-----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, WawappayoA9G2ZWlwaxRyIgKciIJwHFDUnTAJGGSCcVc6tQxCqlU0x4ds4VcVFkZ HtjaZ+AEeRhEKsqaTtJZ8w== 0001047469-99-024565.txt : 19990621 0001047469-99-024565.hdr.sgml : 19990621 ACCESSION NUMBER: 0001047469-99-024565 CONFORMED SUBMISSION TYPE: 424B5 PUBLIC DOCUMENT COUNT: 1 FILED AS OF DATE: 19990618 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BASIN EXPLORATION INC CENTRAL INDEX KEY: 0000827795 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 841143307 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B5 SEC ACT: SEC FILE NUMBER: 333-36143 FILM NUMBER: 99648372 BUSINESS ADDRESS: STREET 1: 370 SEVENTEENTH ST STE 1800 CITY: DENVER STATE: CO ZIP: 80202 BUSINESS PHONE: 3036858000 MAIL ADDRESS: STREET 2: 370 SEVENTEENTH STREET SUITE 1800 CITY: DENVER STATE: CO ZIP: 80202 424B5 1 424B5 FILED PURSUANT TO RULE 424(b)(5) REGISTRATION NO. 333-36143 Prospectus Supplement to Prospectus dated October 2, 1997. [LOGO] 4,000,000 Shares BASIN EXPLORATION, INC. Common Stock ------------------ Basin Exploration, Inc. is offering 3,750,000 of the shares to be sold in the offering. The selling stockholder is offering an additional 250,000 shares to be sold in the offering. Basin will not receive any of the proceeds from the sale of shares sold by the selling stockholder. Basin's common stock is quoted on the Nasdaq National Market under the trading symbol "BSNX". The last reported sale price of Basin's common stock on June 17, 1999 was $16.69 per share. SEE "RISK FACTORS" BEGINNING ON PAGE S-11 TO READ ABOUT FACTORS YOU SHOULD CONSIDER BEFORE BUYING SHARES OF THE COMMON STOCK. ------------------------ NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY OTHER REGULATORY BODY HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR PASSED UPON THE ADEQUACY OR ACCURACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. ------------------------
Per Share Total ----------- -------------- Initial price to public.................................................... $ 16.50 $ 66,000,000 Underwriting discount...................................................... $ 0.94 $ 3,760,000 Proceeds, before expenses, to Basin........................................ $ 15.56 $ 58,350,000 Proceeds, before expenses, to the selling stockholder...................... $ 15.56 $ 3,890,000
The underwriters may, under certain circumstances, purchase up to an additional 600,000 shares from Basin and the selling stockholder at the initial price to public less the underwriting discount. ------------------------ The underwriters expect to deliver the shares against payment in New York, New York on June 23, 1999. GOLDMAN, SACHS & CO. BANC OF AMERICA SECURITIES LLC DAIN RAUSCHER WESSELS A DIVISION OF DAIN RAUSCHER INCORPORATED PETRIE PARKMAN & CO. ---------------- Prospectus Supplement dated June 17, 1999. [3 MAPS] S-2 SUMMARY THE FOLLOWING SUMMARY HIGHLIGHTS SELECTED INFORMATION WE HAVE INCLUDED OR INCORPORATED BY REFERENCE IN THIS PROSPECTUS SUPPLEMENT. IT DOES NOT, HOWEVER, CONTAIN ALL INFORMATION THAT MAY BE IMPORTANT TO YOU. THIS PROSPECTUS SUPPLEMENT, THE ACCOMPANYING PROSPECTUS, AND THE DOCUMENTS INCORPORATED BY REFERENCE INTO THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS INCLUDE INFORMATION ABOUT THIS OFFERING, OUR BUSINESS AND OUR FINANCIAL AND OPERATING CONDITION. WE ENCOURAGE YOU TO READ EACH OF THOSE DOCUMENTS IN THEIR ENTIRETY BEFORE MAKING AN INVESTMENT DECISION. IN THIS PROSPECTUS SUPPLEMENT WE REFER TO BASIN EXPLORATION, INC. AS "WE", "OUR", "US" OR "BASIN", UNLESS THE CONTEXT CLEARLY INDICATES OTHERWISE. IN THE ACCOMPANYING PROSPECTUS WE REFER TO BASIN EXPLORATION, INC. AS "BASIN" AND THE "COMPANY", UNLESS THE CONTEXT CLEARLY INDICATES OTHERWISE. ABOUT BASIN Basin is an independent oil and gas company engaged in the exploration, development and acquisition of oil and gas properties located primarily in the shallow waters of the Gulf of Mexico. We are also active in selected areas of the onshore United States, including the Gulf Coast and the Powder River and Green River Basins of Wyoming. In 1996, we sold a significant portion of our developed properties in the Rocky Mountain region in order to commence an active exploratory drilling program in the Gulf of Mexico. Since that time we have substantially increased our proved reserves, production and cash flow from operations. Through May 1999, we have participated in the drilling of 37 wells in the Gulf of Mexico, 23 of which have been commercially successful, yielding a 62% success rate. As of December 31, 1998, our proved reserves totaled 180 Bcfe, 133% above our proved reserves of 77 Bcfe at December 31, 1996 and 30% greater than our proved reserves of 138 Bcfe at December 31, 1997. Approximately 71% of our proved reserves are gas and 75% are located in the Gulf of Mexico. Our average daily net production for 1998 was 60 MMcfe, a 154% increase over our 1997 average daily net production of 24 MMcfe. For the quarter ended March 31, 1999, our average daily net production was 76 MMcfe, of which 85% was gas and 15% was oil. By early April 1999, we had brought into production a substantial portion of our year-end 1998 proved non-producing reserves, and during April 1999 our average daily net production exceeded 100 MMcfe. Our revenues and cash flow from operations in 1998 increased from 1997 levels by 97% and 120%, to $48.7 million and $33.7 million, despite significantly lower prices for oil and gas in 1998. For 1998, our cash flow from operations per Mcfe of production was $1.53, which we believe was among the highest within the independent oil and gas sector. Approximately 70% of our proved reserves in the Gulf of Mexico are attributable to Miocene-age sands within an area known as the Miocene trend. The Miocene trend is a prolific oil and gas producing area characterized by subtle hydrocarbon indicators, which are more readily detectable using 3-D seismic data that has become available since the mid-1990s. This trend is primarily located in water depths of less than 150 feet near existing infrastructure, offering favorable drilling and development costs. We believe that there are significant remaining undiscovered reserves within the Miocene trend. We explore for these reserves by applying technical expertise specific to the trend utilizing modern 3-D seismic data. To facilitate our continued growth, we have assembled undeveloped leasehold positions totaling 255,141 gross acres, or 180,816 net acres, at December 31, 1998, more than half of which are in the Gulf of Mexico. We have also licensed more than 600 lease blocks of 3-D seismic data and 375,000 miles of conventional 2-D seismic data covering portions of the Gulf of Mexico. We have S-3 integrated this database with geological interpretations by our technical personnel to develop a multi-year inventory of more than 45 drilling prospects supported by 3-D seismic data. Basin's onshore activities include exploring and developing oil and gas properties in southern Louisiana and Texas and in the Powder River and Green River Basins of Wyoming. We have recently enhanced our onshore capabilities through the addition of experienced personnel and acquisitions of geophysical data. We plan to allocate approximately 15% of our capital expenditure budget in 1999 toward exploring and developing onshore properties. Although the shallow waters of the Gulf of Mexico will remain our primary area of focus, we believe that the longer reserve life and exposure to more diverse opportunities offered by these areas will complement our offshore efforts. Our onshore properties accounted for 11% of our production during the quarter ended March 31, 1999. We believe the current operating environment offers us attractive investment opportunities. Until recently, low prevailing oil and gas prices constrained capital availability and capital expenditures for oil and gas companies. The resulting decline in drilling activity has caused a substantial reduction in costs for oil field services. In addition, competition for exploratory leaseholds and property acquisitions has decreased as capital-constrained companies have sought to strengthen their balance sheets. Furthermore, prices for West Texas Intermediate oil and Henry Hub gas, as reflected on the New York Mercantile Exchange, have increased from $12.05 per Bbl and $1.95 per MMBtu at year-end 1998 to $18.03 per Bbl and $2.27 per MMBtu on May 15, 1999. We are pursuing the offering to take advantage of these favorable investment conditions, and we plan to use the additional borrowing capacity resulting from the offering to significantly increase our exploration and development activities. Basin's principal executive offices are located at 370 Seventeenth Street, Suite 3400, Denver, Colorado 80202. Our telephone number is (303) 685-8000. RECENT DEVELOPMENTS During 1999, Basin has sold assets consisting primarily of Gulf of Mexico exploratory prospects for total proceeds of approximately $8 million. Based on receipt of these proceeds, additional borrowing capacity following the offering, and our current projections of cash flow from operations, we plan to increase our capital expenditure budget for 1999 from $65 million to $95 million. We expect this increase in our capital expenditure budget to generate approximately a 50% increase in our drilling activity in 1999 over our original plans for the year. STRATEGY Our goals are to generate per-share growth in reserves, production, earnings and cash flow through exploration, acquisition and development of oil and gas properties. We seek to achieve these objectives through the following strategies: EXPLORE IN THE SHALLOW WATERS OF THE GULF OF MEXICO. Our exploration activities are focused primarily in the shallow waters of the Gulf of Mexico, a prolific producing area that we believe has substantial future potential. In particular, we have targeted the Miocene trend, which offers favorable drilling and operating costs and readily available and affordable 3-D seismic data. It also offers a substantial existing infrastructure of production platforms, pipelines, and processing facilities. CAPITALIZE ON TECHNICAL EXPERTISE. We have assembled a team of geoscientists and petroleum engineers with substantial Gulf of Mexico experience and expertise in generating prospects, evaluating acquisition opportunities, and managing drilling and production operations. We have also recently added senior management and technical personnel with substantial onshore operating S-4 experience, and we intend to use this in-house capability to identify and pursue growth opportunities in selected onshore areas. APPLY ADVANCED TECHNOLOGY. We use advanced technologies, including 3-D seismic data and computer-aided exploration to better define exploration prospects and development opportunities. Basin has licensed more than 600 lease blocks of 3-D seismic data and 375,000 miles of conventional 2-D seismic data covering portions of the Gulf of Mexico. BALANCE SIZE AND RISK PROFILE OF EXPLORATION TARGETS. We generally seek to conduct a drilling program that is balanced between exploration prospects with significant potential relative to our existing reserve base and smaller, lower risk prospects. This balance is intended to mitigate risk while providing exposure to meaningful growth in reserves and production. GENERATE PROSPECTS INTERNALLY. Basin's team of geoscientists internally generates prospects using its technical database and Landmark workstations. This allows us to retain large working interests and operating control and either to defray our capital investment by selling promoted interests or to increase our prospect inventory by swapping for interests in third-party generated prospects. We have internally generated more than 75% of our Gulf of Mexico prospects. OPERATE CORE PROPERTIES. During April 1999, we operated properties accounting for approximately 74% of our production. Operating allows us to exercise greater control over the cost, timing and character of our exploration, development and production activities. PURSUE SELECTIVE ACQUISITIONS. We actively seek to acquire interests in proved oil and gas properties with exploration or development potential to augment operations in our core areas and to establish positions in new areas. MAINTAIN FINANCIAL FLEXIBILITY. Basin is committed to maintaining financial flexibility in order to pursue exploration and development activities and take advantage of acquisition opportunities. The offering will enhance our financial flexibility by reducing our debt. As of March 31, 1999, after giving effect to receipt of the net proceeds of the offering, we would have had total debt of $33 million, leaving $57 million of our revolving line of credit undrawn. As of the same date, after giving effect to the offering, our total debt per Mcfe of 1998 year-end proved reserves would have been $0.18. We believe this level of debt per Mcfe is among the lowest within the independent oil and gas sector. RISK FACTORS See "Risk Factors" for a discussion of certain factors that should be considered in connection with an investment in the common stock. S-5 THE OFFERING Common stock offered by Basin.......................................... 3,750,000 shares Common stock offered by the selling stockholder........................ 250,000 shares ---------- Total shares offered................................................... 4,000,000 shares ---------- ---------- Common stock outstanding after the offering............................ 17,817,000 shares(1)
- ------------------------ (1) Excludes 1,269,500 shares of common stock reserved for issuance upon the exercise of outstanding stock options, 168,062 shares of common stock issuable on exercise of outstanding warrants, and 562,500 shares issuable pursuant to the underwriters' option to purchase additional shares. See "Capitalization" and "Underwriting". Use of Proceeds..... We intend to use the net proceeds from the offering for repayment of debt under our revolving line of credit. Basin will use the increased borrowing capacity under our revolving line of credit, along with cash flow from operations, to increase exploration, development and acquisition activities and for general corporate purposes. Basin will not receive any proceeds from the sale of common stock by the selling stockholder, Michael S. Smith, Basin's Chief Executive Officer, President and largest stockholder. Mr. Smith is selling 250,000 shares of the 3,036,229 shares he beneficially owns. After the offering, and assuming no exercise of the underwriters' option to purchase additional shares, Mr. Smith will beneficially own 15.6% of Basin's common stock (14.9% if the underwriters' option is exercised). See "Selling Stockholder". Nasdaq National Market Symbol....... BSNX
S-6 SUMMARY OIL AND GAS RESERVE INFORMATION In the table below, we provide summary information regarding our estimated net proved oil and gas reserves as of December 31, 1998, and present values of estimated future net cash flows related to these proved reserves, which have been calculated using a 10% per annum discount factor. Our proved reserves and the related future net cash flows as of December 31, 1998 have been estimated using average prices of $1.99 per Mcf of gas and $10.31 per barrel of oil that we were realizing at that date, without escalation in future periods. On that date, closing prices quoted on the New York Mercantile Exchange were $1.95 per MMBtu of Henry Hub gas and $12.05 per barrel of West Texas Intermediate oil. One MMBtu is approximately equivalent to one Mcf of gas. Ryder Scott Company, independent petroleum engineers, prepared reserve report estimates for certain of our oil and gas properties as of December 31, 1998 and audited estimates prepared by our engineers for our other properties as of that date. For a discussion of the limitations inherent in the accuracy and reliability of estimations of net proved oil and gas reserves and related future net cash flows, see "Risk Factors--Reserve estimates are inherently uncertain and depend on many assumptions that may turn out to be untrue".
AS OF DECEMBER 31, 1998 --------------------------------------- DEVELOPED UNDEVELOPED TOTAL ----------- ------------- ----------- Oil (MBbls)............................................................. 3,352 5,315 8,667 Gas (MMcf).............................................................. 103,271 24,231 127,502 Total gas equivalents (MMcfe)........................................... 123,383 56,121 179,504 Present value of future net cash flows before income taxes (in thousands)........................................................ $ 137,775 $ 26,710 $ 164,485 Standardized measure of discounted future net cash flows (in thousands)........................................................ 149,955
Since December 31, 1998, oil and gas prices have increased significantly and the present value of the future net cash flows from our proved reserves has changed. Based on the New York Mercantile Exchange prices in effect on May 15, 1999 of $18.03 per barrel of West Texas Intermediate oil and $2.27 per MMBtu of Henry Hub gas, the present value of future net cash flows before income taxes of Basin's net proved reserves at December 31, 1998 would have been $236 million. The following table shows Basin's total proved reserves as of December 31, 1998 and Basin's net production for the year ended December 31, 1998 by geographic area of operations:
PROVED RESERVES --------------------------------- OIL GAS TOTAL NET PRODUCTION (MBBLS) (MMCF) (MMCFE) (MMCFE) ----------- --------- --------- --------------------- Gulf of Mexico............................................ 4,281 109,626 135,312 18,284 Onshore................................................... 4,386 17,876 44,192 3,682 ----- --------- --------- ------- Total..................................................... 8,667 127,502 179,504 21,966 ----- --------- --------- ------- ----- --------- --------- -------
S-7 SUMMARY OPERATING AND FINANCIAL DATA We have provided in the tables below our selected operating and financial data. The financial information for each of the three years in the period ended December 31, 1998 has been derived from our audited financial statements. The financial information for the three months ended March 31, 1998 and 1999 has been derived from our unaudited financial statements. You should read the following financial information in conjunction with our consolidated financial statements and related notes that are presented elsewhere in this prospectus supplement.
THREE MONTHS ENDED MARCH YEAR ENDED DECEMBER 31, 31, ----------------------------------------- ------------------------ 1996 1997 1998 1998 1999 --------------- ----------- ----------- ----------- ----------- (DOLLARS IN THOUSANDS, EXCEPT OPERATING AND PER SHARE DATA) OPERATING DATA: Proved reserves at December 31: Oil (MBbls)............................... 7,870 8,154 8,667 Gas (MMcf)................................ 29,713 89,534 127,502 Total gas equivalents (MMcfe)............. 76,933 138,458 179,504 Reserve replacement ratio(1).............. 80%(2) 307% 251% Average daily net production: Oil (Bbls)................................ 1,540 1,435 1,988 2,035 1,838 Gas (Mcf)................................. 13,050 15,094 48,262 37,776 64,479 Total gas equivalents (Mcfe).............. 22,290 23,704 60,190 49,986 75,507 Average sales price per unit including hedging effects: Oil (per Bbl)............................. $ 20.03 $ 18.80 $ 13.42 $ 14.69 $ 13.58 Gas (per Mcf)............................. 1.44 2.64 2.21 2.22 1.86 Total gas equivalents (per Mcfe).......... 2.23 2.82 2.21 2.27 1.92 Production cost (per Mcfe)(3)............... $ 0.81 $ 0.68 $ 0.41 $ 0.53 $ 0.37 INCOME STATEMENT DATA: Total revenue............................... $ 41,663 $ 24,720 $ 48,699 $ 10,256 $ 13,055 Net income (loss)........................... 15,570 2,456 (28,500) 239 (398) Diluted earnings (loss) per share........... 1.45 0.22 (2.06) 0.02 (0.03) Weighted average diluted common shares outstanding............................... 10,730 11,345 13,859 14,237 13,973 OTHER FINANCIAL DATA: Cash flow from operations before changes in working capital........................... $ 5,680 $ 15,297 $ 33,658 $ 6,556 $ 8,418 Net cash provided by operating activities... 4,909 15,489 37,834 1,010 11,274 Capital additions........................... 27,741 98,245 107,716 23,281 23,977
S-8
AS OF DECEMBER 31, AS OF MARCH 31, 1999 ----------------------------------- ---------------------------- 1996 1997 1998 ACTUAL AS ADJUSTED(4) --------- ----------- ----------- ----------- --------------- (IN THOUSANDS) BALANCE SHEET DATA (AT PERIOD END): Working capital (deficit).................... $ 19,178 $ (10,036) $ (13,224) $ (16,457) $ (16,457) Total assets................................. 84,957 161,959 201,163 214,843 214,843 Total debt................................... 424 11,206 80,258 91,156 33,256 Total stockholders' equity................... 68,751 121,365 94,219 94,303 152,203 Common shares outstanding.................... 10,701 13,713 13,965 14,027 17,777
- ------------------------ (1) Calculated as the sum of proved reserve extensions, discoveries, additions and revisions divided by production. The reserve replacement ratio excludes proved property purchases and sales. (2) 1996 reserve replacement was affected by the divestiture of Basin's Denver-Julesberg Basin properties, which represented 70% of Basin's proved reserves at the time. (3) Includes lease operating expenses and production taxes. (4) As adjusted to reflect the 3,750,000 shares of common stock offered by Basin and the application of the estimated $57.9 million of net proceeds to repay indebtedness under our revolving line of credit. See "Use of Proceeds" for a discussion of our use of proceeds from the offering. S-9 FORWARD-LOOKING STATEMENTS Some of the information in this prospectus supplement contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements express, or are based on, expectations about future events, activities, or developments that we expect, believe, project, intend, estimate, plan or anticipate will, should, could or may occur. These include such matters as: - amount and nature of capital expenditures; - drilling of wells; - estimated reserves at December 31, 1998 and with oil and gas prices as of May 15, 1999; - timing and amount of future production of oil and gas; - business strategies; - operating costs and other expenses; - cash flow and anticipated liquidity; - prospect development and property acquisitions; - marketing of oil and gas; and - Year 2000 compliance activities. There are many factors that could cause these forward-looking statements to be incorrect, including, but not limited to, the risks described under "Risk Factors" and "Management's Discussion and Analysis of Financial Condition and Results of Operations". These factors include, among others: - general economic conditions; - oil and gas price volatility; - our ability to find, acquire, market, develop and produce new properties; - the risks associated with acquisitions and exploration; - operating hazards attendant to the oil and gas business; - downhole drilling and completion risks that are generally not recoverable from third parties or insurance; - uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures; - potential mechanical failure or underperformance of significant wells; - the strength and financial resources of Basin's competitors; - Basin's ability to find and retain skilled personnel; - climatic conditions; - availability of capital; - availability and cost of material and equipment; - delays in anticipated start-up dates; - environmental risks; - actions or inactions of third-party operators of Basin's properties; - regulatory developments; and - third-party Year 2000 compliance actions. When you consider these forward-looking statements, you should keep in mind these risk factors and the other cautionary statements in this prospectus supplement. Our forward-looking statements speak only as of the date made. Neither Basin, any person acting on Basin's behalf nor the underwriters undertakes any obligation to update any forward-looking statements in this prospectus supplement, the accompanying prospectus or any statement incorporated by reference. S-10 RISK FACTORS An investment in our common stock involves significant risks. In particular, you should carefully consider the following risk factors before you decide to buy the common stock. You should also carefully read and consider all of the information we have included in this prospectus supplement and the other risk factors and information discussed in the accompanying prospectus and in our reports on Forms 10-K and 10-Q, before you decide to buy the common stock. OIL AND GAS PRICES FLUCTUATE FREQUENTLY, AND LOW PRICES COULD HAVE A MATERIAL ADVERSE IMPACT ON OUR BUSINESS. Prices for oil and gas fluctuate widely and have declined significantly during 1998. Gas prices affect us more than oil prices, because most of our production and reserves are gas. At December 31, 1998, 71% of our estimated proved reserves consisted of gas on an Mcfe basis. In 1998, approximately 80% of our total production consisted of gas. Basin's revenues, profitability and future rate of growth substantially depend on prevailing prices for oil, gas and gas liquids. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. The amount we can borrow from banks is subject to periodic re-determination based on changing expectations of future prices. Lower prices may also reduce the estimate of the amount of oil and gas that we can economically produce. As an example, our estimated proved reserves at December 31, 1998 of 180 Bcfe with a present value of future net cash flows before income taxes of $164 million, were lower than they would have been had prices not declined from year-end 1997. WE CANNOT PREDICT FUTURE OIL AND GAS PRICES. PRICES MAY DECLINE FURTHER FROM THEIR 1998 LEVELS. Among the factors that can cause this fluctuation are: - RELATIVELY MINOR CHANGES IN, AND UNCERTAINTY SURROUNDING, THE SUPPLY OF AND DEMAND FOR OIL AND GAS; - THE LEVEL OF CONSUMER DEMAND; - WEATHER; - DOMESTIC AND FOREIGN GOVERNMENTAL REGULATIONS; - THE PRICE AND AVAILABILITY OF ALTERNATIVE FUELS; - POLITICAL CONDITIONS IN THE MIDDLE EAST; - THE PRICE OF OIL AND GAS IMPORTS; AND - ECONOMIC CONDITIONS IN THE UNITED STATES AND IN OTHER COUNTRIES. HEDGING OUR PRODUCTION MAY RESULT IN LOSSES. We periodically enter into commodity hedging transactions, including energy price swap agreements and other financial arrangements in an effort to mitigate the potential impact of declines in oil and gas prices. Such arrangements involve risks. Hedging contracts limit the benefits we would realize if actual prices rise above the contract prices. Because of low prevailing prices during the first quarter of 1999, the absence of market indicators suggesting that prices would rise in the short term, and our desire to protect our cash flow and borrowing base under our revolving line of credit, we hedged significant portions of our anticipated 1999 production during the first quarter of 1999. Since that time, oil and gas prices have risen above levels we had expected. If prices remain at S-11 current levels or increase during the balance of this year, we will have hedging losses that could be material. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" and note 1 of notes to the December 31, 1998 consolidated financial statements for a description of our recent hedging activity. In addition, if our reserves are not produced at the rates we estimated, we would be required to satisfy our obligations under hedging contracts on potentially unfavorable terms without the ability to offset the financial impact through sales of comparable quantities of our own production. Further, the terms of our hedging contracts are based on many assumptions and estimates such as costs of transportation to delivery points. Under financial instrument contracts, we may be at risk for basis differential, which is the difference in the quoted financial price for contract settlement and the actual price received at the physical point of delivery. Substantial variations between our assumptions and estimates and actual results could materially adversely affect our results from operations. In addition, hedging contracts are subject to the risk that the other party may prove unable or unwilling to perform its obligations. Any significant nonperformance could have a material adverse financial effect on us. THE FAILURE TO REPLACE OUR RESERVES WOULD ADVERSELY AFFECT OUR LIQUIDITY AND OPERATIONS. Unless Basin conducts successful development, exploitation or exploration activities or acquires properties containing proved reserves, Basin's proved reserves will decline as those reserves are produced. The rate of decline depends on a number of factors, including drilling density, completion procedures, and reservoir characteristics. Further, decline rates vary from the generally steep declines experienced with production from reservoirs in the Gulf of Mexico, where we have most of our production, to the relatively slow declines of long-lived fields in the Rocky Mountain region, where our other producing properties are located. The market for acquiring proved reserves is extremely competitive, and we may not be able to buy reserves at reasonable prices. Basin's drilling operations may be unsuccessful or may be curtailed, delayed or canceled for many reasons, such as: - title problems; - weather conditions; - compliance with governmental requirements; - cost overruns; - shortages of capital; - mechanical difficulties; and - shortages in drilling rigs or other equipment. We may be unable to make the necessary capital investments to maintain or expand our oil and gas reserves if cash flow from operations is reduced and external sources of capital become limited or unavailable. We cannot assure you that our future acquisition, development and exploration activities will result in reserves added at acceptable costs. S-12 PROPERTIES WE BUY CONTAINING PROVED RESERVES MAY NOT PERFORM AS WE PROJECTED, AND WE MAY NOT BE ABLE TO DISCOVER LIABILITIES CARRIED WITH THE PROPERTIES OR OBTAIN PROTECTION FROM SELLERS AGAINST THEM. The successful acquisition of producing properties requires assessments of many factors, which are inherently inexact and may be inaccurate, including: - the amount of recoverable reserves; - future oil and gas prices; - estimates of operating costs; - estimates of future development costs; and - potential environmental and other liabilities. Our review will not reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their deficiencies and capabilities. We may not inspect every well, platform or pipeline. We cannot necessarily observe structural and environmental problems, such as pipeline corrosion or groundwater contamination, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities they created. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations. SUBSTANTIAL ACQUISITIONS COULD REQUIRE SIGNIFICANT EXTERNAL CAPITAL AND COULD CHANGE BASIN'S RISK AND PROPERTY PROFILE. We frequently engage in bidding and negotiation for producing property acquisitions, many of which are substantial. If successful in this process, we may need to alter or increase our capitalization substantially to finance these acquisitions or joint ventures through the issuance of debt or equity securities, the sale of production payments or otherwise. These changes in capitalization may significantly affect our risk profile. Additionally, significant acquisitions or joint ventures can change the character of our operations and business. The character of the new properties may be substantially different in operating or geological characteristics or geographic location than our existing properties. EXPLORATION IS A HIGH-RISK ACTIVITY AND THE 3-D SEISMIC AND OTHER ADVANCED TECHNOLOGIES WE USE ARE EXPENSIVE, REQUIRE EXPERIENCED PERSONNEL, AND CANNOT ELIMINATE EXPLORATION RISK. Exploration activities are substantially more risky than development or exploitation activities. We use 3-D seismic data and other advanced technologies to reduce our risk, but exploratory drilling remains a speculative activity. Even when extensively used and properly interpreted, 3-D seismic data and visualization techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators. They do not conclusively allow the interpreter to know if hydrocarbons are present or if they are economically producible. The use of 3-D seismic data and certain other technologies also requires greater pre-drilling expenditures than traditional drilling strategies. Basin could incur losses as a result of such expenditures. Poor results from our exploration activities could have a material adverse effect on our future results of operations and financial condition. Prior to 1995, Basin had not conducted operations in the Gulf of Mexico. This operating area is highly competitive and our success there will depend on our ability to attract and retain experienced geoscientists and other professional staff. We currently have ten geoscientists and petroleum engineers plus two engineering consultants who are experienced in Gulf of Mexico operations. Loss of these experienced personnel could have a material adverse impact on Basin's ability to compete in this area. S-13 IF WE CANNOT CONTINUE TO ACCESS CAPITAL FROM EXTERNAL SOURCES, WE MAY BE UNABLE TO EXPAND OUR RESERVES AND PRODUCTION. Because our capital expenditures have generally exceeded our cash flow, we require external sources of capital to develop and explore our properties and acquire additional properties. Our ability to access additional capital will depend on a number of factors, some of which are beyond our control. These include our operational success, the status of the capital markets, and oil and gas prices. Historically we have addressed our long-term liquidity needs through cash flows from operations, bank borrowings and the issuance of equity securities. We continue to examine the following alternate sources of long-term capital: - traditional reserve-base borrowings or the issuance of long-term debt; - the sale of common stock, preferred stock or other equity securities; - the issuance of nonrecourse production-based financing or net profits interests; - sales of non-strategic properties; - sales of interests in prospects and technical information; and - joint ventures. We may be unable to execute our operating strategy if we cannot obtain capital from these sources. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources". OUR DEBT COULD REDUCE OUR FINANCIAL FLEXIBILITY. At March 31, 1999, our long-term debt equaled $91 million, and we had $19 million available to draw down under our revolving line of credit with our banks. Our working capital deficit equaled $16.5 million at March 31, 1999, leaving a net total of $2.5 million of unutilized credit capacity. Under our revolving line of credit, our banks redetermine our borrowing base at least semi-annually, and it is possible that any such review could result in a reduction of our borrowing base. This could occur as a result of weak oil and gas prices or unsuccessful exploration or development activities. The terms of our revolving line of credit may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general corporate purposes. WE WROTE DOWN THE CARRYING VALUE OF OUR PROVED RESERVES AT YEAR-END 1998 TO REFLECT LOW OIL AND GAS PRICES, AND WE COULD EXPERIENCE SUCH WRITE-DOWNS IN THE FUTURE. 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. In addition, write-downs may occur if we have substantial downward adjustments to our estimated proved reserves. Basin uses the full cost method of accounting to report operations for oil and gas properties. We capitalize the costs to acquire, explore for and develop oil and gas properties. Under full cost accounting rules, the net capitalized costs of oil and gas properties may not exceed a ceiling limit that is based on the present value of estimated future net cash flows from proved reserves, using constant oil and gas prices and a 10% discount factor, plus the lower of 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 affect cash flow from operating activities, but it does reduce the book value of our stockholders' equity. We review the carrying value of our properties quarterly, based on prices in effect as of the end of each quarter or as of the time of reporting results. We may not reverse write-downs even if prices increase in S-14 subsequent periods. Primarily because of weak oil and gas prices, we recorded a ceiling limitation write-down for the fourth quarter of 1998 in the amount of $30.8 million ($38.5 million pre-tax). We could have another ceiling limitation write-down in a future period if commodity prices weaken from 1998 year-end levels. OUR ABILITY TO MARKET OUR OIL AND GAS PRODUCTION DEPENDS ON THIRD PARTIES AND ON FLUCTUATING COMMODITY PRICES AND DEMAND WHICH ARE BEYOND OUR CONTROL. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. Demand for gas is highly seasonal, with demand generally higher in the colder winter months and in the hot summer months. As a result, the price and marketability of our spot market gas may vary significantly between seasonal periods. If market factors dramatically changed, the financial impact on Basin could be substantial. The availability of markets for our production is beyond our control. A SIGNIFICANT PART OF THE VALUE OF OUR PRODUCTION IS CONCENTRATED IN A SMALL NUMBER OF OFFSHORE PROPERTIES. During the three months ended March 31, 1999, over 64% of our daily production was from five properties in the Gulf of Mexico. If mechanical problems, storms, or other events curtailed a substantial portion of this production, Basin's cash flow would be materially adversely affected. RESERVE ESTIMATES ARE INHERENTLY UNCERTAIN AND DEPEND ON MANY ASSUMPTIONS THAT MAY TURN OUT TO BE UNTRUE. The process of estimating oil and gas reserves is complex and inherently uncertain. It requires various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. We must project production rates and timing of development expenditures. We need to analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. Oil and gas reserve engineering is a subjective process of estimating accumulations of oil and gas that cannot be measured in an exact manner. Basin's proved reserve information included in this prospectus supplement represents only estimates based on reports prepared in part by independent petroleum engineers and in part by internal Basin engineers. Estimates from other engineers might differ materially from those shown. The accuracy of any reserve estimate is a function of the quality and quantity of available data, engineering and geological interpretation and judgment. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this prospectus supplement. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control. At December 31, 1998, approximately 31% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling operations. The reserve data assumes that we will make these expenditures. Although we estimate our reserves and the costs associated with developing them in accordance with industry standards, the estimated costs may not be accurate, development may not occur as scheduled, and results may not be as estimated. S-15 You should not assume that the present value of future net cash flows referred to in this prospectus supplement is the current market value of our estimated oil and gas reserves. In accordance with SEC requirements, we generally base the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. FLUCTUATIONS IN OUR QUARTERLY RESULTS OF OPERATIONS CAN CAUSE SUDDEN CHANGES IN THE MARKET PRICE OF OUR COMMON STOCK. Our quarterly results of operations may fluctuate significantly as a result of variations in oil and gas prices, production performance and changes in estimated proved reserves. You can expect the market price of our common stock to decline when our quarterly results decline or when announcements of adverse events regarding Basin or the industry are made. THE OIL AND GAS BUSINESS INVOLVES MANY OPERATING RISKS THAT CAN CAUSE SUBSTANTIAL LOSSES. INSURANCE MAY NOT BE ADEQUATE TO PROTECT AGAINST ALL THESE RISKS. The oil and gas business involves a variety of operating risks, including: - fire; - explosion; - blow-out; - uncontrollable flows of oil, gas, or well fluids; - natural disasters; - pipe failure; - casing collapse; - stuck tools; - abnormally pressured formations; and - environmental hazards such as oil spills, gas leaks, pipeline ruptures and discharges of toxic gases. If any of these events occur, Basin could incur substantial losses as a result of: - injury or loss of life; - severe damage to and destruction of property, natural resources and equipment; - pollution and other environmental damage; - clean-up responsibilities; - regulatory investigation and penalties; and - suspension of operations. If we experience any of these problems, it could affect wellbores, platforms, gathering systems and processing facilities, which could adversely affect our ability to conduct operations. S-16 Offshore operations are subject to a variety of operating risks peculiar to the marine environment, such as hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities to third parties or governmental entities. Payment of these liabilities could reduce or eliminate the funds available for exploration, development or acquisitions, or result in loss of properties. In accordance with industry practice, Basin maintains insurance against some, but not all, potential risks. Our coverage includes, but is not limited to, operator's extra expense, physical damage on certain assets, comprehensive general liability, automobile, and workers compensation insurance. We cannot assure you that our insurance will be adequate to cover our losses or liabilities. For example, insurance may not cover downhole operating risks, such as the costs of retrieving stuck equipment. Also, we cannot predict whether insurance will continue to be available at premium levels that justify its purchase. OIL AND GAS OPERATIONS ARE SUBJECT TO EXTENSIVE ENVIRONMENTAL AND OTHER GOVERNMENTAL REGULATION, WHICH CAN AFFECT THE COST, MANNER, OR FEASIBILITY OF DOING BUSINESS. Development, production and sale of oil and gas are subject to extensive federal, state and local environmental and other governmental regulation. We have made and will continue to make large expenditures to comply with environmental and other governmental regulations. These regulations could change in ways that might substantially increase our costs. For example, the Minerals Management Service of the United States Department of the Interior has proposed regulations for valuation of oil and gas produced from federal leases, including offshore leases that could require payment of royalties on the basis of indices that may not reflect actual prices we receive for our production. Also, the Federal Energy Regulatory Commission has promulgated major regulatory initiatives over the past several years that have had a significant impact on gas pricing and gas pipeline operations, services and rates. Those changes have significantly altered the marketing of gas, and the effect of these changes on our ability to market our gas at reasonable prices is uncertain. Offshore operations are subject to more extensive governmental regulation than onshore operations. Under the Outer Continental Shelf Lands Act, the Minerals Management Service regulates development and production of oil and gas in federal waters in the Gulf of Mexico, and it may suspend or terminate operations for violation of its rules. These and other environmental regulations could impose liability for pollution clean up and damages and require cessation of operations in affected areas. Any such costs, damages, suspension or termination could materially and adversely affect Basin's financial condition and operations. We are subject to state and local regulations that impose permitting, reclamation, land use, conservation, and other restrictions on our ability to drill and produce. COMPETITION IN OUR INDUSTRY IS INTENSE AND WE ARE SMALLER AND LESS EXPERIENCED THAN MOST OF OUR COMPETITORS IN THE GULF OF MEXICO. We compete with major and independent oil and gas companies for property acquisitions, especially in the Gulf of Mexico. We also compete for the equipment and labor required to operate and develop such properties. Most of our competitors have financial and other resources substantially greater than ours. During 1996, we commenced operations in the Gulf of Mexico, where we had not previously been active. Competition from major and large independent oil and gas companies is significantly greater in this area than in the Rocky Mountain region, where we previously conducted all of our operations. WE CANNOT CONTROL THE PACE OR TYPE OF ACTIVITIES ON PROPERTIES THAT WE DO NOT OPERATE. Some of our properties in the Gulf of Mexico are operated by third parties. Because we are not the operator, we do not have the ability to control the nature of operations undertaken, such as the S-17 drilling of development wells, or the timing of such operations. This can affect our cash flow and the timing of our production increases. OUR PRINCIPAL STOCKHOLDER IS IN A POSITION TO AFFECT CORPORATE TRANSACTIONS AND OTHER MATTERS. Basin's principal stockholder, Michael S. Smith, together with members of his immediate family and trustees for their benefit, beneficially own approximately 21.4% of Basin's outstanding shares of common stock, and, assuming no exercise of the underwriters' option to purchase additional shares, 15.6% after giving effect to this offering. As a result, Mr. Smith is in a position to substantially influence the outcome of stockholder votes on the election of directors and other matters. In addition, if Mr. Smith were to sell a significant number of his shares, the prevailing market price of Basin's common stock could be adversely affected. THE LOSS OF MICHAEL S. SMITH OR OTHER SENIOR PERSONNEL COULD ADVERSELY AFFECT BASIN. We depend to a large extent on the services of our founder and Chief Executive Officer, Michael S. Smith, and certain other senior management personnel. The loss of the services of Mr. Smith or other key personnel could have a potential adverse effect on Basin's operations. BASIN AND OUR BUSINESS PARTNERS MAY NOT BE YEAR 2000 COMPLIANT, WHICH COULD RESULT IN DISRUPTION OF OUR OPERATIONS. There is no assurance that our Year 2000 readiness project will succeed in accurately and completely identifying all potential problems or all potentially affected systems or in remedying all problems in our systems. There is no assurance that our business partners will likewise succeed in their respective efforts to remedy their Year 2000 problems or that this will be apparent in time for us to formulate a contingency plan. Between now and January 2000, there will be increased competition for people with technical and managerial skills necessary to deal with the Year 2000 problem. Basin and our business partners could face shortages of skilled personnel or other resources, such as particular microprocessors or components containing Year 2000 ready microprocessors. These shortages might delay or otherwise impair our ability to assure that our critical systems or our partners' systems are Year 2000 compliant. If there are Year 2000 related failures in our critical systems or our business partners' critical systems that create substantial disruptions to our business, the adverse impact on us could be material. Despite our belief that the cost to become Year 2000 compliant will not be material, our cost assessments do not take into account the costs, if any, that might be incurred as a result of Year 2000 related failures that occur despite our compliance efforts. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Year 2000 Readiness Disclosure and Statement". ANTI-TAKEOVER PROVISIONS ADOPTED BY BASIN COULD DETER CHANGE OF CONTROL TRANSACTIONS. Basin's restated certificate of incorporation and bylaws and the provisions of the Delaware General Corporation Law make it difficult to change control of Basin and replace incumbent management. We adopted a stockholders' rights plan in 1996. Under this plan, holders of our common stock received rights exercisable if a person or group of affiliated persons acquires 15% of our outstanding common stock or commences a tender or exchange offer that would result in ownership of 15% or more of our outstanding common stock. Basin has a classified board of directors under which directors serve staggered three-year terms, which may hinder or prevent replacement of the entire board of directors by stockholders at any one meeting. In addition, we have entered into agreements with certain of our executive officers that would require us to make additional payments if such officers' employment were terminated, or the terms of such employment were materially altered, upon a change of control. S-18 USE OF PROCEEDS We estimate that we will receive net proceeds (after deducting the underwriting discounts and estimated expenses of the offering payable by Basin) of approximately $57.9 million from this offering. If the underwriters exercise in full their option to purchase additional shares, estimated net proceeds that we will receive from the offering will increase to approximately $66.7 million. We plan to use the net proceeds from the offering to repay a portion of long-term debt outstanding under our revolving line of credit. This repayment will create additional borrowing capacity under our revolving line of credit, which we plan to use, along with cash flow from operations and proceeds from asset sales, to increase our exploration, development and acquisition activities, and for other corporate purposes. As of March 31, 1999, we had $91 million of debt outstanding under this line of credit at a weighted average interest rate of 6.5% per annum. For additional information regarding Basin's revolving line of credit, see "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources--Revolving Line of Credit". Basin will not receive any of the proceeds from the sale of shares by the selling stockholder. See "Selling Stockholder". S-19 CAPITALIZATION The following table shows Basin's capitalization as of March 31, 1999. It also shows our capitalization as adjusted to give effect to our receipt of the estimated net proceeds of the offering of $57.9 million, at the initial price to public of $16.50 per share.
