-----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, UQQBb/d1cw20FL8f3frce8J4TKy67j+IIpo34RYPdknvAJ+BTVPw3LMrw90LSkIn NXW1JRwv6KP435V3X2tTtg== 0000950134-96-005182.txt : 19961003 0000950134-96-005182.hdr.sgml : 19961003 ACCESSION NUMBER: 0000950134-96-005182 CONFORMED SUBMISSION TYPE: S-1/A PUBLIC DOCUMENT COUNT: 1 FILED AS OF DATE: 19961002 SROS: NASD 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: S-1/A SEC ACT: 1933 Act SEC FILE NUMBER: 333-12005 FILM NUMBER: 96638488 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 S-1/A 1 AMENDMENT NO. 1 TO FORM S-1 1 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON OCTOBER 2, 1996 REGISTRATION NO. 333-12005 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 --------------------- PRE-EFFECTIVE AMENDMENT NO. 1 to FORM S-1 REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933 --------------------- DENBURY RESOURCES INC. (Exact name of Registrant as specified in its charter) CANADA 1311 NOT APPLICABLE (State or other jurisdiction of (Primary standard industrial (I.R.S. employer incorporation or organization) classification code number) identification number) 17304 PRESTON ROAD, SUITE 200 PHIL RYKHOEK, C.F.O. DALLAS, TEXAS 75252 DENBURY RESOURCES INC. (972) 380-1923 17304 PRESTON RD., SUITE 200 (Address and telephone number of Registrant's DALLAS, TEXAS 75252 principal executive offices) (972) 380-1923; FACSIMILE: (972) 713-3051 (Name, address and telephone number of Agent for Service)
--------------------- Copies to: DONALD W. BRODSKY CARLOS A. FIERRO DEIDRE L. TREADWELL BAKER & BOTTS, L.L.P. JENKENS & GILCHRIST, 2001 ROSS AVENUE A PROFESSIONAL CORPORATION DALLAS, TX 75201 1100 LOUISIANA, SUITE 1800 (214) 953-6500; FACSIMILE: (214) 953-6503 HOUSTON, TX 77002 (713) 951-3300; FACSIMILE: (713) 951-3314
APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as practicable after this Registration Statement becomes effective. If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933 check the following box: / / If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement of the same offering. / / If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. / / If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box: / / --------------------- CALCULATION OF REGISTRATION FEE - ----------------------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------------------- PROPOSED TITLE OF EACH CLASS AMOUNT MAXIMUM PROPOSED MAXIMUM AMOUNT OF OF SECURITIES TO BE TO BE OFFERING PRICE AGGREGATE OFFERING REGISTRATION REGISTERED REGISTERED* PER SHARE(1)(2) PRICE(2) FEE(3) - ----------------------------------------------------------------------------------------------- Common Shares................. 4,940,000 $12.50 $61,750,000 $21,115.47 - ----------------------------------------------------------------------------------------------- - -----------------------------------------------------------------------------------------------
* Includes an aggregate of 540,000 Shares subject to an Underwriters' over allotment option. (1) Estimated pursuant to Rule 457(c) based on the average of the high and low sales prices of the Common Shares as reported by the Nasdaq National Market of $12.50 in respect of the 4,600,000 Common Shares covered by this Registration Statement, as filed on September 13, 1996, and $12.50 on September 27, 1996 in respect of the 340,000 additional Common Shares covered by this Pre-effective Amendment No. 1. (2) Such figures give effect to the proposed one-for-two reverse stock split. (3) Of this amount, $19,827.59 was previously paid based on 4,600,000 shares of Common Stock covered by this Registration Statement, as filed on September 13, 1996. An additional fee of $1,287.88 is transmitted herewith and is calculated based on 340,000 additional Common Shares covered by this Amendment No. 1. THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(A) OF THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(A), MAY DETERMINE. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- 2 DENBURY RESOURCES INC. CROSS-REFERENCE SHEET BETWEEN ITEMS OF FORM S-1 AND THE PROSPECTUS PURSUANT TO ITEM 501(B) OF REGULATION S-K
ITEM PROSPECTUS NO. CAPTION - ---- ---------------------------------------- 1 Forepart of the Registration Statement and Outside Front Cover Page of Prospectus......... Facing Page; Cross-Reference Sheet; Outside Front Cover Page 2 Inside Front and Outside Back Cover Pages of Prospectus..................................... Inside Front and Outside Back Cover Pages 3 Summary Information and Risk Factors........... Prospectus Summary; Risk Factors 4 Use of Proceeds................................ Use of Proceeds 5 Determination of Offering Price................ * 6 Dilution....................................... * 7 Selling Security Holders....................... * 8 Plan of Distribution........................... Underwriting 9 Description of Securities to be Registered..... Description of Capital Stock 10 Interests of Named Experts and Counsel......... * 11 Information with Respect to the Registrant (a) Description of Business.................... Business and Properties (b) Description of Property.................... Business and Properties (c) Legal Proceedings.......................... Legal Proceedings (d) Market for Common Stock.................... Price Range of Common Shares and Dividend (e) Financial Statements....................... Policy Index to Financial Statements and Schedules (f) Selected Financial Data.................... Selected Consolidated Financial Data (g) Supplementary Financial Information........ Notes to Financial Statements (h) Management's Discussion and Analysis of Financial Condition and Results of Operations..................................... Management's Discussion and Analysis of Financial Condition and Results of Operations (i) Disagreements with Accountants............. * (j) Directors and Officers of Registrant....... Management (k) Compensation of Directors and Officers..... Management (l) Security Ownership......................... Security Ownership of Certain Beneficial Owners and Management (m) Interests of Management in Certain Transactions.. Interests of Management in Certain Transactions 12 Disclosure of Commission Position on Indemnification for Securities Act Liabilities.................................... *
- --------------- * Not Applicable 3 INFORMATION CONTAINED HEREIN IS SUBJECT TO COMPLETION OR AMENDMENT. A REGISTRATION STATEMENT RELATING TO THESE SECURITIES HAS BEEN FILED WITH THE SECURITIES AND EXCHANGE COMMISSION. THESE SECURITIES MAY NOT BE SOLD NOR MAY OFFERS TO BUY BE ACCEPTED PRIOR TO THE TIME THE REGISTRATION STATEMENT BECOMES EFFECTIVE. THIS PROSPECTUS SHALL NOT CONSTITUTE AN OFFER TO SELL OR THE SOLICITATION OF AN OFFER TO BUY NOR SHALL THERE BE ANY SALE OF THESE SECURITIES IN ANY STATE IN WHICH SUCH OFFER, SOLICITATION OR SALE WOULD BE UNLAWFUL PRIOR TO REGISTRATION OR QUALIFICATION UNDER THE SECURITIES LAWS OF ANY SUCH STATE. SUBJECT TO COMPLETION, DATED OCTOBER 2, 1996 PROSPECTUS , 1996 4,400,000 Shares DRI LOGO COMMON SHARES All of the Common Shares offered hereby are being sold by Denbury Resources Inc. Of the 4,400,000 shares offered hereby, 3,600,000 shares are being offered in an underwritten public offering (the "Public Offering") and 800,000 shares are being offered in a concurrent offering (the "TPG Offering") directly to an existing stockholder at a price, subject to approval of Canadian regulatory authorities, equal to the price to the public per share set forth below less underwriting discounts and commissions. The Public Offering and the TPG Offering are each conditioned on the consummation of the other. The Public Offering and the TPG Offering are collectively referred to as the "Offerings." The Common Shares are listed on the Nasdaq National Market under the symbol "DENRF" and on The Toronto Stock Exchange under the symbol "DNR." On September 30, 1996, the closing price of the Common Shares on the Nasdaq National Market and The Toronto Stock Exchange as reported by each such exchange (adjusted for the anticipated one-for-two reverse split of Common Shares) was U.S. $12.50 and Cdn. $17.50, respectively. See "Price Range of Common Shares and Dividend Policy." SEE "RISK FACTORS" BEGINNING ON PAGE 10 FOR A DISCUSSION OF CERTAIN MATTERS 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 UNDERWRITING PROCEEDS TO THE DISCOUNTS AND TO THE PUBLIC COMMISSIONS(1) COMPANY(2) - ------------------------------------------------------------------------------------------------ Per Share Public Offering................ $ $ $ TPG Offering................... $ $ -- $ Total(3)......................... $ $ $ - ------------------------------------------------------------------------------------------------
(1) The Company has agreed to indemnify the Underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended. See "Underwriting." (2) Before deducting estimated expenses of $500,000 payable by the Company. (3) The Company has granted to the Underwriters an option, exercisable within 30 days of the date hereof, to purchase up to 540,000 additional Common Shares at the Price to the Public less Underwriting Discounts and Commissions, solely to cover over-allotments, if any. If such option is exercised in full, the total Price to the Public, Underwriting Discounts and Commissions and Proceeds to the Company will be $ , $ and $ , respectively. See "Underwriting." The Common Shares are being offered in the Public Offering by the several Underwriters when, as and if delivered to and accepted by the Underwriters and subject to various prior conditions, including their right to reject orders in whole or in part. It is expected that delivery of such share certificates will be made in New York, New York on or about , 1996. DONALDSON, LUFKIN & JENRETTE SECURITIES CORPORATION PRUDENTIAL SECURITIES INCORPORATED JOHNSON RICE & COMPANY L.L.C. 4 This page will contain a map of the Gulf Coast Region depicting the geographical location of the Company's twelve largest fields. IN CONNECTION WITH THE PUBLIC OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE SECURITIES AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME. IN CONNECTION WITH THE PUBLIC OFFERING, CERTAIN UNDERWRITERS AND SELLING GROUP MEMBERS (IF ANY) MAY ENGAGE IN PASSIVE MARKET MAKING TRANSACTIONS IN THE COMMON SHARES ON THE NASDAQ NATIONAL MARKET IN ACCORDANCE WITH RULE 10B-6A UNDER THE SECURITIES EXCHANGE ACT OF 1934. SEE "UNDERWRITING." 2 5 PROSPECTUS SUMMARY The following summary is qualified in its entirety and should be read in conjunction with the more detailed information and Consolidated Financial Statements and notes thereto included in this Prospectus. Investors should carefully consider the information set forth under "Risk Factors." 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 ("GAAP"). All share information contained in this Prospectus, other than as appearing in the Consolidated Financial Statements, has been adjusted to reflect a one-for-two reverse split of the Common Shares, which will be submitted to the shareholders for approval on October 9, 1996. The July 1, 1996 estimated proved reserve data included throughout this Prospectus have been prepared by Netherland, Sewell & Associates, Inc. ("Netherland & Sewell"), independent petroleum engineers. Unless otherwise indicated herein, the information contained in this Prospectus assumes that the Underwriters' over-allotment option will not be exercised. The terms "Denbury" and the "Company" refer to Denbury Resources Inc., a Canadian corporation, and all references to the operations and assets of the Company include those of its wholly-owned subsidiaries. Certain terms used herein are defined in the Glossary included elsewhere in this Prospectus. THE COMPANY Denbury is an independent energy company engaged in acquisition, development and exploration activities in the U.S. Gulf Coast region. Since 1993, after having disposed of its Canadian oil and natural gas properties, the Company has focused its operations primarily onshore in Louisiana and Mississippi. Over the last three 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 those properties. For the three-year period ended December 31, 1995, the Company increased its proved reserves by 57% per annum, from 5.8 MMBOE at December 31, 1993 to 14.3 MMBOE. As of July 1, 1996, including the Hess and Ottawa Acquisitions (as herein defined), the Company had increased its proved reserves to 22.7 MMBOE, representing a 59% increase over December 31, 1995 reserves. Over the same three-year period, the Company also increased its average daily production by 88% per annum, from 1,194 BOE/d to 4,207 BOE/d. Pro forma for the Hess and Ottawa Acquisitions, production for the first six months of 1996 was 9,323 BOE/d. For the three-year period ended December 31, 1995, Adjusted EBITDA grew at an annual rate of 94%, from $3.0 million to $11.3 million. Pro forma Adjusted EBITDA for the first six months of 1996 was $18.7 million. As of July 1, 1996, the Company had proved reserves of 11.7 MMBbls and 65.8 Bcf. At such date, the PV10 Value was $175.3 million, of which $157.8 million was attributable to proved developed reserves. Denbury operates wells comprising approximately 68% of its PV10 Value. The twelve largest fields owned by the Company constitute approximately 80% of its estimated proved reserves and within these twelve fields, Denbury owns an average working interest of 84%. BUSINESS STRATEGY 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. The Company seeks to achieve attractive returns on capital through prudent acquisitions, development and exploratory drilling and efficient operations; maintain a conservative balance sheet to preserve maximum financial and operational flexibility; and create strong employee incentives through equity ownership. These fundamental principles are at the core of the Company's long-term growth strategy. REGIONAL FOCUS. By focusing its efforts in the Gulf Coast region, primarily Louisiana and Mississippi, the Company has been able to accumulate substantial geological, reservoir and operating data which it believes provides it with a significant competitive advantage. Given its experience in the Gulf Coast region, the Company believes it is better able to proactively identify and evaluate potential acquisitions, negotiate and 3 6 close selected acquisitions on favorable terms, and develop and operate the properties in an efficient and low-cost manner once acquired. The Company believes the Gulf Coast represents one of the most attractive regions in North America given the region's prolific production history and the new 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 attractive 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 acquires properties where it believes significant additional value can be created. Such properties are typically characterized by: (i) long production histories, (ii) complex geological formations which have multiple producing zones and substantial exploitation potential, (iii) a history of limited operational attention 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. By maintaining conservative levels of debt, the Company is able to respond quickly to acquisitions that fit within its criteria. The Company believes that due to continuing rationalization of properties, primarily by major integrated and independent energy companies, a strong backlog of acquisition opportunities should continue. 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 Company's recent Hess and Ottawa Acquisitions are illustrative of the type of opportunities the Company seeks. OPERATION OF HIGH WORKING INTEREST PROPERTIES. The Company typically seeks to acquire working interest positions that give the Company operational control or which the Company believes may lead to operational control. As the operator of properties comprising approximately 68% of its total PV10 Value, the Company 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 in fully evaluating a field for future potential and, if favorable, consolidates 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 to the point where the potential benefits of value enhancement activities justify the allocation of Company resources. EXPLOITATION OF PROPERTIES. The Company seeks to maximize the value of its properties by either increasing production, increasing recoverable reserves or reducing operating costs, and often through a combination of all three. The Company utilizes a variety of techniques to achieve this goal, 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; (iv) conducting developmental drilling to access undrained portions of the field which can only be produced from a new wellbore; and (v) utilizing exploratory drilling, which is frequently based on various advanced technologies such as 3-D seismic. The Company believes that by employing a full range of value enhancement techniques it is better able to extract the maximum value from its properties. PERSONNEL. The Company believes it has assembled a highly competitive team of experienced and technically proficient employees who are motivated through a positive work environment and by ownership in the Company, which is encouraged through the Company's stock option and stock purchase plans. The Company's geological and engineering professionals have an average of over 15 years of experience in the Gulf Coast region. The Company believes that employee ownership is essential for attracting, retaining and motivating quality personnel. Approximately 92% of Denbury's eligible employees were participating in the Company's stock purchase plan as of July 1, 1996. 4 7 RECENT DEVELOPMENTS TPG INVESTMENTS In December 1995, the Company completed a $40.0 million private placement of securities with the Texas Pacific Group ("TPG") consisting of Common Shares, $10 Convertible First Preferred Shares, Series A ("Convertible Preferred") and warrants to purchase Common Shares (collectively, the "TPG Placement"). The TPG Placement enabled the Company to repay its then outstanding bank debt and facilitated its ability to pursue its long-term growth strategy. See "Interests of Management in Certain Transactions." Concurrent with the Public Offering, the Company will sell an additional 800,000 Common Shares directly to TPG at a price equal to the price to the public less underwriting discounts and commissions. The Public Offering and the TPG Offering are each conditioned on the consummation of the other. CAPITALIZATION ADJUSTMENTS The Company has called a Special Meeting of its shareholders to be held on October 9, 1996 (the "Meeting") to approve an amendment to the Articles of Continuance governing the terms of the Convertible Preferred that would give the Company the right to convert the Convertible Preferred to Common Shares at any time, at the election of the Company (the "Preferred Amendment"). The Company intends to convert the Convertible Preferred simultaneously with the closing of the Offerings. In addition to the Preferred Amendment, the shareholders will be asked to approve at the Meeting: (i) a one-for-two reverse split of Common Shares and (ii) the issuance of Common Shares at an issue price of Cdn. $14.72 per share in lieu of interest that would be due on the Company's 9 1/2% Convertible Debentures ("Debentures") from the conversion date to and including April 13, 1997, if the holders of such Debentures convert the Debentures into Common Shares prior to April 13, 1997. Subsequent to June 30, 1996, the Company issued 187,500 Common Shares for the conversion of the remaining 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"). Giving effect to the issuance of Common Shares for the Warrants and the 6 3/4% Convertible Debentures, and the approval of the three shareholder resolutions and subsequent conversions of the Convertible Preferred and Debentures upon approval by the Board of Directors (collectively, the "Capitalization Adjustments"), as of June 30, 1996 an additional 3,400,200 Common Shares would have been outstanding. ACQUISITION OF HESS PROPERTIES The Company completed several property acquisitions during the first half of 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, from Amerada Hess Corporation ("Amerada Hess") for $37.2 million (the "Hess Acquisition"), effective May 1, 1996. Average daily production during the first half of 1996 from these properties, including the periods when they were not owned by the Company, was approximately 6.6 MMcf/d and 2,230 Bbls/d, or 3,335 BOE/d, net to the interest acquired by Denbury. As of July 1, 1996, the Hess Acquisition properties had estimated net proved reserves of approximately 5.9 MMBOE, consisting of approximately 5.0 MMBbls and 5.6 Bcf, with a PV10 Value of $43.1 million. Approximately 90% of the PV10 Value of the Hess Acquisition was for wells on which Denbury assumed operations with an average working interest of approximately 80%. OTHER ACQUISITIONS In addition to the Hess Acquisition, during the first half of 1996 the Company completed other acquisitions totaling $10.8 million. The largest of these was the acquisition of additional working interests in five Mississippi oil and natural gas properties in which the Company already owned an interest, and certain overriding royalty interests in other areas, which were acquired during April 1996 for approximately $7.5 million from Ottawa Energy, Inc. ("Ottawa"), a subsidiary of Highridge Exploration Ltd. (the "Ottawa 5 8 Acquisition"). In addition to the Ottawa Acquisition, the Company completed four other acquisitions, primarily in Louisiana, totaling $3.3 million. Average daily production during the first half of 1996 from these acquisitions, including the Ottawa Acquisition and the periods when they were not owned by the Company, was approximately 3.7 MMcf/d and 434 Bbls/d, or 1,048 BOE/d, net to the interest acquired by the Company. As of July 1, 1996, the Company's estimated net proved reserves for these acquisitions totaled approximately 1.1 MMBbls and 13.1 Bcf or 3.3 MMBOE, with a PV10 Value of $24.1 million. NEW CREDIT FACILITY In order to fund these acquisitions, improve the terms and increase the size of the previous credit facility, the Company has entered into a new $150.0 million dollar credit facility (the "Credit Facility") with NationsBank of Texas ("NationsBank"). This refinancing closed during the second quarter of 1996, and has a borrowing base as of September 30, 1996 of $60.0 million. 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. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- New Credit Facility." THE OFFERINGS Common Shares offered by the Company: Public Offering........................................ 3,600,000 shares TPG Offering........................................... 800,000 shares Total.......................................... 4,400,000 shares Common Shares to be outstanding after the Offerings...... 19,479,090 shares(1) Use of Proceeds.......................................... To repay outstanding indebtedness under the Credit Facility incurred primarily in connection with the recent acquisitions. The remainder of the proceeds, if any, will be used to fund future capital expenditures related to exploration, development and acquisition activities, to increase working capital and for general corporate purposes. See "Use of Proceeds." Nasdaq National Market trading symbol.................... DENRF The Toronto Stock Exchange trading symbol................ DNR
- --------------- (1) Represents Common Shares outstanding as of August 31, 1996 after giving effect to the Capitalization Adjustments and the Offerings. This total does not include 1,769,250 shares issuable pursuant to outstanding warrants and stock options, of which 1,185,000 were exercisable as of August 31, 1996. 6 9 SUMMARY OIL AND NATURAL GAS RESERVE DATA The net proved oil and natural gas reserve estimates as of December 31, 1995 and July 1, 1996 have been prepared by Netherland & Sewell, and the net proved oil and natural gas reserve estimates as of December 31, 1993 and 1994 have been prepared by the Scotia Group, Inc., both independent petroleum engineers. For additional information relating to the Company's oil and natural gas reserves, see "Risk Factors -- Uncertainty of Estimates of Oil and Natural Gas Reserves," "Business and Properties -- Oil and Natural Gas Operations," and Note 10 to the Consolidated Financial Statements of the Company. Attached hereto as Appendix A is a letter from Netherland & Sewell relating to their July 1, 1996 reserve report.
