-----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, UZ6B9K4+eVJHiViQFdv/QhxkzB+FVqOsBXw+Ccfj3C85IGd8k1I5vI/CW5R2IsnB +ladmzE9sNaecxchFWQnSQ== 0000950134-98-001465.txt : 19980224 0000950134-98-001465.hdr.sgml : 19980224 ACCESSION NUMBER: 0000950134-98-001465 CONFORMED SUBMISSION TYPE: 424B1 PUBLIC DOCUMENT COUNT: 1 FILED AS OF DATE: 19980223 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: DENBURY RESOURCES INC CENTRAL INDEX KEY: 0000945764 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 000000000 FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B1 SEC ACT: SEC FILE NUMBER: 333-43207 FILM NUMBER: 98547286 BUSINESS ADDRESS: STREET 1: 17304 PRESTON RD STREET 2: STE 200 CITY: DALLAS STATE: TX ZIP: 75252 BUSINESS PHONE: 2147133000 MAIL ADDRESS: STREET 1: 17304 PRESTON RD STREET 2: STE 200 CITY: DALLAS STATE: TX ZIP: 75252 FORMER COMPANY: FORMER CONFORMED NAME: NEWSCOPE RESOURCES LTD DATE OF NAME CHANGE: 19950627 FILER: COMPANY DATA: COMPANY CONFORMED NAME: DENBURY MANAGEMENT INC CENTRAL INDEX KEY: 0001053339 STANDARD INDUSTRIAL CLASSIFICATION: [] IRS NUMBER: 752294373 STATE OF INCORPORATION: TX FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B1 SEC ACT: SEC FILE NUMBER: 333-43207-01 FILM NUMBER: 98547287 BUSINESS ADDRESS: STREET 1: 17304 PRESTON RD STREET 2: STE 200 CITY: DALLAS STATE: TX ZIP: 75252 BUSINESS PHONE: 9727133000 MAIL ADDRESS: STREET 1: 17304 PRESTON RD STREET 2: STE 200 CITY: DALLAS STATE: TX ZIP: 75252 424B1 1 PROSPECTUS SUPPLEMENT 1 Filed Pursuant to Rule 424(b)(1) Registration Number 333-43207 PROSPECTUS 4,557,200 Shares DRI LOGO Denbury Resources Inc. COMMON SHARES ------------------------ All of the Common Shares offered hereby are being sold by Denbury Resources Inc. The Common Shares are listed on the New York Stock Exchange and on The Toronto Stock Exchange under the symbol "DNR." On February 19, 1998, the reported last sale price of the Common Shares on the New York Stock Exchange and The Toronto Stock Exchange was US$17.25 per share and C$24.25 per share, respectively. Concurrently with the closing of this offering of Common Shares (the "Equity Offering"), entities affiliated with the Texas Pacific Group ("TPG"), the Company's largest shareholder, will purchase from the Company 313,400 Common Shares (the "TPG Purchase") at $15.955 per share (equal to the price to public per share set forth below less underwriting discounts and commissions). The closing of the Equity Offering and the TPG Purchase are each conditioned upon the closing of the other. Concurrently with the Equity Offering, Denbury Management, Inc.("DMI"), a wholly owned subsidiary of the Company, is offering $125 million in aggregate principal amount of 9% Senior Subordinated Notes Due 2008 (the "Debt Offering" and, together with the Equity Offering, the "Offerings"). The closing of the Equity Offering is not conditioned upon the closing of the Debt Offering. The Common Shares offered hereby are also being offered for sale in Canada. ------------------------ SEE "RISK FACTORS" BEGINNING ON PAGE 12 FOR INFORMATION THAT SHOULD BE CONSIDERED BY PROSPECTIVE INVESTORS. ------------------------ 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. ------------------------ PRICE $16 3/4 A SHARE ------------------------
UNDERWRITING PRICE TO DISCOUNTS AND PROCEEDS TO PUBLIC COMMISSIONS(1) COMPANY(2) -------- -------------- ----------- Per Share.................... $16.75 $.795 $15.955 Total(3)..................... $76,333,100 $3,622,974 $72,710,126
- ------------ (1) The Company has agreed to indemnify the Underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended. See "Underwriters." (2) Before deducting expenses, estimated at $600,000. (3) The Company has granted to the Underwriters an option, exercisable within 30 days of the date hereof, to purchase up to an aggregate of 683,580 additional Common Shares at the price to public less underwriting discounts and commissions, for the purpose of covering over-allotments, if any. If the Underwriters exercise such option in full, the total price to public, underwriting discounts and commissions and proceeds to the Company will be $87,783,065, $4,166,420 and $83,616,645, respectively. See "Underwriters." ------------------------ The Common Shares are offered, subject to prior sale, when, as and if accepted by the Underwriters named herein and subject to approval of certain legal matters by Cravath, Swaine & Moore, counsel for the Underwriters. It is expected that delivery of the Common Shares will be made on or about February 26, 1998 at the office of Morgan Stanley & Co. Incorporated, New York, N.Y., against payment therefor in immediately available funds. ------------------------ MORGAN STANLEY DEAN WITTER GORDON CAPITAL, INC. JOHNSON RICE & COMPANY L.L.C. LOEWEN, ONDAATJE, MCCUTCHEON USA LIMITED February 19, 1998 2 CORE OPERATING AREAS This page will contain a map of the Gulf Coast Region depicting the geographical location of the Company's eight largest fields. --------------------- CERTAIN PERSONS PARTICIPATING IN THIS OFFERING MAY ENGAGE IN TRANSACTIONS THAT STABILIZE, MAINTAIN OR OTHERWISE AFFECT THE PRICE OF THE COMMON SHARES. SPECIFICALLY, THE UNDERWRITERS MAY OVER-ALLOT IN CONNECTION WITH THIS OFFERING AND MAY BID FOR AND PURCHASE THE COMMON SHARES IN THE OPEN MARKET. FOR A DESCRIPTION OF THESE ACTIVITIES, SEE "UNDERWRITERS." IN CONNECTION WITH THIS OFFERING, CERTAIN UNDERWRITERS AND SELLING GROUP MEMBERS MAY ENGAGE IN PASSIVE MARKET MAKING TRANSACTIONS IN THE COMMON SHARES ON THE NEW YORK STOCK EXCHANGE AND THE TORONTO STOCK EXCHANGE IN ACCORDANCE WITH REGULATION M OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED. SEE "UNDERWRITERS." 2 3 IT IS EXPECTED THAT DELIVERY OF THE COMMON SHARES WILL BE MADE AGAINST PAYMENT THEREFOR ON OR ABOUT THE DATE SPECIFIED IN THE LAST PARAGRAPH OF THE COVER PAGE OF THIS PROSPECTUS, WHICH IS THE FIFTH BUSINESS DAY FOLLOWING THE DATE HEREOF (SUCH SETTLEMENT CYCLE BEING HEREIN REFERRED TO AS "T+5"). PURCHASERS OF COMMON SHARES SHOULD NOTE THAT TRADING OF THE COMMON SHARES ON THE DATE HEREOF OR THE DAY THEREAFTER MAY BE AFFECTED BY THE T+5 SETTLEMENT. SEE "UNDERWRITING." NO DEALER, SALESMAN, OR OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY REPRESENTATIONS OTHER THAN THOSE CONTAINED IN THIS PROSPECTUS AND, IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE COMPANY OR ANY OF THE UNDERWRITERS. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR A SOLICITATION OF AN OFFER TO BUY ANY OF THE SECURITIES OFFERED BY THIS PROSPECTUS BY ANYONE IN ANY JURISDICTION IN WHICH SUCH OFFER OR SOLICITATION IS NOT AUTHORIZED, OR IN WHICH THE PERSON MAKING THE OFFER OR SOLICITATION IS NOT QUALIFIED TO DO SO OR TO ANY PERSON TO WHOM IT IS UNLAWFUL TO MAKE SUCH OFFER OR SOLICITATION. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY DISTRIBUTION OF SECURITIES MADE HEREUNDER OR THEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE AN IMPLICATION THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE THE DATE HEREOF OR THEREOF OR THAT THE INFORMATION CONTAINED IN THIS PROSPECTUS IS CORRECT AS OF ANY TIME SUBSEQUENT TO THE DATE HEREOF. --------------------- TABLE OF CONTENTS
PAGE ---- Information Incorporated by Reference........................... 3 Prospectus Summary.................... 5 Risk Factors.......................... 12 Forward-Looking Statements............ 18 Debt Offering......................... 18 Use of Proceeds....................... 18 Price Range of Common Shares.......... 19 Dividend Policy....................... 19 Capitalization........................ 20 Unaudited Pro Forma Consolidated Financial Information............... 21 Selected Consolidated Financial Data................................ 26 Management's Discussion and Analysis of Financial Condition and Results of Operations....................... 27 Business and Properties............... 36 Management............................ 52
PAGE ---- Principal Shareholders................ 55 Interests of Management in Certain Transactions........................ 57 Description of Capital Stock.......... 58 Description of Certain Indebtedness... 59 Canadian Taxation and the Investment Canada Act.......................... 61 Service and Enforcement of Legal Process............................. 62 Shares Eligible for Future Sale....... 62 Underwriters.......................... 64 Legal Matters......................... 65 Experts............................... 66 Available Information................. 66 Glossary.............................. 67 Index to Consolidated Financial Statements.......................... F-1 Summary Reserve Report................ A-1
INFORMATION INCORPORATED BY REFERENCE The following documents of the Company which have been previously filed with the Securities and Exchange Commission (the "Commission") are incorporated in this Prospectus: (i) Annual Report on Form 10-K for the year ended December 31, 1996; (ii) Quarterly Reports on Form 10-Q for the quarters ended March 31, 1997, June 30, 1997 and September 30, 1997; (iii) proxy statement dated May 21, 1997; (iv) reports on Form 8-K dated September 12, 1997, December 8, 1997, December 16, 1997, and January 20, 1998. All documents filed by the Company pursuant to Section 13(a), 13(c), 14 and 15(d) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), subsequent to the date of this Prospectus and prior to the termination of the offering of securities to be made hereunder shall be deemed to be incorporated herein by reference and made a part hereof from the date of filing of such documents. 3 4 Any statement contained herein or in a document incorporated or deemed to be incorporated by reference herein shall be deemed to be modified or superseded for purposes of this Prospectus to the extent that a statement contained herein, therein or in any other subsequently filed document that also is or is deemed to be incorporated by reference herein 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. Any person receiving a copy of this Prospectus may obtain from the Company without charge a copy of any and all documents or part thereof incorporated herein by reference (other than exhibits and schedules to such documents unless such exhibits or schedules are specifically incorporated by reference into the information the Prospectus incorporates), upon written or oral request. Requests should be directed to Phil Rykhoek, Chief Financial Officer and Corporate Secretary, Denbury Resources Inc., 17304 Preston Road, Suite 200, Dallas, Texas, 75252, telephone: (972) 673-2000. 4 5 PROSPECTUS SUMMARY The following summary is qualified in its entirety by reference to, and should be read in conjunction with, the more detailed information and Consolidated Financial Statements included elsewhere in this Prospectus. All dollar amounts in this Prospectus, unless otherwise indicated, are expressed in United States dollars and all financial data is presented in accordance with Canadian generally accepted accounting principles. The December 31, 1997 estimated proved reserve data included throughout this Prospectus have been prepared by Netherland, Sewell & Associates, Inc. ("Netherland & Sewell"), independent petroleum engineers. Unless the context otherwise requires, the terms "Denbury" and the "Company" refer to Denbury Resources Inc., a Canadian corporation, and its wholly owned subsidiaries, the term "DRI" refers to Denbury Resources Inc. only, the term "DMI" refers to the wholly owned subsidiary of DRI, Denbury Management, Inc., a Texas corporation. The term "Transactions" refers collectively to (i) the Chevron Acquisition (as defined herein) and (ii) the Offerings and the TPG Purchase and the application of the estimated net proceeds therefrom. Certain information contained in this summary and elsewhere in this Prospectus, including information with respect to the Company's plans and strategy for its business, are forward-looking statements. Prospective investors should carefully consider the information set forth under "Risk Factors" for a discussion of important factors that could cause actual results to differ materially from the forward-looking statements contained in this Prospectus. Certain oil and gas industry terms used herein are defined in the Glossary included elsewhere in this Prospectus. Unless otherwise indicated herein, the information contained in this Prospectus assumes that the Underwriters' over-allotment option will not be exercised. THE COMPANY OVERVIEW Denbury is an independent energy company engaged in acquisition, development and exploration activities in the U.S. Gulf Coast region, primarily onshore in Louisiana and Mississippi. The Company believes the Gulf Coast represents one of the most attractive regions in North America given the region's prolific production history, complex geology (with multiple producing horizons) and the opportunities that have been created by advanced technologies such as 3-D seismic and various drilling, completion and recovery techniques. As of December 31, 1997, the Company had proved reserves of 52.0 MMBbls and 77.2 Bcf or 64.9 MMBOE, including 27.6 MMBOE attributable to the Chevron Acquisition. At such date, the PV10 Value of these reserves was $361.3 million, of which $276.5 million was attributable to proved developed reserves. Denbury operates wells comprising approximately 83% of its PV10 Value. The eight largest fields in which the Company has an interest constitute approximately 82% of its estimated proved reserves and, within these eight fields, Denbury owns an average working interest of 91%. Over the last four years, the Company has achieved rapid growth in proved reserves, production and cash flow by concentrating on the acquisition of properties which it believes have significant upside potential and through the efficient development, enhancement and operation of its properties. For the four-year period ended December 31, 1997, the Company increased its proved reserves at a compound annual growth rate of 83%, from 5.8 MMBOE to 64.9 MMBOE. Over the four-year period ended December 31, 1996, the Company also increased its average net daily production at a compound annual growth rate of 90%, from 1,193 BOE/d to 8,167 BOE/d, with a further increase to 14,195 BOE/d for the third quarter of 1997. For the same four-year period, EBITDA increased at a compound annual growth rate of 126%, from $3.0 million to $34.9 million. EBITDA for the twelve months ended September 30, 1997 was $51.9 million. Since 1993, when the Company began to focus its operations exclusively in the United States, through December 31, 1995, the Company spent a total of $43.4 million on acquisitions. In May 1996, the Company acquired properties in its core areas of Mississippi and Louisiana from Amerada Hess Corporation ("Amerada Hess") for approximately $37.2 million (the "Hess Acquisition"). As of June 30, 1996, these acquired properties were producing approximately 2,945 BOE/d and had proved reserves of approximately 5.9 MMBOE. Since that date, the Company's extensive development and exploitation on these properties has resulted in an 82% increase in their production to 5,373 BOE/d for the third quarter of 1997 and a 141% increase in their proved reserves to 14.2 MMBOE as of December 31, 1997. 5 6 On December 30, 1997, the Company acquired oil properties in the Heidelberg Field, which is adjacent to the Company's other primary oil properties in Mississippi, from Chevron U.S.A. Inc. ("Chevron") for approximately $202.0 million (the "Chevron Acquisition"). These properties are located approximately nine miles from the Eucutta Field, the property with the highest PV10 Value of those acquired by the Company in the Hess Acquisition. The estimated proved reserves as of December 31, 1997 for the Chevron Acquisition properties are approximately 27.6 MMBOE (43% of the Company's total proved reserves at December 31,1997), with average net daily production of approximately 2,940 BOE/d for the third quarter of 1997. As a result of the significant amount of future development and exploitation to be performed on these properties and the increase in future reserves and production that the Company expects to result from such development and exploitation, the Company has attributed approximately $75.0 million of the purchase price to unevaluated properties. The Company believes that the properties acquired in the Chevron Acquisition provide exploitation opportunities similar to those of the Mississippi properties acquired in the Hess Acquisition. The Company's estimated 1998 development budget for the Heidelberg Field is approximately $30.0 million. See "-- Acquisition of Chevron Properties." BUSINESS STRATEGY The Company seeks to: (i) achieve attractive returns on capital through prudent acquisitions, development and exploratory drilling and efficient operations; (ii) maintain a conservative balance sheet to preserve maximum financial and operational flexibility; and (iii) create strong employee incentives through equity ownership. The Company believes that its growth to date in proved reserves, production and cash flow is a direct result of its adherence to the following fundamental principles which are at the core of the Company's long-term growth strategy: REGIONAL FOCUS. The Company intends to continue the regional focus of its operations. By focusing its efforts in the Gulf Coast region, primarily Louisiana and Mississippi, the Company has been able to accumulate substantial geological and reservoir data and operating experience which it believes provides it with significant competitive advantages. For example, the Company believes it is better able to identify, evaluate and negotiate potential acquisitions, and develop and operate its properties in an efficient and low- cost manner. The Company believes the Gulf Coast represents one of the most attractive regions in North America given the region's prolific production history, complex geology (with multiple producing horizons) and the opportunities that have been created by advanced technologies such as 3-D seismic and various drilling, completion and recovery techniques. Moreover, because of the region's proximity to major pipeline networks serving important northeastern U.S. markets, the Company typically realizes natural gas prices in excess of those realized in many other producing regions. DISCIPLINED ACQUISITION STRATEGY. The Company intends to continue to acquire properties where it believes significant additional value can be created. Such properties are typically characterized by: (i) long production histories; (ii) complex geological formations with multiple producing horizons and substantial exploitation potential; (iii) a history of limited operational focus and capital investment, often due to their relatively small size and limited strategic importance to the previous owner; and (iv) the potential for the Company to gain control of operations. The Company believes that due to continuing rationalization of properties, primarily by major integrated and independent energy companies, future acquisition opportunities should continue to be available. In addition, the Company seeks to maintain a well-balanced portfolio of oil and natural gas development, exploitation and exploration projects in order to minimize the overall risk profile of its investment opportunities while still providing significant upside potential. The recent Hess and Chevron Acquisitions are examples of the types of opportunities the Company seeks. OPERATION OF HIGH WORKING INTEREST PROPERTIES. The Company intends to continue to acquire working interest positions that give it operational control or that the Company believes may lead to operational control. As the operator of properties comprising approximately 83% of its total PV10 Value, the Company believes it is better able to manage and monitor production and more effectively control expenses, the allocation of capital and the timing of field development. Once a property is acquired, the Company employs its technical and operational expertise to fully evaluate a field's future potential. If favorable, it will consolidate its working interest positions, primarily through negotiated transactions, which tend to be attractively priced compared to 6 7 acquisitions available in competitive situations. The consolidation of ownership allows the Company to: (i) enhance the effectiveness of its technical staff by concentrating on relatively few wells; (ii) increase production while adding virtually no additional personnel; and (iii) increase ownership in a property so that the potential benefits of value enhancement activities justify the allocation of Company resources. EXPLOITATION OF PROPERTIES. The Company intends to maximize the value of its properties through a combination of increasing production, increasing recoverable reserves or reducing operating costs. During 1997, the Company's primary methodology for achieving these objectives was the use of horizontal drilling, which it also intends to emphasize in 1998. Horizontal drilling has historically produced oil at faster rates and with lower operating costs on a BOE basis than traditional vertical drilling. The Company also utilizes a variety of other techniques to maximize property values, including: (i) undertaking surface improvements such as rationalizing, upgrading or redesigning production facilities; (ii) making downhole improvements such as resizing downhole pumps or reperforating existing production zones; (iii) reworking existing wells into new production zones with additional potential; and (iv) utilizing exploratory drilling, which is frequently based on various advanced technologies such as 3-D seismic. EXPERIENCED AND INCENTIVIZED PERSONNEL. The Company intends to maintain a highly competitive team of experienced and technically proficient employees and motivate them through a positive work environment and stock ownership in the Company. The Company's 29 geological and engineering professionals have an average of over 15 years of experience in the Gulf Coast region. The Company believes that employee ownership, which is encouraged through the Company's stock option and stock purchase plans, is essential for attracting, retaining and motivating quality personnel. As of January 1, 1998, approximately 86% of the Company's employees were participating in the Company's stock purchase plan. The Company believes that all employees are important to the success of the Company and as such grants bonuses and stock options to both management and employees on a basis roughly proportional to salaries. ACQUISITION OF CHEVRON PROPERTIES On December 30, 1997, the Company acquired oil properties in the Heidelberg Field, Jasper County, Mississippi, from Chevron for approximately $202.0 million. The Chevron Acquisition represents the largest acquisition by the Company to date. The Heidelberg Field is adjacent to the Company's other primary oil properties in Mississippi and includes 122 producing wells, 96 of which the Company will operate. The Company purchased an average working interest of 94% and an average net revenue interest of 81% in these 96 wells, which wells account for approximately 99% of the field's average net daily production. The average net daily production from these properties during the third quarter of 1997 was approximately 2,840 Bbls/d and 600 Mcf/d. The Chevron Acquisition added proved reserves as of December 31, 1997 of approximately 27.2 MMBbls and 2.5 Bcf, or approximately 27.6 MMBOE. As a result of the significant amount of future development and exploitation to be performed on these properties and the increase in future reserves and production that the Company expects to result from such development and exploitation, the Company has attributed approximately $75 million of the purchase price to unevaluated properties. The Company has identified several potential development projects during its initial evaluation of the Heidelberg Field. These include initiating a waterflood project, upgrading lift capacity in over 15 wells and recompleting 30 wells in new zones. In addition, the Company has identified over 40 potential drilling locations in addition to other potential secondary and tertiary recovery projects. Horizontal wells drilled by the Company in 1997 at nearby Davis, Quitman and Eucutta Fields improved daily production rates significantly as compared to vertical wells drilled in the same fields. Consequently, the Company anticipates that 30 of the 40 proposed future wells in the Heidelberg Field will be horizontal wells. The Company's total 1998 development budget for the Heidelberg Field is approximately $30.0 million. TPG PURCHASE In December 1995, the Texas Pacific Group initially invested in the Company through a $40.0 million private placement of securities followed by a $9.6 million purchase of Common Shares in October 1996. TPG 7 8 currently owns approximately 40% of the outstanding Common Shares. In connection with the Offerings, TPG is purchasing an additional 313,400 Common Shares (the "TPG Purchase"). See "Interests of Management in Certain Transactions." After giving effect to the Equity Offering and the TPG Purchase, TPG will own approximately 34% of the outstanding Common Shares. TPG was founded by David Bonderman, James G. Coulter and William S. Price III in 1993 to pursue private and public investment opportunities. The principals of TPG operate limited partnerships with committed capital of over $3.2 billion. TPG has several investments in its portfolio, including America West Airlines, Beringer Wine Estates, Belden & Blake Corporation, Continental Airlines, Del Monte Foods, Ducati Motor, Favorite Brands International, J. Crew Group Inc., Paradyne, St. Joe Communications and Virgin Cinemas. THE EQUITY OFFERING Common Shares offered by DRI................... 4,557,200 shares(a) Common Shares to be outstanding after the Equity Offering.......... 25,885,783 shares(b) Concurrent Debt Offering... Concurrently with the Equity Offering, DMI is offering $125.0 million aggregate principal amount of its 9% Senior Subordinated Notes Due 2008 by a separate prospectus. The closing of the Equity Offering is not conditioned on the closing of the Debt Offering. Use of Proceeds............ The net proceeds from the Equity Offering, together with the net proceeds from the Debt Offering and the TPG Purchase, will be used to reduce the Company's outstanding indebtedness under the Credit Facility incurred primarily in connection with the Chevron Acquisition. Following such repayment, the Company will continue to have borrowing availability under the Credit Facility to fund future acquisitions, development activities and working capital. See "Use of Proceeds." New York Stock Exchange and The Toronto Stock Exchange symbol.......... DNR - --------------- (a) Excludes 313,400 Common Shares to be purchased by TPG in the TPG Purchase. (b) Includes 21,015,183 Common Shares outstanding as of February 19, 1998 and 313,400 Common Shares to be purchased by TPG in the TPG Purchase. This total does not include 2,043,753 shares issuable pursuant to outstanding warrants and stock options, of which 466,372 were exercisable as of February 19, 1998. RISK FACTORS Prior to making an investment decision, prospective investors should consider carefully, together with other information contained in this Prospectus, the risk factors discussed under the caption "Risk Factors" herein. 8 9 SUMMARY HISTORICAL AND PRO FORMA CONSOLIDATED FINANCIAL DATA The summary historical consolidated financial data of the Company set forth below as of and for the years ended December 31, 1994, 1995 and 1996 have been derived from the audited consolidated financial statements of the Company. The summary historical consolidated financial data for the nine-month periods ended September 30, 1996 and 1997, and as of September 30, 1997, have been derived from unaudited consolidated financial statements of the Company which, in management's opinion include all adjustments (consisting of only normal recurring adjustments) necessary to present fairly the results for such periods. The operating results for such periods are not necessarily indicative of the operating results to be expected for a full fiscal year. The summary unaudited pro forma consolidated financial data for the Company set forth below have been derived from the Pro Forma Financial Statements (as defined herein) included elsewhere in this Prospectus. The summary historical and pro forma consolidated financial data are qualified in their entirety by, and should be read in conjunction with, "Unaudited Pro Forma Consolidated Financial Information," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Company's consolidated financial statements included elsewhere in this Prospectus (the "Consolidated Financial Statements").
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, -------------------------------------- ---------------------------- PRO PRO FORMA FORMA 1994 1995 1996 1996(a) 1996 1997 1997(a) ------- ------- ------- -------- ------- ------- -------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND RATIOS) INCOME STATEMENT DATA: Revenue: Oil, natural gas and related product sales............... $12,692 $20,032 $52,880 $ 76,542 $34,709 $60,083 $ 74,117 Interest income............... 23 77 769 769 425 986 986 ------- ------- ------- -------- ------- ------- -------- Total revenues........... 12,715 20,109 53,649 77,311 35,134 61,069 75,103 ------- ------- ------- -------- ------- ------- -------- Expenses: Production.................... 4,309 6,789 13,495 20,145 9,197 15,737 20,974 General and administrative.... 1,105 1,832 4,267 4,954 2,825 4,535 5,049 Interest...................... 1,146 2,085 1,993 13,809 1,530 387 9,193 Imputed preferred dividends... -- -- 1,281 1,281 1,153 -- -- Loss on early extinguishment of debt..................... -- 200 440 440 440 -- -- Depletion and depreciation.... 4,209 8,022 17,904 24,601 12,557 23,224 27,166 Franchise taxes............... 65 100 213 213 160 308 308 ------- ------- ------- -------- ------- ------- -------- Total expenses........... 10,834 19,028 39,593 65,443 27,862 44,191 62,690 ------- ------- ------- -------- ------- ------- -------- Income before income taxes...... 1,881 1,081 14,056 11,868 7,272 16,878 12,413 Provision for federal income taxes......................... (718) (367) (5,312) (4,502) (2,932) (6,245) (4,593) ------- ------- ------- -------- ------- ------- -------- Net income...................... $ 1,163 $ 714 $ 8,744 $ 7,366 $ 4,340 $10,633 $ 7,820 ======= ======= ======= ======== ======= ======= ======== Net income per common share Primary....................... $ 0.19 $ 0.10 $ 0.67 $ 0.41 $ 0.37 $ 0.53 $ 0.31 Fully diluted................. 0.19 0.10 0.62 0.40 0.36 0.50 0.31 Weighted average common shares outstanding................... 6,240 6,870 13,104 17,975 11,616 20,175 25,046 OTHER FINANCIAL DATA: Operating cash flow(b).......... $ 6,185 $ 9,394 $34,140 $ 38,649 $21,767 $40,166 $ 39,643 Capital expenditures............ 16,903 28,524 86,857 288,857 73,320 70,773 272,773 EBITDA(c)....................... 7,213 11,311 34,905 51,230 22,527 39,503 47,786 SELECTED RATIOS: Ratio of earnings to fixed charges(d).................... 2.6x 1.5x 4.4x 1.7x 3.1x 34.9x 2.3x Ratio of EBITDA to interest expense....................... 6.3 5.4 17.5 3.7 14.7 102.1 5.2 Ratio of long-term debt to EBITDA........................ 2.3 0.3 0.1 2.5 1.6(e) 0.4(e) 2.3(e)
9 10
AS OF SEPTEMBER 30, 1997 AS OF DECEMBER 31, ------------------- ---------------------------- PRO 1994 1995 1996 ACTUAL FORMA(a) ------- ------- -------- -------- -------- (IN THOUSANDS) BALANCE SHEET DATA: Working capital (deficit)......................... $(1,620) $ 6,862 $ 12,482 $ 2,899 $ 2,899 Total assets...................................... 48,964 77,641 166,505 210,424 415,634 Long-term debt, net of current maturities......... 16,536 3,474 125 20,005 148,105 Convertible preferred stock....................... -- 15,000 -- -- -- Shareholders' equity.............................. 25,962 53,501 142,504 155,558 232,668
- --------------- (a) Gives effect to the Transactions as if the Transactions had been consummated as of the beginning of the period presented. See "Unaudited Pro Forma Consolidated Financial Information." (b) Represents cash flow provided by operations, exclusive of the net change in non-cash working capital balances. (c) EBITDA represents earnings before interest income, interest expense, income taxes, depletion and depreciation, imputed preferred dividends and losses on early extinguishment of debt. The Company has included information concerning EBITDA because it believes that EBITDA is used by certain investors as one measure of an issuer's historical ability to service its debt. EBITDA is not a measurement determined in accordance with generally accepted accounting principles and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with generally accepted accounting principles. (d) For purposes of determining the ratio of earnings to fixed charges, earnings are defined as earnings from continuing operations before income taxes, plus fixed charges. Fixed charges consist of interest expense, amortization of debt expense, and imputed preferred stock dividends. (e) EBITDA used to calculate the ratio of long-term debt to EBITDA for these periods has been annualized. 10 11 SUMMARY OIL AND NATURAL GAS RESERVE DATA The following table summarizes the estimates of the Company's net proved oil and natural gas reserves as of the dates indicated and the present value attributable to the reserves at such dates. The proved reserve and present value data as of December 31, 1995, 1996 and 1997 have been prepared by Netherland & Sewell, independent petroleum engineers. A summary of the Netherland & Sewell report as of December 31, 1997 is included as Annex A to this Prospectus. See "Risk Factors -- Uncertainty of Estimates of Oil and Natural Gas Reserves," "Business and Properties -- Oil and Natural Gas Operations," and Note 11 to the Consolidated Financial Statements.
AS OF DECEMBER 31, ------------------------------- 1995 1996 1997 ------- -------- -------- PROVED RESERVES: Oil (MBbls)............................................... 6,292 15,052 52,018 Natural Gas (MMcf)........................................ 48,116 74,102 77,191 Oil Equivalent (MBOE)..................................... 14,311 27,403 64,883 Proved developed as a percent of total proved reserves.... 78% 84% 66% PRESENT VALUES: PV10 Value (before income taxes, in thousands)............ $96,965 $316,098(d) $361,329(e) Standardized measure of discounted estimated future net cash flow after net income taxes (in thousands)............................. 81,164 241,872 336,755 REPRESENTATIVE OIL AND GAS PRICES:(a) West Texas Intermediate (per Bbl)......................... $ 18.00 $ 23.39 $ 16.18 NYMEX Henry Hub (per MMBtu)............................... 2.24 3.90 2.58 OTHER RESERVE DATA: Reserve replacement percent(b)............................ 300% 500% 844% Reserve to production ratio (years)(c).................... 9.3 9.2 10.9(f)
- --------------- (a) The oil prices as of each respective year-end were based on West Texas Intermediate ("WTI") posted prices per barrel and NYMEX Henry Hub ("NYMEX") prices per MMBtu, with these representative prices adjusted by field to arrive at the appropriate corporate net price. (b) Equals current period reserve additions through acquisition of reserves, extensions and discoveries, and revisions of prior estimates divided by the production for such period. (c) Calculated by dividing year-end proved reserves by such year's annual production. (d) For comparative purposes, the Company also prepared a reserve report as of December 31, 1996 using a 1996 WTI price of $21.00 per Bbl and a NYMEX price of $2.40 per MMBtu, with these prices also adjusted by field. The PV10 Value in this report was $213.7 million with 27.0 MMBOE of proved reserves. For the nine months ended September 30, 1997, the average WTI price was approximately $18.90 per Bbl and the average NYMEX price was approximately $2.39 per MMBtu. (e) For comparative purposes, the Company also prepared a reserve report as of December 31, 1997 using the prices used in the December 31, 1996 reserve report. The PV10 Value in this report was $633.4 million with 67.8 MMBOE of proved reserves. Of this PV10 Value, $206.7 million was attributable to the Chevron Acquisition, as opposed to its PV10 Value of $109.4 million using December 31, 1997 prices. (f) Calculated by dividing year-end proved reserves by the pro forma annualized production for the nine months ended September 30, 1997. SUMMARY OPERATING DATA The following table sets forth summary data with respect to the production and sales of oil and natural gas by the Company for the periods indicated.
