all or part of this option, they will purchase shares covered by the option at the public offering price that appears on the cover page of this prospectus, less the underwriting discount. If this option is exercised in full, the total price to public will be $60,547,500. The total proceeds to us will be $40,605,111 and the total proceeds to the selling stockholders will be $16,309,539. The underwriters have severally agreed that, to the extent the over-allotment option is exercised, they will each purchase a number of additional shares proportionate to the underwriter's initial amount reflected in the foregoing table. 68 The following table provides information regarding the amount of the discount to be paid to the underwriters by us and the selling stockholders:
TOTAL WITHOUT TOTAL WITH EXERCISE OF FULL EXERCISE OF PER SHARE OVER-ALLOTMENT OPTION OVER-ALLOTMENT OPTION --------- --------------------- --------------------- Brigham Exploration Company.......... $0.351 $2,457,000 $2,591,816 Selling Stockholders................. 0.351 702,000 1,041,034 ---------- ---------- Total......................................... $3,159,000 $3,632,850 ========== ==========
We estimate that the total expenses of the offering, excluding the underwriting discount, will be approximately $500,000. We and the selling stockholders have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933. We, our officers and directors and the selling stockholders have agreed to a 90-day "lock up" with respect to all of the shares of common stock that they beneficially own, including securities that are convertible into shares of common stock and securities that are exchangeable or exercisable for shares of common stock. This means that, subject to certain exceptions, for a period of 90 days following the date of this prospectus, we and such persons may not offer, sell, pledge or otherwise dispose of these securities without the prior written consent of CIBC World Markets Corp. Other than in the United States, no action has been taken by us, the selling stockholders or the underwriters that would permit a public offering of the shares of common stock offered by this prospectus in any jurisdiction where action for that purpose is required. The shares of common stock offered by this prospectus may not be offered or sold, directly or indirectly, nor may this prospectus or any other offering material or advertisements in connection with the offer and sale of any such shares of common stock be distributed or published in any jurisdiction, except under circumstances that will result in compliance with the applicable rules and regulations of that jurisdiction. Persons into whose possession this prospectus comes are advised to inform themselves about and to observe any restrictions relating to the offering and the distribution of this prospectus. This prospectus does not constitute an offer to sell or a solicitation of an offer to buy any shares of common stock offered by this prospectus in any jurisdiction in which such an offer or a solicitation is unlawful. Our common stock is traded on the Nasdaq National Market under the symbol "BEXP." Rules of the Securities and Exchange Commission may limit the ability of the underwriters to bid for or purchase shares before the distribution of the shares is completed. However, the underwriters may engage in the following activities in accordance with the rules: - Stabilizing transactions -- The representatives may make bids or purchases for the purpose of pegging, fixing or maintaining the price of the shares, so long as stabilizing bids do not exceed a specified maximum. - Over-allotments and syndicate covering transactions -- The underwriters may sell more shares of common stock in connection with this offering than the number of shares that they have committed to purchase. This over-allotment creates a short position for the underwriters. This short sales position may involve either "covered" short sales or "naked" short sales. Covered short sales are short sales made in an amount not greater than the underwriters' over-allotment option to purchase additional shares in this offering described above. The underwriters may close out any covered short position either by exercising their over-allotment option or by purchasing shares in the open market. To determine how they will close the covered short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market, as compared to the price at which they may purchase shares through the over-allotment option. Naked short sales are short sales in excess of the over-allotment option. The underwriters must close out any naked short 69 position by purchasing shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that, in the open market after pricing, there may be downward pressure on the price of the shares that could adversely affect investors who purchase shares in this offering. - Penalty bids -- If the representatives purchase shares in the open market in a stabilizing transaction or syndicate covering transaction, they may reclaim a selling concession from the underwriters and selling group members who sold those shares as part of this offering. - Passive market making -- Market makers in the shares who are underwriters or prospective underwriters may make bids for or purchases of shares, subject to limitations, until the time, if ever, at which a stabilizing bid is made. Similar to other purchase transactions, the underwriters' purchases to cover the syndicate short sales or to stabilize the market price of our common stock may have the effect of raising or maintaining the market price of our common stock or preventing or mitigating a decline in the market price of our common stock. As a result, the price of the shares of our common stock may be higher than the price that might otherwise exist in the open market. The imposition of a penalty bid might also have an effect on the price of the shares if it discourages resale of the shares. Neither we nor the underwriters make any representation or prediction as to the effect that the transactions described above may have on the price of the shares. These transactions may occur on the Nasdaq National Market or otherwise. If such transactions are commenced, they may be discontinued without notice at any time. CIBC World Markets Corp. has in the past provided, and may in the future from time to time provide, investment banking and general financing and banking services to us and our affiliates for which they have in the past received, and may in the future receive, customary fees and reimbursement for expenses. SG Cowen Securities Corporation is an affiliate of Societe Generale, which is a selling stockholder and a lender under our senior credit facility. See "Selling Stockholders." The underwriters have an agreement with Yahoo Net Roadshow to host the roadshow on the internet for qualified investors only, and they will follow the guidance set forth by the staff of the SEC regarding such roadshows. The preliminary prospectus will be posted on the roadshow website for informational purposes only. We do not intend to engage in any other electronic distribution of the prospectus. LEGAL MATTERS The validity of the shares of common stock being offered hereby and certain other legal matters in connection with this offering are being passed upon for us by Thompson & Knight L.L.P., Dallas, Texas. Certain legal matters in connection with this offering will be passed upon for the underwriters by Vinson & Elkins L.L.P., Houston, Texas. EXPERTS The consolidated financial statements as of December 31, 2002 and 2001 and for each of the years in the three year period ended December 31, 2002, included in this prospectus have been so included in reliance upon the report of PricewaterhouseCoopers LLP, independent accountants, given on the authority of said firm as experts in auditing and accounting. Cawley, Gillespie & Associates, Inc., independent petroleum consultants, estimated our reserves as of December 31, 2002, 2001 and 2000 and the present value of the estimated future net revenues from those estimated reserves included in this document. These estimates are included in reliance upon their reports given upon their authority as experts on the matters covered by the summary reserve report. 70 WHERE YOU CAN FIND MORE INFORMATION We have filed a registration statement on Form S-2 with the Securities and Exchange Commission in connection with this offering. We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission. You may read and copy the registration statement and any other documents we have filed at the Securities and Exchange Commission's Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the Securities and Exchange Commission at 1-800-SEC-0330 for further information on the Public Reference Room. Our Securities and Exchange Commission filings are also available to the public at the Securities and Exchange Commission's Internet site at http://www.sec.gov. This prospectus is part of the registration statement and does not contain all of the information included in the registration statement. Whenever a reference is made in this prospectus to any of our contracts or other documents, the reference may not be complete and, for a copy of the contract or document, you should refer to the exhibits that are part of the registration statement. The Securities and Exchange Commission allows us to "incorporate by reference" into this prospectus the information we file with it, which means that we can disclose important information to you by referring you to those documents. Information incorporated by reference is part of this prospectus, except for any information that is superseded by information included directly in this prospectus. Later information filed with the Securities and Exchange Commission will update and supersede this information. We incorporate by reference the documents listed below. - Current Report on Form 8-K filed March 6, 2003; - Annual Report on Form 10-K for the year ended December 31, 2002 filed March 31, 2003, as amended by Form 10-K/A filed June 10, 2003 and including the information incorporated therein by reference to Schedule 14A filed May 27, 2003; - Current Report on Form 8-K filed April 1, 2003; - Current Report on Form 8-K filed May 8, 2003; - Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 filed May 15, 2003, as amended by Form 10-Q/A filed June 12, 2003; - Current Report on Form 8-K filed August 12, 2003; and - Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 filed August 14, 2003. You may request a copy of these filings, at no cost, by contacting us at: Brigham Exploration Company 6300 Bridgepoint Parkway Building Two, Suite 500 Austin, Texas 78730 Attention: Investor Relations (512) 427-3300 71 GLOSSARY OF CERTAIN OIL AND GAS TERMS The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry and in this report. The definitions of proved developed reserves, proved reserves and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. 3-D seismic. The method by which a three dimensional image of the earth's subsurface is created through the interpretation of reflection seismic data collected over surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, development and production. All-Sources Finding Costs. The cost associated with acquiring and developing proved oil and natural gas reserves determined on an Mcfe basis by dividing total net capital expenditures, excluding proceeds from the sale of proved oil and gas reserves, associated with drilling and completing of wells, acquiring acreage and geological and geophysical work during the identified period, by the estimated proved reserve additions from exploration and development activities, acquisitions of proved reserves and revisions of previous estimates during the same time period. Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to oil or other liquid hydrocarbons. Bcfe. One billion cubic feet of natural gas equivalent. In reference to natural gas, natural gas equivalents are determined using the ratio of 6 Mcf of natural gas to 1 Bbl of oil, condensate or natural gas liquids. Completion. The installation of permanent equipment for the production of oil or natural gas. Completion Rate. The number of wells on which production casing has been run for a completion attempt as a percentage of the number of wells drilled. Developed Acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production. Development Well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. Drilling Finding Costs. Total capital expenditures (including the costs to drill, plug and abandon dry holes) associated with the drilling and completing of wells during the identified period divided by the estimated proved reserve additions from exploration and development activities, with revisions of previous estimates during the same time period. Dry Well. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion of an oil or gas well. Exploratory Well. A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. Fault. A break in the rocks along which there has been movement of one side relative to the other side. Fault Block. A body of rocks bounded by one or more faults. Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which we have a working interest. Lease Operating Expenses. The expenses, usually recurring, which pay for operating the wells and equipment on a producing lease. 72 MBbl. One thousand barrels of oil or other liquid hydrocarbons. Mcf. One thousand cubic feet of natural gas. MMBbl. One million barrels of oil or other liquid hydrocarbons. Mcfe. One thousand cubic feet of natural gas equivalents. MMBtu. One million Btu, or British Thermal Units. One British Thermal Unit is the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. MMcf. One million cubic feet of natural gas. MMcfe. One million cubic feet of natural gas equivalents. MMcfe/d. MMcfe per day. Net Acres or Net Wells. Gross acres or wells multiplied, in each case, by the percentage working interest we own. Net Production. Production that we own less royalties and production due others. Oil. Crude oil, condensate or other liquid hydrocarbons. Operator. The individual or company responsible for the exploration, development, and production of an oil or gas well or lease. Pay. The vertical thickness of an oil and gas producing zone. Pay can be measured as either gross pay, including non-productive zones or net pay, including only zones that appear to be productive based upon logs and test data. Proved Developed Reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved Reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved Undeveloped Reserves. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserve Replacement Rate. Estimated net reserves added to proved reserves through extensions, discoveries and revisions, divided by production for the period. Royalty. An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner's royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. SEC PV-10% or Securities and Exchange Commission Present Value of Future Net Revenues. The pre-tax present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. Spud. Start drilling a new well (or restart). 73 Standardized Measure. The after-tax present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. Trend. A geographical area that has been known to contain certain types of combinations of reservoir rock, sealing rock and trap types containing commercial amounts of hydrocarbons. Working Interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. 74 INDEX TO FINANCIAL STATEMENTS Report of Independent Accountants........................... F-2 Consolidated Balance Sheets as of December 31, 2002 and 2001...................................................... F-3 Consolidated Statements of Operations for the Years Ended December 31, 2002, 2001, and 2000......................... F-4 Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2002, 2001, and 2000............. F-5 Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001, and 2000......................... F-7 Notes to the Consolidated Financial Statements.............. F-8 Consolidated Balance Sheets as of June 30, 2003 and December 31, 2002.................................................. F-36 Consolidated Statements of Operations for the three and six months ended June 30, 2003 and 2002....................... F-37 Consolidated Statements of Stockholders' Equity for the six months ended June 30, 2003................................ F-38 Consolidated Statements of Cash Flows for the six months ended June 30, 2003 and 2002.............................. F-39 Notes to the Consolidated Financial Statements.............. F-40
F-1 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Stockholders of Brigham Exploration Company In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of stockholders' equity and of cash flows present fairly, in all material respects, the financial position of Brigham Exploration Company (the "Company") and its subsidiaries at December 31, 2002 and 2001, and the results of their operations and their cash flows for the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As discussed in Note 2 to the consolidated financial statements, the Company changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001. As discussed in Note 10 to the consolidated financial statements, the Company has restated diluted earnings per share data for 2001. PRICEWATERHOUSECOOPERS LLP March 27, 2003 Dallas, Texas F-2 BRIGHAM EXPLORATION COMPANY CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT PER SHARE DATA)