AS OF DECEMBER 31, AS OF ----------------------------- JULY 1, 1993 1994 1995 1996 ------- ------- ------- -------- ESTIMATED PROVED RESERVES: Oil (MBbls).......................................... 3,583 4,230 6,292 11,725 Natural gas (MMcf)................................... 13,029 42,047 48,116 65,807 Oil equivalent (MBOE)................................ 5,755 11,238 14,311 22,693 Discounted estimated future net cash flow before income taxes (PV10 Value) (thousands)(1).......... $28,638 $52,691 $96,965 $175,255 Standardized measure of discounted estimated future net cash flow after net income taxes (thousands)(1).................................... $28,465 $46,928 $81,164 $150,160
- --------------- (1) Determined based on period-end unescalated prices and costs in accordance with the guidelines of the Securities and Exchange Commission (the "SEC"), discounted at 10% per annum. The oil prices as of December 31, 1995 and July 1, 1996, respectively, were West Texas Intermediate $18.00 and $20.00 per barrel adjusted by field, and the NYMEX Henry Hub natural gas prices for the same two periods were $2.24 and $2.65 per MMBtu, also adjusted by field. 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.
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED JUNE 30, --------------------------------------- ----------------------------- PRO PRO FORMA FORMA 1993(1) 1994 1995 1995(2) 1995 1996 1996(2) ------- ------ ------- ------- ------- ------- ------- NET AVERAGE DAILY PRODUCTION VOLUMES: Oil (Bbls).......................... 858 1,340 1,995 4,966 1,830 2,894 4,651 Natural gas (Mcf)................... 2,013 9,113 13,271 21,918 12,075 22,518 28,031 Oil equivalent (BOE)................ 1,194 2,859 4,207 8,619 3,843 6,647 9,323 WEIGHTED AVERAGE SALES PRICES: Oil (per Bbl)....................... $13.91 $13.84 $ 14.90 $ 14.64 $ 14.92 $ 17.39 $ 17.33 Natural gas (per Mcf)............... 2.06 1.78 1.90 1.83 1.85 2.80 2.72 UNIT DATA ($ PER BOE): Revenue............................. $13.47 $12.17 $ 13.05 $ 13.09 $ 12.94 $ 17.07 $ 16.84 Production expenses................. (4.75 ) (4.13) (4.42) (4.87) (4.50) (4.42) (4.64) ------ ------ ------- ------- ------- ------- ------- Production netback.................. 8.72 8.04 8.63 8.22 8.44 12.65 12.20 General and administrative.......... (1.80 ) (1.12) (1.25) (0.77) (1.40) (1.46) (1.18) Interest, net....................... 0.04 (0.99) (1.26) (0.50) (1.25) (0.19) (0.07) ------ ------ ------- ------- ------- ------- ------- Operating cash flow (3)............. $ 6.96 $ 5.93 $ 6.12 $ 6.95 $ 5.79 $ 11.00 $ 10.95 ====== ====== ======= ======= ======= ======= =======
- --------------- (1) Includes production from Canadian properties sold during 1993. (2) Gives effect to the (i) Capitalization Adjustments, (ii) Hess Acquisition, (iii) Ottawa Acquisition, and (iv) the application of estimated net proceeds of $50.9 million from the Offerings as if such transactions had been consummated as of January 1 of the period presented. See "Use of Proceeds." (3) Represents cash flow provided by operations, exclusive of the net change in non-cash working capital balances. 7 10 SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA The summary historical financial data set forth below as of and for the years ended December 31, 1993, 1994 and 1995 have been derived from the Company's audited financial statements and notes thereto contained elsewhere in this Prospectus. The financial data for the six-month periods ended June 30, 1995 and 1996 were derived from the unaudited financial statements of the Company, and include in management's opinion, 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 and none of the data presented below are necessarily indicative of future results. The summary historical and unaudited pro forma financial data for the Company are qualified in their entirety and should be read in conjunction with "Pro Forma Operating Results," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Company's Consolidated Financial Statements and Notes.
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED JUNE 30, ---------------------------------------- ----------------------------- PRO PRO FORMA FORMA 1993 1994 1995 1995(1) 1995 1996 1996(1) ------- ------- ------- ------- ------- ------- ------- (DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) SELECTED INCOME STATEMENT DATA: Revenue: Oil, natural gas and related product sales............................ $ 5,868 $12,692 $20,032 $41,196 $ 8,997 $20,650 $28,574 Interest income.................... 76 23 77 77 21 124 124 ------- ------- ------- ------- ------- ------- ------- Total revenues.............. 5,944 12,715 20,109 41,273 9,018 20,774 28,698 ------- ------- ------- ------- ------- ------- ------- Expenses: Production......................... 2,067 4,309 6,789 15,336 3,128 5,350 7,870 General and administrative......... 782 1,105 1,832 2,332 935 1,656 1,906 Interest........................... 83 1,146 2,085 1,716 927 681 233 Imputed preferred dividends........ -- -- -- -- -- 759 -- Loss on early extinguishment of debt............................. -- -- 200 200 200 440 440 Depletion and depreciation......... 1,898 4,209 8,022 16,521 3,075 7,382 10,099 Franchise taxes.................... -- 65 100 100 42 107 107 ------- ------- ------- ------- ------- ------- ------- Total expenses.............. 4,830 10,834 19,028 36,205 8,307 16,375 20,655 ------- ------- ------- ------- ------- ------- ------- Income before the following: 1,114 1,881 1,081 5,068 711 4,399 8,043 Gain on sale of Canadian properties....................... 966 -- -- -- -- -- -- ------- ------- ------- ------- ------- ------- ------- Income before income taxes........... 2,080 1,881 1,081 5,068 711 4,399 8,043 Provision for federal income taxes... (345) (718) (367) (1,722) (242) (1,804) (2,785) ------- ------- ------- ------- ------- ------- ------- Net income........................... $ 1,735 $ 1,163 $ 714 $ 3,346 $ 469 $ 2,595 $ 5,258 ======== ======== ======== ======== ======== ======== ======== Net income per common share(2)....... $ 0.35 $ 0.19 $ 0.10 $ 0.28 $ 0.07 $ 0.23 $ 0.27 ======== ======== ======== ======== ======== ======== ======== Weighted average common shares outstanding(2)..................... 4,990 6,240 6,870 11,921 6,536 11,512 19,321 ======== ======== ======== ======== ======== ======== ======== OTHER DATA: Operating cash flow(3)............. $ 3,030 $ 6,185 $ 9,394 $21,880 $ 4,025 $13,303 $18,582 Capital expenditures............... 29,855 16,903 28,524 -- 10,506 60,733 -- Adjusted EBITDA(4)................. 3,019 7,213 11,311 23,428 4,892 13,537 18,691
AS OF JUNE 30, 1996 AS OF DECEMBER 31, --------------------- ------------------------------- PRO 1993 1994 1995 ACTUAL FORMA(5) ------- ------- ------- -------- -------- (DOLLARS IN THOUSANDS) BALANCE SHEET DATA: Total assets.................................... $35,978 $48,964 $77,641 $132,900 $144,285 Working capital (deficiency).................... (1,410) (1,620) 6,862 (1,184) 10,201 Long-term debt, net of current maturities....... 6,177 16,536 3,474 42,964 34 Convertible preferred stock..................... -- -- 15,000 15,759 -- Shareholders' equity............................ 24,431 25,962 53,501 57,258 127,332
8 11 - --------------- (1) Gives effect to the (i) Capitalization Adjustments, (ii) Hess Acquisition, (iii) Ottawa Acquisition, and (iv) the application of estimated net proceeds of $50.9 million from the Offerings as if such transactions had been consummated as of January 1 of the period presented. See "Use of Proceeds." (2) Adjusted for a proposed one-for-two reverse split of Common Shares to be effective in October 1996, subject to shareholder and regulatory approval. (3) Represents cash flow provided by operations, exclusive of the net change in non-cash working capital balances. (4) Adjusted EBITDA represents earnings before interest income, interest expense, income taxes, depletion and depreciation, gain on sale of oil and natural gas properties, imputed preferred dividends and losses on early extinguishment of debt. Adjusted EBITDA is not intended to represent cash flows for the period, nor has it been presented as an alternative to operating income nor as an indicator of operating performance. It should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. See the Company's Consolidated Statements of Cash Flows in the Consolidated Financial Statements included elsewhere in this Prospectus. Adjusted EBITDA is included in this Prospectus because it is a basis upon which the Company assesses its financial performance. (5) Gives effect to the Capitalization Adjustments and the application of estimated net proceeds of $50.9 million from the Offerings. 9 12 RISK FACTORS In addition to other information set forth elsewhere in this Prospectus, the following factors relating to the Company and the Offerings should be considered when evaluating an investment in the Common Shares offered hereby. PRICE FLUCTUATIONS AND MARKETS The Company's revenue, profitability and future rate of growth are substantially 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 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. It is impossible 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 the Company's oil and natural gas that can be produced economically and could, therefore, 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 in the past entered into hedging arrangements from time to time. The Company did not have any financial hedging contracts in place as of the date of this Prospectus, although it may have 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 shutin for lack of a market or due to inadequacy or unavailability of pipeline or gathering system capacity. 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 55% of the Company's proved developed reserves at July 1, 1996 are located in the lower Gulf Coast geosyncline in southern Louisiana which is characterized by relatively rapid decline rates. Approximately 59% of the Company's total proved reserves at July 1, 1996 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. DRILLING AND OPERATING RISKS Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that new wells drilled by the Company will be productive or that the Company will recover all or any portion of its investment. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but from wells that are productive but do not produce sufficient net revenues to return a profit after 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 10 13 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, damage to property of the Company and others, and the imposition of fines and penalties pursuant to environmental legislation. See "-- Governmental and Environmental Regulation." 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 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. The Company has focused its oil and natural gas operations in certain key areas and currently receives approximately 80% of its production from 14 fields. Any interruption to these key areas could materially adversely affect the operations 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. 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. 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 the reserve reports could have a material adverse effect on the Company. ACQUISITION RISKS The Company's rapid growth in recent years has been attributable in significant part to acquisitions of producing properties. After the Offerings, the Company expects to continue to evaluate and, where appropriate, pursue acquisition opportunities on terms management considers favorable to the Company. There can be no assurance that suitable acquisition candidates will be identified in the future, nor that they will be integrated successfully into the Company's operations or 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 reveal all existing or potential problems, nor will it necessarily permit a buyer to become sufficiently familiar with the properties to fully assess their 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. 11 14 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 be substantially different in operating and geologic characteristics or geographic location than existing properties. While it is the Company's current intent to concentrate on acquiring producing properties with development and exploration potential located in the Gulf Coast region, there is no assurance that the Company will not pursue acquisitions or properties located in other geographic regions. 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 capital expenditures have averaged four times more than its cash flow from operations (exclusive of the changes in non-cash working capital balances) and it has continued this trend into 1996 by spending approximately 4.6 times its cash flow during the first half of 1996. Historically, the Company has funded these expenditures principally through debt and equity. As of September 30, 1996, the Company had a $60.0 million borrowing base on its Credit Facility, $15.0 million of which was available. The Company intends to use the net proceeds from the Offerings to substantially reduce its outstanding bank debt. See "Use of Proceeds." The borrowing base on this facility will be redetermined semi-annually by the lender in its sole discretion and there can be no assurance the borrowing base will be maintained at its present level. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- New Credit Facility." 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. Should outside capital resources be limited, the rate of Company 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 oil and natural gas reserves. 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. CONTROLLING SHAREHOLDER In December 1995, the Company completed a $40.0 million private placement of securities to TPG consisting of the Convertible Preferred, Common Shares and warrants. Assuming approval by the shareholders of the Company, the Convertible Preferred will be converted into approximately 2.8 million Common Shares concurrently with the closing of the Offerings. TPG will buy 800,000 Common Shares in the TPG Offering directly from the Company at the price to the public less underwriting discounts and commissions. After adjusting for the conversion of the Convertible Preferred, the Offerings and the other Capitalization Adjustments, TPG will own approximately 40% of the Common Shares outstanding on a fully-diluted basis. TPG is entitled to nominate a minimum of three of seven representatives to the Company's Board of Directors as long as TPG maintains certain ownership levels. The current Board of Directors has six members of which three members were nominated by TPG. 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 representative. Additionally, TPG has the right (which has been waived for the Public 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 of the Company by purchasing additional shares on the same terms and conditions. However, this right expires should TPG's ownership interest fall below 20%. See "Interests of Management in Certain Transactions." SHARES ELIGIBLE FOR FUTURE SALE After giving pro forma effect to the Offerings and the Capitalization Adjustments, the Company would have had 19,479,090 Common Shares outstanding as of August 31, 1996 (20,019,090 shares assuming 12 15 exercise of the Underwriters' over-allotment option in full). The Common Shares sold in the Public Offering will be freely tradable without restrictions or further registration under the Securities Act of 1933, as amended (the "Securities Act"). 7,608,038 of the 8,408,038 Common Shares beneficially owned by TPG as of the close of the Offerings will be "restricted" securities within the meaning of the Securities Act as a result of the issuance thereof in a private transaction. The Company believes that such "restricted" Common Shares will become eligible for sale on the open market under Rule 144 from time to time after December 21, 1997. In connection with the Public Offering, 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 Donaldson, Lufkin & Jenrette Securities Corporation. See "Underwriting." In addition, the Company has granted certain registration rights to TPG. After December 21, 1997 and until December 21, 2000, TPG has the right, subject to certain conditions, to demand that its stock be registered under the Securities Act on one occasion. TPG also has "piggyback" registration rights and, subject to certain conditions, may participate in a future registration by the Company of Common Shares (or securities convertible into or exchangeable for, or options, warrants or other rights to acquire, Common Shares) under the Securities Act. TPG has waived its "piggyback" registration rights with regard to the Public Offering. 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. 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. The loss of the services from 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 -- Directors and Executive Officers." COMPETITION The Company operates in a highly competitive environment. The Company competes with major 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." 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. State and federal statutes and regulations require permits for drilling, reworking and recompletion operations, drilling bonds and reports concerning operations. 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 13 16 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." 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. 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. 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 -- Environmental Regulations." AUTHORIZATION AND DISCRETIONARY ISSUANCE OF PREFERRED SHARES; ANTI-TAKEOVER PROVISIONS The Company'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 Company'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 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. As of the close of 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 the Company's Board of Directors rather than pursue non-negotiated takeover attempts. These existing anti-takeover provisions 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 "Canadian Taxation and the Investment Canada Act" and "Description of Capital Stock." NO DIVIDENDS During the last five fiscal years, the Company has not paid any dividends on its outstanding Common Shares, nor does the Company intend to do so. In addition, the Company is restricted from doing so under its Credit Facility. The Company currently intends to retain its cash for the continued expansion of its business, including exploration, development and acquisition activities. FORWARD-LOOKING INFORMATION All statements other than statements of historical fact contained in this Prospectus, including statements in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Business and Properties," are forward-looking statements. Forward-looking statements in this Prospectus generally are accompanied by words such as "anticipate," "believe," "estimate," "project" or "expect" or similar statements. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, no assurance can be given that such expectations will prove correct. Factors that could cause the Company's results to differ materially from the results discussed in such forward-looking statements include the aforementioned risks described under "Risk Factors," such as the fluctuations of the prices 14 17 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, the competition from other exploration, development and production companies and the effects of governmental and environmental regulation. All forward-looking statements in this Prospectus are expressly qualified in their entirety by the cautionary statements in this paragraph. 15 18 CONCURRENT OFFERINGS Concurrent with the Public Offering, the Company will sell an additional 800,000 Common Shares to TPG at a price, subject to the approval of Canadian regulatory authorities, equal to the price to the public per share set forth on the cover of this Prospectus less underwriting discounts and commissions. The Public Offering and the TPG Offering are each conditioned on the consummation of the other. USE OF PROCEEDS The net proceeds to the Company from the sale of Common Shares in the Offerings are estimated to be approximately $50.9 million ($57.2 million if the Underwriters' over allotment option is exercised in full), based on an assumed public offering price of $12.50 per share. From these proceeds, the Company intends to repay its borrowings under the Credit Facility to better position the Company for future acquisition and development activities. As of September 30, 1996, the Credit Facility had an outstanding balance of $45.0 million and an average interest rate of 6.8% per annum. The Credit Facility is currently a revolving credit facility that will convert to a three-year term loan in May 1998, unless renewed or extended. The Company borrowed $39.9 million against this Credit Facility during the second quarter of 1996, primarily to fund the Hess Acquisition, the Ottawa Acquisition and other acquisitions. See "Business and Properties -- Acquisitions of Oil and Natural Gas Properties." Since June 30, 1996, an additional $5.0 million has been borrowed to fund the Company's development program. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- New Credit Facility." The remainder of the proceeds from the Offerings, if any, will be used to fund future capital expenditures related to acquisition, development, and exploration activities, increase working capital and for general corporate purposes. To the extent that the net proceeds of the Offerings are not immediately used, they will be invested in investment grade short-term interest-bearing obligations. 16 19 PRICE RANGE OF COMMON SHARES AND DIVIDEND POLICY The Company's Common Shares have been listed on the Nasdaq National Market ("NASDAQ") since August 25, 1995 and on The Toronto Stock Exchange ("TSE") in Toronto, Ontario, Canada, since February 14, 1984 and currently trade under the symbols "DENRF" and "DNR," respectively. The following table summarizes the high and low last reported sales prices on days in which there were trades of the Common Shares on NASDAQ and on the TSE (as reported by such exchanges) for each quarterly period during the last two fiscal years and to date during 1996. The following prices have been adjusted for the proposed one-for-two reverse stock split to be effective in October 1996, subject to shareholder and regulatory approval.
NASDAQ TSE -------------- -------------- HIGH LOW HIGH LOW ----- ----- ----- ----- (U.S. $) (CDN. $) 1994 First Quarter.......................................... -- -- 8.00 6.30 Second Quarter......................................... -- -- 8.80 7.00 Third Quarter.......................................... -- -- 9.00 7.20 Fourth Quarter......................................... -- -- 8.80 7.10 1995 First Quarter.......................................... -- -- 7.80 6.60 Second Quarter......................................... -- -- 8.70 7.00 Third Quarter.......................................... 6.74 5.32 8.70 7.00 Fourth Quarter......................................... 6.26 5.50 8.70 7.10 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 13.70
The last reported sales prices of the Common Shares on NASDAQ and the TSE on September 30, 1996, as reported by such exchanges, were U.S. $12.50 per share and Cdn. $17.50 per share, respectively. During the last five fiscal years, the Company has not paid any dividends on its outstanding Common Shares, nor does the Company intend to do so in the foreseeable future. In addition, the Company is prohibited from doing so under its Credit Facility. See "Management's Discussions and Analysis of Financial Condition and Results of Operations -- New Credit Facility." As of September 30, 1996, to the best of the Company's knowledge, the Common Shares were held of record by approximately 1,200 holders. 17 20 CAPITALIZATION The following table sets forth the capitalization of the Company as of June 30, 1996 and as adjusted to give effect to the Capitalization Adjustments and the application of the $50.9 million estimated net proceeds from the Offerings, as if each had been consummated as of June 30, 1996. See "Use of Proceeds." This table should be read in conjunction with the Company's Consolidated Financial Statements and related notes thereto, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and other financial information included elsewhere in this Prospectus.