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, -------------------------------------- ----------------------------- PRO FORMA PRO FORMA 1994 1995 1996 1996(A) 1996 1997 1997(A) ------ ------- ------- --------- ------- ------- --------- AVERAGE NET DAILY PRODUCTION VOLUMES: Oil (Bbls)................................ 1,340 1,995 4,099 7,520 3,529 7,615 10,522 Natural gas (Mcf)......................... 9,113 13,271 24,406 25,076 23,867 34,061 34,648 Oil equivalent (BOE) ..................... 2,859 4,207 8,167 11,699 7,507 13,292 16,297 WEIGHTED AVERAGE SALES PRICES: Oil (per Bbl)............................. $13.84 $ 14.90 $ 18.98 $ 18.75 $ 18.05 $ 17.53 $ 17.45 Natural gas (per Mcf)..................... 1.78 1.90 2.73 2.72 2.64 2.54 2.54 PER BOE DATA: Revenue................................... $12.17 $ 13.05 $ 17.69 $ 17.88 $ 16.87 $ 16.56 $ 16.65 Production expenses....................... (4.13) (4.42) (4.51) (4.70) (4.47) (4.34) (4.71) ------ ------- ------- ------- ------- ------- ------- Production netback........................ 8.04 8.63 13.18 13.18 12.40 12.22 11.94 General and administrative................ (1.12) (1.25) (1.50) (1.21) (1.45) (1.33) (1.20) Interest, net............................. (0.99) (1.26) (0.26) (2.94) (0.37) 0.18 (1.83) ------ ------- ------- ------- ------- ------- ------- Operating cash flow(b).................... $ 5.93 $ 6.12 $ 11.42 $ 9.03 $ 10.58 $ 11.07 $ 8.91 ====== ======= ======= ======= ======= ======= =======
- --------------- (a) Adjusted to give effect to the Transactions as if the Transactions had been completed as of the beginning of the periods presented. (b) Represents cash flow provided by operations, exclusive of the net change in non-cash working capital balances. 11 12 RISK FACTORS Prospective purchasers of the securities offered hereby should carefully consider the following factors in addition to the other information in this Prospectus. See "Forward-Looking Statements." SUBSTANTIAL CAPITAL REQUIREMENTS In the future, the Company will require additional funds to develop, maintain and acquire additional interests in existing or newly acquired properties. During the last three years, the Company's total capital expenditures, including acquisitions, have averaged significantly more than its cash flow from operations. The Company made capital expenditures of $28.5 million, $86.9 million and $272.8 million in the years ended December 31, 1995 and 1996, and the nine-month period ended September 30, 1997 (including the pro forma effect of the Chevron Acquisition), respectively. Historically, the Company has funded these expenditures principally through internally-generated cash flows, bank debt and the issuance of equity. The Company intends to use the net proceeds from the Offerings and the TPG Purchase to substantially reduce its outstanding bank debt. As of September 30, 1997, after giving pro forma effect to the Transactions, the Company would have had $141.9 million ($123.9 million as of December 31, 1997) available under its Credit Facility. See "Use of Proceeds." The borrowing base on the Credit Facility will be redetermined semi- annually by the lenders thereunder in their sole discretion and there can be no assurance that the borrowing base will be maintained at its present level. If the Company's borrowing base under the Credit Facility is decreased, the Company's ability to obtain the funds necessary to carry out its business strategy may be limited. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Restated Credit Facility" and "Description of Certain Indebtedness." Although the Company carefully monitors its capital requirements and plans its expenditures accordingly, and believes that it will be able to meet all of its obligations in the future, there can be no assurance that additional capital will always be available to the Company in the future or that it will be available on terms that are acceptable to the Company. Numerous factors affect the cost and availability of capital, including market conditions, the Company's results of operations and the rate of the Company's drilling successes. Should outside capital resources be limited, the rate of the Company's growth would substantially decline, and there can also be no assurance that the Company would be able to continue to increase its oil and natural gas production or reserves. PRICE FLUCTUATIONS AND MARKETS The Company's revenue, profitability and future rate of growth are dependent upon the price of, and demand for, oil, natural gas and natural gas liquids. Historically, the markets for oil and natural gas have been volatile and are likely to continue to be volatile in the future. The prices for oil and natural gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond the control of the Company. These factors include the level of consumer product demand, weather conditions, domestic and foreign governmental relations, governmental regulations and taxes, the price and availability of alternative fuels, political conditions in the Middle East and other petroleum producing areas, the foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. Declines in oil and natural gas prices would not only reduce revenue, but could reduce the amount of oil and natural gas that can be produced economically by the Company and, as a result, could have a material adverse effect on the Company's financial condition, results of operations and reserves. In an effort to minimize the effect of price volatility, the Company has from time to time entered into hedging arrangements. The Company currently does not have any financial hedging contracts in place, although it may enter into such contracts in the future. The availability of a ready market for the Company's oil and natural gas production also depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to, and the capacity of, oil and natural gas gathering systems, pipelines or trucking and terminal facilities. Wells may be temporarily shut-in for lack of a market, or due to the inadequacy or unavailability of pipeline or 12 13 gathering system capacity. If any of these market factors were to dramatically change, the impact on the Company's financial condition would be substantial. ACQUISITION RISKS The Company's rapid growth in recent years has been attributable in significant part to acquisitions of producing properties. After the consummation of the Offerings, the Company expects to continue to evaluate and, where appropriate, pursue acquisition opportunities. There can be no assurance that suitable acquisition opportunities will be identified in the future, or that they will be integrated successfully into the Company's operations or be successful in achieving desired profitability objectives. In addition, the Company competes against other companies for acquisitions, and there can be no assurance that the Company will be successful in the acquisition of any material property interests. The successful acquisition of producing properties requires an assessment of recoverable reserves, exploration potential, future oil and natural gas prices, operating costs, potential environmental and other liabilities and other factors beyond the Company's control. In connection with such an assessment, the Company performs a review of the subject properties that it believes to be generally consistent with industry practices. Nonetheless, the resulting assessments are necessarily inexact and their accuracy inherently uncertain, and such a review may not accurately assess a property's value or reveal all existing or potential problems, nor will it necessarily permit a buyer to become sufficiently familiar with the property to fully assess its merits and deficiencies. Inspections may not always be performed on every platform or well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. Additionally, significant acquisitions can change the nature of the operations and business of the Company depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or geographic location than existing properties. While it is the Company's current intention to continue to concentrate on acquiring producing properties with development and exploration potential located in the Gulf Coast region, there can be no assurance that the Company will not pursue acquisitions or properties located in other geographic regions. To the extent that such acquired properties are substantially different than the Company's Gulf Coast properties, the Company's ability to efficiently realize the economic benefits of such transactions may be limited. DRILLING AND OPERATING RISKS Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. There can be no assurance that new wells drilled by the Company will be productive or that the Company will recover all or any portion of its investment in such wells. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net revenues to return a profit after deducting drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain. The Company's drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond the Company's control, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment and services. The Company's operations are subject to all of the risks normally incident to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, blow-outs, the release of contaminants into the environment, cratering and fires, all of which could result in personal injuries, loss of life, pollution damage, damage to property of the Company and others, including the inability to control such risk when wells are being drilled by third party contractors and the imposition of fines and penalties pursuant to environmental legislation. See "-- Governmental and Environmental Regulation" and "Business and Properties -- Legal Proceedings." The Company is not fully insured against all of these risks, nor are all such risks insurable. Although the Company maintains liability insurance in an amount which it considers adequate, the nature of these risks is such that liabilities could exceed policy limits, or, as in the case of environmental fines and penalties, be uninsurable, in which event the Company could incur significant costs that could have a material adverse effect upon its 13 14 financial condition. The Company believes that it has proper procedures in place and that its operating staff carries out their work in a manner designed to mitigate these risks. There can be no assurance, however, that such procedures will be effective in deterring these costs. The Company has focused its oil and natural gas operations in certain key areas and currently receives approximately 80% of its production from 11 fields. Any interruption of operations in these key areas could materially adversely affect the profitability of the Company. In the majority of the Company's Mississippi fields, significant amounts of saltwater are produced which require disposal. Currently, the Company is able to dispose of such saltwater economically, but should it be unable to do so in the future, production from these fields would become uneconomical. NEED TO REPLACE RESERVES The Company's future success depends on its ability to find, develop or acquire additional oil and natural gas reserves that are recoverable on an attractive economic basis. Unless the Company successfully replaces the reserves that it produces (through development, exploration or acquisitions), the Company's proved reserves will decline. Furthermore, approximately 21% of the Company's proved developed reserves at December 31, 1997 are located in the lower Gulf Coast geosyncline in southern Louisiana, which is characterized by relatively rapid decline rates. Approximately 60% of the Company's total proved reserves at December 31, 1997 were either proved undeveloped or proved developed non-producing. Recovery of such reserves will require significant capital expenditures and successful drilling operations. There can be no assurance that the Company will continue to be successful in its effort to develop or replace its proved reserves on terms economically beneficial to the Company, if at all. UNCERTAINTY OF ESTIMATES OF OIL AND NATURAL GAS RESERVES Estimates of the Company's proved developed oil and natural gas reserves and future net revenues therefrom appearing elsewhere herein are based on reserve reports prepared by independent petroleum engineers. There are numerous uncertainties inherent in estimating the quantity of proved reserves, including many factors which are beyond the Company's control. The estimates contained in this Prospectus are based on several assumptions, all of which are speculative to a certain degree. Actual future production, revenues, taxes, operating expenses, development expenditures and quantities of recoverable oil and natural gas reserves could vary substantially from those assumed in the estimates and any significant variance in these assumptions could materially affect the estimated quantity of reserves. The estimation of reserves requires substantial judgment on the part of the petroleum engineers, resulting in imprecise determinations, particularly with respect to new discoveries. Different reserve engineers may make different estimates of reserve quantities and revenues attributable thereto based on the same data. The accuracy of any reserve estimate depends on the quality of available data, as well as engineering and geological interpretation and judgment. The Company's reserves are primarily water-drive reservoirs which can increase the uncertainty of the estimates that have been prepared. Results of drilling, testing and production or price changes subsequent to the date of the estimate may result in revisions to such estimates. The estimates of future net revenues reflect oil and natural gas prices as of the date of estimation, without escalation. There can be no assurance, however, that such prices will be realized or that the estimated production volumes will be produced during the periods indicated. Future performance that deviates significantly from that found in the reserve reports could have a material adverse effect on the Company. EFFECTS OF LEVERAGE AND RESTRICTIVE DEBT COVENANTS As of September 30, 1997, after giving pro forma effect to the Transactions, the Company would have had total consolidated indebtedness of approximately $148.1 million and a debt-to-capitalization ratio of 38.9%. In addition, the Company may incur additional indebtedness in the future under the Credit Facility in connection with its acquisition, development, exploitation and exploration of oil and natural gas producing properties. As of September 30, 1997, after giving pro forma effect to the Transactions, the Company would have had $141.9 million ($123.9 million as of December 31, 1997) of availability under the Credit Facility. 14 15 The degree to which the Company will be leveraged following the Transactions could have important consequences to holders of the Common Shares, including but not limited to, the following: (i) a substantial portion of the Company's cash flow from operations will be dedicated to debt service and will not be available for other purposes; (ii) the Company's ability to obtain additional financing in the future could be limited; (iii) certain of the Company's borrowings are at variable rates of interest, which could result in higher interest expense in the event of increases in interest rates; (iv) the Company may be more vulnerable to downturns in its business or in the general economy and may be restricted from making acquisitions, introducing new technologies or exploiting business opportunities; and (v) the Indenture and the Credit Agreement (as defined herein) contain financial and restrictive covenants that limit the ability of the Company to, among other things, borrow additional funds, dispose of assets or pay cash dividends. Failure by the Company to comply with such covenants could result in an event of default under such debt instruments which, if not cured or waived, could have a material adverse effect on the Company. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Restated Credit Facility" and "Description of Certain Indebtedness." If the Company is unable to generate sufficient cash flow or otherwise obtain funds necessary to make required payments on its indebtedness or, if the Company otherwise fails to comply with the various covenants in such indebtedness (including covenants in the Credit Facility), it would be in default under the terms thereof, which would permit the holders of such indebtedness to accelerate the maturity of such indebtedness and could cause defaults under other indebtedness of the Company, including the Notes, or result in its bankruptcy. The ability of the Company to meet its obligations will be dependent upon the future performance of the Company, which will be subject to prevailing economic conditions and to financial, business and other factors, including factors beyond the control of the Company. CONTROLLING SHAREHOLDER In December 1995, the Company completed a $40.0 million private placement of securities to TPG consisting of Convertible Preferred (as defined herein), Common Shares and warrants to purchase Common Shares. After giving pro forma effect to the Equity Offering and the TPG Purchase, TPG will own approximately 34% of the Common Shares outstanding. TPG is entitled to nominate a minimum of three of the seven members of the Company's Board of Directors so long as TPG maintains certain ownership levels. In addition, certain transactions, including changes to the number of board members, amendments to the Company's Articles of Continuance, certain issuances of debt, certain acquisitions and dispositions, and most issuances of equity, require the two-thirds majority of the Board of Directors, which cannot be obtained without the approval of at least one TPG nominee. Additionally, so long as TPG's equity interest is 20% or greater, it has the right (which has been partially waived for the Equity Offering), but not the obligation, to maintain its pro rata ownership interest in the equity securities of the Company in the event the Company issues any additional equity securities or securities convertible into Common Shares by purchasing additional securities on the same terms and conditions. At the request of the New York Stock Exchange, the Company has agreed to make the extension of this right subject to shareholder ratification every five years with the first vote on the matter expected to be at the Company's annual meeting in the year 2000. See "Interests of Management in Certain Transactions." DEPENDENCE ON KEY PERSONNEL The Company believes that its continued success will depend to a significant extent upon the abilities and continued efforts of its Board of Directors and its senior management, particularly Gareth Roberts, its Chief Executive Officer and President. The Company does not have any employment agreements and does not maintain any key man life insurance policies. The loss of the services of any of its key personnel could have a material adverse effect on the Company's results of operations. The success of the Company will also depend, in part, upon the Company's ability to find, hire and retain additional key management personnel who are also being sought by other businesses. The inability to find, hire and retain such personnel could have a material adverse effect upon the Company's results of operations. See "Management." 15 16 SHARES ELIGIBLE FOR FUTURE SALE As of December 31, 1997, after giving pro forma effect to the Equity Offering and the TPG Purchase, the Company would have had 25,257,283 Common Shares outstanding (25,940,863 Common Shares assuming exercise of the Underwriters' over-allotment option in full). The Common Shares sold in the Equity Offering will be freely tradeable without restrictions or further registration under the Securities Act of 1933, as amended (the "Securities Act"). All of the Common Shares beneficially owned by TPG as of the close of the Equity Offering and the TPG Purchase will be "restricted" securities within the meaning of the Securities Act as a result of TPG being deemed an "affiliate" of the Company under such act. The Company believes that such "restricted" Common Shares are eligible for sale on the open market pursuant to Rule 144 under the Securities Act from time to time. In connection with the Equity Offering and the TPG Purchase, the Company, all of its directors and executive officers and TPG have agreed not to sell or otherwise dispose of any Common Shares, including any securities exercisable for or convertible into Common Shares, for a period of 120 days from the date of this Prospectus, without the prior written consent of Morgan Stanley & Co. Incorporated. See "Underwriters." In addition, the Company has granted certain registration rights to TPG. Until December 21, 2000, TPG has the right, subject to certain conditions, to demand that its Common Shares be registered under the Securities Act on one occasion. See "Interests of Management in Certain Transactions" and "Shares Eligible for Future Sale." The sale of a substantial number of Common Shares or the availability of a substantial number of shares for sale may adversely affect the market price of the Common Shares and could impair the Company's ability to raise additional capital through the sale of its equity securities. COMPETITION The Company operates in a highly competitive industry. The Company competes with a large number of integrated and independent energy companies for the acquisition of desirable oil and natural gas properties, as well as for the equipment and labor required to develop and operate such properties. Many of these competitors have financial and other resources substantially greater than those of the Company. See "Business and Properties -- Competition." The principal resources necessary for the exploration for, and the acquisition, exploitation, production and sale of, oil and natural gas are leaseholds under which oil and natural gas reserves may be discovered, drilling rigs and related equipment to explore for and develop such reserves, capital assets required for the exploitation and production of the reserves and knowledgeable personnel to conduct all phases of oil and natural gas operations. The Company must compete for such resources with major oil companies and independent operators and also with other industries for certain personnel and materials. Although the Company believes its current resources are adequate to preclude any significant disruption of operations in the immediate future, the continued availability of such materials and resources to the Company cannot be assured. GOVERNMENTAL AND ENVIRONMENTAL REGULATION The production of oil and natural gas is subject to regulation under a wide range of United States federal and state statutes, rules, orders and regulations. Federal and state statutes and regulations require permits for drilling, reworking and recompletion operations, drilling bonds and reports concerning operations, and these permits are subject to modification, renewal and revocation by the issuing governmental authority. Most states in which the Company owns and operates properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells and the regulation of the spacing, plugging and abandonment of wells. Many states also restrict production to the market demand for oil and natural gas, and several states have indicated interest in revising applicable regulations in light of the persistent oversupply and low prices for oil and natural gas production. These regulations may limit the rate at which oil and natural gas could otherwise be produced from the Company's properties. Some states have also enacted statutes prescribing ceiling prices for natural gas sold within the state. See "Business and Properties -- Regulations." 16 17 Various federal, state and local laws and regulations relating to the protection of the environment may affect the Company's operations and costs. In particular, the Company's production operations, its salt water disposal operations and its use of facilities for treating, processing or otherwise handling hydrocarbons and wastes therefrom are subject to stringent environmental regulation. The majority of the Company's Louisiana activity is conducted in a marsh environment where environmental regulations are somewhat greater. Although compliance with these regulations increases the cost of Company operations, such compliance has not had a material effect on the Company's capital expenditures, earnings or competitive position. There can be no assurance, however, that future compliance with these regulations will not have such a material adverse effect. Environmental regulations have historically been subject to frequent change by regulatory authorities, and the Company is unable to predict the ongoing cost of complying with these laws and regulations or the future impact of such regulations on its operations. There can be no assurance that present or future regulation will not adversely affect the Company's exploration, development and production of its oil and natural gas producing properties. A significant discharge of hydrocarbons into the environment could, to the extent such event is not insured, subject the Company to substantial expense. See "Business and Properties -- Regulations." AUTHORIZATION AND DISCRETIONARY ISSUANCE OF PREFERRED SHARES; ANTI-TAKEOVER PROVISIONS DRI's Articles of Continuance authorize the future issuance of an unlimited number of First Preferred Shares and Second Preferred Shares (collectively, the "Preferred Shares"), with such designations, rights, privileges, restrictions and conditions as may be determined from time to time by the Board of Directors. Accordingly, the Board of Directors is empowered, without shareholder approval, to issue Preferred Shares with dividend, liquidation, conversion, voting or other rights that could adversely affect the voting power or other rights of holders of the Common Shares. The issuance of the Preferred Shares could be utilized, under certain circumstances, as a method of discouraging, delaying or preventing a change in control of the Company. Such actions could have the effect of discouraging bids for the Company, thereby preventing shareholders from receiving the maximum value for their shares. Although the Company has no present intention to issue any additional Preferred Shares, there can be no assurance that the Company will not do so in the future. After giving effect to the Offerings, no Preferred Shares will be outstanding. See "Interests of Management in Certain Transactions." The Investment Canada Act includes provisions that are intended to encourage persons considering unsolicited tender offers or other unilateral takeover proposals to negotiate with DRI's Board of Directors rather than pursue non-negotiated takeover attempts. These provisions apply to DRI and may have a significant effect on the ability of a shareholder to benefit from certain kinds of transactions that may be opposed by the incumbent Board of Directors. See "Description of Capital Stock" and "Canadian Taxation and the Investment Canada Act." ABSENCE OF DIVIDENDS During the last five fiscal years, the Company has not paid any dividends on its outstanding Common Shares, and the Company does not intend to pay any dividends in the foreseeable future. DRI is a holding company with no independent operations. Accordingly, any amounts available for dividends will be dependent on the prior declaration of dividends by DMI to DRI. In addition, the terms of the Credit Facility restrict, and the terms of the Notes will restrict, the payment of dividends by DMI. The Company currently intends to retain its cash for the continued expansion of its business, including exploration, development and acquisition activities. CONCENTRATION OF CUSTOMERS During 1996, the Company sold 10% or more of its net production of oil and natural gas to the following purchasers: Natural Gas Clearinghouse (20%); Penn Union Energy Services (19%); Enron Trading & Transportation (13%); and Hunt Refining (15%). In addition, the Company is currently selling a majority of its oil to Hunt Refining under a two-year contract which expires in April 1998 and is currently receiving a premium to the posted price in this contract. The Company may not be able to renew this contract in the 17 18 future or may not be able to obtain terms as favorable as those in the existing contract. While the Company believes that its relationships with these purchasers are good, any loss of revenue from these purchasers could have a material adverse effect on the Company's results of operations. FORWARD-LOOKING STATEMENTS The statements contained in this Prospectus that are not historical facts, including, but not limited to, statements found in the "Prospectus Summary," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Business and Properties," are "forward-looking statements," as that term is defined in Section 21E of the Exchange Act, that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, capital expenditures, drilling activity, acquisition plans and proposals, dispositions, development activities, cost savings, production efforts and volumes, hydrocarbon reserves, hydrocarbon prices, liquidity, regulatory matters and competition. Such forward-looking statements generally are accompanied by words such as "plan," "estimate," "expect," "predict," "anticipate," "projected," "should," "assume," "believe" or other words that convey the uncertainty of future events or outcomes. Such forward-looking statements are based upon management's current plans, expectations, estimates and assumptions and are subject to a number of risks and uncertainties that could significantly affect current plans, anticipated actions, the timing of such actions and the Company's financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by or on behalf of the Company. Among the factors that could cause actual results to differ materially are: fluctuations of the prices received or demand for the Company's oil and natural gas, the uncertainty of drilling results and reserve estimates, operating hazards, acquisition risks, requirements for capital, general economic conditions, competition and government regulations, as well as the risks and uncertainties discussed in this Prospectus, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in the Company's other public reports, filings and public statements. DEBT OFFERING Concurrently with the Equity Offering, the Company is offering $125.0 million of 9% Senior Subordinated Notes Due 2008 to the public. The Indenture to be executed in conjunction with the Debt Offering will contain certain covenants, including covenants that limit (i) indebtedness, (ii) restricted payments, (iii) issuances and sale of capital stock of restricted subsidiaries, (iv) sale/leaseback transactions, (v) transactions with affiliates, (vi) liens, (vii) asset sales, (viii) dividend and other payment restrictions affecting restricted subsidiaries and (ix) mergers and consolidations. The closing of the Equity Offering is not conditioned upon the closing of the Debt Offering; however, the closing of the Debt Offering is conditioned upon the closing of the Equity Offering. See "Description of Certain Indebtedness -- Senior Subordinated Notes." USE OF PROCEEDS The net proceeds to the Company from the Equity Offering are estimated to be approximately $72.1 million ($83.0 million if the Underwriters' over-allotment option is exercised in full). Concurrently with the Equity Offering, the Company is offering $125.0 million aggregate principal amount of 9% Senior Subordinated Notes Due 2008 in the Debt Offering. The closing of the Equity Offering is not conditioned upon the closing of the Debt Offering; however, the closing of the Debt Offering is conditioned upon the closing of the Equity Offering. The Company intends to use the total net proceeds of the Offerings and the TPG Purchase (estimated to be $198.9 million in the aggregate) to reduce outstanding borrowings under the Credit Facility. The undrawn balance under the Credit Facility will then be available for capital expenditures and general corporate purposes, including the acquisition of additional producing oil and natural gas properties. As of December 31, 1997, the Credit Facility had an outstanding balance of $240.0 million and an average interest rate of 7.5% per 18 19 annum. After the application of the net proceeds from the Offerings and the TPG Purchase to reduce amounts outstanding under the Credit Facility, the Credit Facility will consist of a five-year revolving credit facility with a borrowing base of $165.0 million. The Company borrowed $220.0 million under the Credit Facility during the fourth quarter of 1997, primarily to fund the Chevron Acquisition. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Restated Credit Facility," "Business and Properties -- Acquisitions of Oil and Natural Gas Properties" and "Description of Certain Indebtedness -- Credit Facility." PRICE RANGE OF COMMON SHARES The Common Shares have been listed on the New York Stock Exchange ("NYSE") since May 8, 1997 and were listed on the Nasdaq National Market ("NASDAQ") from August 25, 1995 through May 8, 1997. The Common Shares have also been listed on The Toronto Stock Exchange ("TSE") in Toronto, Canada, since February 14, 1984. The Common Shares currently trade under the symbol "DNR" on both the NYSE and TSE. The following table summarizes the high and low last reported sale prices (adjusted for the one-for-two reverse stock split in October 1996) as reported by each exchange for each quarterly period during the last two fiscal years and to date during 1998.
NYSE/NASDAQ TSE --------------- --------------- HIGH LOW HIGH LOW ------ ------ ------ ------ (US$) (C$) 1996 First Quarter................................... $ 7.88 $ 6.26 $10.80 $ 8.30 Second Quarter.................................. 10.62 8.50 14.50 12.00 Third Quarter................................... 13.50 10.00 18.60 12.70 Fourth Quarter.................................. 15.25 12.50 20.95 17.00 1997 First Quarter................................... 16.00 12.00 21.75 16.40 Second Quarter.................................. 17.63 13.13 24.50 18.00 Third Quarter................................... 23.75 16.13 33.00 22.20 Fourth Quarter.................................. 24.63 17.88 33.50 25.50 1998 First Quarter (through February 19, 1998)....... 20.25 16.38 29.00 23.50
A recent reported last sale price per share for the Common Shares on the NYSE and the TSE is set forth on the cover page of this Prospectus. As of December 31, 1997, to the best of the Company's knowledge, there were approximately 1,200 holders of record of Common Shares. DIVIDEND POLICY The Company has not paid any dividends in the last five fiscal years on its Common Shares and does not intend to pay any dividends on its Common Shares in the foreseeable future. In the past, the Company has used its available cash flow to conduct exploration and development activities or to make acquisitions, and expects to continue to do so in the future. DRI is a holding company with no independent operations. Accordingly, any amounts available for dividends will be dependent on the prior declaration of dividends by DMI to DRI. In addition, the terms of the Credit Facility restrict, and the terms of the Notes will restrict, the payment of dividends by DMI. 19 20 CAPITALIZATION The following table sets forth as of September 30, 1997 (i) the actual capitalization of the Company, (ii) the capitalization of the Company as adjusted for the Chevron Acquisition, (iii) the capitalization of the Company as further adjusted to give effect to the Equity Offering, the TPG Purchase and the application of the net proceeds therefrom and (iv) the capitalization of the Company as further adjusted to give effect to the Debt Offering and the application of the net proceeds therefrom. See "Use of Proceeds." This table should be read in conjunction with "Unaudited Pro Forma Consolidated Financial Information," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Consolidated Financial Statements.
AS OF SEPTEMBER 30, 1997 ------------------------------------------------------ AS FURTHER ADJUSTED FOR AS ADJUSTED THE EQUITY FOR THE OFFERING AS ADJUSTED COMPANY CHEVRON AND TPG FOR THE HISTORICAL ACQUISITION PURCHASE TRANSACTIONS ---------- ----------- ------------ ------------ (IN THOUSANDS) Cash and cash equivalents....................... $ 2,236 $ 2,236 $ 2,236 $ 2,236 ======== ======== ======== ======== Short-term debt: Credit Facility (a)........................... $ -- $ 47,000 $ -- $ -- -------- -------- -------- -------- Long-term debt: Credit Facility (a)........................... 20,000 175,000 144,890 23,100 9% Senior Subordinated Notes Due 2008......... -- -- -- 125,000 Other notes payable........................... 5 5 5 5 -------- -------- -------- -------- Total long-term debt.................. 20,005 175,005 144,895 148,105 -------- -------- -------- -------- Shareholders' equity (b): Common Shares, no par value; unlimited shares authorized; 20,364,799 outstanding; 25,235,399 outstanding as adjusted for the Transactions............................... 132,744 132,744 209,854 209,854 Retained earnings............................. 22,814 22,814 22,814 22,814 -------- -------- -------- -------- Total shareholders' equity................. 155,558 155,558 232,668 232,668 -------- -------- -------- -------- Total capitalization.................. $175,563 $377,563 $377,563 $380,773 ======== ======== ======== ========
- --------------- (a) The Credit Facility was revised and restated in December 1997 in order to fund the Chevron Acquisition. After repayment of the acquisition tranche and other borrowings thereunder with the net proceeds from the Offerings and the TPG Purchase, the Credit Facility will consist of a five year revolving credit facility with a borrowing base of $165.0 million. (b) Excludes 1,512,206 outstanding stock options as of September 30, 1997 exercisable at various prices ranging from $5.55 to $17.29 per share with a weighted average price of $10.69 (of which 395,222 were currently exercisable), and 700,000 Common Shares reserved for issuance upon exercise of the two series of Common Share purchase warrants. Also excludes 406,620 stock options that were granted on January 2, 1998, none of which are currently exercisable. 20 21 UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL INFORMATION The following unaudited pro forma consolidated statements of income for the year ended December 31, 1996 and the nine months ended September 30, 1997 and the unaudited pro forma consolidated balance sheet as of September 30, 1997 (collectively, the "Pro Forma Financial Statements") are based on the historical consolidated financial statements of the Company and the historical financial statements of the properties acquired by the Company (the "Chevron Properties") in the Chevron Acquisition, adjusted to give effect to the Transactions. Additional property acquisitions were made in 1997 that have not been included in the pro forma adjustments since they are immaterial individually and in the aggregate. These acquisitions are included in the Company's historical statements from the date of their respective acquisition. The Unaudited Pro Forma Consolidated Statement of Income for the year ended December 31, 1996 gives effect to the Transactions as if they had occurred as of January 1, 1996, and the Unaudited Pro Forma Consolidated Statement of Income for the nine months ended September 30, 1997 gives effect to the Transactions as if they had occurred as of January 1, 1997. The Unaudited Pro Forma Consolidated Balance Sheet gives effect to the Transactions as if they had occurred as of September 30, 1997. The pro forma adjustments are described in the accompanying notes and are based upon available information and certain assumptions that management believes are reasonable. The Pro Forma Financial Statements do not purport to represent what the Company's results of operations or financial condition would actually have been had the Transactions in fact occurred on such dates or to project the Company's results of operations or financial condition for any future date or period. The Pro Forma Financial Statements should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Consolidated Financial Statements. 21 22 UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, 1996 ----------------------------------------------------------------- HISTORICAL ADJUSTMENTS ------------------------ ------------------------ OFFERINGS COMPANY CHEVRON CHEVRON AND TPG HISTORICAL PROPERTIES ACQUISITION PURCHASE PRO FORMA ---------- ---------- ----------- --------- --------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Revenues: Oil, natural gas and related product........................ $52,880 $23,662 $ -- $ -- $76,542 Interest and other................ 769 -- -- -- 769 ------- ------- -------- ------- ------- Total revenues............ 53,649 23,662 -- -- 77,311 ------- ------- -------- ------- ------- Expenses: Production........................ 13,495 6,650 -- -- 20,145 General and administrative........ 4,267 -- 687(b) -- 4,954 Interest.......................... 1,993 -- 15,716(c) (3,900)(e) 13,809 Imputed preferred dividend........ 1,281 -- -- -- 1,281 Loss on early extinguishment of debt........................... 440 -- -- -- 440 Depletion and depreciation........ 17,904 -- 6,697(d) -- 24,601 Franchise taxes................... 213 -- -- -- 213 ------- ------- -------- ------- ------- Total expenses............ 39,593 6,650 23,100 (3,900) 65,443 ------- ------- -------- ------- ------- Income before income taxes.......... 14,056 17,012 (23,100) 3,900 11,868 Provision for income taxes.......... (5,312) (6,294)(a) 8,547(a) (1,443)(a) (4,502) ------- ------- -------- ------- ------- Net income.......................... $ 8,744 $10,718 $(14,553) $ 2,457 $ 7,366 ======= ======= ======== ======= ======= Net income per common share Primary........................... $ 0.67 $ 0.41 Fully diluted..................... 0.62 0.40 Average common shares outstanding... 13,104 17,975
See Notes to Unaudited Pro Forma Consolidated Financial Information 22 23 UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
NINE MONTHS ENDED SEPTEMBER 30, 1997 ---------------------------------------------------------------- HISTORICAL ADJUSTMENTS ----------------------- ------------------------ OFFERINGS COMPANY CHEVRON CHEVRON AND TPG HISTORICAL PROPERTIES ACQUISITION PURCHASE PRO FORMA ---------- ---------- ----------- --------- --------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Revenues: Oil, natural gas and related product........................... $60,083 $14,034 $ -- $ -- $74,117 Interest and other................... 986 -- -- -- 986 ------- ------- ------- ------- ------- Total revenues............... 61,069 14,034 -- -- 75,103 ------- ------- ------- ------- ------- Expenses: Production........................... 15,737 5,237 -- -- 20,974 General and administrative........... 4,535 -- 514(b) -- 5,049 Interest............................. 387 -- 10,289(c) (1,483)(e) 9,193 Depletion and depreciation........... 23,224 -- 3,942(d) -- 27,166 Franchise taxes...................... 308 -- -- -- 308 ------- ------- ------- ------- ------- Total expenses............... 44,191 5,237 14,745 (1,483) 62,690 ------- ------- ------- ------- ------- Income before income taxes............. 16,878 8,797 (14,745) 1,483 12,413 Provision for income taxes............. (6,245) (3,255)(a) 5,456(a) (549)(a) (4,593) ------- ------- ------- ------- ------- Net income............................. $10,633 $ 5,542 $(9,289) $ 934 $ 7,820 ======= ======= ======= ======= ======= Net income per common share Primary.............................. $ 0.53 $ 0.31 Fully diluted........................ 0.50 0.31 Average common shares outstanding...... 20,175 25,046
See Notes to Unaudited Pro Forma Consolidated Financial Information 23 24 UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET
AS OF SEPTEMBER 30, 1997 ---------------------------------------------------------------- ADJUSTMENTS ------------------------------------ EQUITY OFFERING COMPANY CHEVRON AND TPG DEBT HISTORICAL ACQUISITION PURCHASE OFFERING PRO FORMA ---------- ----------- -------- --------- --------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) ASSETS: Current assets Cash and cash equivalents........ $ 2,236 $ -- $ -- $ -- $ 2,236 Accrued production receivable.... 7,097 -- -- -- 7,097 Trade and other receivables...... 14,507 -- -- -- 14,507 -------- -------- -------- -------- -------- Total current assets..... 23,840 -- -- -- 23,840 -------- -------- -------- -------- -------- Property and equipment (using full cost accounting) Oil and gas properties........... 230,521 127,000(f) -- -- 357,521 Unevaluated oil and gas properties.................... 6,389 75,000(f) -- -- 81,389 Less accumulated depreciation and depletion..................... (53,527) -- -- -- (53,527) -------- -------- -------- -------- -------- Net property and equipment.... 183,383 202,000 -- -- 385,383 -------- -------- -------- -------- -------- Other assets....................... 3,201 -- -- 3,210(k) 6,411 -------- -------- -------- -------- -------- Total assets............. $210,424 $202,000 $ -- $ 3,210 $415,634 ======== ======== ======== ======== ======== LIABILITIES AND SHAREHOLDERS' EQUITY: Current liabilities Accounts payable and accrued liabilities................... $ 16,858 $ -- $ -- $ -- $ 16,858 Oil and gas production payable... 4,060 -- -- -- 4,060 Current portion of long-term debt.......................... 23 47,000(g) (47,000)(i) -- 23 -------- -------- -------- -------- -------- Total current liabilities............ 20,941 47,000 (47,000) -- 20,941 -------- -------- -------- -------- -------- Long-term liabilities Long-term debt................... 20,005 155,000(h) (30,110)(i)(121,790)(l) 23,105 Senior subordinated debt......... -- -- -- 125,000 (m) 125,000 Provision for site reclamation costs......................... 938 -- -- -- 938 Deferred income taxes and other......................... 12,982 -- -- -- 12,982 -------- -------- -------- -------- -------- Total long-term liabilities............ 33,925 155,000 (36,081) 3,210 162,025 -------- -------- -------- -------- -------- Shareholders' equity Common shares, no par value; unlimited shares authorized; 20,364,799 outstanding; 25,235,399 outstanding pro forma......................... 132,744 -- 77,110(j) -- 209,854 Retained earnings................ 22,814 -- -- -- 22,814 -------- -------- -------- -------- -------- Total shareholders' equity................. 155,558 -- 77,110 -- 232,668 -------- -------- -------- -------- -------- Total liabilities and shareholders' equity... $210,424 $202,000 $ -- $ 3,210 $415,634 ======== ======== ======== ======== ========
See Notes to Unaudited Pro Forma Consolidated Financial Information 24 25 NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL INFORMATION (a) Income taxes were computed using the federal statutory rate of 35% plus a 2% provision for state income taxes. (b) Reflects an increase of $687,000 and $514,000 for the year ended December 31, 1996 and the nine months ended September 30, 1997, respectively, in general and administrative expense for additional personnel and associated costs relating to the properties acquired in the Chevron Acquisition, net of anticipated allocations to operations and capitalization of exploration costs. (c) Reflects an increase in interest expense for the period presented to reflect the $202.0 million of borrowing under the Credit Facility (at an assumed annual interest rate of 7.8% and 6.8% for the year ended December 31, 1996 and the nine months ended September 30, 1997, respectively) that would have been required to fund the Chevron Acquisition had it occurred as of the beginning of each respective period. (d) Depreciation, depletion and amortization ("DD&A") and site reclamation expenses have been computed using the unit of production method and reflects the Company's increased investment in oil and natural gas properties, which investment excludes $75.0 million of the Chevron Acquisition purchase price as the Company intends to classify this amount as unevaluated properties at December 31, 1997. The December 31, 1997 estimated proved reserves prepared by Netherland & Sewell were used in the DD&A computation for the Chevron Acquisition. (e) Reflects a decrease in interest expense for the period presented resulting from (i) the receipt of $77.1 million in estimated net proceeds from the Equity Offering and the TPG Purchase and the application of such net proceeds to reduce borrowings under the Credit Facility and (ii) the receipt of $121.8 million in estimated net proceeds from the Debt Offering and the application of such net proceeds to reduce borrowings under the Credit Facility. Interest expense also includes the amortization of deferred debt issuance costs. (f) Reflects the purchase price paid in the Chevron Acquisition, of which the Company intends to classify $75.0 million as unevaluated properties. (g) Reflects the incurrence of indebtedness under the Acquisition Tranche (as defined herein) of the Credit Facility to finance a portion of the Chevron Acquisition. (h) Reflects the incurrence of indebtedness under the revolving portion of the Credit Facility to finance a portion of the Chevron Acquisition. (i) Reflects the repayment of indebtedness outstanding under the Credit Facility with the net proceeds of the Equity Offering and the TPG Purchase. (j) Reflects the issuance and sale of Common Shares in the Equity Offering and the TPG Purchase, net of underwriting discounts and commissions and estimated expenses. (k) Reflects deferred financing costs incurred in connection with the Debt Offering. (l) Reflects the repayment of indebtedness outstanding under the Credit Facility with the net proceeds of the Debt Offering. (m) Reflects the issuance of the Notes in the Debt Offering. 25 26 SELECTED CONSOLIDATED FINANCIAL DATA The selected historical consolidated financial data for the Company set forth below as of and for the years ended December 31, 1992, 1993, 1994, 1995 and 1996, have been derived from the audited consolidated financial statements of the Company. The selected historical consolidated financial data for the nine-month periods ended September 30, 1996 and 1997, and as of September 30, 1997, have been derived from unaudited consolidated financial statements of the Company which, in management's opinion, include all adjustments (consisting of only normal recurring adjustments) necessary to present fairly the results for such periods. The operating results for such periods are not necessarily indicative of the operating results to be expected for a full fiscal year. The information set forth below should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Consolidated Financial Statements included elsewhere in this Prospectus.