DECEMBER 31, --------------------- 2002 2001 --------- -------- ASSETS Current assets: Cash and cash equivalents................................. $ 15,318 $ 5,112 Accounts receivable....................................... 11,361 9,113 Other current assets...................................... 6,643 2,410 --------- -------- Total current assets.................................. 33,322 16,635 --------- -------- Oil and natural gas properties, using the full cost method of accounting Unproved.................................................. 37,403 35,908 Proved.................................................... 229,991 203,803 Accumulated depletion..................................... (102,414) (87,820) --------- -------- 164,980 151,891 --------- -------- Other property and equipment, net........................... 1,234 1,331 Deferred loan fees.......................................... 2,391 3,166 Other noncurrent assets..................................... 132 52 --------- -------- $ 202,059 $173,075 ========= ======== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable.......................................... $ 14,486 $ 8,146 Royalties payable......................................... 4,508 145 Accrued drilling costs.................................... 2,727 1,969 Participant advances received............................. 1,955 158 Other current liabilities................................. 10,334 4,515 --------- -------- Total current liabilities............................. 34,010 14,933 --------- -------- Senior credit facility...................................... 60,000 75,000 Senior subordinated notes................................... 21,797 16,721 Other noncurrent liabilities................................ 186 206 Commitments and contingencies Series A Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and redemption value, 2,250,000 shares authorized, 1,765,132 and 1,630,692 shares issued and outstanding at December 31, 2002 and 2001, respectively... 19,540 16,614 Series B Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and redemption value, 1,000,000 shares authorized, 501,226 shares issued and outstanding at December 31, 2002......................................... 4,777 - 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, 20,618,161 and 17,127,650 shares issued and 19,479,979 and 16,016,113 shares outstanding at December 31, 2002 and 2001, respectively......................... 206 171 Additional paid-in capital................................ 93,436 80,466 Treasury stock, at cost; 1,138,182 and 1,111,537 shares at December 31, 2002 and 2001, respectively................ (4,282) (4,165) Unearned stock compensation............................... (212) (494) Accumulated other comprehensive (loss) income............. (3,047) 351 Accumulated deficit....................................... (24,352) (26,728) --------- -------- Total stockholders' equity............................ 61,749 49,601 --------- -------- $ 202,059 $173,075 ========= ========
The accompanying notes are an integral part of these consolidated financial statements. F-3 BRIGHAM EXPLORATION COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER SHARE DATA)
YEAR ENDED DECEMBER 31, ------------------------------- 2002 2001 2000 ------- --------- ------- Revenues: Oil and natural gas sales................................. $35,100 $32,293 $19,143 Other revenue............................................. 76 255 69 ------- ------- ------- 35,176 32,548 19,212 ------- ------- ------- Costs and expenses: Lease operating........................................... 3,759 3,486 2,139 Production taxes.......................................... 1,977 1,511 1,786 General and administrative................................ 4,971 3,638 3,100 Depletion of oil and natural gas properties............... 14,594 13,211 7,920 Depreciation and amortization............................. 440 677 620 ------- ------- ------- 25,741 22,523 15,565 ------- ------- ------- Operating income....................................... 9,435 10,025 3,647 ------- ------- ------- Other income (expense): Interest income........................................... 119 264 108 Interest expense.......................................... (6,238) (6,681) (9,906) Debt conversion expense................................... (630) - - Gain on refinancing of senior subordinated notes.......... - - 32,267 Other income (expense).................................... (310) 8,080 (9,504) ------- ------- ------- (7,059) 1,663 12,965 ------- ------- ------- Income before income taxes.................................. 2,376 11,688 16,612 Income taxes................................................ - - - ------- ------- ------- Net income.................................................. 2,376 11,688 16,612 Less accretion and dividends on redeemable preferred stock..................................................... 2,952 2,450 275 ------- ------- ------- Net income (loss) available to common stockholders.......... $ (576) $ 9,238 $16,337 ======= ======= ======= Net income (loss) per share available to common stockholders: Basic..................................................... $ (0.04) $ 0.58 $ 1.01 ======= ======= ======= Restated-- Note 10 ------- Diluted................................................... $ (0.04) $ 0.44 $ 1.01 ======= ======= =======
The accompanying notes are an integral part of these consolidated financial statements. F-4 BRIGHAM EXPLORATION COMPANY CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (IN THOUSANDS)
ACCUMULATED COMMON STOCK ADDITIONAL UNEARNED OTHER TOTAL ---------------- PAID IN TREASURY STOCK COMPREHENSIVE ACCUMULATED STOCKHOLDERS' SHARES AMOUNTS CAPITAL STOCK COMPENSATION INCOME DEFICIT EQUITY ------ ------- ---------- -------- ------------ ------------- ----------- ------------- Balance, December 31, 1999.................... 14,518 $145 $64,171 $ - $ (290) $ - $(55,028) $ 8,998 Net income................ - - - - - - 16,612 16,612 Exercise of employee stock options................. 8 - 19 - - - - 19 Issuance of common stock................... 2,195 22 4,166 - - - - 4,188 Issuance of restricted stock................... 309 3 1,137 - (1,140) - - - Issuance of stock options................. - - 185 - (185) - - - Forfeiture of stock options................. - - (60) - 10 - - (50) Issuance of warrants...... - - 13,910 - - - - 13,910 Cancellation of warrants................ - - (4,979) - - - - (4,979) Purchase of treasury stock................... - - - (3,950) - - - (3,950) In kind dividends on Series A mandatorily redeemable Preferred Stock................... - - (267) - - - - (267) Accretion on Series A mandatorily redeemable Preferred Stock......... - - (8) - - - - (8) ------ ---- ------- ------- ------- -------- -------- -------- Amortization of unearned stock compensation...... - - - - 284 - - 284 Balance, December 31, 2000.................... 17,030 170 78,274 (3,950) (1,321) - (38,416) 34,757 Comprehensive income (loss): Net income.............. - - - - - - 11,688 11,688 Deferred hedge gains and losses, net of tax Cumulative effect (loss) on adoption of SFAS 133......... - - - - - (11,800) - (11,800) Unrealized gain on cash flow hedges.... - - - - - 12,151 - 12,151 -------- Comprehensive income........... 12,039 -------- Exercise of employee stock options................. 97 1 251 - - - - 252 Forfeitures of employee stock options........... - - (115) - 31 - - (84) Forfeitures of restricted stock................... - - 6 (148) 121 - - (21) Purchases of restricted stock................... - - - (67) - - - (67) Issuance of warrants...... - - 4,500 - - - - 4,500 In kind dividends on Series A mandatorily redeemable Preferred Stock................... - - (2,347) - - - - (2,347) Accretion on Series A mandatorily redeemable Preferred Stock......... - - (103) - - - - (103) Amortization of unearned stock compensation...... - - - - 675 - - 675 ------ ---- ------- ------- ------- -------- -------- -------- Balance, December 31, 2001.................... 17,127 171 80,466 (4,165) (494) 351 (26,728) 49,601
F-5 BRIGHAM EXPLORATION COMPANY CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY--(CONTINUED) (IN THOUSANDS)
ACCUMULATED COMMON STOCK ADDITIONAL UNEARNED OTHER TOTAL ---------------- PAID IN TREASURY STOCK COMPREHENSIVE ACCUMULATED STOCKHOLDERS' SHARES AMOUNTS CAPITAL STOCK COMPENSATION INCOME DEFICIT EQUITY ------ ------- ---------- -------- ------------ ------------- ----------- ------------- Balance, December 31, 2001.................... 17,127 171 80,466 (4,165) (494) 351 (26,728) 49,601 Comprehensive income (loss): Net income.............. - - - - - - 2,376 2,376 Deferred hedge gains and losses, net of tax Unrealized loss on cash flow hedges.... - - - - - (3,519) - (3,519) Net losses included in net income.......... - - - - - 121 - 121 -------- Comprehensive income (loss)........... (1,022) -------- Exercise of employee stock options................. 133 1 295 - - - - 296 Expiration of employee stock options........... - - (46) - - - - (46) Forfeitures of restricted stock................... - - (1) (41) 15 - - (27) Revision of terms of employee stock options................. - - 596 - - - - 596 Repurchases of common stock................... - - - (76) - - - (76) Issuance of warrants...... - - 4,605 - - - - 4,605 Warrants exercised for common stock............ 244 2 623 - - - - 625 Common stock issued in exchange for warrants and convertible debt rights.................. 550 6 (56) - - - - (50) Debt converted to common stock................... 2,564 26 9,906 - - - - 9,932 In kind dividends on Series A mandatorily redeemable preferred stock................... - - (2,689) - - - - (2,689) Accretion on Series A mandatorily redeemable preferred stock......... - - (238) - - - - (238) In kind dividends on Series B mandatorily redeemable preferred stock................... - - (24) - - - - (24) Accretion on Series B mandatorily redeemable preferred stock......... - - (1) - - - - (1) Amortization of unearned stock compensation...... - - - - 267 - - 267 ------ ---- ------- ------- ------- -------- -------- -------- Balance, December 31, 2002.................... 20,618 $206 $93,436 $(4,282) $ (212) $ (3,047) $(24,352) $ 61,749 ====== ==== ======= ======= ======= ======== ======== ========
The accompanying notes are an integral part of these consolidated financial statements. F-6 BRIGHAM EXPLORATION COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
YEAR ENDED DECEMBER 31, -------------------------------- 2002 2001 2000 -------- -------- -------- Cash flows from operating activities: Net income................................................ $ 2,376 $ 11,688 $ 16,612 Adjustments to reconcile net income to cash provided (used) by operating activities: Depletion of oil and natural gas properties............ 14,594 13,211 7,920 Depreciation and amortization.......................... 440 677 620 Interest paid through issuance of additional senior subordinated notes................................... 1,076 721 4,575 Amortization of deferred loan fees..................... 1,191 1,372 1,283 Amortization of discount on senior subordinated notes................................................ - - 673 Amortization of deferred loss on derivative instruments.......................................... - - 280 Market value adjustment for derivative instruments..... (263) (9,666) 8,885 Gain on refinancing of senior subordinated notes....... - - (32,267) Loss on investment in Brigham-Duke LLC................. - 94 - Stock option compensation expense...................... 596 - - Changes in operating assets and liabilities: Accounts receivable.................................. (2,248) 164 (4,332) Other current assets................................. (4,534) (1,550) (262) Accounts and royalties payable....................... 10,703 (920) (7,290) Other current liabilities............................ 5,060 3,188 (1,354) Noncurrent assets.................................... 2 13 54 Noncurrent liabilities............................... (20) (70) (32) -------- -------- -------- Net cash provided (used) by operating activities...................................... 28,973 18,922 (4,635) -------- -------- -------- Cash flows from investing activities: Additions to oil and natural gas properties............... (27,696) (34,532) (28,910) Proceeds from sale of oil and natural gas properties...... 871 397 3,938 Additions to other property and equipment................. (249) (396) (162) (Increase) decrease in drilling advances paid............. (132) 960 (937) -------- -------- -------- Net cash used by investing activities............. (27,206) (33,571) (26,071) -------- -------- -------- Cash flows from financing activities: Proceeds from issuance of common stock.................... - - 4,188 Proceeds from issuance of preferred stock and warrants.... 9,356 9,838 20,060 Proceeds from issuance of senior subordinated notes and warrants............................................... 4,000 9,000 7,000 Proceeds from exercise of employee stock options.......... 296 252 19 Proceeds from exercise of warrants........................ 625 - - Fees paid due to common stock exchange for warrants....... (50) - - Repurchases of common stock............................... (76) (67) - Increase in senior credit facility........................ - - 19,000 Repayment of senior credit facility....................... (5,000) - - Principal payments on senior subordinated notes........... - - (20,354) Principal payments on capital lease obligations........... (28) (99) (210) Deferred loan fees paid................................... (684) - (902) -------- -------- -------- Net cash provided by financing activities......... 8,439 18,924 28,801 -------- -------- -------- Net increase (decrease) in cash and cash equivalents........ 10,206 4,275 (1,905) Cash and cash equivalents, beginning of year................ 5,112 837 2,742 -------- -------- -------- Cash and cash equivalents, end of year...................... $ 15,318 $ 5,112 $ 837 ======== ======== ========
The accompanying notes are an integral part of these consolidated financial statements. F-7 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND NATURE OF OPERATIONS Brigham Exploration Company is a Delaware corporation formed on February 25, 1997 for the purpose of exchanging its common stock for the common stock of Brigham, Inc. and the partnership interests of Brigham Oil & Gas, L.P. (the "Partnership"). Hereinafter, Brigham Exploration Company and the Partnership are collectively referred to as "Brigham." Brigham, Inc. is a Nevada corporation whose only asset is its ownership interest in the Partnership. The Partnership was formed in May 1992 to explore and develop onshore domestic oil and natural gas properties using 3-D seismic imaging and other advanced technologies. Since its inception, the Partnership has focused its exploration and development of oil and natural gas properties primarily in West Texas, the Anadarko Basin and the onshore Gulf Coast. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates relate to proved oil and natural gas reserve volumes and the future development costs as well as estimates relating to certain oil and natural gas revenues and expenses. Actual results may differ from those estimates. Principles of Consolidation The accompanying financial statements include the accounts of Brigham and its wholly owned subsidiaries, and its proportionate share of assets, liabilities and income and expenses of the limited partnerships in which Brigham, or any of its subsidiaries has a participating interest. All significant intercompany accounts and transactions have been eliminated. Cash and Cash Equivalents Brigham considers all highly liquid financial instruments with an original maturity of three months or less to be cash equivalents. Property and Equipment Brigham uses the full cost method of accounting for oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including payroll, other internal costs, and interest incurred for the purpose of finding oil and natural gas reserves, are capitalized. Internal costs capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to production, general corporate overhead or similar activities. Costs associated with production and general corporate activities are expensed in the period incurred. Proceeds from the sale of oil and natural gas properties are applied to reduce the capitalized costs of oil and natural gas properties unless the sale would significantly alter the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized. Capitalized costs associated with impaired properties and capitalized costs related to properties having proved reserves, plus the estimated costs of future development, dismantlement, restoration and F-8 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) abandonment costs, net of estimated salvage values, are amortized using the unit-of-production method based on proved reserves. Capitalized costs of oil and natural gas properties, net of accumulated amortization, are limited to the total of estimated future net cash flows from proved oil and natural gas reserves, discounted at ten percent, plus the cost of unevaluated properties. There are many factors, including global events that may influence the production, processing, marketing and valuation of oil and natural gas. A reduction in the valuation of oil and natural gas properties resulting from declining prices or production could adversely impact depletion rates and capitalized cost limitations. Capitalized costs associated with properties that have not been evaluated through drilling or seismic analysis are excluded from the unit-of-production amortization. Exclusions are adjusted annually based on drilling results and interpretative analysis. Other property and equipment, which primarily consists of 3-D seismic interpretation workstations, is depreciated on a straight-line basis over the estimated useful lives of the assets after considering salvage value. Estimated useful lives are as follows: Furniture and fixtures...................................... 10 years Machinery and equipment..................................... 5 years 3-D seismic interpretation workstations and software........ 3 years