AS OF JUNE 30, 1996 ------------------------ ACTUAL AS ADJUSTED -------- ----------- (DOLLARS IN THOUSANDS) Cash and cash equivalents.............................................. $ 3,085 $ 14,470 ======== ======== Long-term debt: Revolving bank loan.................................................. $ 40,000 $ -- Convertible debentures............................................... 2,930 -- Other notes payable.................................................. 34 34 -------- -------- Total long-term debt......................................... 42,964 34 -------- -------- Convertible First Preferred Shares, Series A 1,500,000 authorized; $10 par value; 1,500,000 and -0- shares outstanding, respectively......................................... 15,759 -- -------- -------- Shareholders' equity(1): Common Shares, no par value; unlimited shares authorized; 11,632,215 and 19,432,415 outstanding, respectively(2)....................... 51,226 121,436 Retained earnings(3).............................................. 6,032 5,896 -------- -------- Total shareholders' equity................................... 57,258 127,332 -------- -------- Total capitalization....................................... $115,981 $127,366 ======== ========
- --------------- (1) Excludes 1,043,425 outstanding stock options as of June 30, 1996, exercisable at various prices ranging from $2.50 to $11.36 per share with a weighted average price of $7.36 (of which 503,800 were currently exercisable), and 700,000 Common Shares reserved for issuance upon exercise of the two series of Common Share purchase warrants. (2) Includes the issuance of: (i) 4,400,000 Common Shares upon the closing of the Offerings, (ii) 2,816,372 Common Shares in exchange for the Convertible Preferred, (iii) 308,642 Common Shares for the principal and 12,686 Common Shares for the interest from June 30, 1996 to April 13, 1997 on the 9 1/2% Convertible Debentures, (iv) 187,500 Common Shares for the 6 3/4% Convertible Debentures converted on July 31, 1996 and (v) 75,000 Common Shares for the Cdn. $8.40 warrants exercised on August 27, 1996. See "Interests of Management in Certain Transactions." (3) Includes a $136,000 charge to earnings for the imputed interest from June 30, 1996 to April 13, 1997 for the pro forma early conversion of the 9 1/2% Convertible Debentures. This interest would be paid in Common Shares at a price of Cdn. $14.72 per Common Share. 18 21 PRO FORMA OPERATING RESULTS The following unaudited pro forma consolidated statements of income for the year ended December 31, 1995 and the six months ended June 30, 1996 reflect the historical information of the Company as adjusted to give effect to: (i) revenue and direct operating expenses of the Ottawa Acquisition, (ii) revenue and direct operating expenses of the Hess Acquisition, (iii) the pro forma adjustments related to the Ottawa and Hess Acquisitions ("Acquisition Adjustments") and (iv) the Capitalization Adjustments, the Offerings and application of the estimated net proceeds therefrom, in each case as if such transactions had been consummated as of the beginning of each respective period. A pro forma balance sheet is not presented as both the Ottawa and Hess Acquisitions had been consummated before June 30, 1996. Additional property acquisitions were made in 1996 that have not been included in the pro forma adjustments since they are immaterial individually and in the aggregate. See "Capitalization." The unaudited pro forma consolidated statements of income are provided for comparative purposes only and should be read in conjunction with the historical consolidated financial statements of the Company and the historical statements of revenues and direct operating expenses of the properties acquired in the Ottawa Acquisition and the Hess Acquisition. The pro forma information presented is not necessarily indicative of the results that actually would have been obtained if such transactions had occurred at the beginning of the indicated periods or of future results. 19 22 UNAUDITED PRO FORMA STATEMENT OF INCOME
SIX MONTHS ENDED JUNE 30, 1996 -------------------------------------------------------------------------------------- CAPITALIZATION DENBURY OTTAWA HESS ACQUISITION AND OFFERING PRO FORMA HISTORICAL ACQUISITION ACQUISITION ADJUSTMENTS ADJUSTMENTS COMBINED ---------- ----------- ----------- ----------- -------------- --------- (DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Revenues: Oil, natural gas and related product sales................. $20,650 $ 854 $ 7,070 $ -- $ -- $28,574 Interest and other....... 124 -- -- -- -- 124 ------- ----- ------- ------- ------- ------- Total revenues... 20,774 854 7,070 -- -- 28,698 ------- ----- ------- ------- ------- ------- Expenses: Production............... 5,350 168 2,352 -- -- 7,870 General and administrative........ 1,656 -- -- 250(1) -- 1,906 Interest................. 681 -- -- 1,041(2) (1,489)(3) 233 Imputed preferred dividend.............. 759 -- -- -- (759)(6) -- Loss on early extinguishment of debt.................. 440 -- -- -- -- 440 Depletion and depreciation.......... 7,382 -- -- 2,717(4) -- 10,099 Franchise taxes.......... 107 -- -- -- -- 107 ------- ----- ------- ------- ------- ------- Total expenses... 16,375 168 2,352 4,008 (2,248) 20,655 ------- ----- ------- ------- ------- ------- Income before tax.......... 4,399 686 4,718 (4,008) 2,248 8,043 Provision for federal income tax............... (1,804) (233)(5) (1,604)(5) 1,362(5) (506)(5) (2,785) ------- ----- ------- ------- ------- ------- Net income................. $ 2,595 $ 453 $ 3,114 $(2,646) $ 1,742 $ 5,258 ======= ===== ======= ======= ======= ======= Net income per common share.................... $ 0.23 $ 0.27 ======= ======= Average common shares outstanding.............. 11,512 19,321 ======= =======
See notes on the following page. 20 23 UNAUDITED PRO FORMA STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, 1995 -------------------------------------------------------------------------------------- CAPITALIZATION DENBURY OTTAWA HESS ACQUISITION AND OFFERING PRO FORMA HISTORICAL ACQUISITION ACQUISITION ADJUSTMENTS ADJUSTMENTS COMBINED ---------- ----------- ----------- ----------- -------------- --------- (DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Revenues: Oil, natural gas and related product sales................. $20,032 $2,954 $18,210 $ -- $ -- $41,196 Interest and other....... 77 -- -- -- -- 77 ------- ------ ------- -------- ------ ------- Total revenues... 20,109 2,954 18,210 -- -- 41,273 ------- ------ ------- -------- ------ ------- Expenses: Production............... 6,789 659 7,888 -- 15,336 General and administrative........ 1,832 -- -- 500(1) -- 2,332 Interest................. 2,085 -- -- 3,338(2) (3,707)(3) 1,716 Loss on early extinguishment of debt.................. 200 -- -- -- -- 200 Depletion and depreciation.......... 8,022 -- -- 8,499(4) -- 16,521 Franchise taxes.......... 100 -- -- -- -- 100 ------- ------ ------- -------- ------ ------- Total expenses... 19,028 659 7,888 12,337 (3,707) 36,205 ------- ------ ------- -------- ------ ------- Income before tax.......... 1,081 2,295 10,322 (12,337) 3,707 5,068 Provision for federal income tax(5)............ (367) (780) (3,509) 4,194 (1,260) (1,722) ------- ------ ------- -------- ------ ------- Net income................. $ 714 $1,515 $ 6,813 $ (8,143) $2,447 $ 3,346 ======= ====== ======= ======== ====== ======= Net income per common share.................... $ 0.10 $ 0.28 ======= ======= Average common shares outstanding.............. 6,870 11,921 ======= =======
- --------------- (1) Reflects an increase of $500,000 in annual 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. (2) Reflects an increase in interest expense for the period to reflect the $44.5 million of bank debt that would have been required to fund the Hess and Ottawa Acquisitions had they occurred as of the beginning of each respective period. The applicable interest rate was reduced from the Company's historical bank interest rate by 1 3/8% for such periods to reflect the reduction in the margin over LIBOR as a result of the new Credit Facility. (3) Interest expense was: (i) reduced to reflect receipt of $50.9 million in estimated net proceeds from the Offering and the $460,000 from the exercise on August 27, 1996 of 75,000 of the Cdn. $8.40 Warrants and the application thereof to reduce debt, in each case as if the funds were received and applied at the beginning of each period ($3.8 million and $1.6 million for 1995 and 1996, respectively), (ii) increased to reflect the imputed interest on the Debentures from the end of each respective period through April 13, 1997, in addition to the interest actually charged on the Debentures during the period presented ($167,000 and $87,000 for 1995 and 1996, respectively), and (iii) reduced to reflect the conversion as of the beginning of each period of the 6 3/4% Convertible Debentures that were converted into 187,500 Common Shares on July 31, 1996 ($74,000 and $35,000 for 1995 and 1996, respectively). (4) Depreciation, depletion and amortization ("DD&A") expense has been computed using the unit of production method and reflects the Company's increased investment in oil and natural gas properties. The July 1, 1996 estimated net proved reserves prepared by Netherland & Sewell were used in the DD&A computation for the Hess and Ottawa Acquisitions. (5) Income taxes were computed on a pro forma basis using the federal statutory rate of 34%. (6) Reflects the elimination of the imputed preferred dividend on the Convertible Preferred that will be converted into Common Shares concurrent with the completion of the Offering. 21 24 SELECTED CONSOLIDATED FINANCIAL DATA The following selected consolidated financial data of the Company for each year for the five-year period ended December 31, 1995 are derived from the Company's audited Consolidated Financial Statements. The selected consolidated financial data for the six-month periods ended June 30, 1995 and 1996 are unaudited and include, in management's opinion, all adjustments (consisting of only normal recurring adjustments) necessary to present fairly the results for such interim periods. Results for the interim periods are not necessarily indicative of results to be expected for the entire year. The selected consolidated financial data should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Company's Consolidated Financial Statements and the Notes thereto included elsewhere herein. See Note 8 of the Notes to Consolidated Financial Statements for a reconciliation between Canadian and U.S. GAAP.
SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, -------------------------------------------------- ------------------ 1991 1992 1993 1994 1995 1995 1996 ------- ------ ------- ------- ------- ------- ------- (DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) SELECTED INCOME STATEMENT DATA: Revenue: Oil, natural gas and related product sales.... $ 1,962 $1,912 $ 5,868 $12,692 $20,032 $ 8,997 $20,650 Interest income............................... 5 40 76 23 77 21 124 ------- ------ ------- ------- ------- ------- ------- Total revenues............................ 1,967 1,952 5,944 12,715 20,109 9,018 20,774 ------- ------ ------- ------- ------- ------- ------- Expenses: Production.................................... 669 634 2,067 4,309 6,789 3,128 5,350 General and administrative.................... 437 955 782 1,105 1,832 935 1,656 Interest...................................... 16 8 83 1,146 2,085 927 681 Imputed preferred dividends................... -- -- -- -- -- -- 759 Loss on early extinguishment of debt.......... -- -- -- -- 200 200 440 Depletion and depreciation.................... 1,973 690 1,898 4,209 8,022 3,075 7,382 Franchise taxes............................... -- -- -- 65 100 42 107 ------- ------ ------- ------- ------- ------- ------- Total expenses............................ 3,095 2,287 4,830 10,834 19,028 8,307 16,375 ------- ------ ------- ------- ------- ------- ------- Income (loss) before the following:............. (1,128) (335) 1,114 1,881 1,081 711 4,399 Gain on sale of Canadian properties........... -- -- 966 -- -- -- -- ------- ------ ------- ------- ------- ------- ------- Income (loss) before income taxes............... (1,128) (335) 2,080 1,881 1,081 711 4,399 Provision for federal income taxes.............. -- -- (345) (718) (367) (242) (1,804) ------- ------ ------- ------- ------- ------- ------- Net income (loss)............................... $(1,128) $ (335) $ 1,735 $ 1,163 $ 714 $ 469 $ 2,595 ======= ====== ======= ======= ======= ======= ======= Net income (loss) per common share(1)........... $ (0.58) $(0.11) $ 0.35 $ 0.19 $ 0.10 $ 0.07 $ 0.23 ======= ====== ======= ======= ======= ======= ======= Weighted average common shares outstanding(1)... 1,952 2,949 4,990 6,240 6,870 6,536 11,512 ======= ====== ======= ======= ======= ======= ======= OTHER DATA: Operating cash flow(2).......................... $ 846 $ 354 $ 3,030 $ 6,185 $ 9,394 $ 4,025 $13,303 Capital expenditures............................ 1,068 6,189 29,855 16,903 28,524 10,506 60,733 Adjusted EBITDA(3).............................. 856 323 3,019 7,213 11,311 4,892 13,537
AS OF DECEMBER 31, AS OF JUNE 30, ------------------------------------------------- ------------------- 1991 1992 1993 1994 1995 1995 1996 ------ ------ ------- ------- ------- ------- -------- (DOLLARS IN THOUSANDS) BALANCE SHEET DATA: Total assets.................................... $3,466 $8,225 $35,978 $48,964 $77,641 $56,917 $132,900 Working capital (deficiency).................... (125) 1,369 (1,410) (1,620) 6,862 (2,262) (1,184) Long-term debt, net of current maturities....... -- -- 6,177 16,536 3,474 20,491 42,964 Convertible preferred stock..................... -- -- -- -- 15,000 -- 15,759 Shareholders' equity............................ 2,882 7,548 24,431 25,962 53,501 28,891 57,258
- --------------- (1) Adjusted for a proposed one-for-two reverse split to be effective in October 1996, subject to shareholder and regulatory approval. (2) Represents cash flow provided by operations, exclusive of the net change in non-cash working capital balances. (3) Adjusted 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. Adjusted EBITDA is not intended to represent cash flows for the period, nor has it been presented as an alternative to operating income nor as an indicator of operating performance. It should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. See the Company's Consolidated Statements of Cash Flows in the Consolidated Financial Statements included elsewhere in this Prospectus. Adjusted EBITDA is included in this Prospectus because it is a basis upon which the Company assesses its financial performance. 22 25 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. Since 1993, after having disposed of its Canadian oil and natural gas properties, the Company has focused its operations primarily onshore in Louisiana and Mississippi. Over the last three 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 those properties. ACQUISITION OF HESS PROPERTIES The Company completed several property acquisitions during the first half of 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 was approximately 5.9 MMcf/d and 1,962 Bbls/d, which increased the Company's average daily production during the first half of 1996 by approximately 2.0 MMcf/d and 650 Bbls/d, or 1,000 BOE/d. As of July 1, 1996, the properties in this acquisition had estimated net proved reserves of approximately 5.9 MMBOE which consisted of approximately 5.0 MMBbls and approximately 5.6 Bcf, with a PV10 Value of $43.1 million. Approximately 90% of the PV10 Value was for wells on which Denbury assumed operations with an average working interest of approximately 80%. See "Business and Properties -- Acquisitions of Oil and Natural Gas Properties." OTHER ACQUISITIONS In addition to the Hess Acquisition, during the first half of 1996 the Company completed other acquisitions totaling $10.8 million. The largest of these was the Ottawa Acquisition, 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, which were acquired during April 1996 for approximately $7.5 million. The average daily production from the Ottawa Acquisition during April, May and June 1996 was approximately 1.5 MMcf/d and 354 Bbls/d, which increased the Company's average daily production during the first half of 1996 by approximately 760 Mcf/d and 175 Bbls/d, or 300 BOE/d. In addition to the Ottawa Acquisition, the Company spent an additional $3.3 million on four other acquisitions, primarily in Louisiana. These properties contributed approximately 1.5 MMcf/d and 50 Bbls/d, or 300 BOE/d, to the Company's average daily production during the first half of 1996. See "Business and Properties -- Acquisitions of Oil and Natural Gas Properties." As of July 1, 1996, the Company's estimated net proved reserves for all of these other acquisitions, including the Ottawa Acquisition, totaled approximately 1.1 MMBbls and 13.1 Bcf or 3.3 MMBOE, with a PV10 Value of $24.1 million. NEW CREDIT FACILITY In order to fund these acquisitions, improve the terms and increase the size of its previous credit facility, the Company entered into the new $150.0 million Credit Facility. This refinancing closed during the second quarter of 1996 and has a borrowing base as of September 30, 1996 of $60.0 million. 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. 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, at rates ranging from LIBOR plus 7/8% to LIBOR plus 1 3/8%. 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 and (iv) a prohibition of most debt and corporate guarantees. 23 26 CAPITAL RESOURCES AND LIQUIDITY As outlined in the following table, in each of the last three years and during the first half of 1996, the Company made capital expenditures which required additional debt and equity capital to supplement cash flow from operations.
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED ------------------------------ JUNE 30, 1993 1994 1995 1996 -------- -------- -------- ---------------- (DOLLARS IN THOUSANDS) Acquisitions of oil and natural gas properties.................................... $ 20,076 $ 6,606 $ 16,763 $ 47,974 Oil and natural gas expenditures................ 9,779 10,297 11,761 12,759 ------- ------- ------- ------- Total................................. $ 29,855 $ 16,903 $ 28,524 $ 60,733 ======= ======= ======= =======
Since January 1, 1993, the Company has made total capital expenditures of $136.0 million, which were primarily financed with equity ($58.1 million, including the Convertible Preferred), debt ($43.2 million) and cash from operations ($31.9 million). During 1995, the Company's sources of capital, other than cash flow from operations, were a $1.8 million issue of subordinated debt, a $2.4 million private placement of Common Shares and the $39.5 million, net of expenses, TPG Placement in December 1995. During the first half of 1996, the Company's funds were provided by operating cash flow and bank debt, beginning the year with $100,000 of outstanding bank debt and ending the six month period with $40.0 million of bank debt outstanding. As of June 30, 1996, the Company had a working capital deficit of $1.2 million and total bank debt of $40.0 million. The Company has budgeted development expenditures for the remainder of 1996 that exceed its projected cash flow. As of September 30, 1996, the Company had a borrowing base of $60.0 million with a total of $45.0 million drawn against the Credit Facility. With the increased cash flow from the acquired properties and the undrawn portion of the Credit Facility, the Company anticipates that it can fund its development budget for the second half of 1996 of approximately $16.0 million and meet its obligations in the foreseeable future. If external capital resources are limited or reduced in the future, the Company can adjust its development expenditure program accordingly. However, such adjustments could limit, or even eliminate, the Company's future growth. In addition to its development 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 equity financing from the Offerings in order to reduce its debt levels and better position the Company for future opportunities. Sources and Uses of Funds During the first half of 1996, the Company spent approximately $10.7 million on oil and natural gas development expenditures, $48.0 million on the previously discussed oil and natural gas acquisitions, and approximately $2.0 million on geological, geophysical and acreage expenditures. The development expenditures included $3.9 million spent on drilling and the balance of $6.8 million spent on workover costs. These expenditures were funded by bank debt, available cash and cash flow from operations. 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 the balance of $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 24 27 December 1995 with a portion of the $39.5 million of net proceeds from the TPG Placement. See "Interests of Management in Certain Transactions." 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. During 1993, the Company made capital expenditures of approximately $29.9 million, of which $20.1 million was for acquisitions. The remaining $9.8 million was expended on drilling, completions and equipment. Included in the 1993 capital expenditures was approximately $8.7 million for the acquisition of the several properties from a major oil company in Mississippi (the "Mississippi Acquisition"), approximately $1.8 million for the acquisition and $4.7 million for the exploitation of the Puckett field in Mississippi and approximately $9.0 million for the acquisition of properties in Southern Louisiana (the "Louisiana Acquisition"). The Company's largest source of funds in 1993 was net proceeds of $15.1 million from the issuance of equity in Canada, principally comprised of three offerings totaling 2,142,500 Common Shares at an average price of Cdn. $9.16 per share. In each of these offerings, the Company issued special warrants that were subsequently converted into Common Shares. In addition to cash provided by equity during 1993, the Company also received $7.6 million of cash from long-term debt, $3.0 million of cash flow provided by operations and $3.1 million of cash from the disposal of the Company's remaining Canadian properties. RESULTS OF OPERATIONS Comparison of Six Months Ended June 30, 1996 and June 30, 1995 Denbury continued to increase its daily production with an average of 5,453 BOE/d during the first quarter of 1996 and 7,841 BOE/d during the second quarter, for an overall average of 6,647 BOE/d during the first half of 1996 as compared to 3,843 BOE/d for the comparable six month period of 1995 (73% increase). The combination of the Hess and Ottawa Acquisitions contributed approximately 1,300 BOE/d to the Company's average daily production during the first half of 1996. The production from these two acquisitions for the first six months of 1996, including the periods when they were not owned by the Company, was approximately 3,964 BOE/d. In addition, the Gibson Acquisition contributed approximately 1,039 BOE/d to the Company's average daily production during the first half of 1996, with the balance of the increase, 465 BOE/d, primarily attributable to the Company's development and exploitation program. In addition, oil and natural gas prices improved substantially over 1995 levels during the first half of 1996. Average oil prices were $17.39 per Bbl as compared to $14.92 per Bbl for the comparable period in 1995 (17% increase) and natural gas prices increased to an average price of $2.80 per Mcf during the first half of 1996 as compared to $1.85 for the comparable period in 1995 (51% increase). The Company averaged a sales price of $17.07 per BOE during the first half of 1996 as compared to $12.94 per BOE during the first half of 1995 (32% increase). As a result of the aforementioned production and price increases and property acquisitions, oil and natural gas revenue increased 130% to $20.7 million during the first half of 1996 from $9.0 million for the first half of 1995. Approximately $3.7 million of the increase was related to the Hess and Ottawa Acquisitions, approximately $3.3 million to the Gibson Acquisition, approximately $3.4 million to the increase in product prices, and the balance due to an increase in production as a result of development and other acquisition activities. Production expenses also increased 71% to $5.4 million during the first half of 1996 as compared to $3.1 million for the comparable period in 1995. Production expenses on a BOE basis were $4.42 and $4.50 for the first half of 1996 and 1995 respectively, a decline of 2% from first half 1995 levels. The first quarter of 1996 operating expenses were slightly less on a BOE basis because a larger percentage of the first quarter's production was natural gas (62% on a BOE basis), which typically has a lower operating cost per BOE than 25 28 oil. However, the second quarter included two months of operating expenses relating to the Hess Acquisition which had an average production cost of $6.27 per BOE. In July 1996, the Company assumed operations of these Hess Acquisition properties and will focus on lowering the production costs during the last half of 1996 to levels more consistent with the Company's average. General and administrative expenses increased by 77% to $1.7 million for the first half of 1996 from $935,000 for the comparable period in 1995. On a per BOE basis, however, general and administrative costs remained relatively consistent at $1.46 per BOE for the first half of 1996 as compared to $1.40 per BOE for the comparable period in 1995. During the first half of 1996, the Company conducted a review of salaries and awarded raises and bonuses to its employees. Bonuses, including related payroll taxes, amounted to approximately $225,000. 