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, ---------------------------------------------- ----------------- 1992 1993 1994 1995 1996 1996 1997 ------ ------- ------- ------- ------- ------- ------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) INCOME STATEMENT DATA: Revenue: Oil, natural gas and related product.................... $1,912 $ 5,868 $12,692 $20,032 $52,880 $34,709 $60,083 Interest income......................................... 40 76 23 77 769 425 986 ------ ------- ------- ------- ------- ------- ------- Total revenues...................................... 1,952 5,944 12,715 20,109 53,649 35,134 61,069 ------ ------- ------- ------- ------- ------- ------- Expenses: Production.............................................. 634 2,067 4,309 6,789 13,495 9,197 15,737 General and administrative.............................. 955 782 1,105 1,832 4,267 2,825 4,535 Interest................................................ 8 83 1,146 2,085 1,993 1,530 387 Imputed preferred dividends............................. -- -- -- -- 1,281 1,153 -- Loss on early extinguishment of debt.................... -- -- -- 200 440 440 -- Depletion and depreciation.............................. 690 1,898 4,209 8,022 17,904 12,557 23,224 Franchise taxes......................................... -- -- 65 100 213 160 308 ------ ------- ------- ------- ------- ------- ------- Total expenses...................................... 2,287 4,830 10,834 19,028 39,593 27,862 44,191 ------ ------- ------- ------- ------- ------- ------- Income (loss) before the following:....................... (335) 1,114 1,881 1,081 14,056 7,272 16,878 Gain on sale of Canadian properties..................... -- 966 -- -- -- -- -- ------ ------- ------- ------- ------- ------- ------- Income (loss) before income taxes......................... (335) 2,080 1,881 1,081 14,056 7,272 16,878 Provision for federal income taxes........................ -- (345) (718) (367) (5,312) (2,932) (6,245) ------ ------- ------- ------- ------- ------- ------- Net income (loss)......................................... $ (335) $ 1,735 $ 1,163 $ 714 $ 8,744 $ 4,340 $10,633 ====== ======= ======= ======= ======= ======= ======= Net income (loss) per common share: Primary................................................. $(0.11) $ 0.35 $ 0.19 $ 0.10 $ 0.67 $ 0.37 $ 0.53 Fully diluted........................................... (0.11) 0.35 0.19 0.10 0.62 0.36 0.50 Weighted average common shares outstanding................ 2,949 4,990 6,240 6,870 13,104 11,616 20,175 OTHER FINANCIAL DATA: Operating cash flow(a).................................... $ 354 $ 3,030 $ 6,185 $ 9,394 $34,140 $21,767 $40,166 Capital expenditures...................................... 6,189 29,855 16,903 28,524 86,857 73,320 70,773 EBITDA(b)................................................. 323 3,019 7,213 11,311 34,905 22,527 39,503 SELECTED RATIOS: Ratio of earnings to fixed charges(c)..................... (d) 12.3x 2.6x 1.5x 4.4x 3.1x 34.9x Ratio of EBITDA to interest expense....................... 40.4 36.4 6.3 5.4 17.5 14.7 102.1 Ratio of long-term debt to EBITDA......................... -- 2.0 2.3 0.3 0.1 1.6(e) 0.4(e)
AS OF DECEMBER 31, AS OF ----------------------------------------------- SEPTEMBER 30, 1992 1993 1994 1995 1996 1997 ------ ------- ------- ------- -------- ------------- (IN THOUSANDS) BALANCE SHEET DATA: Working capital (deficit)................................. $1,369 $(1,410) $(1,620) $ 6,862 $ 12,482 $ 2,899 Total assets.............................................. 8,225 35,978 48,964 77,641 166,505 210,424 Long-term debt, net of current maturities................. -- 6,177 16,536 3,474 125 20,005 Convertible preferred stock............................... -- -- -- 15,000 -- -- Shareholders' equity...................................... 7,548 24,431 25,962 53,501 142,504 155,558
- --------------- (a) Represents cash flow provided by operations, exclusive of the net change in non-cash working capital balances. (b) EBITDA represents earnings before interest income, interest expense, income taxes, depletion and depreciation, gain on sale of oil and gas properties, imputed preferred dividends and losses on early extinguishment of debt. The Company has included information concerning EBITDA because it believes that EBITDA is used by certain investors as one measure of an issuer's historical ability to service its debt. EBITDA is not a measurement determined in accordance with generally accepted accounting principles and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with generally accepted accounting principles. (c) For purposes of determining the ratio of earnings to fixed charges, earnings are defined as earnings from continuing operations before income taxes, plus fixed charges. Fixed charges consist of interest expense, amortization of debt expense, and imputed preferred stock dividends. (d) Earnings were inadequate to cover fixed charges as there was a $317,000 deficiency. (e) EBITDA for these periods has been annualized. 26 27 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Denbury is an independent energy company engaged in acquisition, development and exploration activities in the U.S. Gulf Coast region, primarily onshore in Louisiana and Mississippi. Over the last four years, the Company has achieved rapid growth in proved reserves, production and cash flow by concentrating on the acquisition of properties which it believes have significant upside potential and through the efficient development, enhancement and operation of its properties. ACQUISITION OF CHEVRON PROPERTIES On December 30, 1997, the Company acquired oil properties in the Heidelberg Field, Jasper County, Mississippi, from Chevron for approximately $202.0 million. The Chevron Acquisition represents the largest acquisition by the Company to date. The Heidelberg Field is adjacent to the Company's other primary oil properties in Mississippi and includes 122 producing wells, 96 of which the Company will operate. The Company purchased an average working interest of 94% and an average net revenue interest of 81% in these 96 wells, which wells currently account for approximately 99% of the field's average net daily production. The average net daily production from these properties during the third quarter of 1997 was approximately 2,840 Bbls/d and 600 Mcf/d. The Chevron Acquisition added proved reserves as of December 31, 1997 of approximately 27.2 MMBbls and 2.5 Bcf, or approximately 27.6 MMBOE. As a result of the significant amount of future development and exploitation to be performed on these properties and the increase in future reserves and production that the Company expects to result from such development and exploitation, the Company has attributed approximately $75.0 million of the purchase price to unevaluated properties. The Company has identified several potential development projects during its initial evaluation of the Heidelberg Field. These include initiating a waterflood project, upgrading lift capacity in over 15 wells and recompleting 30 wells in new zones. In addition, the Company has identified over 40 potential drilling locations in addition to other potential secondary and tertiary recovery projects. Horizontal wells drilled by the Company in 1997 at nearby Davis, Quitman and Eucutta Fields improved daily production rates significantly as compared to vertical wells drilled in the same fields. Consequently, the Company anticipates that 30 of the 40 proposed future wells in the Heidelberg Field will be horizontal wells. The Company's total 1998 development budget for the Heidelberg Field is approximately $30.0 million. ACQUISITION OF HESS PROPERTIES The Company completed several property acquisitions during 1996, the largest of which was the acquisition of producing oil and natural gas properties in Mississippi, Louisiana and Alabama, plus certain overriding royalty interests in Ohio, for approximately $37.2 million from Amerada Hess, effective May 1, 1996. The average daily production from the properties included in the Hess Acquisition during May and June 1996, the first two months of ownership, was approximately 2,945 BOE/d. The average daily production on these properties had increased to 5,373 BOE/d by the third quarter of 1997. As of December 31, 1997, in the Company's independent reserve report (the "December Report"), the properties acquired in the Hess Acquisition had estimated net proved reserves of approximately 14.2 MMBOE with a PV10 Value of $95.0 million. This compares to approximately 5.9 MMBOE of net proved reserves and a $43.1 million PV10 Value on these same properties as reported in the Company's independent reserve report dated July 1, 1996 (the "July Report"). The December Report was calculated using year-end prices which were based on a WTI price of $16.18 per Bbl and a NYMEX price of $2.58 per MMBtu, with these representative prices adjusted by field to arrive at the appropriate corporate net price, as compared to oil and gas prices of $20.00 and $2.65, respectively, in the July Report. In addition to the increase in proved reserves, the Company produced approximately 1.9 MMBOE from July 1, 1996 through September 30, 1997 with total net operating income of $23.8 million. 27 28 RESTATED CREDIT FACILITY The Company has a credit facility (the "Credit Facility") with NationsBank of Texas, N.A., as agent for a group of banks. The Credit Facility was increased in size from $150.0 million to $300.0 million in December 1997 and the borrowing base was increased to $260.0 million in order to fund the Chevron Acquisition. After application of the net proceeds from the Offerings and the TPG Purchase to reduce amounts outstanding under the Credit Facility, the Credit Facility will consist of a five-year revolving credit facility with a borrowing base of $165.0 million with $123.9 million available on a pro forma basis as of December 31, 1997. The borrowing base is subject to review every six months. The Credit Facility is secured by substantially all of the Company's oil and natural gas properties, except for those acquired in the Chevron Acquisition. Interest is payable on the revolving credit facility at either the prime rate or, depending on the percentage of the borrowing base that is outstanding, at rates ranging from LIBOR plus 7/8% to LIBOR plus 1 3/8%; provided that interest is payable at LIBOR plus 1 5/8% as long as the Acquisition Tranche is outstanding with the rate escalating 0.25% each quarter, beginning on March 1, 1998 through March 31, 1999, unless the Acquisition Tranche is repaid. The Credit Facility has several restrictions, including, among others: (i) a prohibition on the payment of dividends; (ii) a requirement for a minimum equity balance; (iii) a requirement to maintain positive working capital (as defined in the Credit Agreement); (iv) a minimum interest coverage test; and (v) a prohibition on most debt, lien and corporate guarantees. THE NOTES The Notes to be issued by DMI are to be fully and unconditionally guaranteed by DMI's parent company, DRI, pursuant to the terms and conditions of the Indenture. In addition, under certain circumstances, certain subsidiaries may in the future guarantee the Notes. The Indenture will contain certain covenants for the benefit of the holders of the Notes, including, among others, covenants limiting the payment of dividends, including dividends payable from DMI to DRI. CAPITAL RESOURCES AND LIQUIDITY As discussed below, in each of the last three years, the Company's capital expenditures required additional debt and equity capital to supplement cash flow from operations.
NINE MONTHS YEAR ENDED DECEMBER 31, ENDED ----------------------------- SEPTEMBER 30, 1994 1995 1996 1997 ------- ------- ------- ------------- (IN THOUSANDS) Acquisitions of oil and natural gas properties............................ $ 6,606 $16,763 $48,407 $16,073 Oil and natural gas expenditures........ 10,297 11,761 38,450 54,700 ------- ------- ------- ------- Total......................... $16,903 $28,524 $86,857 $70,773 ======= ======= ======= =======
From January 1, 1994 through September 30, 1997, including the pro forma adjustments for the Chevron Acquisition, the Company has made total capital expenditures of $405.1 million. These capital expenditures were funded by the issuance of equity ($105.3 million), bank debt ($209.9 million) and cash generated by operations ($89.9 million). During 1996, the Company's funds were provided by operating cash flow and equity, although the Company did use bank debt during the year. The Company began 1996 with $100,000 of outstanding bank debt, borrowed $47.9 million during the year, paid off the debt with the proceeds from a public offering of Common Shares in October 1996 and ended the year with $100,000 of bank debt outstanding. For the nine months ended September 30, 1997, the Company's average debt outstanding was $3.6 million. As of December 31, 1997, the Company had minimal working capital and approximately $240.0 million of debt outstanding. A portion of this debt also relates to an acquisition tranche on which the interest rate increases 0.25% each quarter beginning on March 1, 1998. Although the Company is still reviewing its budget, particularly in light of the recent Chevron Acquisition, the Company is currently budgeting capital expenditures for 1998 of approximately $95.0 million, of which approximately $30.0 million is allocated for the 28 29 properties included in the Chevron Acquisition. Although the Company's projected cash flow is highly variable and difficult to predict as it is dependent on product prices, drilling success and other factors, these projected expenditures are expected to exceed the Company's cash flow during 1998. As of December 31, 1997, after giving pro forma effect to the Transactions, the Company would have had an unused borrowing base of $123.9 million under the Credit Facility to fund any potential cash flow deficits. If external capital resources are limited or reduced in the future, the Company can also adjust its capital expenditure program accordingly. However, such adjustments could limit, or even eliminate, the Company's future growth. See "Risk Factors -- Substantial Capital Requirements." In addition to its internal capital expenditure program, the Company has historically required capital for the acquisition of producing properties, which have been a major factor in the Company's rapid growth during recent years. There can be no assurance that suitable acquisitions will be identified in the future or that any such acquisitions will be successful in achieving desired profitability objectives. Without suitable acquisitions or the capital to fund such acquisitions, the Company's future growth could be limited or even eliminated. As such, the Company is seeking additional financing from the Offerings and the TPG Purchase in order to reduce amounts outstanding under the Credit Facility and to better position the Company for future opportunities. SOURCES AND USES OF FUNDS. During the first nine months of 1997, the Company spent approximately $54.7 million on exploration and development expenditures and approximately $16.1 million on acquisitions. The exploration and development expenditures included approximately $38.2 million spent on drilling, $6.7 million on geological, geophysical and acreage expenditures and $9.8 million on workover costs. These expenditures were funded by available cash, bank debt and cash flow from operations. The Company anticipates that a total of approximately $10 million will be spent during 1997 on exploration expenditures $65 million on development expenditures, and $225 million on acquisitions. During 1996, the Company spent approximately $33.4 million on oil and natural gas development expenditures, $37.2 million on the Hess Acquisition, $7.5 million on properties acquired in April 1996 (the "Ottawa Acquisition"), $3.7 million on other minor oil and natural gas acquisitions, and approximately $5.1 million on geological, geophysical and acreage expenditures. The development expenditures included $15.5 million spent on drilling and $17.9 million spent on workover costs. These expenditures were funded during the year by bank debt, available cash and cash flow from operations, although the bank debt was retired with the proceeds from a public offering of Common Shares in October 1996. During 1995, the Company made $28.5 million in capital expenditures, with the single largest component being a $10.0 million acquisition of seven producing wells in the Gibson and Humphreys Fields located near the Company's other properties in southern Louisiana (the "Gibson Acquisition"). The balance of 1995 acquisition expenditures were for additional interests in the Company's Lirette Field in Louisiana ($2.9 million), interests in the Bully Camp Field, also in Louisiana ($2.1 million), and a few smaller acquisitions in both Mississippi and Louisiana. During 1995, the Company also spent $1.9 million drilling four wells in Mississippi, $1.1 million for acreage, geological and geophysical and delay rentals, and $8.1 million for workovers of existing properties. The 1995 expenditures were funded on an interim basis with cash flow from operations ($9.4 million) and bank debt ($19.4 million), which was repaid in December 1995 with a portion of the $39.5 million of net proceeds from a private placement of equity with TPG. Capital expenditures for 1994 were $16.9 million and included $10.3 million of development costs, primarily expended on natural gas properties in Louisiana, with the balance of $6.6 million expended on acquisitions of properties primarily in Louisiana, of which $5.5 million was spent on acquiring additional working interests in existing Company-operated properties. Expenditures in 1994 were principally funded by $6.2 million of cash provided by operations and net incremental debt of $8.8 million, of which $1.5 million came from the issuance of unsecured convertible debentures and the balance from bank debt. 29 30 RESULTS OF OPERATIONS OPERATING INCOME During the last three years, operating income has increased significantly as outlined in the following chart. Oil and gas revenue increased as a result of the increased oil and gas production and increases in oil and gas product prices.
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, ---------------------------- ------------------ 1994 1995 1996 1996 1997 ------- ------- -------- ------- -------- Operating income (in thousands) Oil sales............................ $ 6,767 $10,852 $ 28,475 $17,455 $ 36,436 Natural gas sales.................... 5,925 9,180 24,405 17,254 23,647 Less production expenses............. (4,309) (6,789) (13,495) (9,197) (15,737) ------- ------- -------- ------- -------- Operating income.................. $ 8,383 $13,243 $ 39,385 $25,512 $ 44,346 ======= ======= ======== ======= ======== Unit prices Oil price per Bbl.................... $ 13.84 $ 14.90 $ 18.98 $ 18.05 $ 17.53 Gas price per Mcf.................... 1.78 1.90 2.73 2.64 2.54 Netback per BOE Sales price.......................... $ 12.17 $ 13.05 $ 17.69 $ 16.87 $ 16.56 Production expenses.................. (4.13) (4.42) (4.51) (4.47) (4.34) ------- ------- -------- ------- -------- $ 8.04 $ 8.63 $ 13.18 $ 12.40 $ 12.22 ======= ======= ======== ======= ======== Average net daily production volume Bbls................................. 1,340 1,995 4,099 3,529 7,615 Mcf.................................. 9,113 13,271 24,406 23,867 34,061 BOE.................................. 2,858 4,207 8,167 7,507 13,292
COMPARISON OF YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996. Production increases have been fueled by both internal growth from the Company's development and exploration programs and from the acquisition of producing properties. Production on a BOE/d basis increased 47% between 1994 and 1995 with approximately 240 BOE/d attributable to the Gibson Acquisition and the balance of approximately 1,109 BOE/d primarily attributable to internal growth. Between 1995 and 1996, production increased 94% with approximately 2,550 BOE/d attributable to the properties acquired in the Hess and Ottawa Acquisitions and 750 BOE/d attributable to properties acquired in the Gibson Acquisition. The balance of approximately 660 BOE/d was attributable to internal growth on other properties. Oil and gas revenue has increased not only because of the large increase in production, but also due to improved product prices for these periods. Between 1994 and 1995, product price increases were relatively modest with an 8% increase in oil prices and a 7% increase in natural gas prices. The Company also realized an $800,000 gas hedging gain during 1995 which added $.17 per Mcf to its average natural gas price. The Company did not have any oil or natural gas hedges in place during 1996, nor does it have any currently in place due to the relatively strong commodity prices and the reduced debt levels of the Company. During 1996, product prices increased substantially with a 27% increase in the average oil price and a 44% increase in the average natural gas price. Coupled with the production increases, the Company's oil and natural gas revenue increased 164%, or $32.8 million, from 1995 to 1996. Approximately $16.5 million of the increase was related to properties acquired in the Hess and Ottawa Acquisitions, approximately $5.4 million to properties acquired in the Gibson Acquisition, approximately $7.7 million due to the increase in product prices and the balance of approximately $3.2 million due to increased production from internal growth on other properties. Production expenses increased each year along with the increases in production. On a BOE basis, production expenses increased 7% from 1994 to 1995 and increased 2% from 1995 to 1996. The increases were largely attributable to the changes in the mix of properties as the Mississippi oil properties tend to have a higher operating cost per BOE than the Louisiana gas properties. During the first two months of ownership 30 31 (May and June 1996), the production expenses averaged $6.27 per BOE on the Hess Acquisition properties which were more heavily weighted toward Mississippi oil than Louisiana gas. After assuming operations, these averages were brought more in line with the Company averages through cost savings and increased production levels. For the remainder of the year (July through December 1996) production expenses on these properties averaged $5.05 per BOE. COMPARISON OF NINE MONTHS ENDED SEPTEMBER 30, 1997 AND 1996. Production increases have been fueled by both internal growth from the Company's development and exploration programs and from the acquisition of producing properties during 1996, particularly the Hess Acquisition. During May and June of 1996, the first two months of ownership, the properties acquired in the Hess Acquisition averaged approximately 2,945 BOE/d. During the first, second and third quarters of 1997, the production from these same properties averaged approximately 4,385 BOE/d, 4,613 BOE/d and 5,373 BOE/d, respectively, a 49%, 57% and 82% increase, respectively, from initial production levels. Total corporate production on a BOE/d basis increased 21% from the fourth quarter of 1996 average of 10,132 BOE/d to the first quarter of 1997 average of 12,256 BOE/d, increased an additional 9% to 13,405 BOE/d for the second quarter of 1997 and an additional increase of 6% to 14,195 BOE/d for the third quarter of 1997. Since the Company has had only limited acquisitions since the Hess Acquisition, the production increases since June 30, 1996 were almost solely as a result of internal development. On a quarter to quarter comparison, production on a BOE basis increased 54% between the respective third quarters. When comparing the nine month periods, production on a BOE basis has increased 77%, reflecting the effect of the Hess Acquisition effective in May 1996. Oil and gas revenue has increased primarily because of the large increase in production. Oil product prices decreased by 3% and natural gas product prices declined 4% or an overall decline of 2% when measured on a BOE basis when comparing the nine months ended September 30, 1997 to the comparable period in 1996. During the first nine months of 1996, approximately 47% of the Company's production on a BOE basis was oil while during the first nine months of 1997, approximately 57% of the Company's production on a BOE basis was oil. Production expenses on an absolute basis increased between the relative periods of 1996 and 1997 along with the increases in production. On a BOE basis, production expenses decreased 3% when comparing the first nine months of 1996 to the first nine months of 1997. This improvement was a result of efficiencies achieved from higher production volumes (on both an absolute basis and per well basis) despite the Company having a higher percentage of oil production in 1997 as compared to 1996, which typically has a higher operating cost per BOE. GENERAL AND ADMINISTRATIVE EXPENSES As outlined below, general and administrative ("G&A") expenses have increased along with the Company's growth.
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, -------------------------- ----------------- 1994 1995 1996 1996 1997 ------ ------- ------- ------- ------- Net G&A expenses (in thousands) Gross expenses.......................... $2,475 $ 3,900 $ 8,407 $ 5,583 $ 9,999 State franchise taxes................... 65 100 213 159 308 Operator overhead charges............... (890) (1,438) (2,916) (1,906) (3,789) Capitalized exploration expenses........ (480) (630) (1,224) (851) (1,675) ------ ------- ------- ------- ------- Net expenses............................ $1,170 $ 1,932 $ 4,480 $ 2,985 $ 4,843 ====== ======= ======= ======= ======= Average G&A cost per BOE.................. $ 1.12 $ 1.25 $ 1.50 $ 1.45 $ 1.33 Employees as of end of period............. 27 51 122 109 141
COMPARISON OF YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996. On a BOE basis, these costs increased 12% from 1994 to 1995 and increased 20% from 1995 to 1996. Part of the increase in 1995 was attributable to $190,000 of costs ($0.12 per BOE) related to non-recurring personnel changes. As a result of improved 31 32 financial results during the first quarter of 1996 and other factors, the Company conducted a review of salaries and awarded increases and bonuses in February 1996 to its employees. Bonuses, including related payroll taxes, amounted to approximately $225,000 ($0.08 per BOE). During 1996, the Company also accrued $545,000 ($0.18 per BOE) for bonuses which were awarded in February 1997. In addition, the Company began to increase its staff levels during the second quarter of 1996 to handle the Hess Acquisition, but was not entitled to any operator's overhead recovery on these properties until July 15, 1996, resulting in a further increase in general and administrative cost per BOE, as Amerada Hess remained the operator of record until that date. COMPARISON OF NINE MONTHS ENDED SEPTEMBER 30, 1997 AND 1996. On a BOE basis, G&A expenses declined 8% when comparing the first nine months of 1996 to the comparable period in 1997. The decrease is partially attributable to the increased production on both an absolute and per well basis. Furthermore, the respective well operating agreements allow the Company, when it is the operator, to charge a well with a specified overhead rate during the drilling phase. As a result of the increased drilling activity in 1997, the percentage of gross G&A recovered through these types of allocations (listed in the above table as "Operator overhead charges") increased when compared to the corresponding periods of 1996. During the first nine months of 1996, approximately 34% was recovered by operator overhead charges, while during the comparable period of 1997 this increased to 38%. This trend is even more pronounced in the third quarter of 1997 with 42% of the gross G&A recovered as compared to 35% for the third quarter of 1996. INTEREST AND FINANCING EXPENSES
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, --------------------------- ------------------ 1994 1995 1996 1996 1997 ------- ------- ------- -------- ------- (IN THOUSANDS, EXCEPT PER UNIT AMOUNTS) Interest expense....................... $ 1,146 $ 2,085 $ 1,993 $ 1,530 $ 387 Non-cash interest expense.............. (86) (90) (459) (345) (64) ------- ------- ------- ------- ------ Cash interest expense.................. 1,060 1,995 1,534 1,185 323 Interest and other income.............. (23) (77) (769) (425) (986) ------- ------- ------- ------- ------ Net interest expense................. $ 1,037 $ 1,918 $ 765 $ 760 $ (663) ======= ======= ======= ======= ====== Average interest cost per BOE.......... $ 0.99 $ 1.26 $ 0.26 $ 0.37 $(0.18) Average debt outstanding............... 12,200 21,400 19,500 20,673 3,610 Ratio of earnings to fixed charges..... 2.6x 1.5x 4.4x 3.1x 34.9x Imputed preferred dividend............. $ -- $ -- $ 1,281 $ 1,153 $ -- Loss on early extinguishment of debt... -- 200 440 440 --
During the first half of 1996 and 1997, the Company had minimal debt outstanding as virtually all of the bank debt had been retired during the previous fourth quarter. In 1995, the bank debt was repaid with proceeds from the December 1995 private placement of equity with TPG and in 1996, the debt was repaid with proceeds from a public offering of Common Shares completed in October 1996. However, in 1996, the Company did incur debt late in the second quarter in order to fund property acquisitions and, during the third quarter of 1997, the Company borrowed approximately $20 million to fund $12.5 million of property acquisitions and $7.5 million of development expenditures. The private placement of equity in December 1995 with TPG included 1.5 million shares of Convertible Preferred. During 1996, the Company recognized $1.3 million of charges representing the imputed preferred dividend until October 30, 1996 when the Convertible Preferred were converted into 2.8 million Common Shares. Under Canadian generally accepted accounting principles, this dividend was reported as an operating expense, while under U.S. generally accepted accounting principles this would not be an expense but it would be deducted from net income to arrive at net income attributable to the common shareholders. In addition to paying off its bank debt and converting the Convertible Preferred into common equity during 1996, the Company also converted its remaining subordinated debt into common equity, leaving the Company essentially debt-free as of December 31, 1996. 32 33 During 1996, the Company had a $440,000 charge relating to a loss on early extinguishment of debt. These costs related to the remaining unamortized debt issue costs of the Company's prior credit facility which was replaced in May 1996, as previously discussed. The Company also had a charge of $200,000 during the first half of 1995 for the same type of expense relating to a previous bank debt refinancing. Under U.S. generally accepted accounting principles, a loss on early extinguishment of debt would be an extraordinary item rather than a normal operating expense as required by Canadian generally accepted accounting principles. DEPLETION, DEPRECIATION AND SITE RESTORATION COMPARISON OF YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996. DD&A has increased along with the additional capitalized cost and increased production. DD&A per BOE has increased 30% from 1994 to 1995 and 15% from 1995 to 1996 primarily due to 59% of the 1995 capital expenditures and 56% of the 1996 expenditures relating to property acquisitions, which had a higher per unit cost for the Company than those reserves added by development expenditures. COMPARISON OF NINE MONTHS ENDED SEPTEMBER 30, 1997 AND 1996. The Company's DD&A rate per BOE for the first half of 1997 increased to $6.50 per BOE to provide for the estimated effect of reduced oil prices on reserve quantities, the estimated effect of rising drilling costs on certain proved undeveloped locations, and higher than anticipated costs on wells drilled in Louisiana that were proved undeveloped locations at December 31, 1996. In comparison, the Company's DD&A rate was $5.99 per BOE for the year ended December 31, 1996. The oil prices used in the December 31, 1996 reserve report were based on a WTI posting price of $23.39 per Bbl in accordance with the rules of the Commission while the comparable WTI price at June 30, 1997 was $17.15 per Bbl. This reduction in oil prices reduced the June 30, 1997 estimated reserves by approximately 1.3 MMBbls. As a result of two oil and natural gas discoveries announced in September, 1997, the Company's third quarter DD&A rate decreased to $6.22 per BOE ($6.40 per BOE for the nine months ended September 30, 1997). During the third quarter of 1997, the Company also transferred approximately $4.6 million from the unevaluated properties to the full cost pool reflecting activity on these properties, leaving a balance of approximately $6.4 million in unevaluated properties as of September 30, 1997. The DD&A effect of this transfer was approximately $440,000 for the quarter. The Company also provides for the estimated future costs of well abandonment and site reclamation, net of any anticipated salvage, on a unit-of-production basis. This provision is included in the DD&A expense and has increased each year along with an increase in the number of properties owned by the Company.
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, ------------------------- ----------------- 1994 1995 1996 1996 1997 ------ ------ ------- ------- ------- (IN THOUSANDS, EXCEPT PER UNIT AMOUNTS) Depletion and depreciation............... $4,177 $7,918 $17,533 $12,430 $22,899 Site restoration provision............... 32 104 371 127 325 ------ ------ ------- ------- ------- Total amortization....................... $4,209 $8,022 $17,904 $12,557 $23,224 ====== ====== ======= ======= ======= Average DD&A cost per BOE................ $ 4.03 $ 5.22 $ 5.99 $ 6.10 $ 6.40
33 34 INCOME TAXES Due to net operating losses by its U.S. subsidiary each year for tax purposes, the Company does not have any current tax provision. The deferred tax provision as a percentage of net income has varied depending on the mix of Canadian and U.S. expenses. The rate declined from 1994 to 1995 as there were less Canadian expenses, but increased again slightly in 1996 due to the non-deductible imputed preferred dividend and interest on the subordinated debt.
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, ------------------------- ----------------- 1994 1995 1996 1996 1997 ------ ------ ------- ------- ------- Deferred income taxes (thousands)........ $ 718 $ 367 $ 5,312 $ 2,932 $ 6,245 Average income tax costs per BOE......... 0.69 0.24 1.78 1.43 1.72 Effective tax rate....................... 38% 34% 38% 40% 37%
NET INCOME Primarily as a result of increased production and improved product prices, net income and cash flow from operations increased substantially between 1995 and 1996 as outlined below. Between 1994 and 1995, net income decreased 39% as a result of certain nonrecurring charges and a disproportionate increase in DD&A as compared to the increase in revenue. Net income and cash flow from operations increased substantially on both a gross and per share basis between the first nine months of 1996 and the first nine months of 1997 as outlined below.
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, ------------------------- ----------------- 1994 1995 1996 1996 1997 ------ ------ ------- ------- ------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Net income............................... $1,163 $ 714 $ 8,744 $ 4,340 $10,633 Net income per common share: Primary................................ 0.19 0.10 0.67 0.37 0.53 Fully diluted.......................... 0.19 0.10 0.62 0.36 0.50 Cash flow from operations(a)............. 6,185 9,394 34,140 21,767 40,166
- --------------- (a) Represents cash flow provided by operations, exclusive of the net change in non-cash working capital balances. 34 35 The following table summarizes the cash flow, DD&A and net income on a BOE basis for the comparative periods. Each of the individual components are discussed above.