Betterments and major improvements that extend the useful lives are capitalized while expenditures for repairs and maintenance of a minor nature are expensed as incurred. Revenue Recognition Brigham recognizes crude oil revenues using the sales method of accounting. Under this method, Brigham recognizes revenues when oil is delivered and title transfers. Brigham recognizes natural gas revenues using the entitlements method of accounting. Under this method, revenues are recognized based on Brigham's entitled ownership percentage of sales of natural gas to purchasers. Gas imbalances occur when Brigham sells more or less than its entitled ownership percentage of total natural gas production. When Brigham receives less than its entitled share, a receivable is recorded. When Brigham receives more than its entitled share, a liability is recorded. At December 31, 2002, Brigham had recorded a receivable of approximately 1,180 MMcf and $3.7 million and a liability of approximately 1,486 MMcf and $5.7 million associated with gas imbalances. At December 31, 2001, Brigham had recorded a receivable of approximately 441 MMcf and $1.5 million and a liability of approximately 758 MMcf and $2.7 million associated with gas imbalances. Other revenues represent fees charged to third parties for use of gas gathering systems owned by Brigham. These revenues are recognized in the month the gas was produced and gathered. Derivative Instruments and Hedging Activities Brigham uses derivative instruments to manage market risks resulting from fluctuations in commodity prices of natural gas and crude oil. Brigham periodically enters into commodity contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of natural gas or crude oil without the exchange of underlying volumes. The notional amounts of these financial instruments are based on expected production from existing wells. F-9 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) Prior to January 1, 2001, in order for a derivative instrument to qualify for hedge accounting, there must have been clear correlation between the derivative instrument and the forecasted transaction. Correlation of the commodity contracts was determined by evaluating whether the contract gains and losses would substantially offset the effects of price changes on the underlying natural gas and crude oil sales volumes. To the extent that correlation existed between the contracts and the underlying natural gas and crude oil sales volumes, realized gains or losses and related cash flows arising from the contracts were recognized as a component of oil and natural gas sales in the same period as the sale of the underlying volumes. To the extent that correlation did not exist between the contracts and the underlying natural gas and crude oil sales volumes, realized gains or losses and related cash flows arising from the contracts were recognized in the period incurred as a component of other income or loss. The fair market value of any contract that did not meet the correlation test outlined above was recorded as a deferred gain or loss on the balance sheet and was adjusted to current market value at each balance sheet date with any deferred gains or losses recognized as a component of other income. On January 1, 2001, Brigham adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133), as amended. Effective with the adoption of SFAS No. 133, all derivatives are recorded on the balance sheet at fair value and changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if it is, depending on the type of hedge transaction. Brigham's derivatives consist primarily of cash flow hedge transactions in which Brigham is hedging the variability of cash flows related to a forecasted transaction. Changes in the fair value of these derivative instruments designated as cash flow hedges will be reported in other comprehensive income and will be reclassified as earnings in the periods in which earnings are impacted by the variability of the cash flows of the hedged item. The ineffective portion of the cash flow hedges will be recognized in current period earnings. Gains and losses on derivative instruments that do not qualify for hedge accounting are included in other income (expense) in the period in which they occur. The resulting cash flows from derivatives are reported as cash flows from operating activities. The adoption of SFAS No. 133 resulted in a January 1, 2001 transition adjustment to record a net of tax cumulative effect of $11.8 million to other comprehensive income to recognize the fair value (liability) of all derivative instruments that qualified for hedge accounting treatment. Gains and losses on derivatives that were previously deferred as adjustments to the carrying amount of hedged items were not adjusted. At the inception of a derivative contract, Brigham may designate the derivative as a cash flow hedge. For all derivatives designated as cash flow hedges, Brigham formally documents the relationship between the derivative contract and the hedged items, as well as the risk management objective for entering into the derivative contract. To be designated as a cash flow hedge transaction, the relationship between the derivative and the hedged items must be highly effective in achieving the offset of changes in cash flows attributable to the risk both at the inception of the derivative and on an ongoing basis. Brigham measures hedge effectiveness on a quarterly basis and hedge accounting is discontinued prospectively if it is determined that the derivative is no longer effective in offsetting changes in the cash flows of the hedged item. Gains and losses deferred in accumulated other comprehensive income related to cash flow hedge derivatives that become ineffective remain unchanged until the related production is delivered. If Brigham determines that it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument are recognized in earnings immediately. See Note 12 for a description of the derivative contracts in which Brigham participates. F-10 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) Other Comprehensive Income Brigham follows the provisions of Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive Income," which establishes standards for reporting comprehensive income. In addition to net income, comprehensive income includes all changes in equity during a period, except those resulting from investments and distributions to stockholders of Brigham. Brigham had no such changes prior to 2001. The components of other comprehensive income for the years ended December 31 follow (in thousands):
2002 2001 2000 ------- -------- ---- Balance, beginning of year.................................. $ 351 $ - $ - Cumulative effect of adoption of SFAS No. 133............... - (11,800) - Current period settlements reclassified to earnings......... 1,847 9,646 - Current period change in fair value of hedges............... (5,366) 2,505 - Net losses included in earnings............................. 121 - - ------- -------- --- Balance, end of year........................................ $(3,047) $ 351 $ - ======= ======== ===
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 No. 123), as amended by Statement of Financial Accounting Standards No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure--An Amendment of FASB Statement No. 123" (SFAS No. 148). The weighted average fair value per share of stock compensation issued during 2002, 2001 and 2000 was $3.44, $2.19, and $1.92, respectively. The fair value for these options was estimated using the Black-Scholes Option Pricing Model (Black-Scholes Model) with the following weighted average assumptions for grants made in 2002, 2001 and 2000; risk free interest rate of 4.1%, 4.9% and 6.2%; volatility of the expected market prices of Brigham's common stock of 102%, 60% and 67%; expected dividend yield of zero and weighted average expected option lives of 7.0, 7.0 and 6.6 years, respectively. The Black-Scholes Model was developed for use in estimating the fair value of traded options that have no vesting restrictions and are transferable. Additionally, the assumptions required by the Black-Scholes Model are highly subjective. Because Brigham's stock options have significantly different characteristics from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion the Black-Scholes Model does not necessarily provide a reliable single measure of the fair value of Brigham's stock options. F-11 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) 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 No. 123 as amended by SFAS No. 148, Brigham's net income (loss) and net income (loss) per share for the years ended December 31, 2002, 2001 and 2000 would have been the pro forma amounts indicated below:
2002 2001 2000 ------ ------ ------- Net income available to common stockholders (in thousands): As reported................................................. $ (576) $9,238 $16,337 Add back: Stock compensation expense previously included in net income................................................ 101 295 124 Effect of total employee stock-based compensation expense, determined under fair value method for all awards......... (513) (347) 1,009 ------ ------ ------- Pro forma................................................... $ (988) $9,186 $17,470 ====== ====== ======= Net income per share: Basic: As reported............................................... $(0.04) $ 0.58 $ 1.01 Pro forma................................................. (0.06) 0.57 1.08 Diluted: As reported............................................... $(0.04) $ 0.44 $ 1.01 Pro forma................................................. (0.06) 0.44 1.08
Income Taxes Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates of deferred tax assets and liabilities is recognized in income in the year of the enacted rate change. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred Loan Fees Deferred loan fees are incurred in connection with the issuance or modification of debt and are recorded on the balance sheet as deferred assets. The debt issue costs are amortized to interest expense over the life of the debt using the straight-line method. The results obtained using the straight-line method are not materially different than those that would result from using the effective interest method. Segment Information All of Brigham's oil and natural gas properties and related operations are located in the United States and management has determined that Brigham has one reportable segment. Treasury Stock Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held. F-12 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) New Pronouncements In June 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 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 will adopt this standard as required on January 1, 2003. The following pro forma data summarizes Brigham's net income (loss) and net income (loss) per share as if Brigham had adopted the provisions of SFAS 143 on January 1 for the years ended December 31:
2002 2001 2000 ------ ------ ------- (in thousands, except per share data) Pro forma asset retirement obligation..................... $1,931 $1,678 $ 1,398 ====== ====== ======= Net income (loss), as reported............................ $ (576) $9,238 $16,337 Pro forma adjustments to reflect retroactive adoption of SFAS 143................................................ 283 269 255 Pro forma adjustments to reflect accretion expense........ (130) (111) (94) ------ ------ ------- Pro forma net income (loss)............................... $ (423) 9,396 $16,498 ====== ====== ======= Net income (loss) per share: Basic -- as reported.................................... $(0.04) $ 0.58 $ 1.01 ====== ====== ======= Basic -- pro forma...................................... $(0.03) $ 0.59 $ 1.02 ====== ====== ======= Diluted -- as reported.................................. $(0.04) $ 0.44 $ 1.01 ====== ====== ======= Diluted -- pro forma.................................... $(0.03) $ 0.45 $ 1.02 ====== ====== =======
In April 2002, the FASB issued Statement of Financial Accounting Standards No. 145, "Rescission of FASB statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections" (SFAS No. 145). SFAS No. 145 requires, except in the case of events or transactions of a highly unusual and infrequent nature, gains or losses from the early extinguishment of debt to be classified as components of a company's income or loss from continuing operations. Prior to the adoption of the provisions of SFAS No. 145, gains or losses on the early extinguishment of debt were required to be classified in a company's periodic consolidated statements of operations as extraordinary gains or losses, net of associated income taxes, after the determination of income or loss from continuing operations. SFAS No. 145 is effective for fiscal years beginning after May 15, 2002. Due to the requirements of SFAS No. 145, it is less likely that a gain or loss on extinguishment of debt would be classified as an extraordinary item in Brigham's results of operations. Reclassifications Certain reclassifications have been made to the prior year balances to conform to current year presentation. 3. ASSET DISPOSITIONS In February 1999, Brigham entered into a project financing arrangement with Duke Energy Financial Services, Inc. (Duke) to fund the continued exploration of five projects covered by approximately F-13 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) 200 square miles of 3-D seismic data acquired in 1998. In this transaction, Brigham conveyed 100% of its working interest in land and seismic in these project areas to a newly formed limited liability company (the Brigham-Duke LLC) for a total consideration of $10 million. Brigham was the managing member of the Brigham-Duke LLC with a 1% interest and Duke was the sole remaining member with a 99% interest. Pursuant to the terms of the Brigham-Duke LLC agreement, Brigham paid 100% of the drilling and completion costs for all wells drilled by the Brigham-Duke LLC in exchange for a 70% working interest in the wells and their associated drilling and spacing units and allocable seismic data. Upon 100% project payout, Brigham had certain rights to back-in for up to a 94% effective working interest in the Brigham-Duke LLC properties. In October 2001, Duke, as majority member of the Brigham-Duke LLC elected to dissolve the Brigham-Duke LLC. As a result of the dissolution of the Brigham-Duke LLC, the remaining undeveloped land and seismic data in the Brigham-Duke LLC project areas were unconditionally owned by Duke and, in December 2001, Brigham recorded a loss of approximately $94,000 on its investment in the Brigham-Duke LLC. 4. PROPERTY AND EQUIPMENT Property and equipment, at cost, are summarized as follows (in thousands):
DECEMBER 31, --------------------- 2002 2001 --------- -------- Oil and natural gas properties.............................. $ 267,394 $239,711 Accumulated depletion....................................... (102,414) (87,820) --------- -------- 164,980 151,891 --------- -------- Other property and equipment: 3-D seismic interpretation workstations and software...... 2,445 2,307 Office furniture and equipment............................ 2,337 2,225 Accumulated depreciation.................................. (3,548) (3,201) --------- -------- 1,234 1,331 --------- -------- $ 166,214 $153,222 ========= ========
Brigham capitalizes certain payroll and other internal costs directly attributable to acquisition, exploration and development activities as part of its investment in oil and natural gas properties over the periods benefited by these activities. During the years ended December 31, 2002, 2001 and 2000, these capitalized costs amounted to $4.2 million, $3.9 million and $3.4 million, respectively. Capitalized costs do not include any costs related to production, general corporate overhead, or similar activities. Interest costs of $0.9 million, $1.8 million and $2.8 million were capitalized in 2002, 2001 and 2000, respectively. F-14 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) 5. SENIOR CREDIT FACILITY AND SENIOR SUBORDINATED NOTES
DECEMBER 31, ------------------ 2002 2001 ------- ------- (in thousands) Senior credit facility...................................... $60,000 $75,000 Senior subordinated notes................................... 21,797 16,721 ------- ------- Total debt.................................................. $81,797 $91,721 Less: current maturities.................................. - - ------- ------- Total long-term debt...................................... $81,797 $91,721 ======= =======
Senior Credit Facility As of December 31, 2002, Brigham had $60.0 million in borrowings outstanding under its senior credit facility. Principal outstanding under the senior credit facility is due at maturity with interest due monthly for base rate tranches or periodically as London Interbank Offered Rate (LIBOR) tranches mature. The annual interest rate for borrowings under the senior credit facility is either the lender's base rate or LIBOR (1.5% on December 31, 2002) plus 3.00%, at Brigham's option. Obligations under the senior credit facility are secured by substantially all of Brigham's oil and natural gas properties and other tangible assets. The senior credit facility contains various restrictive covenants and compliance requirements, which include minimum current ratio, interest coverage ratio, limitations on capital expenditures related to seismic and land activities, and various other financial covenants. At December 31, 2002 and for the year then ended, Brigham was in compliance with all covenant requirements. In December 2002, the senior credit facility was amended to extend the maturity date to December 31, 2004 and to provide Brigham with $65 million in funding commitments under a revolving credit structure. In December 2001, the senior credit facility was amended to extend the maturity date to December 31, 2003. Brigham recognized $323,000 and $200,000 during 2002 and 2001, respectively, as additional deferred loan fees relating to these amendments. The additional deferred loan fees and the remaining unamortized deferred loan fees will be amortized over the remaining life of the senior credit facility. The senior credit facility was amended in February 2000, to provide Brigham with $75 million in borrowing availability. As part of the amendment, $30 million of the senior credit facility held by Shell Capital was designated as convertible notes. To facilitate this conversion Brigham issued to Shell Capital warrants to be converted into shares of Brigham common stock in the following amounts and prices: (i) $10 million is convertible at $3.90 per share, (ii) $10 million is convertible at $6.00 per share and (iii) $10 million is convertible at $8.00 per share. In addition, certain financial covenants of the senior credit facility were amended or added in the July 1999, February 2000 and October 2000 amendments. In connection with the February 2000 amendment, Brigham reset the price of the warrants previously issued to its existing senior lenders to purchase one million shares of Brigham common stock from the then current exercise price of $2.25 per share to $2.02 per share. In December 2002, Brigham entered into a series of transactions whereby a number of warrants and convertible debt rights were extinguished or converted. Brigham issued 550,000 unregistered shares of its common stock to Shell Capital in exchange for Shell Capital's warrant position (see Senior Subordinated Notes below), and to terminate Shell Capital's right to convert $30 million of Brigham's senior credit facility into shares of Brigham common stock. Also, DLJ Merchant Banking Partners III, L.P. in F-15 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) conjunction with GlobalEnergy Partners, both affiliates of CSFB Private Equity, purchased $10 million of Brigham's senior credit facility from Shell Capital and converted it into 2,564,102 shares of Brigham's common stock at an exercise price of $3.90 per share. Brigham recorded $0.6 million in debt conversion expenses associated with this conversion. The following table details the warrant position and convertible debt rights that were extinguished or converted as a result of the these transactions:
EXERCISE PRICE # SHARES -------- --------- $10 million of convertible notes............................ $3.90 2,564,102 $10 million of convertible notes............................ $6.00 1,666,667 $10 million of convertible notes............................ $8.00 1,250,000 Warrants issued with senior subordinated notes.............. $3.00 1,250,000 --------- 6,730,769 =========