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 as Amerada Hess remained the operator of record until that date. During the first half of 1995, the Company had non-recurring expenses of approximately $190,000 relating to personnel changes. The Company's objective is to lower general and administrative costs for the last half of 1996 on a BOE basis to a level close to the overall average for 1995 of $1.25 per BOE. As a result of the $39.5 million TPG Placement and the corresponding retirement of bank debt, the only interest-bearing debt outstanding during the first quarter of 1996 was approximately $3.3 million of subordinated debt and minor trade notes payable. During the second quarter, however, the Company borrowed $39.9 million on its Credit Facility in order to close the Hess and Ottawa Acquisitions. The net effect was an overall 27% reduction in interest expense to $681,000 for the first half of 1996, from $927,000 for the comparable period of 1995. During the first half of 1996, the Company expensed $759,000 relating to an imputed dividend on the Convertible Preferred. Under Canadian GAAP this is reported as an operating expense, while under U.S. GAAP this would be deducted from net income to arrive at net income applicable to the common shareholders. This charge to earnings reflects the increase in the mandatory redemption value of the Convertible Preferred during the period. The Company has not, nor does it intend to, pay any dividends on the Convertible Preferred. Also during the first half of 1996, the Company had a $440,000 charge relating to a loss on early extinguishment of debt. These costs relate to the remaining unamortized debt issue costs of the Company's prior credit facility with ING Capital Corporation, 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 item relating to another bank refinancing. Under U.S. GAAP, a loss on early extinguishment of debt would be an extraordinary item rather than a normal operating expense as required by Canadian GAAP. DD&A increased by 140% to $7.4 million for the first half of 1996 as compared to $3.1 million for the first half of 1995. DD&A per BOE increased 17% to $6.10 per BOE for the first half of 1996 from $5.22 per BOE for the year ended December 31, 1995 due to a large percentage of the 1995 and 1996 capital expenditures relating to acquisitions, which have had a higher per unit cost for the Company than those reserves added by development expenditures. The deferred tax provision for the first half of 1996 was approximately 41%, which is higher than the U.S. statutory rate due to certain non-deductible Canadian expenses and the non-deductible imputed preferred dividend expense of $759,000. The Company did not have a current tax provision as it generated a loss for federal income tax purposes. Primarily as a result of increased production and improved product prices, net income increased 453% to $2.6 million ($0.11 per common share) for the first half of 1996 from $469,000 ($0.04 per common share) during the first half of 1995. Cash flow from operations (before the change in non-cash working capital balances) also increased 231% over first half 1995 levels to $13.3 million during the first half of 1996 from $4.0 million during the first half of 1995, also primarily due to strong oil and natural gas prices as well as increased production. 26 29 Comparison of Years Ended December 31, 1995 and December 31, 1994 During 1995, production for the year averaged 4,207 BOE/d, which compares to 2,859 BOE/d in 1994 (a 47% increase), with a higher percentage increase in revenue of $7.3 million (a 58% increase) between the two years. Oil production for 1995 increased by 49% from 1,340 Bbls/d in 1994 to 1,995 Bbls/d in 1995 and natural gas production increased by 46% from 9,113 Mcf/d in 1994 to 13,271 Mcf/d in 1995. Approximately 240 BOE/d was attributable to the Gibson Acquisition with the balance primarily attributable to the Company's development and exploitation program. In addition, the average oil price increased 8% from $13.84 per Bbl in 1994 to $14.90 per Bbl in 1995 and the natural gas price also increased 7%, from an average price of $1.78 per Mcf in 1994 to $1.90 per Mcf during 1995. The Company realized a $800,000 gas hedging gain during 1995 which added $0.17 per Mcf to its average net natural gas price. The Company does not have any oil or natural gas hedges in place for 1996 due to the relatively strong commodity prices to date in 1996 and the reduced debt levels and resultant reduced risk of price changes on cash flow. The combination of production and price increases caused oil and natural gas revenue to increase 57%, from $12.7 million in 1994 to $20.0 million in 1995. Approximately $700,000 of the increase is attributable to the Gibson Acquisition, approximately $1.3 million to product price increases with the balance due to the increases in production resulting from development and other acquisition activities. Production expenses were $6.8 million in 1995 compared to $4.3 million in 1994 as a result of increased production, although on a BOE basis, production expense had a slight increase of seven percent to $4.42 per BOE in 1995 from $4.13 in 1994. General and administrative expenses increased by 65% from $1.1 million in 1994 to $1.8 million in 1995 as a result of the Company's continuing growth. On a per BOE basis, these costs also increased by 12% from $1.12 per BOE in 1994 to $1.25 per BOE in 1995 primarily due to $190,000 of expenses during 1995 ($0.12 per BOE) for costs relating to non-recurring personnel changes. Interest expense increased significantly to $2.1 million in 1995 from $1.1 million in 1994. Approximately $19.4 million of bank debt was borrowed during 1995 primarily for acquisitions, increasing bank debt levels to a peak of $32.2 million just before year end when the bank debt was reduced to $100,000 with the proceeds from the TPG Placement. Interest expense on a BOE basis was $1.26 in 1995 versus $0.99 per BOE in 1994 due to the net borrowing during the first eleven months of 1995. Cash flow from operations in 1995 (before the changes in non-cash working capital balances) increased over 1994 by 52%, to $9.4 million in 1995 from $6.2 million in 1994. On a per BOE basis, cash flow from operations in 1995 also increased over 1994 by 3%, to $6.12 in 1995 from $5.93 in 1994. Higher product prices more than offset the higher interest costs, operating expenses and general and administrative costs. DD&A increased by 91% to $8.0 million in 1995 from $4.2 million in 1994. DD&A per BOE also increased 30% from $4.03 in 1994 to $5.22 in 1995 due to a large percentage of the 1995 capital expenditures (60%) relating to acquisitions, which have had a higher per unit cost for the Company than those reserves added by development expenditures. During 1995, the Company recognized $200,000 of expenses relating to the loss on early extinguishment of debt. These costs relate to the unamortized debt issue costs which were written off when the Company changed its primary bank lender in April 1995. Under U.S. GAAP, these costs would be an extraordinary item, rather than a normal operating expense as required under Canadian GAAP. The deferred tax provision for 1995 was approximately 34%, slightly less than 1994's provision of approximately 38%. The 1994 provision was slightly higher than the U.S. statutory rate due to the mix of Canadian versus U.S. expenses. The Company did not have a current tax provision as it generated a loss for federal income tax purposes. Net income decreased by 39% to $714,000 in 1995 from $1.2 million in 1994. Although every category of revenue and expense increased substantially between the two years, the reduced net income was primarily a result of certain nonrecurring charges and a disproportionate increase in depreciation and depletion expense as compared to the increase in revenue. 27 30 Comparison of Years Ended December 31, 1994 and December 31, 1993 During 1994, production for the year averaged 2,859 BOE/d, which compares to 1,194 BOE/d in 1993. Oil production for 1994 increased by 56% from 858 Bbls/d in 1993 to 1,340 Bbls/d in 1994 and natural gas production increased by 353% from 2.0 MMcf/d in 1993 to 9.1 MMcf/d in 1994. However, natural gas prices decreased 14%, from 1993 average prices of $2.06 per Mcf to the $1.78 per Mcf in 1994 with oil prices remaining almost constant at $13.91 per Bbl in 1993 and $13.84 per Bbl in 1994. The net effect of the production increase and natural gas price decrease was an increase in revenue for 1994 of 116% over 1993 revenue, with 1994 oil and natural gas revenue of $12.7 million as compared to 1993 levels of $5.9 million. Approximately $7.8 million of the increase was attributable to production increases, partially offset by the drop in revenue of approximately $931,000 attributable to the decline in natural gas prices. Production expenses were $4.3 million in 1994 compared to $2.1 million in 1993 as a result of increased production. On a BOE basis, production expense declined by 13% to $4.13 per BOE in 1994 from $4.75 per BOE in 1993 as a result of cost saving measures by the Company and the gas properties acquired in the Louisiana Acquisition late in 1993 which generally have a lower operating cost per BOE than oil properties. General and administrative expenses increased by 41% from $782,000 in 1993 to $1.1 million in 1994. This reflects the Company's increased activity and the establishment of the second major operating area in Southern Louisiana in late 1993. On a per BOE basis, however, these costs decreased by 38% from $1.80 per BOE in 1993 to $1.12 per BOE in 1994. Interest expense increased significantly to $1.1 million in 1994 from $83,000 in 1993. Approximately $7.6 million of interest-bearing debt was added in late 1993 primarily to complete the Louisiana Acquisition, and further acquisitions during 1994 increased debt to $16.4 million by year end. Additionally, the weighted average interest rate increased by 0.9 percentage points during 1994 from 8.0% in 1993 to 8.9% in 1994. Interest expense was $0.99 per BOE in 1994 versus a net interest income of $0.04 per BOE in 1993. Cash flow from operations in 1994 (before the changes in non-cash working capital balances) increased over 1993 by 104%, from $3.0 million in 1993 to $6.2 million in 1994. On a per BOE basis, however, cash flow from operations in 1994 decreased from 1993 levels by 15%, from $6.96 per BOE in 1993 to $5.93 per BOE in 1994. Higher interest costs and lower product prices more than offset the positive effects of lower per unit operating and general and administrative costs. DD&A increased by 122% to $4.2 million in 1994 from $1.9 million in 1993 as a result of the 140% increase in production. The percentage increase in DD&A was lower than the percentage increase in production due to the addition of significant reserves at a lower cost per BOE. DD&A per BOE decreased 8% from $4.36 in 1993 to $4.03 in 1994. Deferred taxes represent approximately 38% of income before income taxes in 1994, an increase from the 17% in 1993. The 1993 tax provision was reduced by the application of Canadian tax loss carry forwards against the one-time gain from the sale of Canadian assets. The Company did not have a current tax provision as it generated a loss for federal income tax purposes. Net income, before the one-time gain in 1993 from the sale of Canadian properties, increased by 51% to $1.2 million in 1994 from $769,000 in 1993, primarily as a result of the increased production and associated revenue with a less than proportionate increase in most expenses. 28 31 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. Since 1993, after having disposed of its Canadian oil and natural gas properties, the Company has focused its operations primarily onshore in Louisiana and Mississippi. Over the last three 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 those properties. For the three-year period ended December 31, 1995, the Company increased its proved reserves by 57% per annum, from 5.8 MMBOE at December 31, 1993 to 14.3 MMBOE. As of July 1, 1996, including the Hess and Ottawa Acquisitions (as herein defined), the Company had increased its proved reserves to 22.7 MMBOE, representing a 59% increase over December 31, 1995 reserves. Over the same three-year period, the Company also increased its average daily production by 88% per annum, from 1,194 BOE/d to 4,207 BOE/d. Pro forma for the Hess and Ottawa Acquisitions, production for the first six months of 1996 was 9,323 BOE/d. For the three-year period ended December 31, 1995, Adjusted EBITDA grew at an annual rate of 94%, from $3.0 million to $11.3 million. Pro forma Adjusted EBITDA for the first six months of 1996 was $18.7 million. As of July 1, 1996, the Company had proved reserves of 11.7 MMBbls and 65.8 Bcf. At such date, the PV10 Value was $175.3 million, of which $157.8 million was attributable to proved developed reserves. Denbury operates wells comprising approximately 68% of its PV10 Value. The twelve largest fields owned by the Company constitute approximately 80% of its estimated proved reserves and within these twelve fields, Denbury owns an average working interest of 84%. The Company's address is 17304 Preston Road, Suite 200, Dallas, TX 75252 and the telephone number is (972) 380-1923. BUSINESS STRATEGY 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. The Company seeks to achieve attractive returns on capital through prudent acquisitions, development and exploratory drilling and efficient operations; maintain a conservative balance sheet to preserve maximum financial and operational flexibility; and create strong employee incentives through equity ownership. These fundamental principles are at the core of the Company's long-term growth strategy. REGIONAL FOCUS. By focusing its efforts in the Gulf Coast region, primarily Louisiana and Mississippi, the Company has been able to accumulate substantial geological, reservoir and operating data which it believes provides it with a significant competitive advantage. Given its experience in the Gulf Coast region, the Company believes it is better able to proactively identify and evaluate potential acquisitions, negotiate and close selected acquisitions on favorable terms, and develop and operate the properties in an efficient and low- cost manner once acquired. The Company believes the Gulf Coast represents one of the most attractive regions in North America given the region's prolific production history and the new 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 attractive 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 acquires properties where it believes significant additional value can be created. Such properties are typically characterized by: (i) long production histories; (ii) complex geological formations which have multiple producing zones and substantial exploitation potential; (iii) a history of limited operational attention 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. By maintaining conservative levels of debt, the Company is able to respond quickly 29 32 to acquisitions that fit within its criteria. The Company believes that due to continuing rationalization of properties, primarily by major integrated and independent energy companies, a strong backlog of acquisition opportunities should continue. 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 Company's recent Hess and Ottawa Acquisitions are illustrative of the type of opportunities the Company seeks. OPERATION OF HIGH WORKING INTEREST PROPERTIES. The Company typically seeks to acquire working interest positions that give the Company operational control or which the Company believes may lead to operational control. As the operator of properties comprising approximately 68% of its total PV10 Value, the Company 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 in fully evaluating a field for future potential and, if favorable, consolidates 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 to the point where the potential benefits of value enhancement activities justify the allocation of Company resources. EXPLOITATION OF PROPERTIES. The Company seeks to maximize the value of its properties by either increasing production, increasing recoverable reserves or reducing operating costs, and often through a combination of all three. The Company utilizes a variety of techniques to achieve this goal, 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; (iv) conducting developmental drilling to access undrained portions of the field which can only be produced from a new wellbore; and (v) utilizing exploratory drilling, which is frequently based on various advanced technologies such as 3-D seismic. The Company believes that by employing a full range of value enhancement techniques it is better able to extract the maximum value from its properties. PERSONNEL. The Company believes it has assembled a highly competitive team of experienced and technically proficient employees who are motivated through a positive work environment and by ownership in the Company, which is encouraged through the Company's stock option and stock purchase plans. The Company's geological and engineering professionals have an average of over 15 years of experience in the Gulf Coast region. The Company believes that employee ownership is essential for attracting, retaining and motivating quality personnel. Approximately 92% of Denbury's eligible employees were participating in the Company's stock purchase plan as of July 1, 1996. OIL AND NATURAL GAS OPERATIONS Denbury operates in two core areas, Louisiana and Mississippi. The Company operates 54 wells in Louisiana from an office in Houma and 107 wells in Mississippi from an office in Laurel. The 12 largest oil and natural gas fields owned by the Company constitute approximately 80% of its total reserves on both a BOE and PV10 Value basis Within these 12 fields, Denbury owns an average 84% working interest and operates 77% of the wells, which comprise 54% of the Company's PV10 Value. 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 mostly multiple sandstone reservoirs with strong water-drive characteristics. 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 30 33 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 tables set 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 July 1, 1996 were prepared by Netherland & Sewell. See "Risk Factors -- Uncertainty of Estimates of Oil and Natural Gas Reserves."
1996 AVERAGE PROVED RESERVES AS OF JULY 1, 1996 PRODUCTION(1) ----------------------------------------------- ---------------------- GROSS AVERAGE NET OIL NATURAL GAS PV10 VALUE PV10 VALUE OIL NATURAL GAS PRODUCTIVE REVENUE (MBBLS) (MMCF) (000'S)(2) % OF TOTAL (BBLS/D) (MCF/D) WELLS(3) INTEREST(3) ------- ----------- ---------- ---------- -------- ----------- ---------- ----------- LOUISIANA Lirette................ 290 28,566 $ 45,661 26.1% 157 7,897 11 60.1% Gibson................. 309 6,732 14,879 8.5% 184 4,330 2 54.5% South Chauvin.......... 144 7,362 8,857 5.0% 25 283 2 76.0% Bayou Rambio........... 38 4,591 6,454 3.7% 30 2,200 1 72.2% Lapeyrouse............. 127 2,578 6,025 3.4% 3 66 3 61.8% Other Louisiana........ 1,484 10,863 29,425 16.8% 433 5,541 83 41.0% ------ ------ -------- ------ ----- ------ --- Total Louisiana...... 2,392 60,692 111,301 63.5% 832 20,317 102 44.4% ------ ------ -------- ------ ----- ------ --- MISSISSIPPI Eucutta................ 2,999 -- 20,751 11.8% 350 -- 36 71.9% Davis.................. 2,375 -- 12,420 7.1% 622 -- 24 70.6% South Thompson Creek... 516 -- 5,930 3.4% 116 -- 4 80.0% West Yellow Creek...... 869 -- 4,657 2.7% 266 -- 7 78.2% Quitman................ 854 -- 4,137 2.4% 61 -- 7 67.5% Dexter................. -- 3,699 4,070 2.3% 1 1,643 8 48.3% Puckett................ 750 40 3,845 2.2% 185 9 7 75.4% Other Mississippi...... 818 699 5,103 2.9% 406 202 79 28.9% ------ ------ -------- ------ ----- ------ --- Total Mississippi.... 9,181 4,438 60,913 34.8% 2,007 1,854 172 51.3% ------ ------ -------- ------ ----- ------ --- OTHER.................... 152 677 3,041 1.7% 55 347 14 35.9% ------ ------ -------- ------ ----- ------ --- COMPANY TOTAL............ 11,725 65,807 $175,255 100.0% 2,894 22,518 288 48.1% ====== ====== ======== ====== ===== ====== ===
- --------------- (1) Average production during the period from January 1, 1996 through June 30, 1996. Certain properties, including those purchased in the Hess and Ottawa Acquisitions, were acquired during 1996. This table only includes production during the periods when such properties were owned by the Company. See "-- Production Volumes, Sales Prices and Production Costs" for pro forma production data. (2) The reserves were prepared using constant prices and costs in accordance with the guidelines of the SEC, based on the prices received on a field by field basis as of July 1, 1996. The oil price at that date was West Texas Intermediate $20.00 per Bbl adjusted by field and a NYMEX Henry Hub natural gas price average of $2.65 per MMBtu, also adjusted by field. (3) Includes only productive wells in which the Company had a working interest as of July 1, 1996. 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 areas 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 31 34 significant reserves. The Company believes that the first generation of 3-D data acquired in these swampy areas has the potential to identify significant exploration prospects, particularly in the deeper geopressured sections below 12,000 feet. Lirette 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. An initial geological review indicated significant potential and in early 1994, Denbury increased its interest in the field to an average 60% working interest by acquiring additional interests from working interest partners in four separate transactions. 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 early 1995 to increase the Company's ownership to its current average 78% working interest. As a result of two workovers and two wells drilled during 1996, net production had increased during August 1996 to 11.6 MMcf/d and 181 Bbls/d from 13 wells. During the latter half of 1996 and into 1997, the Lirette Field will be covered by a 3-D survey currently in process. It is anticipated that drilling projects created out of this seismic work will probably be drilled in late 1997 or 1998. See "-- Southern Louisiana 3-D Acquisitions." Gibson/Humphreys In late 1994, Denbury acquired minor working interests in five wells in the Gibson and Humphreys Fields located in Terrebonne Parish, 20 miles northwest of the Lirette Field, in the northern part of the Houma embayment. The Gibson Field, discovered in 1937, has produced over 813 Bcf and 14 MMBbls while the Humphreys Field, discovered in 1956, has produced 527 Bcf and 6 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 majority working interest in these fields. By December 1995, Denbury's acreage position had grown to 3,165 net acres with interests in six active wells and eight inactive wells. During August 1996, net production in these two fields averaged approximately 3.8 MMcf/d and 66 Bbls/d. Two additional wells are currently planned in this area during 1997, one of which is an offset to the Kuntz A-10 well, Gibson Field's largest current producer, to attempt to accelerate the production of the field's behind pipe zones. The second well will be drilled to a new horizon within the same field. South Chauvin In February 1996, Denbury purchased interests in two producing wells and four non-producing wells in South Chauvin Field located in the Houma embayment area, about 4 miles south of Houma and six miles northwest of Lirette Field. Chauvin Field, discovered by Shell Oil, is a faulted anticline which has produced approximately 180 Bcf and 8,500 MBbls since 1960 at depths between 6,000 feet and 14,500 feet. The Company believes considerable potential exists in the deeper sections below 13,000 feet. Some production has already been established at Chauvin from this deeper section but appears not to have been drilled at the optimum location. Denbury intends to either shoot a new 3-D survey or purchase one recently shot by another company within the next 12 months to confirm the structure. Of the three currently producing wells at Chauvin, Denbury owns an average 95% working interest. During August 1996, these three wells produced at an average net rate of 0.4 MMcf/d. The Company plans a series of workovers in the latter half of 1996 and has to date identified 16 potential behind pipe zones in four wells and two undeveloped drilling locations. This drilling activity is planned for 1997. 