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, ------------------------ --------------- 1994 1995 1996 1996 1997 ------ ------ ------ ------ ------ Per BOE data Revenue................................... $12.17 $13.05 $17.69 $16.87 $16.56 Production expenses....................... (4.13) (4.42) (4.51) (4.47) (4.34) ------ ------ ------ ------ ------ Production netback........................ 8.04 8.63 13.18 12.40 12.22 General and administrative................ (1.12) (1.25) (1.50) (1.45) (1.33) Interest.................................. (0.99) (1.26) (0.26) (0.37) 0.18 ------ ------ ------ ------ ------ Cash flow from operations(a)........... 5.93 6.12 11.42 10.58 11.07 DD&A...................................... (4.03) (5.22) (5.99) (6.10) (6.40) Deferred income taxes..................... (0.69) (0.24) (1.78) (1.43) (1.72) Other non-cash items...................... (0.10) (0.19) (0.72) (0.94) (0.02) ------ ------ ------ ------ ------ Net income............................. $ 1.11 $ 0.47 $ 2.93 $ 2.11 $ 2.93 ====== ====== ====== ====== ======
- --------------- (a) Represents cash flow provided by operations, exclusive of the net change in non-cash working capital balances. YEAR 2000 MODIFICATIONS The Company is currently reviewing its computer systems in order to evaluate necessary modifications for the year 2000. The Company does not currently anticipate that it will incur material expenditures to complete any such modifications. RECENTLY ISSUED ACCOUNTING STANDARDS See discussion of Recently Issued Accounting Standards in Note 7 of the Consolidated Financial Statements. 35 36 BUSINESS AND PROPERTIES THE COMPANY Denbury is an independent energy company engaged in acquisition, development and exploration activities in the U.S. Gulf Coast region, primarily onshore in Louisiana and Mississippi. The Company believes the Gulf Coast represents one of the most attractive regions in North America given the region's prolific production history, complex geology (with multiple producing horizons) and the opportunities that have been created by advanced technologies such as 3-D seismic and various drilling, completion and recovery techniques. As of December 31, 1997, the Company had proved reserves of 52.0 MMBbls and 77.2 Bcf or 64.9 MMBOE, including 27.6 MMBOE attributable to the Chevron Acquisition. At such date, the PV10 Value of these reserves was $361.3 million, of which $276.5 million was attributable to proved developed reserves. Denbury operates wells comprising approximately 83% of its PV10 Value. The eight largest fields in which the Company has an interest constitute approximately 82% of its estimated proved reserves and, within these eight fields, Denbury owns an average working interest of 91%. Over the last four years, the Company has achieved rapid growth in proved reserves, production and cash flow by concentrating on the acquisition of properties which it believes have significant upside potential and through the efficient development, enhancement and operation of its properties. For the four-year period ended December 31, 1997, the Company increased its proved reserves at a compound annual growth rate of 83%, from 5.8 MMBOE to 64.9 MMBOE. Over the four-year period ended December 31, 1996, the Company also increased its average net daily production at a compound annual growth rate of 90%, from 1,193 BOE/d to 8,167 BOE/d, with a further increase to 14,195 BOE/d for the third quarter of 1997. For the same four-year period, EBITDA increased at a compound annual growth rate of 126%, from $3.0 million to $34.9 million. EBITDA for the twelve months ended September 30, 1997 was $51.9 million. Since 1993, when the Company began to focus its operations exclusively in the United States, through December 31, 1995, the Company spent a total of $43.4 million on acquisitions. In May 1996, the Company acquired properties in its core areas of Mississippi and Louisiana from Amerada Hess for approximately $37.2 million. As of June 30, 1996, these acquired properties were producing approximately 2,945 BOE/d and had proved reserves of approximately 5.9 MMBOE. Since that date, the Company's extensive development and exploitation on these properties has resulted in an 82% increase in their production to 5,373 BOE/d for the third quarter of 1997 and a 141% increase in their proved reserves to 14.2 MMBOE as of December 31, 1997. On December 30, 1997, the Company acquired oil properties in the Heidelberg Field, which is adjacent to the Company's other primary oil properties in Mississippi, from Chevron for approximately $202.0 million. These properties are located approximately nine miles from the Eucutta Field, the property with the highest PV10 Value of those acquired by the Company in the Hess Acquisition. The estimated proved reserves as of January 1, 1998 for the Chevron Acquisition properties are approximately 27.6 MMBOE, with average net daily production of approximately 2,940 BOE/d for the third quarter of 1997. As a result of the significant amount of future development and exploitation to be performed on these properties and the increase in future reserves and production that the Company expects to result from such development and exploitation, the Company has attributed approximately $75.0 million of the purchase price to unevaluated properties. The Company believes that the properties acquired in the Chevron Acquisition provide exploitation opportunities similar to those of the Mississippi properties acquired in the Hess Acquisition and the Company intends to apply the same technologies to the Heidelberg Field. The Company's estimated 1998 development budget for the Heidelberg Field is approximately $30.0 million. See "-- Acquisition of Chevron Properties." BUSINESS STRATEGY The Company seeks to: (i) achieve attractive returns on capital through prudent acquisitions, development and exploratory drilling and efficient operations; (ii) maintain a conservative balance sheet to preserve maximum financial and operational flexibility; and (iii) create strong employee incentives through equity ownership. The Company believes that its growth to date in proved reserves, production and cash flow is a direct result of its adherence to several fundamental principles which are at the core of the Company's long- 36 37 term growth strategy. The Company's long-term growth strategy includes the following fundamental principles: REGIONAL FOCUS. The Company intends to continue the regional focus of its operations. By focusing its efforts in the Gulf Coast region, primarily Louisiana and Mississippi, the Company has been able to accumulate substantial geological and reservoir data and operating experience which it believes provides it with significant competitive advantages. For example, the Company believes it is better able to identify, evaluate and negotiate potential acquisitions, and develop and operate its properties in an efficient and low- cost manner. The Company believes the Gulf Coast represents one of the most attractive regions in North America given the region's prolific production history, complex geology (with multiple producing horizons) and the opportunities that have been created by advanced technologies such as 3-D seismic and various drilling, completion and recovery techniques. Moreover, because of the region's proximity to major pipeline networks serving important northeastern U.S. markets, the Company typically realizes natural gas prices in excess of those realized in many other producing regions. DISCIPLINED ACQUISITION STRATEGY. The Company intends to continue to acquire properties where it believes significant additional value can be created. Such properties are typically characterized by: (i) long production histories; (ii) complex geological formations with multiple producing horizons and substantial exploitation potential; (iii) a history of limited operational focus and capital investment, often due to their relatively small size and limited strategic importance to the previous owner; and (iv) the potential for the Company to gain control of operations. The Company believes that due to continuing rationalization of properties, primarily by major integrated and independent energy companies, future acquisition opportunities should continue to be available. In addition, the Company seeks to maintain a well-balanced portfolio of oil and natural gas development, exploitation and exploration projects in order to minimize the overall risk profile of its investment opportunities while still providing significant upside potential. The recent Hess and Chevron Acquisitions are examples of the types of opportunities the Company seeks. OPERATION OF HIGH WORKING INTEREST PROPERTIES. The Company intends to continue to acquire working interest positions that give it operational control or that the Company believes may lead to operational control. As the operator of properties comprising approximately 83% of its total PV10 Value, the Company believes it is better able to manage and monitor production and more effectively control expenses, the allocation of capital and the timing of field development. Once a property is acquired, the Company employs its technical and operational expertise to fully evaluate a field's future potential. If favorable, it will consolidate its working interest positions, primarily through negotiated transactions, which tend to be attractively priced compared to acquisitions available in competitive situations. The consolidation of ownership allows the Company to: (i) enhance the effectiveness of its technical staff by concentrating on relatively few wells; (ii) increase production while adding virtually no additional personnel; and (iii) increase ownership in a property so that the potential benefits of value enhancement activities justify the allocation of Company resources. EXPLOITATION OF PROPERTIES. The Company intends to maximize the value of its properties through a combination of increasing production, increasing recoverable reserves or reducing operating costs. During 1997, the Company's primary methodology for achieving these objectives was the use of horizontal drilling, which it also intends to emphasize in 1998. Horizontal drilling has historically produced oil at faster rates and with lower operating costs on a BOE basis than traditional vertical drilling. The Company also utilizes a variety of other techniques to maximize property values, including: (i) undertaking surface improvements such as rationalizing, upgrading or redesigning production facilities; (ii) making downhole improvements such as resizing downhole pumps or reperforating existing production zones; (iii) reworking existing wells into new production zones with additional potential; and (iv) utilizing exploratory drilling, which is frequently based on various advanced technologies such as 3-D seismic. EXPERIENCED AND INCENTIVIZED PERSONNEL. The Company intends to maintain a highly competitive team of experienced and technically proficient employees and motivate them through a positive work environment and stock ownership in the Company. The Company's 29 geological and engineering professionals have an average of over 15 years of experience in the Gulf Coast region. The Company believes that employee ownership, which is encouraged through the Company's stock option and stock purchase plans, is essential for attracting, 37 38 retaining and motivating quality personnel. As of January 1, 1998, approximately 86% of the Company's employees were participating in the Company's stock purchase plan. The Company believes that all employees are important to the success of the Company and as such grants bonuses and stock options to both management and employees on a basis roughly proportional to salaries. OIL AND NATURAL GAS OPERATIONS Denbury operates in two core areas, Louisiana and Mississippi. The Company operates 67 wells in Louisiana from an office in Houma and 161 wells in Mississippi from an office in Laurel. The eight largest oil and natural gas fields owned by the Company constitute approximately 85% and 82%, respectively, of its total proved reserves on a BOE and PV10 Value basis. Within these eight fields, Denbury owns an average 91% working interest and operates 85% of the wells, which comprise 71% of the Company's PV10 Value. The Company's eight largest fields are located in three adjacent counties in Mississippi and one parish in Louisiana. This concentration of value in a relatively small number of fields allows the Company to benefit substantially from any operating cost reductions or production enhancements and allows the Company to effectively manage the properties from its two field offices. These two core areas are similar in that the major trapping mechanisms for oil and natural gas accumulations are structural features usually related to deep-seated salt or shale movement. Both areas typically feature fields with mostly multiple sandstone reservoirs supported by strong waterdrives. However, the two areas differ significantly in drilling costs, risks and the size of potential reserves. In Mississippi, the producing zones are generally shallower than in Louisiana and therefore drilling and workover costs are lower. However, the geological complexity of southern Louisiana, which is more expensive to exploit, creates the potential for larger discoveries, particularly of natural gas. The Company's production in Louisiana is predominately natural gas, while Mississippi is predominately oil. The following table sets forth information with respect to Denbury's properties, reserves and drilling and production activities. The information included in this table about the Company's proved oil and natural gas reserve estimates as of December 31, 1997 were prepared by Netherland & Sewell. See "Risks Factors -- Uncertainty of Estimates of Oil and Natural Gas Reserves."
AVERAGE NET PRODUCTION AS OF PROVED RESERVES THIRD QUARTER OF SEPTEMBER 30, AS OF DECEMBER 31, 1997 1997(A) 1997 --------------------------------------- ----------------------- --------------------- PV10 AVERAGE NATURAL PV10 VALUE NATURAL GROSS NET OIL GAS VALUE % OF OIL GAS PRODUCTIVE REVENUE (MBBLS) (MMCF) (000'S)(B) TOTAL (BBLS/D) (MCF/D) WELLS(C) INTEREST -------- ------- ---------- ----- ---------- --------- ---------- -------- LOUISIANA Lirette..................... 289 27,746 44,668 12.4% 161 11,983 18 63.0% Gibson...................... 302 6,631 12,658 3.5% 196 4,602 3 57.8% South Chauvin............... 135 7,333 9,734 2.7% 48 3,029 4 73.4% Bayou Rambio................ 69 11,353 18,205 5.0% 45 3,254 3 59.1% Other Louisiana............. 1,423 15,048 33,192 9.2% 1,186 10,232 82 48.7% ------ ------ ------- ----- ----- ------ --- Total Louisiana........... 2,218 68,111 118,457 32.8% 1,636 33,100 110 51.5% ------ ------ ------- ----- ----- ------ --- MISSISSIPPI Heidelberg(d)............... 30,171 2,517 118,973 32.9% -- -- -- -- Eucutta..................... 8,967 -- 58,657 16.2% 1,895 -- 45 75.3% Davis....................... 2,660 -- 13,348 3.7% 1,033 -- 25 90.5% Quitman..................... 3,032 -- 19,064 5.3% 1,914 -- 18 60.7% Other Mississippi........... 4,834 5,597 29,667 8.2% 1,594 2,716 87 53.1% ------ ------ ------- ----- ----- ------ --- Total Mississippi........... 49,664 8,114 239,709 66.3% 6,436 2,716 175 66.5% ------ ------ ------- ----- ----- ------ --- Other......................... 136 966 3,163 0.9% 76 466 -- -- ------ ------ ------- ----- ----- ------ --- Company Total................. 52,018 77,191 361,329 100.0% 8,148 36,282 285 60.7% ====== ====== ======= ===== ===== ====== ===
- --------------- 38 39 (a) This table does not include production on the properties acquired in the Chevron Acquisition. See "-- Production Volumes, Sales Prices and Production Costs" for pro forma production data. (b) The reserves were prepared using constant prices and costs in accordance with the guidelines of the Commission, based on the prices received on a field by field basis as of December 31, 1997. The oil price at that date was WTI $16.18 per Bbl adjusted by field and a NYMEX natural gas price average of $2.58 per MMBtu, also adjusted by field. (c) Includes only productive wells in which the Company has a working interest as of September 30, 1997. (d) Includes properties acquired in the Chevron Acquisition, as well as properties acquired in three other minor acquisitions in the same field. The average net production on the properties acquired in the Chevron Acquisition from July 1, 1997 through September 30, 1997 was 2,840 Bbls/d and 600 Mcf/d from 122 gross productive wells with an average net revenue interest of 81%. MISSISSIPPI OPERATING AREA In Mississippi, most of the Company's production is oil, produced largely from depths of less than 10,000 feet. Fields in this region are characterized by relatively small geographic areas which generate prolific production from multiple pay sands. The Company's Mississippi production is usually associated with large amounts of saltwater, which must be disposed of in saltwater disposal wells, and almost all wells require pumping. These factors increase the operating costs on a per barrel basis as compared to Louisiana. The Company places considerable emphasis on reducing these costs in order to maximize the cash flow from this area. The Company has increased its emphasis in horizontal drilling based on its apparent success during the past year. These horizontal wells have contributed to the reduction of operating costs on a BOE basis during the last twelve months, as these wells typically produce oil more efficiently, resulting in higher production rates and better recovery efficiency. The Company drilled its first horizontal well in 1995 at the South Thompson Creek Field in Mississippi and drilled a subsequent horizontal well in this field during 1996. Both of these wells were completed as producers. During the last quarter of 1996 and through the end of 1997, the Company completed twelve horizontal wells at an average cost of $1,050,000. These wells produced at an average production rate of 420 Bbls/d in their initial month of production. Although horizontal wells typically decline rapidly from their initial production rates, these twelve wells had an average production rate of 280 Bbls/d for the month of December 1997 and have been producing for an average of seven months. These horizontal wells typically have a higher internal rate of return than a comparable vertical well, reduce operating costs per BOE and reduce the number of wells required to drain the reservoir. The Company plans to drill over 50 horizontal wells in 1998 in Mississippi. HEIDELBERG FIELD. Heidelberg field was discovered in 1944 and has produced an estimated 191 MMBbls and 36 Bcf since its discovery. This Field is a large salt-cored anticline which is divided by faulting into a western and eastern half. Production is from a series of normally pressured Cretaceous and Jurassic sandstone horizons situated between 4,500 feet and 11,500 feet. There are 11 producing formations in the Heidelberg Field containing 44 individual reservoir intervals, with the majority of the current production coming from the Eutaw and Christmas sands at depths of approximately 5,000 feet. The West Heidelberg Eutaw sands have been unitized and water injection began late in 1996 in order to increase the bottom hole pressure and improve recoveries from the formation. A production response to the injection is expected during 1998. The Eutaw East One Fault Block Oil Pool Unit (Eutaw formation in East Heidelberg) was unitized in October 1997 and injection is projected to commence in March 1998. These waterflood projects, particularly the East Unit, comprise a significant portion of the potential reserves at Heidelberg. The Company has a 78% working interest in the East Unit, 59% of which was acquired in the Chevron Acquisition and the remaining 19% of which was acquired over a three-month period from three other entities. The Company operates a similar Eutaw unit at its East Eucutta Field, located approximately nine miles to the southeast, with production from sands with similar porosity, permeability, thickness and drive mechanisms. 39 40 The Company has identified several potential development projects during its initial evaluation of the Heidelberg Field. These include initiating a waterflood project, upgrading lift capacity in over 15 wells and recompleting 30 wells in new zones. In addition, the Company has identified over 40 potential drilling locations in addition to other potential secondary and tertiary recovery projects. Horizontal wells drilled by the Company in 1997 at nearby Davis, Quitman and Eucutta Fields improved daily production rates significantly as compared to vertical wells drilled in the same fields. Consequently, the Company anticipates that 30 of the 40 proposed future wells will be horizontal wells. The Company's total 1998 development budget for the Heidelberg Field is approximately $30 million. Based on its experience in other fields in the same area, the Company believes that significant additional reserve potential may exist beyond the identified proven reserves. The development budget in 1998 and ensuing years is expected, in part, to be used to evaluate this potential which is summarized below: Higher Oil Recovery in the Eutaw Sand Waterfloods. Since discovery of the Heidelberg Field, total cumulative production in the Eutaw formation through December 1997 has been 80 MMBbls, which, based upon geological and engineering analysis, the Company estimates has recovered 22% of the original oil in place. Based upon a similar analysis, the Company estimates that historical cumulative production from the Eutaw formation under waterflood at nearby East Eucutta Field has recovered an estimated 34% of the oil in place. The Company believes that similar recovery factors may be achievable at Heidelberg Field based on the geological conditions that appear to be analogous. The Company will also attempt to improve the recovery factors through the use of horizontal drilling and may also employ tertiary recovery methods such as carbon dioxide injection. The Company currently is evaluating the feasibility of such methods. Higher Oil Recovery in the Christmas Sands. Because of the success of the Company's horizontal drilling program in other fields in the area, the Company intends to develop the Christmas sands primarily through horizontal drilling. Since its discovery, the Christmas sands have produced approximately 67 MMBbls through December 1997. The Company believes these sands are ideal for horizontal development due to the strong natural water drive of these reservoirs. Recent horizontal drilling by the Company has produced oil at faster rates and reduced operating costs on a BOE basis as compared to vertical drilling. Although Denbury believes that horizontal drilling should ultimately increase the amount of oil recovered from the Christmas sands, to date the Company does not have enough production history to determine if, and to the extent, oil recoveries will increase. Further Drilling in Deeper Zones. The zones below the Christmas formation including the Tuscaloosa, Paluxy, Rodessa, Hosston, Cotton Valley and Smackover formations, have produced on a cumulative basis a combined 44 MMBbls and 14 Bcf through December 1997. The Company believes that additional reserve potential may exist for extensions of existing reservoirs and potential new reservoirs in these zones within the Heidelberg Field area. A 36-square mile 3-D seismic program over the field was shot by Chevron in 1993 and will be acquired under license by Denbury. The Company intends to reprocess the 3-D seismic data to evaluate this potential. EUCUTTA FIELD. The Eucutta Field is located about 18 miles east of Laurel, Mississippi. Since its discovery in 1943, this field has produced 63 MMBbls and 4.7 Bcf. Denbury acquired the majority of its interests in this field as part of the Hess Acquisition and currently operates 45 producing oil wells and 3 saltwater injection wells. Most of the wells produce oil with large amounts of saltwater, which requires pumping and disposal. The Eucutta Field is divided into a shallow Eutaw sand unit in which the Company has a 78% working interest and the deeper Tuscaloosa, Wash-Fred, Paluxy, Rodessa, Sligo and Hosston sand zones in which the Company has a 100% working interest. The Eucutta Field traps oil in multiple sandstone reservoirs from the Eutaw to the Hosston Formations in this highly faulted anticline from depths of 5,000 to 11,000 feet. Denbury recently established new production in the Paluxy interval in a series of six stacked sands. Two additional delineation wells have been drilled and completed for this interval and the Company currently plans to drill six horizontal wells to fully develop this new area. The deeper intervals of the Cotton Valley and Smackover formations have yet to be tested in crestal positions on this structure although these two horizons have proved to be highly productive throughout the Mississippi Salt Basin. 40 41 Since its acquisition in May 1996, the Company has implemented a capital expenditure program at Eucutta Field which included upgrading production facilities, recompletions and drilling wells. At the time of acquisition, production from this field was approximately 1,100 Bbls/d. All seven wells drilled in 1997 were successful, two of which were horizontal wells. As a result of these wells and other development work, during December 1997 the net production increased to an average of 2,976 Bbls/d. The Company plans to shoot a 3-D seismic survey over the field and have it processed by late 1998. During 1998, the Company also plans to drill 16 wells, of which nine will be horizontal wells. DAVIS FIELD. The Davis Field is located 42 miles northeast of Laurel in the northern part of the Mississippi salt basin. Denbury operates 36 producing wells within the area. Davis is a compact anticline that has produced over 21 MMBbls since its discovery by Conoco in 1969. Over 30 sands have produced oil between the intervals of 5,000 feet and 8,000 feet. At the time of acquisition in 1993, the gross production from this field was approximately 700 Bbls/d. During the month of December 1997, the gross production was approximately 960 Bbls/d with net production of 870 Bbls/d. The Davis Field is a relatively mature field and produces large amounts of saltwater. During December 1997, the field produced an average of approximately 53,000 barrels of saltwater per day, all of which were re-injected into the ground. The Company places considerable emphasis on controlling operating costs in this field by minimizing the cost of saltwater disposal and pumping equipment. Since acquiring the majority of the Davis Field in 1993, Denbury has undertaken an active redevelopment program including numerous workovers and five development wells. As a result of this work and continued reductions in operating costs, the Company has been able to steadily increase the proven reserves every year. During 1996, the Company drilled two successful horizontal wells to improve withdrawal efficiency and drilled an additional three horizontal wells in 1997, with one additional well in progress as of December 31, 1997. The Company plans to drill five wells in this field in 1998 of which four will be horizontal wells. QUITMAN FIELD. The Quitman Field is located in Clarke County, Mississippi, 31 miles northeast of Laurel and near the Davis Field. The Company acquired the field as part of the Hess Acquisition and now operates 18 producing wells. The Company owns an average working interest of 93%. The Quitman Field was discovered in 1966 and has since produced approximately 21 MMBbls from 18 separate reservoirs between 7,500 feet and 12,000 feet. The principal producing zones at Quitman Field are the Smackover formation and several sands in the Cotton Valley formation. Since its acquisition in May, 1996, the Company has implemented a capital expenditure program at Quitman Field which has included upgrading production facilities and drilling wells. At the time of acquisition, the net production from this field was approximately 200 Bbls/d. During December 1997, the net production averaged 1,676 Bbls/d. All five wells drilled in 1997 were successful, of which two were horizontal wells. During 1998, the Company plans to drill four wells, of which three will be horizontal wells. OTHER MISSISSIPPI FIELDS. In addition to the above fields, Denbury owns an interest in wells in 35 other fields in Mississippi, which in the aggregate averaged approximately 1,728 Bbls/d and 2.5 MMcf/d of net production during December 1997. LOUISIANA OPERATING AREA The Company's southern Louisiana producing fields are typically large structural features containing multiple sandstone reservoirs. Current production depths range from 7,000 feet to 16,000 feet with potential throughout the area for even deeper production. The region produces predominantly natural gas, with most reservoirs producing with a water-drive mechanism. The majority of the Company's southern Louisiana fields lie in the Houma embayment area of Terrebonne and LaFourche Parishes. The area is characterized by complex geological structures which have produced prolific reserves, typical of the lower Gulf Coast geosyncline. Given the swampy conditions of southern Louisiana, 3-D seismic has only recently become feasible for this area as improvements in field recording techniques have made the process more economical. 3-D seismic has become a valuable tool in exploration and development throughout the onshore Gulf Coast and has been pivotal in discovering 41 42 significant reserves. The Company currently owns or has license to work on over 300 square miles of 3-D seismic data and plans to continue to expand its data ownership. The Company believes that this 3-D seismic data, some of which is the first 3-D shot in these swampy areas, has the potential to identify significant exploration prospects, particularly in the deeper geopressured sections below 12,000 feet. During 1995, the Company acquired approximately 46 square miles of 3-D seismic data over five of its existing fields in Southern Louisiana, namely Bayou Rambio, De Large, North Deep Lake, Gibson and Humphreys. During 1996, the Company entered into a joint venture agreement with two industry partners and shot approximately 158 square miles of 3-D seismic data in the Terrebonne Parish area, which includes three of the Company's existing fields, Lirette, Lapeyrouse and North Lapeyrouse. The Company's existing productive zones are excluded from the joint venture. Denbury owns a one-third interest in any new prospects discovered through this joint venture that currently owns rights to over 35,000 acres within the survey area. The 3-D seismic survey is complete and two wells have been drilled to date based on the results of the survey. One was a dry hole and the other a successful well in the Lirette Field area. There are currently 10 identified prospect areas which have been generated as a result of the survey, of which three should be drilled during the first half of 1998. The 3-D seismic survey is still being reviewed for additional drilling opportunities. LIRETTE FIELD. The Lirette structure is a large salt-cored anticline located about 10 miles south of Houma, Louisiana, which has produced over one Tcf of natural gas from multiple reservoirs. The field is located in six to ten feet of inland water and produces from depths of 8,000 feet to 16,000 feet. The field was discovered in 1937, but in 1993, when the Company first acquired a 23% working interest in the field, gross production had declined to less than 3 MMcf/d. By January 1995, following a series of workovers of existing wells, gross production had grown to approximately 13.2 MMcf/d and 360 Bbls/d (6.5 MMcf/d and 150 Bbls/d net). Additional interests were acquired in 1995 and 1997 to increase the Company's ownership to its current average 82% working interest. During December 1997 the net production from this field averaged approximately 10.6 MMcf/d and 179 Bbls/d from 18 wells. During the latter half of 1996, the Lirette Field was covered by a 3-D seismic survey which is currently being evaluated. One well was drilled in the Lirette area in 1997, the Scana No. 1 Laterre, as a result of this 3-D seismic survey. This well established two pay sands in the prolific Tex W interval a southern untested fault block. Two additional untested fault blocks have been identified on the Lirette structure and are scheduled for drilling during 1998. GIBSON FIELD. In late 1994, Denbury acquired minor working interests in five wells in the Gibson and adjacent Humphreys Fields located in Terrebonne Parish, 20 miles northwest of the Lirette Field, in the northern part of the Houma embayment. The Gibson Field, since its discovery in 1937, has produced over 813 Bcf and 14 MMBbls. During 1995, the Company acquired and processed 38 square miles of 3-D seismic data covering these fields and in November 1995 acquired a additional working interest in these fields. By December 1995, Denbury's acreage position had grown to 3,165 net acres with interests in three active wells and five inactive wells. During December 1997, the net production in this field averaged approximately 5.4 MMcf/d and 105 Bbls/d. Denbury drilled two wells in this area in 1997, one of which was successful. This well, the Pelican A-12, found two productive intervals and was completed in the lower most formation. This well produced at an average rate of 442 Mcf/d, net to the Company, during the month of December 1997. No wells are currently planned in this field for 1998. SOUTH CHAUVIN FIELD. In February 1996, the Company purchased interests in two producing wells and four non-producing wells in South Chauvin Field located in the Houma embayment area, about four miles south of Houma and six miles northwest of Lirette Field. Of the four currently producing wells at Chauvin, the Company owns an average 94% working interest. During December 1997, the net production from this field averaged 4.2 MMcf/d and 85 Bbls/d. In late 1996, the Company acquired 13.7 square miles of 3-D seismic data covering the field and is currently evaluating the data. The Company drilled one well in this area in 1997 which produced at an average rate of 2.9 MMcf/d and 72 Bbls/d, net to the Company, during the month of December 1997. One well, a sidetrack of an existing well, is currently planned in this field for 1998. BAYOU RAMBIO FIELD. Production at the Bayou Rambio Field was established in 1955 and has exceeded 150 Bcf and 920 MBbls to date. The Company operates three producing wells in the field, which is located in 42 43 Terrebonne Parish about 15 miles west of Lirette Field. During December 1997, the net production from this field averaged 7.0 MMcf/d and 53 Bbls/d. Two of these producing wells were drilled in 1997 based on a review of 3-D seismic data. The Company has one additional well planned for the first half of 1998 which will attempt to accelerate the production of the established reserves increasing the field's PV10 Value, while drilling a deeper sand interval which may establish additional pay sands. OTHER LOUISIANA FIELDS. In addition to the above fields, the Company owns an interest in wells at 39 other fields in Louisiana, which in the aggregate averaged approximately 14.2 MMcf/d and 959 Bbls/d of net production during December 1997. ACQUISITIONS OF OIL AND NATURAL GAS PROPERTIES The Company regularly seeks to acquire properties that complement its operations, provide exploitation, exploration and development opportunities and have cost reduction potential. The Company has purchased the majority of its current producing wells and has increased production by a variety of techniques, including development drilling, increasing fluid withdrawal and reworking existing wells. These acquisitions have also balanced the Company's reserve mix between oil and natural gas, increased the scale of its operations in the onshore Gulf Coast area and provided the Company with a significant base of operations within its area of geographic focus. Since 1993, aggregate expenditures to acquire producing properties are approximately $310 million through September 30, 1997 adjusted for the Chevron Acquisition. The properties included in the Company's five largest acquisitions make up approximately 84% of its total proved reserves on a BOE basis as of December 31, 1997. These five acquisitions are discussed below in the order of their acquisition by the Company. MISSISSIPPI ACQUISITION (1993). Effective May 1, 1993, the Company acquired interests in the Davis, Frances Creek and Lake Utopia Fields in the Mississippi salt basin for approximately $9.0 million. At the date of acquisition, the estimated net proved reserves included 2,170 MBbls and 217 MMcf, aggregating to 2.2 MMBOE. From the date of acquisition through September 30, 1997, the Company produced 1,377 MBOE from the acquired properties and has successfully increased its ownership in the Davis Field through approximately $4.3 million of incremental acquisitions. As of December 31, 1997, the estimated net proved reserves of the properties totaled 3.1 MMBOE, with a PV10 Value of $15.8 million. LOUISIANA ACQUISITION (1993). Effective October 1, 1993, Denbury acquired interests in the Lirette, Bayou Rambio, Delarge, Lapeyrouse, Lake Boeuf, North Deep Lake and Bay Baptiste Fields in southern Louisiana for approximately $9.8 million. Six of the seven fields are situated in the prolific Houma Embayment, which is located south of Houma and approximately 40 miles south of New Orleans, Louisiana. This basin contains fields which have produced more than 2 Tcf of gas since 1930. These fields have established productive sand intervals as shallow as 1,000 feet to depths in excess of 17,000 feet, with individual well production rates exceeding 10 MMcf/d. At the date of acquisition, the net proved reserves included 155 MBbls and 9,137 MMcf, aggregating to 1.7 MMBOE. From the date of acquisition through September 30, 1997, the Company produced 2,898 MBOE from the acquired properties. Subsequent to the acquisition, Denbury has successfully completed approximately $12.7 million in acquisitions of incremental interests in the Lirette and Bayou Rambio Fields. As of December 31, 1997, the estimated net proved reserves of the properties were 7.4 MMBOE, with a PV10 Value of $68.7 million. GIBSON ACQUISITION (1995). In October 1995, Denbury acquired additional interests in the Gibson and Humphreys Fields in Southern Louisiana for approximately $10.2 million. At the date of acquisition, the net proved reserves included approximately 412 MBbls and 9,435 MMcf, aggregating to 2.0 MMBOE. From the date of acquisition through September 30, 1997, the Company produced 1,285 MBOE from the acquired properties. As of December 31, 1997, the estimated net proved reserves of the properties were 1.5 MMBOE, with a PV10 Value of $13.9 million. HESS ACQUISITION (1996). The Company completed several property acquisitions during 1996, the largest of which was the acquisition of producing oil and natural gas properties in Mississippi, Louisiana and 43 44 Alabama, plus certain overriding royalty interests in Ohio, for approximately $37.2 million from Amerada Hess, effective May 1, 1996. The average daily production from the properties included in the Hess Acquisition during May and June 1996, the first two months of ownership, was approximately 2,945 BOE/d. The average daily production on these properties had increased to 5,373 BOE/d by the third quarter of 1997. As of December 31, 1997, in the Company's December Report, the properties acquired in the Hess Acquisition had estimated net proved reserves of approximately 14.2 MMBOE with a PV10 Value of $95.0 million. This compares to approximately 5.9 MMBOE of net proved reserves and a $43.1 million PV10 Value on these same properties as reported in the July Report. The December Report was calculated using year-end prices which were based on a WTI price of $16.18 per Bbl and a NYMEX price of $2.58 per Mcf, with these representative prices adjusted by field to arrive at the appropriate corporate net price, as compared to oil and gas prices of $20.00 and $2.65, respectively, in the July Report. In addition to the increase in proved reserves, the Company produced approximately 1.9 MMBOE from July 1, 1996 through September 30, 1997 with total net operating income of $23.8 million. The two largest fields acquired in the Hess Acquisition are the Eucutta and Quitman Fields which make up approximately 82% of the total Hess Acquisition PV10 Value. Both fields are in the same vicinity as the Company's previously existing Mississippi core properties. CHEVRON ACQUISITION (1997). On December 30, 1997, the Company acquired oil properties in the Heidelberg Field, Jasper County, Mississippi, from Chevron for approximately $202.0 million. The Chevron Acquisition represents the largest acquisition by the Company to date. The Heidelberg Field is adjacent to the Company's other primary oil properties in Mississippi and includes 122 producing wells, 96 of which the Company will operate. The Company purchased an average working interest of 94% and an average net revenue interest of 81% in these 96 wells, which wells account for approximately 99% of the field's current average net daily production. The average net daily production from these properties during the third quarter of 1997 was approximately 2,840 Bbls/d and 600 Mcf/d. The Chevron Acquisition added proved reserves as of December 31, 1997 of approximately 27.2 MMBbls and 2.5 Bcf, or approximately 27.6 MMBOE. As a result of the significant amount of future development and exploitation to be performed on these properties and the increase in future reserves and production that the Company expects to result from such development and exploitation, the Company has attributed approximately $75.0 million of the purchase price to unevaluated properties. The Company has identified several potential development projects during its initial evaluation of the Heidelberg Field. These include initiating a waterflood project, upgrading lift capacity in over 15 wells and recompleting 30 wells in new zones. In addition, the Company has identified over 40 potential drilling locations in addition to other potential secondary and tertiary recovery projects. Horizontal wells drilled by the Company in 1997 at nearby Davis, Quitman and Eucutta Fields improved daily production rates significantly as compared to vertical wells drilled in the same fields. Consequently, the Company anticipates that 30 of the 40 proposed future wells in the Heidelberg Field will be horizontal wells. The Company's total 1998 development budget for the Heidelberg Field is approximately $30.0 million. 44 45 PRODUCTION VOLUMES, SALES PRICES AND PRODUCTION COSTS The following table summarizes the Company's net oil and natural gas production volumes, average sales prices and production costs for each of the years in the three-year period ended December 31, 1996 and for the nine month periods ended September 30, 1996 and 1997.
YEAR ENDED DECEMBER 31, NINE MONTHS ENDED SEPTEMBER 30, ------------------------------------ --------------------------------- PRO FORMA PRO FORMA 1994 1995 1996 1996(A) 1996 1997 1997(A) ------ ------ ------ --------- -------- -------- ----------- NET PRODUCTION VOLUME: Oil (MBbls)............ 489 728 1,500 2,752 967 2,079 2,873 Natural gas (MMcf)..... 3,326 4,844 8,933 9,178 6,540 9,299 9,459 Oil equivalent (MBOE).. 1,043 1,535 2,989 4,282 2,057 3,629 4,449 AVERAGE SALE PRICES: Oil ($/Bbl)............ $13.84 $14.90 $18.98 $18.75 $18.05 $17.53 $17.45 Natural gas ($/Mcf).... 1.78 1.90 2.73 2.72 2.64 2.54 2.54 Oil equivalent ($/BOE)............. 12.17 13.05 17.69 17.88 16.87 16.56 16.65 AVERAGE PRODUCTION COSTS: Per BOE................ $ 4.13 $ 4.42 $ 4.51 $ 4.70 $ 4.47 $ 4.34 $ 4.71
- --------------- (a) Pro forma for the Chevron Acquisition. See "-- Acquisitions of Oil and Natural Gas Properties" and "Unaudited Pro Forma Consolidated Financial Information." OIL AND NATURAL GAS ACREAGE The following table sets forth the Company's acreage position as of December 31, 1996:
DEVELOPED UNDEVELOPED --------------- --------------- GROSS NET GROSS NET ------ ------ ------ ------ Louisiana........................................... 29,328 20,374 10,137 7,812 Mississippi......................................... 17,511 11,138 19,180 8,002 Other............................................... 1,710 1,260 1,709 722 ------ ------ ------ ------ Total..................................... 48,549 32,772 31,026 16,536 ====== ====== ====== ======
The following table sets forth the Company's acreage position as of September 30, 1997:
DEVELOPED UNDEVELOPED --------------- --------------- GROSS NET GROSS NET ------ ------ ------ ------ Louisiana........................................... 28,519 19,870 20,542 10,668 Mississippi......................................... 17,102 12,655 27,185 10,970 ------ ------ ------ ------ Total..................................... 45,621 32,525 47,727 21,638 ====== ====== ====== ======
PRODUCTIVE WELLS The following table sets forth the Company's gross and net productive wells as of December 31, 1996:
NATURAL GAS OIL WELLS WELLS TOTAL ------------- ------------ ------------- GROSS NET GROSS NET GROSS NET ----- ----- ----- ---- ----- ----- Louisiana................................... 44 24.8 66 38.1 110 62.9 Mississippi................................. 142 106.0 28 14.8 170 120.8 Other....................................... 4 2.0 12 5.3 16 7.3 --- ----- --- ---- --- ----- Total............................. 190 132.8 106 58.2 296 191.0 === ===== === ==== === =====
45 46 The following table sets forth the Company's gross and net productive wells as of September 30, 1997:
NATURAL GAS OIL WELLS WELLS TOTAL ------------- ------------ ------------- GROSS NET GROSS NET GROSS NET ----- ----- ----- ---- ----- ----- Louisiana................................... 40 25.7 70 43.2 110 68.9 Mississippi................................. 154 132.5 21 7.2 175 139.7 --- ----- --- ---- --- ----- Total............................. 194 158.2 91 50.4 285 208.6 === ===== === ==== === =====
DRILLING ACTIVITY The following table sets forth the results of drilling activities during each of the three years in the period ended December 31, 1996 and the nine months ended September 30, 1997. No wells were in the process of drilling at September 30, 1997.