As further discussed in Note 6, Brigham issued 500,000 shares of Series B preferred stock and 2,298,850 million warrants to purchase Brigham's common stock for net proceeds of $9.4 million. In addition, Brigham used $5.0 million of the net proceeds from the Series B preferred offering to repay outstanding indebtedness under its senior credit facility. In March 2003, Brigham replaced its senior credit facility with a new senior credit facility that provides for a maximum $80 million in commitments, an initial borrowing base of $70 million and matures in March 2006. As of the closing date of the facility, Brigham had $56 million in outstanding borrowings under the new senior credit facility. Borrowings under the new senior credit facility are secured by substantially all of Brigham's oil and natural gas properties and other tangible assets and bear interest at either the base rate of Societe Generale or LIBOR, at Brigham's option, plus a margin that varies according to facility usage. Interest is paid quarterly. The collateral value and borrowing base are redetermined periodically. The unused portion of the committed borrowing base is subject to an annual commitment fee of 0.50%. The new senior credit facility agreement contains various covenants and restrictive provisions, which limit Brigham's ability to incur additional indebtedness, sell properties, purchase or redeem capital stock, make investments or loans, create liens and make certain acquisitions. The new senior credit facility requires Brigham to maintain a current ratio (as defined) of at least 1 to 1 and an interest coverage ratio (as defined) of at least 3.25 to 1. Senior Subordinated Notes As of December 31, 2002, Brigham had $21.8 million of senior subordinated notes outstanding. The senior subordinated notes bear interest at 10.75% per annum, payable quarterly in arrears on the last day of January, April, July and October, are redeemable at Brigham's option for face value at any time and have no principal repayment obligations until maturity in October 2005. At Brigham's option, up to 50% of the interest payments on the senior subordinated notes can be satisfied by payment in kind through the issuance of additional senior subordinated notes in lieu of cash. In December 2002, Brigham extended its option to satisfy 50% of its interest obligation in this manner through October 2003. For the years ended December 31, 2002 and 2001, Brigham exercised this option and issued an additional $1.1 and $0.7 million, respectively, of senior subordinated notes. F-16 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) The senior subordinated notes are issued pursuant to the senior subordinated notes dated October 31, 2000. Under the senior subordinated notes, Shell Capital agreed to provide up to $20 million (plus any amount of interest paid in kind) in senior subordinated notes in borrowing increments of at least $1 million. Once borrowings under the senior subordinated notes facility have been repaid they cannot be withdrawn. The senior subordinated notes are secured obligations ranking junior to Brigham's senior credit facility and have covenants similar to the senior credit facility. In connection with the senior subordinated credit agreement in October 2000, Brigham issued warrants to purchase 1,250,000 shares of Brigham common stock at an exercise price of $3.00 per share. The warrants had a term of seven years and a cashless exercise feature. Brigham valued the warrants using the Black-Scholes Model and recorded the estimated value of $2.9 million as deferred loan costs which are being amortized over the five-year term of the senior subordinated notes. The warrants were extinguished in December 2002 (see Senior Credit Facility above). At January 1, 2000, Brigham had a subordinated notes agreement with $41.3 million total outstanding and warrants issued to the notes holders to purchase one million shares of common stock at an exercise price of $3.50 per share. In February 2000, in connection with an amendment to the agreement, the exercise price on the warrants was reduced to $2.43 per share. Brigham issued an additional $4.6 million in subordinated notes as payment in kind of interest for the year ended December 31, 2000. In November 2000, these subordinated notes and warrants were purchased by Brigham for $20 million resulting in a gain of $32.3 million, net of transaction costs of $1.7 million. 6. PREFERRED STOCK In October 2000, Brigham designated 1.5 million shares of preferred stock as Series A Preferred Stock, and in November 2000, issued 1.0 million shares of mandatorily redeemable preferred stock (the "Series A Preferred Stock") and warrants to purchase 6,666,667 shares of Brigham's common stock (the "Series A Warrants") for net proceeds of $19.8 million. The proceeds from the issuance of the Series A Preferred Stock and Series A Warrants were used to purchase the subordinated notes and warrants held by the holder of the subordinated notes as described in Note 5. The Series A Preferred Stock has a par value of $.01 per share and a stated value of $20 per share. The Series A Preferred Stock is cumulative and pays dividends quarterly at a rate of 6% per annum of the stated value if paid in cash or 8% per annum of the stated value if paid in kind (PIK) through the issuance of additional Series A Preferred Stock in lieu of cash. At Brigham's option, up to 100% of the dividend payments on the Series A Preferred Stock can be paid by the issuance of PIK dividends for five years. The Series A Preferred Stock matures in ten years and is redeemable at Brigham's option at 100% or 101% of stated value (depending upon certain conditions) at anytime prior to maturity. The Series A Warrants have a term of ten years, an exercise price of $3.00 per share and must be exercised, if Brigham so requires, in the event Brigham's average price of common stock is above $5.00 per share each day for 60 consecutive trading days. The exercise price of the Series A Warrants is payable either in cash or in shares of the Series A Preferred Stock valued at liquidation value plus accrued dividends. If Brigham requires exercise of the Series A Warrants, proceeds will be used to fund the redemption of a similar value of then outstanding Series A Preferred Stock. The Series A Warrants were valued at $11.5 million using the Black-Scholes Model and were recorded as additional paid-in capital in 2000. This discount accretes to the Series A Preferred Stock stated value during the life of the securities using the effective interest method. In March 2001, Brigham designated an additional 750,000 shares of preferred stock as Series A and issued 500,000 shares of Series A Preferred Stock and 2,105,263 warrants to purchase Brigham's common stock (the "Additional Series A Warrants") for net proceeds of $9.8 million. F-17 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) The Additional Series A Warrants have terms similar to the Series A Warrants described above except the Additional Series A Warrants have an exercise price of $4.75 per share and must be exercised, if Brigham so requires, in the event that the average price of Brigham's common stock is above 150% of the exercise price (currently $6.525 per share) each day for 60 consecutive trading days. The Additional Series A Warrants were valued at approximately $4.5 million using the Black-Scholes Model and were recorded as additional paid-in capital in March 2001. This discount accretes to the Series A Preferred Stock stated value during the life of the securities using the effective interest method. In connection with the issuance of Series B Preferred Stock in December 2002, the exercise price of the Additional Series A warrants was reset from the then current exercise price of $4.75 per share to $4.35 per share. Brigham had 1,765,132 and 1,630,692 shares of Series A Preferred Stock issued and outstanding with a redemption value of $35.3 million and $32.6 million at December 31, 2002 and 2001, respectively. For the year ended December 31, 2002 and 2001, Brigham issued an additional 134,440 and 130,692 shares, respectively, of Series A Preferred Stock as PIK dividends. In December 2002, Brigham designated 1,000,000 shares of preferred stock as Series B and issued 500,000 shares of mandatorily redeemable preferred stock (the Series B Preferred Stock) and warrants to purchase 2,298,850 shares of Brigham's common stock (the "Series B Warrants") for net proceeds of $9.4 million. A portion of the proceeds were used to reduce borrowings under the senior credit facility by $5 million. The Series B Preferred Stock is cumulative and pays dividends quarterly at a rate of 6% per annum of the stated value if paid in cash or 8% per annum of the stated value if PIK through the issuance of additional Series B Preferred Stock in lieu of cash. At Brigham's option, up to 100% of the dividend payments on the Series B Preferred Stock can be paid by the issuance of PIK dividends for five years. The Series B Preferred Stock matures in ten years and is redeemable in whole at Brigham's option at 101% of the stated value five years after closing. The Series B Preferred Stock ranks in parity with the Series A Preferred Stock and senior as to dividend, redemption and liquidation rights to all other classes and series of capital stock of Brigham authorized on the date of issuance, or to any other class or series of capital stock issued while any shares of the Series B Preferred Stock remain outstanding. The Series B Preferred Stock does not generally have any voting rights, except for certain approval rights and as required by law. The Series B Warrants have terms similar to the Series A Warrants described above with an exercise price of $4.35 per share and must be exercised, if Brigham so requires, in the event that the price of Brigham's common stock averages at least 150% of the exercise price ($6.525 per share) over 60 consecutive trading days. The Series B Warrants were valued at approximately $4.6 million using the Black-Scholes Model and were recorded as additional paid-in capital in December 2002. This discount accretes to the Series B Preferred Stock stated value during the life of the securities using the effective interest method. Brigham had 501,226 shares of Series B Preferred Stock issued and outstanding with a redemption value of $10.0 million at December 31, 2002. For the year ended December 31, 2002, Brigham issued an additional 1,226 shares of Series B Preferred Stock as PIK dividends. 7. ISSUANCE OF COMMON STOCK In December 2002, Brigham issued 550,000 shares of Brigham common stock to Shell Capital in exchange for Shell Capital's warrants and associated convertible debt rights. In addition, Brigham issued 2,564,102 shares of Brigham common stock upon the conversion of $10 million of the senior credit facility. See further discussion above in Note 5. F-18 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) In February 2000, Brigham issued 2,195,122 shares of common stock and 731,707 warrants to purchase Brigham's common stock for total net proceeds of approximately $4.2 million in a private placement to a group of institutional investors led by affiliates of two members of Brigham's board of directors. The equity sale consisted of units that included one share of common stock and one-third of a warrant to purchase Brigham's common stock at an exercise price of $2.5625 per share. In December 2002, 243,902 of these warrants were exercised for common stock resulting in net proceeds of approximately $625,000. In February 2003, the remaining 487,805 warrants were exercised under a cashless feature resulting in the issuance of 248,028 shares of Brigham common stock. 8. CAPITAL LEASE OBLIGATIONS Property under capital leases consists of the following (in thousands):
DECEMBER 31, ------------- 2002 2001 ---- ----- 3-D seismic interpretation workstations and software........ $- $ 45 Office furniture and equipment.............................. - 167 -- ----- - 212 Accumulated depreciation and amortization................... - (175) -- ----- $- $ 37 == =====
There are no obligations under capital leases as of December 31, 2002. 9. INCOME TAXES The provision for income taxes consists of the following (in thousands):
YEAR ENDED DECEMBER 31, -------------------- 2002 2001 2000 ---- ---- ---- Current income taxes: Federal................................................... $- $- $- State..................................................... - - - Deferred income taxes: Federal................................................... - - - State..................................................... - - - -- -- -- $- $- $- == == ==
F-19 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) The differences in income taxes provided and the amounts determined by applying the federal statutory tax rate to income before income taxes result from the following (in thousands):
YEAR ENDED DECEMBER 31, --------------------------- 2002 2001 2000 ----- ------- ------- Tax at statutory rate...................................... $ 832 $ 4,091 $ 5,814 Add the effect of: Nondeductible expenses..................................... 223 4 12 Deductible stock compensation.............................. (110) (9) - Valuation allowance........................................ (945) (4,086) (5,826) ----- ------- ------- $ - $ - $ - ===== ======= =======
The components of deferred income tax assets and liabilities are as follows (in thousands):
DECEMBER 31, -------------------- 2002 2001 -------- -------- Deferred tax assets: Net operating loss carryforwards.......................... $ 34,814 $ 31,085 Capital loss carryforwards................................ 1,001 438 Stock compensation........................................ 808 745 Gas imbalances............................................ 698 445 Unrealized hedging losses................................. 1,066 - Other..................................................... 32 7 -------- -------- 38,419 32,720 -------- -------- Deferred tax liability: Depreciable and depletable property....................... (29,544) (24,058) Derivative liabilities.................................... (325) (233) -------- -------- (29,869) (24,291) -------- -------- Net deferred tax asset.................................... 8,550 8,429 Valuation allowance....................................... (8,550) (8,429) -------- -------- $ - $ - ======== ========
Realization of deferred tax assets associated with net operating loss carryforwards (NOLs) and other credit carryforwards is dependent upon generating sufficient taxable income prior to their expiration. At December 31, 2002, management believes it is more likely than not that these NOLs and other credit carryforwards may expire unused and, accordingly, has established a valuation allowance of $8.6 million against them. The valuation allowance was increased by $0.1 million in 2002 due to an increase of $5.6 million in deferred tax liabilities, partially offset by a $5.7 million increase in carryforward and other amounts. Deferred tax assets of $1.1 million related to unrealized hedging losses in other comprehensive income are included in this $5.7 million increase. At December 31, 2002, Brigham has regular tax NOLs of approximately $99.5 million. Additionally, Brigham has approximately $84.9 million of alternative minimum tax (AMT) NOLs available as a deduction against future AMT income. The NOLs expire from 2012 through 2022. The value of these NOLs depends on the ability of Brigham to generate taxable income. F-20 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) A summary of the NOLs follows (in thousands):
REGULAR AMT NOLS NOLS ------- ------- Expiration Date: December 31, 2012......................................... $13,327 $ 8,703 December 31, 2018......................................... 26,411 23,170 December 31, 2019......................................... 20,806 20,196 December 31, 2020......................................... 12,512 7,587 December 31, 2021......................................... 19,116 18,440 December 31, 2022......................................... 7,298 6,799 ------- ------- $99,470 $84,895 ======= =======
In addition, at December 31, 2002, Brigham has capital loss carryforwards of approximately $2.9 million that expire in varying years through 2007. Brigham believes it has a $5 million limitation on its NOLs under Internal Revenue Code Section 382 due to a potential 50% change in ownership among its 5% stockholders over a three-year period. 10. NET INCOME (LOSS) PER SHARE Basic earnings per share are computed by dividing net income (loss) available to common stockholders by the weighted average number of common shares outstanding for the period. The computation of diluted net income (loss) per share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that would then share in the earnings of Brigham. F-21 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
YEAR ENDED DECEMBER 31, ------------------------------ 2002 2001 2000 ------- ------- -------- Restated (In thousands, except per share data) Basic EPS: Income (loss) available to common stockholders......... $ (576) $ 9,238 $ 16,337 ======= ======= ======== Common shares outstanding.............................. 16,138 15,988 16,241 ======= ======= ======== Basic EPS.............................................. $ (0.04) $ 0.58 $ 1.01 ======= ======= ======== Diluted EPS: Income (loss) available to common stockholders......... $ (576) $ 9,238 $ 16,337 Adjustments for assumed conversions: Interest on convertible debt........................ - 826 - Dividends and accretion on mandatorily redeemable preferred stock................................... - 2,364 - ------- ------- -------- - 3,190 - ------- ------- -------- Income (loss) available to common stockholders--diluted............................... $ (576) $12,428 $ 16,337 ======= ======= ======== Common shares outstanding.............................. 16,138 15,988 16,241 Effect of dilutive securities: Convertible debt.................................... - 2,564 - Warrants............................................ - 926 - Mandatorily redeemable preferred stock.............. - 8,426 - Stock options....................................... - 301 - ------- ------- -------- Potentially dilutive common shares..................... - 12,217 - ------- ------- -------- Adjusted common shares outstanding--diluted......... 16,138 28,205 16,241 ======= ======= ======== Diluted EPS (as restated for 2001--see below).......... $ (0.04) $ 0.44 $ 1.01 ======= ======= ========
At December 31, 2002, 2001, and 2000, potential dilution of approximately 14.3 million, 3.0 million and 11.1 million shares of common stock, respectively, related to mandatorily redeemable preferred stock, convertible debt, warrants and options were outstanding, but were not included in the computation of diluted income (loss) per share because the effect of these instruments would have been anti-dilutive. RESTATEMENT--Diluted earnings per share for 2001 have been restated (downward) to appropriately reflect the impact of Brigham's convertible debt, mandatorily redeemable preferred stock and associated warrants. The revised calculations utilize the "if-converted" method, as the holders can exercise the warrants either by paying cash or tendering the related convertible debt or mandatorily redeemable preferred stock.