AS OF MARCH 31, 1999 ------------------------- ACTUAL AS ADJUSTED ----------- ------------ (IN THOUSANDS) Long-term debt net of current portion(1)............................................... $ 91,000 $ 33,100 ----------- ------------ Stockholders' equity: Preferred stock, par value $.01 per share, 10,000,000 shares authorized; no shares issued............................................................................. -- -- Common stock, par value $.01 per share, 50,000,000 shares authorized; 14,213,000 shares issued and 17,963,000 shares issued, as adjusted(2)......................... 142 180 Additional paid-in capital........................................................... 113,618 171,480 Accumulated deficit.................................................................. (16,886) (16,886) Common stock held in treasury, at cost, 186,000 shares............................... (2,571) (2,571) ----------- ------------ Total stockholders' equity......................................................... 94,303 152,203 ----------- ------------ Total capitalization............................................................... $ 185,303 $ 185,303 ----------- ------------ ----------- ------------
- ------------------------ (1) As of May 15, 1999, long-term debt was $102 million. (2) Excludes 1,269,500 shares of common stock reserved for issuance upon the exercise of outstanding stock options (at a weighted-average exercise price of $11.88 per share) granted under Basin's Equity Incentive Plan. Also excludes 168,062 shares of common stock subject to outstanding warrants having an exercise price of $14.00 per share. Also excludes 562,500 shares that may be issued under the underwriters' option to purchase additional shares that is discussed under "Underwriting". S-20 PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY Basin common stock is traded on the Nasdaq National Market under the symbol "BSNX". The following table shows, for the periods indicated, the high and low reported sales price per share for the common stock as reported by Nasdaq. The bid quotations for the Nasdaq National Market reflect inter-dealer prices, do not include retail markups, markdowns or commissions and may not necessarily reflect actual transactions.
HIGH LOW --------- --------- 1997 First Quarter.............................................................................. $ 7.75 $ 5.88 Second Quarter............................................................................. 8.75 6.38 Third Quarter.............................................................................. 17.88 7.63 Fourth Quarter............................................................................. 23.25 16.38 1998 First Quarter.............................................................................. $ 21.06 $ 13.88 Second Quarter............................................................................. 23.25 14.13 Third Quarter.............................................................................. 18.50 9.00 Fourth Quarter............................................................................. 18.25 10.25 1999 First Quarter.............................................................................. $ 14.88 $ 8.44 Second Quarter (through June 17, 1999)..................................................... 18.38 13.00
On June 17, 1999, the last reported sales price on the Nasdaq National Market was $16.69 per share. As of June 17, 1999, there were 142 holders of record of the common stock. Basin has not in the past paid, and does not intend to pay in the foreseeable future, cash dividends on the common stock. We currently intend to retain earnings, if any, for the future operation and development of our business. Our revolving line of credit contains provisions that may have the effect of limiting or prohibiting the payment of dividends. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources". S-21 SELECTED HISTORICAL FINANCIAL INFORMATION The following table sets forth certain consolidated financial data for Basin as of and for each of the periods indicated. The financial information for each of the three years in the period ended December 31, 1998 has been derived from our audited consolidated financial statements. The financial information for the three months ended March 31, 1998 and 1999 has been derived from our unaudited consolidated financial statements which, in the opinion of our management, have been prepared on the same basis as the annual consolidated financial statements and include all adjustments (consisting of only normal recurring adjustments) necessary for a fair presentation of the financial data for such periods. The following financial information should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations", which includes a discussion of factors materially affecting the comparability of the information presented, and our consolidated financial statements presented elsewhere in this prospectus supplement. The results for the three months ended March 31, 1999 are not necessarily indicative of results to be expected for the full year. Historical financial information is not necessarily predictive of Basin's future results of operations and financial condition.
THREE MONTHS ENDED MARCH YEAR ENDED DECEMBER 31, 31, --------------------------------------- -------------------------- 1996 1997 1998 1998 1999 ----------- ------------ ------------ ------------ ------------ (IN THOUSANDS, EXCEPT PER SHARE DATA) INCOME STATEMENT DATA: Revenue: Oil and gas sales....................................... $ 18,182 $ 24,401 $ 48,620 $ 10,235 $ 13,042 Gain on sale of assets.................................. 22,472 -- -- -- -- Interest and other...................................... 1,009 319 79 21 13 ----------- ------------ ------------ ------------ ------------ 41,663 24,720 48,699 10,256 13,055 ----------- ------------ ------------ ------------ ------------ Costs and expenses: Lease operating expenses................................ 4,776 4,600 8,276 2,143 2,455 Production taxes........................................ 1,829 1,260 770 234 76 Depreciation, depletion and amortization................ 7,606 10,622 29,775 5,986 8,546 General and administrative, net......................... 3,850 3,694 4,380 1,112 1,427 Interest and other...................................... 2,272 764 2,030 413 949 Property impairment..................................... -- -- 38,500 -- -- ----------- ------------ ------------ ------------ ------------ 20,333 20,940 83,731 9,888 13,453 ----------- ------------ ------------ ------------ ------------ Income (loss) before income taxes, net.................. 21,330 3,780 (35,032) 368 (398) Income tax (provision) benefit.......................... (5,760) (1,324) 6,532 (129) -- ----------- ------------ ------------ ------------ ------------ Net income (loss)....................................... $ 15,570 $ 2,456 $ (28,500) $ 239 $ (398) ----------- ------------ ------------ ------------ ------------ ----------- ------------ ------------ ------------ ------------ Diluted earnings (loss) per share....................... $ 1.45 $ 0.22 $ (2.06) $ 0.02 $ (0.03) ----------- ------------ ------------ ------------ ------------ ----------- ------------ ------------ ------------ ------------ Weighted average diluted common shares outstanding...... 10,730 11,345 13,859 14,237 13,973 OTHER FINANCIAL DATA: Cash flow from operations before changes in working capital............................................... $ 5,680 $ 15,297 $ 33,658 $ 6,556 $ 8,418 Net cash provided by operating activities............... 4,909 15,489 37,834 1,010 11,274 Capital additions....................................... 27,741 98,245 107,716 23,281 23,977
S-22
AS OF DECEMBER 31, AS OF MARCH 31, 1999 --------------------------------------- ----------------------------- 1996 1997 1998 ACTUAL AS ADJUSTED(1) ----------- ------------ ------------ ------------ --------------- (IN THOUSANDS) BALANCE SHEET DATA: Working capital (deficit).............. $ 19,178 $ (10,036) $ (13,224) $ (16,457) $ (16,457) Total assets........................... 84,957 161,959 201,163 214,843 214,843 Total debt............................. 424 11,206 80,258 91,156 33,256 Total stockholders' equity............. 68,751 121,365 94,219 94,303 152,203 Common shares outstanding.............. 10,701 13,713 13,695 14,027 17,777
- ------------------------ (1) As adjusted to reflect the 3,750,000 shares of common stock offered by Basin and the application of the estimated $57.9 million of net proceeds to repay indebtedness under our revolving line of credit. See "Use of Proceeds" for a discussion of our use of proceeds from the offering. S-23 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Basin's consolidated financial statements and the accompanying notes contain additional detailed information that should be referred to when reviewing this material. Statements in this discussion may be forward-looking. Such forward-looking statements involve risks and uncertainties, including those discussed below, that could cause actual results to differ significantly from those expressed. See "Summary--Forward-Looking Statements". HISTORY AND OVERVIEW Basin is a domestic independent oil and gas company that conducts exploration, acquisition and production activities in the shallow waters of the Gulf of Mexico and selected areas onshore. We commenced operations in 1981 and completed an initial public offering of common stock in 1992. From our inception through 1991, we primarily acquired and developed properties in the Denver-Julesberg Basin in eastern Colorado. In 1992, we began expanding into other areas within the Rocky Mountain region and initiated exploration activities. During 1995, our capital expenditures on oil and gas properties declined to $16 million from $67 million the year before. This decline occurred primarily because of reduced quality investment opportunities in our core operating areas and limitations on our borrowing capacity under our revolving line of credit. Depressed regional gas prices contributed to both of these factors. In response to these developments and our management's assessment of alternative investment opportunities, we implemented a significant redirection of our business strategy and operations between late-1995 and mid-1996. The redirection included: - adding new financial, technical and business development members to our senior management; - selling our Denver-Julesberg Basin properties for $123.5 million; - creating a Houston-based Gulf of Mexico exploration team through hiring geoscientists and petroleum engineers with substantial experience operating in the area; - acquiring a substantial database of newly available regional 3-D seismic data and Landmark workstations for our Gulf of Mexico geoscientists to use in prospect generation; and - reducing corporate staff and general and administrative overhead. The sale of our Denver-Julesberg Basin assets enabled us to eliminate our long-term debt and establish cash reserves, providing us with liquidity for investments in new capital projects. The sale, however, resulted in a significant initial decline in our revenue and cash flow, as the assets sold accounted for approximately 70% of our production and estimated proved oil and gas reserves at the time. We began our Gulf of Mexico activities in 1996 with no initial property base in the region and our early investments related primarily to acquisitions of 3-D seismic data and exploratory leasehold interests. Our first significant discovery in the Gulf of Mexico was the Eugene Island Block 65 #1 well, which we began drilling at the end of 1996 and completed in 1997. Our first production from Gulf of Mexico assets occurred in August 1997, when we brought two wells drilled on Eugene Island Block 65 on-line. We added other proved properties in the Gulf of Mexico in 1997 and 1998 through both exploratory drilling and acquisitions. As of December 31, 1998, we owned interests in S-24 18 properties with proved reserves in the Gulf of Mexico, of which 14 were producing and four were under development for first production. We established first production on two of these properties early in the second quarter of 1999. Basin's estimated proved oil and gas reserves increased from 62.6 Bcfe as of December 31, 1995, pro forma for the sale of our Denver-Julesberg properties, to 179.5 Bcfe at the end of 1998. As further described below, our net production has grown significantly since mid-1997, as Gulf of Mexico properties have been brought on-line. During 1996, 1997, 1998, and the first three months of 1999, our capital expenditures on oil and gas activities totaled approximately $22.8 million, $105.6 million, $106.7 million and $22.5 million, respectively. Over 90% of these investments relate to our operations in the Gulf of Mexico, including costs that we incurred for exploratory leaseholds, geological and geophysical data, exploratory drilling, completion and development activities, and acquisitions of proved properties. These activities included drilling a total of 37 wells in the Gulf of Mexico through May 15, 1999, of which 23, or 62%, have been successful. We closed the first quarter of 1999 with a working capital deficit of approximately $16.5 million, long-term debt of $91.0 million, and stockholders' equity of $94.3 million. Stockholders' equity at the end of the period reflected the impact of a $38.5 million pre-tax non-cash impairment charge in the fourth quarter of 1998 to reduce the carrying value of our oil and gas properties. This charge, which was precipitated by low oil and gas prices in effect at the end of 1998, did not impact our cash flow or our borrowing capacity under our revolving line of credit with our banks. Basin's initial budget for 1999 provided for capital investments of approximately $65 million, subject to an increase for proceeds from anticipated assets sales. With the net proceeds from the offering and approximately $8 million from asset sales to date in 1999, we plan to increase our 1999 budget to $95 million. Given the prevailing lower cost of oil field services today compared to 1998, we believe our 1999 budget will result in significantly greater drilling activity than our $106.7 million of capital expenditures for 1998 yielded in a higher service cost environment. We estimate that this budget expansion will enable us to increase our exploratory drilling activities during the year by approximately 50% compared to planned activities under our initial 1999 budget. OPERATING ENVIRONMENT Oil and gas price levels, which are volatile and beyond our control, significantly impact our results of operations. Changes in oil and gas prices can also affect the amount and terms of external capital resources available to Basin. Gas prices generally respond to North American supply and demand conditions, including the effects of weather. Oil prices reflect global supply and demand conditions to a greater degree, including the impact on supply of decisions by petroleum exporting countries. Despite temporary periods of interrupted growth, oil and gas demand has generally increased over time. Short-term fluctuations in demand, however, can significantly impact prices. During most of 1998 and the first quarter of 1999, the markets for both oil and gas generally reflected ample supply and price weakness due to a number of factors, including a second consecutive unusually warm winter in North America. Since mid-March 1999, oil and gas prices have increased, apparently in response to announced production cut-backs by petroleum exporting countries and expectations of reduced domestic productive capacity caused by declines in drilling activity. There are well-developed futures markets for oil and gas that provide indications of expected future prices for each product. These prices are often substantially different than current prices reflected on spot markets. Presently, these futures markets reflect expectations of oil and gas prices sustained at levels above the levels that prevailed during most of 1998 and early 1999, particularly for gas, which accounted for 85% of Basin's total production in the first quarter of 1999. Expectations will change in response to future developments and indicated future prices may not actually materialize. S-25 Hedging transactions can be entered into based on prices reflected in commodity futures markets. We periodically enter into fixed price sales agreements or other hedging transactions. We do this to take advantage of prices that we believe to be attractive and to reduce risks related to potential price declines, including the risk of being unable to make capital investments at targeted levels. We have executed various hedging transactions to mitigate our exposure to declines in oil and gas prices. Because of low prevailing prices and other factors, we hedged significant portions of our anticipated 1999 production during the first quarter of 1999. Since that time, oil and gas prices have risen above levels we expected. If prices remain at current levels or increase during the balance of this year, we will incur material losses. See "--Liquidity and Capital Resources". Because our hedges cover only a portion of our anticipated future production, however, we remain vulnerable to the potential effects of a decline in prices. Such hedges also can reduce the benefits realized by Basin from increases in oil and gas prices. See "Risk Factors--Hedging our production may result in losses". For much of the past year, the decline in oil and gas prices negatively impacted the availability of capital resources for most energy companies, including Basin. Besides unfavorably affecting cash flow, this weakness in oil and gas prices increased the cost of, and reduced opportunities for, the issuance of long-term debt and equity securities. Increases in oil and gas prices, as noted above, have resulted in some recent improvement in these conditions. For oil and gas producers, the impairment of capital resources during much of the past year has been partially mitigated by certain improvements in the operating environment. We believe that diminished capital resources for energy companies, in the aggregate, has resulted in significant overall improvement in the quality and terms of investment opportunities available, compared to the period preceding the decline in oil and gas prices that occurred in 1998 and early 1999. In addition to a more favorable market for acquirers of exploratory prospects or producing properties, there have been substantial reductions in the costs of oil field goods and services. As an example, the day rate for a typical shallow-water jack-up drilling rig used by Basin in the Gulf of Mexico has declined from up to $40,000 in the first half of 1998 to less than $15,000 in the first quarter of 1999. Other costs have declined by smaller amounts, but still significantly. The availability and reliability of oil field goods and services have also improved as capacity use has become less strained. As noted, these conditions reflect reduced demand for such goods and services in an environment of relatively low oil and gas prices and, therefore, some reversal would be expected with stronger oil and gas prices. Our Gulf of Mexico exploration activities are dependent on our ability to continue to identify and obtain prospects. We generally use non-proprietary three-dimensional seismic data, which is also available to our competitors, as a tool in our prospect generation. This tends to increase competition for, and cost of, available prospects. Since the beginning of 1998, we successfully expanded our inventory of potential exploratory drilling locations from approximately 30 to 45, while drilling 21 test wells. This inventory of prospects, the majority of which are 100%-owned by Basin, represents more than a two-year set of drilling opportunities, based on our historical and anticipated drilling activity levels. However, we face competition for additional prospects from many better-capitalized oil and gas companies. There is no assurance that over the longer term we will be able to continue to acquire interests in prospects at acceptable costs to replenish our inventory of prospects as these are drilled. Basin seeks to mitigate this risk by pursuing prospect ownership through a number of avenues, including lease sales, farm-ins, exchanges, and acquisitions. We also plan to selectively evaluate and pursue other investment opportunities, including onshore exploration and acquisitions of properties with proved oil and gas reserves, to complement our core exploration activities in the Gulf of Mexico. S-26 RESULTS OF OPERATIONS As discussed under "--History and Overview" above, we sold our assets in the Denver-Julesberg Basin during the first half of 1996 and realized our first production from Gulf of Mexico properties in August 1997. Therefore, period to period comparison results of operations may not be meaningful or indicative of future results. The following operating and financial data, in conjunction with the discussion below, are provided to assist you in understanding our results of operations for the periods presented.
THREE MONTHS ENDED YEAR ENDED DECEMBER 31, MARCH 31, ------------------------------- -------------------- 1996 1997 1998 1998 1999 --------- --------- --------- --------- --------- Production: Oil (MBbl)........................................... 564 524 725 183 165 Gas (MMcf)........................................... 4,776 5,509 17,616 3,400 5,803 Total gas equivalents (MMcfe)........................ 8,160 8,653 21,966 4,498 6,793 Average sales price including hedging effects: Oil (per Bbl)........................................ $ 20.03 $ 18.80 $ 13.42 $ 14.69 $ 13.58 Gas (per Mcf)........................................ 1.44 2.64 2.21 2.22 1.86 Total gas equivalents (per Mcfe)..................... 2.23 2.82 2.21 2.27 1.92 Sales revenue (in thousands): Oil sales............................................ $ 11,292 $ 9,844 $ 9,735 $ 2,690 $ 2,246 Gas sales............................................ 6,890 14,557 38,885 7,545 10,796 --------- --------- --------- --------- --------- Oil and gas sales.................................... $ 18,182 $ 24,401 $ 48,620 $ 10,235 $ 13,042 --------- --------- --------- --------- --------- --------- --------- --------- --------- --------- Expenses (per Mcfe): Lease operating expenses............................. $ 0.59 $ 0.53 $ 0.38 $ 0.48 $ 0.36 Production taxes..................................... 0.22 0.14 0.03 0.05 0.01 Depreciation, depletion and amortization............. 0.93 1.23 1.36 1.33 1.26 General and administrative, net...................... 0.47 0.43 0.20 0.25 0.21
THREE MONTHS ENDED MARCH 31, 1998 AND 1999 REVENUE. Oil and gas sales revenue for the three months ended March 31, 1999 totaled $13.0 million, representing an increase of $2.8 million, or 27%, compared to the first quarter of 1998. A 51% increase in net oil and gas production was partially offset by a 15% decline in unit prices, based on net equivalent unit measures. The increase in oil and gas production is attributable to contributions in the current period from 13 Gulf of Mexico properties, compared to seven in the prior-year period. Due to the additional Gulf of Mexico production, which is predominantly gas, and lower oil production from onshore properties on which investments were deferred due to low oil prices, gas increased from 76% of net equivalent units produced in the first quarter of 1998 to 85% of total oil and gas production in the first quarter of 1999. See "--Liquidity and Capital Resources" for additional discussion of our oil and gas production. Hedging transactions had the effect of increasing oil and gas sales by $0.3 million, or $0.08 per Mcfe in the three months ended March 31, 1998, and by $1.4 million, or $0.20 per Mcfe, in the three months ended March 31, 1999. LEASE OPERATING EXPENSES. Due to an increased number of producing properties and higher production levels, lease operating expenses for the three months ended March 31, 1999 increased by $0.3 million, or 15%, from the amount reported for the comparable period in the prior year. However, lease operating expenses per Mcfe produced declined by 25%, from $0.48 in the quarter ended March 31, 1998 to $0.36 during the three months ended March 31, 1999, due to increased production in the current period from Gulf of Mexico wells, which typically have significantly lower average unit operating costs than our Rocky Mountain properties. S-27 PRODUCTION TAXES. Production taxes for the three months ended March 31, 1999 were $0.1 million, representing a decrease of $0.2 million, or 68%, compared to the comparable period in 1998, due to reduced revenues from onshore properties caused by lower oil and gas prices and a decline in production from such properties. Production taxes as a percentage of oil and gas sales for the three months ended March 31, 1999 were 0.6%, compared to 2.3% in 1998, due to a greater portion of sales in 1999 attributable to properties in federal waters offshore, which are generally not subject to production taxes. DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and amortization expense for the three months ended March 31, 1999 was $8.5 million, representing an increase of $2.6 million, or 43%, compared to 1998. The increase was attributable to the 51% increase in production volumes in 1999 as compared to 1998, offset by a decrease in the per-unit depletion rate. The depletion rate of $1.23 per Mcfe produced in the three months ended March 31, 1999 represented a 4% decrease from the $1.28 per Mcfe average depletion rate during the 1998 period. The lower rate is principally due to the effects of a property impairment charge recorded by us in the fourth quarter of 1998. GENERAL AND ADMINISTRATIVE, NET. General and administrative expenses for the three months ended March 31, 1999, net of amounts capitalized and overhead reimbursements, were $1.4 million, representing an increase of $0.3 million, or 28%, as compared to the comparable period in 1998. The increase resulted from incremental costs incurred to manage expanded operations in the Gulf of Mexico and greater stock-based incentive compensation accruals. Stock compensation expense relates to annual grants to employees of restricted stock, including shares awarded to management that will be earned only if certain performance measures are achieved by Basin. Expense is recognized based on vesting schedules and changes in the price of our stock during applicable vesting periods. INTEREST EXPENSE. Interest expense for the three months ended March 31, 1999 totaled $0.9 million, representing an increase of $0.5 million, or 130%, compared to the first quarter of 1998. The variance was attributable to an increase in average borrowings offset by a slight decrease in average effective interest rates. Interest expense in 1999 excludes $0.6 million of interest capitalized to unproved property costs in accordance with Statement of Financial Accounting Standards No. 34. During the quarter ended March 31, 1999, Basin had average outstanding debt of $88.5 million, with an average effective interest rate of 6.8%, compared to average debt of $22.6 million and an average interest rate of 6.9% in the comparable 1998 period. INCOME TAX BENEFIT (PROVISION). The income tax provision for 1998 approximates the amount that would be calculated by applying statutory income tax rates to income before income taxes. No net income tax benefit has been recognized in 1999 due to an equivalent increase in the deferred tax asset valuation allowance. S-28 YEARS ENDED DECEMBER 31, 1997 AND 1998 We established our first production from Gulf of Mexico assets in the second half of 1997. This production, together with production from subsequently added Gulf of Mexico properties, significantly impacted our results of operations. To assist in interpreting year-to-year comparisons, please review the following quarterly data for the two-year period ended December 31, 1998.
MARCH 31, JUNE 30, SEPT. 30, DEC. 31, MARCH 31, JUNE 30, SEPT. 30, DEC. 31, QUARTER ENDED 1997 1997 1997 1997 1998 1998 1998 1998 - ----------------------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- Production: Oil (MBbl)........... 106 103 147 168 183 189 173 180 Gas (MMcf)........... 403 399 1,688 3,019 3,400 3,936 5,296 4,984 Total gas equivalents (MMcfe)............ 1,039 1,017 2,570 4,027 4,498 5,070 6,334 6,064 Average sales price including hedging effects: Oil (per Bbl)........ $ 20.41 $ 17.73 $ 18.59 $ 18.62 $ 14.69 $ 14.26 $ 14.74 $ 9.99 Gas (per Mcf)........ 2.69 1.73 2.45 2.86 2.22 2.34 2.18 2.12 Total gas equivalents (per Mcfe)......... 3.12 2.47 2.67 2.92 2.27 2.35 2.23 2.04 Sales revenue (in thousands): Oil.................. $ 2,155 $ 1,828 $ 2,737 $ 3,124 $ 2,690 $ 2,697 $ 2,545 $ 1,803 Gas.................. 1,082 689 4,139 8,647 7,545 9,219 11,553 10,568 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- Oil and gas.......... $ 3,237 $ 2,517 $ 6,876 $ 11,771 $ 10,235 $ 11,916 $ 14,098 $ 12,371 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- Expenses (per Mcfe): Lease operating expenses........... $ 1.02 $ 0.96 $ 0.40 $ 0.38 $ 0.48 $ 0.48 $ 0.31 $ 0.28 Production taxes..... 0.35 0.27 0.10 0.09 0.05 0.04 0.03 0.02 Depreciation, depletion and amortization....... 1.12 1.21 1.16 1.30 1.33 1.33 1.33 1.42 General and administrative, net................ 0.76 0.80 0.33 0.31 0.25 0.20 0.18 0.19
REVENUE. Oil and gas sales for 1998 increased by $24.2 million, or 99%, compared to 1997, to $48.6 million. This increase resulted from a 154% increase in combined oil and gas production volumes, partially offset by a 22% decrease in revenue per net equivalent unit produced, from $2.82 per Mcfe in 1997 to $2.21 per Mcfe in 1998. Hedging transactions had the effect of reducing oil and gas sales by $0.5 million, or $0.06 per Mcfe, in 1997 and increasing sales by $3.5 million, or $0.16 per Mcfe, in 1998. We attribute the increase in production volumes from 8,653 MMcfe in 1997 to 21,966 MMcfe in 1998 to commencement of production at nine offshore properties at various times during 1998, and to greater contributions from offshore properties acquired or brought on-line during the second half of 1997, partially offset by natural depletion. We attribute the decline in production between the third and fourth quarters of 1998 largely to the temporary loss of production from a major well, after cement behind production casing failed to hold, allowing water to channel into the well. This well was placed back on-line in the first quarter of 1999 after a re-completion operation. LEASE OPERATING EXPENSES. Lease operating expenses, or LOE, increased in 1998 from the prior year by $3.7 million, or 80%, but LOE per Mcfe produced declined by 28% to $0.38, compared to $0.53 in 1997. As shown in the above table of quarterly data, Basin's LOE per Mcfe has generally improved as Gulf of Mexico production has increased, beginning with the third quarter of S-29 1997. An offset to this pattern in the first half of 1998 primarily reflects costs related to the absorption of properties acquired in late-1997 from bankrupt Midcon Offshore, Inc. Typically, our Gulf of Mexico properties have significantly lower unit operating costs than our Rocky Mountain assets. The relatively low per-unit operating cost of Basin's Gulf of Mexico properties is attributable to higher average production rates per well and a higher proportion of gas production, which is generally less costly to produce than oil. PRODUCTION TAXES. Production taxes for 1998 decreased from 1997 by $0.5 million, or 39%, as the result of reduced sales revenue from onshore properties. This reduction reflects both lower production from onshore assets and lower prices on such production. Production from our properties in federal waters offshore in the Gulf of Mexico is generally not subject to production taxes, accounting for the decline in production taxes as a percentage of oil and gas sales, from 5.2% in 1997 to 1.6% in 1998. DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and amortization expense increased from 1997 by $19.2 million, or 180%, in 1998 to $29.8 million. Most of this increase was attributable to a 154% increase in production volumes. The average depletion rate (which excludes depreciation related to non-oil and gas assets) of $1.31 per Mcfe of production in 1998 represents a 17% increase from the $1.12 per Mcfe recorded in 1997. The higher rate is due to a reduction of estimated proved reserves attributable to lower oil and gas prices at the end of 1998 than one year earlier, and to a cost for proved reserves added in 1998 that was above Basin's historical average. The increased unit cost of additions in 1998 reflects the substantial portion of our capital expenditures in 1998 related to the Gulf of Mexico, where higher unit costs are associated with reserves that generally have a higher value per unit than our onshore properties, due to faster recoveries of reserves, lower production costs, and higher average realizable gas prices. GENERAL AND ADMINISTRATIVE EXPENSES, NET. General and administrative expenses in 1998 increased by $0.7 million, or 19%, from 1997 levels, to $4.4 million. The increase in 1998 resulted primarily from incremental costs incurred to manage expanded operations in the Gulf of Mexico. On a per Mcfe basis, general and administrative expenses during the two-year period generally declined as production volumes increased, as reflected in the table above. INTEREST AND OTHER EXPENSE. Interest and other expense for 1998 equaled $2.0 million, representing an increase of $1.3 million, or 166%, compared to 1997. The increase was attributable to an increase in average borrowings offset by a slight reduction in Basin's average effective interest rate. Interest expense in 1998 excludes $1.5 million of interest capitalized to unproved property costs in accordance with Statement of Financial Accounting Standards No. 34. During 1998, Basin had average outstanding debt of $53.4 million with an average effective interest rate of 6.6%, compared to average borrowings of $10.2 million and an average effective interest rate of 6.7% in 1997. Substantially all of the borrowings in both years were under our revolving line of credit. PROPERTY IMPAIRMENT. During 1998, we recognized a property impairment charge of $38.5 million as the result of the capitalized costs of our oil and gas properties exceeding a "ceiling" on such costs computed in accordance with prescribed guidelines for companies utilizing the full cost accounting method. The charge, which had no impact on our cash flows or our revolving line of credit, was associated with unusually low oil prices in effect at the end of 1998. Additional discussion of the charge, including information regarding the methodology prescribed for computing the full cost ceiling, is presented in note 1 to the December 31, 1998 consolidated financial statements. INCOME TAX PROVISION. The difference between the income tax benefit recorded for 1998 and the amount that would be calculated by applying statutory income tax rates to the loss before income taxes is due primarily to the establishment of a $5.7 million deferred tax asset valuation S-30 allowance. The income tax provision for 1997 approximates the amount that would be calculated by applying statutory income tax rates to income before income taxes. YEARS ENDED DECEMBER 31, 1996 AND 1997 The sale of Basin's Denver-Julesberg Basin assets in the first half of 1996, and the realization of first production from Gulf of Mexico assets in the second half of 1997, result in year-to-year comparisons that obscure important changes. We provide the following quarterly data for the two-year period ended December 31, 1997 to assist you in understanding such changes.