NINE MONTHS YEAR ENDED DECEMBER 31, ENDED ----------------------------------------------- SEPTEMBER 30, 1994 1995 1996 1997 ------------- ------------- ------------- ------------- GROSS NET GROSS NET GROSS NET GROSS NET ----- ---- ----- ---- ----- ---- ----- ---- EXPLORATORY WELLS: Productive..................... -- -- -- -- -- -- 2 0.8 Nonproductive.................. 3 0.8 2 1.0 1 1.0 5 2.4 DEVELOPMENT WELLS: Productive..................... 4 2.9 2 1.5 9 7.9 26 22.7 Nonproductive.................. 1 1.0 -- -- -- -- 2 1.1 ---- ---- ---- ---- ---- ---- ---- ---- Total.................. 8 4.7 4 2.5 10 8.9 35 27.0 ==== ==== ==== ==== ==== ==== ==== ====
PRODUCT MARKETING Denbury's production is primarily from developed fields close to major pipelines or refineries and established infrastructure. As a result, Denbury has not experienced any difficulty in finding a market for its product as it becomes available or in transporting its product to these markets. OIL MARKETING. Denbury markets its oil to a variety of purchasers, most of which are large, established companies. The oil is generally sold under a short-term contract with the sales price based on an applicable posted price, plus a negotiated premium. This price is determined on a well-by-well basis and the purchaser generally takes delivery at the wellhead. Mississippi oil, which accounted for approximately 73% of the Company's oil production in 1996, is primarily light sour crude and sells at a discount to the published WTI posting. The balance of the oil production, Louisiana oil, is primarily light sweet crude, which typically sells at a slight premium to the WTI posting. The Company is currently selling a majority of its oil under a two-year contract to Hunt Refining which expires on April 1998 and is currently receiving a premium to the posted price in this contract. The Company may not be able to renew this contract in the future or may not be able to obtain terms as favorable as those in the existing contract. NATURAL GAS MARKETING. Virtually all of Denbury's natural gas production is close to existing pipelines and consequently, the Company generally has a variety of options to market its natural gas. The Company sells the majority of its natural gas on one year contracts with prices fluctuating month-to-month based on published pipeline indices with slight premiums or discounts to the index. PRODUCTION PRICE HEDGING. For 1995, the Company entered into financial contracts to hedge 75% of the Company's net natural gas production and 43% of the Company's net oil production. The net effect of these hedges was to increase oil and natural gas revenues by approximately $750,000 during 1995. The Company does not currently have any hedging contracts in place, although it may enter into such contracts in the future. 46 47 SIGNIFICANT OIL AND NATURAL GAS PURCHASERS Oil and natural gas sales are made on a day-to-day basis under short-term contracts at the current area market price. The loss of any purchaser would not be expected to have a material adverse effect upon the Company's operations. For the period ended December 31, 1996, the Company sold 10% or more of its net production of oil and natural gas to the following purchasers: Natural Gas Clearinghouse (20%), Penn Union Energy Services (19%), Enron Trading & Transportation (13%) and Hunt Refining (15%). TITLE TO PROPERTIES Customarily in the oil and natural gas industry, only a perfunctory title examination is conducted at the time properties believed to be suitable for drilling operations are first acquired. Prior to commencement of drilling operations, a thorough drill site title examination is normally conducted and curative work is performed with respect to significant defects. During acquisitions, title reviews are performed on all properties; however, formal title opinions are obtained on only the higher value properties. The Company believes that it has good title to its oil and natural gas properties, some of which are subject to minor encumbrances, easements and restrictions. COMPETITION The oil and natural gas industry is highly competitive in all its phases. The Company encounters strong competition from many other energy companies in acquiring economically desirable producing properties and drilling prospects and in obtaining equipment and labor to operate and maintain its properties. In addition, many energy companies possess greater resources than the Company. See "Risk Factors -- Competition." GEOGRAPHIC SEGMENTS All of the Company's operations are in the United States. OFFICE AND FIELD FACILITIES The Company leases its executive and administrative offices in Dallas, Texas, consisting of approximately 25,000 square feet, under a lease that continues through May 1999. On August 6, 1997, the Company entered into a ten year office lease for approximately 50,000 square feet to replace its current corporate headquarters. This new lease is expected to commence late in 1998. EMPLOYEES At January 15, 1998, the Company had 183 employees associated with its operations, including 69 field personnel in Mississippi and 35 field personnel in Louisiana. None of the Company's employees is represented by a union. The Company considers its employee relations to be satisfactory. LEGAL PROCEEDINGS From time to time, the Company is a party to legal proceedings in the ordinary course of its business, including actions for personal injury and property damage occurring as a result of the operation of wells, and claims for environmental damage. In June of 1997, a well blow-out occurred at the Lake Chicot Field, for which the Company is operator, in St. Martin Parish, Louisiana in which four individuals that were employees of other third party entities were killed, none of whom were employees or contractors of the Company. In connection with this blow-out, a lawsuit was filed on July 2, 1997, Barbara Trahan, et al .v. Mallard Bay Drilling L.L.C., Parker Drilling Company and Denbury Management, Inc., Case No. 58226-G in the 16th Judicial District Court in St. Martin Parish, Louisiana alleging various defective and dangerous conditions violation of certain rules and regulations and acts of negligence. The Company believes that all litigation to which it is a party is covered by insurance and none of such legal proceedings can be reasonably expected to have a material adverse effect on the Company's financial condition or results of operations. See "Risk Factors -- Drilling and Operating Risks." 47 48 REGULATIONS The availability of a ready market for oil and gas production depends upon numerous factors beyond the Company's control. These factors include regulation of natural gas and oil production, federal and state regulations governing environmental quality and pollution control, state limits on allowable rates of production by well or proration unit, the amount of natural gas and oil available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. State and federal regulations generally are intended to prevent waste of natural gas and oil, protect rights to produce natural gas and oil between owners in a common reservoir, control the amount of natural gas and oil produced by assigning allowable rates of production and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. The following discussion summarizes the regulation of the United States oil and gas industry and is not intended to constitute a complete discussion of the various statutes, rules, regulations and governmental orders to which the Company's operations may be subject. REGULATION OF NATURAL GAS AND OIL EXPLORATION AND PRODUCTION. The Company's operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for drilling wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations. The Company's operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells which may be drilled in and the unitization or pooling of oil and gas properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production. The effect of these regulations may limit the amount of oil and gas the Company can produce from its wells and may limit the number of wells or the locations at which the Company can drill. Each state generally imposes a production or severance tax with respect to production and sale of crude oil, natural gas and natural gas liquids within their respective jurisdictions. The regulatory burden on the oil and gas industry increases the Company's costs of doing business and, consequently, affects its profitability. Inasmuch as such laws and regulations are frequently expanded, amended and reinterpreted, the Company is unable to predict the future cost or impact of complying with such regulations. FEDERAL REGULATION OF SALES AND TRANSPORTATION OF NATURAL GAS. Federal legislation and regulatory controls in the U.S. have historically affected the price of the natural gas produced by the Company and the manner in which such production is marketed. The Federal Energy Regulatory Commission (the "FERC") regulates the interstate transportation and sale for resale of natural gas by interstate and intrastate pipelines. The FERC previously regulated the maximum selling prices of certain categories of gas sold in "first sales" in interstate and intrastate commerce under the Natural Gas Policy Act. Effective January 1, 1993, however, the Natural Gas Wellhead Decontrol Act (the "Decontrol Act") deregulated natural gas prices for all "first sales" of natural gas, which includes all sales by the Company of its own production. As a result, all sales of the Company's domestically produced natural gas may be sold at market prices, unless otherwise committed by contract. The FERC's jurisdiction over natural gas transportation and gas sales other than first sales was unaffected by the Decontrol Act. The Company's natural gas sales are affected by the regulation of intrastate and interstate gas transportation. In an attempt to restructure the interstate pipeline industry with the goal of providing enhanced access to, and competition among, alternative natural gas supplies, the FERC, commencing in April 1992, issued Order Nos. 636, 636-A and 636-B ("Order No. 636") which have altered significantly the interstate transportation and sale of natural gas. Among other things, Order No. 636 required interstate pipelines to unbundle the various services that they had provided in the past, such as sales, transmission and storage, and to offer these services individually to their customers. By requiring interstate pipelines to "unbundle" their services and to provide their customers with direct access to pipeline capacity held by them, Order No. 636 has enabled pipeline customers to choose the levels of transportation and storage service they require, as well as to purchase natural gas directly from third-party merchants other than the pipelines and obtain 48 49 transportation of such gas on a non-discriminatory basis. The effect of Order No. 636 has been to enable the Company to market its natural gas production to a wider variety of potential purchasers. The Company believes that these changes generally have improved the Company's access to transportation and have enhanced the marketability of its natural gas production. To date, Order No. 636 has not had any material adverse effect on the Company's ability to market and transport its natural gas production. However, the Company cannot predict what new regulations may be adopted by the FERC and other regulatory authorities, or what effect subsequent regulations may have on the Company's activities. In addition, Order No. 636 and a number of related orders were appealed. Recently, the United States Court of Appeals for the District of Columbia Circuit issued an opinion largely upholding the basic features and provision of Order No. 636. However, even though Order No. 636 itself has been judicially approved, several related FERC orders remain subject to pending appellate review and further changes could occur as a result of court order or at the FERC's own initiative. In recent years the FERC also has pursued a number of other important policy initiatives which could significantly affect the marketing of natural gas. Some of the more notable of these regulatory initiatives include (i) a series of orders in individual pipeline proceedings articulating a policy of generally approving the voluntary divestiture of interstate natural gas pipeline-owned gathering facilities to pipeline affiliates, (ii) the completion of a rulemaking involving the regulation of interstate natural gas pipelines with marketing affiliates under Order No. 497, (iii) FERC's on-going efforts to promulgate standards for pipeline electronic bulletin boards and electronic data exchange, (iv) a generic inquiry into the pricing of interstate pipeline capacity, (v) efforts to refine FERC's regulations controlling the operation of the secondary market for released interstate natural gas pipeline capacity, and (vi) a policy statement regarding market-based rates and other non-cost-based rates for interstate pipeline transmission and storage capacity. Several of these initiatives are intended to enhance competition in natural gas markets. While any resulting FERC action would affect the Company only indirectly, the ongoing, or, in some instances, preliminary evolving nature of these regulatory initiatives makes it impossible at this time to predict their ultimate impact upon the Company's activities. OIL PRICE CONTROLS AND TRANSPORTATION RATES. Sales of crude oil, condensate and gas liquids by the Company are not currently regulated and are made at market prices. Commencing in October 1993, the FERC has modified its regulation of oil pipeline rates and services in order to comply with the Energy Policy Act of 1992. That Act mandated that FERC streamline oil pipeline ratemaking by abandoning its old, cumbersome procedures and issue new procedures to be effective January 1, 1995. In response, the FERC issued a series of rules (Order Nos. 561 and 561-A) establishing an indexing system under which oil pipelines will be able to change their transportation rates, subject to prescribed ceiling levels. The FERC's new oil pipeline ratemaking methodology was recently affirmed by the Court. The Company is not able at this time to predict the effects of Order Nos. 561 and 561-A, if any, on the transportation costs associated with oil production from the Company's oil producing operations. GATHERING REGULATIONS. Under the Natural Gas Act (the "NGA"), facilities used for and operations involving the production and gathering of natural gas are exempt from FERC jurisdiction, while facilities used for and operations involving interstate transmission are not. Under current law even facilities which otherwise would have been classified as gathering may be subject to the FERC's rate and service jurisdiction when owned by an interstate pipeline company and when such regulation is necessary in order to effectuate FERC's Order No. 636 open-access initiatives. FERC has reaffirmed that it does not have jurisdiction over natural gas gathering facilities and services and that such facilities and services are properly regulated by state authorities. As a result, natural gas gathering may receive greater regulatory scrutiny by state agencies. In addition, the FERC has approved several transfers by interstate pipelines of gathering facilities to unregulated gathering companies, including affiliates. This could allow such companies to compete more effectively with independent gatherers. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. While some states provide for the rate regulation of pipelines engaged in the intrastate transportation of natural gas, such regulation has not generally been applied against gatherers of natural gas. Natural gas gathering may receive greater regulatory scrutiny following the pipeline industry restructuring under Order No. 636. Thus the Company's gathering operations could be 49 50 adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. See "Risk Factors -- Governmental and Environmental Regulation." ENVIRONMENTAL REGULATIONS. The Company's operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stricter environmental legislation and regulations could continue. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and gas industry in general, the business and prospects of the Company could be adversely affected. The EPA and various state agencies have limited the approved methods of disposal for certain hazardous and nonhazardous wastes. Certain wastes generated by the Company's oil and natural gas operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes," and therefore be subject to more rigorous and costly operating and disposal requirements. The Company currently owns or leases numerous properties that for many years have been used for the exploration and production of oil and gas. Most of these properties have been operated by prior owners, operators and third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under the Company's control. These properties and the wastes disposed thereon may be subject to Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), Federal Resource Conservation and Recovery Act and analogous state laws. Under such laws, the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination. The Company's operations may be subject to the Clean Air Act ("CAA") and comparable state and local requirements. Certain provisions of CAA may result in the gradual imposition of certain pollution control requirements with respect to air emissions from the operations of the Company. The EPA and states have been developing regulations to implement these requirements. The Company may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. However, the Company does not believe its operations will be materially adversely affected by any such requirements. Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as the Company, to prepare and implement spill prevention, control, countermeasure and response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 ("OPA") contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. The OPA subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including but not limited to, the costs of responding to a release of oil to surface waters. Regulations are currently being developed under the OPA and state laws concerning oil pollution prevention and other matters that may impose additional regulatory burdens on the Company. The Resource Conservation and Recovery Act ("RCRA") is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements (and liability for failure to meet such requirements) on a person who is either a "generator" or "transporter" of hazardous waste or an "owner" or "operator" of a hazardous waste treatment, storage or disposal facility. At present, RCRA includes a statutory exemption that allows most crude oil and natural gas exploration and production wastes to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. At various times in the past, proposals have been made to amend RCRA and various state statutes to rescind the exemption that excludes crude oil and natural gas exploration and production wastes from regulation as hazardous waste under such statutes. Repeal or modification of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste to be managed and disposed of by the Company. Hazardous wastes are subject to more rigorous and costly disposal requirements than are non-hazardous wastes. Any such 50 51 change in the applicable statues may require the Company to make additional capital expenditures or incur increased operating expenses. Some states have enacted statutes governing the handling, treatment, storage and disposal of naturally occurring radioactive material ("NORM"). NORM is present in varying concentrations in subsurface and hydrocarbon reservoirs around the world and may be concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Mississippi legislation prohibits the transfer of property for residential or other unrestricted use if the property contains NORM above prescribed levels. The Company also is subject to a variety of federal, state and local permitting and registration requirements relating to the protection of the environment. Management believes that the Company is in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on the Company. See "Risk Factors -- Governmental and Environmental Regulation." TAXATION Since all of the Company's oil and natural gas operations are located in the United States, the Company's primary tax concerns relate to U.S. tax laws, rather than Canadian tax laws. Certain provisions of the United States Internal Revenue Code of 1986, as amended, are applicable to the petroleum industry. Current law permits the Company to deduct currently, rather than capitalize, intangible drilling and development costs ("IDC") incurred or borne by it. The Company, as an independent producer, is also entitled to a deduction for percentage depletion with respect to the first 1,000 barrels per day of domestic crude oil (and/or equivalent units of domestic natural gas) produced by the Company (if such percentage of depletion exceeds cost depletion). Generally, this deduction is 15% of gross income from an oil and natural gas property, without reference to the taxpayer's basis in the property. Percentage depletion can not exceed the taxable income from any property (computed without allowance for depletion), and is limited in the aggregate to 65% of the Company's taxable income. Any depletion disallowed under the 65% limitation, however, may be carried over indefinitely. For additional tax disclosures, see Note 4 of the Consolidated Financial Statements. 51 52 MANAGEMENT The names of the directors and officers of the Company, their ages, the offices held by them with the Company and the periods during which such offices have been held are set forth below. Each officer and director holds office for one year or until his death, resignation or removal or until his successor is duly elected and qualified. The officers set forth below hold the same position in both DRI and DMI unless otherwise noted.
NAME AGE POSITION(S) ---- --- ----------- Ronald G. Greene(a)(b)(c)(d)................ 48 Chairman of the Board of DRI Wilmot L. Matthews(a)....................... 61 Director of DRI William S. Price, III(b)(c)(d).............. 40 Director of DRI David M. Stanton............................ 34 Director of DRI Wieland F. Wettstein(a)..................... 47 Director of DRI David Bonderman............................. 54 Director of DRI Gareth Roberts.............................. 45 President, Chief Executive Officer and Director of DRI and DMI Matthew Deso................................ 44 Vice President, Exploration and Director of DMI Phil Rykhoek................................ 41 Chief Financial Officer and Secretary and Director of DMI Mark A. Worthey............................. 40 Vice President, Operations and Director of DMI Bobby J. Bishop............................. 37 Controller and Chief Accounting Officer Ron Gramling................................ 52 President of DMI marketing subsidiary Lynda Perrard............................... 54 Vice President, Land of DMI
- --------------- (a) Member of the Audit Committee. (b) Member of the Compensation Committee. (c) Member of the Stock Option Plan Committee. (d) Member of the Stock Purchase Plan Committee. Ronald G. Greene is the Chairman of the Board, and has been a director of the Company since 1995. Mr. Greene is the founder and Chairman of the Board of Renaissance Energy Ltd. and was Chief Executive Officer of Renaissance from its inception in 1974 until May 1990. He is also the sole shareholder, officer and director of Tortuga Investment Corp., a private investment company. Mr. Greene also serves on the Board of Directors of a private Western Canadian airline. Wilmot L. Matthews was first elected as director of the Company on December 9, 1997. Mr. Matthews, a Chartered Accountant, has been involved in all aspects of investment banking by serving in various positions with Nesbitt Burns Inc. and its predecessor companies from 1964 until his retirement in September 1996, most recently as Vice Chairman and Director. Mr. Matthews is currently President of Marjad Inc., a personal investment company, and also serves on the Board of Directors of Renaissance Energy Ltd. and several private companies. William S. Price, III has been a director of the Company since 1995. Mr. Price is a co-founder and principal of TPG. Prior to forming TPG in 1992, Mr. Price was vice-president of strategic planning and business development for G.E. Capital, and from 1985 to 1991 was employed by the management consulting firm of Bain & Company, attaining officer status and acting as co-head of the Financial Services practice. Mr. Price is Chairman of the Board of Favorite Brands International, Inc. and Co-Chairman of the Board of Beringer Wine Estates. Mr. Price also serves on the Board of Directors of Continental Airlines, Inc., Continental Micronesia, Inc., VSP Holdings, Inc., Belden & Blake Corporation and Del Monte Foods. 52 53 David M. Stanton has been a director of the Company since 1995. Mr. Stanton is a managing director of TPG. From 1991 until he joined TPG in 1994, Mr. Stanton was a venture capitalist with Trinity Ventures where he specialized in information technology, software and telecommunications investments. Mr. Stanton also serves on the Board of Directors of TPG Communications, Inc., Paradyne Partners, L.P. and Belden & Blake Corporation. Wieland F. Wettstein has been a director of the Company since 1990. Mr. Wettstein is the Executive Vice President of, and indirectly controls 50% of, Finex Financial Corporation Ltd., a merchant banking company in Calgary, Alberta, a position he has held for more than five years. Mr. Wettstein serves on the Board of Directors of a public oil and natural gas company, BXL Energy, and on the Board of Directors of a private technology firm. David Bonderman has been a director of the Company since 1996. Mr. Bonderman is a co-founder and principal of TPG. Prior to forming TPG in 1992, Mr. Bonderman was the Chief Operating Officer of the Robert M. Bass Group, Inc. (now doing business as Keystone, Inc.), joining them in 1983. Keystone, Inc. is the personal investment vehicle of Fort Worth, Texas-based investor Robert M. Bass. Mr. Bonderman serves on the boards of Continental Airlines; Inc.; Beringer Wine Estates; Credicom Asia; Bell & Howell Company; Ryanair, Limited; Virgin Cinemas, Limited; Ducati Motors S.P.A.; and Washington Mutual, Inc. Gareth Roberts -- President, Chief Executive Officer and a Director, is the founder of DMI, which was founded in April 1990. Mr. Roberts has more than 20 years of experience in the exploration and development of oil and natural gas properties with Texaco, Inc., Murphy Oil Corporation and Coho Resources, Inc. His expertise is particularly focused in the Gulf Coast region where he specializes in the acquisition and development of old fields with low productivity. Mr. Roberts holds honors and masters degrees in Geology and Geophysics from St. Edmund Hall, Oxford University. Mr. Roberts also serves on the Board of Directors of Belden & Blake Corporation. Matthew Deso -- Vice President, Exploration, has been with the Company since October 1990, first as a consultant then, when he moved to Dallas in January 1994, as Vice President of Exploration, his current position. Mr. Deso has twenty years of petroleum geology experience, and received a Bachelor of Science in Geosciences from the University of Texas in 1976. Mr. Deso also worked for Enserch Exploration (three years), Terra Resources (three years) and TXO Production Corp. (eight years) in positions of varying responsibility. Phil Rykhoek -- Chief Financial Officer, a Certified Public Accountant, joined the Company and was appointed to the position of Chief Financial Officer and Secretary in June 1995. Prior to joining the Company, Mr. Rykhoek was Executive Vice President and co-founder of Petroleum Financial, Inc., a private company formed in May 1991 to provide oil and natural gas accounting services on a contract basis to other entities. From 1982 to 1991 (except for 1986), Mr. Rykhoek was employed by Amerac Energy Corporation (formerly Wolverine Exploration Company), most recently as Vice President and Chief Accounting Officer. He retained his officer status during his tenure at Petroleum Financial, Inc. Mark A. Worthey -- Vice President, Operations, is a geologist and is responsible for all aspects of operations in the field. He joined the Company in September 1992. Previously, he was with Coho Resources, Inc. as an exploitation manager, beginning his employment there in 1985. Mr. Worthey graduated from Mississippi State University with a Bachelor of Science degree in petroleum geology in 1984. Bobby J. Bishop -- Controller and Chief Accounting Officer, a Certified Public Accountant, joined the Company as Controller in August 1993 and was appointed to the position of Chief Accounting Officer in December, 1997. Prior to joining the Company, Mr. Bishop was the Chief Financial Officer for Arcadia Exploration and Production Company, a private company. He also worked for Lake Ronel Oil Company and TXO Production Corp. Mr. Bishop graduated from the University of Oklahoma with a Bachelor of Business Administration in Accounting in 1983. Ron Gramling -- President of DRI's marketing subsidiary, joined the Company in May 1996 when the Company purchased the subsidiary's assets. Prior to becoming affiliated with the Company, he was employed by Hadson Gas Systems as Vice President of term supply. Mr. Gramling has 27 years of marketing, 53 54 transportation and supply experience in the natural gas and crude oil industry. He received his Bachelor of Business Administration degree from Central State University, Edmond, Oklahoma in 1970. Lynda Perrard -- Vice President, Land of DMI, joined the Company in April 1994. Ms. Perrard has over 30 years of experience in the oil and gas industry as a petroleum landman. Prior to joining the Company, Ms. Perrard was the President and Chief Executive Officer of Perrard Snyder, Inc., a corporation performing contract land services. Ms. Perrard also served as Vice President, Land for Snyder Exploration Company from 1986 to 1991. As part of the Securities Purchase Agreement that governed the TPG's initial investment in the Company, TPG has the right to designate three of seven nominees to serve on the Board of Directors of the Company. It was also intended by the parties to the agreement that Mr. Ronald G. Greene would be nominated to serve as one of the seven directors and that the remaining three directors would be nominated by the Company. TPG will forfeit its right to designate one of the directors that it would otherwise be entitled to designate if at any time TPG owns securities of the Company representing less than 30% of the outstanding Common Shares, calculated on a fully-diluted basis. TPG shall forfeit its right to designate any director if at any time TPG's share holdings represent less than 20% of the outstanding Common Shares, calculated on a fully-diluted basis. Currently, Messrs. Stanton, Bonderman and Price are the directors of the Company nominated by TPG. 54 55 PRINCIPAL SHAREHOLDERS The following table sets forth information, as of December 31, 1997, concerning beneficial ownership of the Common Shares before and after giving effect to the Transactions for: (i) any shareholders known to the Company to beneficially own more than 5% of the issued and outstanding Common Shares; and (ii) all executive officers and directors individually and as a group. Except as otherwise indicated and except for those Common Shares that are listed as being beneficially owned by more than one shareholder, each shareholder identified in the table has sole voting and investment power with respect to their Common Shares.
BENEFICIAL OWNERSHIP BENEFICIAL OWNERSHIP AS OF AFTER THE DECEMBER 31, 1997 TRANSACTIONS -------------------------- ------------ NAME AND ADDRESS OF BENEFICIAL OWNER SHARES PERCENT PERCENT ------------------------------------ ------------ --------- ------------ Ronald G. Greene................................. 900,900(a) 4.4%(a) 3.6%(a) Suite 700, 407 -- 2nd Street Calgary, Alberta T2P 2Y3 David Bonderman.................................. 8,658,038(b) 41.2%(b) 34.7%(b) 201 Main Street, Suite 2420 Ft. Worth, TX 76102 Wilmot L. Matthews............................... 156,250(c) * * 1 First Canadian Place, Suite 5101 Toronto, ON M5X 1E3 William S. Price, III............................ 8,411,038(d) 40.0%(d) 33.7%(d) 600 California Street, Suite 1850 San Francisco, CA 94108 David M. Stanton................................. 2,000(e) * * Wieland F. Wettstein............................. 83,389(f) * * Gareth Roberts................................... 498,302(g) 2.4%(g) 2.0%(g) Phil Rykhoek..................................... 4,422(h) * * Mark A. Worthey.................................. 79,001(h) * * Matthew Deso..................................... 25,801(h) * * Bobby J. Bishop.................................. 2,439 * * All of the executive officers and directors as a group (11 persons)............................. 10,413,542(i) 49.3%(i) 41.3%(i) TPG Advisors, Inc................................ 8,408,038(j) 40.0%(j) 33.7%(j) 201 Main Street, Suite 2420 Ft. Worth, TX 76102
- --------------- * Less than 1%. (a) Includes 30,150 Common Shares held by Mr. Greene's spouse in her retirement plan, 900 shares held in trust for Mr. Greene's minor children and 520,833 Common Shares held by Tortuga Investment Corp., which is solely owned by Mr. Greene. (b) Includes 250,000 Common Shares in a family partnership 100% controlled by Mr. Bonderman and 625,000 Common Share purchase warrants held by TPG which, for purposes of this disclosure, are assumed to be exercised. These warrants were exercised on January 20, 1998. Mr. Bonderman is a director, executive officer and shareholder of TPG Advisors, Inc., which is the general partner of TPG GenPar, L.P., which in turn is the general partner of both TPG Partners, L.P., and TPG Parallel I, L.P., which are the direct beneficial owners of the remaining securities attributed to Mr. Bonderman. Mr. Bonderman's beneficial ownership after the Transactions includes the Common Shares purchased by TPG in the TPG Purchase. (c) Includes 52,300 Common Shares held by a subsidiary of Marjad Inc., which is wholly owned by Mr. Matthews, 2,450 Common Shares held in various trusts of which Mr. Matthews is a trustee and an 55 56 income beneficiary and 1,500 Common Shares as to which Mr. Matthews holds a power of attorney but no beneficial interest. (d) Includes 1,000 Common Shares held by Mr. Price and 2,000 Common Shares held by Mr. Price's spouse and 625,000 Common Share purchase warrants held by TPG which, for purposes of this disclosure, are assumed to be exercised. These warrants were exercised on January 20, 1998. Mr. Price is a director, executive officer and shareholder of TPG Advisors, Inc., which is the general partner of TPG GenPar, L.P., which in turn is the general partner of both TPG Partners, L.P., and TPG Parallel I, L.P., which are the direct beneficial owners of the remaining securities attributed to Mr. Price. Mr. Price's beneficial ownership after the Transactions includes the Common Shares purchased by TPG in the TPG Purchase. (e) Although Mr. Stanton is not considered to be a "beneficial owner" as that term is defined by the Commission, Mr. Stanton is a managing director of TPG. (f) Includes 76,439 Common Shares held by S.P. Hunt Holdings Ltd., which is solely owned by a trust of which Mr. Wettstein is a trustee. (g) Includes 138,330 Common Shares held by a corporation, which is solely owned by Mr. Roberts, 38,000 Common Shares held in a private charitable foundation which he and his wife control, and 2,228 Common Shares held by his wife. (h) Includes 1,875, 73,250 and 17,500 Common Shares which Mr. Rykhoek, Mr. Worthey and Mr. Deso, respectively, have the right to acquire pursuant to stock options which are currently vested or which vest within 60 days of December 31, 1997. (i) Includes 92,625 Common Shares which the officers and directors as a group have the right to acquire pursuant to stock options which are currently vested or which vest within 60 days of December 31, 1997 and 625,000 Common Share purchase warrants held by TPG which, for purposes of this disclosure, are assumed to be exercised. These warrants were exercised on January 20, 1998. Beneficial ownership does include the Common Shares held by affiliates of TPG, although Mr. Price and Mr. Bonderman, who are directors of the Company, are not the owners of record of these securities. Mr. Price and Mr. Bonderman are directors, executive officers and shareholders of TPG Advisors, Inc., which is the general partner of TPG GenPar, L.P., which in turn is the general partner of both TPG Partners, L.P. and TPG Parallel I, L.P., which are the direct beneficial owners of these securities. The beneficial ownership after the Transactions of the directors and executive officers as a group includes the Common Shares purchased by TPG in the TPG Purchase. (j) Includes 625,000 Common Share purchase warrants held by TPG which, for purposes of this disclosure, are assumed to be exercised. These warrants were exercised on January 20, 1998. 56 57 INTERESTS OF MANAGEMENT IN CERTAIN TRANSACTIONS Other than as described in the paragraphs that follow, there are no material interests, direct or indirect, of any director, officer or any shareholder of the Company who beneficially owns, directly or indirectly, or exercises control or direction over more than 5% of the outstanding Common Shares, or any known family member, associate or affiliate of such persons, participating in any transaction within the last three years or in any proposed transaction that has materially affected or would materially affect the Company, or any of its subsidiaries. The Company believes that the terms of the transactions described below were as favorable to the Company as terms that reasonably could have been obtained from non-affiliated third parties. TPG INVESTMENTS In December 1995, the Company closed a $40.0 million private placement of securities with partnerships that are affiliated with TPG (the "TPG Placement"). The TPG Placement was comprised of: (i) 4.2 million Common Shares issued at $5.85 per share; (ii) 625,000 warrants at a price of $1.00 per warrant, entitling the holders thereof to purchase 625,000 Common Shares at $7.40 per share; and (iii) 1.5 million shares of $10 stated value Convertible First Preferred Shares, Series A (the "Convertible Preferred"). The shareholders of the Company at a Special Meeting on October 9, 1996 approved a resolution to amend the terms of the Convertible Preferred to allow the Company to require a conversion of the Convertible Preferred at any time. All of the Convertible Preferred shares were converted into 2,816,372 Common Shares on October 30, 1996. As per the terms of the warrants, the Company is allowed to force conversion of the warrants after December 21, 1997 if the price of the Common Shares exceeds $10.00 per share for a period of 40 consecutive trading days. As of December 31, 1997, TPG is the beneficial owner of 7,783,038 Common Shares, which represents 38% of the outstanding Common Shares (40% after the exercise of the warrants on January 20, 1998). In connection with the TPG Placement, TPG received the right to nominate three of the directors of the Company out of a maximum of seven. Of the current directors, Messrs. Bonderman, Price and Stanton were nominated by TPG. See "Management." In addition, until December 21, 1997, TPG had certain "piggyback" registration rights which allowed TPG to include all or part of the Common Shares acquired by TPG in any registration statement of the Company during that period. Commencing December 21, 1997 and until December 21, 2000, TPG may request and receive one demand registration whereby TPG may make a written request to the Company for registration under the Securities Act of the Common Shares acquired by TPG. Finally, the agreement provides that TPG shall have the right, but not the obligation, to maintain its pro rata ownership interest in the equity securities of the Company, in the event that the Company issues any additional equity securities or securities convertible into Common Shares of the Company, by purchasing additional securities of the Company on the same terms and conditions. This right, however, expires should TPG's share holdings represent less than 20% of the outstanding Common Shares calculated on a fully-diluted basis. At the request of the NYSE, the Company has agreed to make the extension of this right subject to shareholder ratification every five years with the first vote on the matter expected to be at the annual meeting in the year 2000. TPG waived its right to maintain its pro rata ownership with regard to the public offering by the Company in October 1996, but did purchase 800,000 Common Shares included in the offering directly from the Company. These Common Shares were sold for 93.5% of the public offering price, or the same net price that the remainder of the shares included in the offering were being sold to the underwriters. TPG has waived its right to maintain its pro rata ownership with regard to the Equity Offering but is planning to purchase 313,400 shares in the TPG Purchase at 95.25% of the public offering price, or the same net price that the remainder of the shares included in the Equity Offering are being sold to the Underwriters. As of December 31, 1997, after giving pro forma effect to the Transactions, TPG will be the beneficial owner of 8,721,438 Common Shares, which represents 34% of the outstanding Common Shares. In 1995, the Company issued 333,333 Common Shares to Tortuga Investment Corp. as a financial advisory fee for its services in connection with the TPG Placement. Tortuga Investment Corp. is a corporation wholly owned by Mr. Ronald Greene, currently Chairman of the Board of Directors of the Company. Mr. Greene was not a director of the Company, nor had he held any director or officer position with the Company, prior to the time of the issuance of such Common Shares. 