QUARTER YEAR TO DATE ----------------------- ----------------------- AS REPORTED RESTATED AS REPORTED RESTATED ----------- -------- ----------- -------- March 31, 2001................................ $ 0.02 $ 0.02 $0.02 $0.02 June 30, 2001................................. $ 0.46 $ 0.30 $0.51 $0.36 September 30, 2001............................ $ 0.17 $ 0.13 $0.67 $0.49 December 31, 2001............................. $(0.15) $(0.15) $0.54 $0.44
There is no impact on previously reported diluted earnings per share data for 2002 or 2000. F-22 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) 11. CONTINGENCIES, COMMITMENTS AND FACTORS WHICH MAY AFFECT FUTURE OPERATIONS Litigation 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 June 1, 2001, Leonel Garcia, a landowner in Brooks County, Texas, filed suit against Brigham claiming that Brigham transported natural gas under his property through an existing pipeline without his consent. Mr. Garcia claimed $1.2 million in actual damages and $3 million in exemplary damages. In May 2002, Brigham settled the case through mediation for a cash payment of $125,000. Subsequently, Brigham began using an alternate pipeline. On November 20, 2001, Brigham filed a lawsuit in the District Court of Travis County, Texas against Steve Massey Company, Inc. (Massey) for breach of contract. The Petition claims Massey furnished defective casing to Brigham, which ultimately led to the casing failure of the Palmer "347" No. 5 well (the "Palmer #5") and the loss of the Palmer #5 as a producing well. Brigham believes the amount of damages incurred due to the loss of the Palmer #5 may exceed $5 million. Massey joined as additional defendants to the lawsuit other parties that had responsibility for the manufacture, importation or fabrication of the casing for its use in the Palmer #5. The case is currently in discovery. A trial has been set for August 2003. On February 20, 2002, Massey filed an Original Petition to Foreclose Lien in Brooks County, Texas. Massey's Petition claims Brigham breached its contract for failure to pay for the casing it furnished Brigham for the Palmer #5 (and that Brigham's claim is defective, forming the basis of the lawsuit described in the paragraph above). Massey's Petition claims Brigham owes Massey a total of $445,819. Brigham's Motion to Transfer Venue to Travis County, Texas, and Motion to Consolidate Massey's claim with Brigham's suit against Massey pending in Travis County, were recently granted. If Massey is successful in its claim, Massey would have the right to foreclose its lien against the well, associated equipment and Brigham's leasehold interest. At this point in time, Brigham cannot predict the outcome of either its Travis County case or Massey's claim. 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 investigated the accident and issued three citations and imposed a total of $168,000 in fines. Brigham is appealing the citations, but at this time, cannot predict the outcome of that appeal. 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 on July 11, 2002. Plaintiffs are seeking unspecified both actual and punitive damages. Brigham cannot predict the outcome of this case, however Brigham believes it has sufficient insurance to cover the claim. As of December 31, 2002, there were no known environmental or other regulatory matters related to Brigham's operations that are reasonably expected to result in a material liability to Brigham. Compliance with environmental laws and regulations has not had, and is not expected to have, a material adverse effect on Brigham's capital expenditures, earnings or competitive position. F-23 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) Operating Lease Commitments Brigham leases office equipment and space under operating leases expiring at various dates. The noncancelable term of the lease for Brigham's office space expires in 2007 with an option to renew for an additional five years. The future minimum annual rental payments under the noncancelable terms of these leases at December 31, 2002 are as follows (in thousands): 2003........................................................ $ 885 2004........................................................ 885 2005........................................................ 885 2006........................................................ 885 2007........................................................ 443 ------ $3,983 ======
Future minimum rental payments are not reduced by minimum sublease rental income of approximately $13,000 due in 2003 under noncancelable subleases. Rental expense for the years ended December 31, 2002, 2001 and 2000 was approximately $868,000, $731,000 and $805,000, respectively. Major Purchasers The following purchasers accounted for 10% or more of Brigham's oil and natural gas sales for the years ended December 31, 2002, 2001 and 2000:
2002 2001 2000 ---- ---- ---- Purchaser A................................................. 19% 45% 36% Purchaser B................................................. - 15% 20% Purchaser C................................................. 15% - - Purchaser D................................................. 11% - -
Brigham believes that the loss of any individual purchaser would not have a long-term material adverse impact on its financial position or results of operations. Factors Which May Affect Future Operations Since Brigham's major products are commodities, significant changes in the prices of oil and natural gas could have a significant impact on Brigham's results of operations for any particular year. 12. 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) support its capital budgeting plans, and (iii) lock-in prices to protect the economics related to certain capital projects. F-24 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) Natural Gas Derivative Contracts The following table sets forth Brigham's outstanding natural gas hedging contracts and the weighted average NYMEX prices for those contracts as of December 31, 2002:
FIRST SECOND THIRD FOURTH OUTSTANDING QUARTER QUARTER QUARTER QUARTER AVERAGE ------- ------- ------- ------- ----------- 2003--Swap Contracts Volume (MMbtu)...................... 832,500 591,500 460,000 322,000 549,851 Price per MMBtu..................... $ 3.63 $ 3.32 $ 3.50 $ 3.73 $ 3.54
The following table sets forth the natural gas hedging contracts Brigham entered subsequent to December 31, 2002 and the weighted average NYMEX prices for those contracts:
FIRST SECOND THIRD FOURTH OUTSTANDING QUARTER QUARTER QUARTER QUARTER AVERAGE ------- ------- ------- ------- ----------- 2003--Swap Contracts Volume (MMbtu)...................... - 227,500 138,000 92,000 114,692 Price per MMBtu..................... $ - $ 5.21 $ 5.08 $ 5.12 $ 5.15 2003--Floors Volume (MMbtu)...................... - 150,000 460,000 460,000 187,912 Price per MMBtu..................... $ - $ 4.50 $ 4.50 $ 4.50 $ 4.50 2004--Swap Contracts Volume (MMbtu)...................... 295,750 227,500 138,000 92,000 187,912 Price per MMBtu..................... $ 4.96 $ 4.25 $ 4.18 $ 4.36 $ 4.53
Oil Derivative Contracts The following table sets forth Brigham's outstanding oil hedging contracts and the weighted average NYMEX prices for those contracts as of December 31, 2002:
FIRST SECOND THIRD FOURTH OUTSTANDING QUARTER QUARTER QUARTER QUARTER AVERAGE ------- ------- ------- ------- ----------- 2003--Swap Contracts Volume (Bbl)............................ 67,500 50,050 55,200 41,400 53,471 Price per Bbl........................... $25.29 $24.28 $23.77 $23.21 $24.26 2003--Collars Volume (Bbl)............................ 22,500 22,750 - - Ceiling price per Bbl................... $22.56 $22.56 $ - $ - Floor price per Bbl..................... $18.00 $18.00 $ - $ -
F-25 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) The following table sets forth the oil hedging contracts Brigham entered subsequent to December 31, 2002 and the weighted average NYMEX prices for those contracts:
FIRST SECOND THIRD FOURTH OUTSTANDING QUARTER QUARTER QUARTER QUARTER AVERAGE ------- ------- ------- ------- ----------- 2003--Swap Contracts Volume (Bbl)............................ - 11,375 - - 2,836 Price per Bbl........................... $ - $29.33 $ - $ - $29.33 2004--Swap Contracts Volume (Bbl)............................ 29,575 20,475 13,800 9,200 18,145 Price per Bbl........................... $25.35 $24.52 $23.91 $23.80 $24.65
At December 31, 2002, the fair value of hedging contracts included in accumulated other comprehensive income and other current liabilities was approximately $3.2 million which is expected to be included in the results of operations for the year ended December 31, 2003. At December 31, 2001, the fair value of hedging contracts included in accumulated other comprehensive income and other current assets was approximately $351,000 of which approximately $50,000 was classified as noncurrent assets. 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 year period ended December 31, 2002:
YEAR ENDED DECEMBER 31, -------------------------- 2002 2001 2000 ------ ------ ------ Natural Gas Average price per Mcf as reported (including hedging results)............................................... $ 3.21 $ 3.11 $ 1.94 Average price per Mcf realized (excluding hedging results)............................................... $ 3.33 $ 4.29 $ 4.06 Decrease in revenue (in thousands)........................ $ 712 $8,001 $9,400 Oil Average price per Bbl as reported (including hedging results)............................................... $23.55 $24.05 $29.17 Average price per Bbl realized (excluding hedging results)............................................... $25.17 $24.38 $29.47 Decrease in revenue (in thousands)........................ $1,135 $ 153 $ 107
Derivative instruments that do not qualify as hedging contracts are recorded at fair value on the balance sheet. At each balance sheet date, the value of these derivatives is adjusted to reflect current fair value and any gains or losses are recognized as other income or expense. At December 31, 2002 and 2001, the fair value of these derivatives included in other liabilities was $0 and $0.4 million, respectively. Brigham recognized $0.4 million, $9.7 million and $(8.9) million in non-cash gains (losses) related to changes in the fair values of these derivative contracts and $0.6 million, $1.5 million, and $0.6 million in losses related to the cash settlement payments made by Brigham to the counterparty for the years ended December 31, 2002, 2001 and 2000, respectively. For the year ended December 31, 2002, ineffectiveness associated with Brigham's derivative commodity instruments designated as cash flow hedges decreased earnings by approximately $0.1 million. These amounts are included in other income and expense. There was no ineffectiveness for the year ended December 31, 2001. F-26 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) 13. FINANCIAL INSTRUMENTS Brigham's non-derivative financial instruments include cash and cash equivalents, accounts receivable, accounts payable and long-term debt. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximate fair value because of their immediate or short-term maturities. The carrying value of Brigham's senior credit facility approximates its fair market value since it bears interest at floating market interest rates. The fair value of Brigham's senior subordinated notes at December 31, 2002 and 2001 was $24.0 million and $13.9 million, respectively. Brigham's accounts receivable relate to oil and natural gas sold to various industry companies, and amounts due from industry participants for expenditures made by Brigham on their behalf. Credit terms, typical of industry standards, are of a short-term nature and Brigham does not require collateral. Brigham's accounts receivable at December 31, 2002 and 2001 do not represent significant credit risks as they are dispersed across many counterparties. Counterparties to the natural gas and crude oil price swaps are investment grade financial institutions. 14. EMPLOYEE BENEFIT PLANS Brigham has adopted a defined contribution 401(k) plan for substantially all of its employees. The plan provides for Brigham matching of employee contributions to the plan, at Brigham's discretion. During 2002 and 2001, Brigham matched 25% of eligible employee contributions. Based on attainment of performance goals established at the beginning of 2002, Brigham matched an additional 62.5% and 17% of eligible employee contributions made during 2002 and 2001, respectively. Brigham contributed $260,000 and $102,000 to the 401(k) plan for the years ended December 31, 2002 and 2001, respectively, to match eligible contributions by employees. Brigham did not match employee contributions in 2000. 15. STOCK BASED COMPENSATION Brigham provides an incentive plan for the issuance of stock options, stock appreciation rights, stock, restricted stock, cash or any combination of the foregoing. The objective of this plan is to reward key employees whose performance may have a significant effect on the success of Brigham. An aggregate of 1,588,170 shares of Brigham's common stock was reserved for issuance pursuant to this plan. By resolution of the stockholders in May 2001, the number of shares of common stock available under the plan was amended to equal the lesser of 13% of the shares of common stock of Brigham issued and outstanding at any time or 2,077,335 shares. The Compensation Committee of the Board of Directors determines the type of awards made to each participant and the terms, conditions and limitations applicable to each award. At December 31, 2002, Brigham has issued approximately 85,000 incentive awards in excess of the amount currently authorized by the plan. Brigham will ask stockholders to approve an increase in the total shares available for incentive awards at the next annual meeting in May 2003. The requested increase will be greater than 85,000 shares. Options granted subsequent to March 4, 1997 have an exercise price equal to the fair market value of Brigham's common stock on the date of grant and generally vest over three to five years. In May 2002, Brigham accelerated the vesting of certain employee stock options and extended the time limitation for exercising certain employee stock options following termination of employment. These revisions resulted in the immediate recognition of stock compensation cost as measured at the effective date of the changes. Accordingly, a non-cash charge to general and administrative expense in the amount of $596,000 was recorded. F-27 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) Brigham also maintains a plan under which it offers stock compensation to non-employee directors. Pursuant to the terms of the plan, non-employee directors are entitled to annual grants. Options granted under this plan have an exercise price equal to the fair market value of Brigham's common stock on the date of grant and generally vest over five years. The following table summarizes activity under the incentive plan for each of the three years ended December 31, 2002:
WEIGHTED AVERAGE SHARES EXERCISE PRICE --------- ---------------- Options outstanding December 31, 1999....................... 1,519,726 $ 4.47 Options granted........................................... 793,500 2.83 Options forfeited or cancelled............................ (898,112) (5.57) Options exercised......................................... (8,000) (5.11) --------- Options outstanding December 31, 2000....................... 1,407,114 2.89 Options granted........................................... 546,500 3.44 Options forfeited or cancelled............................ (239,369) (3.48) Options exercised......................................... (97,474) (2.59) --------- Options outstanding December 31, 2001....................... 1,616,771 3.00 Options granted........................................... 475,000 4.12 Options forfeited or cancelled............................ (177,129) (3.25) Options exercised......................................... (132,507) (2.23) --------- Options outstanding December 31, 2002....................... 1,782,135 $ 3.34 =========
Brigham is required to use variable accounting for 252,500 of the stock options granted during 2000 of which 217,000 remain outstanding at December 31, 2002. This method of accounting requires recognition of noncash compensation expense for the difference between the option exercise price and the market price of Brigham's stock at the end of the accounting period of vested options. Since the market price for Brigham's stock is a component of the variable cost accounting calculation, it is not possible to determine the total noncash compensation expense that will be recognized during the vesting period of these options. The following table summarizes information about stock options outstanding at December 31, 2002:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE -------------------------------------------------- ------------------------------- NUMBER WEIGHTED- NUMBER OUTSTANDING AT AVERAGE WEIGHTED- EXERCISABLE AT WEIGHTED- DECEMBER 31, REMAINING AVERAGE DECEMBER 31, AVERAGE EXERCISE PRICE 2002 CONTRACTUAL LIFE EXERCISE PRICE 2002 EXERCISE PRICE -------------- -------------- ---------------- -------------- -------------- -------------- $1.55 to $1.83............. 181,500 4.1 years $1.83 105,000 $1.83 2.38 to 3.41.............. 869,635 5.0 years 2.48 414,293 2.64 3.61 to 5.19.............. 719,000 5.7 years 4.07 129,300 3.75 6.31 to 14.38............. 12,000 2.8 years 6.98 9,533 7.16 --------- ------- $1.55 to $14.38............ 1,782,135 5.2 years $3.34 658,126 $2.79 ========= =======