MARCH 31, JUNE 30, SEPT. 30, DEC. 31, MARCH 31, JUNE 30, SEPT. 30, DEC. 31, QUARTER ENDED 1996 1996 1996 1996 1997 1997 1997 1997 - ----------------------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- Production: Oil (MBbl)........... 216 152 98 98 106 103 147 168 Gas (MMcf)........... 2,458 1,465 429 424 403 399 1,688 3,019 Total gas equivalents (MMcfe)............ 3,754 2,377 1,017 1,012 1,039 1,017 2,570 4,027 Average sales price including hedging effects: Oil (per Bbl)........ $ 17.94 $ 20.84 $ 21.10 $ 22.31 $ 20.41 $ 17.73 $ 18.59 $ 18.62 Gas (per Mcf)........ 1.47 1.32 1.22 1.95 2.69 1.73 2.45 2.86 Total gas equivalents (per Mcfe)......... 1.99 2.14 2.54 2.98 3.12 2.47 2.67 2.92 Sales revenue (in thousands): Oil.................. $ 3,875 $ 3,164 $ 2,064 $ 2,189 $ 2,155 $ 1,828 $ 2,737 $ 3,124 Gas.................. 3,611 1,932 522 825 1,082 689 4,139 8,647 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- Oil and gas.......... $ 7,486 $ 5,096 $ 2,586 $ 3,014 $ 3,237 $ 2,517 $ 6,876 $ 11,771 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- Expenses (per Mcfe): Lease operating expenses........... $ 0.45 $ 0.56 $ 0.81 $ 0.94 $ 1.02 $ 0.96 $ 0.40 $ 0.38 Production taxes..... 0.19 0.20 0.28 0.34 0.35 0.27 0.10 0.09 Depreciation, depletion and amortization....... 0.89 0.89 1.06 1.04 1.12 1.21 1.16 1.30 General and administrative, net................ 0.32 0.43 0.79 0.83 0.76 0.80 0.33 0.31
REVENUE. Oil and gas sales for 1997 increased by $6.2 million, or 34%, to $24.4 million, due largely to improved average sales prices. An 83% increase in gas prices, offset by a 6% decrease in oil prices, yielded a 26% increase in revenue per net equivalent unit produced, from $2.23 per Mcfe in 1996 to $2.82 per Mcfe in 1997. Hedging transactions had the effect of reducing oil and gas sales by $0.5 million in both years. Production increased by 6% in net equivalent units, from 8,160 MMcfe in 1996 to 8,653 MMcfe in 1997. The relatively small change in production volumes from year-to-year obscures significant changes during each year due to the Denver-Julesberg sales in March and June 1996 and the commencement of Gulf of Mexico production in August 1997. In conjunction with the second Denver-Julesberg sale transaction, which closed in June 1996, Basin recognized a non-recurring $22.5 million gain. Other revenue reported in both 1996 and 1997 primarily represented interest income on cash equivalents held after the second Denver-Julesberg sale transaction prior to redeploying those proceeds into investments in oil and gas properties. LEASE OPERATING EXPENSES. LOE declined in 1997 from the prior year by $0.2 million, or 4%, and LOE per Mcfe produced declined by 10%, to $0.53 in 1997, compared to $0.59 in 1996. Again, S-31 the relatively small changes from year-to-year do not reflect significant changes within each year. Average LOE per Mcfe by quarter reflects that both the properties included in the Denver-Julesberg sales and the Gulf of Mexico properties that began contributing in the second half of 1997 have significantly lower unit operating costs than Basin's retained Rocky Mountain assets, which have high unit operating costs due to relatively low average production rates per well and a high proportion of oil production, which is generally more costly to produce than gas. PRODUCTION TAXES. Production taxes for 1997 decreased from 1996 by $0.6 million, or 31%, as the result of reduced sales from onshore properties in 1997 due to the inclusion in 1996 of production from Denver-Julesberg Basin properties prior to the Denver-Julesberg sales. Production from properties in federal waters offshore is generally not subject to production taxes and such taxes did not increase in the second half of 1997 when Basin added offshore Gulf of Mexico production. Production taxes therefore declined as a percentage of oil and gas sales, averaging 5.2% for all of 1997 and 3.3% in the second half of the year, compared to 10.1% in 1996. DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and amortization expense increased in 1997 by $3.0 million, or 40%, to $10.6 million. The average depletion rate of $1.12 per Mcfe of production in 1997 represents a 37% increase from the $0.82 per Mcfe recorded in 1996. The higher rate is due to the addition of proved reserves in 1997 at a higher average unit cost than Basin's historical average and to the unfavorable impact on estimated proved reserves of using lower assumed future oil and gas prices at the end of 1997 than at the end of 1996. The increased unit cost of additions in 1997 reflects the substantial portion of our capital expenditures in 1997 related to the Gulf of Mexico, where higher unit costs are generally associated with reserves having a higher value per unit than Basin's onshore properties, due to typically faster recoveries of reserves, lower production costs, and higher average realizable gas prices. GENERAL AND ADMINISTRATIVE EXPENSES, NET. General and administrative expenses in 1997 decreased by $0.2 million, or 4%, from 1996 levels, to $3.7 million. The decrease in 1997 resulted primarily from staff reductions made in mid-1996 in conjunction with the Denver-Julesberg sales and related reductions in office rent expense attributable to Basin's relocation to smaller space. These savings, which benefited all of 1997 but only a portion of 1996, were partially offset by higher bonus awards and stock-based incentive compensation costs recorded in 1997. On a per Mcfe basis, general and administrative expenses during the two-year period generally varied inversely with production volumes. INTEREST AND OTHER EXPENSE. Interest and other expense for 1997 was $0.8 million, representing a decrease of $1.5 million, or 66%, compared to 1996. The decrease was attributable to a decrease in average borrowings after the Denver-Julesberg sales and a reduction in Basin's average effective interest rate, reflecting lower prevailing market interest rates and more favorable borrowing terms obtained after the Denver-Julesberg sales. During 1997, we had average outstanding debt of $10.2 million with an average effective interest rate of 6.7%, compared to average borrowings of $28.2 million and an average effective interest rate of 8.0% in 1996. Substantially all of the borrowings in both years were under our revolving line of credit. INCOME TAX PROVISION. The income tax provision for 1997 approximates the amount that would be calculated by applying statutory income tax rates to income before income taxes. The 1997 current provision for income taxes was decreased, and the deferred provision was increased, by approximately $0.5 million due to a change in estimate of current taxes payable for 1996. The difference between the income tax provision recorded for 1996 and the amount that would be calculated by applying statutory income tax rates to income before income taxes is due primarily to reversal of a previously established $2.2 million deferred tax asset valuation allowance. S-32 LIQUIDITY AND CAPITAL RESOURCES Historically, Basin's principal sources of capital have been cash flow from operations, the revolving line of credit, proceeds from asset sales, and proceeds from sales of common stock. Our principal uses of capital have been for the exploration, acquisition, and development of oil and gas properties. Basin's initial budget for 1999 provided for capital investments of approximately $65 million. With the net proceeds from the offering and approximately $10 million from asset sales, we will increase our 1999 budget to $95 million. Given the prevailing lower cost of oil field services today compared to 1998, we believe our 1999 budget will result in significantly greater drilling activity than our $106.7 million of capital expenditures for 1998 yielded in a higher service cost environment. We estimate that this budget expansion will enable us to increase our exploratory drilling activities during the year by approximately 50% compared to planned activities under our initial 1999 budget. Basin's accrual-basis capital expenditures during the first quarter of 1999, plus deposits for five leases for which we submitted apparent winning bids at the central Gulf of Mexico lease sale held March 17, 1999, totaled approximately $23.1 million. Net cash provided by operations before changes in working capital totaled $8.4 million during the first quarter of 1999. Other sources of funds for investments during the quarter included $11.0 million of net borrowings under the revolving line of credit, a $3.2 million reduction in net working capital, and $2.4 million of proceeds from asset sales. Subsequent to March 31, 1999 we received $5.6 million of proceeds from another asset sale. Basin closed the first quarter of 1999 with a working capital deficit of approximately $16.5 million and long-term debt of $91.0 million, all of which was outstanding under the revolving line of credit. The borrowing base established under the revolving line of credit is currently $110 million and will be $90 million following completion of the offering. PRODUCTION AND CASH FLOW. Our cash flow from operations is generally determined by our production level and oil and gas prices. Since 1996, we have made significant investments to initiate and then expand our operations in the Gulf of Mexico. These investments have resulted in an increase in our production from an average rate of 11.2 MMcfe per day in the second quarter of 1997, prior to commencement of Gulf of Mexico production, to an average of 75.5 MMcfe per day in the first quarter of 1999. Production added late in the first quarter and early in the second quarter of 1999 increased our net production rate to a level above 100 MMcfe per day during April 1999. Based primarily on estimates reflected in our year-end 1998 reserve reports and production levels achieved to-date, we anticipate that our net production in 1999 will be at least 50% greater than during 1998, when production totaled 21,966 MMcfe, or an average of 60.2 MMcfe per day. The expected increase is attributable primarily to projected production from Gulf of Mexico properties with proved reserves at the end of 1998 that were either on-line for only a portion of 1998 or had not yet commenced producing. Partially offsetting these additions will be natural depletion-related declines in production from existing producing wells. Actual realization of the production increases projected for the remainder of 1999 will be dependent upon meeting scheduled dates for commencement of production from wells not yet on-line at the end of 1998, and upon achieving projected performance from major wells, including certain wells with little or no production history. Although management and our independent petroleum engineering consultants believe the projections are reasonable, there is no assurance that they will be met. See "Risk Factors" and "Summary--Forward-Looking Statements" for a description of certain risks that may impact our ability to achieve projected production levels. MARKETING AND HEDGING TRANSACTIONS. Basin's production is generally sold under month-to-month contracts at prevailing prices. From time-to-time, however, as conditions are deemed to warrant, we have entered into hedging transactions or fixed price sales contracts for a portion of our oil and gas production. The purposes of these transactions are to limit Basin's exposure to S-33 future oil and gas price declines and achieve a more predictable cash flow. However, such contracts also limit the benefits we would realize if prices increase. Hedging contracts increased Basin's revenue by $0.3 million and $1.4 million in the three-month periods ended March 31, 1998 and 1999, respectively. See "Risk Factors--Hedging our production may result in losses". Through May 7, 1999, Basin had entered into the following fixed price swap and collar arrangements covering the period beginning April 1, 1999 (one MMBtu approximates one Mcf of gas):
OIL COLLARS GAS SWAPS OIL SWAPS ---------------------------- ---------------------------------- ---------------------------- NYMEX AVERAGE DAILY NYMEX AVERAGE DAILY NYMEX AVERAGE DAILY FLOOR TIME PERIOD VOLUME (MMBTU) PRICE/MMBTU VOLUME (BBL) PRICE/BBL VOLUME (BBL) PRICE/BBL - ------------------------- ----------------- --------------- --------------- ----------- --------------- ----------- 4/1/99-6/30/99........... 53,300 $ 2.09 1,500 $ 16.67 1,000 $ 14.00 7/1/99-9/30/99........... 50,000 2.10 1,000 14.00 10/1/99-12/31/99......... 38,300 2.09 1,000 14.00 1/1/00-12/31/00.......... 3,300 2.15 1/1/01-12/31/03.......... 10,000 2.15 NYMEX CEILING TIME PERIOD PRICE/BBL - ------------------------- ----------- 4/1/99-6/30/99........... $ 16.00 7/1/99-9/30/99........... 16.00 10/1/99-12/31/99......... 16.00 1/1/00-12/31/00.......... 1/1/01-12/31/03..........
In addition, we have periodically entered into spread trades or options transactions related to oil or gas futures markets. Under a spread trade, fixed prices under a hedging contract are determined in the future by reference to the price of an underlying contract. Such positions may enable us to lock in favorable fixed prices for future hedging positions, but can also result in unfavorable fixed price contracts if the related reference price declines. As of May 7, 1999, Basin had an outstanding gas spread trade that provides for a fixed price for 10,000 MMBtu per day for the period of March 2000 through October 2000 to be established in the future, when so elected by Basin, at a price equal to the New York Mercantile Exchange February 2000 contract price less $0.41. As of May 7, 1999, we had also sold the following call options: 20,000 MMBtu of gas per day for the period from April 1999 through November 1999, at a strike price of $1.95 per MMBtu; 10,000 MMBtu of gas per day for the period from April 1999 through December 2001, at a strike price of $2.50 per MMBtu; 500 barrels of oil per day for the period from April 1999 through June 1999, at a strike price of $16.00 per barrel; and 1,000 barrels of oil per day for the period from July 1999 through December 1999, at a strike price of $16.75 per barrel. REVOLVING LINE OF CREDIT. Effective January 1, 1999, we entered into a credit agreement with our existing bank group that provides for borrowings of up to $110 million under two combined facilities. Facility A, currently established at $90 million, represents the borrowing base that is considered to be "conforming" based upon the banks' customary practices and standards in making conventional borrowing base determinations for oil and gas producers. Facility B, which is currently established at $20 million, is a shorter-term supplemental line of credit. Interest rates applied to borrowings under the credit agreement are determined by reference to the prime rate or LIBOR, at our election. Facility A provides for a varying spread of 0% to 0.25% to be added to the prime rate, or 0.75% to 1.5% to be applied to LIBOR, based upon our facility usage ratio. Facility B provides for a spread of 3.5% to be added to the prime rate, or 4.75% to be applied to LIBOR, subject to a 0.25% increase in such spreads effective June 1, 1999. Our credit agreement provides for borrowings to be revolving loans until November 30, 2001, at which time the outstanding balance will be converted into a four-year amortizing term loan unless the credit agreement is amended, and subject to the scheduled termination of Facility B effective May 31, 2000. The borrowing base under the credit agreement is scheduled to be re-determined at three-month intervals until Facility B is retired, and then at six-month intervals until the revolving loan is converted into a term loan. The next re-determination is scheduled to occur as of July 1, 1999. Our credit agreement contains various covenants, including limitations on our ability to incur other debt, dispose of assets, pay dividends, or repurchase stock. Pursuant to our credit agreement, S-34 substantially all of our producing properties are subject to mortgages in favor of the banks and our remaining properties are subject to a negative pledge. The weighted average interest rate on borrowings outstanding under the credit agreement at March 31, 1999 was 6.5%. Our annual interest costs will fluctuate based upon fluctuations in short-term interest rates. Assuming debt outstanding during 1999 remained unchanged from the amount outstanding at March 31, 1999, the annual impact on interest expense of a ten percent change in the average interest rate would be approximately $0.5 million, before amounts capitalized. As the interest rate is variable and is reflective of current market conditions, the carrying value of Basin's debt approximates its fair value. Borrowing base re-determinations conducted by the bank group reflect a number of estimates and assumptions including, but not limited to, future production from Basin's proved properties, risk factors for proved reserves, projected oil and gas prices, future operating and development costs, and interest rates. Changes in such estimates and assumptions can significantly impact the size of the borrowing base established by the banks. Because these factors will be influenced by future events, which cannot be forecast with certitude, we cannot predict what level of borrowing base will be established at any future determination date. The provision for Facility B was intended, in part, to provide short-term funds to develop our proved undeveloped and proved developed nonproducing reserves in the Gulf of Mexico. It is anticipated that funds drawn under Facility B will be retired through expansion of Facility A, if our reserve values are sufficiently increased, or that Facility B will be repaid from cash flows or proceeds from the sale of assets or securities. At May 15, 1999, $90 million was outstanding under Facility A and $12 million was outstanding under Facility B. Positive or negative changes in the borrowing base during 1999 could impact the level of our capital expenditures during the year. Increases, supported by performance of our properties, drilling results, and/or higher oil and gas prices, could improve our ability to grow. Decreases would adversely affect our liquidity and capital resources, potentially resulting in a reduction of planned capital expenditures or the sale of our assets or the issuance of securities. CAPITAL EXPENDITURES. Since the beginning of 1996, we have focused our exploration activities in the shallow waters of the Gulf of Mexico, primarily off the coast of Louisiana. During the second half of 1998 we began to direct a small portion of our exploration budget toward onshore opportunities. We also pursue acquisition and development opportunities in the vicinity of our Gulf of Mexico exploration operations, in the Rocky Mountain region where we have an existing base of proved reserves and producing wells, and in certain other major domestic producing basins where we believe significant upside potential exists. Our capital expenditures are generally discretionary and activity levels are determined by a number of factors, including oil and gas prices, availability of funds, quantity and character of identified investment projects, availability of service providers, and competition. Basin's capital expenditures in 1998 totaled approximately $107 million, of which 96% related to operations in the Gulf of Mexico. Approximately $28 million was invested in acquisitions of exploratory leaseholds and geological and geophysical data in the Gulf of Mexico. Approximately $68 million related to Gulf of Mexico drilling, completion, and related development costs. The remainder related to small acquisitions of proved reserves and activities onshore. Gulf of Mexico operations in 1998 included ongoing development of nine productive wells drilled or acquired in 1997, participation in the drilling of 17 wells, of which 11 were successful, and development costs related to the successful wells drilled during the year. Basin's initial budget for 1999 provided for capital investments of approximately $65 million, subject to an increase for proceeds from anticipated asset sales. With the net proceeds from the offering and approximately $8 million from asset sales to date in 1999, we plan to increase our 1999 budget to $95 million. Given the prevailing lower cost of oil field services today compared to S-35 1998, we believe our 1999 budget will result in significantly greater drilling activity than our $106.7 million of capital expenditures for 1998 yielded in a higher service cost environment. We estimate that this budget expansion will enable us to increase our exploratory drilling activities during the year by approximately 50% compared to planned activities under our initial 1999 budget. The revised 1999 budget primarily provides for: - development of seven Gulf of Mexico properties with one or more discovery wells yet to commence sustained production as of the end of 1998; - investments in seismic data and prospects; - participation in approximately nine net (18 to 20 gross) exploratory wells in the Gulf of Mexico; - participation in a small number of onshore exploration opportunities; - development of projected 1999 prospect discoveries; and - continued exploitation of our other offshore and onshore properties. This reduced budget for exploratory leaseholds reflects the unusually large investment made by Basin in 1998 to build a multi-year inventory of drilling prospects. New investments planned for 1999 will seek to maintain this inventory level rather than significantly expand it. We also intend to pursue acquisitions of properties with proved and probable reserves as an integral part of our overall business strategy, with the expectation that these efforts will result in significant investment activity over time. At this time, no portion of our 1999 budget has been specifically allocated for acquisitions of proved properties. If such a transaction is executed, it will likely require a re-allocation of funds from other planned activities and/or external financing. During the first quarter of 1999, Basin's accrual-basis capital expenditures totaled approximately $22.5 million. Such investments were primarily for development of several Gulf of Mexico properties on which discovery wells were drilled during the prior year, participation in drilling five (2.5 net) Gulf of Mexico wells, related completion costs on two (0.8 net) of these wells, and acquisitions of additional Gulf of Mexico 3-D seismic data and leasehold interests. At the March 1999 federal Central Gulf of Mexico lease sale, we also submitted deposits totaling $0.6 million related to five apparent winning bids aggregating $3.0 million. The Minerals Management Service has subsequently awarded all five leases to us, and we have paid the remaining 80% of the respective bid amounts, or an additional total of $2.4 million. This amount was provided for within our budget for exploration and development activities in the current year. The amount and allocation of future capital expenditures will depend on a number of factors that are not entirely within Basin's control or ability to forecast, including drilling results, scheduling of activities by other operators, availability of service providers, success in acquiring prospect leaseholds, and success in consummating acquisitions of proved properties. Basin's planned capital expenditures are also based on estimates regarding availability of capital that depend on assumptions and estimates regarding production, oil and gas prices, and borrowing base re-determinations under our revolving line of credit. Due to these uncertainties, and other matters described under "Risk Factors" and "Summary--Forward-Looking Statements", actual capital expenditures may vary significantly from current expectations. YEAR 2000 READINESS DISCLOSURE AND STATEMENT Readers are cautioned that the forward-looking statements contained in the following Year 2000 discussion should be read in conjunction with Basin's disclosures under the heading "Summary-- Forward-Looking Statements" in this prospectus supplement. S-36 Year 2000 issues result from the inability of many computer programs to accurately calculate, store or use a date subsequent to December 31, 1999. The date can be erroneously interpreted in a number of different ways; typically the year 2000 is interpreted as the year 1900. This could result in a system failure or miscalculations causing disruptions of or errors in operations. Systems potentially affected include not only information technology systems--computer systems controlling a company's accounting, land, operations, seismic processing, and other specialized functions--but also non-information technology systems controlled by embedded chips, which include many common and specialized machines and support systems. The effects of the Year 2000 problem can be exacerbated by the interdependence of computer and telecommunications systems in the United States and throughout the world. This interdependence can affect us and the parties with whom we do business. STATE OF READINESS. We have created an internal committee to assess our Year 2000 readiness and to lead our remediation efforts. The committee is composed of the general counsel, chief financial officer, controller, and manager of information systems. The committee's objective is to prevent loss or impairment of those functions material to Basin's operations and business continuity or to avoid potential liability to third parties. At the direction of the committee, department heads and managers have assessed and remediated our information technology and non-information technology systems, and have communicated with our business partners regarding the status of their assessment and remediation efforts, with the results summarized below. We have completed an assessment of our information technology systems to determine whether they are Year 2000 compliant. The licensors of both our core financial, land and operations software system and the underlying operating system have certified that such software is Year 2000 compliant. Our Gulf of Mexico seismic data interpretation software system is not currently Year 2000 compliant, but we have begun an upgrade of that system with software which the licensor has represented will be compliant. We are also upgrading our reservoir economics software to make it Year 2000 compliant. Basin expects the upgrade and testing of these software systems to be completed by July 1999. Additionally, we have assessed other less critical information technology systems and we believe them to be compliant. We also rely on non-information technology systems, such as office telephones, facsimile machines, HVAC systems and elevators in our leased offices, security systems, and automated measuring equipment on platforms and other production facilities, which may have embedded technology such as micro-controllers. Department heads and managers have identified those non- information technology systems that may be susceptible to failure or impairment by reason of Year 2000 problems and that are potentially critical to our operations and business continuity. Based on that review, Basin has sent written inquiries to the suppliers of those systems to determine the status of their Year 2000 compliance. Our communications systems vendors, and the property managers of the buildings in which our Houston and Denver offices are situated, have certified their systems to be Year 2000 compliant. We are still receiving and analyzing responses from vendors of non-information technology systems that may affect our production operations. The operations department will follow up those inquiries with telephone interviews to assess the status of such systems. Assessment and remediation of non-information technology systems should be completed by September 1999. We have sent written inquiries to our significant suppliers, customers, banks, government agencies, benefit plan providers, and others with whom we have significant business relationships to determine the extent to which we are vulnerable to those third parties' failure to correct their own Year 2000 issues. To date, we have not received definitive responses from many of these entities and therefore cannot assess whether they are Year 2000 compliant or how their failure to be compliant would affect us. Those third parties who have responded have generally indicated that S-37 they are either Year 2000 compliant or expect to be compliant. Our department heads and managers have compiled a list of critical third parties to whom telephone follow-up will be made. For Gulf of Mexico operations, these include representative vendors and suppliers who could supply necessary goods and services to maintain our production operations and continue any ongoing or planned drilling activities. We expect to have this follow-up inquiry completed by July 1999 and we will seek to use those vendors and suppliers providing adequate assurances regarding their compliance. ESTIMATED COMPLIANCE COSTS. We have relied primarily on our internal staff to assess our current Year 2000 readiness and do not anticipate extensive use of external resources to complete our assessment or remediation. We have not separately quantified our costs of internal resources on this project but do not expect that we will incur material costs in remediating our information technology systems to be Year 2000 compliant. Costs incurred for the purchase of new software and hardware are capitalized and all other costs are expensed as incurred. We have not incurred, and do not anticipate that we will incur, costs for external resources in excess of $100,000 relating to the assessment and remediation of Year 2000 issues. That estimate does not include the cost of remediating problems caused by third-party vendors, customers, or other business partners, which Basin will not be able to fairly estimate until the extent, if any, of their Year 2000 non-compliance is known. RISKS OF NON-COMPLIANCE AND CONTINGENCY PLANS. As indicated above, the only critical information technology systems that we believe are not yet Year 2000 compliant are our seismic data interpretation and reservoir economics systems, which should be compliant by July 1999. Accordingly, we do not expect Year 2000 issues to cause our information technology systems to have any material adverse impact on our business, operations or financial condition. We believe that the potential impact, if any, of our non-critical information technology systems not being Year 2000 compliant will at most require employees to manually complete otherwise automated tasks or calculations and should not impact our ability to continue exploration, drilling, production or sales activities. We are not able to predict at this time what the impact could be of non-information technology system failures but do not believe that there will be a material disruption of our operations. Until we have completed our inquiries to third parties, we will not be able to fairly assess the potential impact of their failure to be Year 2000 compliant on our operations, business, or financial condition. The most reasonably likely "worst case" impacts could be impairment of our ability to deliver our production to, or receive payment from, third parties gathering and/or purchasing our production from affected facilities, impairment of the ability of third-party suppliers or service companies to provide needed materials or services to our planned or ongoing operations, thereby necessitating deferral or shut-in of exploration, development or production operations, and our inability to execute financial transactions with our banks or other third parties whose systems fail or misfunction. We have no reason to believe that any of these contingencies will occur or that our principal vendors, customers, and business partners will not be Year 2000 compliant. Basin does not currently have a contingency plan under development or in place to address these potential problems. We do intend to develop contingency plans in response to testing our information technology and non-information technology systems and in response to the results of our third-party inquiries. These contingency plans may include installing back-up computer systems or equipment, temporarily replacing systems or equipment with manual processes, and identifying alternate suppliers, service companies and purchasers. Basin expects these plans to be complete by October 1999. Basin's Year 2000 program is a continuing process that may result in changes to cost esti- mates and schedules as testing and business partner assessment progresses. Unexpected Year 2000 compliance problems of either Basin or our vendors, customers, service providers, or other entities with whom we do business could have a material adverse impact on our business, financial condition or operating results. S-38 BUSINESS AND PROPERTIES Basin is an independent oil and gas company engaged in the exploration, development and acquisition of oil and gas properties located primarily in the shallow waters of the Gulf of Mexico. We are also active in selected areas of the onshore United States, including the Gulf Coast and the Powder River and Green River Basins of Wyoming. In 1996, we sold a significant portion of our developed properties in the Rocky Mountain region in order to commence an active exploratory drilling program in the Gulf of Mexico. Since that time we have substantially increased our proved reserves, production and cash flow from operations. Through May 1999, we have participated in the drilling of 37 wells in the Gulf of Mexico, 23 of which have been commercially successful, yielding a 62% success rate. As of December 31, 1998, our proved reserves totaled 180 Bcfe, 133% above our proved reserves of 77 Bcfe at December 31, 1996 and 30% greater than our proved reserves of 138 Bcfe at December 31, 1997. Approximately 71% of our proved reserves are gas and 75% are located in the Gulf of Mexico. Our average daily net production for 1998 was 60 MMcfe, a 154% increase over our 1997 average daily net production of 24 MMcfe. For the quarter ended March 31, 1999, our average daily net production was 76 MMcfe, of which 85% was gas and 15% was oil. By early April 1999, we had brought into production a substantial portion of our year-end 1998 proved non-producing reserves, and during April 1999 our average daily net production exceeded 100 MMcfe. Our revenues and cash flow from operations in 1998 increased from 1997 levels by 97% and 120%, to $48.7 million and $33.7 million, despite significantly lower prices for oil and gas in 1998. For 1998, our cash flow from operations per Mcfe of production was $1.53, which we believe was among the highest within the independent oil and gas sector. Approximately 70% of our proved reserves in the Gulf of Mexico are attributable to Miocene-age sands within an area known as the Miocene trend. The Miocene trend is a prolific oil and gas producing area characterized by subtle hydrocarbon indicators, which are more readily detectable using 3-D seismic data that has become available since the mid-1990s. This trend is primarily located in water depths of less than 150 feet near existing infrastructure, offering favorable drilling and development costs. We believe that there are significant remaining undiscovered reserves within the Miocene trend. We explore for these reserves by applying technical expertise specific to the trend utilizing modern 3-D seismic data. To facilitate our continued growth, we have assembled undeveloped leasehold positions totaling 255,141 gross acres, or 180,816 net acres, at December 31, 1998, more than half of which are in the Gulf of Mexico. We have also licensed more than 600 lease blocks of 3-D seismic data and 375,000 miles of conventional 2-D seismic data covering portions of the Gulf of Mexico. We have integrated this database with geological interpretations by our technical personnel to develop a multi-year inventory of more than 45 drilling prospects supported by 3-D seismic data. Basin's onshore activities include exploring and developing oil and gas properties in southern Louisiana and Texas and in the Powder River and Green River Basins of Wyoming. We have recently enhanced our onshore capabilities through the addition of experienced personnel and acquisitions of geophysical data. We plan to allocate approximately 15% of our capital expenditure budget in 1999 toward exploring and developing onshore properties. Although the shallow waters of the Gulf of Mexico will remain our primary area of focus, we believe that the longer reserve life and exposure to more diverse opportunities offered by these areas will complement our offshore efforts. Our onshore properties accounted for 11% of our production during the quarter ended March 31, 1999. We believe the current operating environment offers us attractive investment opportunities. Until recently, low prevailing oil and gas prices constrained capital availability and capital expenditures for oil and gas companies. The resulting decline in drilling activity has caused a substantial reduction in costs for oil field services. In addition, competition for exploratory leaseholds and property S-39 acquisitions has decreased as capital-constrained companies have sought to strengthen their balance sheets. Furthermore, prices for West Texas Intermediate oil and Henry Hub gas, as reflected on the New York Mercantile Exchange, have increased from $12.05 per Bbl and $1.95 per MMBtu at year-end 1998 to $18.03 per Bbl and $2.27 per MMBtu on May 15, 1999. We are pursuing the offering to take advantage of these favorable investment conditions, and we plan to use the additional borrowing capacity resulting from the offering to significantly increase our exploration and development activities. RECENT DEVELOPMENTS During 1999, our Gulf of Mexico activities have included the completion of three (1.95 net) exploratory wells that were successfully drilled in 1998, the drilling of seven (3.45 net) exploratory wells, of which two (0.55 net) wells were apparent discoveries and two (1.0 net) are currently drilling, and the drilling of one (0.65 net) successful development well. We also participated in one (0.60 net) exploratory well in Wyoming, which was abandoned in February 1999 due to an apparent underground blowout. We have since drilled and cased a replacement well, the cost of which was substantially funded by insurance proceeds. We are presently testing a secondary objective below the primary objective formation. On March 17, 1999, Basin submitted apparent winning bids for five leases at the federal Central Gulf of Mexico lease sale held by the Minerals Management Service. These leases cover 24,023 gross and net undeveloped acres offshore Louisiana. All of these leases, having an aggregate leasehold bonus cost of approximately $3.0 million, have been awarded to us by the Minerals Management Service. During 1999, Basin has sold assets consisting primarily of Gulf of Mexico exploratory prospects for total proceeds of approximately $8 million. Based on receipt of these proceeds, additional borrowing capacity following the offering, and our current projections of cash flow from operations, we plan to increase our capital expenditure budget for 1999 from $65 million to $95 million. We expect this increase in our capital expenditure budget to generate approximately a 50% increase in our drilling activity in 1999 over our original plans for the year. STRATEGY Our goals are to generate per-share growth in reserves, production, earnings and cash flow through exploration, acquisition and development of oil and gas properties. We seek to achieve these objectives through the following strategies: EXPLORE IN THE SHALLOW WATERS OF THE GULF OF MEXICO. Our exploration activities are focused primarily in the shallow waters of the Gulf of Mexico, a prolific producing area that we believe has substantial future potential. In particular, we have targeted the Miocene trend, which offers favorable drilling and operating costs and readily available and affordable 3-D seismic data. It also offers a substantial existing infrastructure of production platforms, pipelines, and processing facilities. CAPITALIZE ON TECHNICAL EXPERTISE. We have assembled a team of geoscientists and petroleum engineers with substantial Gulf of Mexico experience and expertise in generating prospects, evaluating acquisition opportunities, and managing drilling and production operations. We have also recently added senior management and technical personnel with substantial onshore operating experience, and we intend to use this in-house capability to identify and pursue growth opportunities in selected onshore areas. APPLY ADVANCED TECHNOLOGY. We use advanced technologies, including 3-D seismic data and computer-aided exploration to better define exploration prospects and development opportunities. Basin has licensed more than 600 lease blocks of 3-D seismic data and 375,000 miles of conventional 2-D seismic data covering portions of the Gulf of Mexico. S-40 BALANCE SIZE AND RISK PROFILE OF EXPLORATION TARGETS. We generally seek to conduct a drilling program that is balanced between exploration prospects with significant potential relative to our existing reserve base and smaller, lower risk prospects. This balance is intended to mitigate risk while providing exposure to meaningful growth in reserves and production. GENERATE PROSPECTS INTERNALLY. Basin's team of geoscientists internally generates prospects using its technical database and Landmark workstations. This allows us to retain large working interests and operating control and either to defray our capital investment by selling promoted interests or to increase our prospect inventory by swapping for interests in third-party generated prospects. We have internally generated more than 75% of our Gulf of Mexico prospects. OPERATE CORE PROPERTIES. During April 1999, we operated properties accounting for approximately 74% of our production. Operating allows us to exercise greater control over the cost, timing and character of our exploration, development and production activities. PURSUE SELECTIVE ACQUISITIONS. We actively seek to acquire interests in proved oil and gas properties with exploration or development potential to augment operations in our core areas and to establish positions in new areas. MAINTAIN FINANCIAL FLEXIBILITY. Basin is committed to maintaining financial flexibility in order to pursue exploration and development activities and take advantage of acquisition opportunities. The offering will enhance our financial flexibility by reducing our debt. As of March 31, 1999, after giving effect to receipt of the net proceeds of the offering, we would have had total debt of $33 million, leaving $57 million of our revolving line of credit undrawn. As of the same date, after giving effect to the offering, our total debt per Mcfe of 1998 year-end proved reserves would have been $0.18. We believe this level of debt per Mcfe is among the lowest within the independent oil and gas sector. PRINCIPAL PRODUCING PROPERTIES Our principal producing properties are located offshore in the shallow waters of the Gulf of Mexico and in the Powder River and Green River Basins in Wyoming. Our Gulf of Mexico properties accounted for 75% of our proved reserves at December 31, 1998 and 89% of our production for the quarter ended March 31, 1999. As of December 31, 1998, Basin's Gulf of Mexico proved reserves were distributed among 18 fields. Production had been established from 14 of these fields as of that date, and the other four fields were under development for first production. Our working interests in the 18 fields ranged from approximately 8% to 100%, with an average of 54%. We operate 11 of the 18 fields and these 11 properties accounted for approximately 67% of our Gulf of Mexico production for the quarter ended March 31, 1999 and two-thirds of our total proved reserves in the Gulf of Mexico at the end of 1998. Most of Basin's onshore proved reserves as of December 31, 1998 were concentrated in six fields in the Powder River and Green River Basins. These reserves were broadly distributed among approximately 200 producing wells, as well as a limited number of undeveloped locations. Most of our producing wells in the Rocky Mountain area have been on-line for several years and their respective production declines are relatively moderate and well-established. No individual onshore field accounted for more than 3% of the estimated present value of our reserves at the end of 1998. We own a majority working interest in most of our onshore proved properties and we act as operator of properties accounting for 59% of our total proved onshore reserves at the end of 1998. Our onshore properties accounted for 25% of our proved reserves at December 31, 1998 and 11% of our production for the quarter ended March 31, 1999. The following table presents information about our ten most valuable producing properties at December 31, 1998, as measured by the estimated pre-tax present value of future net cash flows. As shown below, these ten properties accounted for 80% of Basin's estimated pre-tax present value S-41 related to proved reserves at December 31, 1998. These same properties accounted for 79% of our total oil and gas production in the first quarter of 1999, which averaged 75.5 MMcfe per day.