57 58 MODIFICATION OF DEBENTURES In addition to modifying the terms of the Convertible Preferred at the special meeting of the shareholders on October 9, 1996, the shareholders approved the issuance of 7,948 Common Shares in lieu of interest, plus an additional 308,642 Common Shares to redeem the principal amount of the outstanding 9.5% Convertible Debentures (the "Debentures") in accordance with their existing terms. Mr. Ronald G. Greene, Chairman of the Board of Directors, owned 80% of the Debentures, which were purchased by him at market value prior to his election to the Board of Directors. These Debentures were redeemed on October 15, 1996. Mr. Greene also purchased C $1,500,000 of 6 3/4% Convertible Debentures at market value prior to his election to the Board of Directors that were converted into 187,500 Common Shares on July 31, 1996 in accordance with the terms of the 6 3/4% Convertible Debentures. PURCHASE OF WORKING INTERESTS In May 1996, the Company purchased oil and natural gas working interests from four employees for an aggregate consideration of $387,000, which included $158,000 paid to Mr. Matthew Deso, Vice President of Exploration of the Company, $133,000 paid to Mr. Mark Worthey, Vice President of Operations of the Company and $26,000 paid to the spouse of Mr. Gareth Roberts, President and Chief Executive Officer of the Company. The purchase prices were determined by the Company based on the present value of the estimated future net revenue to be generated from the estimated proved reserves of the properties (based on the prior year's report thereon from Netherland & Sewell) using a 15% discount rate. The acquisitions were for additional working interests in properties in which the Company also holds an interest. To the best of the Company's knowledge, none of the Company's officers or directors have any remaining interests in properties owned by the Company. DESCRIPTION OF CAPITAL STOCK GENERAL The authorized share capital of DRI consists of an unlimited number of Common Shares, of which 20,386,683 were issued and outstanding as of December 31, 1997, and two classes of preferred shares, unlimited in number and issuable in series, none of which is outstanding. In addition to the issued and outstanding Common Shares, options to purchase 1,550,256 Common Shares and 700,000 warrants were outstanding as of December 31, 1997. An additional 406,620 stock options were granted on January 2, 1998. There are no limitations imposed by Canadian legislation or regulations or by the Articles of Continuance or Bylaws of DRI on the right of holders of either the Common Shares or the Common Share Purchase Warrants who are not residents of Canada to hold or vote the Common Shares or to hold the Common Share Purchase Warrants. COMMON SHARES The holders of the Common Shares are entitled: (i) to one vote for each Common Share held at all meetings of shareholders of DRI, other than meetings of the holders of any other class of shares meeting as a class or the holders of one or more series of any class of shares meeting as a series; (ii) to any dividends that may be declared by the Board of Directors thereon; and (iii) in the event of liquidation, dissolution or winding-up of DRI, are entitled, subject to the rights of the holders of shares ranking prior to the Common Shares, to share rateably in such assets of DRI as are available for distribution. The holders of Common Shares have no pre-emptive rights under Canadian law or the Articles of Continuance. At December 31, 1997, 75,000 warrants were outstanding at an exercise price of C$8.40 expiring on May 5, 2000 and 625,000 warrants were outstanding at an exercise price of $7.40 expiring on December 21, 1999. The 625,000 warrants held by TPG were exercised on January 20, 1998. Each warrant entitles the holder thereof to purchase one Common Share at any time prior to the expiration date. 58 59 DRI is also required to maintain a continuously effective registration statement for a two-year period relating to the resale of 705,643 Common Shares, including 75,000 Common Shares issuable upon the exercise of warrants, which were issued in two private placements in April and May 1995. An effective registration statement relating to this requirement is currently on file with the Commission. DRI has granted TPG certain demand registration rights and preemptive rights in connection with the TPG Placement. For a description of these rights, see "Interests of Management in Certain Transactions." TPG has waived its rights to maintain its pro rata ownership in connection with the Equity Offering although they intend to buy 313,400 Common Shares concurrently with the Equity Offering directly from the Company. These Common Shares will be sold to TPG for 95.25% of the public offering price, the same net price at which the remainder of the Common Shares included in the Equity Offering are being sold to the Underwriters. PREFERRED SHARES DRI's Articles of Continuance authorize the future issuance of First Preferred Shares and Second Preferred Shares (collectively, the "Preferred Shares"), with such designations, rights, privileges, restrictions and conditions as may be determined from time to time by the Board of Directors. Accordingly, the Board of Directors is empowered, without shareholder approval, to issue Preferred Shares with dividend, liquidation, conversion, voting or other rights that could adversely affect the voting power or other rights of holders of DRI's Common Shares. In the event of issuance, the Preferred Shares could be utilized, under certain circumstances, as a method of discouraging, delaying or preventing a change in control of the Company. Such actions could have the effect of discouraging bids for DRI and, thereby, preventing shareholders from receiving the maximum value for their shares. Although the Company has no present intention to issue any additional Preferred Shares, there can be no assurance that the Company will not do so in the future. There are no Preferred Shares currently outstanding. DESCRIPTION OF CERTAIN INDEBTEDNESS CREDIT FACILITY Effective December 29, 1997, the Company restated its Credit Facility with NationsBank of Texas, N.A., as Administrative Agent, and a syndicate of lenders pursuant to an agreement (the "Credit Agreement") under which DMI is the borrower from such lenders. The following is a summary of certain terms of the Credit Facility and is qualified in its entirety by reference to the Credit Agreement and the various related documents entered into in connection with the Credit Facility. The total commitment under the Credit Facility is $300.0 million, subject to borrowing base availability. The initial borrowing base under the Credit Facility is $260.0 million, $95.0 million of which consists of an interim acquisition financing commitment (the "Acquisition Tranche"). The initial borrowing base of $260 million will be reduced simultaneously with the issuance by the Company of any debt or equity securities by an amount equal to the net proceeds from the issuance of such securities, until such time as the borrowing base is reduced to the conforming borrowing base of $165.0 million. The interest rate on the Credit Facility includes a premium so long as the Acquisition Tranche is outstanding. Such premium is currently 0.25% and will increase 0.25% each quarter, commencing March 31, 1998, through March 31, 1999 until the Acquisition Tranche is repaid. The borrowing base in effect under the Credit Agreement is subject to redetermination semi-annually, at the sole discretion of the lenders. The borrowing base may be affected from time to time by the performance of the Company's oil and natural gas properties and changes in oil and natural gas prices, among other factors. The Company incurs a commitment fee of up to 0.45% per year on the unused portion of the borrowing base. Borrowings under the Credit Facility are payable in full on December 29, 2002 and bear interest at the option of the Company at the bank's prime rate or, depending on the percentage of the borrowing base that is outstanding, at rates ranging from LIBOR plus 7/8% to LIBOR plus 1 3/8% (plus the applicable premium in effect when the Acquisition Tranche is outstanding). As of December 31, 1997, after giving effect to the 59 60 Transactions, the Company would have had a borrowing base of $165.0 million, of which $123.9 million was available. The obligations of DMI as borrower under the Credit Facility will be fully and unconditionally guaranteed by DRI, DMI's direct corporate parent. In addition, the Credit Facility will be secured by first priority security interests in certain oil and natural gas properties which secured the Company's prior credit facility entered into on May 31, 1996 (excluding the properties acquired in the Chevron Acquisition) and a pledge of all of the stock of DMI; provided, however, that if the borrowings outstanding under the Credit Facility exceed the borrowing base after redetermination on July 1, 1998, the Credit Facility will be secured by substantially all of the Company's oil and natural gas properties (including those acquired in the Chevron Acquisition). The Credit Facility contains certain covenants which, among other things, restrict the Company's ability to pay dividends and other restricted payments, incur additional indebtedness, create liens, enter into leases and investments (including hedging investments), engage in mergers and consolidations or engage in certain transactions with affiliates. In addition, the Company will be required to comply with certain financial ratios and tests, including a minimum tangible net worth test, a current ratio coverage test and an EBITDA to interest ratio test. SENIOR SUBORDINATED NOTES Concurrently with the Equity Offering DMI is offering up to $125.0 million aggregate principal amount of its 9% Senior Subordinated Notes Due 2008 pursuant to the Debt Offering. The following is a summary of certain terms of the Notes and is qualified in its entirely by reference to the Indenture (the "Indenture") relating to the Notes. A copy of the proposed form of Indenture has been filed with the Registration Statement of which this Prospectus forms a part. The Notes will be unsecured senior subordinated obligations of DMI, and will rank pari passu in right of payment with all existing and future senior subordinated indebtedness of DMI and will be subordinated to future senior indebtedness of the Company. The Notes mature on March 1, 2008. The Notes will bear interest at the rate of 9% per annum and will be payable semi-annually, commencing on September 1, 1998. The Notes will be fully and unconditionally guaranteed (the "DRI Guaranty") on a senior subordinated basis by DRI. The indebtedness represented by the DRI Guaranty will be unsecured senior subordinated obligations of DRI, and will rank pari passu in right of payment with all existing and future senior subordinated indebtedness of DRI. In addition, under certain circumstances, the Notes will in the future be fully and unconditionally guaranteed on a senior subordinated basis by certain subsidiaries of DMI. Except as stated below, the Notes will not be redeemable prior to March 1, 2003. Thereafter, the Notes will be redeemable at the option of DMI, in whole or in part, at any time or from time to time, at a premium which will be at a fixed percentage that declines to par on or after March 1, 2006, in each case together with accrued and unpaid interest, if any, to the date of redemption. In the event the Company consummates a Stock Offering prior to March 1, 2001, DMI may, at its option, use all or a portion of the proceeds from such offering to redeem up to 35% of the original aggregate principal amount of the Notes at a redemption price equal to 109% of the aggregate principal amount of the Notes to be redeemed, plus accrued and unpaid interest, if any, thereon to the redemption date, provided at least $81.0 million aggregate principal amount of the Notes remains outstanding after each such redemption. Upon the occurrence of a Change of Control (as defined in the Indenture), each holder of Notes will have the right to require the Company to purchase all or a portion of such holder's Notes at a price equal to 101% of the aggregate principal amount thereof, together with accrued and unpaid interest to the date of purchase. The Indenture will contain certain covenants, including covenants that limit (i) indebtedness, (ii) restricted payments, (iii) distributions from restricted subsidiaries, (iv) transactions with affiliates, (v) sales of assets and subsidiary stock (including sale and leaseback transactions), (vi) dividend and other payment restrictions affecting restricted subsidiaries, and (vii) mergers or consolidations. 60 61 CANADIAN TAXATION AND THE INVESTMENT CANADA ACT The following is a summary of the principal Canadian income tax considerations generally applicable to nonresidents of Canada who hold the Common Shares as capital property, deal at arm's length with the Company and do not use or hold and are deemed not to use or hold their Common Shares in the course of carrying on a business in Canada and do not carry on insurance business in Canada. This summary has been prepared by reference to the existing provisions of the Income Tax Act (Canada) (the "Act"), the Income Tax Regulations (the "Regulations"), all published proposals for the amendment of the Act and the Regulations to the date hereof and the published administrative practices of Revenue Canada, the agency that administers the Act. Although this summary does not specifically address the provincial income tax consequences of an investment in Common Shares, generally speaking, provincial taxation does not apply to persons who are not resident in Canada and who do not own or hold property in the course of carrying on a business in Canada. Apart from changes to the Act and the Regulations which have been publicly announced to the date hereof, this summary does not consider the potential for any future alterations to Canadian income tax legislation. DISPOSITIONS OF COMMON SHARES A nonresident of Canada will only be subject to taxation in Canada under the Act in respect of a disposition of Common Shares if such shares constitute "taxable Canadian property" to such nonresident. Provided that the Common Shares are listed on a recognized stock exchange in Canada at the time of a disposition, they will only constitute "taxable Canadian property" to a holder if the holder, either alone or together with persons with whom the holder does not deal at arm's length, owns or at any time in the five years prior to the date of dispositions, has owned in excess of 25% of the issued and outstanding shares of a class or series of the capital of the Company. Persons who are related by blood or marriage, or are subject to common control are deemed to deal otherwise than at arm's length; other persons may also be considered to be dealing otherwise than at arm's length in certain circumstances. For the purposes of determining the 25% threshold, rights or options to acquire Common Shares will be treated as ownership thereof. Subject to the comments set out below in respect of the application of the U.S.-Canada Income Tax Convention to U.S. resident holders, nonresidents whose shares constitute "taxable Canadian property" will be subject to taxation thereon on the same basis as Canadian residents. Generally speaking, three-quarters of the excess of the holder's proceeds of disposition, over the adjusted cost basis of the Common Shares, must be included in income as a taxable capital gain, to be taxed at prevailing federal Canadian rates. Nonresidents whose shares are repurchased by the Company, except in respect of certain purchases made by the Company in the open market, will give rise to the deemed payment of a dividend by the Company to the former holder of Common Shares in an amount equal to the excess paid over the paid-up capital of the Common Shares so repurchased. Such deemed dividend will be excluded from the former holders' proceeds of disposition of his Common Shares for the purposes of computing any capital gain but will be subject to Canadian nonresident withholding tax in the manner described below under "Dividends." In certain limited circumstances, a sale by a holder of the Common Shares to a corporation resident in Canada with which the holder does not deal at arm's length may give rise to the deemed payment of a dividend, to the extent the amount received in consideration therefor exceeds the paid-up capital of the Common Shares disposed thereof. Pursuant to the U.S.-Canada Income Tax Convention (the "Convention"), shareholders of the Company who are residents of the U.S. for the purposes of the Convention and whose shares would otherwise be "taxable Canadian property" may be exempt from Canadian taxation in respect of any gains on the Common Shares provided the principal value of the Company is not derived from real property located in Canada at the time of the disposition. The Company owns no Canadian real property and the Company has no present intention to acquire Canadian real property. 61 62 DIVIDENDS Under the Act, a withholding tax is imposed at the rate of 25% on the amount of any dividends paid or credited on the Common Shares to a person not resident in Canada. Pursuant to the Canada U.S.-Canada Income Tax Convention, the rate of tax on such dividends is reduced to 5% for dividends received by any U.S. resident corporation who owns in excess of 10% of the voting shares of the corporation, and to 15% in all other instances. INVESTMENT CANADA ACT The Investment Canada Act (the "ICA") prohibits the acquisition of control of a Canadian business by non-Canadians without review and approval of the Investment Review Division of Industry Canada, the agency that administers the ICA, unless such acquisition is exempt from review under the provisions of the ICA. Investment Review Division of Industry Canada must be notified of such exempt acquisitions. The ICA covers acquisitions of control of corporate enterprises, whether by purchase of assets, shares or "voting interests" of an entity that controls, directly or indirectly, another entity carrying on a Canadian business. The ICA will have no effect on the acquisition of shares covered by this Prospectus. Apart from the ICA, there are no other limitations on the right of nonresident or foreign owners to hold or vote securities imposed by Canadian law or the Certificate of Continuance of the Company. There are no other decrees or regulations in Canada which restrict the export or import of capital, including foreign exchange controls, or that affect the remittance of dividends, interest or other payments to nonresident holders of the Company's Common Shares except as discussed above. THE FOREGOING DISCUSSION IS A SUMMARY OF THE PRINCIPAL CANADIAN FEDERAL INCOME AND ESTATE TAX CONSEQUENCES OF THE OWNERSHIP, SALE OR OTHER DISPOSITION OF THE COMMON SHARES. ACCORDINGLY, INVESTORS ARE URGES TO CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE CANADIAN INCOME AND ESTATE TAX CONSEQUENCES OF THE OWNERSHIP AND DISPOSITION OF THE COMMON SHARES, INCLUDING THE APPLICATION AND EFFECT OF THE LAWS OF ANY STATE, LOCAL, FOREIGN OR OTHER TAXING JURISDICTION. SERVICE AND ENFORCEMENT OF LEGAL PROCESS DRI is incorporated under the laws of Canada. Some of the directors, controlling persons and officers of DRI, as well as the experts named herein, are residents of Canada and all or substantially all of such persons' assets are located outside of the United States. As a result, it may be difficult for holders of Common Shares to effect service within the United States upon the directors, controlling persons, officers and experts who are not residents of the United States or to realize in the United States upon judgments of courts of the United States against such persons and DRI predicated upon civil liability under the United States federal securities laws. DRI has been advised by its counsel, Burnet, Duckworth & Palmer, Calgary, Alberta, that there is doubt as to the enforceability in Canada against DRI or against any of its directors, controlling persons, officers or experts who are not residents of the United States, in original actions for enforcement of judgments of United States courts, of liabilities predicated solely upon United States federal securities laws. SHARES ELIGIBLE FOR FUTURE SALE After giving effect to the Transactions, the Company would have had 25,257,283 Common Shares outstanding as of December 31, 1997 (25,940,863 Common Shares assuming exercise of the Underwriters' over-allotment option in full). The Common Shares sold in the Equity Offering will be freely tradeable without restrictions or further registration under the Securities Act. As of the close of the Equity Offering, all of the Common Shares beneficially held by TPG will be "restricted" securities within the meaning of the Securities Act as a result of TPG being deemed an "affiliate" of the Company under such act. These "restricted" Common Shares may be publicly sold only if registered under the Securities Act or sold in accordance with an applicable exemption from registration, such as that provided by Rule 144. 62 63 In general, under Rule 144 as currently in effect, a person (or persons whose shares are aggregated) who has beneficially owned shares for at least one year, including persons who may be deemed "affiliates" of the Company, would be entitled to sell within any three-month period a number of shares that does not exceed the greater of the average weekly trading volume during the four calendar weeks preceding such sale or 1% of the then outstanding Common Shares. A person who is deemed not to have been an "affiliate" of the Company at any time during the 90 days preceding a sale, and who has beneficially owned such shares for at least two years, would be entitled to sell such Common Shares under Rule 144 without regard to the volume limitations described above. The Company is unable to estimate the number of Common Shares, if any, that TPG may sell from time to time under Rule 144, since such number will depend on the future market price and trading volume for the Common Shares, as well as other factors beyond the Company's control. In connection with the Equity Offering, the Company, each of its directors and executive officers and TPG have agreed not to sell or otherwise dispose of any Common Shares, including any securities exercisable for or convertible into Common Shares, for a period of 120 days from the date of this Prospectus, without the prior written consent of Morgan Stanley & Co. Incorporated. See "Underwriters." The Company has granted TPG certain demand and "piggyback" registration rights with respect to its Common Shares. See "Interests of Management in Certain Transactions." TPG has waived its right to maintain its pro rata ownership in connection with the Equity Offering. An increase in the number of Common Shares that may become available for sale in the public market may adversely affect the market price prevailing from time to time of the Common Shares and could impair the Company's ability to raise additional capital through the sale of its equity securities. 63 64 UNDERWRITERS Under the terms and subject to the conditions contained in an underwriting agreement (the "Underwriting Agreement"), DRI has agreed to sell 4,557,200 Common Shares to a syndicate of underwriters (the "Underwriters"), for whom Morgan Stanley & Co. Incorporated, Gordon Capital, Inc., Johnson Rice & Company L.L.C. and Loewen, Ondaatje, McCutcheon USA Limited are acting as representatives (the "Representatives"), and the Underwriters have severally agreed to purchase the number of Common Shares set forth opposite their respective names below:
NUMBER UNDERWRITERS OF SHARES ------------ --------- Morgan Stanley & Co. Incorporated........................... 789,300 Gordon Capital, Inc. ....................................... 789,300 Johnson Rice & Company L.L.C. .............................. 789,300 Loewen, Ondaatje, McCutcheon USA Limited.................... 789,300 A.G. Edwards & Sons, Inc. .................................. 140,000 EVEREN Securities, Inc. .................................... 70,000 Gaines, Berland Inc. ....................................... 70,000 Jefferies & Company Inc. ................................... 70,000 Lehman Brothers Inc. ....................................... 140,000 Merrill Lynch, Pierce, Fenner & Smith Incorporated.......... 140,000 Midland Walwyn Capital Inc. ................................ 70,000 NationsBanc Montgomery Securities LLC....................... 140,000 Nesbitt Burns Securities Inc. .............................. 70,000 PaineWebber Incorporated.................................... 140,000 Petrie Parkmann & Co. ...................................... 70,000 Sanders Morris Mundy Inc. .................................. 70,000 Smith Barney Inc. .......................................... 140,000 Southwest Securities Inc. .................................. 70,000 --------- Total............................................. 4,557,200 =========
The Underwriting Agreement provides that the obligations of the several Underwriters to pay for and accept delivery of the Common Shares offered hereby are subject to the approval of certain legal matters by their counsel and to certain other conditions. If any of the Common Shares are purchased by the Underwriters pursuant to the Underwriting Agreement, all such Common Shares (other than the Common Shares covered by the over-allotment option described below) must be so purchased. The Company has been advised by the Representatives that the Underwriters propose to offer the Common Shares to the public initially at the price to public set forth on the cover page of this Prospectus and to certain dealers (who may include the Underwriters) at such price less a concession not to exceed $0.485 per share. The Underwriters may allow, and such dealers may reallow, a concession not in excess of $0.10 per share to any other Underwriter or certain other dealers. After the initial offering of the Common Shares the offering price and other selling terms may from time to time be varied by the Underwriters. The Company has granted to the Underwriters an option to purchase up to 683,580 additional Common Shares at the price to public set forth on the cover page hereof less underwriting discounts and commissions, solely to cover over-allotments. Such option may be exercised at any time until 30 days after the date of this Prospectus. To the extent that the Underwriters exercise such option, each of the Underwriters will be committed, subject to certain conditions, to purchase a number of Common Shares proportionate to such Underwriter's initial commitment as indicated in the preceding table. Each of the Underwriters has represented and, during the period of six months after the date hereof, agreed that (a) it has not offered or sold and will not offer or sell any Common Shares in the United Kingdom except to persons whose ordinary activities involve them in acquiring, holding, managing or disposing of 64 65 investments (as principal or agent) for the purpose of their business or otherwise in circumstances which have not resulted and will not result in an offer to the public in the United Kingdom within the meaning of the Public Offers of Securities Regulations (1995) (the "Regulations"); (b) it has complied and will comply with all applicable provisions of the Financial Services Act 1986 and the Regulations with respect to anything done by it in relation to the Common Shares offered hereby in, from or otherwise involving the United Kingdom; and (c) it has only issued or passed on and will only issue or pass on to any person in the United Kingdom any document received by it in connection with the issue of the Common Shares if that person is a kind described in Article 11(3) of the Financial Services Act 1986 (Investment Advertisements) (Exemptions) Order 1996, or is a person to whom such document may otherwise lawfully be issued or passed on. The Company has agreed to indemnify the Underwriters against certain liabilities that may be incurred in connection with the offering of the Common Shares, including liabilities under the Securities Act, or to contribute to payments that the Underwriters may be required to make in respect thereof. It is expected that delivery of the Common Shares will be made against payment therefor on or about the date specified in the last paragraph of the cover page of this Prospectus, which is the fifth business day following the date hereof. Under Rule 15c6-1 of the U.S. Securities and Exchange Commission under the Exchange Act, trades in the secondary market generally are required to settle in three business days, unless the parties to any such trade expressly agree otherwise. Accordingly, purchasers who wish to trade Common Shares on the date hereof or the day thereafter will be required, by virtue of the fact that the Common Shares initially will settle in T+5, to specify an alternate settlement cycle at the time of any such trade to prevent a failed settlement. Purchasers of Common Shares who wish to trade Common Shares on the date hereof or the day thereafter should consult their own advisor. In order to facilitate the Equity Offering, the Underwriters may engage in transactions that stabilize, maintain or otherwise affect the price of the Common Shares. Specifically, the Underwriters may over-allot in connection with the Equity Offering, creating a short position in the Common Shares for their own account. In addition, to cover over-allotments or to stabilize the price of the Common Shares, the Underwriters may bid for, and purchase, Common Shares in the open market. Finally, the underwriting syndicate may reclaim selling concessions allowed to an underwriter or a dealer for distributing the Common Shares in the Equity Offering, if the syndicate repurchases previously distributed Common Shares in transactions to cover syndicate short positions, in stabilization transactions or otherwise. Any of these activities may stabilize or maintain the market price of the Common Shares above independent market levels. The Underwriters are not required to engage in these activities, and may end any of these activities at any time. The Common Shares being sold in the TPG Purchase are being sold directly to TPG by the Company. The TPG Purchase is not being made on an underwritten basis, and the Underwriters of the Equity Offering are not acting on behalf of the Company, as agents or in any other capacity, in connection therewith. TPG has agreed to provide, at the closing of the TPG Purchase, an undertaking to the TSE not to sell any of the Common Shares acquired pursuant to the TPG Purchase for a period of six months following the acquisition of such Common Shares without the prior written consent of the TSE. The closing of the TPG Purchase and the Equity Offering are each conditioned upon, and will occur concurrently with, the closing of the other. LEGAL MATTERS The legality of the securities offered hereby will be passed upon for the Company by Burnet, Duckworth & Palmer, Calgary, Alberta and Jenkens & Gilchrist, a Professional Corporation, Houston, Texas. Certain legal matters in connection with the Offerings will be passed upon for the Underwriters by Osler, Hoskin & Harcourt, Calgary, Alberta and Cravath, Swaine & Moore, New York, New York. 65 66 EXPERTS The consolidated financial statements and financial statement schedule of the Company as at December 31, 1995 and 1996 and for each of the three years in the period ended December 31, 1996 included and incorporated by reference in this Prospectus and elsewhere in the Registration Statement, have been audited by Deloitte & Touche, Chartered Accountants, Calgary, Alberta, Canada, as stated in their reports appearing and incorporated by reference in this Prospectus and elsewhere in the Registration Statement, and have been so included in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing. The statements of revenues and direct operating expenses of Chevron's working interest in the Heidelberg Fields acquired by the Company for each of the two years in the period December 31, 1996 and for the nine months ended September 30, 1997 included in this Prospectus has been so included in reliance on the report of Price Waterhouse LLP, independent accountants, given on the authority of said firm as experts in auditing and accounting. The reference to the reports of Netherland, Sewell & Associates, Inc., independent petroleum engineers located in Dallas, Texas, contained herein with respect to the proved reserves, the estimated future net revenue from such proved reserves, and the discounted present values of such estimated future net revenue, is made in reliance upon the authority of such firms as experts with the respect to such matters. AVAILABLE INFORMATION The Company is subject to the information requirements of the Exchange Act, and in accordance therewith files reports, proxy statements and other information with the Commission. Such reports, proxy statements and other information can be inspected and copied at the public reference facilities maintained by the Commission at 450 5th Street, N.W., Room 1024, Washington, D.C. 20549, and at the following regional offices of the Commission: Seven World Trade Center, 13th Floor, New York, New York 10048 and Citicorp Center, 500 West Madison Street, Suite 1400, Chicago, Illinois 60661, at prescribed rates. In addition, such materials filed electronically by the Company with the Commission are available at the Commission's World Wide Web site at http://www.sec.gov. The Common Shares are traded on the NYSE and such reports, proxy statements and other information may be inspected at 20 Broad Street, New York, New York 10005. The Common Shares are also traded on the TSE and any filings with the TSE may be inspected at The Exchange Tower, 2 First Canada Plaza, Toronto, Ontario, Canada M5X 1J2. The Company has filed with the Commission a Registration Statement on Form S-3 under the Securities Act, with respect to the securities offered hereby. This Prospectus does not contain exhibits and schedules and certain other information which is part of the Registration Statement and which have been omitted from this Prospectus as permitted by the rules and regulations of the Commission. Statements contained herein concerning the contents of any contract, agreement or other document filed as an exhibit to the Registration Statement are necessarily summaries of such contracts, agreements or documents and are qualified in their entirety by reference to each such exhibit. The Registration Statement and the exhibits and schedules forming a part thereof can be obtained from the Commission. 66 67 GLOSSARY The terms defined in this section are used throughout this Prospectus. ANTICLINE. Geologically positive structure favorable for trapping hydrocarbons. Bbl. One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons. Bbls/d. Barrels of oil produced per day. Bcf. One billion cubic feet of natural gas. BOE. One barrel of oil equivalent using the ratio of one barrel of crude oil, condensate or natural gas liquids to 6 Mcf of natural gas. BOE/d. BOEs produced per day. Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit. COMMERCIAL WELL; COMMERCIALLY PRODUCTIVE WELL. An oil and gas well which produces oil and natural gas in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. DEVELOPMENT WELL. A developmental well is a well drilled within the presently proved productive area of an oil or natural gas reservoir, as indicated by reasonable interpretation of available data, with the objective of completing that reservoir. DRY HOLE; DRY WELL; NON-PRODUCTIVE WELL. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well. EXPLORATORY WELL. An exploratory well is a well drilled either in search of a new, as-yet undiscovered oil or natural gas reservoir or to greatly extend the known limits of a previously discovered reservoir. FARMOUT. An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location. FORMATION. A succession of sedimentary beds that were deposited under the same general geologic conditions. GEOPRESSURED. Pressures in excess of the normal increase in pressure with depth. GEOSYNCLINE. A regional area of subsidence in which sediments are accumulated. GROSS ACRES OR GROSS WELLS. The total acres or wells, as the case may be, in which a working interest is owned. HORIZONTAL WELLS. Wells which are drilled at angles greater than 70 degrees from vertical. MBbl. One thousand barrels of crude oil or other liquid hydrocarbons. MBOE. One thousand BOEs. MBOE/d. One thousand BOE/d. MBtu. One thousand Btus. Mcf. One thousand cubic feet of natural gas. Mcf/d. One thousand cubic feet of natural gas produced per day. MMBbl. One million barrels of crude oil or other liquid hydrocarbons. MMBOE. One million BOEs. 67 68 MMBtu. One million Btus. MMcf. One million cubic feet of natural gas. MMcf/d. One million cubic feet of natural gas produced per day. NET; NET REVENUE INTEREST. Production or revenue that is owned by the Company and produced for its interest after deducting royalties and other similar interests. NET ACRES OR NET WELLS. The sum of the fractional working interests owned in gross acres or gross wells. PV10 VALUE. When used with respect to oil and natural gas reserves, PV10 Value means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect at the determination date, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted to present value using an annual discount rate of 10% in accordance with the guidelines of the Commission. PRODUCTIVE WELL. A well that is producing oil or natural gas or that is capable of production. PROVED DEVELOPED RESERVES. Reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. PROVED RESERVES. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. PROVED UNDEVELOPED RESERVES. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. ROYALTY INTEREST. An interest in an oil and natural gas property entitling the owner to a share of oil or natural gas production free of costs of production. Tcf. One trillion cubic feet of natural gas. UNDEVELOPED ACREAGE. Lease acreage on which wells have not been participated in or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. WORKING INTEREST. The cost-bearing interest in a well or property which gives the owner the right to drill, produce and conduct operating activities on the property as well as to a share of production. 68 69 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996 NINE MONTHS ENDED SEPTEMBER 30, 1996 AND 1997 (UNAUDITED)
PAGE ---- DENBURY RESOURCES INC. AND SUBSIDIARIES Independent Auditors' Report.............................. F-2 Consolidated Balance Sheets............................... F-3 Consolidated Statements of Income......................... F-4 Consolidated Statements of Cash Flows..................... F-5 Consolidated Statement of Changes in Shareholders' Equity................................................. F-6 Notes to Consolidated Financial Statements................ F-7 thru F-29 STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF CHEVRON PROPERTIES Report of Independent Accountants......................... F-30 Statements of Revenues and Direct Operating Expenses of Properties............................................. F-31 Notes to Statement of Revenues and Direct Operating Expenses of Properties................................. F-32 thru F-34
F-1 70 INDEPENDENT AUDITORS' REPORT To the Shareholders of Denbury Resources Inc. We have audited the consolidated balance sheets of Denbury Resources Inc. as at December 31, 1995 and 1996 and the consolidated statements of income, changes in shareholders' equity and cash flows for each of the years in the three year period ended December 31, 1996. 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 auditing standards generally accepted in Canada and the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly in all material respects, the financial position of the Company as at December 31, 1995 and 1996 and the results of its operations and the changes in shareholders' equity and cash flows for each of the years in the three year period ended December 31, 1996, in accordance with accounting principles generally accepted in Canada. Deloitte & Touche Chartered Accountants Calgary, Alberta February 21, 1997 F-2 71 DENBURY RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (AMOUNTS IN THOUSANDS OF U.S. DOLLARS)
ASSETS DECEMBER 31, ------------------- SEPTEMBER 30, 1995 1996 1997 -------- -------- ------------- (UNAUDITED) CURRENT ASSETS Cash and cash equivalents................................ $ 6,553 $ 13,453 $ 2,236 Accrued production receivable............................ 3,212 11,906 7,097 Trade and other receivables.............................. 1,160 3,643 14,507 -------- -------- -------- Total current assets............................. 10,925 29,002 23,840 -------- -------- -------- PROPERTY AND EQUIPMENT (USING FULL COST ACCOUNTING) Oil and natural gas properties........................... 72,510 159,724 230,521 Unevaluated oil and natural gas properties............... 7,085 6,413 6,389 Less accumulated depreciation and depletion.............. (13,982) (31,141) (53,527) -------- -------- -------- Net property and equipment....................... 65,613 134,996 183,383 -------- -------- -------- OTHER ASSETS............................................... 1,103 2,507 3,201 -------- -------- -------- TOTAL ASSETS..................................... $ 77,641 $166,505 $210,424 ======== ======== ======== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable and accrued liabilities................. $ 2,872 $ 10,903 $ 16,858 Oil and gas production payable........................... 1,014 5,550 4,060 Current portion of long-term debt........................ 177 67 23 -------- -------- -------- Total current liabilities........................ 4,063 16,520 20,941 -------- -------- -------- LONG-TERM LIABILITIES Senior bank debt......................................... 75 125 20,005 Subordinated debt and other notes payable................ 3,399 -- -- Provision for site reclamation costs..................... 242 613 938 Deferred income taxes and other.......................... 1,361 6,743 12,982 -------- -------- -------- Total long-term liabilities...................... 5,077 7,481 33,925 -------- -------- -------- CONVERTIBLE FIRST PREFERRED SHARES, SERIES A 1,500,000 shares authorized, issued and outstanding at December 31, 1995..................................... 15,000 -- -- -------- -------- -------- SHAREHOLDERS' EQUITY Common shares, no par value unlimited shares authorized; outstanding -- 11,428,809, 20,055,757 and 20,364,799 shares at December 31, 1995, December 31, 1996 and September 30, 1997, respectively...................... 50,064 130,323 132,744 Retained earnings........................................ 3,437 12,181 22,814 -------- -------- -------- Total shareholders' equity....................... 53,501 142,504 155,558 -------- -------- -------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY....... $ 77,641 $166,505 $210,424 ======== ======== ========
See Notes to Consolidated Financial Statements. Approved by the Board: /s/ GARETH ROBERTS /s/ WIELAND F. WETTSTEIN - ----------------------------------------------------- ----------------------------------------------------- Gareth Roberts Wieland F. Wettstein Director Director
F-3 72 DENBURY RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS) (U.S. DOLLARS)
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, --------------------------- ----------------- 1994 1995 1996 1996 1997 ------- ------- ------- ------- ------- (UNAUDITED) REVENUES Oil, natural gas and related product sales................................... $12,692 $20,032 $52,880 $34,709 $60,083 Interest income and other.................. 23 77 769 425 986 ------- ------- ------- ------- ------- Total revenues..................... 12,715 20,109 53,649 35,134 61,069 ------- ------- ------- ------- ------- EXPENSES Production................................. 4,309 6,789 13,495 9,197 15,737 General and administrative................. 1,105 1,832 4,267 2,825 4,535 Interest................................... 1,146 2,085 1,993 1,530 387 Imputed preferred dividends................ -- -- 1,281 1,153 -- Loss on early extinguishment of debt....... -- 200 440 440 -- Depletion and depreciation................. 4,209 8,022 17,904 12,557 23,224 Franchise taxes............................ 65 100 213 160 308 ------- ------- ------- ------- ------- Total expenses..................... 10,834 19,028 39,593 27,862 44,191 ------- ------- ------- ------- ------- Income before income taxes................... 1,881 1,081 14,056 7,272 16,878 Provision for federal income taxes........... (718) (367) (5,312) (2,932) (6,245) ------- ------- ------- ------- ------- NET INCOME................................... $ 1,163 $ 714 $ 8,744 $ 4,340 $10,633 ======= ======= ======= ======= ======= NET INCOME PER COMMON SHARE Primary.................................... $ 0.19 $ 0.10 $ 0.67 $ 0.37 $ 0.53 Fully diluted.............................. 0.19 0.10 0.62 0.36 0.50 ======= ======= ======= ======= ======= Average number of common shares outstanding................................ 6,240 6,870 13,104 11,616 20,175 ======= ======= ======= ======= =======
See Notes to Consolidated Financial Statements F-4 73 DENBURY RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (AMOUNTS IN THOUSANDS OF U.S. DOLLARS)
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, ------------------------------ ------------------- 1994 1995 1996 1996 1997 -------- -------- -------- -------- -------- (UNAUDITED) CASH FLOW FROM OPERATING ACTIVITIES: Net income..................................... $ 1,163 $ 714 $ 8,744 $ 4,340 $ 10,633 Adjustments needed to reconcile to net cash flow provided by operations: Depreciation, depletion and amortization..... 4,304 8,113 17,904 12,557 23,224 Deferred income taxes........................ 718 367 5,312 2,932 6,245 Imputed preferred dividend................... -- -- 1,281 1,153 -- Loss on early extinguishment of debt......... -- 200 440 440 -- Other........................................ -- -- 459 345 64 -------- -------- -------- -------- -------- 6,185 9,394 34,140 21,767 40,166 Changes in working capital items relating to operations: Accrued production receivable................ (986) (1,303) (8,694) (4,388) 4,809 Trade and other receivables.................. (124) (168) (1,508) (659) (10,864) Accounts payable and accrued liabilities..... 1,581 (1,660) 6,711 9,688 5,955 Oil and gas production payable............... 261 490 4,536 2,004 (1,490) -------- -------- -------- -------- -------- NET CASH FLOW PROVIDED BY OPERATIONS............. 6,917 6,753 35,185 28,412 38,576 -------- -------- -------- -------- -------- CASH FLOW USED FOR INVESTING ACTIVITIES: Oil and natural gas expenditures............. (10,297) (11,761) (38,450) (25,704) (54,700) Acquisition of oil and natural gas properties................................. (6,606) (16,763) (48,407) (47,616) (16,073) Net purchases of other assets................ (122) (560) (1,726) (1,290) (1,238) Acquisition of subsidiary, net of cash acquired................................... -- -- 209 209 -- -------- -------- -------- -------- -------- NET CASH USED FOR INVESTING ACTIVITIES........... (17,025) (29,084) (88,374) (74,401) (72,011) -------- -------- -------- -------- -------- CASH FLOW FROM FINANCING ACTIVITIES: Bank borrowings.............................. 9,835 19,350 47,900 44,900 19,900 Bank repayments.............................. (2,485) (34,200) (47,900) -- -- Issuance of subordinated debt................ 1,451 1,772 -- -- -- Issuance of common stock..................... 367 26,825 60,664 1,690 2,421 Issuance of preferred stock.................. -- 15,000 -- -- -- Costs of debt financing...................... (122) (493) (411) (408) (33) Other........................................ 62 (82) (164) (135) (70) -------- -------- -------- -------- -------- NET CASH PROVIDED BY FINANCING ACTIVITIES........ 9,108 28,172 60,089 46,047 22,218 -------- -------- -------- -------- -------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS.................................... (1,000) 5,841 6,900 58 (11,217) CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR... 1,712 712 6,553 6,553 13,453 -------- -------- -------- -------- -------- CASH AND CASH EQUIVALENTS AT END OF PERIOD....... $ 712 $ 6,553 $ 13,453 $ 6,611 $ 2,236 ======== ======== ======== ======== ======== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for interest..... $ 1,027 $ 2,127 $ 1,621 $ 1,080 $ 150 SUPPLEMENTAL DISCLOSURE OF FINANCING ACTIVITIES: Conversion of subordinated debt to common stock...................................... -- -- $ 3,314 $ 1,465 -- Conversion of preferred stock to common stock...................................... -- -- 16,281 -- -- Assumption of liabilities in acquisition..... -- -- 1,321 1,321 --
See Notes to Consolidated Financial Statements F-5 74 DENBURY RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY (DOLLAR AMOUNTS IN THOUSANDS OF U.S. DOLLARS)