Exchange of Certain Options for Shares of Restricted Stock On October 25, 2000, the compensation committee of the Board of Directors approved a proposal to give its employees a one-time right to elect to cancel all or half of their outstanding employee stock options F-28 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) which were previously granted with exercise prices of $5.00 per share (the "$5 Options") or $6.31 per share (the "$6.31 Options") and to receive in exchange shares of restricted stock under Brigham's 1997 Incentive Plan. The exchange ratios were .643 shares of restricted stock for each share of common stock underlying a $5 Option and .4 shares of restricted stock for each share of common stock underlying a $6.31 Option. Pursuant to the option exchange offer, on October 27, 2000, a total of 244,794 of the $5 Options were canceled in exchange for 157,401 shares of restricted stock, and a total of 379,665 of the $6.31 Options were canceled in exchange for 151,866 shares of restricted stock. Regardless of whether the canceled options were vested or unvested, the shares of restricted stock vest 25% per year beginning October 27, 2000. The restricted stock agreements contain provisions for accelerated vesting in some circumstances, which provisions are similar to those in the agreements covering the canceled options. This exchange resulted in noncash compensation expense of approximately $1.1 million that is being recognized over the vesting period of the restricted stock. 16. RELATED PARTY TRANSACTIONS During the years ended December 31, 2002, 2001 and 2000, Brigham incurred costs of approximately $1.1 million, $0.4 million and $0.1 million, respectively, in fees for land acquisition services performed by a company owned by a brother of Brigham's President and Chief Executive Officer and its Executive Vice President--Land and Administration. Other participants in Brigham's 3-D seismic projects reimbursed Brigham for a portion of these amounts. At December 31, 2002 and 2001, Brigham had recorded a liability in accounts payable of approximately $0 and $30,000, respectively, related to services performed by this company. A director of Brigham served as a consultant to Brigham on various aspects of its business and strategic issues. Fees paid for these services by Brigham were approximately $45,000, $44,000 and $33,000 for the years ended December 31, 2002, 2001 and 2000, respectively. Additional disbursements totaling approximately $12,000, $6,000 and $12,000 were made during 2002, 2001 and 2000, respectively, for the reimbursement of certain expenses. At December 31, 2002 and 2001, there were no payables related to these services recorded by Brigham. At December 31, 2002 Brigham had short-term accounts receivable of approximately $94,000 from a director of Brigham. These receivables represent the director's share of costs related to his working interest ownership in the Staubach No. 1, Burkhart #1R and Matthes-Huebner #1 wells that are operated by Brigham. The director obtained his interest in these wells through an exploration and production company that is not affiliated with Brigham. At December 31, 2002, $23,000 of the balance due was current and the remainder was over ninety days past due. Open short-term accounts receivable with the director are approximately $15,000 as of March 2003 and are thirty days past due. On March 1, 2002, Brigham ended an agreement to sell substantially all of its crude production to a single company, and began utilizing a broader range of purchasers. In April 2002, Brigham began selling a portion of its oil production to Citation Crude Marketing, Inc. based on an evaluation of terms and capabilities offered by several companies. Brigham's Executive Vice President and CFO and board member through July 12, 2002 is the brother of the President of Citation Crude Marketing, Inc., and the son of the President and Chief Executive Officer of Citation Oil & Gas Corporation. Brigham sold approximately 212,000 barrels of oil with a value of $5.6 million to Citation Crude Marketing, Inc. during 2002. F-29 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) From time to time, in the normal course of business, Brigham has engaged a drilling company in which one of Brigham's current directors owns stock and serves on the board of directors. Total payments to the drilling company during 2002 and 2001 were $0.4 million and $3.9 million, respectively. At December 31, 2002, Brigham owed the drilling company approximately $0.4 million. At December 31, 2001 the drilling company was not performing work for Brigham and there were no amounts owed. From time to time during 2002, in the normal course of business, Brigham has engaged a service company in which one of Brigham's current directors owns stock and serves on the board of directors. Total payments to the service company during 2002 were $130,000. At December 31, 2002, Brigham owed the service company approximately $76,000. For the year ended December 31, 2001, the service company was not a related party. In October 2001, Brigham entered into a Joint Exploration Agreement with Carrizo Oil & Gas, Inc. (Carrizo). Under the terms of this agreement the parties (1) blended their existing oil and gas leasehold positions covering a South Texas prospect, (2) identified five separate areas of mutual interest within the prospect, and (3) agreed upon procedures for the future exploration and development of the prospect. In November and December of 2002, Brigham and Carrizo entered into agreements that increased Brigham's interest in some of the leasehold within the South Texas prospect. One of Brigham's current directors was a co-founder of Carrizo and is currently chairman of Carrizo's board of directors. At December 31, 2002 and 2001, Brigham was owed $413,000 and $158,000, respectively, by Carrizo for exploration and production activities. Brigham owed Carrizo $11,000 and $13,000 at December 31, 2002 and 2001, respectively. During 2001, Brigham entered into three agreements with Aspect Resources, LLC (Aspect). These agreements included: (1) a Joint Development Agreement extending the term of an area of mutual interest arrangement, and establishing cost sharing for potential expenditures within the project area; (2) an Agreement and Partial Assignment of Seismic Participation Agreement under which Aspect assigned Brigham an interest in an existing 3-D seismic project and Brigham must pay the assigned interest portion of future costs; (3) a Geophysical Exploration Agreement under which Brigham assigned Aspect an interest in an existing 3-D project area (with certain exclusion) and Aspect agreed to provide certain seismic data overlapping the project area and share in future costs. The President of Aspect was a director of Brigham and a member of the Compensation Committee for a portion of 2002 and all of 2001. Total amounts paid to Aspect during 2002 and 2001 for exploration, development and production operations were $189,000 and $588,000, respectively. Total amounts paid to Brigham by Aspect, or on their behalf, during 2002 and 2001 for exploration, development and production operations were $1,008,000 and $524,000, respectively. Brigham owed Aspect $0 and $174,000 at December 31, 2002 and 2001, respectively, for various exploration and production activities. Aspect owed Brigham $312,000 and $291,000 at December 31, 2002 and 2001, respectively, for various oil and gas exploration and production activities. Brigham was also owed $2,800 and $20,000 by Aspect Management Corp., an affiliate of Aspect, at December 31, 2002 and 2001, respectively, for joint venture operations. F-30 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) 17. SUPPLEMENTAL CASH FLOW INFORMATION
YEAR ENDED DECEMBER 31, ------------------------- 2002 2001 2000 ------- ------ ------ (in thousands) Cash paid for interest...................................... $ 3,974 $4,257 $3,894 Noncash investing and financing activities: Increase in current liabilities for deferred loan fees to be paid in future...................................... - 200 - Increase in deferred loan fees for issuance of warrants... - - 2,400 Dividends and accretion on mandatorily redeemable preferred stock........................................ 2,952 2,450 275 Conversion of senior credit facility to common stock...... 10,000 - -
18. OTHER ASSETS AND LIABILITIES Other current assets consist of the following (in thousands):
DECEMBER 31, --------------- 2002 2001 ------ ------ Gas imbalance receivables................................... $3,656 $1,537 Deposits.................................................... 1,909 - Other....................................................... 1,078 873 ------ ------ $6,643 $2,410 ====== ======
Deposits are amounts held by Brigham's derivative counterparty. Other current liabilities consist of the following (in thousands):
DECEMBER 31, ---------------- 2002 2001 ------- ------ Gas imbalance liabilities................................... $ 5,650 $2,717 Derivative liabilities...................................... 3,168 384 Other....................................................... 1,516 1,414 ------- ------ $10,334 $4,515 ======= ======
19. OIL AND NATURAL GAS EXPLORATION AND PRODUCTION ACTIVITIES Oil and natural gas sales reflect the market prices of net production sold or transferred with appropriate adjustments for royalties, net profits interest and other contractual provisions. Lease operating expenses include lifting costs incurred to operate and maintain productive wells and related equipment including such costs as operating labor, repairs and maintenance, materials, supplies and fuel consumed. Production taxes include production and severance taxes. Depletion of oil and natural gas properties relates to capitalized costs incurred in acquisition, exploration and development activities. Results of operations do not include interest expense and general corporate amounts. F-31 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) Costs Incurred and Capitalized Costs The costs incurred in oil and natural gas acquisition, exploration and development activities follow (in thousands):
DECEMBER 31, --------------------------- 2002 2001 2000 ------- ------- ------- Costs incurred for the year: Exploration............................................... $12,693 $18,210 $14,238 Property acquisition...................................... 3,213 3,437 2,540 Development............................................... 13,301 14,353 12,555 Proceeds from participants................................ (703) (135) (40) ------- ------- ------- $28,504 $35,865 $29,293 ======= ======= =======
Costs incurred represent amounts incurred by Brigham for exploration, property acquisition and development activities. Periodically, Brigham will receive proceeds from participants subsequent to project initiation for an assignment of an interest in the project. These payments are represented by "Proceeds from participants" in the table above. During the three years ended December 31, 2002, 2001 and 2000, we spent $11.4 million, $10.9 million and $8.4 million, respectively to develop our proved undeveloped reserves. At December 31, 2002, our standardized measure of discounted future net cash flows includes estimated future development cost of our proved undeveloped reserves for the next three years of $21.7 million, $14.9 million and $5.6 million, respectively, for 2003, 2004 and 2005. Following is a summary of capitalized costs (in thousands) excluded from depletion at December 31, 2002 by year incurred. At this time, Brigham is unable to predict either the timing of the inclusion of these costs and the related natural gas and oil reserves in its depletion computation or their potential future impact on depletion rates.
DECEMBER 31, ---------------------- PRIOR 2002 2001 2000 YEARS TOTAL ------ ------ ---- ------- ------- Property acquisition.............................. $ 682 $ 565 $195 $11,990 $13,432 Exploration....................................... 1,406 418 77 19,838 21,739 Capitalized interest.............................. 516 405 15 1,296 2,232 ------ ------ ---- ------- ------- Total........................................... $2,604 $1,388 $287 $33,124 $37,403 ====== ====== ==== ======= =======
20. OIL AND NATURAL GAS RESERVES AND RELATED FINANCIAL DATA (UNAUDITED) Information with respect to Brigham's oil and natural gas producing activities is presented in the following tables. Reserve quantities, as well as certain information regarding future production and discounted cash flows, were determined by Brigham's independent petroleum consultants and internal petroleum reservoir engineers. Oil and Natural Gas Reserve Data The following tables present Brigham's estimates of its proved oil and natural gas reserves. Brigham emphasizes reserves are approximates and are expected to change as additional information becomes available. Reservoir engineering is a subjective process of estimating underground accumulations of oil and F-32 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Accordingly, there can be no assurance that the reserves set forth herein will ultimately be produced nor can there be assurance that the proved undeveloped reserves will be developed within the periods anticipated. A substantial portion of the reserve balances was estimated utilizing the volumetric method, as opposed to the production performance method.
NATURAL GAS OIL (MMCF) (MBBLS) ------- ------- Proved reserves at December 31, 1999........................ 65,457 3,027 Revisions of previous estimates........................... 83 (554) Extensions, discoveries and other additions............... 17,058 758 Production................................................ (4,431) (361) ------ ----- Proved reserves at December 31, 2000........................ 78,167 2,870 Revisions of previous estimates........................... (1,959) 351 Extensions, discoveries and other additions............... 22,554 1,101 Sales of minerals-in-place................................ (3,402) (106) Production................................................ (6,766) (468) ------ ----- Proved reserves at December 31, 2001........................ 88,594 3,748 Revisions of previous estimates........................... (824) (31) Extensions, discoveries and other additions............... 18,005 599 Sales of minerals-in-place................................ (556) (8) Production................................................ (5,791) (701) ------ ----- Proved reserves at December 31, 2002........................ 99,428 3,607 ====== ===== Proved developed reserves at December 31: 2000...................................................... 39,271 1,802 2001...................................................... 38,633 2,609 2002...................................................... 42,161 2,330
Proved reserves are estimated quantities of natural gas and crude oil, which geological and engineering data indicate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Standardized Measure of Discounted Future Net Cash Inflows and Changes Therein The following table presents a standardized measure of discounted future net cash inflows (in thousands) relating to proved oil and natural gas reserves. Future cash flows were computed by applying year-end prices of oil and natural gas relating to Brigham's proved reserves to the estimated year-end quantities of those reserves. Future price changes were considered only to the extent provided by contractual agreements in existence at year-end. Future production and development costs were computed by estimating those expenditures expected to occur in developing and producing the proved oil and natural gas reserves at the end of the year, based on year-end costs. Actual future cash inflows may vary considerably, and the F-33 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) standardized measure does not necessarily represent the fair value of Brigham's oil and natural gas reserves.
DECEMBER 31, -------------------------------- 2002 2001 2000 --------- -------- --------- Future cash inflows....................................... $ 601,081 $301,201 $ 899,819 Future production costs................................... (82,689) (47,430) (127,308) Future development costs.................................. (48,668) (36,983) (26,987) Future income tax expense................................. (104,724) (34,062) (216,342) --------- -------- --------- Future net cash inflows................................... 365,000 182,726 529,182 10% annual discount for estimated timing of cash flows.... (125,302) (61,802) (169,954) --------- -------- --------- Standardized measure of discounted future net cash flows................................................... $ 239,698 $120,924 $ 359,228 ========= ======== =========
The base sales prices for Brigham's reserves were $4.74 per Mcf for natural gas and $31.25 per Bbl for oil as of December 31, 2002, $2.57 per Mcf for natural gas and $19.84 per Bbl for oil as of December 31, 2001, and $10.42 per Mcf for natural gas and $26.83 per Bbl for oil as of December 31, 2000. These base prices were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate Brigham's reserves at these dates. Changes in the future net cash inflows discounted at 10% per annum follow (in thousands):
DECEMBER 31, -------------------------------- 2002 2001 2000 -------- --------- --------- Beginning of period....................................... $120,924 $ 359,228 $ 113,546 Sales of oil and natural gas produced, net of production costs................................................ (31,475) (27,296) (15,218) Development costs incurred.............................. 8,625 8,310 5,308 Extensions and discoveries.............................. 60,872 41,278 295,239 Sales of minerals-in-place.............................. (1,064) (22,476) - Net change of prices and production costs............... 136,808 (322,047) 175,018 Change in future development costs...................... (8,000) (15,956) 6,990 Changes in production rates and other................... (17,003) (29,545) (83,322) Revisions of quantity estimates......................... (2,876) (22,676) (12,262) Accretion of discount................................... 14,681 49,766 11,447 Change in income taxes.................................. (41,794) 102,338 (137,518) -------- --------- --------- End of period............................................. $239,698 $ 120,924 $ 359,228 ======== ========= =========
21. QUARTERLY FINANCIAL DATA (UNAUDITED)
YEAR ENDED DECEMBER 31, 2002 --------------------------------------------- QUARTER 1 QUARTER 2 QUARTER 3 QUARTER 4 --------- --------- --------- --------- (IN THOUSANDS, EXCEPT PER SHARE DATA) Revenue............................................... $ 6,444 $8,786 $9,449 $10,497 Operating income...................................... 1,016 2,278 3,424 2,717 Net income (loss)..................................... (1,332) 61 989 (294) Net income (loss) per share: Basic............................................... $ (0.08) $ 0.00 $ 0.06 $ (0.02) Diluted............................................. $ (0.08) $ 0.00 $ 0.06 $ (0.02)
F-34 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
YEAR ENDED DECEMBER 31, 2001 --------------------------------------------- QUARTER 1 QUARTER 2 QUARTER 3 QUARTER 4 --------- --------- --------- --------- (IN THOUSANDS, EXCEPT PER SHARE DATA) Revenue............................................... $7,043 $10,504 $8,871 $ 6,130 Operating income (loss)............................... 2,425 4,876 3,296 (572) Net income (loss)..................................... 424 8,327 2,947 (2,460) Net income (loss) per share: Basic............................................... $ 0.03 $ 0.52 $ 0.18 $ (0.15) Diluted*............................................ $ 0.02 $ 0.30 $ 0.13 $ (0.15)
- --------------------------- * As discussed further in Note 10, the diluted earnings per share data for 2001 Quarter 2 and 3 have been restated. F-35 BRIGHAM EXPLORATION COMPANY CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA)
JUNE 30, DECEMBER 31, 2003 2002 ----------- ------------ (UNAUDITED) ASSETS Current assets: Cash and cash equivalents................................. $ 12,231 $ 15,318 Accounts receivable....................................... 9,051 11,361 Gas imbalance receivable.................................. 6,325 3,656 Other current assets...................................... 1,003 2,987 -------- -------- Total current assets.................................... 28,610 33,322 -------- -------- Oil and natural gas properties, net (full cost method)...... 177,306 164,980 Other property and equipment, net........................... 1,263 1,234 Deferred loan fees.......................................... 2,843 2,391 -------- -------- Other noncurrent assets..................................... 648 132 -------- -------- $210,670 $202,059 ======== ======== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable.......................................... $ 10,883 $ 14,486 Royalties payable......................................... 6,476 4,508 Accrued drilling costs.................................... 2,135 2,727 Participant advances received............................. 1,339 1,955 Gas imbalance liability................................... 11,289 5,650 Other current liabilities................................. 3,701 4,684 -------- -------- Total current liabilities............................... 35,823 34,010 -------- -------- Senior credit facility...................................... 53,000 60,000 Senior subordinated notes................................... 22,382 21,797 Other noncurrent liabilities................................ 2,486 186 Commitments and contingencies Series A Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and redemption value, 2,250,000 shares authorized, 1,835,860 and 1,765,132 shares issued and outstanding at June 30, 2003 and December 31, 2002, respectively.............................................. 21,144 19,540 Series B Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and redemption value, 1,000,000 shares authorized, 521,313 and 501,226 shares issued and outstanding at June 30, 2003 and December 31, 2002, respectively.............................................. 5,196 4,777 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, 21,706,692 and 20,618,161 shares issued and 20,562,410 and 19,479,979 shares outstanding at June 30, 2003 and December 31, 2002, respectively................ 217 206 Additional paid-in capital................................ 94,104 93,436 Treasury stock, at cost; 1,144,282 and 1,138,182 shares at June 30, 2003 and December 31, 2002, respectively....... (4,292) (4,282) Unearned stock compensation............................... (2,163) (212) Accumulated other comprehensive (loss) income............. (2,799) (3,047) Accumulated deficit....................................... (14,428) (24,352) -------- -------- Total stockholders' equity.............................. 70,639 61,749 -------- -------- $210,670 $202,059 ======== ========