PERCENTAGE PERCENTAGE BASIN BASIN NET OF FIRST OF 12/31/98 WORKING REVENUE QUARTER PRE- TAX INTEREST INTEREST 1999 NET PV-10 FIELD OPERATOR (%) (%) PRODUCTION VALUE(1) - ----------------------------------- ------------ ----------- ----------- ---------- ------------ West Cameron Block 45.............. Basin 100% 79% 19% 25% West Delta Block 61 S/2............ Basin 65 46 0(2) 11 High Island Block A-568............ Samedan 33 28 14 9 Eugene Island Block 65............. Basin 76 62 9 7 East Cameron Block 378............. Sonat 47 37 8 7 East Cameron Block 34.............. Basin 60 49 3 6 West Cameron Block 56 N/2.......... Basin 67 51 14 6 Eugene Island Block 49............. Basin 100 81 5 3 East Cameron Block 220............. Basin 100 81 4 3 West Cameron Block 172............. IP Petroleum 15 12 3 3 Other Fields....................... 21 20 ---- ---- Total............................ 100% 100%
- ------------------------ (1) Pre-tax PV-10 value refers to the pre-tax present value at December 31, 1998 of estimated future net cash flows before income taxes discounted at 10% per annum, calculated using unescalated prices and costs in effect on the date of the applicable reserve reports (unless such prices or costs are subject to change pursuant to contractual provisions). (2) First production established during April 1999. The ten properties shown in the table above are all located in the Gulf of Mexico. Each of these is briefly described below. WEST CAMERON BLOCK 45 FIELD. West Cameron Block 45 is located five miles offshore Louisiana in water depth of 34 feet. We acquired a 100% working interest in this property in November 1997. The field had been on production since the 1940s, and had recovered over 500 Bcfe at the time of our acquisition, but it had never been exploited with the benefit of modern 3-D seismic data and production had declined to less than 4 MMcfe per day. Before we acquired the property, we used 3-D seismic to identify several prospects in multiple lower Miocene-age sands. In the second and third quarters of 1998, we drilled three successful exploratory wells on West Cameron Block 45 in separate structural fault blocks. We modified an existing West Cameron Block 45 platform to handle the additional production, and we brought the three new wells on-line at various times in late 1998 and 1999. Gross production from the field during the quarter ended March 31, 1999 averaged approximately 20 MMcfe per day. WEST DELTA BLOCK 61 S/2 FIELD. We acquired a 100% working interest in certain intervals under the south-half of West Delta Block 61 through a farm-in from another energy company. The property is located 15 miles offshore Louisiana in water depth of 105 feet. West Delta Block 61 is part of a producing field complex that extends into Block 62 to the west, and which has produced in excess of 75 Bcf of gas and 1.0 MMBbl of oil and condensate from multiple Miocene-age sands. Twelve wells had been drilled on West Delta Block 61 prior to our farm-in. Using data from a new 3-D seismic survey, we identified an undrilled structural fault block with several seismic amplitude anomalies. We drilled the #8 well in the second quarter of 1998 to test the field and in early 1999, we drilled and completed the #B-2 development well, and subsequently installed a platform and a pipeline that connected the facility to a nearby third-party platform for processing. Production from both the #8 and the #B-2 wells commenced in early April 1999. S-42 HIGH ISLAND BLOCK A-568 FIELD. High Island Block A-568 is located 100 miles offshore Texas in 280 feet of water. We purchased a 33.3% working interest in this block as part of the November 1997 acquisition that also included interests in West Cameron Block 45. Prior to our acquisition, 15 wells had been drilled on High Island Block A-568 and cumulative production from the field had exceeded 105 Bcfe from multiple Pleistocene-age sands. In the second half of 1997, prior to our acquisition, the joint owners drilled two new wells in the field to exploit potential reserves identified with 3-D seismic data. We had identified the drilling potential using 3-D data before the wells were drilled, but had been unsuccessful in attempts to acquire the property beforehand. Both wells were drilled from an existing production platform, expediting development, and first sales occurred in November 1997 and January 1998, respectively. EUGENE ISLAND BLOCK 65 FIELD. We acquired a 100% working interest in Eugene Island Block 65 in April 1996, at the first federal Gulf of Mexico lease sale in which Basin participated. The property is located 18 miles offshore Louisiana in water depth of 21 feet. Two wells previously drilled on the block by another operator had established marginal production and had then been abandoned. Utilizing new 3-D seismic data, we were able to identify two prospective traps in multiple Miocene-age sands that had not been tested. We subsequently drilled two successful exploratory wells on this block, after promoting interests out to partners while retaining control of operations. We initiated production from both wells in August 1997, within seven months of drilling the discovery well, after installing a production platform with facilities and a connecting pipeline. In November 1998, the #2 well on Eugene Island Block 65 stopped producing after cement behind production casing failed to hold, allowing water to channel into the well. We conducted a workover and re-completion operation to seal off the water and returned the well to production in March 1999. We owned a 37.5% working interest in Eugene Island Block 65 when the discovery well was drilled, and have increased our ownership interests in the field over time through purchasing the interests of two partners and earning reversionary interests when project payout was reached in September 1998. Currently, we own a 76.4% working interest in the lease, but also retain the remaining 23.6% working interest in the #2 well until 400% of costs related to the recent repair are recouped, due to a partner's election not to participate in the operation. EAST CAMERON BLOCK 378 FIELD. East Cameron Block 378 is located 110 miles offshore Louisiana, in water depth of approximately 450 feet. In February 1997, we acquired a 46.5% working interest in a discovery well that had recently been drilled and completed subsea on the block. The operator of the property initiated production from the well in July 1998, after laying lines to connect the well to a nearby third-party platform for processing. EAST CAMERON BLOCK 34 FIELD. We acquired a 60% working interest in East Cameron Block 34 at the March 1997 federal Central Gulf of Mexico lease sale. The property is located seven miles offshore Louisiana in water depth of 37 feet. East Cameron Block 34 is part of a producing field complex that extends into Block 33 to the west which produced in excess of 390 Bcf of gas and 2.5 MMBbl of condensate from multiple Miocene-age sands. Five wells had been drilled on the block prior to our acquisition. Before acquiring the block, Basin acquired a 3-D seismic survey and identified three prospects in multiple Miocene-age sands. In the first quarter of 1998, after drilling a non-commercial well on the block at the beginning of the year, Basin drilled a second exploratory well to test a separate prospect. Production commenced from the well in the fourth quarter of 1998 after installation of a caisson platform with facilities and a pipeline connection. Basin has identified another prospect on the block that will be considered for drilling at a later date. S-43 WEST CAMERON BLOCK 56 N/2 FIELD. We acquired a 100% working interest in certain intervals under the northeast quarter of West Cameron Block 56 through farm-in. We retained a 66.7% working interest and operations after bringing in an industry partner on a promoted basis prior to drilling a test well. This block is located seven miles offshore Louisiana in water depth of 35 feet. It is part of a producing field complex extending into West Cameron Block 45 to the north, which has produced more than 400 Bcf of gas and 13 MMBbl of oil and condensate from multiple Miocene-age sands. Prior to our farm-in, 23 wells had been drilled on West Cameron Block 56. Utilizing 3-D seismic data, we identified an undrilled structural fault block with a seismic anomaly. In the third quarter of 1997, we drilled a successful exploratory well on the prospect. We initiated production from this well in April 1998 after installing a caisson facility and pipeline to connect the well to a production platform on adjacent West Cameron Block 45. As part of a separate transaction closed in November 1997, we acquired the farmor's residual interest in West Cameron Block 56 and its 100% working interest in West Cameron Block 45, along with certain other properties. EUGENE ISLAND BLOCK 49 FIELD. This property is found 20 miles offshore Louisiana, in water depth of 20 feet. We acquired a 100% working interest in Eugene Island Block 49 at the March 1997 federal Central Gulf of Mexico lease sale. Another company drilled a well on this block in 1992 that encountered gas in three zones, but was not completed. Utilizing new 3-D seismic data and conventional well log analysis, we identified a prospect with multiple upper-Miocene sand objectives in a better structural location than encountered by this abandoned well. We also identified two additional modest-sized prospects on the block. In the third quarter of 1997, we drilled the primary prospect and commenced completion operations after finding commercial reserves. Production commenced from the well in the third quarter of 1998 after we installed a caisson platform and a pipeline to connect the facility to a nearby third-party production platform for processing. EAST CAMERON BLOCK 220 FIELD. We obtained our 100% working interest in this producing property through an acquisition in November 1997. The block is located 65 miles offshore Louisiana in 118 feet of water. The East Cameron Block 220 Field has produced over 78 Bcf from 17 wells since October 1980, including approximately 42 Bcf from shallow Pleistocene reservoirs and over 36 Bcf from a deeper Pliocene reservoir. East Cameron Block 220 is part of a producing field complex that includes adjacent blocks 219 and 221. Production from the property had declined to uneconomic rates and was shut-in at the time we acquired the block. Our principal interest in the property related to several prospective exploratory locations that we identified with 3-D seismic data prior to making the acquisition. During the first half of 1998, we restored production from two existing well-bores through workovers and in late-1998 we drilled a successful exploratory well from an existing platform on the block. Production from the new well was initiated in the first quarter of 1999. We anticipate drilling another exploratory well on the block later this year, as further discussed below. WEST CAMERON BLOCK 172 FIELD. This property is located 27 miles offshore Louisiana in 49 feet of water. We acquired a 15% working interest in West Cameron Block 172 from another energy company in 1998 after identifying several undrilled prospective fault closures with new 3-D seismic data. The block is part of a field complex that had previously produced approximately 60 Bcfe from Miocene-age sands out of six wells. We participated in drilling an unsuccessful well on a shallow prospect on the block in early 1998, but then participated in drilling three successful wells on the property during the second half of 1998 and early 1999. Each of these wells encountered multiple Miocene-age sands below a true vertical depth of 8,800 feet. Production from the first two discovery wells was initiated in December 1998 and January 1999 and the third well is expected to commence production during the third quarter of this year. S-44 EXPLORATORY PROSPECTS OFFSHORE EXPLORATORY PROSPECTS Basin currently has an inventory of more than 45 undrilled prospects in the Gulf of Mexico. The following table shows information regarding those leases on which we have identified one or more undrilled prospects. Virtually all of our Gulf of Mexico prospects are supported by 3-D seismic data.
BASIN BASIN NET WORKING REVENUE INTEREST INTEREST LEASE PROSPECT OPERATOR (%) (%) EXPIRATION - ----------------------------------------------- ------------- ----------- ----------- --------- East Cameron Block 34.......................... Basin 60 49 (1) East Cameron Block 44.......................... Basin 100 81 07/01/03 East Cameron Block 51.......................... Basin 100 81 07/01/03 East Cameron Block 65.......................... Basin 75 61 06/01/03 East Cameron Block 220......................... Basin 50 40 (1) Chieftain East Cameron Block 255......................... Int'l 40 32 08/01/02 East Cameron Block 271......................... Basin 100 81 07/01/04 East Cameron Block 378......................... Hall-Houston 23 17 (1) Eugene Island Block 13......................... Basin 100 74 01/12/02 Eugene Island Block 65......................... Basin 76 62 (1) Eugene Island Block 82......................... Basin 50 41 09/01/01 Galveston Block 190............................ Houston Expl. 23 18 12/31/03 Chieftan Grand Isle Block 66............................ Int'l 40 32 08/01/02 Main Pass Block 265............................ Basin 50 40 07/01/03 Mississippi Canyon Block 110................... Shell 8 6 07/31/02 Mustang Island Block A65....................... Basin 100 81 10/01/03 South Marsh Island Block 286................... Basin 100 81 07/01/02 South Pass Block 47............................ Basin 50 40 05/01/04 Vermilion Block 16............................. Basin 60 49 07/01/02 Vermilion Block 48............................. Basin 100 82 06/01/01 Vermilion Block 83............................. Basin 50 40 08/01/03 Vermilion Block 267 N/2........................ Basin 40 32 05/01/02 West Cameron Block 62.......................... Basin 100 81 06/01/03 West Cameron Block 69.......................... Basin 100 82 07/01/01 West Cameron Block 72.......................... Basin 100 82 06/01/01 West Cameron Block 104......................... Basin 100 82 07/01/01 West Cameron Block 287......................... Basin 100 81 07/01/04 Chieftain West Cameron Block 300......................... Int'l 25 20 06/30/00 West Cameron Block 476......................... Basin 50 40 06/01/03 West Delta Block 63............................ Basin 50 40 06/01/03 West Delta Block 87............................ Basin 100 81 08/01/03 West Delta Block 98............................ Basin 100 81 07/01/04 West Delta Block 121........................... Vastar 25 20 08/01/03 West Delta Block 122........................... Vastar 25 18 (2) West Delta Block 131........................... Basin 100 81 07/01/04 West Delta Block 140........................... Basin 100 81 08/01/03 AVERAGE (36 LEASES)............................ 68 55
(1) Lease held for an indefinite extended term so long as production continues. (2) Lease extension granted by the Minerals Management Service pending development for production. S-45 Described below are twelve of the exploratory prospects that Basin expects to drill during the next twelve months, including several that we assess as being among our higher potential prospects. We can give no assurance that we will drill these prospects during the next year or afterwards, as drilling plans are affected by many factors, including some that may not be in our control. See "Risk Factors--Exploration is a high risk activity and the 3-D seismic and other advanced technologies we use are expensive, require experienced personnel, and cannot eliminate exploration risk". EAST CAMERON BLOCK 65 PROSPECT. We acquired a 100% working interest in East Cameron Block 65 at the March 1998 federal central Gulf of Mexico lease sale for approximately $3.7 million, and subsequently sold a 25% working interest in the prospect on a promoted basis and recouped a proportionate share of our investment. We plan to sell or exchange additional interests in the property in order to own between 30% and 50% at the time of drilling. Our prospect targets Miocene-age sands below 15,000 feet. We anticipate drilling the prospect in the second half of 1999. The property is located 25 miles offshore Louisiana in water depth of 55 feet. EAST CAMERON BLOCK 220 PROSPECT. East Cameron Block 220 is located 65 miles offshore Louisiana in 118 feet of water. We acquired a 100% working interest in this producing property as part of a November 1997 transaction. The field has produced a total 78 Bcfe from two shallow Pleistocene-age structures approximately 3,000 feet deep and from a deeper Pliocene-age structure found at approximately 11,000 feet. The prospect's primary objectives are approximately 600 feet deeper than the lowest producing Pliocene-age sands in the East Cameron Block 220 Field. The objective sands are lower Pliocene-age sands characterized by 3-D seismic data anomalies that correlate with proved reservoirs in the upper Pliocene-age section. The trap is the same faulted structure that traps hydrocarbons in the upper Pliocene sand horizon, and the equivalent-age sands are found at adjacent Block 219 to the east. We recently sold a 50% working interest in the exploratory rights, but not the proved reserves, on the block on a promoted basis and anticipate drilling a well later this year to evaluate this prospect. EAST CAMERON BLOCK 378 PROSPECT. This block is located 110 miles offshore Louisiana in 450 feet of water. We acquired a 23.25% working interest in the exploratory rights on this block in February 1997 as a part of an acquisition that also included a 46.5% interest in the discovery well described above. The seller retained half of its original interest. The exploratory prospect targets Pleistocene-age sands that exhibit several stacked anomalies below 11,000 feet true vertical depth, on the flank of a salt dome. Basin participated in reprocessing the 3-D seismic data across the block in order to improve the imaging of the salt-sediment interface. We expect the operator to propose drilling a test well in late 1999 or early 2000 to evaluate this prospect. GALVESTON BLOCK 190 PROSPECT. We acquired a 45% working interest in Galveston Block 190 at the August 1998 federal Western Gulf of Mexico lease sale for approximately $1.0 million and subsequently sold one-half of our interest to a working interest partner on a promoted basis and recouped a proportionate share of our investment. The block is located 15 miles offshore Texas in 40 feet of water. Our main objective on this prospect will be Miocene-age sands found at 14,200 feet, along a fault that is part of the same system of faults that traps shallower sands at Galveston Block 189. Seismic data does not evidence hydrocarbon indicators for this prospect, due to the formation depth and pressure environment, but a recent 3-D seismic survey indicates that the prospect is structurally updip of a well that tested hydrocarbons from the same sands. When drilling the test well to evaluate our main objective, we will also test a shallower prospect in shallower Miocene-age sands in an upthrown structural closure. We currently anticipate that the operator will propose drilling a test well on the block later this year. MAIN PASS BLOCK 265 PROSPECT. We acquired a 100% working interest in Main Pass Block 265 for approximately $3.3 million at the March 1998 federal Central Gulf of Mexico lease sale. Subsequently, we sold 25% working interests to each of two partners on a promoted basis and S-46 recouped a proportionate share of our investment. Our principal targets on the block, which is located 45 miles offshore Louisiana in water depth of 230 feet, are two separate stratigraphic traps in the Miocene-age sand interval below 12,000 feet. Both prospects exhibit good anomalies with strong hydrocarbon indicators analogous to numerous fields discovered in the same area utilizing recent 3-D seismic data. We anticipate drilling the first test well to a true vertical depth of 12,500 feet in the third quarter of 1999. SOUTH PASS BLOCK 47 PROSPECT. This property is located eight miles offshore Louisiana in 225 feet of water. We acquired a 100% working interest in South Pass Block 47 at the March 1999 federal Central Gulf of Mexico lease sale for approximately $0.2 million and subsequently sold a 50% working interest in the prospect on a promoted basis, recouping a proportionate share of our investment. Two wells drilled by another company previously produced approximately 21 Bcfe from this block. Using recent 3-D seismic data, we identified two separate prospects on the block in Pliocene-age sands that exhibit strong anomalies similar to anomalies evidenced by productive fields along the trend. We anticipate drilling a test well to a true vertical depth of approximately 10,000 feet later this year to evaluate the first of these prospects. VERMILION BLOCK 16 PROSPECT. This block is located three miles offshore Louisiana in 25 feet of water. Basin acquired a 60% working interest in the lease at the March 1997 federal Central Gulf of Mexico lease sale for approximately $0.3 million. It is an 800-acre federal lease bordering Louisiana state waters. The prospect is located in a prolific lower-Miocene trend, called the Rob M, that has produced in excess of 2.7 trillion cubic feet of gas equivalents from the same age sands about three miles southeast at the Vermilion 25/26 Field. This prospect covers a much smaller area and has much smaller reserve potential than the Vermilion 25/26 Field, but it exhibits analogous features. Our prospect straddles a lease line and resides on both Vermilion Block 16 and Vermilion Block 25, which is held by another company. As a result, we anticipate that a test well will most likely be drilled on a joint basis after an equitable split of prospect ownership is negotiated between owners of both blocks. Therefore, we cannot now quantify our ultimate ownership interest in the prospect or predict the timing of a test well. We do, however, expect these matters to be resolved to facilitate drilling a test well later this year or in 2000 to an anticipated target depth of approximately 16,000 feet. VERMILION BLOCK 83 PROSPECT. This block is located 23 miles offshore Louisiana in water depth of 55 feet. We acquired a 100% working interest in Vermilion Block 83 for approximately $2.3 million at the March 1998 federal Central Gulf of Mexico lease sale. Subsequently, we sold 25% working interests to each of two partners on a promoted basis and recouped a proportionate share of our investment. The prospect targets Miocene-age sand. The prospect is supported by an anomaly evident on new 3-D seismic data that appears to be analogous to one found at the Vermilion Block 84, which has produced approximately 52 Bcfe to date. We have commenced the drilling of a test well to a planned true vertical depth of approximately 9,000 feet to evaluate this prospect. VERMILION BLOCK 267 N/2 PROSPECT. This half-block is located 70 miles offshore Louisiana in 160 feet of water. We acquired a 40% working interest in this lease at the March 1997 federal Central Gulf of Mexico lease sale for approximately $0.2 million. This prospect targets Pliocene age sands at 11,300 feet which exhibit good anomalies with strong hydrocarbon indicators on 3-D seismic. The lease offsets an adjacent producing field that has produced approximately 85 Bcfe to-date. We anticipate drilling a test well later this year to evaluate this prospect. WEST DELTA BLOCK 63 PROSPECT. This property is located 20 miles offshore Louisiana in water depth of 125 feet. We acquired a 100% working interest in West Delta Block 63 for approximately $3.2 million at the March 1998 federal Central Gulf of Mexico lease sale, and subsequently brought in a 50% working interest partner on a promoted basis and recouped a proportionate share of our investment. The block was previously part of the West Delta Block 62 Field complex and became available just prior to the lease sale. The principal targets on this block are in the Miocene-age sand S-47 interval, in two separate structural traps formed along the same fault system as on West Delta Block 62. Another company previously drilled one of the prospects, which tested positive for hydrocarbons but was not developed. Using recent 3-D seismic data, we anticipate being able to encounter the same sands in an improved structural position and to evaluate additional untested sands. The second prospect is located updip of a well that produced hydrocarbons from the same sands but was not located in an optimal position on the structure and prematurely watered out. As with the other prospect on this block, we anticipate using a recent 3-D seismic survey to enhance the positioning of a well to develop the potential reserves. We have commenced the drilling of a test well to a planned true vertical depth of approximately 14,000 feet to evaluate the initial prospect on this block. If that well is successful, we will also likely drill a second well this year to evaluate the second prospect on the block. WEST CAMERON BLOCK 72 PROSPECT. This property is located 11 miles offshore Louisiana in water depth of 38 feet. We acquired a 100% working interest in West Cameron Block 72 at the April 1996 federal Central Gulf of Mexico lease sale for approximately $0.4 million. This prospect targets multiple Miocene-age sands below a true vertical depth of 10,500 feet. These normally pressured water-drive reservoirs produced in excess of 100 Bcf of gas and 1.9 MMBbl of condensate between 1970 and 1995. Utilizing recent 3-D seismic data and conventional well log analysis, we have identified a prospect that is correlative to those abandoned wells in an improved structural location. We plan to sell or exchange interests in the property in order to own between 30% and 50% at the time of drilling, and anticipate drilling a test well in the second half of 1999 or in 2000. WEST DELTA BLOCKS 121 AND 122 PROSPECT. These two contiguous blocks are located on the north flank of a salt dome, found 28 miles offshore Louisiana in 270 feet of water. We acquired a 50% working interest in West Delta Block 122 through a farm-in in mid-1997 and proceeded to exchange one-half of our interest in the block for an interest in another prospect before drilling. An earlier lessee of West Delta Block 122 had produced less than one million barrels of oil and approximately one Bcf of gas from two wells on the block, between 1967 and 1969. We first identified our prospect using 2-D seismic data and then acquired a 1996 3-D seismic survey prior to negotiating a farm-in. In the third quarter of 1997, we participated in a successful exploratory well drilled on West Delta Block 122. A second well followed immediately, to evaluate a separate prospect on the block. This well was also a discovery, but the well was ultimately abandoned due to mechanical problems that occurred during drilling operations. We anticipate that this second well will be re-drilled at a later date as part of the overall development of the field. In March 1998, the partners in West Delta Block 122 jointly submitted the high bid for adjacent West Delta Block 121 at a federal Central Gulf of Mexico lease sale. We paid approximately $1.6 million for our 25% working interest share of West Delta Block 121. Development plans for West Delta Blocks 121 and 122 include installation in the third quarter of 1999 of a 12-slot platform capable of supporting a drilling rig and pipelines to transport production to a nearby platform for processing. The operator plans to initiate production from the field in the fourth quarter of 1999, and to resume drilling on the property later this year or in 2000. In addition to development potential established on these blocks, the joint owners have identified several prospective exploratory locations. Future drilling on West Delta Blocks 121 and 122 is expected to evaluate prospects in Pliocene-age sands trapped against a salt dome that exhibit anomalies on 3-D seismic data at depths between 9,500 feet and 14,000 feet. ONSHORE PROSPECTS We plan to invest approximately 15% of our total capital budget during 1999 in exploration and development activities outside of the Gulf of Mexico. Our objectives for this diversification are to establish one or more substantial operating areas to gain increased exposure over time to high quality investment opportunities, in order to balance our risk profile and enhance shareholder S-48 returns. We believe that the current depressed level of capital investments in the domestic exploration and production industry affords us an unusually favorable opportunity to gain entry and establish a strategic base of operations in areas that we assess as having desirable attributes for new investments. We have identified two principal onshore areas in which we plan to pursue opportunities that we believe will be complementary to our core activities in the Gulf of Mexico. We believe that the onshore Gulf Coast provides one of the best opportunities for us to establish a new impact area. Many sand formations and trapping structures in the onshore Gulf Coast are analogous to those found in the Gulf of Mexico, offering comparable advantages, such as the effectiveness of 3-D seismic data in identifying favorable drilling opportunities. A recent re-focusing away from this area by several major and large independent oil and gas companies has resulted in substantial reductions in the cost of 3-D seismic data and improvements in the availability of exploratory leaseholds. Drilling and other service costs have also significantly declined from the levels of 1997 and early 1998. Recently, we have negotiated access to 2,000 square miles of 3-D seismic data covering a prospective area in southern Louisiana. We have also acquired a 19% working interest in an exploratory prospect that we expect to be tested later this year. Further, we are negotiating to acquire additional 3-D seismic data and prospect participation interests. We will also target certain basins in the Rocky Mountain region where we believe application of technological advancements can significantly enhance drilling success rates or reserve recovery factors. Important technological improvements during the past several years in drilling, completion, fracture stimulation and 3-D seismic data have been applied in this region to enhance project returns. An example of this potential is the active basin-centered gas play in the greater Green River Basin in Wyoming, where tight sands gas production at some fields has been made economic through improved fracture stimulation techniques. Basin is currently participating in one exploration play of this type, at our Powder Mountain Prospect. POWDER MOUNTAIN PROSPECT. Basin operates this 19,000-acre federal unit, which is located in the southeast portion of the Greater Green River Basin of Wyoming. Basin owns a 60% working interest before payout and 45% after project payout. The main prospect target is the basin-centered, tight-gas sand intervals of the Lance formation found at depths between 11,400 feet and 12,900 feet. Three wells previously drilled on or near our acreage block penetrated the Lance formation, although the wells were targeting deeper objectives. Data from these earlier wells indicate the presence of up to 400 feet of over-pressured, gas-saturated tight sand intervals in the Lance Formation. Basin began drilling its initial well in the unit in late1998, but subsequently lost the well due to mechanical complications caused by an abnormally high-pressured sand in a secondary objective just below the Lance Formation. We abandoned the well and have since drilled and cased a replacement well, the expense of which was substantially funded by insurance proceeds. Logs confirm the presence of thick, highly pressured, tight gas sands. We expect to proceed with multiple fracture stimulation treatments of the Lance formation after initially testing a formation below the Lance. We identify the principal risks in this exploratory prospect as the adequacy of sand permeability and effectiveness of fracture stimulation, which remain undetermined. The stabilized production tests obtained from these treatments will begin to indicate the economic viability of the play. If the results are encouraging, future development could potentially include drilling multiple wells to develop the gas reserves in place. S-49 OIL AND GAS RESERVES Basin engaged Ryder Scott Company, independent petroleum engineers, to prepare estimates of proved reserves, projected future production, and related future net cash flows for certain of our properties as of December 31, 1998, and to audit Basin's estimates of such data for our remaining properties as of that date. Ryder Scott Company prepared reserve report estimates for certain of our oil and gas properties as of December 31, 1998 and audited estimates prepared by our engineers for our other properties as of that date. Estimates prepared by Ryder Scott Company or Basin's engineers were based upon a review of production histories and other geologic, economic, ownership, volumetric and engineering data. In determining the estimates of the reserves that are economically recoverable, oil and gas prices and estimated development and production costs as of December 31, 1998 were utilized. The following table sets forth estimates as of December 31, 1998 derived from Basin's reserve reports. The present values (discounted at 10 percent) of estimated future net cash flows before income taxes shown in the table are not intended to represent the current market value of the estimated oil and gas reserves owned by Basin. For further information concerning the present value of future net cash flows from these proved reserves, see Unaudited Supplemental Oil and Gas Reserve Information in the December 31, 1998 consolidated financial statements.
PROVED RESERVES --------------------------------------- DEVELOPED UNDEVELOPED TOTAL ----------- ------------- ----------- Oil (MBbls)......................................... 3,352 5,315 8,667 Gas (MMcf).......................................... 103,271 24,231 127,502 Total gas equivalents (MMcfe)....................... 123,383 56,121 179,504 Future net cash flows before income taxes (in thousands)........................................ $ 170,691 $ 45,413 $ 216,104 Present value of future net cash flows before income taxes (in thousands).............................. $ 137,775 $ 26,710 $ 164,485
Since December 31, 1998 oil and gas prices have increased significantly and the present value of the future net cash flows from our proved reserves has changed. Based on the New York Mercantile Exchange in effect on May 15, 1999 of $18.03 per barrel of West Texas Intermediate oil and $2.27 per MMBtu of Henry Hub gas, the present value of future net cash flows before income taxes of Basin's net proved reserves at December 31, 1998 would have been $236 million. The following table shows Basin's total proved reserves at December 31, 1998 and Basin's net production for the year ended December 31, 1998 by geographic area of operations:
PROVED RESERVES ------------------------------------------- OIL (MBBLS) GAS (MMCF) TOTAL (MMCFE) ------------- ------------ -------------- Gulf of Mexico.................................... 4,281 109,626 135,312 Onshore........................................... 4,386 17,876 44,192 ----- ------------ -------------- Total............................................. 8,667 127,502 179,504 ----- ------------ -------------- ----- ------------ --------------
The weighted average sales prices utilized for purposes of estimating Basin's proved reserves and future net cash flows therefrom as of December 31, 1998 were $10.31 per Bbl for oil and $1.99 per Mcf for gas. These prices are below the average prices prevailing during most of 1998, when we realized average oil and gas prices of $11.80 per Bbl and $2.07 per Mcf, respectively, before hedging effects. S-50 There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth herein represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and 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 and the existence of development plans. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered. Further, the estimated future net cash flows from proved reserves and the present value thereof are based upon certain assumptions, including geologic success, prices, future production levels and cost, that may not prove correct over time. Predictions about prices and future production levels are subject to great uncertainty, and the meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Oil and gas prices have fluctuated widely in recent years. There is no assurance that prices will not be materially higher or lower than the prices utilized in estimating Basin's reserves. See "Risk Factors--Oil and gas prices fluctuate frequently, and low prices could have a material adverse impact on our business". ACREAGE The following table illustrates the gross and net acres of developed and undeveloped oil and gas leases held by Basin as of December 31, 1998. Undeveloped acreage includes leasehold interests that may already have been classified as containing proved undeveloped reserves. A gross acre is one in which a working interest is owned. A net acre is the sum of the fractional working interests owned in gross acres.
DEVELOPED ACREAGE(1) UNDEVELOPED ACREAGE -------------------- -------------------- GROSS NET GROSS NET --------- --------- --------- --------- Louisiana offshore.................................................. 71,428 40,624 125,333 97,131 Texas offshore...................................................... 10,440 3,324 11,517 8,351 --------- --------- --------- --------- Total offshore.................................................... 81,868 43,948 136,850 105,482 --------- --------- --------- --------- Montana............................................................. -- -- 9,335 7,074 Utah................................................................ 1,810 932 14,979 9,639 Wyoming............................................................. 45,048 25,500 87,489 55,662 Other onshore....................................................... 1,910 883 6,488 2,959 --------- --------- --------- --------- Total onshore..................................................... 48,768 27,315 118,291 75,334 --------- --------- --------- --------- Total........................................................... 130,636 71,263 255,141 180,816 --------- --------- --------- --------- --------- --------- --------- ---------
- ------------------------ (1) Developed acreage is acreage assigned to producing wells for the spacing unit of the producing formation. Developed acreage in certain of Basin's properties that include multiple formations with different well spacing requirements may be considered undeveloped for certain formations, but have only been included as developed acreage in the presentation above. S-51 PRODUCTION The following table sets forth Basin's net oil and gas production, average sales prices, and costs and expenses associated with such production during the periods indicated.
YEAR ENDED DECEMBER 31, ------------------------------- 1996 1997 1998 --------- --------- --------- Production: Oil (MBbls).................................................................. 564 524 725 Gas (MMcf)................................................................... 4,776 5,509 17,616 Total gas equivalents (MMcfe)................................................ 8,160 8,653 21,966 Average daily net production: Oil (Bbls)................................................................... 1,540 1,435 1,988 Gas (Mcf).................................................................... 13,050 15,094 48,262 Total gas equivalents (Mcfe)................................................. 22,290 23,704 60,190 Average sales price per unit:(1) Oil (Bbl).................................................................... $ 20.88 $ 19.07 $ 11.80 Gas (Mcf).................................................................... 1.44 2.71 2.07 Total gas equivalents (Mcfe)................................................. 2.29 2.88 2.05 Production costs per Mcfe(2)................................................... $ 0.81 $ 0.68 $ 0.41
- ------------------------ (1) Excluding hedging effects. (2) Production costs include lease operating expense and production taxes. Basin owned 306 gross (202 net) producing oil wells and 77 gross (49 net) producing gas wells as of December 31, 1998. A well is categorized under state reporting regulations as an oil well or a gas well based upon the ratio of gas to oil produced when it first commenced production, and such designation may not be indicative of current production. DEVELOPMENT, EXPLORATION AND ACQUISITION EXPENDITURES The following table sets forth certain information regarding the costs incurred by Basin in its development, exploration and acquisition activities during the periods indicated.
YEAR ENDED DECEMBER 31, ----------------------------------- 1996 1997 1998 --------- ----------- ----------- (IN THOUSANDS) Development costs........................................................... $ 4,472 $ 17,901 $ 22,671 Exploration costs........................................................... 10,250 27,995 58,063 Property acquisition costs: Unproved(1)............................................................... 5,056 11,057 22,920 Proved.................................................................... 3,067 48,680 3,018 --------- ----------- ----------- Total costs incurred........................................................ $ 22,845 $ 105,633 $ 106,672 --------- ----------- ----------- --------- ----------- -----------
- ------------------------ (1) Excludes $4,914,000, $1,113,000 and $150,000 of costs recouped through the resale of partial interests in prospects to industry partners in 1996, 1997 and 1998, respectively. S-52 DRILLING ACTIVITY The following table sets forth the wells drilled and completed by Basin during the periods indicated.