COMMON SHARES (NO PAR VALUE) --------------------- RETAINED SHARES AMOUNT EARNINGS TOTAL ---------- -------- -------- -------- BALANCE -- JANUARY 1, 1994........................ 6,208,417 $ 22,872 $ 1,560 $ 24,432 Issued pursuant to employee stock option plan... 96,250 367 -- 367 Net income...................................... -- -- 1,163 1,163 ---------- -------- ------- -------- BALANCE -- DECEMBER 31, 1994...................... 6,304,667 23,239 2,723 25,962 ---------- -------- ------- -------- Issued pursuant to employee stock option plan... 10,000 54 -- 54 Private placement of Special Warrants exchanged.................................... 614,143 2,314 -- 2,314 Private placement of common shares.............. 4,499,999 24,457 -- 24,457 Net income...................................... -- -- 714 714 ---------- -------- ------- -------- BALANCE -- DECEMBER 31, 1995...................... 11,428,809 50,064 3,437 53,501 ---------- -------- ------- -------- Issued pursuant to employee stock option plan... 197,675 1,070 -- 1,070 Issued pursuant to employee stock purchase plan......................................... 31,311 358 -- 358 Public placement of common shares............... 4,940,000 58,776 -- 58,776 Conversion of preferred stock................... 2,816,372 16,281 -- 16,281 Conversion of warrants.......................... 75,000 460 -- 460 Conversion of subordinated debt................. 566,590 3,314 -- 3,314 Net income...................................... -- -- 8,744 8,744 ---------- -------- ------- -------- BALANCE -- DECEMBER 31, 1996...................... 20,055,757 130,323 12,181 142,504 ---------- -------- ------- -------- Issued pursuant to employee stock option plan... 270,056 1,764 -- 1,764 Issued pursuant to employee stock purchase plan......................................... 38,986 657 -- 657 Net income...................................... -- -- 10,633 10,633 ---------- -------- ------- -------- BALANCE -- SEPTEMBER 30, 1997 (UNAUDITED)......... 20,364,799 $132,744 $22,814 $155,558 ========== ======== ======= ========
See Notes to Consolidated Financial Statements F-6 75 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996 AND FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1996 AND 1997 (UNAUDITED) 1. SIGNIFICANT ACCOUNTING POLICIES The Company's operating activities are related to exploration, development and production of oil and natural gas in the United States. All of the Canadian operations were sold effective September 1, 1993. The Company's name was changed on June 7, 1994, from Canadian Newscope Resources Inc. to Newscope Resources Ltd. and again on December 21, 1995 to Denbury Resources Inc. On October 9, 1996 the shareholders of the Company approved an amendment to the Articles of Continuance to consolidate the number of issued and outstanding Common Shares on the basis of one Common Share for each two Common Shares outstanding. All applicable shares and per share data have been adjusted for the reverse stock split. PRINCIPLES OF CONSOLIDATION The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles and include the accounts of the Company and its wholly owned subsidiaries, Denbury Holdings Ltd., Denbury Management, Inc. and Denbury Marine L.L.C. and the Company's equity in the operation of its 50% owned subsidiary, Denbury Energy Services ("Services"). The Company acquired the remaining 50% of Services effective May 1, 1996 and began consolidating all of Services as of that date. All material intercompany balances and transactions have been eliminated. OIL AND NATURAL GAS OPERATIONS a) Capitalized costs The Company follows the full-cost method of accounting for oil and natural gas properties. Under this method, all costs related to the exploration for and development of oil and natural gas reserves are capitalized and accumulated in a single cost center representing the Company's activities undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells and general and administrative expenses directly related to exploration and development activities. Proceeds received from disposals are credited against accumulated costs except when the sale represents a significant disposal of reserves in which case a gain or loss is recognized. b) Depletion and depreciation The costs capitalized, including production equipment, are depleted or depreciated on the unit-of-production method, based on proved oil and natural gas reserves as determined by independent petroleum engineers. Oil and natural gas reserves are converted to equivalent units based upon the relative energy content which is six thousand cubic feet of natural gas to one barrel of crude oil. c) Site reclamation Estimated future costs of well abandonment and site reclamation, including the removal of production facilities at the end of their useful life, are provided for on a unit-of-production basis. Costs are based on engineering estimates of the anticipated method and extent of site restoration, valued at year-end prices, net of estimated salvage value, and in accordance with the current legislation and industry practice. The annual provision for future site reclamation costs is included in depletion and depreciation expense. F-7 76 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) d) Ceiling test The capitalized costs less accumulated depletion, depreciation, related deferred taxes and site reclamation costs are limited to an amount which is not greater than the estimated future net revenue from proved reserves using period-end prices less estimated future site restoration and abandonment costs, future production-related general and administrative expenses, financing costs and income taxes, plus the cost (net of impairments) of undeveloped properties. e) Joint interest operations Substantially all of the Company's oil and natural gas exploration and production activities are conducted jointly with others. These financial statements reflect only the Company's proportionate interest in such activities. FOREIGN CURRENCY TRANSLATION Since 1993 when the Company sold its Canadian oil and natural gas properties, virtually all of the Company's assets are located in the United States. These assets and the United States operations are accounted for and reported in U.S. dollars and no translation is necessary. The minor amount of Canadian assets and liabilities are translated to U.S. dollars using year-end exchange rates and any Canadian operations, which are principally minor administrative and interest expenses, are translated using the historical exchange rate. EARNINGS PER SHARE Net income per common share is computed by dividing the net income attributable to common shareholders by the weighted average number of shares of common stock outstanding. In accordance with Canadian generally accepted accounting principles ("GAAP"), the imputed dividend during 1996 on the Convertible First Preferred Shares, Series A has been recorded as an operating expense in the accompanying financial statements and this is deducted from net income in computing earnings per share. The conversion of the Convertible First Preferred Shares, Series A ("Convertible Preferred") was anti-dilutive and was not included in the calculation of earnings per share. In computing fully diluted earnings per share, the stock options, warrants and convertible debt instruments were dilutive for the year ended December 31, 1996 and for the nine months ended September 30, 1997 and were assumed to be converted or exercised as of the beginning of the respective period with the proceeds used to reduce interest expense. For the prior years, these instruments were either anti-dilutive or immaterial. All of the Convertible Preferred and the convertible debt were converted into common shares during 1996 and thus were not relevant to the calculation of earnings per share during 1997. STATEMENT OF CASH FLOWS For purposes of the Statement of Cash Flows, cash equivalents include time deposits, certificates of deposit and all liquid debt instruments with maturities at the date of purchase of three months or less. REVENUE RECOGNITION The Company follows the "sales method" of accounting for its oil and natural gas revenue whereby the Company recognizes sales revenue on all oil or natural gas sold to its purchasers, regardless of whether the sales are proportionate to the Company's ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 1995 and 1996 and September 30, 1997, the Company's aggregate oil and natural gas imbalances were not material to its financial statements. F-8 77 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The Company recognizes revenue and expenses of purchased producing properties commencing from the closing or agreement date, at which time the Company also assumes control. FINANCIAL INSTRUMENTS WITH OFF-BALANCE SHEET RISK AND CONCENTRATIONS OF CREDIT RISK The Company's product price hedging activities are described in Note 6 to the consolidated financial statements. Credit risk relating to these hedges is minimal because of the credit risk standards required for counter-parties and monthly settlements. The Company has entered into hedging contracts with only large and financially strong companies. The Company's financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents, short-term investments and trade and accrued production receivables. The Company's cash equivalents and short-term investments represent high-quality securities placed with various investment grade institutions. This investment practice limits the Company's exposure to concentrations of credit risk. The Company's trade and accrued production receivables are dispersed among various customers and purchasers; therefore, concentrations of credit risk are limited. Also, the Company's more significant purchasers are large companies with excellent credit ratings. If customers are considered a credit risk, letters of credit are the primary security obtained to support lines of credit. FAIR VALUE OF FINANCIAL INSTRUMENTS As of December 31, 1995, December 31, 1996 and September 30, 1997, the carrying value of the Company's debt and other financial instruments approximates its fair market value. The Company's bank debt is based on a floating interest rate and thus adjusts to market as interest rates change. The Company's other financial instruments are primarily cash, cash equivalents, short-term receivables and payables which approximate fair value due to the nature of the instrument and the relatively short maturities. USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amount of certain assets, liabilities, revenues and expenses as of and for the reporting period. Estimates and assumptions are also required in the disclosure of contingent assets and liabilities as of the date of the financial statements. Actual results may differ from such estimates. INTERIM FINANCIAL DATA In the opinion of management, the accompanying unaudited consolidated financial statements contain all the adjustments (consisting of only normal recurring accruals) necessary to present fairly the consolidated financial position as of September 30, 1997, and the results of its operations and its cash flow for the nine months ended September 30, 1996 and 1997. 2. PROPERTY AND EQUIPMENT UNEVALUATED OIL AND NATURAL GAS PROPERTIES EXCLUDED FROM DEPLETION Under full cost accounting, the Company may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves have been discovered or impairment has occurred. A F-9 78 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) summary of the unevaluated properties excluded from oil and natural gas properties being amortized at December 31, 1995 and 1996 and September 30, 1997 and the year in which they were incurred follows:
DECEMBER 31, 1995 DECEMBER 31, 1996 --------------------------------- ---------------------- INCURRED IN INCURRED IN ------------------------ ---------------------- 1993 1994 1995 TOTAL 1995 1996 TOTAL ------ ------ ------ ------ ---- ------ ------ (AMOUNTS IN THOUSANDS) Property acquisition cost..... $1,151 $1,230 $2,909 $5,290 $252 $2,614 $2,866 Exploration costs............. -- 1,146 649 1,795 87 3,460 3,547 ------ ------ ------ ------ ---- ------ ------ Total............... $1,151 $2,376 $3,558 $7,085 $339 $6,074 $6,413 ====== ====== ====== ====== ==== ====== ======
SEPTEMBER 30, 1997 (UNAUDITED) ---------------------- INCURRED IN ---------------------- 1995 1996 1997 TOTAL ---- ------ ------ ------ (AMOUNTS IN THOUSANDS) Property acquisition cost.............................. $-- $ 286 $ 930 $1,216 Exploration costs...................................... 53 1,457 3,663 5,173 --- ------ ------ ------ Total........................................ $53 $1,743 $4,593 $6,389 === ====== ====== ======
The Company anticipates that approximately $75 million of the costs relating to the Chevron Acquisition which closed in December, 1997 will be classified as unevaluated as of December 31, 1997. Costs are transferred into the amortization base on an ongoing basis as the projects are evaluated and proved reserves established or impairment determined. Pending determination of proved reserves attributable to the above costs, the Company cannot assess the future impact on the amortization rate. General and administrative costs that directly relate to exploration and development activities that were capitalized during the period totaled $480,000, $630,000 and $1,224,000 for the years ended December 31, 1994, 1995 and 1996 and $851,000 and $1,675,000 for the nine months ended September 30, 1996 and 1997, respectively. Amortization per BOE was $4.03, $5.22, $5.99 and $6.40 for the years ended December 31, 1994, 1995 and 1996 and nine months ended September 30, 1997, respectively. 3. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS
DECEMBER 31, ------------- SEPTEMBER 30, 1995 1996 1997 ------ ---- ------------- (AMOUNTS IN THOUSANDS) (UNAUDITED) Senior bank loan......................................... $ 100 $100 $ 20,000 Convertible debentures................................... 3,296 -- -- Other notes payable...................................... 255 92 28 ------ ---- ------------- 3,651 192 20,028 Less portion due within one year......................... (177) (67) (23) ------ ---- ------------- Total long-term debt................................... $3,474 $125 $ 20,005 ====== ==== =============
F-10 79 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) BANKS During 1996 the Company entered into a new $150 million credit facility with NationsBank of Texas, N.A. ("NationsBank"). This refinancing closed on May 31, 1996 and has a borrowing base as of December 31, 1996 of $60 million. NationsBank is the agent bank and the facility includes two other banks. The credit facility is a two-year revolving credit facility that converts to a three year term loan in May 1998, unless renewed or extended. This revolver conversion date was extended to May 1999 on April 1, 1997. The credit facility is secured by virtually all the Company's oil and natural gas properties and interest is payable at either the bank's prime rate or, depending on the percentage of the borrowing base that is outstanding, ranging from LIBOR plus 7/8% to LIBOR plus 1 3/8%. This credit facility also has several restrictions including, among others: (i) a prohibition on the payment of dividends, (ii) a requirement for a minimum equity balance, (iii) a requirement to maintain positive working capital as defined, and (iv) a prohibition of most debt and corporate guarantees. As of December 31, 1996, the Company had $100,000 outstanding on this line of credit and $645,000 of letters of credit outstanding. The Company made two amendments to its bank credit facility during 1997 and revised and restated its facility in December, 1997. See Note 12 for additional disclosures. SUBORDINATED DEBT On March 23, 1994, Denbury issued Cdn. $2,000,000 principal amount of 6 3/4% unsecured convertible debentures and on January 17, 1995, Denbury issued Cdn. $2,500,000 principal amount of 9 1/2% unsecured convertible debentures. These debentures were converted into 566,590 Common Shares during 1996. INDEBTEDNESS REPAYMENT SCHEDULE The Company's indebtedness is repayable as follows:
DECEMBER 31, 1996 ------------------------------------- OTHER NOTES YEAR BANK LOAN PAYABLE TOTAL ---- --------- ----------- ----- (AMOUNTS IN THOUSANDS) 1997.............................................. $ -- $67 $ 67 1998.............................................. 17 23 40 1999.............................................. 33 2 35 2000.............................................. 33 -- 33 2001.............................................. 17 -- 17 ---- --- ---- $100 $92 $192 ==== === ====
F-11 80 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
SEPTEMBER 30, 1997 (UNAUDITED) --------------------------------------- OTHER NOTES YEAR BANK LOAN PAYABLE TOTAL ---- --------- ----------- ------- (AMOUNTS IN THOUSANDS) 1997........................................... $ -- $ 3 $ 3 1998........................................... -- 23 23 1999........................................... 3,333 2 3,335 2000........................................... 6,667 -- 6,667 2001........................................... 6,667 -- 6,667 2002........................................... 3,333 -- 3,333 ------- --- ------- $20,000 $28 $20,028 ======= === =======
4. INCOME TAXES The Company's tax provision is as follows:
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, ----------------------- ------------------ 1994 1995 1996 1996 1997 ----- ----- ------- ------- ------- (AMOUNTS IN THOUSANDS) (UNAUDITED) Deferred Federal.................................... $718 $367 $5,312 $2,932 $5,907 State...................................... -- -- -- -- 338 ---- ---- ------ ------ ------ Total.............................. $718 $367 $5,312 $2,932 $6,245 ==== ==== ====== ====== ======
Income tax expense for the year varies from the amount that would result from applying Canadian federal and provincial tax rates to income before income taxes as follows:
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, ----------------------- ------------------ 1994 1995 1996 1996 1997 ----- ----- ------- ------- -------- (AMOUNTS IN THOUSANDS) (UNAUDITED) Deferred income tax provision calculated using the Canadian federal and provincial statutory combined tax rate of 44.34%............................... $ 834 $ 479 $ 6,233 $3,224 $ 7,484 Increase resulting from: Imputed preferred dividend.............. -- -- 568 511 -- Non-deductible Canadian expenses........ -- -- 97 64 -- Decrease resulting from: Effect of lower income tax rates on United States income................. (116) (112) (1,586) (867) (1,239) ----- ----- ------- ------ ------- $ 718 $ 367 $ 5,312 $2,932 $ 6,245 ===== ===== ======= ====== =======
F-12 81 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The Company at December 31, 1996 had net operating loss carryforwards for U.S. tax purposes of approximately $18,329,000 and approximately $12,485,000 for alternative minimum tax purposes. The net operating losses are scheduled to expire as follows:
INCOME ALTERNATIVE YEAR TAX MINIMUM TAX ---- ------- ------------ (AMOUNTS IN THOUSANDS) 2004.................................................. $ 39 $ -- 2005.................................................. 11 -- 2006.................................................. 644 500 2007.................................................. 714 99 2008.................................................. 5,016 4,889 2009.................................................. 3,377 2,868 2010.................................................. 3,467 3,420 2011.................................................. 5,061 710
5. SHAREHOLDERS' EQUITY AUTHORIZED The Company is authorized to issue an unlimited number of Common Shares with no par value, First Preferred Shares and Second Preferred Shares. The preferred shares may be issued in one or more series with rights and conditions as determined by the Directors. COMMON SHARES Each Common Share entitles the holder thereof to one vote on all matters on which holders are permitted to vote. The Texas Pacific Group ("TPG") was granted a right of first refusal in the private placement (see below), to maintain proportionate ownership. No stockholder has any right to convert common stock into other securities. The holders of shares of common stock are entitled to dividends when and if declared by the Board of Directors from funds legally available therefore and, upon liquidation, to a pro rata share in any distribution to stockholders, subject to prior rights of the holders of the preferred stock. The Company is restricted from declaring or paying any cash dividend on the Common Shares by its bank loan agreement. 1996 CAPITAL ADJUSTMENTS During 1996, the Company issued 250,000 Common Shares for the conversion of the 6 3/4% Convertible Debentures of the Company and 75,000 Common Shares for the exercise of half of the Cdn. $8.40 Warrants ("Warrants"). On October 10, 1996, the Company effected a one-for-two reverse split of its outstanding common Shares. Effective October 15, 1996, all of the Company's outstanding 9 1/2% Convertible Debentures ("Debentures") were converted by their holders in accordance with their terms into 308,642 Common Shares. The holders of the Debentures also received an additional 7,948 Common Shares in lieu of interest which would have been due the holders absent an early conversion of the Debentures. At a special meeting held on October 9, 1996, the shareholders of the Company approved an amendment to the terms of the First Preferred Shares, Series A ("Convertible Preferred") to allow the Company to require the conversion of the Convertible Preferred at any time, provided that the conversion rate in effect as of January 1, 1999 would apply to any required conversion prior to that date. The Company converted all of the 1,500,000 shares of Convertible Preferred on October 30, 1996 into 2,816,372 Common Shares. The Company also issued an aggregate of 4,940,000 Common Shares on October 30, 1996 and November 1, 1996 at a net price of $12.035 per share as part of a public offering for net proceeds to the Company of approximately $58.8 million (the "Public Offering"). TPG purchased 800,000 of these shares at $12.035 per share. F-13 82 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) PRIVATE PLACEMENT OF SECURITIES In December 1995, the Company closed a $40 million private placement of securities with partnerships that are affiliated with the Texas Pacific Group ("TPG Placement"). The TPG Placement was comprised of: (i) 4.166 million common shares issued at $5.85 per share, (ii) 625,000 warrants at a price of $1.00 per warrant entitling the holder to purchase 625,000 common shares at $7.40 per share through December 21, 1999 and (iii) 1.5 million shares of $10 stated value Convertible Preferred. The Convertible Preferred shares were initially convertible at $7.40 of stated value per common share with such conversion rate declining 2.5% per quarter. The shares also had a mandatory redemption at a 63.86% premium at December 21, 2000. The Convertible Preferred were converted into 2,816,372 Common Shares on October 30, 1996. During the period that the Convertible Preferred were outstanding, the Company made a charge to net income to accrue the increase during the period in the mandatory redemption premium. The Company may force conversion of the $7.40 warrants issued in the TPG Placement after December 21, 1997, if the price of the Common Shares exceeds $10.00 per share for a period of 40 consecutive days. As part of the TPG Placement, TPG was granted certain "piggyback" registration rights which allow TPG to include all or part of the Common Shares acquired by TPG in any registration statement of the Company during the first two years. After the initial two years and until December 21, 2000, TPG may request and receive one demand registration statement to register the Common Shares acquired by TPG. The TPG agreement provides that TPG shall have the right, but not the obligation, to maintain its pro rata ownership interest (after the assumed exercise of their warrants) in the equity securities of the Company, in the event that the Company issues any additional equity securities or securities convertible into Common Shares of the Company, by purchasing additional shares of the Company on the same terms and conditions. However, this right expires should TPG's share holdings represent less than 20% of the outstanding Common Shares. TPG waived its right to maintain its pro rata ownership with regard to the Equity Offering. As part of the TPG Placement, Tortuga Investment Corp. was paid a financial advisor fee of 333,333 Common Shares of the Company. The sole shareholder of Tortuga Investment Corp. was appointed to the Board of Directors of the Company and elected Chairman upon the closing of the TPG Placement. WARRANTS At December 31, 1996, 75,000 warrants were outstanding at an exercise price of Cdn. $8.40 expiring on May 5, 2000. TPG holds 625,000 warrants at an exercise price of $7.40 expiring on December 21, 1999. Each warrant entitles the holder thereof to purchase one Common Share at any time prior to the expiration date. SPECIAL WARRANT ISSUES On April 25, 1995, the Company issued 614,143 Special Warrants at a price of $4.70 (Cdn. $6.50) per Special Warrant for gross proceeds of $2,750,000 (29,036 Common Share Purchase Warrants were issued to Southcoast Capital Corporation, as placement agent, in partial payment of their fee). Costs of the issue were $436,000, resulting in net proceeds to the Company of approximately $2,314,000. Each Special Warrant was exchanged, at no additional cost, for one Common Share of Denbury on August 11, 1995. F-14 83 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) STOCK OPTIONS AND STOCK PURCHASE PLAN The Company maintains a Stock Option Plan which authorizes the grant of options of up to 2,243,525 of Common Shares. Under the plan, incentive and non-qualified options may be issued to officers, key employees and consultants. The plan is administered by the Stock Option Committee of the Board. Following is a summary of stock option activity during the years ended December 31, 1994, 1995 and 1996 and the nine months ended September 30, 1997:
YEAR ENDED DECEMBER 31, NINE MONTHS ENDED ------------------------------------------------------------------- SEPTEMBER 30, 1994 1995 1996 1997 ------------------- ------------------- --------------------- --------------------- WEIGHTED WEIGHTED WEIGHTED WEIGHTED AVERAGE AVERAGE AVERAGE AVERAGE NUMBER PRICE NUMBER PRICE NUMBER PRICE NUMBER PRICE ------- -------- ------- -------- --------- -------- --------- -------- (UNAUDITED) OUTSTANDING AT BEGINNING OF PERIOD.............. 541,312 $6.68 557,312 $6.30 731,925 $6.11 1,053,000 $ 7.63 Granted............... 138,750 5.64 274,500 5.89 525,500 8.96 750,512 13.64 Terminated............ (26,500) 9.35 (89,887) 7.79 (6,750) 6.28 (21,250) 12.02 Exercised............. (96,250) 3.74 (10,000) 5.42 (197,675) 5.42 (270,056) 6.93 Expired............... -- -- -- -- -- -- -- -- ------- ----- ------- ----- --------- ----- --------- ------ OUTSTANDING AT END OF PERIOD.............. 557,312 $6.30 731,925 $6.11 1,053,000 $7.63 1,512,206 $10.69 ======= ===== ======= ===== ========= ===== ========= ====== Options exercisable at end of period....... 487,937 $6.39 539,675 $6.19 532,375 $6.82 395,222 $ 7.56 ======= ===== ======= ===== ========= ===== ========= ======
WEIGHTED WEIGHTED OPTIONS OUTSTANDING AS OF OPTIONS AVERAGE WEIGHTED AVERAGE EXERCISABLE AVERAGE DECEMBER 31, 1996: OUTSTANDING PRICE REMAINING LIFE (YRS.) OPTIONS PRICE - ------------------------- ----------- -------- --------------------- ----------- -------- Exercise price of: $3.65 to $6.99 372,000 $ 5.79 4.3 305,250 $ 5.77 $7.00 to $9.99 444,625 7.78 6.5 175,906 7.70 $10.00 to $14.87 236,375 10.23 9.4 51,219 10.09
In February 1996, the Company also implemented a Stock Purchase Plan which authorizes the sale of up to 250,000 Common Shares to all full-time employees with at least six months of service. Under the plan, the employees may contribute up to 10% of their base salary and the Company matches 75% of the employee contribution. The combined funds are used to purchase previously unissued Common Shares of the Company based on its current market value at the end of the each quarter. The Company recognizes compensation expense for the 75% Company matching portion, which for 1996 totaled $147,000 and for the nine months ended September 30, 1997 totaled $282,000. This plan is administered by the Stock Purchase Plan Committee of the Board. 6. PRODUCT PRICE HEDGING CONTRACTS In October 1994, the Company entered into two financial contracts ("collars") to hedge 10,000 Mcf/d of natural gas production for calendar year 1995. The first natural gas contract for 8,000 Mcf/d of natural gas had a floor of $1.845 per MMBTU and a ceiling of $2.095 per MMBTU. The second natural gas contract was for 2,000 Mcf/d and had a floor of $1.775 per MMBTU and a ceiling of $1.885 per MMBTU. These contracts covered 75% of the Company's net revenue interest production in 1995 and increased oil and natural gas revenues by approximately $800,000 during such period. In addition, in 1995 the Company entered into two swap contracts for oil. The first oil contract was for 500 Bbls/d of oil at a price of $17.79 per barrel of oil commencing on February 1, 1995, and ending on January 31, 1996. The second oil contract was also for 500 Bbls/d of oil at a price of $18.83, for the period commencing on April 12, 1995, and ending on December 30, 1995. These contracts covered 43% of the Company's net revenue interest production for 1995 and decreased oil and natural gas revenues by approximately $47,000 during such period. F-15 84 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The Company did not have any hedge contracts in place as of December 31, 1996 or September 30, 1997. 7. COMMITMENTS AND CONTINGENCIES The Company has operating leases for the rental of office space, office equipment, and vehicles. At December 31, 1996, and September 30, 1997 long-term commitments for these items require the following future minimum rental payments:
DECEMBER 31, SEPTEMBER 30, 1996 1997 ------------ ------------- (AMOUNTS IN THOUSANDS) (UNAUDITED) 1997............................................. $ 442 $ 123 1998............................................. 441 474 1999............................................. 166 988 2000............................................. -- 1,196 2001............................................. -- 1,192 2002............................................. -- 1,178 ------ ------ $1,049 $5,151 ====== ======
On August 6, 1997, the Company entered into a ten year office lease. See Note 12. The Company is subject to various possible contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases and other matters. Although management believes it has complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. In addition, production rates, marketing and environmental matters are subject to regulation by various federal and state agencies. The Company is not currently a party to any litigation which would have a material impact on its financial statements. However, due to the nature of its business, certain legal or administrative proceedings may arise in the ordinary course of its business. 8. DIFFERENCES IN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES BETWEEN CANADA AND THE UNITED STATES The consolidated financial statements have been prepared in accordance with GAAP in Canada. The primary differences between Canadian and U.S. GAAP affecting the Company's consolidated financial statements are as discussed below. LOSS ON EXTINGUISHMENT OF DEBT AND IMPUTED PREFERRED DIVIDENDS The most significant GAAP difference relates to the presentation of the early extinguishment of debt and the imputed dividend on the Convertible Preferred. During 1996, the Company expensed $1,281,000 relating to the imputed preferred dividend, as required under Canadian GAAP. Under U.S. GAAP, this dividend would be deducted from net income to compute the net income attributable to the common shareholders. The Company also expensed its debt issue cost relating to the Company's prior bank credit agreements totaling $200,000 and $440,000 for 1995 and 1996, respectively. Under Canadian GAAP this is an operating expense, while under U.S. GAAP a loss on early extinguishment of debt is an extraordinary item. While net income per common share and all balance sheet accounts are not affected by these differences in GAAP, the net income F-16 85 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) for 1995 and 1996 under U.S. GAAP would be $714,000 and $10,025,000, respectively, while under Canadian GAAP the amounts reported were $714,000 and $8,744,000, respectively. EARNINGS PER SHARE In addition, the methodology for computing earnings per common share is not consistent between the two countries. For Canadian purposes, dilutive securities are only considered in the fully diluted presentation of earnings per share and the proceeds from such dilutive securities are used to reduce debt in the calculation. Under U.S. GAAP, the proceeds from such instruments are used to repurchase Common Shares, using a slightly different methodology for the primary and fully diluted calculations. For the years ended December 31, 1994 and 1995, the stock options, warrants, convertible debt and the conversion of the Convertible Preferred were either anti-dilutive or immaterial and were not included in the earnings per share under either GAAP calculation. For the year ended December 31, 1996, the Convertible Preferred was still anti-dilutive, but the stock options, convertible debt and warrants were dilutive and included in the earnings per share calculations, but with different results under the two respective GAAP's. Under U.S. GAAP for the year ended December 31, 1996, the primary earnings per share would be $.64 and the fully-diluted earnings per share would be $.63 as compared to the $.67 and $.62 as reported under Canadian GAAP. For the first nine months of 1996, under U.S. GAAP, the primary and fully-diluted earnings per common share would be $0.36 and $0.35, compared to the $0.37 and $0.36, respectively, as reported under Canadian GAAP. Under U.S. GAAP for the first nine months of 1997, the primary and fully-diluted earnings per common share would be $0.50 and $0.49, as compared to the $0.53 and $0.50, respectively, as reported under Canadian GAAP. During 1996, the Company issued 4,940,000 Common Shares in a public offering and used a portion of the proceeds to retire bank debt. On a pro forma basis using U.S. GAAP and assuming that the Common Shares had been issued as of January 1, 1996 and the interest expense for 1996 relating to the bank debt was reversed, the primary earnings per share would be $.57 per share. No interest income was assumed in the pro forma calculation even though the proceeds from the equity issuance exceeded the bank debt that was retired. STOCK-BASED COMPENSATION In 1995, the United States Financial Accounting Standards Board issued Statement of Financial Accounting Standards ("SFAS") No. 123, "Accounting for Stock-Based Compensation." SFAS No. 123 is effective for fiscal years beginning after December 31, 1995 and requires companies to use recognized option pricing models to estimate the fair value of stock-based compensation, including stock options. The Statement requires additional disclosures based on this fair value based method of accounting for an employee stock option and encourages, but does not require, companies to recognize the value of these stock option grants as additional compensation using the methodology of SFAS No. 123. The Company has elected to continue recognizing expense as prescribed by APB Opinion No. 25, "Accounting for Stock Issued to Employees", as allowed under SFAS No. 123 rather than recognizing compensation expense as calculated under SFAS No. 123. As such, the adoption of SFAS No. 123 during 1996 did not have any effect on the Company's consolidated financial statements. F-17 86 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The Company has two stock-based compensation plans as more fully described in Note 5. With regard to its stock option plan, the Company applies APB Opinion No. 25 in accounting for this plan and accordingly no compensation cost has been recognized. Had compensation expense been determined based on the fair value at the grant dates for the stock option grants consistent with the method of SFAS No. 123, the Company's net income and net income per common share would have been reduced to the pro forma amounts indicated below:
YEAR ENDED DECEMBER 31, ----------------------- 1995 1996 ------- -------- Net income: As reported (thousands)................................... $ 714 $8,744 Pro forma (thousands)..................................... 503 8,215 Net income per common share: As reported............................................... $0.10 $ 0.67 Pro forma................................................. 0.07 0.63 Stock options issued during period (thousands).............. 275 526 Weighted average exercise price............................. $5.90 $ 8.96 Average per option compensation value of options granted(a)................................................ 2.34 2.95 Compensation cost (thousands)............................... 320 801
- --------------- (a) Calculated in accordance with the Black-Scholes option pricing model, using the following assumptions; expected volatility computed using, as of the date of grant, the prior three-year monthly average of the Common Shares as listed on the TSE, which ranged from 32% to 67%; expected dividend yield -- 0%; expected option term -- 3 years, and risk-free rate of return as of the date of grant which ranged from 5.3% to 7.8%, based on the yield of five-year U.S. treasury securities. DEFERRED INCOME TAXES Deferred income taxes relate to temporary differences based on tax laws and statutory rates in effect at the December 31, 1995 and 1996 balance sheet dates. At December 31, 1995, and 1996, all deferred tax assets and liabilities were computed based on Canadian GAAP amounts and were noncurrent as follows:
NINE MONTHS ENDED DECEMBER 31, SEPTEMBER 30, ------------------ ------------- 1995 1996 1997 ------- ------- ------------- (AMOUNTS IN THOUSANDS) (UNAUDITED) Deferred tax assets: Loss carryforwards............................... $(4,511) $(4,902) $(10,100) Deferred tax liabilities: Exploration and intangible development costs..... 5,942 11,645 23,088 ------- ------- -------- Net deferred tax liability......................... $ 1,431 $ 6,743 $ 12,988 ======= ======= ========
RECENTLY ISSUED ACCOUNTING STANDARDS The Accounting Standards Executive Committee of the American Institute of Certified Public Accountants has adopted Statement of Position 96-1, "Environmental Remediation Liabilities," which provides guidance on the recognition, measurement, display and disclosure of environmental remediation liabilities. The Statement is effective for the Company's 1997 fiscal year. Management evaluated such Statement and believes that it will not have a material effect on the financial position or results of operations of the Company. F-18 87 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In February 1997 the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 128 Earnings Per Share, ("SFAS 128") simplifies the standards for computing earnings per share ("EPS") and makes them more comparable to international EPS standards. SFAS 128 replaces the presentation of primary EPS with a presentation of basic EPS. Basic EPS excludes dilution and is computed by dividing income available to common shareholders by the weighted average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised, converted into common stock or resulted in the issuance of common shares that then shared in the earnings of the entity. Diluted EPS is computed similarly to fully diluted EPS pursuant to Accounting Principles Board Opinion No. 15. SFAS 128 is effective for financial statements issued for periods ending after December 15, 1997, including interim periods. Earlier application is not permitted. Basic EPS for the year ended December 31, 1994, 1995 and 1996 and the nine months ended September 30, 1996 and 1997 under SFAS 128 would $0.19, $0.10, $0.67, $0.37, and $0.53 per common share respectively. This compares to $0.19, $0.10, $0.64, $0.36, and $0.50 respective periods as computed under current U.S. GAAP. In June 1997, the FASB issued SFAS No. 130, "Reporting Comprehensive Income" and SFAS No. 131, "Disclosures About Segments of an Enterprise and Related Information." SFAS No. 130 establishes standards for reporting and display of comprehensive income in the financial statements. Comprehensive income is the total of net income and all other non-owner changes in equity. SFAS No. 131 requires that companies disclose segment data based on how management makes decisions about allocating resources to segments and measuring their performance. SFAS Nos. 130 and 131 are effective for 1998. Adoption of these standards is not expected to have an effect on the Company's financial statements, financial position or results of operations. 9. SUPPLEMENTAL INFORMATION SIGNIFICANT OIL AND NATURAL GAS PURCHASERS Oil and natural gas sales are made on a day-to-day basis or under short-term contracts at the current area market price. The loss of any purchaser would not be expected to have a material adverse effect upon operations. For the period ended December 31, 1996, the Company sold 10% or more of its net production of oil and natural gas to the following purchasers: Natural Gas Clearinghouse (20%), Penn Union Energy Services (19%), Enron Oil Trading & Transportation (13%), and Hunt Refining (15%). COSTS INCURRED The following table summarizes costs incurred in oil and natural gas property acquisition, exploration and development activities. Property acquisition costs are those costs incurred to purchase, lease, or otherwise acquire property, including both undeveloped leasehold and the purchase of revenues in place. Exploration costs include costs of identifying areas that may warrant examination and in examining specific areas that are considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserves, including the cost of drilling development wells, and to provide facilities for extracting, treating, gathering, and storing the oil and natural gas. F-19 88 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Costs incurred in oil and natural gas activities for the years ended December 31, 1994, 1995 and 1996 and the nine months ended September 1997 are as follows:
NINE MONTHS YEAR ENDED DECEMBER 31, ENDED --------------------------- SEPTEMBER 30, 1994 1995 1996 1997 ------- ------- ------- ------------- (AMOUNTS IN THOUSANDS) (UNAUDITED) Property acquisition......................... $ 6,736 $17,198 $48,856 $17,592 Exploration.................................. 1,796 1,687 4,592 14,058 Development.................................. 8,371 9,639 33,409 39,123 ------- ------- ------- ------- $16,903 $28,524 $86,857 $70,773 ======= ======= ======= =======
PROPERTY ACQUISITIONS During April 1996, the Company closed an acquisition of additional working interests in five Mississippi oil and natural gas properties in which the Company already owned an interest, plus certain overriding royalty interests in other areas for approximately $7.5 million (the "Ottawa Acquisition"). The properties were acquired from Ottawa Energy, Inc., a subsidiary of Highridge Exploration Ltd. On April 17, 1996, Denbury entered into a purchase and sale agreement with Amerada Hess Corporation to purchase producing oil and natural gas properties in Mississippi, Louisiana and Alabama, plus certain overriding royalty interests in Ohio, for approximately $37.2 million (the "Hess Acquisition"). The Company funded this acquisition with bank financing from its NationsBank credit facility and closed this transaction during June 1996. These two acquisitions were accounted for under purchase accounting and the results of operations were consolidated during the second quarter of 1996. Pro forma results of operations of the Company as if the acquisitions had occurred at the beginning of each respective period are as follows:
YEAR ENDED DECEMBER 31, ----------------- 1995 1996 ------- ------- Revenues (thousands)........................................ $41,273 $61,573 Net income (thousands)...................................... 899 9,820 Net income per common share................................. 0.13 0.75
In computing the pro forma results, depreciation, depletion and amortization expense was computed using the units of production method, and an adjustment was made to interest expense reflecting the bank debt that was required to fund the acquisitions. The pro forma results reflect an increase of $250,000 and $500,000 for 1996 and 1995, respectively, in general and administrative expense for additional personnel and associated costs relating to the acquired properties, net of anticipated allocations to operations and capitalization of exploration costs. F-20 89 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following represents the revenues and direct operating expenses attributable to the net interest acquired in the Hess Acquisition by the Company and are presented on the full cost accrual basis of accounting. Depreciation, depletion, and amortization, allocated general and administrative expenses, interest expense and income, and income taxes have been excluded because the property interests acquired represent only a portion of a business and these expenses are not necessarily indicative of the expenses to be incurred by the Company.