The accompanying notes are an integral part of these consolidated financial statements. F-36 BRIGHAM EXPLORATION COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER SHARE DATA) (UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ------------------ ----------------- 2003 2002 2003 2002 -------- ------- ------- ------- Revenues: Oil and natural gas sales......................... $12,127 $8,769 $26,766 $15,203 Other revenue..................................... 43 17 81 27 ------- ------ ------- ------- 12,170 8,786 26,847 15,230 ------- ------ ------- ------- Costs and expenses: Lease operating................................... 1,270 796 2,244 1,667 Production taxes.................................. 806 499 1,744 852 General and administrative........................ 1,187 1,718 2,326 2,682 Depletion of oil and natural gas properties....... 3,799 3,394 7,901 6,531 Depreciation and amortization..................... 160 101 257 204 Accretion of discount on asset retirement obligations.................................... 37 - 71 - ------- ------ ------- ------- 7,259 6,508 14,543 11,936 ------- ------ ------- ------- Operating income............................. 4,911 2,278 12,304 3,294 ------- ------ ------- ------- Other income (expense): Interest income................................... 7 74 28 93 Interest expense.................................. (1,224) (1,649) (2,506) (3,070) Other income (expense)............................ (281) 79 (170) (169) ------- ------ ------- ------- (1,498) (1,496) (2,648) (3,146) ------- ------ ------- ------- Income before income taxes and cumulative effect of change in accounting principle.................... 3,413 782 9,656 148 Income taxes........................................ - - - - ------- ------ ------- ------- Income before cumulative effect of change in accounting principle.............................. 3,413 782 9,656 148 Cumulative effect of change in accounting principle......................................... - - 268 - ------- ------ ------- ------- Net income.......................................... 3,413 782 9,924 148 Less accretion and dividends on redeemable preferred stock............................................. 1,028 721 2,023 1,419 ------- ------ ------- ------- Net income (loss) available to common stockholders...................................... $ 2,385 $ 61 $ 7,901 $(1,271) ======= ====== ======= ======= Net income (loss) per share available to common stockholders: Basic Income (loss) before cumulative effect of change in accounting principle............... $ 0.12 $ 0.00 $ 0.39 $ (0.08) Cumulative effect of change in accounting principle.................................... - - 0.01 - ------- ------ ------- ------- $ 0.12 $ 0.00 $ 0.40 $ (0.08) ======= ====== ======= ======= Diluted Income (loss) before cumulative effect of change in accounting principle............... $ 0.10 $ 0.00 $ 0.29 $ (0.08) Cumulative effect of change in accounting principle.................................... - - 0.01 - ------- ------ ------- ------- $ 0.10 $ 0.00 $ 0.30 $ (0.08) ======= ====== ======= ======= Weighted average shares outstanding: Basic............................................. 20,087 16,038 19,898 16,027 ======= ====== ======= ======= Diluted........................................... 30,037 17,760 32,090 16,027 ======= ====== ======= =======
The accompanying notes are an integral part of these consolidated financial statements. F-37 BRIGHAM EXPLORATION COMPANY CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (IN THOUSANDS) (UNAUDITED)
ACCUMULATED OTHER COMMON STOCK ADDITIONAL UNEARNED COMPREHENSIVE ---------------- PAID IN TREASURY STOCK INCOME ACCUMULATED SHARES AMOUNTS CAPITAL STOCK COMPENSATION (LOSS) DEFICIT ------ ------- ---------- -------- ------------ ------------- ------------ Balance, December 31, 2002.................... 20,618 $206 $93,436 $(4,282) $ (212) $(3,047) $(24,352) Comprehensive income: Net income.............. - - - - - - 9,924 Deferred hedge gains and losses, net of tax: Unrealized gain on cash flow hedges.... - - - - - 172 - Net losses included in net income.......... - - - - - 76 - Comprehensive income........... Exercise of employee stock options................. 225 2 592 - - - - Issuance of stock options................. - - 296 - (296) - - Issuance of restricted stock................... - - 1,831 - (1,831) - - Expiration of employee stock options........... - - (19) - - - - Forfeitures of restricted stock................... - - - (10) 2 - - Warrants exercised for common stock............ 864 9 (9) - - - - In kind dividends on Series A mandatorily redeemable preferred stock................... - - (1,415) - - - - Accretion on Series A mandatorily redeemable preferred stock......... - - (189) - - - - In kind dividends on Series B mandatorily redeemable preferred stock................... - - (402) - - - - Accretion on Series B mandatorily redeemable preferred stock......... - - (17) - - - - Amortization of unearned stock compensation...... - - - - 174 - - ------ ---- ------- ------- ------- ------- -------- Balance, June 30, 2003.... 21,707 $217 $94,104 $(4,292) $(2,163) $(2,799) $(14,428) ====== ==== ======= ======= ======= ======= ======== TOTAL STOCKHOLDERS' EQUITY ------------- Balance, December 31, 2002.................... $61,749 Comprehensive income: Net income.............. 9,924 Deferred hedge gains and losses, net of tax: Unrealized gain on cash flow hedges.... 172 Net losses included in net income.......... 76 ------- Comprehensive income........... 10,172 Exercise of employee stock options................. 594 Issuance of stock options................. - Issuance of restricted stock................... - Expiration of employee stock options........... (19) Forfeitures of restricted stock................... (8) Warrants exercised for common stock............ - In kind dividends on Series A mandatorily redeemable preferred stock................... (1,415) Accretion on Series A mandatorily redeemable preferred stock......... (189) In kind dividends on Series B mandatorily redeemable preferred stock................... (402) Accretion on Series B mandatorily redeemable preferred stock......... (17) Amortization of unearned stock compensation...... 174 ------- Balance, June 30, 2003.... $70,639 =======
The accompanying notes are an integral part of these consolidated financial statements. F-38 BRIGHAM EXPLORATION COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS) (UNAUDITED)
SIX MONTHS ENDED JUNE 30, ------------------- 2003 2002 -------- -------- Cash flows from operating activities: Net income................................................ $ 9,924 $ 148 Adjustments to reconcile net income to cash provided by operating activities: Depletion of oil and natural gas properties.......... 7,901 6,531 Depreciation and amortization........................ 257 204 Interest paid through issuance of additional senior subordinated notes.................................. 585 497 Amortization of deferred loan fees and debt issuance costs............................................... 533 585 Market value adjustment for derivative instruments... 170 (384) Accretion of discount on asset retirement obligations......................................... 71 - Cumulative effect of change in accounting principle........................................... (268) - Stock option compensation expense.................... - 596 Changes in operating assets and liabilities: Accounts receivable............................... 2,310 (2,637) Gas imbalance receivable and other current assets.......................................... (766) (1,283) Accounts payable.................................. (3,603) 4,052 Royalties payable................................. 1,968 1,214 Participant advances received..................... (616) 113 Gas imbalance and other current liabilities....... 5,090 417 Other noncurrent assets and liabilities........... (38) 3 -------- -------- Net cash provided by operating activities......... 23,518 10,056 -------- -------- Cash flows from investing activities: Additions to oil and natural gas properties............ (18,841) (13,047) Proceeds from sale of oil and natural gas properties... 352 617 Additions to other property and equipment.............. (209) (183) Decrease in drilling advances paid..................... (516) (580) -------- -------- Net cash used by investing activities............. (19,214) (13,193) -------- -------- Cash flows from financing activities: Repayment of senior credit facility.................... (7,000) - Deferred loan fees paid................................ (985) (360) Proceeds from issuance of senior subordinated notes.... - 4,000 Proceeds from exercise of employee stock options....... 594 107 Principal payments on capital lease obligations........ - (22) -------- -------- Net cash provided (used) by financing activities...................................... (7,391) 3,725 -------- -------- Net increase (decrease) in cash and cash equivalents........ (3,087) 588 Cash and cash equivalents, beginning of year................ 15,318 5,112 -------- -------- Cash and cash equivalents, end of period.................... $ 12,231 $ 5,700 ======== ========
The accompanying notes are an integral part of these consolidated financial statements. F-39 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 Anadarko Basin, the Texas Gulf Coast and West Texas. 2. BASIS OF PRESENTATION The accompanying financial statements include the accounts of Brigham and its wholly-owned subsidiaries, and its proportionate share of assets, liabilities and income and expenses of the limited partnerships in which Brigham, or any of its subsidiaries, has a participating interest. All significant intercompany accounts and transactions have been eliminated. The accompanying consolidated financial statements are unaudited, and in the opinion of management, reflect all adjustments that are necessary for a fair presentation of the financial position and results of operations for the periods presented. All such adjustments are of a normal and recurring nature. The results of operations for the periods presented are not necessarily indicative of the results to be expected for the entire year. The unaudited consolidated financial statements should be read in conjunction with Brigham's 2002 Annual Report on Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Certain reclassifications have been made to prior year amounts to conform to current year presentation. 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 June 1, 2001, Leonel Garcia, a landowner in Brooks County, Texas, filed suit against Brigham claiming that Brigham transported natural gas under his property through an existing pipeline without his consent. Mr. Garcia claimed $1.2 million in actual damages and $3 million in exemplary damages. In May 2002, Brigham settled the case through mediation for a cash payment of $125,000. Subsequently, Brigham began using an alternate pipeline. On November 20, 2001, Brigham filed a lawsuit in the District Court of Travis County, Texas against Steve Massey Company, Inc. ("Massey") for breach of contract. The Petition claims Massey furnished defective casing to Brigham, which ultimately led to the casing failure of the Palmer "347" No. 5 well (the "Palmer #5") and the loss of the Palmer #5 as a producing well. Brigham believes the amount of damages incurred due to the loss of the Palmer #5 may exceed $5 million. Massey joined as additional defendants to the lawsuit other parties that had responsibility for the manufacture, importation or fabrication of the casing for its use in the Palmer #5. The case is currently in discovery. A trial has been set for January 2004. On February 20, 2002, Massey filed an Original Petition to Foreclose Lien in Brooks County, Texas. Massey's Petition claims Brigham breached its contract for failure to pay for the casing it furnished Brigham for the Palmer #5 (and that Brigham's claim is defective, forming the basis of the lawsuit F-40 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) (UNAUDITED) described in the paragraph above). Massey's Petition claims Brigham owes Massey a total of $445,819. Brigham's Motion to Transfer Venue to Travis County, Texas, and Motion to Consolidate Massey's claim with Brigham's suit against Massey pending in Travis County, were recently granted. If Massey is successful in its claim, Massey would have the right to foreclose its lien against the well, associated equipment and Brigham's leasehold interest. At this point in time, Brigham cannot predict the outcome of either its Travis County case or Massey's claim. 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 investigated the accident and issued three citations and imposed a total of $168,000 in fines. Brigham is appealing the citations, but at this time, cannot predict the outcome of that appeal. 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 on July 11, 2002. Plaintiffs are seeking unspecified both actual and punitive damages. Brigham cannot predict the outcome of this case, however Brigham believes it has sufficient insurance to cover the claim. The operator of the Stonehocker #1 is disputing Brigham's ownership interest in the well. Brigham expects the Oklahoma Corporation Commission to rule on the dispute in late August or early September 2003. The Stonehocker #1 began producing to sales in early July 2003 at a rate of approximately 7.0 MMcf of natural gas per day, or approximately 0.9 MMcfed net to Brigham if Brigham prevails. A company that relinquished its working interest in the Nold #1S well as a result of a non-consent election in the re-completion of the well is asserting that it did not relinquish its interest, but rather became subject only to a 400 percent payout provision. If the issue were to be litigated, and the ruling unfavorable, Brigham would be required to distribute revenues in excess of expenses for the disputed interest periods subsequent to payout. The financial statement impact of an unfavorable ruling would be an out of period reduction in revenue and expenses, with an overall negative impact on net income of approximately $0.7 million at June 30, 2003. 4. NET INCOME (LOSS) PER SHARE Basic earnings per share are computed by dividing net income (loss) available to common stockholders by the weighted average number of common shares outstanding for the period. The computation of diluted net income (loss) per share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that would then share in the earnings of Brigham. F-41 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) (UNAUDITED) The following table reconciles the numerators and denominators of the basic and diluted earnings per common share computations for net income (loss) available to common stockholders for the three and six months ended June 30, 2003 and 2002:
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, --------------------- ------------------- 2003 2002 2003 2002 --------- --------- -------- -------- (in thousands, except per share amounts) Basic EPS: Income (loss) available to common stockholders before cumulative change in accounting principle...................................... $ 2,385 $ 61 $ 7,633 $(1,271) Cumulative change in accounting principle........ - - 268 - ------- ------- ------- ------- Income (loss) available to common stockholders................................ $ 2,385 $ 61 $ 7,901 $(1,271) ======= ======= ======= ======= Common shares outstanding...................... 20,087 16,038 19,898 16,027 ======= ======= ======= ======= Basic EPS Income (loss) available to common stockholders before change in accounting principle.......... $ 0.12 $ 0.00 $ 0.39 $ (0.08) Cumulative change in accounting principle........ - - 0.01 - ------- ------- ------- ------- $ 0.12 $ 0.00 $ 0.40 $ (0.08) ======= ======= ======= ======= Diluted EPS: Income (loss) available to common stockholders before cumulative change in accounting principle...................................... $ 2,385 $ 61 $ 7,633 $(1,271) Cumulative change in accounting principle........ - - 268 - ------- ------- ------- ------- Income (loss) available to common stockholders................................ 2,385 61 7,901 (1,271) Adjustments for assumed conversions: Dividends and accretion on mandatorily redeemable preferred stock(1)............... 677 - 1,795 - ------- ------- ------- ------- 677 - 1,795 - ------- ------- ------- ------- Income (loss) available to common stockholders before change in accounting principle--diluted... 3,062 61 9,428 (1,271) Cumulative change in accounting principle........ - - 268 - ------- ------- ------- ------- Income (loss) available to common stockholders--diluted....................... $ 3,062 $ 61 $ 9,696 $(1,271) ======= ======= ======= ======= Common shares outstanding........................... 20,087 16,038 19,898 16,027 Effect of dilutive securities: Warrants......................................... 459 1,227 600 - Mandatorily redeemable preferred stock........... 8,966 - 11,071 - Stock options.................................... 525 495 521 - ------- ------- ------- ------- Potentially dilutive common shares.................. 9,950 1,722 12,192 - ------- ------- ------- ------- Adjusted common shares outstanding diluted....... 30,037 17,760 32,090 16,027 ======= ======= ======= =======
F-42 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) (UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, --------------------- ------------------- 2003 2002 2003 2002 --------- --------- -------- -------- (in thousands, except per share amounts) Diluted EPS Income (loss) available to common stockholders before change in accounting principle.......... $ 0.10 $ 0.00 $ 0.29 $ (0.08) Change in accounting principle................... - - 0.01 - ------- ------- ------- ------- $ 0.10 $ 0.00 $ 0.30 $ (0.08) ======= ======= ======= =======