YEAR ENDED DECEMBER 31, ----------------------------------------------------------- 1996 1997 1998 ---------------------- ---------------------- ----------- GROSS NET GROSS NET GROSS ----------- --- ----------- --- ----------- Development: Oil................................................................ 3 2.8 5 5.0 1 Gas................................................................ - - 1 0.6 - Non-productive..................................................... 1 .9 - - - -- -- -- -- -- Total............................................................ 4 3.7 6 5.6 1 -- -- -- -- -- -- -- -- -- -- Exploratory: Oil................................................................ - - - - - Gas................................................................ - - 5 3.2 8 Non-productive..................................................... 3 1.4 3 1.5 5 -- -- -- -- -- Total............................................................ 3 1.4 8 4.7 13 -- -- -- -- -- -- -- -- -- -- NET --- Development: Oil................................................................ 1.0 Gas................................................................ - Non-productive..................................................... - -- Total............................................................ 1.0 -- -- Exploratory: Oil................................................................ - Gas................................................................ 4.8 Non-productive..................................................... 2.2 -- Total............................................................ 7.0 -- --
S-53 MANAGEMENT DIRECTORS AND EXECUTIVE OFFICERS The following table sets forth the names, ages and titles of the executive officers and the members of the board of directors of Basin:
NAME AGE POSITION - ---------------------------------------------------- --------- ---------------------------------------------------- Michael S. Smith(1)................................. 44 Chairman of the Board, President and Chief Executive Officer Neil L. Stenbuck(1)................................. 46 Chief Financial Officer, Treasurer, Vice President and Director Howard L. Boigon(1)................................. 52 Vice President-General Counsel, Secretary and Director Thomas J. Corley.................................... 39 Vice President-Engineering and Production Patrick A. Jackson.................................. 46 Vice President-Onshore Exploration Dalton F. Polasek................................... 47 Vice President-Gulf Coast Engineering David A. Pustka..................................... 45 Vice President-Gulf Coast Exploration Samuel D. Winegrad.................................. 40 Vice President-Corporate Development Donald H. Anderson(2)(3)............................ 50 Director John F. Greene(2)(3)................................ 58 Director J. Paul Hellstrom(2)................................ 58 Director Michael A. Nicolais(2).............................. 73 Director Larry D. Unruh(2)(3)................................ 48 Director
- ------------------------ (1) Member of the Executive Committee. (2) Member of the Compensation and Incentive Committee. (3) Member of the Audit Committee. MICHAEL S. SMITH is Chairman of the Board, President, Chief Executive Officer, a director and a founder of Basin. Mr. Smith has been Chairman of the Board since 1983 and has been a director since inception. Mr. Smith was elected President and Chief Executive Officer in 1988. Mr. Smith is past president and a director of the Colorado Oil and Gas Association and served on the State of Colorado Governor's Minerals, Energy & Geology Policy Advisory Board. NEIL L. STENBUCK is Vice President-Finance, Chief Financial Officer, Treasurer and a director of Basin. He joined Basin in 1995. He was previously with United Meridian Corporation where he served as vice president--capital via the 1994 merger between UMC and General Atlantic Resources, Inc., where he held the same position beginning in 1989. He joined General Atlantic in 1987 as vice president--finance and accounting. Mr. Stenbuck is a certified public accountant. HOWARD L. BOIGON is Vice President-General Counsel, Secretary and a director of Basin. Mr. Boigon joined Basin in March 1992. Previously, he had been a partner in the Denver office of Davis, Graham & Stubbs since 1978, having been with the firm since 1973 specializing in the practice of oil and gas law. Mr. Boigon began representing Basin as outside counsel in 1989. He is past president and currently a director of the Colorado Oil and Gas Association, a member of the Executive Committee of RMOGA-Colorado and a member of the Advisory Board of the International Oil and Gas Educational Center of the Southwestern Legal Foundation. He has served as Chair of the Mineral Law Section of the Colorado Bar Association and Trustee of the Rocky Mountain Mineral Law Foundation. He has lectured and written on various topics of oil and gas law. S-54 THOMAS J. CORLEY is Vice President-Engineering and Production of Basin. He joined Basin in March 1996. For the previous three years he was vice president-manager of engineering at St. Mary Land & Exploration Company where he was responsible for the acquisition efforts and engineering functions of the company. From 1983 to 1993 he held various positions of increasing responsibility at General Atlantic Resources, Inc., involving operations, acquisitions and reservoir engineering and served there last as director of acquisitions. Mr. Corley is a member of the Society of Petroleum Engineers and served as a distinguished panel member at the 1995 SPE Annual Meeting. PATRICK A. JACKSON is Vice President-Onshore Exploration. Mr. Jackson joined Basin in February 1999. He spent the previous 19 years actively exploring in the United States and around the world with Amoco Production Company. From 1996 to 1999 Mr. Jackson was a member of a small team that evaluated the risks and opportunities of prospects in Amoco's worldwide portfolio. From 1993 to 1996 he served as Amoco's Onshore United States Exploration Manager. Prior to 1993, his responsibilities included prospect generation and evaluation, and management in the western United States. DALTON F. POLASEK, JR. is Vice President-Gulf Coast Engineering of Basin. Mr. Polasek has been employed in that position since February 1996. From 1994 to 1996, he was employed by SMR Energy Income Funds, as vice president of engineering. From 1991 to 1994, Mr. Polasek served as the director of Gulf Coast acquisitions/engineering for General Atlantic Resources. Prior to joining General Atlantic, Mr. Polasek served as manager of planning and business development for Mark Producing Company from 1983 to 1991. DAVID A. PUSTKA is Vice President-Gulf Coast Exploration and Gulf Coast Division Manager of Basin. He joined Basin in November 1995. From 1992 to 1995 he was vice president in charge of United States exploration for British-Borneo Exploration, Inc., a wholly-owned subsidiary of British-Borneo Petroleum Syndicate, PLC. From 1983 to 1992, he was responsible for exploration activities at Walter Oil & Gas Corporation, a privately held Gulf of Mexico exploration company, becoming a vice president in 1990. Mr. Pustka is a member of the American Association of Petroleum Geologists and the Houston Geological Society. SAM D. WINEGRAD is Vice President-Corporate Development of Basin. He joined Basin in August 1995. Mr. Winegrad was previously with United Meridian Corporation where he was vice president-land, the same position he occupied at General Atlantic Resources, Inc. at the time of its merger in 1994 with UMC. He joined General Atlantic in 1987 and became vice president-land the same year. DONALD H. ANDERSON is a director of Basin. He was elected to that position in November 1997. He is the executive director and a principal of Western Growth Capital LLC, a Colorado-based private equity investment and consulting firm. He joined WGC in March 1997 and has assumed responsibility for the firm's private equity and consulting services activities. Prior to joining WGC, Mr. Anderson was chairman, president and chief executive officer of PanEnergy Services, PanEnergy's non-jurisdictional operating subsidiary, from December 1994 until PanEnergy's announced merger with Duke Energy in March 1997. In that capacity, he was responsible for PanEnergy's gas and electric marketing, gas gathering and processing, and crude oil and gas liquids trading and pipeline transportation activities. Mr. Anderson was previously president, chief operating officer and director of Associated Natural Gas Corporation, the primary purchaser of our production in the Denver-Julesberg Basin, from 1989 until its merger with PanEnergy in 1994. He is a director of Genesis Energy, LLC. JOHN F. GREENE is a director of Basin. He was elected to that position in February 1996. From 1985 until his retirement in 1995, he served as executive vice president of exploration and production for the Louisiana Land and Exploration Company, where he served on the board of directors from 1989 until his retirement. From 1981 to 1985, Mr. Greene was president and chief executive S-55 officer for Milestone Petroleum and then executive vice president of exploration for Meridian Oil and Gas Company via its merger with Milestone. He began his career at Continental Oil Company holding various positions including director of exploratory projects for onshore and offshore offices and division exploration manager for the western United States. Mr. Greene serves as a director of the Colorado Wyoming Reserve Company, an oil and gas exploration company. J. PAUL HELLSTROM is a director of Basin. He was elected to that position in March 1992. Mr. Hellstrom was employed by The First Boston Corporation from 1975 to 1989. At the time of his retirement in 1989, Mr. Hellstrom was co-head of First Boston's Real Estate Group, earlier having served as head of its Energy and Project Finance Groups. Prior to joining First Boston, he was a first vice president in charge of the Project Finance Group at Blyth Eastman Dillon & Co., Inc. and an Assistant Treasurer with Manufacturers Hanover Trust Company. Mr. Hellstrom currently serves as a director of First Reserve Corporation. First Reserve is a direct investor in natural resource and energy-related industries. MICHAEL A. NICOLAIS is a director of Basin. He was elected to that position in March 1992. Since April 1993 he has been employed by Carret & Co., Inc. as Senior Managing Director. From June 1991 to April 1993, he was employed by Goldman Capital Management, Inc. as Managing Director. From 1949 to 1991, Mr. Nicolais was employed by The Clark Estates, Inc., serving as president from 1968 to 1990. Mr. Nicolais served as a director of Mesa Petroleum Company from 1969 until 1984. He serves as a director of Hitox Corp. of America. LARRY D. UNRUH is a director of Basin. He was elected to that position in March 1992. Since 1982 he has been the managing tax partner at Hein + Associates, certified public accountants. During 1980 and 1981, he was chief financial officer of Otis Energy Inc. Prior to 1980, Mr. Unruh held tax and accounting positions with Hein + Associates, Coopers & Lybrand and Peat, Marwick Mitchell & Co. Mr. Unruh is a certified public accountant and is a member of the Federal Tax Division of American Institute of Certified Public Accountants. Mr. Unruh serves as a director of Altris Software, Inc., an electronic imaging company. S-56 SELLING STOCKHOLDER The following table sets forth certain information regarding the beneficial ownership of the common stock as of June 17, 1999, and as adjusted to reflect the offering of 250,000 shares by the selling stockholder, Michael S. Smith, the Chairman of the Board, President, and Chief Executive Officer of Basin, and 3,750,000 shares by Basin:
SHARES BENEFICIALLY SHARES BENEFICIALLY OWNED PRIOR TO THE OWNED AFTER THE OFFERING OFFERING(2) ------------------------ NUMBER OF SHARES TO BE ------------------------ SELLING STOCKHOLDER NUMBER PERCENT SOLD IN THE OFFERING NUMBER PERCENT - ----------------------------------------- ----------- ----------- ---------------------- ----------- ----------- Michael S. Smith(1) ..................... 3,036,229 21.4 250,000 2,786,229 15.6 Suite 3400 370 Seventeenth St. Denver, CO 80202
- ------------------------ (1) Includes 2,390,628 shares held by Mr. Smith; 304,300 shares held by Iris Smith, Mr. Smith's wife; 96,000 shares held by trusts for Mr. Smith's children, of which Mr. Smith is trustee; 4,000 shares held by Mr. Smith's children; and 76,468 shares held by KaiTar Foundation, a nonprofit charitable foundation of which Mrs. Smith is president and Mr. Smith is vice-president. Mr. Smith has no voting or investment power with respect to the shares held by Iris Smith and disclaims beneficial ownership of such shares. Mr. Smith, in his capacity as the trustee of the trusts for his children and as vice president of KaiTar Foundation, has voting and investment power with respect to the shares held in such capacity and may be deemed to be the beneficial owner of such shares but disclaims beneficial ownership of such shares. Also includes options for 94,167 shares exercisable within 60 days, 10,666 shares of restricted stock the restrictions on which lapse on February 3, 2000, and 60,000 performance shares, the restrictions on which lapse December 31, 1999, December 31, 2000 and December 31, 2001 in equal amounts of 20,000 shares per year. (2) Excludes the underwriters' option to purchase up to 562,500 additional shares from Basin and up to 37,500 additional shares from Mr. Smith pursuant to the terms of the underwriting agreement. If this option is exercised in full, Mr. Smith will beneficially own 2,748,729 shares or 14.9% of the common stock. The preceding information regarding the selling stockholder supersedes the information under the heading "Selling Stockholder" in the accompanying prospectus. EXPERTS The consolidated financial statements for each of the three years ended December 31, 1998 included in this prospectus supplement have been audited by Arthur Andersen LLP, independent public accountants, as indicated in their report with respect thereto, and are included herein in reliance upon the authority of said firm as experts in giving said report. Estimates of Basin's historical onshore oil and gas reserves as of December 31, 1995, 1996 and 1997 are based upon engineering studies prepared by Basin and audited by the independent engineering firm of Netherland Sewell & Associates, Inc. Estimates of historical offshore reserves of Basin as of December 31, 1996, 1997 and 1998 and onshore oil and gas reserves as of December 31, 1998 are based upon engineering studies either prepared by the independent engineering firm of Ryder Scott Company Petroleum Engineers or prepared by Basin and audited by Ryder Scott Company Petroleum Engineers. Such estimates are included in reliance upon the authority of such firms as experts in such matters. VALIDITY OF COMMON STOCK The validity of the shares of common stock offered hereby will be passed upon for Basin by Davis, Graham & Stubbs LLP, Denver, Colorado. The validity of the shares of common stock offered hereby will be passed upon for the underwriters by Sullivan & Cromwell, New York, New York. S-57 INDEX TO FINANCIAL STATEMENTS
PAGE --------- Interim Consolidated Financial Statements (Unaudited): Consolidated Statements of Operations for the three months ended March 31, 1998 and 1999................... F-1 Consolidated Balance Sheets as of December 31, 1998 and March 31, 1999..................................... F-2 Consolidated Statements of Cash Flow for the three months ended March 31, 1998 and 1999.................... F-3 Consolidated Statements of Changes in Stockholders' Equity for the period from January 1, 1998 through March 31, 1999........................................................................................... F-4 Notes to Consolidated Financial Statements................................................................. F-5 Audited Consolidated Financial Statements: Report of Independent Public Accountants................................................................... F-6 Consolidated Statements of Operations for the years ended December 31, 1996, 1997, and 1998................ F-7 Consolidated Balance Sheets as of December 31, 1997 and 1998............................................... F-8 Consolidated Statements of Cash Flow for the years ended December 31, 1996, 1997 and 1998.................. F-9 Consolidated Statements of Changes in Stockholders' Equity for the years ended December 31, 1996, 1997 and 1998..................................................................................................... F-10 Notes to Consolidated Financial Statements................................................................. F-11
F-i BASIN EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE THREE MONTHS ENDED MARCH 31, -------------------- 1998 1999 --------- --------- (IN THOUSANDS, EXCEPT PER SHARE DATA) REVENUE: Oil sales.................................................................................. $ 2,690 $ 2,246 Gas sales.................................................................................. 7,545 10,796 Interest and other......................................................................... 21 13 --------- --------- 10,256 13,055 --------- --------- COSTS AND EXPENSES: Lease operating expenses................................................................... 2,143 2,455 Production taxes........................................................................... 234 76 Depreciation, depletion and amortization................................................... 5,986 8,546 General and administrative, net............................................................ 1,112 1,427 Interest expense........................................................................... 413 949 --------- --------- 9,888 13,453 --------- --------- INCOME (LOSS) BEFORE INCOME TAXES.......................................................... 368 (398) Income tax provision....................................................................... 129 -- --------- --------- NET INCOME (LOSS).......................................................................... $ 239 $ (398) --------- --------- --------- --------- BASIC: Earnings (loss) per share................................................................ $ 0.02 $ (0.03) Weighted average shares outstanding...................................................... 13,784 13,973 DILUTED: Earnings (loss) per share................................................................ $ 0.02 $ (0.03) Weighted average shares outstanding...................................................... 14,237 13,973
The accompanying notes are an integral part of these consolidated financial statements. F-1 BASIN EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS DECEMBER 31, 1998 AND MARCH 31, 1999
DECEMBER 31, MARCH 31, 1998 1999 -------------- ------------ (IN THOUSANDS, EXCEPT SHARE DATA) ASSETS CURRENT ASSETS: Cash and equivalents.............................................................. $ 331 $ 20 Accounts receivable............................................................... 10,036 9,227 Prepaids and other................................................................ 2,752 3,791 -------------- ------------ 13,119 13,038 -------------- ------------ PROPERTY AND EQUIPMENT, at cost: Oil and gas properties, under the full cost method of accounting Proved.......................................................................... 265,826 287,299 Unproved........................................................................ 34,039 33,902 Less accumulated depreciation, depletion and amortization......................... (113,462) (121,819) -------------- ------------ 186,403 199,382 Furniture and equipment, net...................................................... 1,408 1,306 -------------- ------------ 187,811 200,688 -------------- ------------ OTHER ASSETS........................................................................ 233 1,117 -------------- ------------ $ 201,163 $ 214,843 -------------- ------------ -------------- ------------ LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable.................................................................. $ 12,465 $ 14,409 Accrued liabilities............................................................... 13,620 14,930 Current portion of long-term debt................................................. 258 156 -------------- ------------ 26,343 29,495 -------------- ------------ LONG-TERM DEBT, net of current portion.............................................. 80,000 91,000 OTHER LONG-TERM OBLIGATIONS......................................................... 601 45 STOCKHOLDERS' EQUITY: Preferred stock, par value $.01 per share; 10,000,000 shares authorized, no shares issued and outstanding.......................................................... -- -- Common stock, par value $.01 per share, 50,000,000 shares authorized, 14,151,000 and 14,213,000 shares issued, respectively...................................... 142 142 Additional paid-in capital........................................................ 113,136 113,618 Accumulated deficit............................................................... (16,488) (16,886) Common stock held in treasury, at cost, 186,000 shares............................ (2,571) (2,571) -------------- ------------ 94,219 94,303 -------------- ------------ $ 201,163 $ 214,843 -------------- ------------ -------------- ------------
The accompanying notes are an integral part of these consolidated financial statements. F-2 BASIN EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOW
FOR THE THREE MONTHS ENDED MARCH 31, ---------------------- 1998 1999 ---------- ---------- (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss)...................................................................... $ 239 $ (398) Adjustments to reconcile net income (loss) to net cash provided by operating activities-- Depreciation, depletion and amortization............................................. 5,986 8,546 Deferred income tax expense.......................................................... 129 -- Stock compensation expense........................................................... 202 254 Other................................................................................ -- 16 ---------- ---------- 6,556 8,418 Changes in operating assets and liabilities-- Decrease (increase) in-- Receivables........................................................................ (6,104) 809 Prepaids and other................................................................. 174 (939) (Decrease) increase in-- Accounts payable and accrued expenses.............................................. 657 2,982 Ad valorem taxes and other......................................................... (273) 4 ---------- ---------- Net cash provided by operating activities............................................ 1,010 11,274 ---------- ---------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital additions...................................................................... (23,281) (23,977) Deposits on offshore leases............................................................ (3,989) (566) Proceeds from sale of property and equipment........................................... 20 2,438 ---------- ---------- Net cash used in investing activities................................................ (27,250) (22,105) ---------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from notes payable and long-term debt......................................... 31,500 23,500 Principle payments on notes payable and long-term debt................................. (5,538) (12,602) Proceeds from sale of stock............................................................ -- 62 Debt issuance costs and other.......................................................... (5) (440) ---------- ---------- Net cash provided by financing activities............................................ 25,957 10,520 ---------- ---------- DECREASE IN CASH AND EQUIVALENTS......................................................... (283) (311) CASH AND EQUIVALENTS, beginning of period................................................ 531 331 ---------- ---------- CASH AND EQUIVALENTS, end of period...................................................... $ 248 $ 20 ---------- ---------- ---------- ---------- SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid for interest................................................................. $ 283 $ 1,369 ---------- ---------- ---------- ---------- Cash paid for income taxes............................................................. $ -- $ -- ---------- ---------- ---------- ----------
The accompanying notes are an integral part of these consolidated financial statements. F-3 BASIN EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY FOR THE PERIOD FROM JANUARY 1, 1998 THROUGH MARCH 31, 1999
RETAINED COMMON STOCK ADDITIONAL TREASURY STOCK EARNINGS TOTAL ---------------------- PAID-IN ---------------------- (ACCUMULATED STOCKHOLDERS' SHARES AMOUNT CAPITAL SHARES AMOUNT DEFICIT) EQUITY --------- ----------- ----------- ----------- --------- -------------- -------------- (IN THOUSANDS) BALANCES, January 1, 1998............. 13,833 $ 138 $ 110,627 (120) $ (1,412) $ 12,012 $ 121,365 Issuance of common stock.............. 130 2 627 -- -- -- 629 Exercise of warrants for common stock............................... 79 1 1,107 (62) (1,108) -- -- Purchase of treasury stock............ -- -- -- (4) (51) -- (51) Issuance and vesting of restricted stock............................... 109 1 775 -- -- -- 776 Net income (loss)..................... -- -- -- -- -- (28,500) (28,500) --------- ----- ----------- --- --------- -------------- -------------- BALANCES, December 31, 1998........... 14,151 142 113,136 (186) (2,571) (16,488) 94,219 Issuance of common stock.............. 12 -- 62 -- -- -- 62 Issuance and vesting of restricted stock............................... 50 -- 420 -- -- -- 420 Net income (loss)..................... -- -- -- -- -- (398) (398) --------- ----- ----------- --- --------- -------------- -------------- BALANCES, March 31, 1999.............. 14,213 $ 142 $ 113,618 (186) $ (2,571) $ (16,886) $ 94,303 --------- ----- ----------- --- --------- -------------- -------------- --------- ----- ----------- --- --------- -------------- --------------
The accompanying notes are an integral part of these consolidated financial statements. F-4 BASIN EXPLORATION, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) UNAUDITED FINANCIAL STATEMENTS In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments (consisting only of normal recurring items) necessary to present fairly the financial position of Basin Exploration, Inc. and its wholly-owned subsidiaries as of March 31, 1999, and the results of operations and cash flows for the three-month periods presented. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to the Securities and Exchange Commission's rules and regulations. The results of operations for the periods presented are not necessarily indicative of the results to be expected for the full year. Management believes the disclosures made are adequate to ensure that the information is not misleading and suggests that these financial statements be read in conjunction with Basin's Consolidated Financial Statements and Notes for the three years in the period ended December 31, 1998 included elsewhere in this prospectus supplement. (2) ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities. The Statement establishes accounting and reporting standards requiring that every derivative instrument including certain derivative instruments embedded in other contracts be recorded on the balance sheet as either an asset or liability measured at its fair value and that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Basin is required to adopt the statement as of January 1, 2000, but may implement the Statement as of the beginning of any fiscal quarter prior to that date. Statement 133 cannot be applied retroactively. Basin has not yet quantified the impacts of adopting Statement 133 or determined the timing or method of adoption. However, Statement 133 could increase the volatility of the Company's earnings and other comprehensive income. (3) ACCOUNTING FOR OIL AND GAS PROPERTIES Basin follows the full cost method of accounting for oil and gas properties. Under this method, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized. If capitalized costs, net of amortization and related deferred taxes, exceed the full cost ceiling, the excess would be expensed in the period such excess occurs. Calculation of the full cost ceiling includes an estimate of the discounted value of future net cash flows attributable to proved reserves using various assumptions and parameters consistent with promulgations of the Securities and Exchange Commission, and such calculation is sensitive to changes in prevailing oil and gas sales prices. Oil and natural gas prices are volatile and reflect seasonal factors, as well as other supply and demand conditions. A decline in prices subsequent to April 1, 1999 could result in a requirement that Basin recognize an impairment expense in a future period. F-5 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Stockholders and Board of Directors of Basin Exploration, Inc.: We have audited the accompanying consolidated balance sheets of Basin Exploration, Inc. and subsidiaries as of December 31, 1998 and 1997, and the related consolidated statements of operations, changes in stockholders' equity and cash flow for each of the three years in the period ended December 31, 1998. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Basin Exploration, Inc. and subsidiaries as of December 31, 1998 and 1997, and the results of their operations and their cash flow for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Denver, Colorado, February 24, 1999. F-6 BASIN EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, -------------------------------- 1996 1997 1998 --------- --------- ---------- (IN THOUSANDS, EXCEPT PER SHARE DATA) REVENUE: Oil sales................................................................... $ 11,292 $ 9,844 $ 9,735 Gas sales................................................................... 6,890 14,557 38,885 Gain on sale of assets...................................................... 22,472 -- -- Interest and other.......................................................... 1,009 319 79 --------- --------- ---------- 41,663 24,720 48,699 --------- --------- ---------- COSTS AND EXPENSES: Lease operating expenses.................................................... 4,776 4,600 8,276 Production taxes............................................................ 1,829 1,260 770 Depreciation, depletion and amortization.................................... 7,606 10,622 29,775 General and administrative, net............................................. 3,850 3,694 4,380 Interest and other.......................................................... 2,272 764 2,030 Property impairment......................................................... -- -- 38,500 --------- --------- ---------- 20,333 20,940 83,731 --------- --------- ---------- INCOME (LOSS) BEFORE INCOME TAXES............................................. 21,330 3,780 (35,032) Income tax (provision) benefit................................................ (5,760) (1,324) 6,532 --------- --------- ---------- NET INCOME (LOSS)............................................................. $ 15,570 $ 2,456 $ (28,500) --------- --------- ---------- --------- --------- ---------- BASIC: Earnings (loss) per share................................................... $ 1.45 $ 0.22 $ (2.06) Weighted average shares outstanding......................................... 10,700 11,228 13,859 DILUTED: Earnings (loss) per share................................................... $ 1.45 $ 0.22 $ (2.06) Weighted average shares outstanding......................................... 10,730 11,345 13,859
The accompanying notes are an integral part of these consolidated financial statements. F-7 BASIN EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
DECEMBER 31, ------------------------- 1997 1998 ----------- ------------ (IN THOUSANDS, EXCEPT PER SHARE DATA) ASSETS CURRENT ASSETS: Cash and equivalents................................................................. $ 531 $ 331 Accounts receivable.................................................................. 8,348 10,036 Prepaids and other................................................................... 3,805 2,752 ----------- ------------ 12,684 13,119 ----------- ------------ PROPERTY AND EQUIPMENT, at cost: Oil and gas properties, under the full cost method of accounting Proved............................................................................. 177,704 265,826 Unproved........................................................................... 15,669 34,039 Less accumulated depreciation, depletion and amortization............................ (46,284) (113,462) ----------- ------------ 147,089 186,403 Furniture and equipment, net......................................................... 2,086 1,408 ----------- ------------ 149,175 187,811 OTHER ASSETS........................................................................... 100 233 ----------- ------------ $ 161,959 $ 201,163 ----------- ------------ LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable..................................................................... $ 8,087 $ 12,465 Accrued liabilities.................................................................. 12,067 11,998 Accrued ad valorem taxes............................................................. 2,394 1,622 Income taxes payable................................................................. 19 -- Current portion of long-term debt.................................................... 153 258 ----------- ------------ 22,720 26,343 LONG-TERM DEBT, net of current portion................................................. 11,053 80,000 OTHER LONG-TERM OBLIGATIONS............................................................ 266 601 DEFERRED INCOME TAXES.................................................................. 6,555 -- COMMITMENTS AND CONTINGENCIES (Note 5) STOCKHOLDERS' EQUITY: Preferred stock, par value $.01 per share; 10,000,000 shares authorized, no shares issued and outstanding............................................................. -- -- Common stock, $.01 par value, 50,000,000 shares authorized, 13,833,000 and 14,151,000 shares issued, respectively........................................................ 138 142 Additional paid-in capital........................................................... 110,627 113,136 Retained earnings (accumulated deficit).............................................. 12,012 (16,488) Common stock held in treasury, at cost, 120,000 and 186,000 shares, respectively..... (1,412) (2,571) ----------- ------------ 121,365 94,219 ----------- ------------ $ 161,959 $ 201,163 ----------- ------------ ----------- ------------
The accompanying notes are an integral part of these consolidated financial statements. F-8 BASIN EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOW
FOR THE YEARS ENDED DECEMBER 31, ------------------------------------- 1996 1997 1998 ----------- ---------- ------------ (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss)....................................................... $ 15,570 $ 2,456 $ (28,500) Adjustments to reconcile net income (loss) to net cash provided by operating activities-- Gain on sale of assets................................................ (22,472) -- -- Depreciation, depletion and amortization.............................. 7,606 10,622 29,775 Deferred income tax expense (benefit)................................. 4,760 1,795 (6,555) Property impairment................................................... -- 38,500 Stock compensation expense............................................ 98 439 452 Amortization of debt issuance costs................................... 118 -- -- Other................................................................. -- (15) (14) ----------- ---------- ------------ 5,680 15,297 33,658 Changes in operating assets and liabilities-- Decrease (increase) in-- Restricted cash..................................................... 578 -- -- Receivables......................................................... 1,664 (3,188) (1,693) Prepaids and other.................................................. (1,861) (1,438) 919 (Decrease) increase in-- Accounts payable and accrued liabilities............................ 103 5,692 5,406 Ad valorem taxes and other.......................................... (2,255) 107 (437) Income taxes payable................................................ 1,000 (981) (19) ----------- ---------- ------------ Net cash provided by operating activities............................. 4,909 15,489 37,834 ----------- ---------- ------------ CASH FLOWS FROM INVESTING ACTIVITIES: Capital additions....................................................... (27,741) (98,245) (107,716) Proceeds from sale of property and equipment............................ 125,625 195 52 Asset sale transaction costs............................................ (5,257) -- -- ----------- ---------- ------------ Net cash provided by (used in) investing activities................... 92,627 (98,050) (107,664) ----------- ---------- ------------ CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from notes payable and long-term debt.......................... 8,594 53,000 85,245 Principal payments on notes payable..................................... (85,517) (42,218) (16,193) Proceeds from sale of stock, net........................................ 84 50,320 629 Purchase of treasury stock and options.................................. (287) (33) (51) ----------- ---------- ------------ Net cash provided by (used in) financing activities................... (77,126) 61,069 69,630 ----------- ---------- ------------ INCREASE (DECREASE) IN CASH AND EQUIVALENTS............................... 20,410 (21,492) (200) CASH AND EQUIVALENTS, beginning of year................................... 1,613 22,023 531 ----------- ---------- ------------ CASH AND EQUIVALENTS, end of year......................................... $ 22,023 $ 531 $ 331 ----------- ---------- ------------ ----------- ---------- ------------ SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid for interest.................................................. $ 2,327 $ 637 $ 3,133 Cash paid for taxes..................................................... $ -- $ 981 $ (23)
The accompanying notes are an integral part of these consolidated financial statements. F-9 BASIN EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1996, 1997 AND 1998 ------------------------------------------------------------------------------------------- RETAINED COMMON STOCK ADDITIONAL TREASURY STOCK EARNINGS ---------------------- PAID-IN ---------------------- (ACCUMULATED STOCKHOLDERS' SHARES AMOUNT CAPITAL SHARES AMOUNT DEFICIT) EQUITY --------- ----------- ----------- ----------- --------- -------------- -------------- (IN THOUSANDS) BALANCES, December 31, 1995........... 10,724 $ 107 $ 59,288 (32) $ (94) $ (6,014) $ 53,287 Purchase of treasury stock and options........................... -- -- (250) (24) (38) -- (288) Issuance and vesting of restricted stock and stock options........... 33 1 181 -- -- -- 182 Net income.......................... -- -- -- -- -- 15,570 15,570 --------- ----- ----------- --- --------- -------------- -------------- BALANCES, December 31, 1996........... 10,757 108 59,219 (56) (132) 9,556 68,751 Issuance of common stock............ 3,001 30 51,340 -- -- -- 51,370 Common stock offering costs......... -- -- (499) -- -- -- (499) Purchase of treasury stock.......... -- -- -- (64) (1,280) -- (1,280) Issuance and vesting of restricted stock............................. 75 -- 567 -- -- -- 567 Net income.......................... -- -- -- -- -- 2,456 2,456 --------- ----- ----------- --- --------- -------------- -------------- BALANCES, December 31, 1997........... 13,833 138 110,627 (120) (1,412) 12,012 121,365 Issuance of common stock............ 130 2 627 -- -- -- 629 Exercise of warrants for common stock............................. 79 1 1,107 (62) (1,108) -- -- Purchase of treasury stock.......... -- -- -- (4) (51) -- (51) Issuance and vesting of restricted stock............................. 109 1 775 -- -- -- 776 Net income (loss)................... -- -- -- -- -- (28,500) (28,500) --------- ----- ----------- --- --------- -------------- -------------- BALANCES, December 31, 1998........... 14,151 $ 142 $ 113,136 (186) $ (2,571) $ (16,488) $ 94,219 --------- ----- ----------- --- --------- -------------- -------------- --------- ----- ----------- --- --------- -------------- --------------
The accompanying notes are an integral part of these consolidated financial statements. F-10 BASIN EXPLORATION, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES ORGANIZATION AND OPERATIONS--The consolidated financial statements include the financial statements of Basin Exploration, Inc. and its wholly owned subsidiaries (collectively referred to as "Basin"). Basin operates its business and reports its operations as one business segment. Basin is engaged in the exploration, development and production of natural gas and crude oil. Basin's principal producing area is offshore in the Gulf of Mexico. Basin, as operator of jointly-owned oil and gas properties, sells a significant amount of such production to certain major customers (see Note 8), and pays vendors for oil and gas services. Joint interest receivables are subject to collection under terms of operating agreements which generally provide lien rights. The accompanying financial statements present the operations of Basin on a consolidated basis. All significant intercompany accounts and transactions have been eliminated in consolidation. The preparation of financial statements in conformity with generally accepted accounting principles 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. Actual results could differ from those estimates. CASH EQUIVALENTS--Cash equivalents are comprised of highly liquid instruments with original maturities of three months or less. The total carrying amount of cash and equivalents approximates the fair value of such instruments. OIL AND GAS PROPERTIES--Basin follows the full cost method of accounting for oil and gas properties. Under this method, all costs associated with the development, exploration and acquisition of oil and gas properties are capitalized in Basin's one cost center (full cost pool), which is the continental United States including the Gulf of Mexico. Payroll and other internal costs capitalized include salaries and related fringe benefits paid to employees directly engaged in the acquisition, exploration and development of oil and gas properties as well as all other directly identifiable, internal costs associated with these activities. Payroll and other internal costs associated with production operations and general corporate activities are expensed in the period incurred. Future development, site restoration, dismantlement and abandonment costs, net of salvage values, are estimated on a property-by-property basis based on prevailing prices and are amortized to expense, along with the capitalized costs discussed above, using the unit-of-production method based upon actual production and estimates of proved reserve quantities. Accumulated depreciation, depletion and amortization is recorded on the balance sheet as a reduction to property, plant and equipment costs. Basin invests in unevaluated oil and gas properties and related assets for the purpose of future exploration for proved reserves. The costs of such assets are included in unproved oil and gas properties at the lower of cost or estimated fair market value and are not subject to amortization. Proceeds from sales of oil and gas properties are credited to the full cost pool with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas. Under full cost accounting rules promulgated by the Securities and Exchange Commission, if net capitalized costs of oil and gas properties, less related deferred income taxes, exceed the full cost ceiling at the end of a fiscal quarter, the excess is charged to expense in that period. The full cost ceiling is calculated as the estimated present value of future net cash flows from proved oil and gas reserves using a 10% discount factor and unescalated oil and gas prices as of the end of the period, or shortly thereafter, plus the book value of unproved oil and gas properties. Calculation F-11 BASIN EXPLORATION, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) of the full cost ceiling may be particularly sensitive to changes in expected production rates or the level of oil and gas prices, which may be volatile due to seasonal factors and other influences. Basin recognized a $38,500,000 non-cash impairment charge ($30,750,000 after income tax) for the quarter ended December 31, 1998, based on a ceiling test calculation that utilized average realized prices of $10.23 per barrel of oil and $1.87 per Mcf of natural gas. A decline in prices could result in a requirement that Basin recognize additional impairment expense in a future period. FURNITURE AND EQUIPMENT--Furniture and equipment are depreciated over estimated useful lives of four to seven years. Maintenance and repair costs are expensed as incurred. INCOME TAXES--Basin computes income taxes in accordance with Statement of Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income Taxes." SFAS 109 requires an asset and liability approach which results in the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the carrying amounts and the tax bases of those assets and liabilities. SFAS 109 also requires the recording of a valuation allowance if it is more likely than not that some portion or all of a deferred tax asset will not be realized. HEDGING ACTIVITIES--Basin periodically enters into commodity derivative contracts and fixed-price physical contracts to manage its exposure to oil and gas price volatility. Commodity derivatives contracts, which are placed with major financial institutions or other counterparties of high credit quality that Basin believes are minimal credit risks, may take the form of futures contracts, swaps or options. The reference prices of these commodity derivatives contracts are based upon crude oil and natural gas futures which have a high degree of historical correlation with actual prices received by Basin. Basin accounts for its commodity derivatives contracts using the hedge (deferral) method of accounting. Under this method, realized gains and losses from Basin's price risk management activities are recognized in oil and gas revenue when the associated production occurs and the resulting cash flows are reported as cash flows from operating activities. Gains and losses from commodity derivatives contracts that are closed before the hedged production occurs are deferred until the production month originally hedged. In the event of a loss of correlation between changes in oil and gas reference prices under a commodity derivatives contract and actual oil and gas prices, a gain or loss would be recognized currently to the extent the commodity derivatives contract did not offset changes in actual oil and gas prices. Basin recognized a reduction in oil revenue of $480,000 and $144,000 under hedging agreements in 1996 and 1997, respectively. Basin recognized a reduction in gas revenue of $383,000 under hedging agreements in 1997. Basin recognized increases in oil and gas revenue of $1,175,000 and $2,357,000, respectively, under hedging agreements in 1998. F-12 BASIN EXPLORATION, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) As of February 24, 1999, Basin was a party to the following fixed price swap arrangements (one MMBtu approximates one Mcf of natural gas):
OIL GAS -------------------------- ------------------------------ AVERAGE DAILY AVERAGE DAILY TIME PERIOD VOLUME (BBL) $/BBL VOLUME (MMBTU) $/MMBTU - --------------------------------------------------------- --------------- --------- ----------------- ----------- 1/1/99 -- 3/31/99........................................ 1,000 17.00 30,167 2.15 4/1/99 -- 6/30/99........................................ 1,000 17.00 33,297 2.18 7/1/99 -- 9/30/99........................................ 30,000 2.20 10/1/99 -- 12/31/99...................................... 25,000 2.16 1/1/00 -- 12/31/01....................................... 10,000 2.15