YEAR ENDED DECEMBER 31, --------------------------- 1994 1995 1996 ------- ------- ------- (AMOUNTS IN THOUSANDS) Revenues: Oil, natural gas and related product sales............. $17,787 $18,210 $20,165 Direct operating expenses: Lease operating expense................................ 6,598 7,888 6,302 ------- ------- ------- Excess of revenues over direct operating expenses........ $11,189 $10,322 $13,863 ======= ======= =======
The following represents the revenues and direct operating expenses attributable to the net interest acquired in the Ottawa Acquisition by the Company and are presented on the full cost accrual basis of accounting. Depreciation, depletion, and amortization, allocated general and administrative expenses, interest expense and income, and income taxes have been excluded because the property interests acquired represent only a portion of a business and these expenses are not necessarily indicative of the expenses to be incurred by the Company.
YEAR ENDED DECEMBER 31, 1996 ------------ (AMOUNTS IN THOUSANDS) Revenues: Oil, natural gas and related product sales................ $4,215 Direct operating expenses: Lease operating expense................................... 760 ------ Excess of revenues over direct operating expenses........... $3,455 ======
In November 1995, the Company acquired seven producing wells and certain non-producing leases in the Gibson/Humphreys Fields of Terrebonne Parish, Louisiana for approximately $10.2 million. See also Note 12 for disclosures regarding the Chevron Acquisition made in December, 1997. F-21 90 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 10. CONDENSED CONSOLIDATING FINANCIAL INFORMATION Denbury Management, Inc. will be issuing debt securities during early 1998 which will be fully and unconditionally guaranteed by Denbury Resources Inc. Denbury Holdings Ltd. was merged into Denbury Resources Inc. in December 1997 and is not a guarantor of the debt. Condensed consolidating financial information for Denbury Resources Inc. and Subsidiaries as of December 31, 1995 and 1996 and September 30, 1997 and for the years ended December 31, 1994, 1995 and 1996 and for the nine months ended September 30, 1996 and 1997 is as follows: DENBURY RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS (IN THOUSANDS OF U.S. DOLLARS)
DECEMBER 31, 1995 ------------------------------------------------------------------------------ DENBURY DENBURY DENBURY MANAGEMENT DENBURY RESOURCES INC. RESOURCES INC. INC. (ISSUER) HOLDINGS LTD. (GUARANTOR) ELIMINATIONS CONSOLIDATED ------------- ------------- -------------- ------------ -------------- ASSETS Current assets.......................... $10,910 $ -- $ 15 $ -- $10,925 Property and equipment (using full cost accounting)........................... 65,613 -- -- -- 65,613 Investment in subsidiaries (equity method)............................... -- 71,693 70,130 (141,823) -- Other assets............................ 1,075 -- 1,591 (1,563) 1,103 ------- ------- ------- --------- ------- Total assets................... $77,598 $71,693 $71,736 $(143,386) $77,641 ======= ======= ======= ========= ======= LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities..................... $ 4,054 $ -- $ 9 $ -- $ 4,063 Long-term liabilities................... 1,851 1,563 3,226 (1,563) 5,077 Convertible First Preferred Shares...... -- -- 15,000 -- 15,000 Shareholders' equity.................... 71,693 70,130 53,501 (141,823) 53,501 ------- ------- ------- --------- ------- Total liabilities and shareholders' equity......... $77,598 $71,693 $71,736 $(143,386) $77,641 ======= ======= ======= ========= =======
F-22 91 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) DENBURY RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS (IN THOUSANDS OF U.S. DOLLARS)
DECEMBER 31, 1996 ------------------------------------------------------------------------------ DENBURY DENBURY DENBURY MANAGEMENT DENBURY RESOURCES INC. RESOURCES INC. INC. (ISSUER) HOLDINGS LTD. (GUARANTOR) ELIMINATIONS CONSOLIDATED ------------- ------------- -------------- ------------ -------------- ASSETS Current assets............................. $ 28,722 $ -- $ 280 $ -- $ 29,002 Property and equipment (using full cost accounting).............................. 134,996 -- -- -- 134,996 Investment in subsidiaries (equity method).................................. -- 142,321 140,763 (283,084) -- Other assets............................... 2,505 -- 1,560 (1,558) 2,507 -------- -------- -------- --------- -------- Total assets....................... $166,223 $142,321 $142,603 $(284,642) $166,505 ======== ======== ======== ========= ======== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities........................ $ 16,421 $ -- $ 99 $ -- $ 16,520 Long-term liabilities...................... 7,481 1,558 -- (1,558) 7,481 Shareholders' equity....................... 142,321 140,763 142,504 (283,084) 142,504 -------- -------- -------- --------- -------- Total liabilities and shareholders' equity........................... $166,223 $142,321 $142,603 $(284,642) $166,505 ======== ======== ======== ========= ========
SEPTEMBER 30, 1997 (UNAUDITED) ------------------------------------------------------------------------------ DENBURY DENBURY DENBURY MANAGEMENT DENBURY RESOURCES INC. RESOURCES INC. INC. (ISSUER) HOLDINGS LTD. (GUARANTOR) ELIMINATIONS CONSOLIDATED ------------- ------------- -------------- ------------ -------------- ASSETS Current assets............................. $ 23,453 $ -- $ 387 $ -- $ 23,840 Property and equipment (using full cost accounting).............................. 183,383 -- -- -- 183,383 Investment in subsidiaries (equity method).................................. -- 155,174 153,630 (308,804) -- Other assets............................... 3,200 -- 1,545 (1,544) 3,201 -------- -------- -------- --------- -------- Total assets....................... $210,036 $155,174 $155,562 $(310,348) $210,424 ======== ======== ======== ========= ======== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities........................ $ 20,937 $ -- $ 4 $ -- $ 20,941 Long-term liabilities...................... 33,925 1,544 -- (1,544) 33,925 Shareholders' equity....................... 155,174 153,630 155,558 (308,804) 155,558 -------- -------- -------- --------- -------- Total liabilities and shareholders' equity........................... $210,036 $155,174 $155,562 $(310,348) $210,424 ======== ======== ======== ========= ========
F-23 92 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) DENBURY RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF INCOME (IN THOUSANDS OF U.S. DOLLARS)
YEAR ENDED DECEMBER 31, 1994 ------------------------------------------------------------------------------ DENBURY DENBURY DENBURY MANAGEMENT DENBURY RESOURCES INC. RESOURCES INC. INC. (ISSUER) HOLDINGS LTD. (GUARANTOR) ELIMINATIONS CONSOLIDATED ------------- ------------- -------------- ------------ -------------- Revenues................................... $12,714 $ -- $ 1 $ -- $12,715 Expenses................................... 10,607 -- 227 -- 10,834 ------- ------- ------- -------- ------- Income (loss) before the following: 2,107 -- (226) -- 1,881 Equity in net earnings of subsidiaries... -- 1,389 1,389 (2,778) -- ------- ------- ------- -------- ------- Income before income taxes................. 2,107 1,389 1,163 (2,778) 1,881 Provision for federal income taxes......... (718) -- -- -- (718) ------- ------- ------- -------- ------- Net income................................. $ 1,389 $ 1,389 $ 1,163 $ (2,778) $ 1,163 ======= ======= ======= ======== =======
YEAR ENDED DECEMBER 31, 1995 ------------------------------------------------------------------------------ DENBURY DENBURY DENBURY MANAGEMENT DENBURY RESOURCES INC. RESOURCES INC. INC. (ISSUER) HOLDINGS LTD. (GUARANTOR) ELIMINATIONS CONSOLIDATED ------------- ------------- -------------- ------------ -------------- Revenues................................... $20,107 $ -- $ 460 $ (458) $20,109 Expenses................................... 19,026 -- 460 (458) 19,028 ------- ------- ------ --------- ------- Income (loss) before the following: 1,081 -- -- -- 1,081 Equity in net earnings of subsidiaries... -- 714 714 (1,428) -- ------- ------- ------ --------- ------- Income before income taxes................. 1,081 714 714 (1,428) 1,081 Provision for federal income taxes......... (367) -- -- -- (367) ------- ------- ------ --------- ------- Net income................................. $ 714 $ 714 $ 714 $ (1,428) $ 714 ======= ======= ====== ========= =======
YEAR ENDED DECEMBER 31, 1996 ------------------------------------------------------------------------------ DENBURY DENBURY DENBURY MANAGEMENT DENBURY RESOURCES INC. RESOURCES INC. INC. (ISSUER) HOLDINGS LTD. (GUARANTOR) ELIMINATIONS CONSOLIDATED ------------- ------------- -------------- ------------ -------------- Revenues................................... $53,631 $ -- $ 179 $ (161) $53,649 Expenses................................... 38,008 -- 1,746 (161) 39,593 ------- ------- ------- -------- ------- Income (loss) before the following: 15,623 -- (1,567) -- 14,056 Equity in net earnings of subsidiaries... -- 10,311 10,311 (20,622) -- ------- ------- ------- -------- ------- Income before income taxes................. 15,623 10,311 8,744 (20,622) 14,056 Provision for federal income taxes......... (5,312) -- -- -- (5,312) ------- ------- ------- -------- ------- Net income................................. $10,311 $10,311 $ 8,744 $(20,622) $ 8,744 ======= ======= ======= ======== =======
F-24 93 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) DENBURY RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF INCOME (IN THOUSANDS OF U.S. DOLLARS)
NINE MONTHS ENDED SEPTEMBER 30, 1996 (UNAUDITED) ------------------------------------------------------------------------------ DENBURY DENBURY DENBURY MANAGEMENT DENBURY RESOURCES INC. RESOURCES INC. INC. (ISSUER) HOLDINGS LTD. (GUARANTOR) ELIMINATIONS CONSOLIDATED ------------- ------------- -------------- ------------ -------------- Revenues................................... $35,130 $ -- $ 117 $ (113) $35,134 Expenses................................... 26,507 -- 1,468 (113) 27,862 ------- ------- ------- --------- ------- Income (loss) before the following: 8,623 -- (1,351) -- 7,272 Equity in net earnings of subsidiaries... -- 5,691 5,691 (11,382) -- ------- ------- ------- --------- ------- Income before income taxes................. 8,623 5,691 4,340 (11,382) 7,272 Provision for federal income taxes......... (2,932) -- -- -- (2,932) ------- ------- ------- --------- ------- Net income................................. $ 5,691 $ 5,691 $ 4,340 $ (11,382) $ 4,340 ======= ======= ======= ========= =======
NINE MONTHS ENDED SEPTEMBER 30, 1997 (UNAUDITED) ------------------------------------------------------------------------------ DENBURY DENBURY DENBURY MANAGEMENT DENBURY RESOURCES INC. RESOURCES INC. INC. (ISSUER) HOLDINGS LTD. (GUARANTOR) ELIMINATIONS CONSOLIDATED ------------- ------------- -------------- ------------ -------------- Revenues................................... $61,066 $ -- $ 105 $ (102) $61,069 Expenses................................... 44,191 -- 102 (102) 44,191 ------- ------- ------- --------- ------- Income (loss) before the following: 16,875 -- 3 -- 16,878 Equity in net earnings of subsidiaries... -- 10,630 10,630 (21,260) -- ------- ------- ------- --------- ------- Income before income taxes................. 16,875 10,630 10,633 (21,260) 16,878 Provision for federal income taxes......... (6,245) -- -- -- (6,245) ------- ------- ------- --------- ------- Net income................................. $10,630 $10,630 $10,633 $ (21,260) $10,633 ======= ======= ======= ========= =======
11. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED) Net proved oil and natural gas reserve estimates as of December 31, 1995 and 1996 were prepared by Netherland & Sewell and the net oil and natural gas reserve estimates as of December 31, 1994 were prepared by The Scotia Group, Inc., both independent petroleum engineers located in Dallas, Texas. The reserves were prepared in accordance with guidelines established by the Securities and Exchange Commission and accordingly, were based on existing economic and operating conditions. Oil and natural gas prices in effect as of the reserve report date were used without any escalation except in those instances where the sale is covered by contract, in which case the applicable contract prices including fixed and determinable escalations were used for the duration of the contract, and thereafter the last contract price was used. Operating costs, production and ad valorem taxes and future development costs were based on current costs with no escalation. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. Moreover, the present values should not be construed as the current market value of the Company's oil and natural gas reserves or the costs that would be incurred to obtain equivalent reserves. All of the reserves are located in the United States. F-25 94 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) ESTIMATED QUANTITIES OF RESERVES
YEAR ENDED DECEMBER 31, --------------------------------------------------- 1994 1995 1996 --------------- --------------- --------------- OIL GAS OIL GAS OIL GAS (MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF) ------ ------ ------ ------ ------ ------ Balance beginning of year............... 3,583 13,029 4,230 42,047 6,292 48,116 Revisions of previous estimates....... (48) 2,827 830 (1,620) (490) 3,737 Revisions due to price changes........ -- -- -- -- 1,053 402 Extensions, discoveries and other additions.......................... 640 14,978 732 -- 3,492 5,480 Production............................ (489) (3,326) (728) (4,844) (1,500) (8,933) Acquisition of minerals in place...... 544 14,539 1,228 12,533 6,205 25,300 ----- ------ ----- ------ ------ ------ Balance at end of period................ 4,230 42,047 6,292 48,116 15,052 74,102 ===== ====== ===== ====== ====== ====== Proved developed reserves: Balance at beginning of year.......... 3,418 12,303 3,755 35,578 5,290 34,894 Balance at end of period.............. 3,755 35,578 5,290 34,894 13,371 58,634
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN RELATING TO PROVED OIL AND NATURAL GAS RESERVES The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves ("Standardized Measure") does not purport to present the fair market value of the Company's oil and natural gas properties. An estimate of such value should consider, among other factors, anticipated future prices of oil and natural gas, the probability of recoveries in excess of existing proved reserves, the value of probable reserves and acreage prospects, and perhaps different discount rates. It should be noted that estimates of reserve quantities, especially from new discoveries, are inherently imprecise and subject to substantial revision. Under the Standardized Measure, future cash inflows were estimated by applying year-end prices, adjusted for fixed and determinable escalations, to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash inflows over the Company's tax basis in the associated proved oil and natural gas properties. Tax credits and net operating loss carry forwards were also considered in the future income tax calculation. Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure.
DECEMBER 31, ------------------------------- 1994 1995 1996 -------- -------- --------- (AMOUNTS IN THOUSANDS) Future cash inflows................................. $126,129 $214,932 $ 627,476 Future production costs............................. (35,069) (56,323) (134,986) Future development costs............................ (7,369) (16,154) (28,722) -------- -------- --------- Future net cash flows before taxes.................. 83,691 142,455 463,768 10% annual discount for estimated timing of cash flows.......................................... (31,000) (45,490) (147,670) -------- -------- --------- Discounted future net cash flows before taxes....... 52,691 96,965 316,098 Discounted future income taxes...................... (5,763) (15,801) (74,226) -------- -------- --------- Standardized measure of discounted future net cash.............................................. $ 46,928 $ 81,164 $ 241,872 ======== ======== =========
F-26 95 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following table sets forth an analysis of changes in the Standardized Measure of Discounted Future Net Cash Flows from proved oil and natural gas reserves:
YEAR ENDED DECEMBER 31, ----------------------------- 1994 1995 1996 ------- -------- -------- (AMOUNTS IN THOUSANDS) Beginning of year..................................... $28,465 $ 46,928 $ 81,164 Sales of oil and natural gas produced, net of production costs.................................... (8,383) (13,243) (39,385) Net changes in sales prices........................... 863 23,037 116,587 Extensions and discoveries, less applicable future development and production costs.................... 13,416 1,926 34,113 Previously estimated development costs incurred....... 2,492 2,193 5,278 Revisions of previous estimates, including revised estimates of development costs, reserves and rates of production....................................... (2,914) 3,958 7,747 Accretion of discount................................. 2,847 4,693 8,116 Purchase of minerals in place......................... 15,732 21,710 86,677 Net change in income taxes............................ (5,590) (10,038) (58,425) ------- -------- -------- End of period......................................... $46,928 $ 81,164 $241,872 ======= ======== ========
12. SUBSEQUENT EVENTS (UNAUDITED) On December 30, 1997, Denbury acquired producing oil and natural gas properties in Mississippi, for approximately $202 million (the "Chevron Acquisition"). The acquisition included 122 wells, of which 96 wells will be Company operated. The Company funded this acquisition with bank financing from a revised and restated credit facility. This acquisition was accounted for under purchase accounting and the results of operations will be consolidated effective December 31, 1997. Pro forma results of operations of the Company as if the Chevron Acquisition had occurred at the beginning of each respective period are as follows:
NINE MONTHS ENDED YEAR ENDED SEPTEMBER 30, DECEMBER 31, ---------------------- 1996 1996 1997 -------------- --------- --------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Revenues........................................... $77,311 $52,534 $75,103 Net income......................................... 4,909 1,181 6,886 Net income per common share........................ 0.37 0.10 0.34
In computing the pro forma results, depreciation, depletion and amortization expense was computed using the units of production method, and an adjustment was made to interest expense reflecting the bank debt that was required to fund the acquisitions. The pro forma results reflect an increase of $687,000, $514,000 and $514,000 for 1996 and the nine months ended September 30, 1996 and 1997, respectively, in general and administrative expense for additional personnel and associated costs relating to the acquired properties, net of anticipated allocations to operations and capitalization of exploration costs. F-27 96 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following represents the revenues and direct operating expenses attributable to the net interest acquired in the Chevron Acquisition by the Company and are presented on the full cost accrual basis of accounting. Depreciation, depletion, and amortization, allocated general and administrative expenses, interest expense and income, and income taxes have been excluded because the property interests acquired represent only a portion of a business and these expenses are not necessarily indicative of the expenses to be incurred by the Company.
YEAR ENDED NINE MONTHS DECEMBER 31, ENDED ----------------- SEPTEMBER 30, 1995 1996 1997 ------- ------- ------------- Revenues: Oil, natural gas and related product............... $17,460 $23,662 $14,034 Direct operating expenses: Lease operating expense............................ 5,825 6,650 5,237 ------- ------- ------- Excess of revenues over direct operating expenses.... $11,635 $17,012 $ 8,797 ======= ======= =======
The Company made two amendments to its credit facility during 1997. In April, 1997, the Company amended its bank credit facility (i) to extend the revolver by one year to May 31, 1999, (ii) to extend the termination date by one year to May 31, 2002, and (iii) to reduce the commitment fee percentages. In October, 1997, the Company further amended its bank credit facility to (i) modify the security requirement of the facility such that mortgages will only be required by the banks to the extent that they were in place as of the date of the amendment and (ii) to modify certain other definitions and minor provisions of the agreement. In order to fund the Chevron Acquisition, the Company revised and restated its credit facility (the "Credit Facility") with NationsBank of Texas, as agent, ("NationsBank") a group of banks and increased the size of the facility from $150 million to $300 million. This restatement was made during the fourth quarter of 1997, with an adjusted borrowing base as of December 31, 1997 of $260 million of which $20 million was available. The Credit Facility includes a five year revolving credit facility of $165 million, unless renewed or extended, plus an Acquisition Tranche of $95 million. Unless the acquisition tranche is repaid, the interest rate on the total loan escalates 0.25% each quarter beginning March 1, 1998 through March 31, 1999. Upon repayment of the acquisition tranche, the interest rate reverts back to the LIBOR margins applicable to borrowings where borrowings under the Acquisition Tranche are not outstanding. On August 6, 1997, the Company entered into a ten year office lease for its corporate headquarters which is expected to commence late in 1998. The estimated minimum annual rental payments for the first five years of the lease are projected to be $1.15 million per year (commencing on occupancy) and the minimum annual rental payments during the remaining five years of the lease are projected to be $1.25 million per year. F-28 97 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) UNAUDITED QUARTERLY INFORMATION The following table presents unaudited summary financial information on a quarterly basis for 1995 and 1996 and the first three quarters of 1997 (in thousands except per share amounts).
1995 ----------------------------------------------- MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 -------- ------- ------------ ----------- Revenues.................................. $ 4,381 $ 4,636 $ 4,841 $ 6,251 Expenses.................................. 3,723 4,583 4,554 6,168 Net income................................ 435 35 190 54 Net income per share (primary)............ 0.08 0.00 0.02 0.00 Cash flow from operations(a).............. 2,112 1,913 2,234 3,135
1996 ----------------------------------------------- MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 -------- ------- ------------ ----------- Revenues.................................. $ 9,092 $11,682 $14,359 $18,516 Expenses.................................. 6,767 9,608 11,486 11,732 Net income................................ 1,380 1,215 1,745 4,404 Net income per share (primary)(b)......... 0.12 0.11 0.14 0.25 Cash flow from operations(a).............. 6,065 7,238 8,464 12,373
1997 --------------------------------- MARCH 31 JUNE 30 SEPTEMBER 30 -------- ------- ------------ Revenues.................................. $21,653 $19,015 $20,401 Expenses.................................. 13,375 15,512 15,304 Net income................................ 5,215 2,207 3,211 Net income per share (primary)............ 0.26 0.11 0.16 Cash flow from operations(a).............. 14,922 12,001 13,243
- --------------- (a) Exclusive of the net change in non-cash working capital balances. (b) Due to the significant variances between quarters in net income and average shares outstanding, the combined quarterly income per share does not equal the reported earnings per share for 1996. F-29 98 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors of Denbury Resources Inc. We have audited the accompanying statement of revenues and direct operating expenses of Chevron U.S.A. Inc.'s working interest in the Heidelberg Fields (the "Properties") acquired by Denbury Resources Inc. (the "Company") for each of the two years in the period ended December 31, 1996 and for the nine months ended September 30, 1997. This statement is the responsibility of the Company's management. Our responsibility is to express an opinion on this statement based on our audit. We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statement of revenues and direct operating expenses is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statement of revenues and direct operating expenses. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the statement of revenues and direct operating expenses. We believe that our audit provides a reasonable basis for our opinion. The accompanying statement of revenues and direct operating expenses was prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission (for inclusion in the registration statement on Form S-3 of Denbury Resources Inc.) as described in Note 1 and is not intended to be a complete presentation of the Properties' revenues and expenses. In our opinion, the statement of revenues and direct operating expenses referred to above presents fairly, in all material respects, the revenues and direct operating expenses of the Properties described in Note 1 for each of the two years in the period ended December 31, 1996 and for the nine months ended September 30, 1997, in conformity with generally accepted accounting principles. Price Waterhouse LLP San Francisco, California December 19, 1997 F-30 99 STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF PROPERTIES
YEAR ENDED DECEMBER 31, NINE MONTHS ENDED ------------------ SEPTEMBER 30, 1995 1996 1997 ------- ------- ----------------- (AMOUNTS IN THOUSANDS) Revenues: Oil, natural gas and related product sales......... $17,460 $23,662 $14,034 Direct operating expenses: Lease operating expense............................ 5,825 6,650 5,237 ------- ------- ------- Excess of revenues over direct operating expense..... $11,635 $17,012 $ 8,797 ======= ======= =======
The accompanying notes are an integral part of these statements. F-31 100 NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF PROPERTIES 1. BASIS OF PRESENTATION Denbury Resources Inc. (the "Company") agreed on November 25, 1997 to acquire Chevron U.S.A. Inc.'s working interest in the Heidelberg Fields for approximately $202 million. The Properties are located in the state of Mississippi. The acquisition is expected to close in December 1997. These acquired Properties will be consolidated in the Company's financial statements effective January 1, 1998. Other owners of working interests in the Properties covered by the acquisition agreement have the preferential right to acquire the Properties, which if exercised could reduce the interest acquired by the Company. Historical financial statements reflecting financial position, results of operations and cash flows required by generally accepted accounting principles are not presented, as such information is neither readily available on an individual property basis nor meaningful for the Properties acquired because the entire acquisition cost is being assigned to oil and natural gas properties. Accordingly, the statement of revenues and direct operating expenses is presented in lieu of the financial statements required under Rule 3-05 of Securities and Exchange Commission Regulation S-X. The accompanying statement of revenues and direct operating expenses (the "Statement") relates only to the working interest in the Properties acquired and may not be representative of future operations. The Statement includes revenues from natural gas sales and direct operating expenses for each of the periods presented. The Statement does not include federal and state income taxes, interest, depletion, depreciation and amortization or general and administrative expenses because such amounts would not be indicative of those expenses which would be incurred by the Company. Revenues in the Statement are recognized on the entitlement method. The accompanying Statement has been prepared on the accrual basis in accordance with generally accepted accounting principles. Preparation of the Statement in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the Statement and accompanying notes. Actual results could differ from those estimates. 2. COMMITMENTS AND CONTINGENCIES Chevron U.S.A. Inc. is a defendant in numerous lawsuits, including, along with other oil companies, actions challenging oil royalty and severance tax payments based on posted prices. Plaintiffs may seek to recover large and sometimes unspecified amounts, and some matters may remain unresolved for several years. The amount of such future cost is indeterminable. Such liability for events occurring prior to the effective date of the acquisition shall be retained by Chevron U.S.A. Inc. and Chevron U.S.A. Inc. has indemnified the Company for any costs incurred by it in conjunction with these suits. Given the nature of the Properties acquired and as stipulated in the purchase agreement, the Company is subject to loss contingencies, if any, pursuant to existing or expected environmental laws, regulations, and leases covering the acquired Properties. Management does not believe such matters will have a material impact on the Statement. 3. CONCENTRATION OF CUSTOMERS During the year ended December 31, 1996 and the nine months ended September 30, 1997, approximately 67% and 31% of the Properties' production was sold to Hunt Refining Company and Southland Oil Company, respectively. During the year ended December 31, 1995, approximately 88% and 10% of the Properties' production was sold to Amerada Hess Corporation and Hunt Refining Company, respectively. While management believes that its relationships with these purchasers is good, any loss of revenue from these purchasers due to nonpayment or late payment by the purchaser would have an adverse effect on the Statement. F-32 101 NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF PROPERTIES -- (CONTINUED) 4. OIL AND NATURAL GAS RESERVES INFORMATION (UNAUDITED) The Properties' proved oil and natural gas reserves at December 31, 1997, 1996 and 1995 have been estimated by the Company's petroleum consultants, Netherland & Sewell, in accordance with guidelines established by the Securities and Exchange Commission ("SEC"). The December 31, 1997 reserves have been adjusted by production from the Properties to estimate the September 30, 1997 reserves.
OIL GAS ESTIMATED QUANTITIES OF PROVED RESERVES (MBBL) (MMCF) - --------------------------------------- -------- ------- January 1, 1995............................................. 31,331.1 3,303.7 Production................................................ 1,321.5 290.6 -------- ------- December 31, 1995........................................... 30,009.6 3,013.1 Production................................................ 1,252.0 245.1 -------- ------- December 31, 1996........................................... 28,757.6 2,768.0 Production................................................ 793.6 160.1 -------- ------- September 30, 1997.......................................... 27,964.0 2,607.9 ======== ======= Proved Developed Reserves: As of January 1, 1995..................................... 17,230.8 3,303.7 As of December 31, 1995................................... 15,909.3 3,013.1 As of December 31, 1996................................... 14,657.3 2,768.0 As of September 30, 1997.................................. 13,863.7 2,607.9
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN RELATED TO OIL AND NATURAL GAS RESERVES The standardized measure of discounted future net cash flows ("Standardized Measure") relating to oil and natural gas reserves acquired is calculated in accordance with regulations prescribed by the SEC. The Standardized Measure has been prepared assuming year-end selling prices adjusted for future fixed and determinable price changes, year-end development and production costs and a 10% annual discount rate. The reserves and the related Standardized Measure at September 30, 1997 were adjusted for production during the nine-months ended September 30, 1997 and the years ended December 31, 1996 and 1995, and in addition, Standardized Measure was also adjusted for price changes to derive reserves and the Standardized Measure as of September 30, 1997, December 31, 1996 and December 31, 1995. The Standardized Measure is not a fair market value of the mineral interests purchased and the Standardized Measure presented for the proved oil and natural gas reserves does not purport to present the fair market value of the oil and natural gas properties. An estimate of such value should consider, among other factors, anticipated future prices of oil and natural gas, the probability of recoveries of existing proved reserves, the value of probable reserves and acreage prospects, and perhaps different discount rates. It should be noted that estimates of reserve quantities are inherently imprecise and subject to substantial revision.
DECEMBER 31, ---------------------- SEPTEMBER 30, 1995 1996 1997 --------- --------- ------------- (AMOUNTS IN THOUSANDS) Future cash inflows............................ $ 470,689 $ 613,780 $ 426,489 Future production and development costs........ (201,520) (204,876) (189,243) --------- --------- --------- Future net cash flows undiscounted............. 269,169 408,904 237,246 10% annual discount for estimated timing of cash flows................................... (142,503) (203,206) (113,931) --------- --------- --------- Standardized measure of discounted future net cash flows................................... $ 126,666 $ 205,698 $ 123,315 ========= ========= =========
F-33 102 NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF PROPERTIES -- (CONTINUED) The following are principal sources of changes in the standardized measure of discounted future net cash flows:
YEAR ENDED NINE MONTHS DECEMBER 31, ENDED -------------------- SEPTEMBER 30, 1995 1996 1997 -------- -------- ------------- (AMOUNTS IN THOUSANDS) Standardized measure of discounted future net cash flows at beginning of period.............. $ 97,753 $126,666 $205,698 Changes resulting from: Net change in prices........................... 30,772 83,377 (89,014) Sales of oil and natural gas produced.......... (11,635) (17,012) (8,797) Accretion of discount.......................... 9,776 12,667 15,428 -------- -------- -------- Standardized measure of discounted future net cash flows at end of period.................... $126,666 $205,698 $123,315 ======== ======== ========
F-34 103 [NSAI LETTERHEAD] January 13, 1998 Mr. William E. Gross Denbury Management, Inc. 17304 Preston Road, Suite 200 Dallas, Texas 75252 Dear Mr. Gross: In accordance with your request, we have estimated the proved and probable reserves and future revenue, as of December 31, 1997, to the Denbury Management, Inc. (DMI) interest in certain oil and gas properties located in Louisiana, Mississippi, Ohio, and Texas as listed in the accompanying tabulations. These properties include those in the East Heidelberg and West Heidelberg Fields acquired from Chevron U.S.A. Inc. (CUSA) effective December 31, 1997. For the purposes of this report, all DMI properties except those acquired from CUSA are referred to as the Corporate Properties. This report has been prepared using constant prices and costs as set forth in this letter. For the proved reserves, this report conforms to the guidelines of the Securities and Exchange Commission (SEC). However, inasmuch as the SEC does not recognize probable reserves, the sections of this report dealing with such reserves should not be used in filings with the SEC. As presented in the accompanying summary projections, Tables I through V, we estimate the net reserves and future net revenue to the DMI interest, as of December 31, 1997, to be:
NET RESERVES FUTURE NET REVENUE ----------------------- ---------------------------- OIL GAS PRESENT WORTH CATEGORY (BARRELS) (MCF) TOTAL AT 10% -------- ---------- ---------- ------------ ------------- Proved Developed Producing....................... 20,495,088 32,925,654 $240,589,400 $182,575,200 Non-Producing................... 10,860,120 36,879,723 174,904,500 93,904,400 Proved Undeveloped................ 20,663,028 7,385,636 187,968,700 84,849,000 ---------- ---------- ------------ ------------ Total Proved............ 52,018,236 77,191,013 $603,462,600 $361,328,600
The oil reserves shown include crude oil, condensate, and gas plant liquids. Oil volumes are expressed in barrels which are equivalent to 42 United States gallons. Gas volumes are expressed in thousands of standard cubic feet (MCF) at the contract temperature and pressure bases. As shown in the Table of Contents, this report is divided into sections for Corporate Properties and Chevron Acquisition Properties. Each section includes summary projections of reserves and revenue for each reserve category and by reserve category for each state along with one-line summaries of reserves, economics, and basic data by lease. Supplemental data summaries are also included by reserve category for each state. For the purposes of this report, the term "lease" refers to a single economic projection. [NSAI LETTERHEAD FOOTER] A-1 104 The estimated reserves and future revenue shown in this report are for proved developed producing, proved developed non-producing, proved undeveloped, and probable reserves. No study was made to determine whether possible reserves might be established for these properties. This report does not include any value which could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Future gross revenue to the DMI interest is prior to deducting state production taxes and ad valorem taxes. Future net revenue is after deducting these taxes, future capital costs, and operating expenses, but before consideration of federal income taxes. In accordance with SEC guidelines, the future net revenue has been discounted at an annual rate of 10 percent to determine its "present worth." The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties. For the purposes of this report, a field inspection of the properties has not been performed nor has the mechanical operation or condition of the wells and their related facilities been examined. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs which may be incurred due to such possible liability. Also, our estimates do not include any salvage value for the lease and well equipment nor the cost of abandoning the properties. Oil prices used in this report are based on a December 1997 average Koch West Texas Intermediate posted price of $16.18 per barrel, adjusted by lease for gravity, transportation fees, and regional posted price differentials. The natural gas liquids price used for Gibson Field, Louisiana, is $12.26 per barrel. Gas prices used in this report are based on a December 1997 NYMEX Henry Hub Natural Gas Contract settlement price of $2.58 per MMBTU, adjusted by lease for transportation fees, BTU content, and regional price differentials. Oil, natural gas liquids, and gas prices are held constant in accordance with SEC guidelines. Lease and well operating costs are based on operating expense records of DMI and CUSA. For non-operated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with costs estimated to be incurred at and below the district and field levels. As requested, lease and well operating costs for the operated properties include only direct lease and field level costs. Headquarters general and administrative overhead expenses of DMI are not included. Lease and well operating costs are held constant in accordance with SEC guidelines. Capital costs are included as required for workovers, new development wells, and production equipment. We have made no investigation of potential gas volume and value imbalances which may have resulted from overdelivery or underdelivery to the DMI interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on DMI receiving its net revenue interest share of estimated future gross gas production. The reserves included in this report are estimates only and should not be construed as exact quantities. They may or may not be recovered; if recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. A substantial portion of these reserves are for behind-pipe zones, undeveloped locations, and producing wells that lack sufficient production history upon which performance-related estimates of reserves can be based. Therefore, these reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogies to similar production. As such reserve estimates are usually subject to greater revision than those based on substantial production and pressure data, it may be necessary to revise these estimates up or down in the future as additional performance data become available. The sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions included in this report due to governmental policies and uncertainties of supply and demand. Also, estimates of reserves may increase or decrease as a result of future operations. In evaluating the information at our disposal concerning this report, we have excluded from our consideration all matters as to which legal or accounting, rather than engineering and geological, interpretation may be controlling. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geological data; therefore, our conclusions necessarily represent only informed professional judgments. A-2 105 The titles to the properties have not been examined by Netherland, Sewell & Associates, Inc., nor has the actual degree or type of interest owned been independently confirmed. The data used in our estimates were obtained from Denbury Management, Inc.; Chevron U.S.A. Inc.; other interest owners; various operators of the properties; and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. We are independent petroleum engineers, geologists, and geophysicists; we do not own an interest in these properties and are not employed on a contingent basis. Basic geologic and field performance data together with our engineering work sheets are maintained on file in our office. Very truly yours, /s/ FREDERIC D. SEWELL DMA:EIB A-3 106 [DRI LOGO] -----END PRIVACY-ENHANCED MESSAGE-----