- --------------------------- (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 2.1 million shares and 14.8 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, 2003 and 2002, respectively, and options and warrants to purchase 13,000 shares and 19.0 million 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, 2003 and 2002, respectively, because the effects would have been antidilutive. 5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES Brigham utilizes various commodity swap and option contracts to (i) reduce the effects of volatility in price changes on the oil and natural gas commodities it produces and sells, (ii) support its capital budgeting plans, and (iii) lock-in prices to protect the economics related to certain capital projects. At June 30, 2003, the fair value of hedging contracts included in other current assets was approximately $0.1 million and the fair value of hedging contracts included in other liabilities was approximately $3.0 million of which approximately $0.3 million was classified as noncurrent. For the three months ended June 30, 2003 and 2002, Brigham recognized cash settlement losses of $1.7 million and $0.6 million, respectively, which were recorded as a reduction of oil and natural gas sales. For the six months ended June 30, 2003 and 2002, Brigham recognized cash settlement losses of $5.0 million and $0.3 million, respectively, which were recorded as a reduction of oil and natural gas sales. For the three months ended June 30, 2003 and 2002, ineffectiveness associated with Brigham's derivative commodity instruments designated as cash flow hedges decreased earnings by approximately $0.2 million and $0, respectively. For the six months ended June 30, 2003 and 2002, ineffectiveness associated with Brigham's derivative commodity instruments designated as cash flow hedges decreased earnings by approximately $0.1 million and $0, respectively. These amounts are included in other income (expense). Based on market prices at June 30, 2003, approximately $(2.6) million of the balance in accumulated other comprehensive income (loss) would be expected to transfer to earnings during the next 12 months. Derivative instruments not qualifying as hedging contracts are recorded at fair value on the balance sheet. At each balance sheet date, the value of derivatives not qualifying as hedging contracts is adjusted to reflect current fair value and any gains or losses are recognized as other income or expense. At June 30, 2003 and 2002, there were no derivatives not qualifying as hedging contracts. For the three months ended June 30, 2003, and 2002, other income (expense) included $0 and $0.6 million, respectively, in non-cash gains related to changes in the fair values of these derivative contracts. For the six months ended June 30, F-43 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) (UNAUDITED) 2003, and 2002, other income (expense) included $0 and $0.4 million, respectively, in non-cash gains related to changes in the fair values of these derivative contracts and $0 and $0.6 million, respectively, in cash losses related to cash settlement payments made by Brigham to the counterparty. Natural Gas Derivative Contracts The following table sets forth Brigham's outstanding natural gas hedging contracts and the weighted average NYMEX prices for those contracts as of June 30, 2003:
FIRST SECOND THIRD FOURTH OUTSTANDING QUARTER QUARTER QUARTER QUARTER AVERAGE -------- -------- -------- -------- ----------- 2003--Swap Contracts Volume (MMbtu)........................ 598,000 414,000 506,000 Price per MMBtu....................... $ 3.87 $ 4.04 $ 3.94 2003--Floors Volume (MMbtu)........................ 460,000 460,000 460,000 Price per MMBtu....................... $ 4.50 $ 4.50 $ 4.50 2004--Swap Contracts Volume (MMbtu)........................ 295,750 227,500 138,000 92,000 188,313 Price per MMBtu....................... $ 4.96 $ 4.25 $ 4.18 $ 4.36 $ 4.53 2004--Collars Volume (MMbtu)........................ 273,000 182,000 138,000 92,000 Ceiling price per Mmbtu............... $ 9.90 $ 5.45 $ 5.39 $ 5.62 Floor price per MMbtu................. $ 4.00 $ 4.00 $ 4.00 $ 4.00 2005--Collars Volume (MMbtu)........................ 90,000 91,000 Ceiling price per Mmbtu............... $ 7.25 $ 5.40 Floor price per MMbtu................. $ 4.00 $ 4.00
F-44 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) (UNAUDITED) Oil Derivative Contracts The following table sets forth Brigham's outstanding oil hedging contracts and the weighted average NYMEX prices for those contracts as of June 30, 2003:
FIRST SECOND THIRD FOURTH OUTSTANDING QUARTER QUARTER QUARTER QUARTER AVERAGE ------- ------- ------- ------- ----------- 2003--Swap Contracts Volume (Bbl).............................. 55,200 41,400 52,675 Price per Bbl............................. $ 23.77 $ 23.21 $ 24.18 2004--Swap Contracts Volume (Bbl).............................. 29,575 20,475 13,800 9,200 18,263 Price per Bbl............................. $ 25.35 $ 24.52 $ 23.91 $ 23.80 $ 24.65 2004--Collars Volume (Bbl).............................. 13,650 9,100 9,200 9,200 Ceiling price per Bbl..................... $ 27.74 $ 26.64 $ 25.91 $ 25.39 Floor price per Bbl....................... $ 23.00 $ 23.00 $ 23.00 $ 23.00 2005--Collars Volume (Bbl).............................. 9,000 Ceiling price per Bbl..................... $ 25.07 Floor price per Bbl....................... $ 23.00
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, 2003 and 2002:
THREE MONTHS SIX MONTHS ENDED ENDED JUNE 30, JUNE 30, ---------------- ---------------- 2003 2002 2003 2002 ------- ------ ------- ------ NATURAL GAS Average price per Mcf as reported (including hedging results)........................................... $ 4.72 $ 3.30 $ 5.12 $ 2.92 Average price per Mcf realized (excluding hedging results)........................................... $ 5.60 $ 3.51 $ 6.40 $ 2.91 Increase (decrease) in revenue (in thousands)......... $(1,341) $ (321) $(3,847) $ 18 OIL Average price per Bbl as reported (including hedging results)........................................... $ 27.45 $23.90 $ 28.39 $21.95 Average price per Bbl realized (excluding hedging results)........................................... $ 29.52 $25.59 $ 31.37 $22.97 Decrease in revenue (in thousands).................... $ (370) $ (271) $(1,198) $ (321)
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 F-45 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) (UNAUDITED) recognized. Brigham has asset retirement obligations associated with the future plugging and abandonment of proved properties and related facilities. Prior to the adoption of SFAS 143, Brigham assumed salvage value approximated plugging and abandonment costs. As such, estimated salvage value was not excluded from depletion and plugging and abandonment costs were not accrued for over the life of the oil and gas properties. The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment to record (i) a $1.4 million increase in the carrying values of proved properties, (ii) a $0.8 million decrease in accumulated depletion of oil and natural gas properties and (iii) a $1.9 million increase in noncurrent abandonment liabilities. The net impact of items (i) through (iii) was to record a gain of $0.3 million as a cumulative effect adjustment of a change in accounting principle in Brigham's consolidated statements of operations upon adoption on January 1, 2003. The following pro forma data summarizes Brigham's net income (loss) and net income (loss) per share as if Brigham had applied the provisions of SFAS 143 on January 1, 2002, including an associated pro forma asset retirement obligation on that date of $1.8 million:
THREE MONTHS SIX MONTHS ENDED ENDED JUNE 30, JUNE 30, -------------- ---------------- 2003 2002 2003 2002 ------ ----- ------ ------- (in thousands, except per share amounts) Net income (loss), as reported............................ $2,385 $ 61 $7,901 $(1,271) Pro forma adjustments to reflect retroactive adoption of SFAS 143................................................ - 21 (268) 42 Pro forma adjustments to reflect accretion expense........ - (34) - (66) ------ ----- ------ ------- Pro forma net income (loss)............................... $2,385 $ 48 $7,633 $(1,295) ====== ===== ====== ======= Net income (loss) per share: Basic--as reported...................................... $ 0.12 $0.00 $ 0.40 $ (0.08) ====== ===== ====== ======= Basic--pro forma........................................ $ 0.12 $0.00 $ 0.39 $ (0.08) ====== ===== ====== ======= Diluted--as reported.................................... $ 0.10 $0.00 $ 0.30 $ (0.08) ====== ===== ====== ======= Diluted--pro forma...................................... $ 0.10 $0.00 $ 0.29 $ (0.08) ====== ===== ====== =======
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, 2003:
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, 2003 JUNE 30, 2003 ------------------ ---------------- (in thousands) Beginning asset retirement obligations................. $1,965 $1,931 Liabilities incurred................................... 60 60 Accretion expense...................................... 37 71 ------ ------ Ending asset retirement obligations.................... $2,062 $2,062 ====== ======
F-46 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) (UNAUDITED) 7. STOCK BASED COMPENSATION Brigham accounts for employee stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees". Accordingly, Brigham has adopted the disclosure-only provisions of Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"). Had compensation cost for Brigham's stock options been determined based on the fair market value at the grant dates of the awards consistent with the methodology prescribed by SFAS 123 as amended by SFAS 148, Brigham's net income (loss) and net income (loss) per share for the three and six month periods ended June 30, 2003 and 2002 would have been the pro forma amounts indicated below:
THREE MONTHS SIX MONTHS ENDED ENDED JUNE 30, JUNE 30, ------------------ -------------------- 2003 2002 2003 2002 -------- ------- -------- --------- (in thousands, except per share amounts) Net income (loss) available to common stockholders--basic: As reported.......................................... $2,385 $ 61 $7,901 $(1,271) Add back: Stock compensation expense previously included in net income............................ 3 (14) 6 (30) Effect of total employee stock-based compensation expense, determined under fair value method for all awards........................................ (117) (107) (159) (201) ------ ----- ------ ------- Pro forma............................................ $2,271 $ (60) $7,748 $(1,502) ====== ===== ====== ======= Net income (loss) available to common stockholders--diluted: As reported.......................................... $3,062 $ 61 $9,696 $(1,271) Add back: Stock compensation expense previously included in net income............................ 3 (14) 6 (30) Effect of total employee stock-based compensation expense, determined under fair value method for all awards........................................ (117) (107) (159) (201) ------ ----- ------ ------- Pro forma............................................ $2,948 $ (60) $9,543 $(1,502) ====== ===== ====== ======= Net income (loss) per share: Basic: As reported....................................... $ 0.12 $0.00 $ 0.40 $ (0.08) Pro forma......................................... 0.11 0.00 0.39 (0.09) Diluted: As reported....................................... $ 0.10 $0.00 $ 0.30 $ (0.08) Pro forma......................................... 0.10 0.00 0.30 (0.09)
8. RECENT ACCOUNTING PRONOUNCEMENTS In May 2003, the FASB issued Statement of Financial Accounting Standards No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" (SFAS No. 150). SFAS No. 150 requires an issuer to classify certain financial instruments, such as mandatorily redeemable preferred stock, as liabilities (or assets in some circumstances). We adopted this standard as required on July 1, 2003. Upon adoption, Series A preferred stock and Series B preferred stock will be reclassified as liabilities on the balance sheet. The combined carrying value of the preferred stock is $26.3 million at F-47 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) (UNAUDITED) June 30, 2003. We are continuing to assess the impact of SFAS No. 150 and may be required to make other adjustments that will have an effect on our consolidated financial position, results of operations or cash flows. 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 us on July 1, 2001 and January 1, 2002, respectively. SFAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. Additionally, SFAS 141 requires companies to disaggregate and report separately from goodwill certain intangible assets. SFAS 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under SFAS 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment. The appropriate application of SFAS 141 and 142 to oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves is unclear. Depending on how the accounting and disclosure literature is clarified, these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves for both undeveloped and developed leaseholds may be classified separately from oil and gas properties, as intangible assets on our balance sheets. Additional disclosures required by SFAS 141 and 142 would be included in the notes to financial statements. Historically, we, like many other oil and gas companies, have included these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves as part of the oil and gas properties, even after SFAS 141 and 142 became effective. This interpretation of SFAS 141 and 142 would only affect our balance sheet classification of oil and gas leaseholds. Our results of operations and cash flows would not be affected, since these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves would continue to be amortized in accordance with accounting rules for oil and gas companies provided in Statement of Financial Accounting Standards No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies". At June 30, 2003 we had undeveloped leaseholds of approximately $4.0 million that would be classified on our balance sheet as "intangible undeveloped leasehold" and developed leaseholds of an estimated $0.1 million that would be classified as "intangible developed leaseholds" if we applied the interpretation currently being deliberated. This classification would require us to make the disclosures set forth under FAS 142 related to these interests. We will continue to classify our oil and gas leaseholds as tangible oil and gas properties until further guidance is provided. F-48 APPENDIX A-1 TO PROSPECTUS SUMMARY RESERVE REPORT OF CAULEY, GILLESPIE & ASSOCIATES, INC. AS OF DECEMBER 31, 2002 A-1 CAWLEY, GILLESPIE & ASSOCIATES, INC. PETROLEUM CONSULTANTS 306 West Seventh Street Suite 625 Suite 302 1000 Louisiana Street Fort Worth, Texas 76102-4987 Houston, Texas 77002-5008 Telephone (817) 336-2461 Telephone (713) 651-9944 Facsimile (817) 877-3728 Facsimile (713) 651-9980
February 18, 2003 Mr. Lance Langford Brigham Exploration Company 6300 Bridgepoint Parkway Building 2, Suite 500 Austin, Texas 78730 Re: Evaluation Summary BRIGHAM OIL & GAS, L.P. INTERESTS Proved Reserves Kansas, New Mexico, Oklahoma and Texas As of December 31, 2002 Pursuant to the Guidelines of the Securities and Exchange Commission for Reporting Corporate Reserves and Future Net Revenue Dear Mr. Langford: As requested, we are submitting our reserve estimates and economic forecasts attributable to the subject interests. The evaluated properties are located in various counties in Kansas, Montana, New Mexico, Oklahoma and Texas. This report was prepared using constant prices and costs and conforms to the guidelines of the Securities and Exchange Commission (SEC). The proved reserves and economics for all categories are summarized as follows:
PROVED ---------------------------------------- TOTAL DEVELOPED UNDEVELOPED ------------ ----------- ----------- Net Reserves Oil -- Bbl......................................... 3,607,066 2,330,100 1,276,966 Gas -- Mcf......................................... 99,427,867 42,160,618 57,267,250 Future Net Cash Flow -- $............................ 469,787,469 222,243,739 247,480,203 Discounted @ 10% -- $........................... 307,374,031 151,013,753 156,360,266
Of the proved developed reserves, 46,113.96 MMCFE are attributable to currently producing zones in existing wells and 10,027.27 MMCFE are attributable to zones in existing wells that are not currently producing. Future revenue is prior to deducting state production taxes and Ad Valorem taxes. Future net cash flow is after deducting these taxes, future capital costs and operating expenses, but before consideration of federal income taxes. In accordance with SEC guidelines, the future net cash flow has been discounted at an annual rate of ten percent to determine its "present worth". The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties. A-2 BRIGHAM EXPLORATION COMPANY (SEC CASE) FEBRUARY 18, 2003 PAGE 2 The oil reserves include oil and condensate. Oil volumes are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in thousands of standard cubic feet (Mcf) at contract temperature and pressure base. The net MCFE production is based on one barrel of oil being the equivalent of six Mcf. Our estimates are for proved reserves only and do not include any probable or possible reserves nor have any values been attributed to interest in acreage beyond the location for which undeveloped reserves have been estimated. The base oil and gas prices being received at December 31, 2002 were $31.25/bbl and $4.740/Mcf, adjusted for differentials. All economic factors were held constant in accordance with SEC guidelines. An on-site field inspection of the properties has not been performed nor have the mechanical operation or condition of the wells and their related facilities been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have not been included. The reserve classifications and the economic considerations used herein conform to the criteria of the Securities and Exchange Commission as defined in page 1 of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. All estimates represent our best judgment based on the data available at the time of preparation. It should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts. Additionally, the prices and costs may vary from those utilized which may increase or decrease both the volume and future net revenue. Ownership was accepted as furnished and has not been independently confirmed. Oil and gas price differentials, gas shrinkage, lease operating expenses and investments were furnished by Brigham and were verified on a spot-check basis. We are independent registered professional engineers and geologists. We do not own an interest in the properties or Brigham Exploration Company and are not employed on a contingent basis. Our work-papers and related data utilized in the preparation of these estimates are available in our office. Yours very truly, Cawley, Gillespie & Associates, Inc. /s/ Aaron Cawley -------------------------------------- Aaron Cawley, P.E. President A-3 - -------------------------------------------------------------------------------- (Brigham Exploration Company Logo) 9,000,000 SHARES COMMON STOCK --------------------------- PROSPECTUS --------------------------- September 17, 2003 CIBC WORLD MARKETS RAYMOND JAMES JOHNSON RICE & COMPANY L.L.C. - -------------------------------------------------------------------------------- YOU SHOULD RELY ONLY ON THE INFORMATION CONTAINED OR INCORPORATED BY REFERENCE IN THIS PROSPECTUS. NO DEALER, SALESPERSON OR OTHER PERSON IS AUTHORIZED TO GIVE INFORMATION THAT IS NOT CONTAINED IN THIS PROSPECTUS. THIS PROSPECTUS IS NOT AN OFFER TO SELL NOR IS IT SEEKING AN OFFER TO BUY THESE SECURITIES IN ANY JURISDICTION WHERE THE OFFER OR SALE IS NOT PERMITTED. THE INFORMATION CONTAINED IN THIS PROSPECTUS IS CORRECT ONLY AS OF THE DATE OF THIS PROSPECTUS, REGARDLESS OF THE TIME OF THE DELIVERY OF THIS PROSPECTUS OR ANY SALE OF THESE SECURITIES. -----END PRIVACY-ENHANCED MESSAGE-----