32 35 Bayou Rambio Production at the Bayou Rambio Field was established in 1955 and has exceeded 150 Bcf and 920 MBbls to date. Denbury operates one producing well in the field, the Kelly #2 which is located in Terrebonne Parish about 15 miles west of Lirette Field. During October 1995, the Company successfully recompleted this well and during the first part of 1996, acquired additional interests in this well, bringing its working interest to 88%. During August 1996, the Kelly #2 produced at an average net rate of approximately 1 MMcf/d and 10 Bbls/d. The Company is currently evaluating 15 square miles of 3-D seismic data covering this area. Based upon this evaluation, a development location is tentatively scheduled to be drilled during 1997. This field has historically produced from twenty-five different pay zones. Lapeyrouse The Lapeyrouse Field is a large structural feature which has produced over 2 Tcf and 10 MMBbls since its discovery in 1941. Denbury currently operates one producing well and one shut-in well and has a small interest in one other producing well in the Lapeyrouse field. Net production from this area was relatively minor during August 1996, averaging 0.1 MMcf/d and 2 Bbls/d. However, this area is part of the Lirette 3-D joint venture and also will be covered by the 147 square mile 3-D survey to be conducted in late 1996. The Company believes considerable potential exists in the section below 15,000 feet which has produced 8 Bcf from one well in the field. The Company is planning a workover of the shut-in well during 1997, pending a review of the 3-D seismic, and anticipates that other drilling opportunities may arise as 3-D data is evaluated across this large feature. See "-- Southern Louisiana 3-D Acquisitions." Other Louisiana The Company has a 50% working interest in 17 operated producing wells in the Bayou Des Allemands Field, located in the LaFourche and St. Charles Parishes. This field was acquired as part of the Hess Acquisition. During August 1996, net production from this field averaged 0.1 MMcf/d and 162 Bbl/d. Production in this field is from discrete sand intervals located from 3,700 feet to 11,500 feet in depth. Over 30 behind pipe sands have been identified for future completion as the present zones deplete. Additional potential may exist in updip locations in producing fault blocks, in untested fault blocks and in deeper horizons. A 3-D seismic survey is planned during 1997 to help identify any upside potential. The Company also acquired Lake Chicot Field in St. Martin Parish, Louisiana as part of the Hess Acquisition and has a 50% working interest in 12 wells. Only three wells are currently producing, although the Company is in the process of returning another 9 wells to production as the field was temporarily shut-in when the Company took over as operator after the acquisition. Denbury owns a non-operated 19% working interest in three active wells in North Deep Lake Field in Cameron Parish. During 1995, one of these wells was successfully recompleted into a shallower sand. During August 1996, net production from this field averaged 1.6 MMcf/d. Denbury owns a 100% working interest in 551 acres covering Breton Sound Blocks 12 and 13 located in Louisiana State water approximately 70 miles southeast of New Orleans. Breton Sound Block 13 is an abandoned oil and natural gas field in 14 feet of water. Production was established in the 1960s from a mid-Miocene sand at 7,500 feet, but water and natural gas coning from an associated natural gas cap prevented significant economic production. The field was abandoned in the 1970s after having produced less than 150 MBbls. During the second quarter of 1996, Denbury drilled a horizontal well to redevelop this field. The well tested at a gross production rate of 5.5 MMcf/d and commenced production on September 2, 1996. During the first 23 days of production, the well's gross production averaged 1.9 MMcf/d and 55 Bbls/d. Although the well is on production, the Company is still in process of completing its oil storage facilities that should be completed by early October. Because of the limited oil storage facilities, the Company is not currently able to produce the well at its optimum rates and until the facilities are completed, an accurate assessment of future production rates is not possible. 33 36 Southern Louisiana 3-D Acquisitions During 1995, the Company acquired approximately 46 square miles of 3-D seismic data over five of its existing fields in southern Louisiana consisting of Bayou Rambio, DeLarge, North Deep Lake, Gibson and Humphreys. During the second quarter of 1996, the Company entered into a joint venture agreement with two industry partners to acquire approximately 147 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 will own a one-third interest in any new prospects discovered through this joint venture, which currently owns rights to over 35,000 acres within the survey area. The Company will be responsible for one-third of the cost of both the 3-D seismic survey and any wells drilled. The Company anticipates that the 3-D seismic survey should be completed and the data analyzed by the fall of 1997. In addition, five of the fields acquired during the first half of 1996 have 3-D seismic coverage which should be available to the Company in the future and two additional fields are presently being surveyed. The acquisition and processing of this data will occur during the second half of 1996 and continue into 1997. 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. Eucutta 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 recent Hess Acquisition and currently operates 31 producing oil wells and 16 saltwater injection wells. The field is divided into a shallow Eutaw sand unit in which the Company has a 76% working interest and the deeper Tuscaloosa sand zones in which the Company has a 100% working interest. The Eucutta Field traps oil in multiple sandstones in a highly faulted anticline. At present, seven different sands are productive at depths between 5,000 feet and 11,000 feet. Most of the wells produce oil with large amounts of saltwater, which requires pumping. During August 1996, net production from this field averaged 1,169 Bbls/d. The Company plans a capital expenditure program at Eucutta Field which will include upgrading producing facilities, drilling wells and a 3-D seismic evaluation. The Company believes that through a combination of these investments, production can be increased and operating costs reduced. Two wells are planned to be drilled in late 1996, with perhaps four more in 1997 and 1998. Consideration is being given to acquiring a 3-D seismic survey over the field and, if pursued, most likely would occur in 1997. Davis/Frances Creek The Davis Field and nearby Frances Creek Field are located 42 miles northeast of Laurel in the northern part of the Mississippi salt basin. Denbury operates 19 producing wells within the area and owns minor non-operated interests in eight other wells. The net average production from these wells during August 1996 was approximately 805 Bbls/d. 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. Both the Davis and Frances Creek Fields are relatively mature fields and produce large amounts of saltwater. During August 1996, these fields produced an average of approximately 55,000 barrels of saltwater per day, all of which were re-injected into the ground. The Company places considerable emphasis on controlling operating costs in these fields to minimize the cost of saltwater disposal and pumping equipment. 34 37 Since acquiring the majority of the field in 1993, Denbury has undertaken an active redevelopment program including numerous workovers and two 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 the remainder of 1996, the Company plans to drill a horizontal well to improve withdrawal efficiency, with another horizontal well planned for 1997. The Company has identified 11 zones behind pipe for future development. South Thompson Creek The South Thompson Creek Field is located in Wayne County, Mississippi, about 23 miles southeast of Laurel. Denbury operates 3 wells in the field with an average working interest of 100%. In August 1996, net production from the field averaged 506 Bbls/d. The South Thompson Creek Field is an anticline which has produced a total of 3.9 MMBbls since its discovery in 1960 from sandstone reservoirs in the Hosston, Rodessa and Tuscaloosa formations. Denbury first acquired an interest in the field in 1993 and increased its ownership in 1995 by acquiring the apex of the field. Subsequently, in 1995, the Company drilled its first horizontal well and in April 1996, Denbury acquired the remaining interest in the field as part of the Ottawa Acquisition. A second horizontal well was drilled in May 1996, which during August 1996 produced an average of 378 Bbls/d and 763 barrels of saltwater per day. In 1997, the Company may drill a third horizontal well in the field pending continued evaluation of the first two horizontal wells. In addition, there are two shut in wells which have recompletion potential. West Yellow Creek The West Yellow Creek Field is located 28 miles west of Laurel in Wayne County, Mississippi. Denbury operates seven producing oil wells and two saltwater disposal wells, with an average working interest of 97%. During August 1996, net production from the field averaged 271 Bbls/d. The Company's production is located in the central part of West Yellow Creek Field which has produced over 34 MMBbls since 1947, with most of the production being from the Eutaw formation at 5,000 feet. Production also occurs from multiple sands in the Tuscaloosa and Washita-Fredericksburg formations. This Tuscaloosa and Washita-Fredericksburg production, discovered in 1966, was essentially abandoned prior to 1993, when the Company acquired its first interests in the field. The Company began a drilling program in 1993 which continued through 1994. By a combination of successful drilling and additional production acquisitions, the Company was able to increase its net production from 40 Bbls/d in 1993 to 250 Bbls/d in 1995. In 1996, the Company acquired an additional 50% working interest in the operated wells through the Ottawa Acquisition. Quitman The Quitman Field is located in Clarke County, Mississippi, 31 miles northeast of Laurel and near the Davis and Frances Creek Fields. The Company acquired the field as part of the Hess Acquisition and now operates seven producing wells and 13 shut in wells. The Company owns an average working interest of 82%. In August 1996, net production from these wells averaged 173 Bbls/d. The Quitman Field was discovered in 1966 and has produced approximately 21 MMBbls from 18 separate reservoirs between 4,000 feet and 12,000 feet. The principal producing zones at Quitman are the Smackover formation and several sands in the Cotton Valley formation. Denbury has identified 24 prospective zones behind pipe in existing shut-in wells. Testing of these zones will begin during the second half of 1996. The Company also plans to upgrade production and saltwater disposal facilities in an attempt to lower operating costs. 35 38 In 1997, the Company plans to evaluate the Quitman Field and the immediate vicinity, including Davis and Frances Creek fields, with a 3-D seismic survey. The Company believes that this survey will aid in the accurate evaluation of the existing reservoir and could lead to the discovery of new producing horizons. Dexter The Dexter Field is located in southern Mississippi, about 60 miles northeast of New Orleans, Louisiana. This field has produced 240 Bcf and 10.8 MMBbls since its discovery in 1957 from a series of natural gas and oil bearing reservoirs between 8,000 feet and 16,000 feet. The Company currently owns interests in eight outside operated wells, with an average 56% working interest. These interests were acquired in several transactions between 1992 and 1996. During August 1996, average net production from these wells was 2.3 MMcf/d. The Company has identified four additional zones for recompletion potential and may drill a development well in this field in 1997. Puckett The Puckett Field, which was discovered in 1960, is located about 40 miles northwest of Laurel in Southern Mississippi. Since its discovery Puckett has produced 7.3 Bcf and 6 MMBbls. Denbury operates seven wells in the field with an average working interest of 94%. In August 1996, average net production from these wells was 143 Bbls/d. Denbury acquired its interest in January 1993 and immediately began a workover program in the field. Gross production was increased from 40 BOE/d to its current level of 186 BOE/d during August 1996. Current plans are to produce the current zones and then recomplete these wells into uphole horizons. There are presently 13 zones identified behind pipe for future development. Other Mississippi The Sandersville Field is located about 12 miles northeast of Laurel, Mississippi. The field produces heavy oil from shallow sands of the Eutaw formation along with large amounts of saltwater. The Sandersville Field was first purchased in late 1994 when Denbury acquired a 97% working interest in 15 active and inactive wells. During 1996, the Company completed a rework of six producing wells and two saltwater disposal wells, and net production in August 1996 averaged 254 Bbls/d. Sandersville Field is a four-mile long structure with oil trapped in multiple sands at around 4,000 feet. Historically, the recovery of oil has been low and may be enhanced by horizontal drilling. A study is underway to determine the best location to test this concept with a well planned for mid-1997. ACQUISITIONS OF OIL AND NATURAL GAS PROPERTIES The Company regularly seeks to acquire properties that complement its operations, that provide exploitation, exploration and development opportunities and that 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 were approximately $93.7 million. The properties included in the Company's five largest acquisitions make up approximately 80% of its total proved reserves on a BOE basis. These five acquisitions are discussed below in the order of their acquisition by the Company. Mississippi Acquisition 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 2,206 MBOE. From the date of acquisition through June 30, 1996, the Company produced 789 MBOE from the acquired properties and has successfully increased its ownership in the Davis Field through approximately $600,000 of incremental 36 39 acquisitions. As of July 1, 1996, the estimated net proved reserves of the properties totaled 2.4 MMBOE, with a PV10 Value of $12.5 million. Louisiana Acquisition 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 located 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 1,677 MBOE. From the date of acquisition through June 30, 1996, the Company produced 1,669 MBOE from the acquired properties. Subsequent to the acquisition, Denbury has successfully completed approximately $9.6 million in acquisitions of incremental interests in the Lirette and Bayou Rambio Fields. As of July 1, 1996, the estimated net proved reserves of the properties was 7.1 MMBOE, with a PV10 Value of $65.0 million. Gibson Acquisition 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 1,985 MBOE. From the date of acquisition through June 30, 1996, the Company produced 256 MBOE from the acquired properties. As of July 1, 1996, the estimated net proved reserves of the properties was 1.6 MMBOE, with a PV10 Value of $16.5 million. Ottawa Acquisition In April 1996, the Company acquired additional working interests in five of its existing oil and natural gas properties in Mississippi, plus certain overriding royalty interests in other areas, from Ottawa for approximately $7.5 million. This acquisition included 29 producing gross wells (8.8 net working interest wells), plus overriding royalty interests in an additional 65 wells. These properties contributed approximately 760 Mcf/d and 175 Bbls/d, or 300 BOE/d, to the Company's average net daily production during the first half of 1996. Average daily production during the first half of 1996 from these properties, including the periods when they were not owned by the Company, was approximately 1,615 Mcf/d and 360 Bbls/d, or 629 BOE/d, net to the interest acquired by Denbury. As of July 1, 1996, the estimated net proved reserves of these properties was 1.3 MMBOE, with a PV10 Value of $10.4 million. Hess Acquisition The largest acquisition by the Company to date, which occurred during the first half of 1996, 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. In May and June 1996, these properties contributed approximately 2.0 MMcf/d and 650 Bbls/d, or 1,000 BOE/d, to the Company's average daily production during the first half of 1996. Average daily production during the first half of 1996 from these properties, including the periods when they were not owned by the Company, was approximately 6.6 MMcf/d and 2,230 Bbls/d, or 3,335 BOE/d, net to the interest acquired by Denbury. The properties in this acquisition had estimated net proved reserves of approximately 5.9 MMBOE which consisted of 5.0 MMBbls and 5.6 Bcf, with a PV10 Value of $43.1 million. Approximately 90% of the PV10 Value of the Hess Acquisition was for wells on which Denbury assumed operations with an average working interest of approximately 80%. Four fields out of a total of 60 fields, comprise approximately 73% of the total Hess Acquisition PV10 Value. The two largest fields in Mississippi, Eucutta and Quitman Fields, make up approximately 57% of the total acquisition PV10 Value. Both fields are 37 40 in the same vicinity as the Company's existing Mississippi core properties, with the Eucutta Field located in Wayne County, Mississippi between the Company's Sandersville and West Yellow Creek existing production. The Quitman Field is located in Clarke County, Mississippi, adjacent to the Company's Davis and Frances Creek existing production. The two largest fields in Louisiana are the Atchafalaya Bay and Bayou Des Allemands Fields, which comprise approximately 16% of the total acquisition PV10 Value. These two fields are in adjacent parishes to Terrebonne Parish where the majority of the Company's existing Louisiana production is located. Atchafalaya Bay Field is just west of Terrebonne Parish in St. Mary Parish and Bayou Des Allemands Field is located Northeast of Terrebonne Parish in St. Charles and LaFourche Parishes. 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 year of the three-year period ended December 31, 1995 and the six month periods ended June 30, 1995 and 1996.
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED JUNE 30, -------------------------------------- ----------------------------- PRO PRO FORMA FORMA 1993 1994 1995 1995(1) 1995 1996 1996(1) ------ ------ ------ ------- ------ ------ ------- NET PRODUCTION VOLUME: Crude oil (MBbls)......... 313 489 728 1,813 331 527 847 Natural gas (MMcf) ....... 735 3,326 4,844 8,000 2,186 4,098 5,102 Oil equivalent (MBOE)..... 435 1,043 1,535 3,146 696 1,210 1,697 AVERAGE SALE PRICES: Crude oil ($/Bbl)......... $13.91 $13.84 $14.90 $14.64 $14.92 $17.39 $17.33 Natural gas ($/Mcf) ...... 2.06 1.78 1.90 1.83 1.85 2.80 2.72 Oil equivalent ($/BOE).... 13.47 12.17 13.05 13.09 12.94 17.07 16.84 AVERAGE PRODUCTION COSTS: Per equivalent BOE........ $ 4.75 $ 4.13 $ 4.42 $ 4.87 $ 4.50 $ 4.42 $ 4.64
- --------------- (1) During 1996, the Company made two significant property acquisitions. See "Acquisitions of Oil and Natural Gas Properties." The summary pro forma results assume that these transactions were completed as of the beginning of each respective period. See also "Pro Forma Operating Results." OIL AND NATURAL GAS ACREAGE The following table sets forth the Company's acreage position as of December 31, 1995:
DEVELOPED UNDEVELOPED ----------------- ----------------- GROSS NET GROSS NET ------ ------ ------ ------ Louisiana............................................. 13,704 10,333 3,990 3,902 Mississippi........................................... 5,940 3,079 3,826 1,963 Oklahoma.............................................. -- -- 550 340 Texas................................................. 840 660 1,385 417 ------ ------ ------ ------ Total....................................... 20,484 14,072 9,751 6,622 ====== ====== ====== ======
38 41 The following table sets forth the Company's acreage position as of June 30, 1996:
DEVELOPED UNDEVELOPED ----------------- ----------------- GROSS NET GROSS NET ------ ------ ------ ------ Alabama............................................... 870 600 1,089 361 Louisiana............................................. 29,802 20,487 7,565 6,765 Mississippi........................................... 18,087 11,903 13,181 6,336 Oklahoma.............................................. -- -- 550 340 Texas................................................. 840 660 1,385 417 ------ ------ ------ ------ Total....................................... 49,599 33,650 23,770 14,219 ====== ====== ====== ======
PRODUCTIVE WELLS The following table sets forth the Company's gross and net productive wells as of December 31, 1995:
NATURAL GAS OIL WELLS WELLS TOTAL -------------- -------------- --------------- GROSS NET GROSS NET GROSS NET ----- ---- ----- ---- ----- ----- Louisiana.................................. 9 5.7 32 20.5 41 26.2 Mississippi................................ 64 45.9 11 2.2 75 48.1 Texas...................................... -- -- 4 2.9 4 2.9 --- ---- -- ---- --- ----- Total ........................... 73 51.6 47 25.6 120 77.2 === ==== == ==== === =====
The following table sets forth the Company's gross and net productive wells as of June 30, 1996:
NATURAL GAS OIL WELLS WELLS TOTAL --------------- -------------- --------------- GROSS NET GROSS NET GROSS NET ----- ----- ----- ---- ----- ----- Alabama................................... 2 0.2 5 1.0 7 1.2 Louisiana................................. 54 27.9 48 27.2 102 55.1 Mississippi............................... 158 102.8 14 5.3 172 108.1 Texas..................................... 2 1.8 5 3.3 7 5.1 --- ----- -- ---- --- ----- Total........................... 216 132.7 72 36.8 288 169.5 === ===== == ==== === =====
DRILLING ACTIVITY The following table sets forth the results of drilling activities during each of the three years in the period ended December 31, 1995 and the six months ended June 30, 1996. Two wells were in the process of drilling at June 30, 1996.
SIX MONTHS ENDED JUNE 30, YEAR ENDED DECEMBER 31, 1996 ------------------------------------------- ----------- GROSS NET GROSS NET GROSS NET GROSS NET ----- --- ----- --- ----- --- ----- --- EXPLORATORY WELLS: Productive................................ -- -- -- -- -- -- -- -- Nonproductive............................. 1 0.5 3 0.8 2 1.0 1 1.0 DEVELOPMENT WELLS: Productive................................ 5 2.2 4 2.9 2 1.5 4 3.5 Nonproductive............................. 1 0.9 1 1.0 -- -- -- -- - --- - --- - --- - --- Total.................................. 7 3.6 8 4.7 4 2.5 5 4.5 = === = === = === = ===
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 all of its product as it becomes available or in transporting its product to these markets. 39 42 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 one-year 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 80% of the Company's oil production in 1995, is primarily light sour crude and sells at a discount to the published West Texas Intermediate posting. The balance of the oil production, Louisiana oil, is primarily light sweet crude, which typically sells at a slight premium to the West Texas Intermediate posting. 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 did not have any hedge contracts in place as of September 30, 1996 although it may have such contracts in the future. 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 operations. For the period ended December 31, 1995, the Company sold 10% or more of its net production of oil and natural gas to the following purchasers: Natural Gas Clearinghouse (21%), Amerada Hess (20%), Conoco, Inc. (12%), and Brymore Energy Corp. (12%), which as of May 1, 1996 is wholly-owned by the Company. 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. 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. GEOGRAPHIC SEGMENTS During 1993, the Company had $618,000 of oil and natural gas sales in Canada and generated $1.1 million of net income in Canada, including the gain on sale of Canadian properties of $966,000. All Canadian oil and natural gas properties were disposed of in 1993 and thus all of the Company's operations are now in the United States. 40 43 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 the 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 in, 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. 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 41 44 as to purchase natural gas directly from third-party merchants other than the pipelines and obtain 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 provisions 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 orders 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 the FERC to 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. 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. 42 45 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 Company also is subject to a variety of federal, state, and local permitting and registration requirements relating to 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. 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 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 it (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. See Note 4 "Income Taxes" of the Consolidated Financial Statements for additional tax disclosures. LEGAL PROCEEDINGS There are no material pending legal proceedings to which the Company or any of its subsidiaries is a party or of which any of their property is the subject. However, due to the nature of its business, certain legal or administrative proceedings arise from time to time in the ordinary course of its business. 43 46 MANAGEMENT DIRECTORS AND EXECUTIVE OFFICERS The names of the directors and officers of the Company, the offices held by them with the Company and the periods during which such offices have been held are set forth below. Each executive 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 Company currently has a vacancy on its Board of Directors caused by the resignation of Mr. Martin Fortier on August 30, 1996. If replaced, this vacancy will be filled by a non-TPG nominee.