In addition, Basin periodically enters into spread trades or options transactions related to oil or natural gas futures markets. Under a spread trade, fixed prices under a hedging contract are determined in the future by reference to the price of an underlying contract. Such positions may enable Basin to lock in favorable fixed prices for future hedging positions, but can also result in unfavorable fixed price contracts if the reference price represented by the underlying contract declines. As of February 24, 1999, Basin had entered into spread trades for natural gas providing for a fixed price for 20,000 MMBtu per day for the period of March 2000 through September 2000 to be established in the future upon an election by Basin by reference to the underlying NYMEX October 1999 contract price less $0.28. Basin also had sold call options for 10,000 MMBtu of natural gas per day for the period from March 1999 through April 1999 with a strike price of $1.93 per MMBtu, and from January 1999 through December 2001 with an average strike price of $2.50 per MMBtu. Call options had also been sold covering a quantity of 1,000 barrels of oil per day for the period from July 1999 through December 1999, at a strike price of $16.75 per barrel. In accordance with SFAS 107, "Disclosures About Fair Value of Financial Instruments," Basin has estimated the fair value of its hedging arrangements at December 31, 1998, utilizing the then-applicable crude oil and natural gas strips. While it is not Basin's intention to terminate any of the arrangements, it is estimated that Basin would have received approximately $1,170,000 to terminate the then-existing arrangements on December 31, 1998. Due to the volatility of crude oil and natural gas prices, the fair market value may not be representative of the actual gain or loss that will ultimately be realized by Basin. In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 establishes accounting and reporting standards requiring that every derivative instrument including certain derivative instruments embedded in other contracts be recorded in the balance sheet as either an asset or liability measured at its fair market value and that changes in the derivative's fair market value be recognized currently in earnings unless specific hedge accounting criteria are met. SFAS 133 is effective for Basin in 2000, but early adoption is allowed. Basin has not yet quantified the impacts of adopting SFAS 133 or determined the timing or method of adoption. However, SFAS 133 could increase volatility in earnings and other comprehensive income. EARNINGS (LOSS) PER SHARE--Basin adopted SFAS 128, "Earnings Per Share," beginning with the fourth quarter of 1997. All prior period earnings per share have been restated to conform to the provisions of the statement. Basic earnings per share is computed based on the weighted average F-13 BASIN EXPLORATION, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) number of common shares outstanding. Diluted earnings per share is computed based on the weighted average number of common shares outstanding adjusted for the incremental shares attributed to outstanding options and warrants to purchase common stock. Options to purchase 171,500 and 30,000 shares in 1996 and 1997, respectively, were not included in the computation of diluted earnings per share because the option exercise price was greater than the average market price of Basin's common stock. All options and warrants to purchase common shares were excluded from the computation of diluted earnings per share in 1998 because they were antidilutive as a result of Basin's net loss in that year. In connection with the acquisition of Sterling Energy Corp. in November 1994, Basin issued warrants to purchase 300,000 shares of Basin's common stock at an exercise price of $14.00 per share. Such warrants became exercisable on October 13, 1994 and have an expiration date of December 31, 1999. During 1997 and 1998, 48,523 and 79,145 warrants were exercised, respectively. The remaining 172,332 warrants were outstanding at December 31, 1998. COMPREHENSIVE INCOME--Basin adopted SFAS 130, "Comprehensive Income," beginning with the fourth quarter of 1997. There are no components of comprehensive income which have been excluded from net income and, therefore, no separate statement of comprehensive income has been presented. (2) ACQUISITIONS AND DIVESTITURES OF OIL AND GAS PROPERTIES In February 1996, Basin entered into agreements pursuant to which it sold all of its assets in the Denver-Julesberg Basin in two transactions closed in March and June 1996, respectively, for an aggregate sales price of $123,500,000, effective January 1, 1996. Combined, these transactions resulted in Basin selling its interests in approximately two-thirds of its producing wells and 70% of its proved oil and gas reserves at December 31, 1995. Basin recognized a gain of $22,472,000 in conjunction with the second transaction. Revenue and expenses associated with the sold properties were included in Basin's results of operations through the respective closing dates. Basin consummated an acquisition of certain oil and gas properties from Midcon Offshore, Inc. on November 26, 1997. The purchase price was approximately $31,300,000, subject to normal post-closing adjustments. Basin was the high bidder at a bankruptcy court proceeding conducted to sell such assets, which were comprised principally of working interests in six federal lease blocks on the outer-continental shelf in the Gulf of Mexico, and the related platforms and production facilities. Approximately $5,000,000 of the purchase price was attributed to prospective drilling locations. The acquisition was accounted for as a purchase and, accordingly, the operating results of the acquired assets have been included in Basin's consolidated financial statements since the closing date. F-14 BASIN EXPLORATION, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (3) LONG-TERM DEBT
DECEMBER 31 -------------------- 1997 1998 --------- --------- (IN THOUSANDS) Revolving credit facility.............................................. $ 11,000 $ 80,000 Other notes............................................................ 206 258 --------- --------- 11,206 80,258 Less: current portion................................................ (153) (258) --------- --------- Long-term debt, net of current portion................................. $ 11,053 $ 80,000 --------- --------- --------- ---------
Effective January 1, 1999, Basin entered into an Amended and Restated Credit Agreement (the "Credit Agreement") with its existing bank group. The Credit Agreement provides for borrowings of up to $110,000,000 under two combined facilities. Facility A, initially established at $90,000,000, represents the borrowing base that is considered to be "conforming" , based upon the bank's then-current customary practices and standards in making conventional borrowing base determinations for oil and gas producers. Such practices and standards are intended to be substantially similar to the bank group's present practices, except for market-induced changes relating to pricing, costs and risk factors related to oil and gas reserves. Facility B, initially established at $20,000,000, is a shorter-term supplemental line of credit. The Credit Agreement provides for the interest rate on borrowings to be determined by reference to the prime rate or LIBOR, at Basin's election. Facility A provides for a varying spread of 0% to 0.25% to be added to the prime rate, or 0.75% to 1.5% to be applied to LIBOR, based upon Basin's facility usage ratio at the time. Facility B provides for a spread of 3.5% to be added to the prime rate or 4.75% to be applied to LIBOR, subject to a 0.25% increase in such spreads effective June 1, 1999. The Credit Agreement provides for borrowings to be revolving loans until November 30, 2001, at which time the outstanding balance will be converted into a four-year amortizing term loan unless the Credit Agreement has been amended to extend the revolving period, and subject to the scheduled termination of Facility B effective May 31, 2000. The borrowing base under the Credit Agreement is scheduled to be re-determined as of March 1, 1999 and generally at three-month intervals thereafter until Facility B is retired, and then at six-month intervals until converted into a term loan. The Credit Agreement contains various covenants, including ones that could limit Basin's ability to incur other debt, dispose of assets, pay dividends, or repurchase stock. Pursuant to the agreement governing the Credit Agreement, substantially all of Basin's producing properties are subject to mortgages in favor of the banks and Basin's remaining properties are subject to a negative pledge. The weighted average interest rate on borrowings outstanding under the Credit Agreement at December 31, 1998 was 6.2%. Outstanding debt at December 31, 1998 is payable as follows (in thousands): 1999.............................................................. $ 258 2000.............................................................. -- 2001.............................................................. -- 2002.............................................................. 20,000 2003.............................................................. 20,000 Thereafter........................................................ 40,000 --------- $ 80,258 --------- ---------
F-15 BASIN EXPLORATION, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (4) BENEFIT PLANS 401(K) SAVINGS--Basin has a 401(k) profit sharing plan (the "Plan"). Eligible employees may make voluntary contributions to the Plan, which may be matched by Basin, at its discretion, up to 6 percent of the employee's eligible compensation. Basin has historically matched the first three percent of employees' eligible compensation that is contributed under the Plan. The amount of employee contributions is limited as specified in the Plan. At its discretion, Basin may also make additional contributions to the Plan. Basin expensed $96,000, $183,000 and $208,000, with respect to the Plan for the years ended December 31, 1996, 1997 and 1998, respectively. STOCK PLAN--Under Basin's Equity Incentive Plan, officers, key employees, consultants and directors of Basin are eligible to receive incentive stock options, non-qualified stock options, restricted stock and performance shares. The restricted stock and performance shares awarded under the plan entitle the grantee to the rights of a shareholder, including the right to receive any dividends and to vote such shares, but the shares are restricted as to sale, transfer or encumbrance. At December 31, 1998, a total of approximately 1,758,000 shares were available for grant under the plans. Options granted generally vest over three to four years, and expire after ten years. A total of 1,175,000 shares of Basin's common stock are subject to such plans as of December 31, 1998, including 186,000 non-vested shares of restricted stock and performance shares and 989,000 outstanding stock options. The following table summarizes stock options activity for the years presented:
YEAR ENDED DECEMBER 31, --------------------------------- 1996 1997 1998 ---------- --------- ---------- Balance, beginning of period................................................. 702,500 649,000 773,500 Granted...................................................................... 252,500 202,500 345,000 Exercised.................................................................... (33,500) (78,000) (129,500) Forfeited/canceled........................................................... (272,500) -- -- ---------- --------- ---------- Balance, end of period....................................................... 649,000 773,500 989,000 ---------- --------- ---------- ---------- --------- ----------
Additional information regarding outstanding options at December 31, 1998 is as follows:
NUMBER OF WEIGHTED WEIGHTED AVERAGE NUMBER OF WEIGHTED OPTIONS AVERAGE REMAINING LIFE IN OPTIONS AVERAGE RANGE OF EXERCISE PRICES PER SHARE OUTSTANDING EXERCISE PRICE YEARS EXERCISABLE EXERCISE PRICE - ----------------------------------- ------------ --------------- ------------------- ------------ --------------- $13.25 -- $20.38................... 464,000 $ 15.48 8.0 109,000 $ 16.13 $7.63 -- $11.00.................... 165,000 $ 9.64 4.4 131,667 $ 9.52 $5.13 -- $7.00..................... 215,000 $ 6.32 7.6 138,333 $ 6.15 $3.88 -- $4.94..................... 145,000 $ 4.27 7.1 100,833 $ 4.21 -- ------------ ------- ------------ ------- 989,000 $ 10.87 7.0 479,833 $ 8.94 -- -- ------------ ------- ------------ ------- ------------ ------- ------------ -------
Basin granted 25,000, 23,000 and 59,000 shares of restricted stock during 1996, 1997 and 1998, respectively. Related compensation expense was recognized in the amounts of approximately F-16 BASIN EXPLORATION, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (4) BENEFIT PLANS (CONTINUED) $98,000, $120,000 and $409,000 for the years ended December 31, 1996, 1997 and 1998, respectively. Cumulatively through December 31, 1998, 73,000 shares of restricted stock had been forfeited, 53,000 shares were no longer subject to restriction, and 81,000 shares of restricted stock remained subject to forfeiture. Basin granted 55,000 and 50,000 performance shares during 1997 and 1998, respectively. In order for the performance shares to be released to the grantee, Basin must attain certain performance goals by the end of a three-year performance cycle which begins with the year of award. Related compensation expense was recognized in the amount of $447,000 and $367,000 for the years ended December 31, 1997 and 1998, respectively. In October 1995, the Financial Accounting Standards Board issued SFAS 123, "Accounting for Stock-Based Compensation." SFAS 123 is effective for 1996 and after and recommends a fair value based method of accounting for employee stock compensation, including stock options. However, companies may choose to account for stock compensation using the intrinsic value based method as prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and provide pro forma disclosures of net income and earnings per share as if the fair value based method had been applied. Basin has elected to continue to account for stock compensation using the intrinsic value based method. Had Basin elected to follow SFAS 123, the fair value of each option grant would have been estimated on the date of grant using the Black-Sholes option-pricing model with the following weighted-average assumptions and effects:
YEAR ENDED DECEMBER 31, -------------------------------- 1996 1997 1998 --------- --------- ---------- Assumptions: Risk free interest rate...................................................... 6.75% 5.75% 5.75% Expected dividend yield...................................................... 0% 0% 0% Expected life in years....................................................... 5 5 5 Expected volatility.......................................................... 55% 58% 58% Weighted average fair value per share.......................................... $ 2.73 $ 5.66 $ 8.40 Pro forma net income (loss) (in thousands)..................................... $ 15,468 $ 2,285 $ (29,315) Pro forma diluted earnings (loss) per share.................................... $ 1.44 $ 0.20 $ (2.12)
F-17 (5) COMMITMENTS AND CONTINGENCIES LEASES--Basin is the primary obligor under various noncancelable office space operating lease arrangements. Basin also subleases certain office space to and from third parties under various noncancelable lease arrangements. The following is a schedule of future minimum lease payments under these leases at December 31, 1998:
FUTURE MINIMUM FUTURE MINIMUM LEASE OBLIGATIONS LEASE RECEIPTS ------------------- ------------------- (IN THOUSANDS) 1999.......................................... $ 596 $ 186 2000.......................................... 136 -- ----- ----- $ 732 $ 186 ----- ----- ----- -----
Payments related to these lease obligations were approximately $707,000, $990,000 and $1,096,000 for the years ended December 31, 1996, 1997 and 1998, respectively. Related receipts were $89,000, $502,000 and $506,000 in the years ended December 31, 1996, 1997 and 1998. LEGAL PROCEEDINGS--Basin, from time to time, is involved in various legal and administrative proceedings and claims of various types which arise in the ordinary course of its business. While any litigation contains an element of uncertainty, in the opinion of management, none of these actions, either individually or in the aggregate, are likely to have a material adverse effect on Basin's financial condition, liquidity or results of operations. (6) INCOME TAXES The components of the provision (benefit) for income taxes are as follows:
YEAR ENDED DECEMBER 31, ------------------------------- 1996 1997 1998 --------- --------- --------- (IN THOUSANDS) Current provision (benefit): Federal......................................................................... $ 950 $ (434) $ (58) State........................................................................... 50 (37) 81 --------- --------- --------- 1,000 (471) 23 --------- --------- --------- Deferred provision (benefit): Federal......................................................................... 4,760 1,795 (6,555) State........................................................................... -- -- -- --------- --------- --------- 4,760 1,795 (6,555) --------- --------- --------- Provision (benefit for income taxes).............................................. $ 5,760 $ 1,324 $ (6,532) --------- --------- --------- --------- --------- ---------
F-18 (6) INCOME TAXES (CONTINUED) Reconciliations of income tax provisions (benefit) computed at the federal statutory rate with income tax provisions recorded by Basin for each of the past three years are as follows:
YEAR ENDED DECEMBER 31, -------------------------------- 1996 1997 1998 --------- --------- ---------- (IN THOUSANDS) Income (loss) before income taxes.............................................. $ 21,330 $ 3,780 $ (35,032) Computed tax (benefit) at the applicable federal statutory rate................ 7,252 1,285 (11,911) State income tax (benefit), net of federal tax effect.......................... 704 39 (350) Deferred tax assets valuation allowance........................................ (2,196) -- 5,729 --------- --------- ---------- Income tax provision (benefit)................................................. $ 5,760 $ 1,324 $ (6,532) --------- --------- ---------- --------- --------- ----------
The tax effects of significant temporary differences representing deferred tax assets and liabilities are as follows:
DECEMBER 31, -------------------- 1997 1998 --------- --------- (IN THOUSANDS) Deferred tax (assets) liabilities: Oil and gas properties and equipment...................................................... $ 7,581 $ (2,357) Net operating loss carryforward........................................................... -- (2,505) Percentage depletion carryforward......................................................... -- (589) Alternative minimum tax credit carryforward............................................... (1,026) (278) Valuation allowance....................................................................... -- 5,729 --------- --------- Net deferred tax liability.................................................................. $ 6,555 $ -- --------- --------- --------- ---------
(7) RELATED PARTY TRANSACTIONS Prior to its initial public offering, Basin advanced $559,000 to its principal stockholder at an annual interest rate of 9 percent. Pursuant to the terms of the note, the principal stockholder elected to surrender 28,217 shares of Basin's common stock to Basin in the fourth quarter of 1997 to settle the note. The surrendered shares are reflected as treasury stock in the accompanying statement of changes in stockholders' equity. (8) OIL AND GAS ACTIVITIES Basin's oil and gas operations are conducted solely in the United States. Certain information concerning these activities follows: F-19 (8) OIL AND GAS ACTIVITIES (CONTINUED) MAJOR PURCHASERS--The following parties purchased ten percent or more of Basin's oil and gas production:
YEAR ENDED DECEMBER 31, ------------------------------- PURCHASER 1996 1997 1998 - ------------------------------------------------------------------------------------------- --------- --------- --------- Texaco..................................................................................... (a) 46% 28% Dynegy..................................................................................... (a) (a) 26% Eighty-Eight Oil........................................................................... 26% 21% (a) PanEnergy.................................................................................. 43% (a) (a)
- ------------------------ (a) less than ten percent COSTS INCURRED--Costs incurred in oil and gas operations and related depletion per equivalent unit-of-production were as follows:
YEAR ENDED DECEMBER 31, ----------------------------------- 1996 1997 1998 --------- ----------- ----------- (IN THOUSANDS, EXCEPT FOR GAS EQUIVALENT DATA) Property acquisition-- Unproved(1)............................................................... $ 5,056 $ 11,057 $ 22,920 Proved.................................................................... 3,067 48,680 3,018 Exploration costs........................................................... 10,250 27,995 58,063 Development costs........................................................... 4,472 17,901 22,671 --------- ----------- ----------- Gross expenditures.......................................................... $ 22,845 $ 105,633 $ 106,672 --------- ----------- ----------- --------- ----------- ----------- Depletion per one thousand cubic feet of gas equivalent..................... $ 0.82 $ 1.12 $ 1.31 --------- ----------- ----------- --------- ----------- -----------
- ------------------------ (1) Excludes $4,914,000, $1,113,000 and $150,000 of costs recouped through the resale of partial interests in prospects to industry partners in 1996, 1997 and 1998, respectively. COSTS NOT BEING AMORTIZED--Oil and gas property costs not being amortized at December 31, 1998, consisted of $34,039,000 of leasehold and seismic costs, of which $2,669,000, $3,312,000 and $28,058,000 were incurred in 1996, 1997 and 1998, respectively. Basin anticipates that substantially all unevaluated costs will be classified as evaluated costs within three years. UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION There are numerous uncertainties inherent in estimating quantities of proved reserves and projected future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data and standardized measures set forth herein represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and 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. As a result, estimates of different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate. Accordingly, reserve estimates will vary from the quantities of oil and gas that are ultimately recovered. Further, the estimated future net cash flows from proved reserves and the present value thereof are based upon certain assumptions, including geologic success, and future F-20 (8) OIL AND GAS ACTIVITIES (CONTINUED) prices, production levels and costs, that may not prove correct over time. Predictions of future production levels are subject to great uncertainty, and the meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Oil and gas prices have fluctuated widely in recent years. The calculated weighted average sales prices utilized for the purposes of estimating Basin's proved reserves and future net cash flows were: $25.35 per barrel of oil and $3.02 per Mcf of gas at December 31, 1996; $16.34 per barrel of oil and $2.32 per Mcf of gas at December 31, 1997 and $10.31 per barrel of oil and $1.99 per Mcf of gas at December 31, 1998. Estimated reserve quantities and standardized measures set forth herein utilize such prices (which were based on prevailing sales prices at the time) held constant in future periods and a 10% discount rate. All of Basin's reserves are located onshore or offshore in the United States. The following tables include estimates for Basin's onshore and offshore reserves combined. Estimates of onshore reserves were prepared by Basin's engineers and audited by Netherland, Sewell & Associates, Inc. at December 31, 1995, 1996 and 1997 and by Ryder Scott Company Petroleum Engineers at December 31, 1998. Estimates of offshore reserves were either prepared by Ryder Scott Company Petroleum Engineers, or prepared by Basin's engineers and audited by Ryder Scott Company Petroleum Engineers. ANALYSES OF CHANGES IN PROVED RESERVES The following table sets forth information regarding Basin's estimated net total proved and proved developed oil and gas reserve quantities:
OIL GAS (MBBLS) (MMCF) --------- ---------- Balance, December 31, 1995................................................................. 12,606 131,436 Revisions................................................................................ 52 (451) Extensions, discoveries and additions.................................................... 49 6,391 Production............................................................................... (564) (4,776) Sales of reserves in-place............................................................... (6,559) (104,140) Purchases of reserves in-place........................................................... 2,286 1,253 --------- ---------- Balance, December 31, 1996................................................................. 7,870 29,713 Revisions................................................................................ (1,439) (6,488) Extensions, discoveries and additions.................................................... 1,458 32,911 Production............................................................................... (524) (5,509) Sales of reserves in-place............................................................... (56) (1,015) Purchases of reserves in-place........................................................... 845 39,922 --------- ---------- Balance, December 31, 1997................................................................. 8,154 89,534 Revisions................................................................................ (1,486) (6,136) Extensions, discoveries and additions.................................................... 2,057 57,888 Production............................................................................... (725) (17,616) Purchases of reserves in-place........................................................... 667 3,832 --------- ---------- Balance, December 31, 1998................................................................. 8,667 127,502 --------- ---------- --------- ---------- Proved developed reserves-- December 31, 1996........................................................................ 4,046 19,182 December 31, 1997........................................................................ 4,863 82,571 December 31, 1998........................................................................ 3,352 103,271
F-21 STANDARDIZED MEASURE The following table presents the standardized measure of discounted future net cash flows related to proved oil and gas reserves:
YEAR ENDED DECEMBER 31, -------------------------------------- 1996 1997 1998 ------------ ----------- ----------- (IN THOUSANDS) Future production revenues................................................ $ 289,105 $ 341,310 $ 342,618 Future production costs................................................... (108,522) (79,550) (71,609) Future development costs.................................................. (20,583) (40,829) (54,905) Future income taxes....................................................... (39,101) (31,723) (17,894) ------------ ----------- ----------- Future net cash flows..................................................... 120,899 189,208 198,210 Discount factor at 10% per annum.......................................... (57,593) (53,726) (48,255) ------------ ----------- ----------- Standardized measure of discounted future net cash flows(1)............... $ 63,306 $ 135,482 $ 149,955 ------------ ----------- ----------- ------------ ----------- -----------
- ------------------------ (1) Total future net cash flows before income taxes discounted at 10% per annum are $83,656,000, $160,230,000 and $164,485,000 as of December 31, 1996, 1997 and 1998, respectively. The estimate of future income taxes is based on the future net cash flows from proved reserves adjusted for the tax basis of the oil and gas properties but without consideration of general and administrative and interest expenses. For standardized measure purposes Basin estimates future income taxes using the "year-by-year" method. For ceiling test purposes Basin estimates future income taxes using the "short-cut" method. A summary of changes in the standardized measure of discounted future net cash flows is as follows:
YEAR ENDED DECEMBER 31, -------------------------------------- 1996 1997 1998 ------------ ----------- ----------- (IN THOUSANDS) Standardized measure of discounted future net cash flows, beginning of year.................................................................... $ 117,248 $ 63,306 $ 135,482 Changed in sales prices and production costs.............................. 17,693 (34,217) (51,857) Changes in estimated future development costs............................. (1,819) 6,973 3,061 Sales of minerals-in-place................................................ (83,530) (1,019) -- Purchase of minerals-in place............................................. 10,887 65,644 7,537 Revisions of previous quantity estimates.................................. (169) (11,065) (9,015) Costs incurred that reduced future development costs...................... -- 2,253 474 Extensions, discoveries and improved recovery............................. 16,286 67,973 91,660 Sales of oil and gas, net of production costs and taxes................... (11,577) (18,541) (39,574) Accretion of discount..................................................... 12,907 8,366 16,023 Net change in future income taxes......................................... (8,530) (4,398) 10,218 Changes in timing of production and other................................. (6,090) (9,793) (14,054) ------------ ----------- ----------- Standardized measure of discounted future net cash flows, end of year..... $ 63,306 $ 135,482 $ 149,955 ------------ ----------- ----------- ------------ ----------- -----------
F-22 UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA
FIRST SECOND THIRD FOURTH TOTAL --------- --------- --------- ---------- ---------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) 1997 Revenue.............................................. $ 3,412 $ 2,566 $ 6,906 $ 11,836 $ 24,720 Gross profit from operations......................... 1,814 1,269 5,589 9,869 18,541 Net income (loss).................................... 9 (570) 966 2,051 2,456 Earnings (loss) per share: Basic.............................................. -- (0.05) 0.09 0.16 0.22 Diluted............................................ -- (0.05) 0.09 0.16 0.22 1998 Revenue.............................................. $ 10,256 $ 11,908 $ 14,144 $ 12,391 $ 48,699 Gross profit from operations......................... 7,858 9,262 11,932 10,522 39,574 Net income (loss).................................... 239 746 1,242 (30,727) (28,500) Earnings (loss) per share: Basic.............................................. 0.02 0.05 0.09 (2.21) (2.06) Diluted............................................ 0.02 0.05 0.09 (2.21) (2.06)
Gross profit from operations is comprised of oil and gas sales less lease operating expenses and production taxes. The net loss for the fourth quarter of 1998 includes a property impairment of $38,500,000. Earnings (loss) per share is computed independently for each of the quarters presented and, therefore, may not sum to the totals for the year. F-23 UNDERWRITING Basin Exploration, Inc., the selling stockholder and the underwriters named below have entered into an underwriting agreement with respect to the shares being offered. Subject to certain conditions, each underwriter has severally agreed to purchase the number of shares indicated in the following table. Goldman, Sachs & Co., Banc of America Securities LLC, Dain Rauscher Wessels, a division of Dain Rauscher Incorporated, and Petrie Parkman & Co., Inc. are the representatives of the underwriters.
UNDERWRITERS NUMBER OF SHARES - ------------------------------------------------------------------------------------ ------------------ Goldman, Sachs & Co................................................................. 1,275,000 Banc of America Securities LLC...................................................... 637,500 Dain Rauscher Wessels, a division of Dain Rauscher Incorporated..................... 637,500 Petrie Parkman & Co., Inc........................................................... 637,500 J.C. Bradford & Co.................................................................. 203,125 Hanifen, Imhoff Inc................................................................. 203,125 Morgan Keegan & Company, Inc........................................................ 203,125 Southcoast Capital Corporation...................................................... 203,125 ---------- Total............................................................................. 4,000,000 ---------- ----------
------------------------ If the underwriters sell more shares than the total number set forth in the table above, the underwriters have an option to buy up to an additional 600,000 shares from Basin and the selling stockholder to cover such sales. They may exercise that option for 30 days. If any shares are purchased pursuant to this option, the underwriters will severally purchase shares in approximately the same proportion as set forth in the table above. The following tables show the per share and total underwriting discounts and commissions to be paid to the underwriters by Basin and the selling stockholder. Such amounts are shown assuming both no exercise and full exercise of the underwriters' option to purchase additional shares.
Paid by Basin ---------------------------- No Exercise Full Exercise ------------- ------------- Per Share................................................... $ 0.94 $ 0.94 Total....................................................... $ 3,525,000 $ 4,053,750 Paid by the Selling Stockholder ---------------------------- No Exercise Full Exercise ------------- ------------- Per Share................................................... $ 0.94 $ 0.94 Total....................................................... $ 235,000 $ 270,250
Shares sold by the underwriters to the public will initially be offered at the initial price to public set forth on the cover of this prospectus supplement. Any shares sold by the underwriters to securities dealers may be sold at a discount of up to $0.55 per share from the initial price to public. Any such securities dealers may resell any shares purchased from the underwriters to certain other brokers or dealers at a discount of up to $0.10 per share from the initial price to public. If all the shares are not sold at the initial price to public, the representatives may change the price and the other selling terms. Basin, the selling stockholder and certain officers and directors of Basin have agreed with the underwriters not to sell or dispose of or hedge any of their common stock or securities convertible U-1 into or exchangeable for shares of common stock during the period from the date of this prospectus supplement continuing through the date 90 days after the date of this prospectus supplement, except with the prior written consent of the representatives. This agreement does not apply to the issuance of common stock by Basin pursuant to any existing employee benefit plans or outstanding warrants. In connection with the offering, the underwriters may purchase and sell shares of common stock in the open market. These transactions may include short sales, stabilizing transactions and purchases to cover positions created by short sales. Short sales involve the sale by the underwriters of a greater number of shares than they are required to purchase in the offering. Stabilizing transactions consist of certain bids or purchases made for the purpose of preventing or retarding a decline in the market price of the common stock while the offering is in progress. The underwriters also may impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the representatives have repurchased shares sold by or for the account of such underwriter in stabilizing or short covering transactions. These activities by the underwriters may stabilize, maintain or otherwise affect the market price of the common stock. As a result, the price of the common stock may be higher than the price that otherwise might exist in the open market. If these activities are commenced, they may be discontinued by the underwriters at any time. These transactions may be effected on the Nasdaq National Market, in the over-the-counter market or otherwise. Petrie Parkman & Co., Inc. owns 11,103 shares of common stock and warrants to purchase 652 shares of common stock. The warrants have an exercise price of $14.00 per share and a December 31, 1999 expiration date. Basin and the selling stockholder estimate that their share of the total expenses of the offering, excluding underwriting discounts and commissions, will be approximately $450,000 and $10,000, respectively. Basin and the selling stockholder have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act of 1933. U-2 PROSPECTUS $200,000,000 [LOGO] BASIN EXPLORATION, INC. DEBT SECURITIES COMMON STOCK PREFERRED STOCK WARRANTS Basin Exploration, Inc. (the "Company" or "Basin") may offer from time to time (i) debt securities ("Debt Securities"), consisting of debentures, notes, bonds and/or other unsecured evidences of indebtedness in one or more series, (ii) shares of the Company's common stock, $.01 par value ("Common Stock"), (iii) shares of preferred stock, $.01 par value ("Preferred Stock"), in one or more series, or (iv) warrants to purchase Debt Securities, Preferred Stock or Common Stock. The foregoing securities are collectively referred to as the "Securities." Any Securities may be offered with other Securities or separately. The Securities will be offered at an aggregate initial offering price not to exceed US $200,000,000 or the equivalent (based on the applicable exchange rate at the time of sale), if Debt Securities of the Company are issued in principal amounts denominated in one or more foreign currencies or currency units as shall be designated by the Company at prices and on terms to be determined at the time of sale. SEE "RISK FACTORS" FOR CERTAIN CONSIDERATIONS RELEVANT TO AN INVESTMENT IN THE SECURITIES. This Prospectus will be supplemented by one or more accompanying Prospectus Supplements, which will set forth with regard to the particular Securities in respect of which this Prospectus is being delivered (i) in the case of Debt Securities, the title; aggregate principal amount; currency of denomination (which may be in U.S. dollars, in any other currency, currencies or currency unit, including the European Currency Unit); maturity; interest rate, if any (which may be fixed or variable), or method of calculation thereof; time of payment of any interest; form of payment of any interest whether in the form of cash, additional Debt Securities, Common Stock or some combination thereof; any terms for redemption at the option of the Company or the holder; any terms for sinking fund payments; any index or other method used to determine the amounts payable; the ranking of such Debt Securities (whether senior, senior subordinated or subordinated); any conversion or exchange rights, at the option of the Company or the holder; any listing on a securities exchange; the initial public offering price and any other terms in connection with the offering and sale of such Debt Securities; (ii) in the case of Common Stock, the number of shares of Common Stock, the terms of the offering thereof and information regarding the selling stockholder, if any; (iii) in the case of Preferred Stock, the designation, stated value and liquidation preference per share; the initial public offering price per share and the number of shares to be offered; dividend rate (or method of calculation); dates on which dividends shall be payable and dates from which dividends shall accrue; any redemption or sinking fund provisions; any conversion or exchange rights; any listing of the Preferred Stock on a securities exchange; and any other terms in connection with the offering and sale of such Preferred Stock; and (iv) in the case of Warrants, the number and terms thereof, the designation and the number of Securities issuable upon their exercise; the exercise price; any listing of the Warrants or the underlying Securities on a securities exchange and any other terms in connection with the offering, sale and exercise of the Warrants. The Prospectus Supplement will also contain information, as applicable, about certain United States federal income tax considerations relating to the Securities in respect of which this Prospectus is being delivered. The Company's Common Stock is quoted on the Nasdaq National Market (Symbol: "BSNX"). Each Prospectus Supplement will indicate if the Securities offered thereby will be quoted on any market or listed on any securities exchange. The Company may sell Securities to or through one or more underwriters, and may also sell Securities directly to other purchasers or through agents. See "Plan of Distribution." Each Prospectus Supplement will set forth the names of any underwriters, dealers or agents involved in the sale of the Securities in respect of which this Prospectus is being delivered, and any applicable fee, commission or discount arrangements with them. THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. THIS PROSPECTUS MAY NOT BE USED TO CONSUMMATE SALES OF SECURITIES UNLESS ACCOMPANIED BY A PROSPECTUS SUPPLEMENT. THE DATE OF THIS PROSPECTUS IS OCTOBER 2, 1997. AVAILABLE INFORMATION The Company is subject to the informational requirements of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and in accordance therewith files reports, proxy statements and other information with the Securities and Exchange Commission (the "Commission"). Such reports, proxy statements and other information may be inspected and copied at the public reference facilities of the Commission, Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549, as well as at the following Regional Offices: 7 World Trade Center, Suite 1300, New York, New York 10048, and Citicorp Center, 500 West Madison Street, Suite 1400, Chicago, Illinois 60661. Copies of such material can be obtained from the Commission by mail at prescribed rates. Requests should be directed to the Commission's Public Reference Section, Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington D.C. 20549. The Commission also maintains a website at http://www.sec.gov that contains reports, proxy statements, and other information. The Company's Common Stock is quoted on the Nasdaq National Market. Reports, proxy and information statements and other information relating to the Company can be inspected at the offices of the Nasdaq Stock Market, Inc., 1735 K Street, Washington, D.C., 20006. The Company has filed with the Commission a Registration Statement on Form S-3 (herein, together with all amendments and exhibits, referred to as the "Registration Statement") under the Securities Act of 1933 (the "Securities Act") with respect to the Securities offered by this Prospectus. This Prospectus, which forms part of the Registration Statement, does not contain all of the information set forth in the Registration Statement, certain parts of which have been omitted in accordance with the rules and regulations of the Commission. For further information with respect to the Company and the Securities, reference is hereby made to such Registration Statement, including the exhibits filed therewith. The Registration Statement and the exhibits thereto can be obtained by mail from or inspected and copied at the public reference facilities maintained by the Commission as described in the prior paragraph. The Company distributes to its stockholders annual reports containing audited consolidated financial statements and quarterly reports containing unaudited financial information for the first three quarters of each year. INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE The following documents filed by the Company with the Commission are incorporated by reference in this Prospectus: (1) Annual Report on Form 10-K for the year ended December 31, 1996, filed with the Commission on March 31, 1997; (2) Amendment to Annual Report on Form 10-K for the year ended December 31, 1996 on Form 10-K/A-1, filed with the Commission on June 5, 1997; (3) Quarterly Report on Form 10-Q for the period ended March 31, 1997, filed with the Commission on May 15, 1997; (4) Quarterly Report on Form 10-Q for the period ended June 30, 1997, filed with the Commission on August 12, 1997; (5) Registration Statement on Form 8-A filed with the Commission on February 27, 1996, relating to the Company's Stockholders' Rights Plan; (6) The description of the Common Stock contained in the Company's Registration Statement on Form 8-A dated April 24, 1992, filed with the Commission on April 27, 1992. All documents subsequently filed by the Company pursuant to Sections 13(a), 13(c), 14 or 15(d) of the Exchange Act prior to the termination of the offering of the Securities offered hereby shall be deemed to be incorporated by reference in this Prospectus and to be a part hereof from the date of filing of such 2 documents. Any statement contained in a document incorporated or deemed to be incorporated by reference shall be deemed to be modified or superseded for purposes of this Prospectus to the extent that a statement contained herein or in any other subsequently filed document, which also is or is deemed to be incorporated by reference herein or in any Prospectus Supplement, modifies or supersedes such statement. Any statement so modified or superseded shall not be deemed, except as so modified or superseded, to constitute a part of this Prospectus. The Company will provide without charge to each person to whom a copy of this Prospectus is delivered, on the oral or written request of such person, a copy of any or all of the documents incorporated herein by reference (other than exhibits, unless such exhibits are specifically incorporated by reference in such documents). Requests for such copies should be directed to the Secretary, 370 Seventeenth Street, Suite 3400, Denver, Colorado 80202, telephone: (303) 685-8000, facsimile: (303) 685-8010. SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS This Prospectus includes and incorporates by reference statements that are not purely historical and are "forward-looking statements" within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. All statements, other than statements of historical facts, included or incorporated by reference in this Prospectus, involve risks and uncertainties that could cause actual results to differ from projected results. Such statements address activities, events or developments that the Company expects, believes, projects, intends or anticipates will or may occur, including such matters as future capital, development and exploration expenditures (including the amount and nature thereof), drilling of wells, future production of oil and gas, business strategies, cash flow and anticipated liquidity, prospect development and property acquisition, or marketing of oil and gas. Factors that could cause actual results to differ materially ("Cautionary Disclosures") include, among others: general economic conditions, the market price of oil and natural gas, the risks associated with exploration, the Company's ability to find, acquire, market, develop and produce new properties, operating hazards attendant to the oil and natural gas business, downhole drilling and completion risks that are generally not recoverable from third parties or insurance, concentration of the Company's production in a small number of properties in the Gulf of Mexico, uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures, potential mechanical failure of individually significant productive wells, the strength and financial resources of the Company's competitors, the Company's ability to find and retain skilled personnel, climatic conditions, labor relations, availability and cost of material and equipment, delays in anticipated start-up dates, environmental risks, the results of financing efforts, actions or inactions of third-party operators of the Company's properties, regulatory developments, and other factors described in this Prospectus and in any Prospectus Supplement and in the Company's annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K filed with the Commission. Many of such factors are beyond the Company's ability to control or predict. All forward-looking statements included or incorporated by reference in this Prospectus are based on information available to the Company on the date hereof, and the Company assumes no obligation to update such forward-looking statements as a result of new information, future events or otherwise. Although the Company believes that the assumptions and expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct or that the Company will take any actions that may presently be planned. Prospective investors are cautioned not to put undue reliance on forward-looking statements. Certain important factors that could cause actual results to differ materially from the Company's expectations are disclosed under "Risk Factors" and elsewhere in this Prospectus. All written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Disclosures. 