NAME AGE POSITION(S) - ----------------------------------------- ------ ----------------------------------------- Ronald G. Greene(1)(2)(3)(4)............. 47 Chairman of the Board William S. Price, III(2)(3)(4)........... 40 Director David M. Stanton(1)...................... 34 Director Wieland F. Wettstein(1).................. 46 Director David Bonderman.......................... 53 Director Gareth Roberts........................... 43 President, Chief Executive Officer and Director Phil Rykhoek............................. 40 Chief Financial Officer and Secretary Mark A. Worthey.......................... 38 Vice President, Operations Matthew Deso............................. 43 Vice President, Exploration
- --------------- (1) Member of the Audit Committee. (2) Member of the Compensation Committee. (3) Member of the Stock Option Plan Committee. (4) Member of the Stock Purchase Plan Committee. Directors Ronald G. Greene - Chairman of the Board, 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 CEO 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. William S. Price, III has been a director of the Company since 1995. Mr. Price is a co-founder and principal of the Texas Pacific Group, a private investment firm that specializes in corporate acquisitions in a wide range of industries. Prior to forming the Texas Pacific Group 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 also serves on the Board of Directors of Continental Airlines, Inc., Continental Micronesia, Inc., PPOM, LP., and Vivra Heart Services. David M. Stanton has been a director of the Company since 1995. Mr. Stanton is a managing director of the Texas Pacific Group, a private investment firm that specializes in corporate acquisitions in a wide range of industries. From 1991 until he joined the Texas Pacific Group in 1994, Mr. Stanton was a venture capitalist with Trinity Ventures where he specialized in information technology, software and telecommunications investments. Wieland F. Wettstein has been a director of the Company since 1990. Mr. Wettstein is the Executive Vice-President 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 two public oil and natural gas companies, BXL Energy and Attock Energy Corporation, and on the boards of a private technology firm and a private gas marketing company. David Bonderman became a director of the Company in May, 1996. Mr. Bonderman is a co-founder and principal of the Texas Pacific Group, a private investment firm that specializes in corporate acquisitions in a 44 47 wide range of industries. Prior to forming the Texas Pacific Group 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 is an honor graduate from Harvard Law School and serves on the boards of Continental Airlines, Inc., PPOM, L.P., American Savings Bank, Bell & Howell Company, National Reinsurance and Virgin Cinemas Limited. Mr. Bonderman also serves in general partner advisory board roles for Acadia Partners, Colony Investors and Newbridge Investment Partners. Executive Officers Gareth Roberts - President, Chief Executive Officer and Director, is the founder and President of Denbury Management, Inc. 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. 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 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. Matthew Deso - Vice President, Exploration, has been with Denbury Management, Inc. since October 1990, first as a consultant then, when he moved to Dallas in January 1994, as Vice President of Exploration. 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. Mark A. Worthey - Vice President, Operations, is a geologist and is responsible for all aspects of operations in the field. He joined Denbury Management, Inc. 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. As part of the Securities Purchase Agreement that governed the TPG Placement, 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, on a fully-diluted basis, represent less than 20% of the outstanding Common Shares. Currently, Mr. David M. Stanton, Mr. David Bonderman and Mr. William S. Price, III are directors of the Company nominated by TPG. The Company currently has a vacancy on its Board of Directors caused by the resignation of Mr. Martin Fortier on August 30, 1996. If replaced, this vacancy will be filled by a non-TPG nominee. COMPENSATION OF DIRECTORS AND OFFICERS The following table sets forth certain summary information regarding compensation paid or accrued by the Company to or on behalf of the Company's Chief Executive Officer and each of the other three most highly compensated executive officers ("Named Executive Officers") of the Company (determined as of December 31, 1995) for the fiscal years ended December 31, 1993, 1994 and 1995. 45 48 The Company reimburses the directors of the Company for out-of-pocket traveling expenses in connection with each board meeting attended. There are no other arrangements in respect of which directors of the Company receive monetary compensation for acting in that capacity.
LONG-TERM ANNUAL -------------------- COMPENSATION(1) COMMON SHARES -------------------- UNDERLYING NAME AND PRINCIPAL POSITION YEAR SALARY BONUSES OPTION/SARS GRANTED - ----------------------------------------------- ---- -------- -------- -------------------- Gareth Roberts................................. 1995 $150,000 $ 3,410 -- President and Chief Executive Officer 1994 150,000 -- -- 1993 150,000 6,000 55,500 Phil Rykhoek................................... 1995 $ 55,682 $ 1,923 50,000 Chief Financial Officer and Secretary(2) 1994 -- -- -- 1993 -- -- -- Mark A. Worthey................................ 1995 $100,000 $ 1,923 -- Vice President, Operations 1994 89,000 4,000 5,000 Denbury Management, Inc. 1993 89,000 4,000 89,250 Matthew Deso................................... 1995 $100,000 $ 1,923 5,000 Vice President, Exploration 1994 89,000 4,000 12,500 Denbury Management, Inc.(3) 1993 55,000 4,000 55,000
- --------------- (1) The aggregate amount of all other annual compensation as defined by applicable securities regulations was not greater than the lesser of $50,000 or 10% of the total annual salary and bonus of each Named Executive Officer for each financial year. (2) Mr. Rykhoek joined Denbury in June 1995. (3) Mr. Deso joined Denbury in April 1993. STOCK OPTIONS The Company has an employee stock option plan (the "Plan") pursuant to which stock options may be granted to full and part-time employees, officers and directors of the Company and its subsidiaries, from time to time, as the board of directors of the Company may determine. The Plan allows the granting of either non-qualified or incentive stock options. Under the terms of the Plan, the number of Common Shares reserved for issuance may not exceed 1,050,000 Common Shares. The term of options granted under the Plan are determined by the board of directors provided that no option may be granted for a period that exceeds 10 years from the date of the grant, or such lesser period of time as permitted, from time to time, by the applicable rules of the TSE. The purchase price of any shares subject to options under the Plan is fixed by the board of directors, but may not be less than the greater of the two average closing trading prices for the ten trading days preceding the date of grant as reported on the TSE and NASDAQ. All option agreements granted under the Plan must be in accordance with the policies and procedures of the TSE and NASDAQ. At a meeting of the Board of Directors of the Company on May 16, 1996, the Plan was amended to increase the number of options authorized to be issued under the Plan to 1,250,000. This amendment is subject to shareholder and regulatory approval. As of August 31, 1996, options outstanding pursuant to the Plan were comprised of incentive stock options covering 634,000 Common Shares held by one officer/director, three officers and 33 employees and non-qualified stock options covering 435,250 Common Shares held by two directors, one officer/director, three officers, 14 employees and one former employee. These options are exercisable at prices ranging from $3.66 to $11.36, with a weighted average price of $7.56. Of the total outstanding options, 485,000 were currently exercisable as of August 31, 1996. From January 1, 1996 through August 31, 1996, the Company granted 516,500 options. 46 49 OPTION GRANTS IN LAST FISCAL YEAR The following table represents the options granted to the Named Executive Officers during 1995 and the value of such options:
POTENTIAL REALIZABLE VALUE AT ASSUMED ANNUAL INDIVIDUAL GRANTS RATES OF ------------------------------------------------------ STOCK PRICE NUMBER OF % OF APPRECIATION FOR SECURITIES TOTAL OPTIONS EXERCISE OPTION UNDERLYING GRANTED TO OR BASE TERM(2) OPTIONS EMPLOYEES IN PRICE EXPIRATION ------------------- NAME GRANTED(#) FISCAL YEAR ($/SH)(1) DATE 5%($) 10%($) - --------------------------- ---------- ------------- --------- ---------- ------- -------- Gareth Roberts............. -- -- -- -- -- -- Phil Rykhoek............... 25,000(3) 9% $6.08 6/22/00 $41,954 $ 92,707 25,000(4) 9% 6.02 8/18/05 94,800 240,242 Mark A. Worthey............ -- -- -- -- -- -- Matthew Deso............... 5,000(3) 2% 5.92 1/3/00 8,186 18,089
- --------------- (1) These options are denominated in Canadian dollars and are converted to U.S. dollars for this table using an exchange rate of Cdn. $1.35 = U.S. $1.00. (2) Calculated based on the fair market value of the Common Shares on the date of grant. The amounts represent only certain assumed compounded annual rates of appreciation. Actual gains, if any, on stock option exercises and Common Share holdings cannot be predicted, and there can be no assurance that the gains set forth in the table will be achieved. A conversion exchange rate of Cdn. $1.35 = U.S. $1.00 was assumed in the calculation. (3) The options vest in installments of 50% on the date of grant and 50% one year from the date of grant. (4) The options vest in installments of 25% six months from the date of grant, 25% one year from the date of grant, 25% two years from the date of grant, and 25% three years from the date of grant. OPTION EXERCISES AND HOLDINGS The following table sets forth information with respect to the Named Executive Officers concerning unexercised options held as of December 31, 1995. None of the Named Executive Officers exercised any options during 1995. During 1996, the Named Executive Officers exercised a total of 28,750 options. AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION VALUES
VALUE OF UNEXERCISED IN-THE NUMBER OF UNEXERCISED MONEY OPTIONS AT OPTIONS AT FISCAL FISCAL YEAR-END YEAR-END(1) ---------------------------- ---------------------------- EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE ----------- ------------- ----------- ------------- Gareth Roberts................................ 27,750 -- $21,326 $ -- Phil Rykhoek.................................. 12,500 37,500 2,199 7,708 Mark A. Worthey............................... 73,250 -- 1,620 -- Matthew Deso.................................. 60,000 2,500 4,861 810
- --------------- (1) Based on the closing sale price of the Common Shares on December 21, 1995, the last day prior to December 31, 1995 in which there was trading activity, of $6.25 per share as reported by NASDAQ. A conversion exchange rate of Cdn. $1.35 = U.S. $1.00 was assumed in the calculation as the options are denominated in Canadian dollars. 47 50 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, 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. FINANCIAL ADVISORY FEE In October 1993, the Company paid a management fee of $75,000 to Finex Financial Corporation Ltd. a Company indirectly controlled by Mr. Martin G. Fortier, a then director of the Company, and Mr. Wieland F. Wettstein, a director of the Company, for services rendered and assistance provided in raising equity and in the sale of its Canadian operations. TPG PLACEMENT In December 1995, the Company closed a $40.0 million private placement of securities with partnerships that are affiliated with TPG. 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 holder to purchase 625,000 Common Shares at $7.40 per share; and (iii) 1.5 million shares of $10 stated value Convertible Preferred. The Convertible Preferred shares are initially convertible at $7.40 of stated value per Common Share with such conversion rate declining 2.5% per quarter. The Convertible Preferred do not have any cash or other stated dividend requirement. The Convertible Preferred have a mandatory redemption at a 63.86% premium at December 21, 2000, but also originally provided that the Company can cause a mandatory conversion after January 1, 1999 if the price of the Common Stock exceeds $10.00 per share for a period of 40 consecutive trading days. The Company will present to the shareholders for approval at a Special Meeting on October 9, 1996 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. See "-- Modification of Convertible Preferred and Debentures." The Company may also force conversion of the warrants after December 21, 1997, if the price of the Common Stock exceeds $10.00 per share for a period of 40 consecutive trading days. As of August 31, 1996, TPG is the beneficial owner of 7,608,038 Common Shares, which represents 48.4% of the outstanding Common Shares prior to the Offerings. See "Security Ownership of Certain Beneficial Owners and Management." In connection with the TPG Placement, TPG received the right to nominate three of the seven directors of the Company. See "Management -- Executive Officers and Directors." In addition, for a period of two years TPG has 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 that period. Beginning 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 (after the assumed exercise of its warrants and Convertible Preferred) 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. This right, however, expires should TPG's share holdings represent less than 20% of the outstanding Common Shares. TPG has waived its registration rights and its right to maintain its pro rata ownership with regard to the Public Offering. 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. Mr. Greene was not a director of 48 51 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. TPG OFFERING Concurrent with the Public Offering, the Company will sell an additional 800,000 Common Shares to TPG at the price to the public per share less the underwriting discounts and commissions. See "Concurrent Offerings." MODIFICATION OF CONVERTIBLE PREFERRED AND DEBENTURES In order to position the Company for the Public Offering, the Board of Directors and its financial advisors determined that it was in the best interests of the Company to: (i) increase the market price per Common Share to levels significantly above U.S. $5.00, the level below which certain stocks are subject to the penny stock rules; (ii) simplify the capital structure of the Company; and (iii) reduce the overhang that exists as a result of existing convertible securities. The Board of Directors believe that these goals would be best achieved by taking the following actions: (i) consolidating the number of Common Shares through a one-for-two reverse split of the Common Shares; (ii) modifying the terms of the Convertible Preferred such that the Convertible Preferred may be converted to Common Shares at the election of the Company prior to January 1, 1999; and (iii) issuing Common Shares in lieu of interest to the holders of the Debentures in order to induce such holders to convert to Common Shares prior to the mandatory redemption date. Accordingly, the Company has called a Special Meeting of the shareholders of the Company to be held on October 9, 1996 to consider resolutions to effect the foregoing. If the resolution regarding the Convertible Preferred is approved by the shareholders and subject to, and simultaneously with, the completion of the Offerings, the Company plans to require a conversion, thereby increasing the number of Common Shares of the Company by 2,816,373 and eliminating the outstanding Convertible Preferred. TPG, which currently owns 35% of the outstanding Common Shares, is the sole holder of the Convertible Preferred. If the resolution regarding the Debentures is approved, the Company would issue a total of 7,958 Common Shares in lieu of interest, assuming an approval date and conversion as of October 15, 1996, plus an additional 308,642 Common Shares for the principal amount in accordance with the existing terms of the Debentures. Mr. Ronald G. Greene, Chairman of the Board of Directors, owns 80% of the Debentures which were purchased by him at market value prior to his election to the Board of Directors. Mr. Greene also purchased Cdn. $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 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 using a 15% discount rate. The acquisition was 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. 49 52 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table sets forth information, as of August 31, 1996, concerning beneficial ownership of the Common Shares by: (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 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 shares.
BENEFICIAL BENEFICIAL OWNERSHIP PRIOR OWNERSHIP AFTER TO OFFERINGS OFFERINGS(1) NAME AND ADDRESS OF ----------------------- --------------- BENEFICIAL OWNER SHARES PERCENT PERCENT - ----------------------------------------------------- --------- ------- --------------- Ronald G. Greene..................................... 869,917(2) 5.8%(2) 4.5%(2) Suite 700, 407 -- 2nd Street Calgary, Alberta T2P 2Y3 David Bonderman...................................... 7,608,038(3) 48.4%(3) 41.8%(3) 201 Main Street, Suite 2420 Ft. Worth, TX 76102 William S. Price, III................................ 7,608,038(3) 48.4%(3) 41.8%(3) 600 California Street, Suite 1850 San Francisco, CA 94108 David M. Stanton..................................... --(4) * * Wieland F. Wettstein................................. 161,414(5) 1.1%(5) * Gareth Roberts....................................... 514,239(6) 3.4%(6) 2.6%(6) Phil Rykhoek......................................... 13,818(7) * * Mark A. Worthey...................................... 76,369(7) * * Matthew Deso......................................... 66,569(7) * * All of the executive officers and directors as a group (9 persons).................................. 9,310,364(8) 58.6%(8) 49.8%(8) TPG Advisors, Inc.................................... 7,608,038(3) 48.4%(3) 41.8%(3) 201 Main Street, Suite 2420 Ft. Worth, TX 76102
- --------------- * Less than 1%. (1) After giving effect to the issuance of an aggregate of 4,400,000 Common Shares in the Offerings. (2) After giving effect to the pro forma conversion of Cdn. $2,000,000 of the 9 1/2% Convertible Debentures into 257,059 Common Shares assuming a conversion date of June 30, 1996. Includes 30,150 Common Shares held by Mr. Greene's spouse in her retirement plan and 520,833 Common Shares held by Tortuga Investment Corp., which is solely owned by Mr. Greene. (3) After giving effect to: (i) the pro forma conversion of the 1,500,000 Convertible Preferred into 2,816,372 Common Shares, and (ii) the pro forma exercise of the 625,000 Common Share purchase warrants. Neither Mr. Bonderman, Mr. Price nor TPG Advisors, Inc. are the owner of record of any securities of the Company. However, Mr. Bonderman and Mr. Price 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 Offerings," includes 800,000 Common Shares which the Company will sell to TPG as part of the TPG Offering. (4) Although Mr. Stanton is not considered to be a "beneficial owner" as that term is defined by the Securities and Exchange Commission, Mr. Stanton is a managing director of TPG Partners, L.P. 50 53 (5) After giving effect to the pro forma exercise of the 18,000 Common Shares which Mr. Wettstein has the right to acquire pursuant to vested stock options. Also includes 110,489 Common Shares held by S.P. Hunt Holdings Ltd., which is solely owned by a trust of which Mr. Wettstein is a trustee, and 19,600 Common Shares owned by his spouse. (6) After giving effect to the pro forma exercise of the 27,750 Common Shares which Mr. Roberts has the right to acquire pursuant to vested stock options. Also includes 138,330 Common Shares held by Ashley Petroleum, Inc., which is solely owned by Mr. Roberts, and 1,426 Common Shares held by his wife. (7) After giving effect to the pro forma exercise, as applicable, of the 13,438, 73,250 and 62,500 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 the next sixty days. (8) After giving effect to: (i) the pro forma conversion of Cdn. $2,000,000 of the 9 1/2% Convertible Debentures into 257,059 Common Shares, (ii) the pro forma conversion of the 1,500,000 Convertible Preferred into 2,816,372 Common Shares, (iii) the pro forma exercise of the 625,000 Common Share purchase warrants, and (iv) the pro forma exercise of the 194,938 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 the next sixty days. Ownership does include the shares held by 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 same securities. The "Beneficial Ownership after Offerings," includes 800,000 Common Shares which the Company will sell to TPG as part of the TPG Offering. DESCRIPTION OF CAPITAL STOCK GENERAL The authorized share capital of Denbury consists of an unlimited number of Common Shares, of which 11,941,390 were issued and outstanding as of August 31, 1996, and two classes of preferred shares, unlimited in number and issuable in series, none of which will be outstanding after the completion of the Offerings. In addition to the issued and outstanding Common Shares, options to purchase Common Shares and other forms of convertible securities for Common Shares are outstanding. There are no limitations imposed by Canadian legislation or regulations or by the Articles of Continuance or Bylaws of the Company 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 to one vote for each Common Share held at all meetings of shareholders of the Company, 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; are entitled to any dividends that may be declared by the board of directors thereon; and in the event of liquidation, dissolution or winding-up of the Company, are entitled, subject to the rights of the holders of shares ranking prior to the Common Shares, to share rateably in such assets of the Company as are available for distribution. The holders of Common Shares have no pre-emptive rights under Canadian law or the Articles of Continuance. At August 31, 1995, 75,000 warrants were outstanding at an exercise price of Cdn. $8.40 expiring on May 5, 2000 and 625,000 warrants were outstanding at an exercise price of U.S. $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. The Company has the option after December 21, 1997 to require exercise of the 51 54 625,000 warrants if the weighted average trading price of the Common Stock exceeds $10.00 per share for a period of 40 consecutive trading days. The Company 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 150,000 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. The Company has granted TPG certain demand and "piggyback" 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 "piggyback" registration rights and preemptive rights in connection with the Public Offering. Concurrent with the Public Offering, the Company will sell an additional 800,000 Common Shares to TPG at the price to the public per share less underwriting discounts and commissions. See "Concurrent Offerings." PREFERRED SHARES The Company'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 the Company'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 the Company 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. As of the close of the Offerings, no Preferred Shares will be outstanding. For a description of the currently outstanding Convertible Preferred, see "Interests of Management in Certain Transactions." 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 52 55 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 base of the Common Shares, must be included in income as a taxable capital gain, to be taxed at prevailing federal Canadian rates, which range from approximately 26% to 39%. 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 of. Pursuant to the U.S. -- Canada Income Tax Convention (the "Convention"), shareholders of the Company who are resident in the U.S. for the purposes of the Convention and whose shares might 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. DIVIDENDS Under the Act, 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 6% for dividends received in 1996 and 5% thereafter 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. 53 56 SHARES ELIGIBLE FOR FUTURE SALE After giving effect to the Offerings and the Capitalization Adjustments, the Company would have had 19,479,090 Common Shares outstanding as of August 31, 1996 (20,019,090 shares assuming exercise of the Underwriters' over-allotment option in full). The Common Shares sold in the Public Offering will be freely tradable without restrictions or further registration under the Securities Act. 7,608,038 of the 8,408,038 Common Shares beneficially held by TPG as of the close of the Offerings will be "restricted" securities within the meaning of the Securities Act as a result of the issuance thereof in a private transaction. 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 those provided by Rule 144 promulgated under the Securities Act. 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 two years, 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 (approximately 194,791 shares immediately after the Offerings). 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 three years, would be entitled to sell such shares under Rule 144 without regard to the volume limitations described above. The Company believes that 7,608,038 shares owned by TPG will be eligible for sale in the public market pursuant to Rule 144 after December 21, 1997, and the remaining shares beneficially held by TPG will be eligible for sale in the public market pursuant to Rule 144 immediately upon close of the TPG Offering. The Company is unable to estimate the number of 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 Public 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 shares 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 Donaldson, Lufkin & Jenrette Securities Corporation. See "Underwriting." 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 "piggyback" registration rights and preemptive rights in connection with the Public 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. 54 57 UNDERWRITING Subject to the terms and conditions contained in an underwriting agreement (the "Underwriting Agreement"), a syndicate of underwriters named below (the "Underwriters"), for whom Donaldson, Lufkin & Jenrette Securities Corporation, Prudential Securities Incorporated and Johnson Rice & Company L.L.C., are acting as representatives (the "Representatives"), have severally agreed to purchase 3,600,000 Common Shares from the Company. The number of Common Shares that each Underwriter have severally agreed to purchase is set forth opposite its name below:
NUMBER UNDERWRITERS OF SHARES - --------------------------------------------------------------------------------- ----------- Donaldson, Lufkin & Jenrette Securities Corporation.............................. Prudential Securities Incorporated............................................... Johnson Rice & Company L.L.C..................................................... ---------- Total.................................................................. 3,600,000 ==========
The Underwriting Agreement provides that the obligation of the several Underwriters to pay for and accept delivery of the Common Shares are subject to certain 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 the 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 $ per share. The Underwriters may allow, and such dealers may re-allow, a discount not in excess of $ per share to any other Underwriter and certain other dealers. The Company has granted to the Underwriters an option to purchase up to 540,000 additional Common Shares at the public offering price 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 option shares proportionate to such Underwriter's initial commitment as indicated in the preceding table. The Company, each of its directors and executive officers and TPG, subject to certain exceptions, have agreed not to offer, sell or otherwise dispose of any Common Shares, or any shares exercisable for or convertible into Common Shares, prior to the expiration of 120 days from the date of this Prospectus, without the prior written consent of Donaldson, Lufkin & Jenrette Securities Corporation on behalf of the Underwriters. The Company has agreed to indemnify the Underwriters against certain liabilities, including liabilities under the Securities Act or to contribute to payments that the Underwriters may be required to make in respect thereof. In connection with the Public Offering, certain Underwriters may engage in passive market making transactions in the Common Shares on the Nasdaq National Market immediately prior to the commencement of sales in the offering made hereby, in accordance with Rule 10b-6A under the Securities Exchange Act of 1934, as amended. Passive market making consists of displaying bids on the Nasdaq National Market limited 55 58 by the bid prices of independent market makers and purchases limited by such prices and effected in response to order flow. Net purchases by a passive market maker on each day are limited to a specified percentage of the passive market maker's average daily trading volume in the Common Shares during a specified prior period and must be discontinued when such limit is reached. Passive market making may stabilize the market price of the Common Shares at a level above that which might otherwise prevail and, if commenced, may be discontinued at any time. PLAN OF DISTRIBUTION FOR THE TPG OFFERING Pursuant to a Stock Purchase Agreement (the "Stock Purchase Agreement") entered into by TPG and the Company, TPG has irrevocably agreed to purchase 800,000 Common Shares at a price, subject to approval by Canadian regulatory authorities, equal to the price to the public per share in the Public Offering less the underwriting discounts and commissions. Pursuant to the Stock Purchase Agreement, TPG has represented and warranted that the execution, delivery and performance of the Stock Purchase Agreement by it has been duly and validly authorized by all necessary actions and that the Stock Purchase Agreement is the legal, valid and binding obligation of TPG. The Company has represented that the execution, delivery and performance of the Stock Purchase Agreement by it has been duly and validly authorized by all necessary corporate actions and that the Stock Purchase Agreement is the legal, valid and binding obligation of the Company. The TPG Offering is being made directly by the Company to TPG. The TPG Offering is not being made on an underwritten basis, and the Underwriters of the Public Offering are not acting on behalf of the Company, as agents or in any other capacity, in connection therewith. The closing of the purchase of Common Shares pursuant to the Stock Purchase Agreement is conditioned upon, and will occur concurrently with, the closing of the Public Offering. SERVICE AND ENFORCEMENT OF LEGAL PROCESS The Company is incorporated under the laws of Canada. Some of the directors, controlling persons and officers of the Company, 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 the 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 the Company predicated upon civil liability under the United States federal securities laws. The Company has been advised by its counsel, Burnet, Duckworth & Palmer, Calgary, Alberta, that there is doubt as to the enforceability in Canada against the Company 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. LEGAL MATTERS The legality of the Common Shares offered hereby have been passed upon for the Company by Burnet, Duckworth & Palmer, Calgary, Alberta and Jenkens & Gilchrist, a Professional Corporation, Houston, Texas. Certain matters in connection with the Public Offering will be passed upon for the Underwriters by Baker & Botts, L.L.P., Dallas, Texas. 56 59 EXPERTS The consolidated financial statements and financial statement schedule of the Company for each of the three years ended December 31, 1995 and the statements of revenues and direct operating expenses attributable to certain oil and natural gas properties (Ottawa Properties) acquired by the Company for the year ended December 31, 1995 included 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 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 attributable to certain oil and natural gas properties (Amerada Hess Properties) acquired by the Company for the years ended December 31, 1995, 1994 and 1993 included in this Prospectus and Registration Statement have been audited by Deloitte & Touche LLP, independent auditors, as stated in their report appearing herein and have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing. The reference to the reports of Netherland, Sewell & Associates, Inc. and The Scotia Group, Inc., both 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 Securities Exchange Act of 1934, as amended, and in accordance therewith files reports, proxy statements and other information with the Securities and Exchange Commission (the "SEC"). Such reports, proxy statements and other information can be inspected and copied at the public reference facilities maintained by the SEC at 450 5th Street, N.W., Room 1024, Washington, D.C. 20549, and at the following regional offices of the SEC: 7 World Trade Center, 13th Floor, New York, New York 10048 and Northwestern Atrium 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 Company's Common Stock is traded on the Nasdaq National Market and such reports, proxy statements and other information may be inspected at the Nasdaq Stock Market, 1735 K Street, N.W., Washington, D.C. 20006. The Company has filed with the SEC a Registration Statement on Form S-1 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 SEC. 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 SEC. 57 60 GLOSSARY The terms defined in this section are used throughout this Prospectus. ADJUSTED EBITDA. Adjusted 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. 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. CDN. Canadian. 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. DEVELOPED ACREAGE. The number of acres which are allocated or assignable to producing wells or wells capable of production. 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 in 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. 58 61 MBTU. One thousand Btus. MCF. One thousand cubic feet of natural gas. MCF/D. One thousand cubic of natural gas produced per day. MMBBL. One million barrels of crude oil or other liquid hydrocarbons. MMBOE. One million BOEs. 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 using an annual discount rate of 10% in accordance with the guidelines of the SEC. 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 through existing wells with existing equipment and operating methods. PROVED RESERVES. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. PROVED UNDEVELOPED RESERVES. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. 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 operating interest which gives the owner the right to drill, produce and conduct operating activities on the property as well as to a share of production. 59 62 INDEX TO FINANCIAL STATEMENTS AND SCHEDULES YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993 SIX MONTHS ENDED JUNE 30, 1996 AND 1995 (UNAUDITED)
PAGE ---------------- 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 the Consolidated Financial Statements.............................. F-7 thru F-23 Statement of Revenues and Direct Operating Expenses of Ottawa Properties Independent Auditors' Report.............................................. F-24 Statement of Revenues and Direct Operating Expenses....................... F-25 Notes to Statement of Revenues and Direct Operating Expenses.............. F-26 thru F-27 Statements of Revenues and Direct Operating Expenses of Amerada Hess Properties Independent Auditors' Report.............................................. F-28 Statements of Revenues and Direct Operating Expenses...................... F-29 Notes to Statements of Revenues and Direct Operating Expenses............. F-30 thru F-32
F-1 63 INDEPENDENT AUDITORS' REPORT To the Shareholders of Denbury Resources Inc. (formerly Newscope Resources Ltd.) We have audited the consolidated balance sheets of Denbury Resources Inc. (formerly Newscope Resources Ltd.) as at December 31, 1995 and 1994 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, 1995. 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 1994 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, 1995, in accordance with accounting principles generally accepted in Canada. DELOITTE & TOUCHE Chartered Accountants Calgary, Alberta February 23, 1996 F-2 64 DENBURY RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (AMOUNTS IN THOUSANDS OF U.S. DOLLARS) ASSETS
DECEMBER 31, -------------------- JUNE 30, 1994 1995 1996 -------- -------- ----------- (UNAUDITED) CURRENT ASSETS Cash and cash equivalents.................................. $ 712 $ 6,553 $ 3,085 Accrued production receivable.............................. 1,909 3,212 6,307 Trade and other receivables................................ 993 1,160 2,837 ------- -------- -------- Total current assets............................... 3,614 10,925 12,229 ------- -------- -------- PROPERTY AND EQUIPMENT (USING FULL COST ACCOUNTING) Oil and natural gas properties............................. 44,820 72,510 133,442 Unevaluated oil and natural gas properties................. 6,251 7,085 6,571 Less accumulated depreciation and depletion................ (6,149) (13,982) (21,140) ------- -------- -------- Net property and equipment......................... 44,922 65,613 118,873 ------- -------- -------- OTHER ASSETS................................................. 428 1,103 1,798 ------- -------- -------- TOTAL ASSETS....................................... $48,964 $ 77,641 $132,900 ======= ======== ======== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable and accrued liabilities................... $ 5,056 $ 3,886 $ 13,288 Current portion of long-term debt.......................... 178 177 125 ------- -------- -------- Total current liabilities.......................... 5,234 4,063 13,413 ------- -------- -------- LONG-TERM LIABILITIES Senior bank debt........................................... 14,950 75 40,000 Subordinated debt and other notes payable.................. 1,586 3,399 2,964 Provision for site reclamation costs....................... 138 242 340 Deferred income taxes and other............................ 1,094 1,361 3,166 ------- -------- -------- Total long-term liabilities........................ 17,768 5,077 46,470 ------- -------- -------- CONVERTIBLE FIRST PREFERRED SHARES, SERIES A 1,500,000 shares authorized, issued and outstanding at December 31, 1995.................................... -- 15,000 15,759 ------- -------- -------- SHAREHOLDERS' EQUITY Common shares, no par value unlimited shares authorized; outstanding -- 12,609,335, 22,857,619 and 23,264,430 shares at December 31, 1994, December 31, 1995 and June 30, 1996, respectively.................................. 23,239 50,064 51,226 Retained earnings.......................................... 2,723 3,437 6,032 ------- -------- -------- Total shareholders' equity.............................. 25,962 53,501 57,258 ------- -------- -------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY......... $48,964 $ 77,641 $132,900 ======= ======== ========
See Notes to Consolidated Financial Statements. Approved by the Board: /s/ Gareth Roberts /s/ Wieland F. Wettstein ----------------------------------- ----------------------------------- Gareth Roberts Wieland F. Wettstein Director
F-3 65 DENBURY RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS) (U.S. DOLLARS)
SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, ----------------------------- ------------------ 1993 1994 1995 1995 1996 ------- ------- ------- ------- ------- (UNAUDITED) REVENUES Oil, natural gas and related product sales.................................... $5,868 $12,692 $20,032 $8,997 $20,650 Interest income............................. 76 23 77 21 124 ------ ------- ------- ------ ------- Total revenues........................... 5,944 12,715 20,109 9,018 20,774 ------ ------- ------- ------ ------- EXPENSES Production.................................. 2,067 4,309 6,789 3,128 5,350 General and administrative.................. 782 1,105 1,832 935 1,656 Interest.................................... 83 1,146 2,085 927 681 Imputed preferred dividends................. -- -- -- -- 759 Loss on early extinguishment of debt........ -- -- 200 200 440 Depletion and depreciation.................. 1,898 4,209 8,022 3,075 7,382 Franchise taxes............................. -- 65 100 42 107 ------ ------- ------- ------ ------- Total expenses...................... 4,830 10,834 19,028 8,307 16,375 ------ ------- ------- ------ ------- Income before the following: 1,114 1,881 1,081 711 4,399 Gain on sale of Canadian properties......... 966 -- -- -- -- ------ ------- ------- ------ ------- Income before income taxes.................... 2,080 1,881 1,081 711 4,399 Provision for federal income taxes............ (345) (718) (367) (242) (1,804) ------ ------- ------- ------ ------- NET INCOME.................................... $1,735 $ 1,163 $ 714 $ 469 $ 2,595 ====== ======= ======= ====== ======= NET INCOME PER COMMON SHARE................... $ 0.17 $ 0.09 $ 0.05 $ 0.04 $ 0.11 ====== ======= ======= ====== ======= Average number of common shares outstanding... 9,980 12,480 13,739 13,071 23,024 ====== ======= ======= ====== =======
See Notes to Consolidated Financial Statements F-4 66 DENBURY RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (AMOUNTS IN THOUSANDS OF U.S. DOLLARS)
SIX MONTHS YEAR ENDED DECEMBER 31, ENDED JUNE 30, -------------------------------- -------------------- 1993 1994 1995 1995 1996 -------- -------- -------- -------- -------- (UNAUDITED) CASH FLOW FROM OPERATING ACTIVITIES: Net income............................ $ 1,735 $ 1,163 $ 714 $ 469 $ 2,595 Adjustments needed to reconcile to net cash flow provided by operations: Depreciation, depletion and amortization..................... 1,916 4,304 8,113 3,075 7,382 Deferred income taxes.............. 345 718 367 242 1,804 Gain on sale of Canadian properties....................... (966) -- -- -- -- Imputed preferred dividend......... -- -- -- -- 759 Loss on early extinguishment of debt............................. -- -- 200 200 440 Other.............................. -- -- -- 39 323 -------- -------- -------- -------- -------- 3,030 6,185 9,394 4,025 13,303 Changes in working capital items relating to operations: Accrued production receivable...... (586) (986) (1,303) (481) (3,096) Trade and other receivables........ (260) (124) (168) (261) (702) Accounts payable and accrued liabilities...................... 2,742 1,842 (1,170) (664) 8,082 -------- -------- -------- -------- -------- NET CASH FLOW PROVIDED BY OPERATIONS.... 4,926 6,917 6,753 2,619 17,587 -------- -------- -------- -------- -------- CASH FLOW USED FOR INVESTING ACTIVITIES: Oil and natural gas expenditures... (9,779) (10,297) (11,761) (4,001) (12,759) Acquisition of oil and natural gas properties....................... (20,076) (6,606) (16,763) (6,505) (47,974) Proceeds on disposal of Canadian properties....................... 3,129 -- -- -- -- Net purchases of other assets...... (157) (122) (560) (227) (754) Acquisition of subsidiary, net of cash acquired.................... -- -- -- -- 209 -------- -------- -------- -------- -------- NET CASH USED FOR INVESTING ACTIVITIES............................ (26,883) (17,025) (29,084) (10,733) (61,278) -------- -------- -------- -------- -------- CASH FLOW FROM FINANCING ACTIVITIES: Bank borrowings.................... 7,600 9,835 19,350 5,750 39,900 Bank repayments.................... -- (2,485) (34,200) (2,100) -- Issuance of subordinated debt...... -- 1,451 1,772 1,772 -- Issuance of common stock........... 15,148 367 26,825 2,460 796 Issuance of preferred stock........ -- -- 15,000 -- -- Costs of debt financing............ (251) (122) (493) (269) (378) Other.............................. 277 62 (82) (36) (95) -------- -------- -------- -------- -------- NET CASH PROVIDED BY FINANCING ACTIVITIES............................ 22,774 9,108 28,172 7,577 40,223 -------- -------- -------- -------- -------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........................... 817 (1,000) 5,841 (537) (3,468) Cash and cash equivalents at beginning of year............................... 895 1,712 712 712 6,553 -------- -------- -------- -------- -------- CASH AND CASH EQUIVALENTS AT END OF PERIOD................................ $ 1,712 $ 712 $ 6,553 $ 175 $ 3,085 ======== ======== ======== ======== ======== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for interest......................... $ 64 $ 1,027 $ 2,127 $ 1,009 $ 271 SUPPLEMENTAL DISCLOSURE OF FINANCING ACTIVITIES: Conversion of subordinated debt to common stock..................... -- -- -- -- $ 366 Assumption of liabilities in acquisition...................... -- -- -- -- 1,321
See Notes to Consolidated Financial Statements F-5 67 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, 1993........................... 7,579,460 $ 7,724 $ (175) $ 7,549 Issued pursuant to employee stock option plan........ 552,375 1,033 -- 1,033 Private placement of Special Warrants exchanged...... 1,885,000 5,866 -- 5,866 Private placement of Special Warrants exchanged...... 1,000,000 4,356 -- 4,356 Private placement of Special Warrants exchanged...... 1,400,000 3,893 -- 3,893 Net income........................................... -- -- 1,735 1,735 ---------- ------- ------ ------- BALANCE -- DECEMBER 31, 1993......................... 12,416,835 22,872 1,560 24,432 ---------- ------- ------ ------- Issued pursuant to employee stock option plan........ 192,500 367 -- 367 Net income........................................... -- -- 1,163 1,163 ---------- ------- ------ ------- BALANCE -- DECEMBER 31, 1994......................... 12,609,335 23,239 2,723 25,962 ---------- ------- ------ ------- Issued pursuant to employee stock option plan........ 20,000 54 -- 54 Private placement of Special Warrants exchanged...... 1,228,285 2,314 -- 2,314 Private placement of common shares................... 8,999,999 24,457 -- 24,457 Net income........................................... -- -- 714 714 ---------- ------- ------ ------- BALANCE -- DECEMBER 31, 1995......................... 22,857,619 50,064 3,437 53,501 ---------- ------- ------ ------- (Unaudited) Issued pursuant to employee stock option plan........ 251,500 656 -- 656 Issued pursuant to employee stock purchase plan...... 30,311 140 -- 140 Conversion of subordinated debt...................... 125,000 366 -- 366 Net income........................................... -- -- 2,595 2,595 ---------- ------- ------ ------- BALANCE -- JUNE 30, 1996 (UNAUDITED)................. 23,264,430 $51,226 $6,032 $57,258 ========== ======= ====== =======
See Notes to Consolidated Financial Statements F-6 68 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1993, 1994 AND 1995 AND FOR THE SIX MONTHS ENDED JUNE 30, 1995 AND 1996 (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. 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, Brymore Energy Corporation ("Brymore"). The Company acquired the remaining 50% of Brymore effective May 1, 1996 and began consolidating all of Brymore as of that date. 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 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. d) Ceiling test The capitalized costs less accumulated depletion, depreciation and deferred taxes 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 F-7 69 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 is 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. The stock options, warrants, convertible debt and the conversion of the Convertible First Preferred Shares, Series A ("Convertible Preferred") were anti-dilutive or immaterial and were not included in the calculation of earnings per share. 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 original maturities 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, 1994 and 1995 and June 30, 1996, the Company's aggregate oil and natural gas imbalances were not material to its financial statements. 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 F-8 70 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. 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 financial position as of June 30, 1996, and the results of operations and changes in financial position for the six months ended June 30, 1995 and 1996. 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 summary of the unevaluated properties excluded from oil and natural gas properties being amortized at December 31, 1994 and 1995 and June 30, 1996 and the year in which they were incurred follows:
DECEMBER 31, 1994 DECEMBER 31, 1995 ---------------------------------- ------------------------------------ INCURRED IN INCURRED IN ------------------------ -------------------------- 1992 1993 1994 TOTAL 1993 1994 1995 TOTAL ---- ------ ------ ------ ------ ------ ------ ------ (AMOUNTS IN THOUSANDS) Property acquisition cost..................... $11 $3,696 $1,230 $4,937 $1,151 $1,230 $2,909 $5,290 Exploration costs.......... 128 1,186 1,314 -- 1,146 649 1,795 --- ------ ------ ------ ------ ------ ------ ------ Total............ $11 $3,824 $2,416 $6,251 $1,151 $2,376 $3,558 $7,085 === ====== ====== ====== ====== ====== ====== ======
JUNE 30, 1996 ---------------------------- (UNAUDITED) INCURRED IN ---------------------------- 1994 1995 1996 TOTAL ------ ------ ------ ------ (AMOUNTS IN THOUSANDS) Property acquisition cost............................... $ 606 $ 590 $2,379 $3,575 Exploration costs....................................... 1,101 581 1,314 2,996 ------ ------ ------ ------ Total......................................... $1,707 $1,171 $3,693 $6,571 ====== ====== ====== ======
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. F-9 71 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) General and administrative costs that directly relate to exploration and development activities that were capitalized during the period totaled $480,000, $480,000 and $630,000 for the years ended December 31, 1993, 1994 and 1995 and $260,000 and $516,000 for the six months ended June 30, 1995 and 1996, respectively. Amortization per BOE was $4.36, $4.03, $5.22 and $6.10 for the years ended December 31, 1993, 1994 and 1995 and six months ended June 30, 1996, respectively. 3. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS
DECEMBER 31, ------------------ JUNE 30, 1994 1995 1996 ------- ------ ----------- (AMOUNTS IN THOUSANDS) (UNAUDITED) Senior bank loan..................................... $14,950 $ 100 $40,000 Convertible debentures............................... 1,426 3,296 2,930 Other notes payable.................................. 338 255 159 ------- ------ ------- 16,714 3,651 43,089 Less portion due within one year..................... 178 177 125 ------- ------ ------- Total long-term debt....................... $16,536 $3,474 $42,964 ======= ====== =======