3 RISK FACTORS PROSPECTIVE PURCHASERS OF THE SECURITIES SHOULD CAREFULLY READ THIS PROSPECTUS, ANY PROSPECTUS SUPPLEMENT DELIVERED HEREWITH, AND THE DOCUMENTS INCORPORATED BY REFERENCE HEREIN AND THEREIN. OWNERSHIP OF SECURITIES INVOLVES CERTAIN RISKS. IN DETERMINING WHETHER TO PURCHASE THE SECURITIES, PROSPECTIVE INVESTORS SHOULD CONSIDER CAREFULLY THE FOLLOWING RISK FACTORS AND THE OTHER INFORMATION CONTAINED IN THIS PROSPECTUS, IN ADDITION TO THE OTHER RISK FACTORS AND INFORMATION SET FORTH IN ANY PROSPECTUS SUPPLEMENT DELIVERED HEREWITH. OIL AND GAS PRICES; HEDGING Basin's revenues and profitability are substantially dependent upon prevailing prices for oil, gas and natural gas liquids. For much of the past decade, the markets for oil and natural gas have been extremely volatile. The Company anticipates that such markets will continue to be volatile in the foreseeable future. In general, future prices of oil, gas and natural gas liquids are dependent upon numerous external factors such as various economic, political and regulatory developments and competition from other sources of energy. The unsettled nature of the energy market and the unpredictability of worldwide political developments, including, for example, actions of OPEC members, make it particularly difficult to estimate future prices of oil, gas and natural gas liquids. Any significant decline in the price of oil, gas or natural gas liquids for an extended period would have a material adverse effect on the Company's financial condition and results of operations, and would, under certain circumstances, result in a reduction in funds available under the Company's bank credit facilities and impair access to other sources of capital. From time to time, as conditions are deemed to warrant, the Company enters into energy price swap arrangements to reduce its sensitivity to oil and gas price volatility. Such arrangements are subject to a number of risks. If the Company's reserves are not produced at the rates estimated by the Company due to inaccuracies in the reserve estimation process, operational difficulties or regulatory limitations, the Company would be required to satisfy its obligations under hedging contracts on potentially unfavorable terms without the ability to hedge that risk through sales of comparable quantities of its own production. Further, the terms under which the Company enters into hedging contracts are based on assumptions and estimates of numerous factors such as cost of production and pipeline and other transportation costs to delivery points. Under financial instrument contracts, the Company may also be at risk for basis differential, which is the difference in the quoted financial price for contract settlement and the actual price received at the physical point of delivery. Substantial variations between the assumptions and estimates used by the Company and actual results experienced could materially adversely affect the Company's anticipated profit margins and its ability to manage the risk associated with fluctuations in oil and gas prices. In addition, hedging contracts are subject to the risk that the other party may prove unable or unwilling to perform its obligations under such contracts. Any significant nonperformance could have a material adverse financial effect on the Company. Furthermore, hedging contracts limit the benefits the Company would realize if actual prices rise above the contract prices. REPLACEMENT OF RESERVES Basin's future success depends upon its ability to find, develop and/or acquire additional oil and gas reserves at prices that permit profitable operations. Except to the extent that Basin conducts successful development, exploitation or exploration activities or acquires properties containing proved reserves, the proved reserves of Basin will decline. The rate of decline depends upon reservoir characteristics and varies from the steep decline rate characteristic of Gulf of Mexico reservoirs, where Basin has most of its production, to the relatively slow decline rate characteristic of the long-lived fields in the Rocky Mountain region, where the Company's other properties are located. The market for acquiring proved reserves is extremely competitive, and the Company may not be able to buy reserves for development and exploitation at prices it considers to be reasonable or within its budgets. The cost of drilling, completing and operating wells may vary significantly from initial estimates. Basin's drilling operations may be unsuccessful or may be curtailed, delayed or canceled as a result of numerous factors not within Basin's control, including but 4 not limited to title problems, weather conditions, compliance with governmental requirements, shortage of capital, mechanical difficulties and shortages or delays in the delivery of drilling rigs or other equipment. Accordingly, there can be no assurance that Basin's acquisition, development, exploitation and exploration activities will result in reserves added at acceptable costs. ACQUISITION RISKS Acquisitions of producing oil and gas properties have been a key element of Basin's success, and Basin will continue to seek acquisitions in the future. Even though Basin performs a review of the properties in connection with its acquisitions which it believes is consistent with industry practices, such reviews are inherently incomplete, and the evaluations resulting therefrom are necessarily inexact and uncertain. It is generally not feasible to review in depth every property and all records in connection with an acquisition of many properties, particularly when the seller does not operate the property. Ordinarily Basin will focus its due diligence efforts on the higher valued properties and will spot-check the remainder. However, even an in-depth review of properties and records may not necessarily reveal existing or potential problems nor will it permit a buyer to become familiar enough with the properties to assess fully their deficiencies and capabilities. Inspections may not be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Contractual indemnities may not be obtainable, and the Company may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with the Company's expectations. EXPLORATION RISKS With the sale of its D-J Basin properties in 1996, and its initiation of exploration activities in the Gulf of Mexico, the Company currently is spending a large portion of its capital budget on exploration. Exploration activities involve substantially more risk than development or exploitation activities. Although the Company believes that its use of 3-D seismic data and other advanced technologies should increase the probability of success of its exploratory wells and should reduce average finding costs through elimination of prospects that might otherwise be drilled solely on the basis of 2-D seismic data and other traditional methods, exploratory drilling remains a speculative activity. Even when fully utilized and properly interpreted, 3-D seismic data and visualization techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not conclusively allow the interpreter to know if hydrocarbons will in fact be present in such structures. In addition, the use of 3-D seismic data and such technologies requires greater predrilling expenditures than traditional drilling strategies and the Company could incur losses as a result of such expenditures. Failure of the Company's exploration activities would have a material adverse effect on the Company's future results of operations and financial condition. The Company had conducted no previous operations in the Gulf of Mexico prior to the opening of its regional office in late 1995 in Houston, Texas. This operating area is highly competitive and the Company's success in its activities there will depend on its ability to attract and retain geoscientists and other professional staff with extensive experience operating in the area. The Company's Houston office currently has a staff that includes seven geoscientists and petroleum engineers plus 3 engineering consultants, all of whom are experienced in Gulf Coast operations. Loss of these experienced personnel could have a material adverse impact on the Company's ability to compete in this area. FUTURE CAPITAL REQUIREMENTS The Company will require substantial additional capital to further develop and explore its properties and to acquire additional properties. Cash flows from operations, to the extent available, will be used to fund these expenditures. The Company may seek additional capital from traditional reserve base borrowings, equity and debt offerings, joint ventures, and/or production payment financing. The Company's ability to access additional capital will depend significantly on its continued success in exploring for and developing its reserves and the status of the capital markets at the time such capital is sought. Accordingly, 5 there can be no assurance that capital will be available to the Company from any source or that, if available, it will be on terms acceptable to the Company. Should sufficient capital not be available, the development and exploration of the Company's properties could be delayed and, accordingly, the implementation of the Company's business strategy would be adversely affected. MARKETING OF PRODUCTION; SEASONALITY The marketability of Basin's production depends upon the availability and capacity of gathering systems and pipelines, the effects of federal and state regulation of such production and transportation, general economic conditions, supply of and demand for oil and natural gas, all of which could adversely affect Basin's ability to market its production. Demand for natural gas is highly seasonal, with demand generally higher in the colder winter months and in the hot summer months. As a result, the price received for spot market natural gas may vary significantly between seasonal periods. To date, the Company generally has been able to sell its available spot market natural gas at prevailing spot market prices, such that volumes sold have not materially fluctuated seasonally. There is no assurance, however, that the Company will be able to continue to achieve this result. CONCENTRATION OF VALUE As of the date of this Prospectus, a significant portion of Basin's production is concentrated in two wells on one platform in the Gulf of Mexico. If mechanical problems, storms, or other events that caused curtailment or cessation of such production were to occur, Basin's cash flow would be materially adversely affected. The Company will remain vulnerable to a disproportionate impact of delays or interruptions of production from these wells until it develops a more diversified production base including additional properties. ESTIMATES OF RESERVES AND RELATED DATA Numerous uncertainties are inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth in this Prospectus or incorporated herein by reference represents only estimates based on available geological, geophysical, production and engineering data, the extent, quality and reliability of which vary. Oil and gas reserve engineering is a subjective process of estimating accumulations of oil and gas that cannot be measured in an exact manner, and estimates of other engineers might differ materially from those shown. The accuracy of any reserve estimate is a function of the quality and quantity of available data, engineering and geological interpretation and judgment. In addition, the estimates of future net cash flow from proved reserves of the Company and the present value thereof are based upon certain assumptions about future production levels, prices, costs and participation, if any, by third parties in the development of the Company's reserves that may not prove correct over time, for reasons which may or may not be under the control of or known to the Company. Any significant variance from these assumptions could materially affect the quantity and value of the Company's reserves as compared to the estimates contained in this Prospectus. FLUCTUATIONS IN QUARTERLY RESULTS Basin's quarterly results of operations may fluctuate significantly as a result of variations in oil and gas prices and variations in the Company's drilling activities. Drilling activities can be affected by a number of factors including the need to utilize capital for new acquisitions, availability of permits for drilling or recompletions, weather, seasonal restrictions (such as growing crops and winter game restrictions), governmental regulations and available cash flow. OPERATING HAZARDS The oil and gas business involves a variety of operating risks, including the risk of fire, explosion, blow-out, pipe failure, casing collapse, stuck tools, abnormally pressured formations and environmental hazards 6 such as oil spills, gas leaks, pipeline ruptures and discharges of toxic gases, the occurrence of any of which could result in substantial losses to Basin due to injury and loss of life, loss of or damage to wellbores and/ or drilling or production equipment, costs of overcoming downhole problems, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Gathering systems and processing facilities are subject to many of the same hazards and any significant problems related to those facilities could adversely affect Basin's ability to market its production. Moreover, offshore operations are subject to a variety of operating risks peculiar to the marine environment, such as hurricanes or other adverse weather conditions. Basin maintains insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. Insurance may not cover downhole operating risks, such as the costs of retrieving stuck equipment. Furthermore, Basin cannot predict whether insurance will continue to be available at premium levels that justify its purchase or whether insurance will be available at all to cover the risks faced by the Company. ENVIRONMENTAL REGULATION The drilling for and production, handling, transportation and disposal of oil and gas and by-products are subject to extensive regulation under federal, state and local environmental laws. In most instances, the applicable regulatory requirements relate to water and air pollution control and solid waste management measures, permitting requirements, or restrictions on operations in environmentally sensitive areas, such as coastal zones, wetlands, and wildlife habitat. Environmental assessments have not been performed on all of Basin's properties. To date, expenditures for environmental control facilities and for remediation have not been significant in relation to the results of operations of Basin. Basin believes, however, that the trend toward stricter standards in environmental legislation and regulation is likely to continue. Offshore operations are subject to more extensive governmental regulation, including regulation that may, in certain circumstances, impose absolute liability for environmental damage and allow interruption or termination of business activities by government authorities based on environmental or other considerations. The Oil Pollution Act of 1990 (the "OPA") also requires proof of financial responsibility to cover costs of potential oil spills; the amount of such required coverage ranges from $35 million to $150 million based on federal risk assessment. From time to time, legislation has been introduced in Congress which would reclassify oil and gas production wastes as "hazardous waste" under the Resource Conservation and Recovery Act. If such legislation were to pass, it could have a significant adverse impact on the operating costs of Basin, as well as the oil and gas industry in general. Initiatives regulating the disposal of exploration and production waste are also pending or have been enacted in certain states, including states in which Basin conducts operations, and these various initiatives could have a similar impact on the Company. GOVERNMENTAL REGULATION Development, production and sale of oil and gas are subject to extensive federal, state and local governmental regulation which may be changed from time to time in response to economic or political conditions. Matters subject to regulation include, but are not limited to, permits for drilling operations, drilling, plugging and reclamation bonds, operational practices and reporting, the spacing of wells, unitization and pooling of properties, taxation and environmental protection. The Minerals Management Service of the United States Department of the Interior ("MMS") has proposed regulations for valuation of crude oil and natural gas produced from federal leases, including offshore leases, that could require payment of royalties on the basis of indices or benchmarks that may not reflect actual prices received by the Company for its production. The Federal Energy Regulatory Commission has promulgated major regulatory initiatives over the past several years which have had a significant impact on natural gas pricing and natural gas pipeline operations, services and rates. Those changes have significantly altered the marketing of natural gas. Although the purpose of these changes is generally to enhance competition in natural gas marketing, the effect of these changes on the Company's ability to market its gas at reasonable 7 prices from any given property is uncertain. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and gas wells below actual production capacity in order to conserve supplies of oil and gas. Under the Outer Continental Shelf Lands Act ("OCSLA") the MMS regulates development and production of oil and gas in federal waters in the Gulf of Mexico and may suspend or terminate operations for violation of MMS rules. Any such suspension or termination could materially and adversely affect the Company's financial condition and operations. There are many legislative proposals pending in Congress and in the legislatures of various states that, if enacted, might significantly affect the oil and gas industry. Basin is not able to predict what will be enacted and thus what effect, if any, such proposals would have on Basin. COMPETITION Competition in the oil and gas industry is intense, particularly with respect to the acquisition of producing properties and proved undeveloped acreage and the acquisition of interests in offshore exploration prospects in the Gulf of Mexico. Major and independent oil and gas companies, as well as individuals and drilling programs, actively bid for desirable oil and gas properties, as well as for the equipment and labor required to operate and develop such properties. A number of Basin's competitors have financial resources and exploration and development budgets that are substantially greater than those of Basin, which may adversely affect the Company's ability to compete successfully. In addition, many of the Company's larger competitors may be better able to respond to factors that affect the demand for oil and natural gas production such as changes in worldwide oil and natural gas prices and levels of production, the cost and availability of alternative fuels, and the application of government regulations. The Company commenced operations in the Gulf of Mexico area during 1996, where it had not previously been active. Competition from major and large independent oil and gas companies is significantly greater in this area than in the Rocky Mountain region, where the Company had conducted all of its previous operations. PRINCIPAL STOCKHOLDER Basin's principal stockholder, Michael S. Smith, together with members of his immediate family and trustees for their benefit, beneficially own approximately 30% of Basin's outstanding shares. As a result, Mr. Smith is in a position to substantially influence the outcome of stockholder votes on the election of directors and other matters. In addition, if Mr. Smith were to sell a significant number of his shares, the prevailing market price of the Common Stock could be adversely affected. DEPENDENCE ON KEY PERSONNEL Basin depends to a large extent on the services of its founder and CEO, Michael Smith and certain other senior management personnel. The loss of the services of Mr. Smith or other key personnel could have a potential adverse effect on Basin's operations. ANTI-TAKEOVER PROVISIONS Basin's Restated Certificate of Incorporation and Bylaws and the provisions of the Delaware General Corporation Law make it more difficult to change control of Basin and replace incumbent management. The Company adopted a Stockholders' Rights Plan in 1996, pursuant to which holders of Common Stock of the Company received rights which are exercisable if a person or group of affiliated persons acquires 15% of the Company's outstanding Common Stock or commences a tender or exchange offer, the consummation of which would result in ownership of 15% or more of the Company's outstanding Common Stock. See "Description of Capital Stock--Stockholders' Rights Plan." In addition, the Company has entered into agreements with certain of its executive officers which would require additional payments by the Company if such officers' employment were terminated upon a change of control. 8 THE COMPANY GENERAL Basin Exploration, Inc. ("Basin" or the "Company") is an independent oil and gas exploration and production company operating in the United States. The Company's business objective is to efficiently increase its proved oil and gas reserves in order to grow production, cash flow, and earnings per share. The Company seeks to accomplish this by exploring for new oil and gas reserves and acquiring proved properties with exploitation or development potential, utilizing advanced technologies. The Company currently conducts exploration activities exclusively in the shallow waters of the Gulf of Mexico, offshore Louisiana and Texas. Basin seeks acquisition opportunities both in the vicinity of the Company's exploration activities offshore and in certain geographic areas onshore where the Company's staff has had extensive experience, including the Rocky Mountains and onshore Gulf Coast areas. Basin's reserves are located primarily in the Gulf of Mexico and in the Powder River and Green River Basins in Wyoming. At December 31, 1996, the Company's estimated proved reserves totaled approximately 7.9 MMBbl and 29.7 Bcf of natural gas, or 76.9 Bcfe. Most of Basin's proved oil and gas reserves are attributable to Company-operated properties. A significant portion of Basin's reserves at the beginning of 1996 were located in the Denver-Julesburg ("D-J") Basin in eastern Colorado, but such reserves were sold in 1996 to provide funds for other operations, including initiation of operations in the Gulf of Mexico. Since commencing operations in the Gulf of Mexico in 1996, the Company has participated in drilling ten wells, of which five have been or are expected to be completed as producers. The Company has operated all but one of these wells, with an average working interest at the time of drilling of approximately 51%. Five of the ten wells drilled to date have been drilled since July 1, 1997, reflecting a recent acceleration in activity after a start-up period during which the Company assembled its initial prospect inventory. As of the date of this Prospectus, the Company has assembled a Gulf of Mexico leasehold inventory of 96,421 gross acres, comprising 63,248 net acres, with more than 20 identified potential exploration prospects, all of which are supported by the Company's interpretations of three-dimensional ("3-D") seismic data. In order to reduce the risks and costs for acreage, drilling and completion operations, the Company uses 3-D seismic and computer-aided exploration and exploitation technology in virtually all of its activities in the Gulf of Mexico. The Company has also closed acquisitions of Gulf of Mexico proved properties totaling more than $18 million in 1997 through the date of this Prospectus. Two of the Gulf of Mexico wells that the Company has completed, both located on Eugene Island Block 65, commenced production in August 1997 and now account for a substantial portion of the Company's total oil and gas production. The three other drilled wells that the Company anticipates will commence production, plus an additional Gulf of Mexico well in which the Company acquired an interest after it was drilled and completed, are temporarily suspended pending additional development. Three of these wells, one each on East Cameron Block 378, Eugene Island Block 83, and West Cameron Block 56, are expected to commence production shortly before or during the first quarter of 1998. The Company's onshore oil and gas assets are comprised of properties that generally have a relatively stable, long-lived production profile. The Company has identified potential for additional drilling, well deepenings, or secondary recovery on several of the more valuable properties. The Company intends to continue to exploit, and to pursue acquisitions to expand, this asset base. The Company currently has a capital budget established for 1997 of approximately $60 million, allocated approximately equally to exploration activities, development, and acquisitions that have already been consummated. This budget could be increased for additional acquisitions or for development of additional exploratory discoveries. The 1997 capital budget represents a significant increase from capital expenditures on oil and gas properties in 1996 and 1995 of approximately $23 million and $16 million, respectively. 9 HISTORY Basin commenced operations in 1981 and completed an initial public offering of its common stock in 1992. From its inception through 1991, the Company primarily acquired, developed and exploited properties in the D-J Basin. Such operations were expanded into other areas within the Rocky Mountain region in 1992, and the Company initiated Rocky Mountain exploration activities in 1993. By December 31, 1994, the Company's estimated proved oil and gas reserves had grown to 247.2 Bcfe, of which 169.2 Bcfe, or 68.4%, were located in the D-J Basin. From 1992 through 1994, the D-J Basin was one of the most active drilling areas in the United States and the Company was one of the more active and successful operators in the area. As the basin became increasingly exploited, however, it was the Company's assessment and experience that the number and quality of development projects in the area significantly diminished. During 1995, the Company's capital expenditures on oil and gas properties declined to $16 million, from $67 million the year before, and its estimated proved oil and gas reserves declined to 207.1 Bcfe at year-end. Principal factors contributing to these reductions included: (i) a smaller and lower-quality inventory of D-J Basin exploitation projects; (ii) insufficient success in identifying acquisition opportunities and viable exploration plays in the Company's other Rocky Mountain focus areas; and (iii) liquidity constraints caused largely by the Company's higher debt levels. In direct response to these developments, the Company implemented a significant redirection of its business strategy and operations between late-1995 and mid-1996, including: (i) the addition of new financial, technical and business development members to its senior management; (ii) the sale of the Company's D-J Basin assets, including approximately 70% of the Company's estimated proved reserves, for $123.5 million; (iii) establishment of a Houston-based Gulf of Mexico exploration team through the hiring of senior geoscientists and petroleum engineers with substantial experience operating in the shallow waters of the Gulf of Mexico; and (iv) a substantial reduction in corporate general and administrative overhead. Since the redirection of its business, the Company has significantly increased its proved reserves and production base through Gulf of Mexico drilling activity and acquisitions, and it has established a sizable inventory of Gulf of Mexico leaseholds and prospects for future exploratory drilling. 10 USE OF PROCEEDS Unless a Prospectus Supplement indicates otherwise, the net proceeds to be received by the Company from the sale of the Securities will be used for repayment of indebtedness, to finance the Company's operations, for the continued development of its oil and gas properties and for other general corporate purposes. Pending such application, such net proceeds may be invested in short-term marketable securities. RATIO OF EARNINGS TO FIXED CHARGES The ratio of earnings to fixed charges for the Company was as follows for the years ended December 31, 1996, 1995, 1994, 1993 and 1992:
YEAR ENDED DECEMBER 31, -------------------------------------------------- 1996 1995 1994 1993 ----- ----- ----- ----- Ratio of earnings to fixed charges (unaudited)....................... 9.6 (a) 2.6 3.5 1992 ----- Ratio of earnings to fixed charges (unaudited)....................... 3.2
- ------------------------ (a) Earnings did not cover fixed charges in 1995 by $27.3 million. As used in the above calculations, "earnings" means earnings before income taxes and fixed charges, and "fixed charges" means interest on all indebtedness, that portion of rental expense that management believes to be representative of interest expense and capitalized interest. DESCRIPTION OF DEBT SECURITIES Debt Securities may be issued from time to time in one or more series by the Company. The Debt Securities will constitute either indebtedness designated as Senior Indebtedness ("Senior Debt Securities"), indebtedness designated as Senior Subordinated Indebtedness ("Senior Subordinated Debt Securities") or indebtedness designated as Subordinated Indebtedness ("Subordinated Debt Securities"). The particular terms of each series of Debt Securities offered by a particular Prospectus Supplement will be described therein. Senior Debt Securities, Senior Subordinated Debt Securities and Subordinated Debt Securities will each be issued under a separate indenture (individually an "Indenture" and collectively the "Indentures") to be entered into prior to the issuance of such Debt Securities. The Indentures will be substantially identical, except for provisions relating to subordination. See "Subordination of Senior Subordinated Debt Securities and Subordinated Debt Securities." A copy of the form of the Indenture is filed as an Exhibit to the Registration Statement of which this Prospectus is a part. There will be a separate Trustee (individually a "Trustee" and collectively the "Trustees") under each Indenture. Information regarding the Trustee under an Indenture will be included in any Prospectus Supplement relating to the Debt Securities issued thereunder. The following discussion includes a summary description of the material terms of the Indentures, other than terms which are specific to a particular series of Debt Securities and which will be described in the Prospectus Supplement relating to such series. The following summaries do not purport to be complete and are subject to, and are qualified in their entirety by reference to, all of the provisions of the Indentures, including the definitions therein of certain terms capitalized in this Prospectus. Wherever particular Sections, Articles or defined terms of the Indentures are referred to herein or in a Prospectus Supplement, such Sections, Articles or defined terms are incorporated herein or therein by reference. 11 GENERAL The Debt Securities will be general unsecured obligations of the Company. The Indentures do not limit the aggregate amount of Debt Securities which may be issued thereunder, and Debt Securities may be issued thereunder from time to time in separate series up to the aggregate amount from time to time authorized for each series. Debt Securities of a series may be issuable in registered form without coupons ("Registered Debt Securities"), in bearer form with or without coupons attached ("Bearer Debt Securities") or in the form of one or more global Securities in registered or bearer form (each, a "Global Security"). Bearer Debt Securities, if any, will be offered only to non-United States persons and to offices located outside the United States of certain United States financial institutions. The applicable Prospectus Supplement or Prospectus Supplements will describe the following terms of the series of Debt Securities in respect of which this Prospectus is being delivered: (1) the title of such Debt Securities; (2) any limit on the aggregate principal amount of such Debt Securities; (3) whether such Debt Securities will be issued as Registered Debt Securities, Bearer Debt Securities or any combination thereof, and any limitation on issuance of such Bearer Debt Securities and any provisions regarding the transfer or exchange of such Bearer Debt Securities, including exchange for Registered Debt Securities of the same series; (4) whether any of such Debt Securities are to be issuable in permanent global form and, if so, the terms and conditions, if any, upon which interests in such Debt Securities in global form may be exchanged, in whole or in part, for the individual Debt Securities represented thereby; (5) the person to whom any interest on any Debt Security of the series shall be payable, if other than the person in whose name the Debt Security is registered on the Regular Record Date; (6) the date or dates on which such Debt Securities will mature; (7) the rate or rates of interest, if any, or the method of calculation thereof, which such Debt Securities will bear, and the basis upon which interest will be calculated if other than that of a 360-day year of twelve 30-day months; (8) the date or dates from which any such interest will accrue, the Interest Payment Dates on which any such interest on such Debt Securities will be payable, the Regular Record Date for any interest payable on any Interest Payment Date and any provision for the deferral of interest payments; (9) whether any such interest will be payable in cash, through the issuance of additional Debt Securities, through the issuance of Common Stock, through some combination of cash and additional Debt Securities or through some combination of cash and Common Stock; (10) the place or places where the principal of, premium, if any, and interest on such Debt Securities will be payable; (11) the period or periods within which, the events upon the occurrence of which, and the price or prices at which, such Debt Securities may, pursuant to any optional or mandatory provisions, be redeemed or purchased, in whole or in part, by the Company and any terms and conditions relevant thereto; (12) the obligations of the Company, if any, to redeem or repurchase such Debt Securities pursuant to any sinking fund or analogous provisions or at the option of the Holders thereof; (13) the denominations in which any such Debt Securities will be issuable, if other than denominations of US $1,000 and any integral multiple thereof; (14) the units of payment of principal of, premium, if any, and interest on such Debt Securities if other than US dollars, which units may consist of currency, currencies, currency unit or units, or securities; (15) any index or formula to be used to determine the amount of payments of principal, premium, if any, and interest on such Debt Securities, and any commodities, currencies, currency units or indices, or value, rate or price, relevant to such determination; (16) if the principal of, premium, if any, or interest on such Debt Securities is to be payable, at the election of the Company or a Holder thereof, in one or more currencies or currency units other than that or those in which such Debt Securities are stated to be payable, the currencies or currency units in which payment of the principal of, premium, if any, and interest on such Debt Securities as to which election is made shall be payable, and the periods within which and the terms and conditions upon which such election is to be made; (17) if other than the principal amount thereof, the portion of the principal amount of such Debt Securities of the series which will be payable upon acceleration of the Maturity thereof; (18) whether such Debt Securities are subordinate in right of payment to any Senior Indebtedness of the Company and, if so, the terms and conditions of such subordination and the aggregate principal amount of such Senior Indebtedness outstanding as of a recent date; (19) any covenants to which the Company may be subject with respect to such Debt Securities; 12 (20) the applicability of the provisions described under "Defeasance" below; (21) the terms and conditions, if any, pursuant to which such Debt Securities are convertible into or exchangeable for Common Stock or other securities; (22) if the principle amount payable at the Stated Maturity of the Debt Securities is not determinable upon original issuance or at any time prior to Maturity, the amount that is deemed to be the principal amount outstanding at any time; (23) the terms of any guarantee of the payment of principal and interest on the Debt Securities; (24) any additions, deletions or changes in the Events of Default with respect to the Debt Securities and (25) any other terms of such Debt Securities. Debt Securities may be issued at a discount from their principal amount. United States federal income tax considerations and other special considerations applicable to any such Original Issue Discount Securities will be described in the applicable Prospectus Supplement. If the purchase price of any series of Debt Securities is denominated in a foreign currency or currencies or a foreign currency unit or units or if the principal of, premium, if any, and interest on any series of Debt Securities are payable in a foreign currency or currencies, a foreign currency unit or units or in securities, the restrictions, elections, general tax considerations, specific terms and other information with respect to such series of Debt Securities will be set forth in the applicable Prospectus Supplement. Debt Securities may be issued from time to time with payment terms which are calculated by reference to the value, rate or price of one or more commodities, currencies, currency units or indices. Holders of such Debt Securities may receive a principal amount (including premium, if any) on any principal payment date, or a payment of interest on any interest payment date, that is greater than or less than the amount of principal (including premium, if any) or interest otherwise payable on such dates, depending upon the value, rate or price on the applicable dates of the applicable currency, currency unit, commodity or index. Information as to the methods for determining the amount of principal, premium, if any, or interest payable on any date, the currencies, currency units, commodities or indices to which the amount payable on such date is linked and any additional tax considerations will be set forth in the applicable Prospectus Supplement. SENIOR DEBT SECURITIES The Senior Debt Securities will rank pari passu with all other unsecured and unsubordinated debt of the Company and senior to the Senior Subordinated Debt Securities and Subordinated Debt Securities. SUBORDINATION OF SENIOR SUBORDINATED DEBT SECURITIES, SUBORDINATED DEBT SECURITIES AND GUARANTEES The payment of the principal of, premium, if any, and interest on the Senior Subordinated Debt Securities and the Subordinated Debt Securities will, to the extent set forth in the respective Indentures governing such Senior Subordinated Debt Securities and Subordinated Debt Securities, be subordinated in right of payment to the prior payment in full of all Senior Indebtedness. Upon any payment or distribution of assets to creditors upon any liquidation, dissolution, winding up, reorganization, assignment for the benefit of creditors, marshalling of assets or any bankruptcy, insolvency or similar proceedings of the Company, the holders of all Senior Indebtedness will be entitled to receive payment in full of all amounts due or to become due thereon before the Holders of the Senior Subordinated Debt Securities or the Subordinated Debt Securities will be entitled to receive any payment in respect of the principal of, premium, if any, or interest on such Senior Subordinated Debt Securities or Subordinated Debt Securities, as the case may be. In the event of the acceleration of the maturity of any Senior Subordinated Debt Securities or Subordinated Debt Securities, the holders of all Senior Indebtedness will be entitled to receive payment in full of all amounts due or to become due thereon before the Holders of the Senior Subordinated Debt Securities or Subordinated Debt Securities, as the case may be, will be entitled to receive any payment upon the principal of, premium, if any, or interest on such Senior Subordinated Debt Securities or Subordinated Debt Securities, as the case may be. No payments on account of principal, premium, if any, or interest in respect of the Senior Subordinated Debt Securities or Subordinated Debt 13 Securities may be made if there shall have occurred and be continuing a default in the payment of principal of (or premium, if any) or interest on any Senior Indebtedness beyond any applicable grace period, or a default with respect to any Senior Indebtedness permitting the holders thereof to accelerate the maturity thereof, or if any judicial proceedings shall be pending with respect to any such default. For purposes of the subordination provisions, the payment, issuance or delivery of cash, property or securities (other than stock, and certain subordinated securities, of the Company) upon conversion, redemption or otherwise of a Senior Subordinated Debt Security or Subordinated Debt Security will be deemed to constitute payment on account of the principal of such Senior Subordinated Debt Security or Subordinated Debt Security, as the case may be. By reason of such provisions, in the event of insolvency, holders of Senior Subordinated Debt Securities and Subordinated Debt Securities may recover less, ratably, than holders of Senior Indebtedness with respect thereto. The term "Senior Indebtedness," means the obligations of the Company with respect to (i) Indebtedness of the Company under the Bank Credit Facility and any renewal, refunding, refinancing, replacement or extension thereof and (ii) any other Indebtedness of the Company (other than the Securities), whether outstanding on the date of this Indenture or thereafter created, incurred or assumed, and any renewal, refunding, refinancing, replacement or extension thereof, unless, in the case of any particular Indebtedness, the instrument creating or evidencing the same or pursuant to which the same is outstanding expressly provides that such Indebtedness shall not be senior in right of payment to the Securities or that such indebtedness is PARI PASSU with or junior to the Securities. Notwithstanding the foregoing, Senior Indebtedness shall not include (i) indebtedness of the Company to a subsidiary of the Company, (ii) amounts owed for goods, materials or services purchased in the ordinary course of business, (iii) indebtedness incurred in violation of this Indenture, (iv) amounts payable or any other Indebtedness to employees of the Company or any Subsidiary of the Company, (v) any liability for Federal, state, local or other taxes owed or owing by the Company, (vi) any indebtedness of the Company that, when incurred and without regard to any election under Section 1111(b) of the United States Bankruptcy Code, was without recourse to the Company, and (vii) indebtedness evidenced by Senior Subordinated Debt Securities. If this Prospectus is being delivered in connection with a series of Senior Subordinated Debt Securities or Subordinated Debt Securities, the accompanying Prospectus Supplement or the information incorporated herein by reference will set forth the approximate amount of Senior Indebtedness outstanding as of the end of the Company's most recent fiscal quarter. FORM, EXCHANGE, REGISTRATION, CONVERSION, TRANSFER AND PAYMENT Debt Securities are issuable in definitive form as Registered Debt Securities, as Bearer Debt Securities or both. Unless otherwise indicated in an applicable Prospectus Supplement, Bearer Debt Securities will have interest coupons attached. Debt Securities are also issuable in temporary or permanent global form. Registered Debt Securities of any series (other than a Global Security) will be exchangeable for other Registered Debt Securities of the same series and of a like aggregate principal amount and tenor of different authorized denominations. In addition, with respect to any series of Bearer Debt Securities, at the option of the holder, subject to the terms of the Indenture, such Bearer Debt Securities (with all unmatured coupons, except as provided below, and all matured coupons in default) will be exchangeable into Registered Debt Securities of the same series of any authorized denominations and of a like aggregate principal amount and tenor. Bearer Debt Securities surrendered in exchange for Registered Debt Securities between a Regular Record Date or a Special Record Date and the relevant date for payment of interest shall be surrendered without the coupon relating to such date for payment of interest, and interest accrued as of such date will not be payable in respect of the Registered Debt Security issued in exchange 14 for such Bearer Debt Security, but will be payable only to the holder of such coupon when due in accordance with the terms of the Indenture. In connection with its sale during the restricted period (as defined below), no Bearer Debt Security (including a Debt Security in permanent global form that is either a Bearer Debt Security or exchangeable for Bearer Debt Securities) shall be mailed or otherwise delivered to any location in the United States (as defined under "--Limitations on Issuance of Bearer Debt Securities") and a Bearer Debt Security may be delivered outside the United States in definitive form in connection with its original issuance only if prior to delivery the person entitled to receive such Bearer Debt Security furnishes written certification, in the form required by the Indenture, to the effect that such Bearer Debt Security is owned by: (a) a person (purchasing for its own account) who is not a United States person (as defined under "--Limitations on Issuance of Bearer Debt Securities"); (b) a United States person who (i) is a foreign branch of a United States financial institution purchasing for its own account or for resale or (ii) acquired such Bearer Debt Security through the foreign branch of a United States financial institution and who for purposes of the certification holds such Bearer Debt Security through such financial institution on the date of certification and, in either case, such United States financial institution certifies to the Company or the distributor selling the Bearer Debt Security within a reasonable time stating that it agrees to comply with the requirements of Section 165(j)(3)(A), (B) or (C) of the United States Internal Revenue Code of 1986, as amended (the "Code"), and the regulations thereunder, or (c) a United States or foreign financial institution for purposes of resale within the "restricted period" as defined in United States Treasury Regulations Section 1.163-5(c)(2)(i)(D)(7). A financial institution described in clause (c) of the preceding sentence (whether or not also described in clauses (a) and (b)) must certify that it has not acquired the Bearer Debt Security for purpose of resale, directly or indirectly, to a United States person or to a person within the United States or its possessions. In the case of a Bearer Debt Security in permanent global form, such certification must be given in connection with notation of a beneficial owner's interest therein in connection with the original issuance of such Debt Security or upon exchange of a portion of a temporary global Debt Security. Debt Securities may be presented for exchange as provided above, and Registered Debt Securities may be presented for registration of transfer (with the form of transfer endorsed thereon duly executed), at the office or agency of the Company maintained for such purposes and at any other office or agency maintained for such purpose with respect to any series of Debt Securities and referred to in the applicable Prospectus Supplement, without a service charge and upon payment of any taxes and other governmental charges as described in the Indenture. Such transfer or exchange will be effected upon the Company or its agent, as the case may be, being satisfied with the documents of title and identity of the person making the request. The Company shall not be required to (i) issue, register the transfer of or exchange Debt Securities of any series during a period of 15 days prior to the mailing of a notice of redemption of Debt Securities of that series; or (ii) register the transfer of or exchange any Debt Security, or portion thereof, called for redemption, except that any Bearer Debt Security exchangeable for a Registered Debt Security of that series may be so exchanged during the period preceding the redemption date therefor which is simultaneously surrendered for redemption. PAYMENT AND PAYING AGENTS Unless otherwise indicated in the applicable Prospectus Supplement, payment of principal of (and premium, if any) and interest on Bearer Debt Securities will be payable, subject to any applicable laws and regulations, in the designated currency or currency unit, at the offices of such Paying Agents ("Paying Agents") outside the United States as the Company may designate from time to time, at the option of the holder, by check or by transfer to an account maintained by the payee with a bank located outside the United States; provided, however, that the written certification described above under "--Form, Exchange, Registration, Conversion, Transfer and Payment" has been delivered prior to the first actual payment of 15 interest. Unless otherwise indicated in the applicable Prospectus Supplement, payment of interest on Bearer Debt Securities on any Interest Payment Date will be made only against surrender to the Paying Agent of the coupon relating to such Interest Payment Date. No payment with respect to any Bearer Debt Security will be made at any office or agency of the Company in the United States or by check mailed to any address in the United States or by transfer to any account maintained with a bank located in the United States, nor shall any payments be made in respect of Bearer Debt Securities upon presentation to the Company or its designated Paying Agents within the United States. Notwithstanding the foregoing, payments of principal of (and premium, if any) and interest on Bearer Debt Securities denominated and payable in US dollars will be made at the office of the Company's Paying Agent in the United States, if (but only if) payment of the full amount thereof in US dollars at all offices or agencies outside the United States is illegal or effectively precluded by exchange controls or other similar restrictions. Unless otherwise indicated in the applicable Prospectus Supplement, payment of principal of (and premium, if any) and interest on Registered Debt Securities will be made in the designated currency or currency unit at the office of such Paying Agent or Paying Agents as the Company may designate from time to time, except that at the option of the Company payment of any interest may be made by check mailed to the address of the person entitled thereto as such address shall appear in the Security Register. Unless otherwise indicated in an applicable Prospectus Supplement, payment of any installment of interest on Registered Debt Securities will be made to the person in whose name such Registered Debt Security is registered at the close of business on the Regular Record Date for such interest. Unless otherwise indicated in the applicable Prospectus Supplement, the Corporate Trust Office of the Trustee will be designated as a Paying Agent for the Trustee for payments with respect to Debt Securities which are issuable solely as Registered Debt Securities, and the Company will maintain a Paying Agent outside the United States for payments with respect to Debt Securities (subject to limitations described above in the case of Bearer Debt Securities) which are issued solely as Bearer Debt Securities, or as both Registered Debt Securities and Bearer Debt Securities. Any Paying Agents outside the United States and any other Paying Agents in the United States initially designated by the Company for the Debt Securities will be named in an applicable Prospectus Supplement. The Company may at any time designate additional Paying Agents or rescind the designation of any Paying Agent or approve a change in the office through which any Paying Agent acts, except that, if Debt Securities of a series are issued solely as Registered Debt Securities, the Company will be required to maintain a Paying Agent in each Place of Payment for such series and, if Debt Securities of a series are issued as Bearer Securities, the Company will be required to maintain (i) a Paying Agent in the United States for principal payments with respect to any Registered Debt Securities of the series (and for payments with respect to Bearer Debt Securities of the series in the circumstances described above, but not otherwise), and (ii) a Paying Agent in a Place of Payment located outside the United States where Securities of such series and any coupons appertaining thereto may be presented and surrendered for payment. All monies paid by the Company to a Paying Agent for the payment of principal of and any premium or interest on any Debt Security which remain unclaimed at the end of two years after such principal, premium or interest shall have become due and payable will (subject to applicable escheat laws) be repaid to the Company and the holder of such Debt Security or any coupon will thereafter look only to the Company for payment thereof. 16 TEMPORARY GLOBAL SECURITIES If so specified in the applicable Prospectus Supplement, all or any portion of the Debt Securities of a series which are issuable as Bearer Debt Securities will initially be represented by one or more temporary global Debt Securities, without interest coupons, to be deposited with a common depository in London for the Euroclear System ("Euroclear") and CEDEL S.A. ("CEDEL") for credit to the designated accounts. On and after the date determined as provided in any such temporary global Debt Security and described in the applicable Prospectus Supplement, each such temporary global Debt Security will be exchangeable for definitive Bearer Debt Securities, definitive Registered Debt Securities or all or a portion of a permanent global security, or any combination thereof, as specified in the applicable Prospectus Supplement, but, unless otherwise specified in the applicable Prospectus Supplement, only upon written certification in the form and to the effect described under "--Form, Exchange, Registration, Conversion, Transfer and Payment." No Bearer Debt Security delivered in exchange for a portion of a temporary global Debt Security will be mailed or otherwise delivered to any location in the United States in connection with such exchange. Unless otherwise specified in the applicable Prospectus Supplement, interest in respect of any portion of a temporary global Debt Security payable in respect of an Interest Payment Date occurring prior to the issuance of definitive Debt Securities or a permanent global Debt Security will be paid to each of Euroclear and CEDEL with respect to the portion of the temporary global Debt Security held for its account. Each of Euroclear and CEDEL will undertake in such circumstances to credit such interest received by it in respect of a temporary global Debt Security to the respective accounts for which it holds such temporary global Debt Security only upon receipt in each case of written certification in the form and to the effect described above under "--Form, Exchange, Registration, Conversion, Transfer and Payment" as of the relevant Interest Payment Date regarding the portion of such temporary global Debt Security on which interest is to be so credited. PERMANENT GLOBAL SECURITIES If any Debt Securities of a series are issuable in permanent global form, the applicable Prospectus Supplement will describe the circumstances, if any, under which beneficial owners of interests in any such permanent global Debt Securities may exchange such interests for Debt Securities of such series and of like tenor and principal amount in any authorized form and denomination. No Bearer Debt Security delivered in exchange for a portion of a permanent global Debt Security shall be mailed or otherwise delivered to any location in the United States in connection with such exchange. BOOK-ENTRY DEBT SECURITIES The Debt Securities of a series may be issued in whole or in part in the form of one or more Global Securities that will be deposited with, or on behalf of, a depositary ("Depositary") or its nominee identified in the applicable Prospectus Supplement. In such a case, one or more Global Securities will be issued in a denomination or aggregate denomination equal to the portion of the aggregate principal amount of Outstanding Debt Securities of the series to be represented by such Global Security or Securities. The specific terms of the depositary arrangement with respect to any portion of a series of Debt Securities and the rights of, and limitations on, owners of beneficial interests in any such Global Security representing all or a portion of a series of Debt Securities will be described in the applicable Prospectus Supplement. LIMITATIONS ON ISSUANCE OF BEARER DEBT SECURITIES In compliance with United States federal tax laws and regulations, Bearer Debt Securities (including securities in permanent global form that are either Bearer Debt Securities or exchangeable for Bearer Debt Securities) will not be offered or sold during the restricted period (as defined in United States Treasury Regulations Section 1.163-5(c)(2)(i)(D)(7)) (generally, the first 40 days after the closing date, 17 and, with respect to unsold allotments, until sold) within the United States or to United States persons (each as defined below) other than to an office located outside the United States of a United States financial institution (as defined in Section 1.165-12(c)(1)(v) of the United States Treasury Regulations), purchasing for its own account or for resale or for the account of certain customers, that provides a certificate stating that it agrees to comply with the requirements of Section 165(j)(3)(A), (B) or (C) of the Code and the United States Treasury Regulations thereunder, or to certain other persons described in Section 1.163-5(c)(2)(i)(D)(1)(iii)(B) of the United States Treasury Regulations. Moreover, such Bearer Debt Securities will not be delivered in connection with their sale during the restricted period within the United States. Any underwriters and dealers participating in the offering of Bearer Debt Securities must covenant that they will not offer or sell during the restricted period any Bearer Debt Securities within the United States or to United States persons (other than the persons described above) or deliver in connection with the sale of Bearer Debt Securities during the restricted period any Bearer Debt Securities within the United States and that they have in effect procedures reasonably designed to ensure that their employees and agents who are directly engaged in selling the Bearer Debt Securities are aware of the restrictions described above. No Bearer Debt Security (other than a temporary global Bearer Debt Security) will be delivered in connection with its original issuance nor will interest be paid on any Bearer Debt Security until receipt by the Company of the written certification described above under "--Form, Exchange, Registration, Conversion, Transfer and Payment." Each Bearer Debt Security, other than a temporary global Bearer Debt Security, will bear a legend to the following effect: "Any United States person who holds this obligation will be subject to limitations under the United States federal income tax laws, including the limitations provided in Sections 165(j) and 1287(a) of the Internal Revenue Code." As used herein, "United States person" means any citizen or resident of the United States, any corporation, partnership or other entity created or organized in or under the laws of the United States and any estate or trust the income of which is subject to United States federal income taxation regardless of its source, and "United States" means the United States of America (including the states and the District of Columbia) and its possessions. EVENTS OF DEFAULT The following will be Events of Default under the Indenture with respect to Debt Securities of any series: (a) failure to pay principal (or premium, if any) on any Debt Security of that series when due; (b) failure to pay any interest on any Debt Security of that series when due, which failure continues for 30 days; (c) failure to perform any other covenant of the Company in the applicable Indenture or any other covenant to which the Company may be subject with respect to Debt Securities of that series (other than a covenant solely for the benefit of a series of Debt Securities other than that series), which failure continues for 90 days after written notice as provided in the applicable Indenture; and (d) certain events of bankruptcy, insolvency or reorganization. If an Event of Default with respect to Outstanding Debt Securities of any series shall occur and be continuing, either the Trustee or the Holders of at least 25% in principal amount of the Outstanding Debt Securities of that series, by notice as provided in the applicable Indenture, may declare the principal amount (or, if the Debt Securities of that series are Original Issue Discount Securities, such portion of the principal amount as may be specified in the terms of that series) of all Debt Securities of that series to be due and payable immediately, except that upon the occurrence of an Event of Default specified in (d) above, the principal amount (or in the case of Original Issue Discount Securities, such portion) of all Debt Securities shall be immediately due and payable without any action by the Trustee or any Holder. At any time after a declaration of acceleration with respect to Debt Securities of any series has been made, but before judgment or decree based on such acceleration has been obtained, the Holders of a majority in principal amount of the Outstanding Debt Securities of that series may, under certain circumstances, rescind and annul such acceleration. For information as to waiver of defaults, see "Modification and Waiver" below. 18 The Indentures will provide that, subject to the duty of the respective Trustees thereunder during an Event of Default to act with the required standard of care, each such Trustee will be under no obligation to exercise any of its rights or powers under the respective Indentures at the request or direction of any of the Holders, unless such Holders shall have offered to such Trustee reasonable security or indemnity. Subject to certain provisions, including those requiring security or indemnification of the applicable Trustee, the Holders of a majority in principal amount of the Outstanding Debt Securities of any series will have the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee, or exercising any trust or power conferred on such Trustee, with respect to the Debt Securities of that series. No Holder of a Debt Security of any series will have any right to institute any proceeding with respect to the applicable Indenture or for any remedy thereunder, unless such Holder shall have previously given to the applicable Trustee written notice of a continuing Event of Default and unless the Holders of at least 25% in aggregate principal amount of the Outstanding Debt Securities of the same series shall have written requests, and offered reasonable indemnity, to such Trustee to institute such a proceeding, and the Trustee shall not have received from the Holders of a majority in aggregate principal amount of the Outstanding Debt Securities of the same series a direction inconsistent with such request and shall have failed to institute such proceeding within 60 days. However, such limitations do not apply to a suit instituted by a Holder of a Debt Security for enforcement of payment of the principal of and interest on such Debt Security on or after the respective due dates expressed in such Debt Security. The Company is required to furnish to the Trustees annually a statement as to the performance by the Company of its obligations under the respective Indentures and as to any default in such performance. MODIFICATION AND WAIVER The Indenture provides that Supplemental Indentures may be entered into by the Company and the Trustee without the consent of any Holders of Debt Securities in certain limited circumstances, including (i) to cure any ambiguity, omission, defect or inconsistency, (ii) to provide for the assumption of the obligations of the Company under the Indenture upon the merger, consolidation or sale or other disposition of all or substantially all of the assets of the Company and its Subsidiaries taken as a whole and certain other events specified in the "Merger, Consolidation and Sale of Substantially All Assets" covenant, (iii) to provide for uncertificated Debt Securities in addition to or in place of certificated Debt Securities, (iv) to comply with any requirement of the Commission in order to effect or maintain the qualification of the Indenture under the Trust Indenture Act of 1939, as amended, (v) to make any change in the Debt Securities of any or all series that does not adversely affect the rights of any Holder of Debt Securities of the affected series in any material respect, (vi) to add Subsidiary guarantors pursuant to the procedures set forth in the Indentures, and (vii) certain other modifications and amendments as set forth in the Indenture. The Indenture contains provisions permitting the Company and the Trustee, with the written consent of the Holders of not less than a majority in aggregate principal amount of the Debt Securities, of any series then outstanding, to execute supplemental indentures or amendments adding any provisions to or changing or eliminating any of the provisions of the Indenture or modifying the rights of the Holders of the Debt Securities of such series, except that no such supplemental indenture, amendment or waiver may, without the consent of all the Holders of Debt Securities of such series then outstanding, among other things, (i) reduce the principal amount of Debt Securities of such series whose Holders must consent to an amendment or waiver, (ii) reduce the rate of or change the time of payment of interest on any Debt Securities, (iii) change the currency in which any amount due in respect of the Debt Securities is payable, (iv) reduce the principal of or any premium on or change the Stated Maturity of any Debt Securities or alter the redemption or repurchase provisions with respect thereto, (v) reduce the relative ranking of any Debt Securities, (vi) release any security that may have been granted in respect of the Debt Securities, (vii) impair the right of any Holder to institute suit for enforcement of any payment on or with respect to 19 such Holder's Debt Securities and (viii) make certain other significant amendments or modifications as specified in the Indenture. The Holders of at least a majority in principal amount of the Outstanding Debt Securities of any series may, on behalf of the Holders of all Debt Securities of that series, waive compliance by the Company with certain covenants of the applicable Indenture and any past default under the applicable Indenture with respect to that series, except a default in the payment of the principal of, premium, if any, or interest on, any Debt Security of that series or in respect of a provision which under the applicable Indenture cannot be modified or amended without the consent of the Holder of each Outstanding Debt Security of that series affected. CONSOLIDATION, MERGER AND SALE OF ASSETS The Company, without the consent of any Holders of any series of outstanding Debt Securities, may consolidate with or merge into, or transfer or lease its assets substantially as an entirety (treating the Company and each of its Subsidiaries as a single consolidated entity) to, any corporation, and any other corporation may consolidate with or merge into, or transfer or lease its assets substantially as an entirety to, the Company, provided that the corporation (if other than the Company) formed by such consolidation or into which the Company is merged or which acquires or leases the assets of the Company substantially as an entirety is organized and existing under the laws of the United States of America or any political subdivision thereof, and assumes the Company's obligations under each series of Outstanding Debt Securities and the Indentures applicable thereto and that the Trustee is satisfied that, after giving effect to such transaction, no Event of Default, and no event which, after notice or lapse of time or both, would become an Event of Default, shall have occurred and be continuing. DEFEASANCE If so indicated in the applicable Prospectus Supplement with respect to the Debt Securities of a series, the Company at its option (i) will be discharged from any and all obligations in respect of the Debt Securities of such series (except for certain obligations to register the transfer or exchange of Debt Securities of such series, to replace destroyed, stolen, lost or mutilated Debt Securities of such series, and to maintain an office or agency in respect of the Debt Securities and hold moneys for payment in trust) or (ii) will be released from its obligations to comply with certain covenants specified in the applicable Prospectus Supplement with respect to the Debt Securities of such series, and the occurrence of certain Events of Default as specified in the applicable Prospectus Supplement with respect to the Debt Securities of such series, shall no longer be Events of Default, if, in either case, the Company irrevocably deposits with the applicable Trustee, in trust, money, Government Obligations of the government issuing the currency in which the Debt Securities of the relevant series are denominated or a combination thereof that through the payment of interest thereon and principal thereof in accordance with the terms will provide money in an amount sufficient to pay all the principal of and premium, if any, and interest on the Securities of such series on the dates such payments are due (up to the Stated Maturity Date, or the Redemption Date, as the case may be) in accordance with the terms of such Debt Securities. Such a trust may only be established if, among other things, (a) 123 days pass after the deposit is made and during the 123-day period no Event of Default described in clause (d) under "Events of Default" shall have occurred and be continuing at the end of such period and (b) the Company shall have delivered an Opinion of Counsel to the effect that (i) the Holders of the Debt Securities will not recognize gain or loss for United States federal income tax purposes as a result of such deposit or defeasance and will be subject to United States federal income tax in the same manner as if such defeasance had not occurred, and (ii) the trust resulting from the deposit does not constitute, or is qualified as, a regulated investment company under the Investment Company Act of 1940. Such opinion, in the case of defeasance under clause (i) above, must refer to and be based upon a ruling of the Internal Revenue Service or a change in applicable federal income tax law occurring after the date of the applicable Indenture. In the event the Company fails to 20 comply with its remaining obligations under the applicable Indenture after a defeasance of such Indenture with respect to the Debt Securities of any series as described under clause (ii) above and the Debt Securities of such series are declared due and payable because of the occurrence of any undefeased Event of Default, the amount of money and Government Obligations on deposit with the applicable Trustee may be insufficient to pay amounts due on the Debt Securities of such series at the time of the acceleration resulting from such Event of Default. However, the Company will remain liable in respect to such payments. Notwithstanding the description set forth under "Subordination of Senior Subordinated Debt Securities and Subordinated Debt Securities" above, in the event that the Company deposits money or Government Obligations in compliance with the Indenture that governs any Senior Subordinated Debt Securities or Subordinated Debt Securities, as the case may be, in order to defease all or certain of its obligations with respect to the applicable series of Debt Securities, the money or Government Obligations so deposited will not be subject to the subordination provisions of the applicable Indenture and the indebtedness evidenced by such series of Debt Securities will not be subordinated in right of payment to the holders of applicable Senior Indebtedness to the extent of the money or Government Obligations so deposited. REGARDING THE TRUSTEES The Indentures contain certain limitations on the right of each Trustee, should it become a creditor of the Company, to obtain payment of claims in certain cases, or to realize for its own account on certain property received in respect of any such claim as security or otherwise. Each Trustee will be permitted to engage in certain other transactions; however, if it acquires any conflicting interest within the meaning of the Trust Indenture Act of 1939 and there is a default under the Debt Securities issued under the applicable Indenture, it must eliminate such conflict or resign. 21 DESCRIPTION OF PREFERRED STOCK The Company's Certificate of Incorporation currently authorizes the issuance of 10,000,000 shares of Preferred Stock, par value $.01 per share, issuable in series. The board of directors of the Company is authorized to approve the issuance of one or more series of Preferred Stock without further authorization of the stockholders of the Company and to fix the number of shares, the designations, the relative rights and preferences and the limitations of any such series. At the date of this Prospectus, no shares of preferred stock were issued and outstanding, and 500,000 shares of Series A Junior Participating Preferred Stock were reserved for issuance in connection with the Company's Stockholders' Rights Plan dated February 24, 1996 (the "Rights Plan"). See "Description of Common Stock--Stockholders' Rights Plan." The terms of the Company's currently authorized Series A Junior Participating Preferred Stock do not limit the issuance of other series of Preferred Stock ranking as to dividends and payments upon liquidation senior to, on a parity with or junior to such existing Preferred Stock. The applicable Prospectus Supplement will set forth the number of shares, particular designation, relative rights and preferences and the limitations of any series of Preferred Stock in respect of which this Prospectus is delivered. The particular terms of any such series will include the following: (i) The maximum number of shares to constitute the series and the designation thereof; (ii) The annual dividend rate, if any, on shares of the series, whether such rate is fixed or variable or both, the date or dates from which dividends will begin to accrue or accumulate, whether dividends will be cumulative and whether such dividends shall be paid in cash, Common Stock or otherwise; (iii) Whether the shares of the series will be redeemable and, if so, the price at and the terms and conditions on which the shares of the series may be redeemed, including the time during which shares of the series may be redeemed and any accumulated dividends thereon that the holders of shares of the series shall be entitled to receive upon the redemption thereof; (iv) The liquidation preference, if any, applicable to shares of the series; (v) Whether the shares of the series will be subject to operation of a retirement or sinking fund and, if so, the extent and manner in which any such fund shall be applied to the purchase or redemption of the shares of the series for retirement or for other corporate purposes, and the terms and provisions relating to the operation of such fund; (vi) The terms and conditions, if any, on which the shares of the series shall be convertible into, or exchangeable for, shares of any other class or classes of capital stock of the Company or another corporation or any series of any other class or classes, or of any other series of the same class, including the price or prices or the rate or rates of conversion or exchange and the method, if any, of adjusting the same; (vii) The voting rights, if any, of the shares of the series; (viii) The currency or units based on or relating to currencies in which such series is denominated and/ or in which payments will or may be payable; (ix) The methods by which amounts payable in respect of such series may be calculated and any commodities, currencies or indices, or price, rate or value, relevant to such calculation; (x) Any listing of the shares of the series on a securities exchange; and (xi) Any other preferences and relative, participating, optional or other rights or qualifications, limitations or restrictions thereof. 22 Any material United States federal income tax consequences and other special considerations to any offered Preferred Stock will be described in the Prospectus Supplement relating to the offering and sale of such Preferred Stock. TRANSFER AGENT AND REGISTRAR The transfer agent and registrar for each series of Preferred Stock will be designated in the related Prospectus Supplement. DESCRIPTION OF COMMON STOCK GENERAL The following is a description of certain general terms and provisions of the Common Stock. The summary of terms of the Company's Common Stock contained in this Prospectus does not purport to be complete and is subject to, and qualified in its entirety by, the provisions of the Company's Restated Certificate of Incorporation, Bylaws and Rights Plan, each of which has been incorporated by reference herein. The Company's Restated Certificate of Incorporation authorizes the issuance of 50,000,000 shares of Common Stock, $.01 par value. All issued and outstanding shares of Common Stock are validly issued, fully paid and nonassessable. The holders of Common Stock are entitled to one vote for each share held on all matters submitted to a vote of holders of Common Stock. The Common Stock does not have cumulative voting rights. Each share of Common Stock is entitled to participate equally in dividends, as and when declared by the Company's board of directors, and in the distribution of assets in the event of liquidation, subject in all cases to any prior rights of outstanding shares of the Company's preferred stock. The shares of Common Stock have no preemptive or conversion rights, redemption rights or sinking fund provisions. STOCKHOLDERS' RIGHTS PLAN On February 24, 1996, the Company's board of directors declared a dividend distribution of one Preferred Stock Purchase Right (a "Right") for each outstanding share of Common Stock. The description and terms of the Rights are set forth in the Rights Agreement which is incorporated herein by reference. The distribution was made as of March 6, 1996, to stockholders of record on that date. Each Right entitles the registered holder of Common Stock to purchase from the Company one one-hundredth (1/100) of a share of preferred stock, designated as Series A Junior Participating Preferred Stock, at a price of $18.75 per one one-hundredth (1/100) of a share, subject to adjustments. The Rights will expire at the close of business on March 6, 2006, unless the expiration date is extended or unless the Rights are earlier redeemed or exchanged by the Company as described in the Rights Agreement. Initially, the Rights will not be exercisable or represented by a separate certificate but will trade together with the Common Stock. The Rights, unless redeemed prior thereto, become exercisable only upon the close of business on the day which is the earlier of (a) the tenth day after a public announcement that a person or group of affiliated or associated persons, with certain exceptions as noted in the Rights Agreement, has acquired beneficial ownership of 15% or more of the Company's outstanding Common Stock (an "Acquiring Person") or (b) the tenth business day (or such later date as may be determined by the Company's board of directors prior to such time as any person or group of affiliated persons becomes an Acquiring Person) after the commencement or announcement of an intention to commence a tender or exchange offer, the consummation of which would result in the ownership of 15% or more of the Company's outstanding Common Stock. All issuances of Common Stock after the date of the Rights Agreement will include Rights. 23 TRANSFER AGENT AND REGISTRAR The co-transfer agents and co-registrars for the Common Stock are Corporate Stock Transfer, Inc., and First Interstate Bank of California. LISTING The Company's Common Stock is quoted on the Nasdaq National Market under the symbol BSNX. 24 DESCRIPTION OF WARRANTS GENERAL The Company may issue Warrants to purchase shares of Common Stock, shares of Preferred Stock or Debt Securities. Warrants may be issued, subject to regulatory approvals, independently or together with any Common Stock, Preferred Stock or Debt Securities, as the case may be, and may be attached to or separate from such Common Stock, Preferred Stock or Debt Securities. Each series of Warrants will be issued under a separate warrant agreement (each a "Warrant Agreement") to be entered into between the Company and a warrant agent (the "Warrant Agent"). The Warrant Agent will act solely as an agent of the Company in connection with the Warrants of such series and will not assume any obligation or relationship of agency or trust for or with any holders or beneficial owners of Warrants. The applicable Prospectus Supplement will describe the following terms of any Warrants in respect of which this Prospectus is delivered: (i) the title of such Warrants; (ii) a description of the securities (which may include shares of Common Stock, shares of Preferred Stock or Debt Securities) for which such Warrants are exercisable; (iii) the price or prices at which such Warrants will be issued; (iv) the periods during which the Warrants are exercisable; (v) the number of shares of Common Stock or Preferred Stock or the amount of Debt Securities for which each Warrant is exercisable; (vi) the exercise price for such Warrants, including any changes to or adjustments in the exercise price; (vii) the currency or currencies, including composite currencies, in which the exercise price of such Warrants may be payable; (viii) if applicable, the designation and terms of the shares of Preferred Stock with which such Warrants are issued; (ix) if applicable, the terms of the Debt Securities with which such Warrants are issued; (x) if applicable, the number of Warrants issued with each share of Common Stock or Preferred Stock or Debt Security; (xi) if applicable, the date on and after which such Warrants and the related shares of Common Stock or Preferred Stock or Debt Securities will be separately transferable; (xii) if applicable, a discussion of certain United States federal income tax considerations; (xiii) any listing of the Warrants on a securities exchange; and (xiv) any other terms of such Warrants, including terms, procedures and limitations relating to the exchange and exercise of such Warrants. SELLING STOCKHOLDER Common Stock owned by Michael S. Smith, Chairman of the Board, President and Chief Executive Officer, may be offered for Mr. Smith's account pursuant to this Prospectus. The following table sets forth information as of September 22, 1997 regarding the Common Stock owned by Mr. Smith, which may be offered hereunder.
SHARES BENEFICIALLY SHARES BENEFICIALLY OWNED PRIOR TO THE OFFERING OWNED AFTER THE OFFERING ----------------------- NUMBER OF SHARES TO BE ------------------------ SELLING STOCKHOLDER NUMBER PERCENT SOLD IN THE OFFERING NUMBER PERCENT - ------------------------------------------ ---------- ----------- -------------------------- ----------- ----------- Michael S. Smith.......................... 3,248,150(1) 30.13 Not to exceed 300,000* * *
- ------------------------ * To be included in a Prospectus Supplement (1) Includes 2,675,150 shares held by Mr. Smith; 304,300 shares held by Iris Smith, Mr. Smith's wife; 96,000 shares held by trusts for Mr. Smith's children, of which Mr. Smith is trustee; and 92,700 shares held by KaiTar Foundation, a nonprofit charitable foundation of which Mrs. Smith is president and Mr. Smith is vice-president. Mr. Smith has no voting or investment power with respect to the shares held by Iris Smith and disclaims beneficial ownership of such shares. Mr. Smith, in his capacity as the trustee of the trusts for his children and as vice president of KaiTar Foundation, has voting and investment power with respect to the shares held in such capacity and may be deemed to be the beneficial owner of such shares but disclaims beneficial ownership of such shares. Also includes options for 60,000 shares exercisable within 60 days and 20,000 performance shares, the restrictions on which lapse December 31, 1999. 25 PLAN OF DISTRIBUTION The Company may offer and sell the Debt Securities, Preferred Stock, Common Stock and Warrants to or through underwriters or dealers, and also may offer and sell Debt Securities, Preferred Stock, Common Stock and Warrants directly to other purchasers or through agents. The distribution of the Securities may be affected from time to time in one or more transactions at a fixed price or prices, which may be changed, at market prices prevailing at the time of sale, at prices related to such market prices or at negotiated prices. Each Prospectus Supplement will set forth the terms of the offering of the particular series of Securities to which the Prospectus Supplement relates, including the name or names of any underwriters, dealers or agents, the purchase price or prices of the Securities, the proceeds to the Company or the selling stockholder, if applicable, from the sale of such series of Securities, the use of such proceeds, any initial public offering price or purchase price of such series of Securities, any underwriting discount or commission, any discounts, concessions or commissions allowed or reallowed or paid by any underwriters to other dealers, any commissions paid to any agents, and the securities exchanges, if any, on which such Securities will be listed. Any initial public offering price or purchase price and any discounts, concessions or commissions allowed or reallowed or paid by any underwriter to other dealers may be changed from time to time. In connection with distributions of Common Stock or otherwise, the Company may enter into hedging transactions with broker-dealers in connection with which such broker-dealers may sell Common Stock registered hereunder in the course of hedging through short sales the positions they assumed with the Company. In connection with the sale of the Securities, underwriters or agents may receive compensation from the Company, the selling stockholder, if applicable, or from purchasers of Securities for whom they may act as agents in the form of discounts, concessions or commissions. Underwriters may sell Securities to or through dealers, and such dealers may receive compensation in the form of discounts, concessions or commissions from the underwriters and/or commissions from the purchasers for whom they may act as agents. Underwriters, dealers and agents that participate in the distribution of Securities may be deemed to be underwriters, and any discounts or commissions received by them from the Company and any profit on the resale of Securities by them may be deemed to be underwriting discounts and commissions under the Securities Act. Any such underwriter or agent will be identified, and any such compensation received from the Company will be described, in the applicable Prospectus Supplement. The sale of all or a portion of the shares of Common Stock offered hereby by the Selling Stockholder may be effected from time to time on any exchange on which the Common Stock is then listed at prevailing prices at the time of such sale, at prices related to such prevailing prices or at negotiated prices. The Selling Stockholder may sell all or a portion of the shares offered hereby in private transactions or in the over-the-counter market at prices related to the prevailing prices of the shares on the Nasdaq National Market. Under agreements which may be entered into by the Company, underwriters and agents who participate in the distribution of Securities may be entitled to indemnification by the Company or the selling stockholder against certain liabilities, including liabilities under U.S. securities legislation. The Company may grant underwriters who participate in the distribution of Securities an option to purchase additional Securities to cover over-allotments, if any. Certain underwriters and selling group members (if any) who are qualifying registered market makers on the Nasdaq National Market may engage in passive market making transactions in the Common Stock on the Nasdaq National Market in accordance with Rule 10b-6A under the Securities Exchange Act of 1934, as amended, during the two business day period before commencement of offers or sales of the Common Stock. 26 The place and date of delivery for the Securities in respect of which this Prospectus is being delivered will be set forth in the applicable Prospectus Supplement. If so indicated in the applicable Prospectus Supplement, the Company will authorize underwriters or agents to solicit offers by certain institutions to purchase Securities from the Company pursuant to delayed delivery contracts providing for payment and delivery at a future date. Institutions with which such contracts may be made include commercial and savings banks, insurance companies, pension funds, investment companies, educational and charitable institutions and others, but in all cases such institutions must be approved by the Company. Unless otherwise set forth in the applicable Prospectus Supplement, the obligations of any purchaser under any such contract will not be subject to any conditions except that (i) the purchase of the Securities shall not at the time of delivery be prohibited under the laws of the jurisdiction to which such purchaser is subject, and (ii) if the Securities are also being sold to underwriters acting as principals for their own account, the underwriters shall have purchased such Securities not sold for delayed delivery. The underwriters and such other persons will not have any responsibility in respect of the validity or performance of such contracts. Unless otherwise indicated in the applicable Prospectus Supplement, the Securities in respect of which this Prospectus is being delivered (other than Common Stock) will be a new issue of securities, will not have an established trading market when issued and will not be listed on any securities exchange. Any underwriters or agents to or through whom such Securities are sold by the Company for public offering and sale may make a market in such Securities, but such underwriters or agents will not be obligated to do so and may discontinue any market making at any time without notice. No assurance can be given as to the liquidity of the trading market for any such Securities. Certain of the underwriters and their affiliates may from time to time perform various commercial banking and investment banking services for the Company, for which customary compensation is received. EXPERTS The consolidated financial statements of the Company, included in its Annual Report on Form 10-K for the year ended December 31, 1996, incorporated by reference in this Prospectus and elsewhere in the Registration Statement have been audited by Arthur Andersen LLP, independent public accountants, as indicated in their report with respect thereto, and are incorporated herein in reliance upon the authority of said firm as experts in giving said report. Future financial statements of the Company and the reports thereon of Arthur Andersen LLP, or any successor independent accounting firm that has audited the Company's financial statements, also will be incorporated by reference in this Prospectus and elsewhere in the Registration Statement in reliance upon the authority of such firm as experts in giving those reports to the extent said firm has audited those financial statements and consented to the use of their reports thereon. Estimates of historical onshore oil and natural gas reserves of the Company as of December 31, 1994, 1995 and 1996, incorporated by reference herein are based upon engineering studies prepared by the Company and audited by the independent engineering firm of Netherland, Sewell & Associates, Inc. Estimates of historical offshore reserves of the Company as of December 31, 1996, incorporated by reference herein are based upon engineering studies prepared by the independent engineering firm of Ryder Scott Company Petroleum Engineers. Such estimates are incorporated by reference herein (to the extent covered by consents filed with the Commission) in reliance upon the authority of such firms as experts in such matters. LEGAL MATTERS Certain legal matters relating to the validity of the Securities will be passed upon for the Company by Davis, Graham & Stubbs LLP, Denver, Colorado. Certain legal matters will be passed upon for the underwriters, if any, by the counsel named in the applicable Prospectus Supplement. 27 GLOSSARY The terms defined in this section are used throughout this Prospectus. 2-D SEISMIC DATA. Seismic data that are acquired and processed to yield a two-dimensional cross section of the subsurface. 3-D SEISMIC DATA. Seismic data that are acquired and processed to yield a three-dimensional picture of the subsurface. BCF. Billion cubic feet (of gas). BCFE. Billion cubic feet (of gas) equivalent. EXPLOITATION. The conduct of a drilling or recompletion operation intended to recover reserves from a formation known to be productive in the area or on trend with existing production but not classifiable as proved. EXPLORATORY WELL. A well drilled to find and produce oil or 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. GROSS ACRES. An acre in which a working interest is owned. MMBBL. One million barrels of crude oil or other liquid hydrocarbons. NET ACRES. The sum of the fractional working interests owned in gross acres. PRODUCTIVE WELL. A well that is producing oil or gas or that is capable of production. 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. UNDEVELOPED ACREAGE. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether such acreage contains proved reserves. WORKING INTEREST. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and to share in the production. 28 - ------------------------------------------------ ------------------------------------------------ - ------------------------------------------------ ------------------------------------------------ No dealer, salesperson or other person is authorized to give any information or to represent anything not contained in this prospectus. You must not rely on any unauthorized information or representations. This prospectus is an offer to sell only the shares offered hereby, but only under circumstances and in jurisdictions where it is lawful to do so. The information contained in this prospectus is current only as of its date. -------------------------- TABLE OF CONTENTS Prospectus Supplement
Page --------- Summary........................................ S-3 Risk Factors................................... S-11 Use of Proceeds................................ S-19 Capitalization................................. S-20 Price Range of Common Stock and Dividend Policy....................................... S-21 Selected Historical Financial Information...... S-22 Management's Discussion and Analysis of Financial Condition and Results of Operations................................... S-24 Business and Properties........................ S-39 Management..................................... S-54 Selling Stockholder............................ S-57 Experts........................................ S-57 Validity of Common Stock....................... S-57 Index to Financial Statements.................. F-i Underwriting................................... U-1 Prospectus Available Information.......................... 2 Incorporation of Certain Documents by Reference.................................... 2 Special Note Regarding Forward-Looking Statements................................... 3 Risk Factors................................... 4 The Company.................................... 9 Use of Proceeds................................ 11 Ratio of Earnings to Fixed Charges............. 11 Description of Debt Securities................. 11 Description of Preferred Stock................. 22 Description of Common Stock.................... 23 Description of Warrants........................ 25 Selling Stockholder............................ 25 Plan of Distribution........................... 26 Experts........................................ 27 Legal Matters.................................. 27 Glossary....................................... 28
4,000,000 Shares BASIN EXPLORATION, INC. Common Stock ---------------- [LOGO] -------------------------- GOLDMAN, SACHS & CO. BANC OF AMERICA SECURITIES LLC DAIN RAUSCHER WESSELS A DIVISION OF DAIN RAUSCHER INCORPORATED PETRIE PARKMAN & CO. Representatives of the Underwriters - ------------------------------------------------ ------------------------------------------------ - ------------------------------------------------ ------------------------------------------------ -----END PRIVACY-ENHANCED MESSAGE-----