BANKS On May 5, 1995, the Company refinanced and on November 14, 1995 amended its revolving credit facility with a new lender, ING Capital Corporation, expanding its credit line to $25,000,000 from $15,000,000. The new credit facility, denominated in U.S. dollars, is a senior secured one-year revolving facility converting to a four year term loan in April 1996, unless renewed or extended. The total outstanding principal balance may at no time exceed a borrowing base as determined semi-annually by the lender and is secured by all of the Company's current and future oil and natural gas properties. Interest is payable at the Company's option at the bank prime base rate plus 1% or the LIBOR rate plus 2.75%. The credit facility also has certain other restrictions, including: (i) a requirement to maintain positive working capital, (ii) a minimum equity balance of $25 million after certain adjustments, (iii) a prohibition on the payment of dividends, (iv) a maximum of $2 million per year on general and administrative expenses and (v) a prohibition of most other debt and corporate guarantees. As of December 31, 1995, the Company had $100,000 outstanding on the line of credit, with an available borrowing base of $25 million. On May 30, 1996, the Company refinanced its revolving credit facility with NationsBank of Texas as agent. See Note 11 for additional disclosures. SUBORDINATED DEBT On March 23, 1994, Denbury issued Cdn. $2,000,000 principal amount of unsecured convertible debentures. The debentures are due in five years, have an interest rate of 6 3/4% per annum, and are convertible at any time by the holders into Common Shares at a conversion price of Cdn. $4.00 per Common Share. Under certain conditions after July 15, 1996, the Company has the right to require an early redemption. On January 17, 1995, Denbury issued Cdn. $2,500,000 principal amount of unsecured convertible debentures. The debentures are due in five years, have an interest rate of 9 1/2% per annum, and are convertible at any time by the holders into Common Shares at a conversion price of Cdn. $4.05 per Common Share. Under certain conditions after April 13, 1997, the Company has the right to require an early redemption. F-10 72 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) INDEBTEDNESS REPAYMENT SCHEDULE The Company's indebtedness is repayable as follows:
DECEMBER 31, 1995 ------------------------------------------------- CONVERTIBLE OTHER NOTES YEAR BANK LOAN DEBENTURES PAYABLE TOTAL ------------------------------------------- --------- ----------- ----------- ------ (AMOUNTS IN THOUSANDS) 1996....................................... $ 25 $ -- $152 $ 177 1997....................................... 33 -- 79 112 1998....................................... 33 -- 22 55 1999....................................... 9 1,465 2 1,476 2000....................................... -- 1,831 -- 1,831 ---- ------ ---- ------ $100 $3,296 $255 $3,651 ==== ====== ==== ======
JUNE 30, 1996 (UNAUDITED) -------------------------------------------------- CONVERTIBLE OTHER NOTES YEAR BANK LOAN DEBENTURES PAYABLE TOTAL ------------------------------------------ --------- ----------- ----------- ------- (AMOUNTS IN THOUSANDS) 1996...................................... $ -- $ -- $ 56 $ 56 1997...................................... -- -- 79 79 1998...................................... 6,667 -- 22 6,689 1999...................................... 13,333 1,099 2 14,434 2000...................................... 13,333 1,831 -- 15,164 2001...................................... 6,667 -- -- 6,667 ------- ------ ---- ------- $40,000 $2,930 $159 $43,089 ======= ====== ==== =======
4. INCOME TAXES The Company's tax provision is as follows:
SIX MONTHS YEAR ENDED ENDED DECEMBER 31, JUNE 30, -------------------- -------------- 1993 1994 1995 1995 1996 ---- ---- ---- ---- ------ (AMOUNTS IN THOUSANDS) (UNAUDITED) Deferred Federal....................................... $345 $718 $367 $242 $1,804 State......................................... -- -- -- -- -- ---- ---- ---- ---- ------ Total................................. $345 $718 $367 $242 $1,804 ==== ==== ==== ==== ======
F-11 73 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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:
SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, ----------------------- -------------- 1993 1994 1995 1995 1996 ----- ----- ----- ---- ------ (AMOUNTS IN THOUSANDS) (UNAUDITED) Deferred income tax provision calculated using the Canadian federal and provincial statutory combined tax rate of 44.34%...... $ 922 $ 834 $ 479 $315 $2,287 Decrease resulting from: Effect of lower income tax rates on United States income.............................. (105) (116) (112) (73) (483) Utilization of prior years' losses........... (472) -- -- -- -- ----- ----- ----- ---- ------ $ 345 $ 718 $ 367 $242 $1,804 ===== ===== ===== ==== ======
The Company at December 31, 1995 had net operating loss carryforwards for U.S. tax purposes of approximately $12,366,000 and approximately $10,875,000 for alternative minimum tax purposes. The net operating losses are scheduled to expire as follows:
INCOME ALTERNATIVE YEAR TAX MINIMUM TAX -------------------------------------- ------ ----------- (AMOUNTS IN THOUSANDS) 2005.................................. $ 39 $ -- 2006.................................. 11 -- 2007.................................. 1,358 599 2008.................................. 5,016 4,889 2009.................................. 3,377 2,868 2010.................................. 2,565 2,519
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 STOCK 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 Stock by its bank loan agreements. F-12 74 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONVERTIBLE DEBENTURES The Company has reserved 1,117,284 Common Shares for issuance upon the conversion of Convertible Debentures which have been issued (See Note 3). 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) 8.333 million common shares issued at $2.925 per share, (ii) 1.25 million warrants at a price of $0.50 per warrant entitling the holder to purchase 1.25 million common shares at $3.70 per share and (iii) 1.5 million shares of $10 stated value Convertible First Preferred Shares, Series A ("Convertible Preferred"). The Convertible Preferred shares are initially convertible at $3.70 of stated value per common share with such conversion rate declining 2.5% per quarter. The shares also have a mandatory redemption at a 63.86% premium at December 21, 2000, but also provide that the Company can cause a mandatory conversion after January 1, 1999 if the price of the Common Stock exceeds $5.00 per share for a period of 40 consecutive trading days. The Convertible Preferred do not have any cash or other stated dividend requirements although the Company is making an accrual each year to account for the mandatory redemption premium quarterly accretion. This accrual correspondingly reduces the net income available to the common shareholders and is considered in the Company's primary earnings per share calculation. The Company may also force conversion of the warrants after December 21, 1997, if the price of the Common Stock exceeds $5.00 per share for a period of 40 consecutive trading days. See Note 11 "Subsequent Events" concerning a special meeting of shareholders to modify the terms of the Convertible Preferred. In addition, for a period of two years TPG has 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 that period. Furthermore, after the initial two years 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 1933, as amended, for 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 and Convertible Preferred) 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 has waived its registration rights and right to maintain its pro rata ownership with regard to the Public Offering. As part of the TPG Placement, Tortuga Investment Corp. was paid a financial advisor fee of 666,666 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, 1995, 300,000 warrants were outstanding at an exercise price of Cdn. $4.20 expiring on May 5, 2000 and 1,250,000 warrants were outstanding at an exercise price of U.S. $3.70 expiring on December 21, 1999. Each warrant entitles the holder thereof to purchase one Common Share at any time prior to the expiration date. The Company has the option after December 21, 1997, to require exercise of the 1,250,000 warrants if the weighted average trading price of the Common Stock exceeds $5.00 per share for a period of 40 consecutive trading days. F-13 75 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) SPECIAL WARRANT ISSUES On April 25, 1995, the Company issued 1,228,285 Special Warrants at a price of $2.35 (Cdn. $3.25) per Special Warrant for gross proceeds of $2,750,000 (58,072 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. On April 6, 1993, Denbury issued 1,885,000 Special Warrants at a price of Cdn. $4.25 per Special Warrant for gross and net proceeds of $6,348,000 and $5,866,000 respectively. On June 22, 1993, Denbury issued 1,000,000 Special Warrants at a price of Cdn. $6.00 per Special Warrant for gross and net proceeds of $4,693,000 and $4,356,000 respectively. On December 10, 1993, Denbury issued an additional 1,400,000 Special Warrants at a price of Cdn. $4.00 per Special Warrant for gross and net proceeds of $4,208,000 and $3,893,000 respectively. Each of these Special Warrants was exchanged, at no additional cost, for one Common Share resulting in the issue of 4,285,000 Common Shares. STOCK OPTIONS AND STOCK PURCHASE PLAN The Company maintains a Stock Option Plan which authorizes the grant of options of up to 2,100,000 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. At December 31, 1995, a total of 1,463,850 options had been granted under the plan, of which 1,079,350 shares were exercisable as of that date. In February 1996, the Company also implemented a Stock Purchase Plan which authorizes the sale of up to 500,000 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. This plan is administered by the Stock Purchase Plan Committee of the Board. Following is a summary of stock option activity during the years ended December 31, 1993, 1994 and 1995 and the six months ended June 30, 1996:
SIX MONTHS YEAR ENDED DECEMBER 31, ENDED ----------------------------------- JUNE 30, SHARES UNDER OPTION 1993 1994 1995 1996 ---------------------------------------- --------- --------- --------- ----------- (UNAUDITED) Outstanding at beginning of year........ 659,000 1,082,625 1,114,625 1,463,850 Granted................................. 1,001,000 277,500 549,000 888,000 Terminated.............................. (25,000) (53,000) (179,775) (13,500) Exercised............................... (552,375) (192,500) (20,000) (251,500) Expired................................. -- -- -- -- --------- --------- --------- --------- Outstanding at end of period (exercisable at $1.25 to $5.68 per share)................................ 1,082,625 1,114,625 1,463,850 2,086,850 ========= ========= ========= =========
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. F-14 76 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. The Company does not have any hedge contracts in place as of September 30, 1996. 7. COMMITMENTS AND CONTINGENCIES The Company has operating leases for the rental of office space, office equipment, and vehicles. At June 30, 1996 and December 31, 1995, long-term commitments for these items require the following future minimum rental payments:
DECEMBER 31, JUNE 30, 1995 1996 ------------ ----------- (AMOUNTS IN THOUSANDS) (UNAUDITED) 1996........................................ $304 $ 320 1997........................................ 251 428 1998........................................ 239 409 1999........................................ 86 166 2000........................................ -- -- ---- ------ $880 $1,323 ==== ======
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 difference between Canadian and U.S. GAAP affecting the Company's 1995 financial statements results from the fact that under U.S. GAAP the loss on early extinguishment of debt during 1995 would be an extraordinary item while under Canadian GAAP, it is not extraordinary. Net income, net income per share and all balance sheet amounts for the year ended December 31, 1995 are not effected by the difference in GAAP; however, the net income before extraordinary items would be $846,000 ($0.06 per common share) as compared to the $714,000 ($0.05 per common share) as reported under Canadian GAAP. The primary differences between Canadian and U.S. GAAP affecting the Company's 1996 consolidated financial statements relate to the presentation of the early extinguishment of debt and the imputed dividend on F-15 77 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) the Convertible Preferred. During the first six months of 1996, the Company expensed $759,000 relating to the imputed preferred dividend, as required under Canadian GAAP. Under U.S. GAAP, this dividend would be deducted after 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 agreement with ING Capital Corporation totaling $440,000. 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 for the first six months of 1996 under U.S. GAAP would be $3,354,000, while under Canadian GAAP the amount reported was $2,595,000. In addition, the methodology for computing earnings per common share is not consistent between the two countries. However, for the first six months of 1996 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. Therefore the difference in methodology had no effect on the earnings per common share reported in the Consolidated Financial Statements. In 1995, the United States Financial Accounting Standards Board issued Statement of Financial Accounting Standard ("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 does not intend to recognize compensation expense as calculated under SFAS No. 123 in the future and intends to continue recognizing expense as prescribed by APB Opinion No. 25, "Accounting for Stock Issued to Employees," as allowed under SFAS No. 123. As such, the adoption of SFAS No. 123 during 1996 will not have any effect on the Company's consolidated financial statements. As of June 30, 1996, the Company has two stock-based compensation plans. In the stock purchase plan which was implemented on February 1, 1996, an employee can elect to contribute up to 10% of their base earnings. The Company matches 75% of these contributions and the combined funds are used to purchase previously unissued Common Shares based upon the current market price. The Company recognizes compensation expense for the 75% Company matching portion, which during the six months ended June 30, 1996 totaled $60,000. F-16 78 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The Company also has a stock option plan as more fully described in Note 5. 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 SIX MONTHS DECEMBER 31, ENDED JUNE 30, 1995 1996 ------------ -------------- (UNAUDITED) Net income: As reported (thousands)................................. $ 714 $2,595 Pro forma (thousands)................................... 503 2,435 Net income per common share: As reported............................................. $ 0.05 $ 0.11 Pro forma............................................... 0.04 0.11 Stock options issued during period (thousands)............ 549 888 Weighted average exercise price........................... $ 2.95 $ 4.32 Average per option compensation value of options granted(1).............................................. 1.17 1.44 Compensation cost (thousands)............................. 320 243
- --------------- (1) 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 37% 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 relate to temporary differences based on tax laws and statutory rates in effect at the December 31, 1994 and 1995 and June 30, 1996 balance sheet dates. At December 31, 1994, and 1995 and June 30, 1996, all deferred tax assets and liabilities were computed based on Canadian GAAP amounts and were noncurrent as follows:
DECEMBER 31, ------------------- JUNE 30, 1994 1995 1996 ------- ------- ----------- (AMOUNTS IN THOUSANDS) (UNAUDITED) Deferred tax assets: Loss carryforwards.......................................... $(3,332) $(4,205) $(5,380) Deferred tax liabilities: Exploration and intangible development costs................ 4,396 5,636 8,615 ------- ------- ------- Net deferred tax liability.................................... $ 1,064 $ 1,431 $ 3,235 ======= ======= =======
9. SUPPLEMENTAL INFORMATION GEOGRAPHIC SEGMENTS During 1993, the Company had $618,000 of oil and natural gas sales in Canada and generated $1,065,000 of net income in Canada, including the gain on sale of Canadian properties of $966,000. All Canadian oil and natural gas properties were disposed of in 1993 and thus, all of the Company's operations are now in the United States. F-17 79 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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, 1995, the Company sold 10% or more of its net production of oil and natural gas to the following purchasers: Natural Gas Clearinghouse (21%), Amerada Hess (20%), Conoco, Inc. (12%), and Brymore Energy Corp. (12%). 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. Costs incurred in oil and natural gas activities for the years ended December 31, 1993, 1994 and 1995 and the six months ended June 30, 1996 are as follows:
SIX MONTHS YEAR ENDED DECEMBER 31, ENDED ------------------------------- JUNE 30, 1993 1994 1995 1996 ------- ------- ------- ----------- (AMOUNTS IN THOUSANDS) (UNAUDITED) Property acquisition................... $21,604 $ 6,736 $17,198 $48,179 Exploration............................ 608 1,796 1,687 1,841 Development............................ 7,643 8,371 9,639 10,713 ------- ------- ------- ------- $29,855 $16,903 $28,524 $60,733 ======= ======= ======= =======
PROPERTY ACQUISITIONS In November 1995, the Company closed on an acquisition of seven producing wells and certain non-producing leases in the Gibson/Humphreys fields of Terrebonne Parish, Louisiana for approximately $10.2 million. The 1995 acquisition was accounted for under purchase accounting and the results of operations were consolidated beginning October 1, 1995. Unaudited pro forma results of operations of the Company as if the acquisition had occurred at the beginning of each respective period are as follows:
PRO FORMA YEAR ENDED DECEMBER 31, --------------------- 1994 1995 ------- ------- (IN THOUSANDS EXCEPT PER SHARE AMOUNTS) (UNAUDITED) Revenues....................................................... $14,587 $22,235 Net income..................................................... 767 587 Net income per common share.................................... 0.06 0.04
F-18 80 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 that bank debt that was required to fund the acquisition. No additional general and administrative expense was expected as the Company could absorb these operations without additional personnel. The following represents the revenues and direct operating expenses attributable to the net interest acquired in the Gibson/Humphreys field 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 ------ ------ (AMOUNTS IN THOUSANDS) Revenues: Oil, natural gas and related product sales..................... $1,872 $2,849 ------ ------ Direct operating expenses: Lease operating expense........................................ 495 420 Severance and property taxes................................... 87 154 ------ ------ 582 574 ------ ------ Excess of revenues over direct operating expenses................ $1,290 $2,275 ====== ======
See Note 11 for additional property acquisition disclosures. 10. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED) Net proved oil and natural gas reserve estimates as of July 1, 1996 and December 31, 1995 were prepared by Netherland & Sewell and the net oil and natural gas reserve estimates as of December 31, 1994 and 1993 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-19 81 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) ESTIMATED QUANTITIES OF RESERVES
YEAR ENDED DECEMBER 31, SIX MONTHS --------------------------------------------------- ENDED JUNE 30, 1993 1994 1995 1996 --------------- --------------- --------------- --------------- OIL GAS OIL GAS OIL GAS OIL GAS (MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF) ------ ------ ------ ------ ------ ------ ------ ------ BALANCE BEGINNING OF YEAR..... 565 2,383 3,583 13,029 4,230 42,047 6,292 48,116 Revisions of previous estimates................ (254) 234 (48) 2,827 830 (1,620) (259) (238) Extensions, discoveries and other additions.......... 299 -- 640 14,978 732 -- 10 3,134 Production.................. (272) (673) (489) (3,326) (728) (4,844) (527) (4,098) Acquisition of minerals in place.................... 3,245 11,084 544 14,539 1,228 12,533 6,209 18,893 ----- ------ ----- ------ ----- ------ ------ ------ BALANCE AT END OF PERIOD...... 3,583 13,029 4,230 42,047 6,292 48,116 11,725 65,807 ===== ====== ===== ====== ===== ====== ====== ====== PROVED DEVELOPED RESERVES: Balance at beginning of year..................... 425 1,755 3,418 12,303 3,755 35,578 5,290 34,894 Balance at end of period.... 3,418 12,303 3,755 35,578 5,290 34,894 10,439 58,052
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. F-20 82 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
DECEMBER 31, ------------------------------ JULY 1, 1993 1994 1995 1996 -------- -------- -------- --------- (AMOUNTS IN THOUSANDS) Future cash inflows................................... $67,279 $126,129 $214,932 $ 392,385 Future production costs............................... (20,587) (35,069) (56,323) (105,280) Future development costs.............................. (3,408) (7,369) (16,154) (24,117) ------- -------- -------- --------- Future net cash flows before taxes.................... 43,284 83,691 142,455 262,988 10% annual discount for estimated timing of cash flows............................................ (14,646) (31,000) (45,490) (87,733) ------- -------- -------- --------- Discounted future net cash flows before taxes......... 28,638 52,691 96,965 175,255 Discounted future income taxes........................ (173) (5,763) (15,801) (25,095) ------- -------- -------- --------- STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS............................................... $28,465 $ 46,928 $ 81,164 $ 150,160 ======= ======== ======== =========
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, SIX MONTHS ENDED ---------------------------- JUNE 30, 1993 1994 1995 1996 ------- ------- -------- ---------------- (AMOUNTS IN THOUSANDS) Beginning of year.................................. $ 4,584 $28,465 $ 46,928 $ 81,164 Sales of oil and natural gas produced, net of production costs................................. (3,801) (8,383) (13,243) (15,300) Net changes in sales prices........................ (937) 863 23,037 20,556 Extensions and discoveries, less applicable future development costs................................ 579 13,416 1,926 2,239 Previously estimated development costs incurred.... 709 2,492 2,193 3,331 Revisions of previous estimates, including revised estimates of development costs, reserves and rates of production.............................. (996) (2,914) 3,958 (3,975) Accretion of discount.............................. 458 2,847 4,693 4,058 Purchase of minerals in place...................... 27,304 15,732 21,710 67,381 Net change in income taxes......................... 565 (5,590) (10,038) (9,294) ------- ------- -------- -------- End of period...................................... $28,465 $46,928 $ 81,164 $150,160 ======= ======= ======== ========
11. SUBSEQUENT EVENTS (UNAUDITED) 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 owns an interest, plus certain overriding royalty interests in other areas for approximately $7.5 million. 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 acquisition included 439 wells (110 net working interest wells), of which 129 wells are Company operated with the balance consisting of 124 non-operated working interest wells and 186 royalty interests wells. Of the 439 total acquired wells, 37 operated, 37 non-operated and 21 royalty interest wells are currently non-producing. The Company funded this acquisition with bank financing from a new credit facility and closed this transaction during June 1996. F-21 83 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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:
SIX MONTHS ENDED YEAR ENDED JUNE 30, DECEMBER 31, ------------------- 1995 1995 1996 ------------ ------- ------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Revenues............................................ $ 41,273 $18,913 $28,698 Net income.......................................... 899 878 3,516 Net income per common share......................... 0.07 0.07 0.15
In order to fund these two acquisitions and also to generally improve the terms and increase the size of its existing credit facility, the Company has entered into a new $150 million credit facility with NationsBank of Texas ("NationsBank"). This refinancing closed on May 31, 1996 and has a borrowing base as of September 30, 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. 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. At a meeting of the Board of Directors of the Company on May 16, 1996, the Company's Stock Option Plan was amended to increase the number of option shares authorized to be issued under the Plan from 2,000,000 to 2,500,000. This amendment is subject to shareholder and regulatory approval. On July 31, 1996, the Company issued 375,000 Common Shares for the conversion of the remaining 6 3/4% Convertible Debentures of the Company and on August 27, 1996, issued 150,000 Common Shares for the exercise of 150,000 Cdn. $4.20 warrants. In September 1996, the Company called a Special Meeting of the shareholders of the Company to be held on October 9, 1996 to consider and, if thought fit, pass three resolutions. The first resolution is to ratify and approve an amendment to the Articles of Continuance to consolidate the number of issued and outstanding Common Shares on the basis of one (1) Common Share for each two (2) Common Shares outstanding. The second resolution is to ratify and approve an amendment to the Articles of Continuance which governs the conversion provision attaching to the Convertible Preferred Shares which will give the Company the right to require the holders of the Preferred Shares to convert their Preferred Shares into Common Shares at any time, provided that the conversion rate in effect as of January 1, 1999 will be used for any required conversion prior to that date. Prior to this Preferred Amendment, the Company could not require a conversion of these Preferred Shares prior to January 1, 1999. If approved by the shareholders and subject to, and simultaneously with, the completion of the Offerings, the Company plans to require a conversion, thereby increasing the number of Common Shares of the Company by 5,632,745 and eliminating the outstanding Preferred Shares. The third resolution is to provide for the Company to issue Common Shares at an issue price of Cdn. $7.36 per share in payment of the interest that would be due on the 9 1/2% Convertible Debentures from the conversion date (following shareholders approval of the resolution) through and including April 13, 1997, if the holders of the debentures convert their debentures into Common Shares prior to April 13, 1997. If approved, the Company would issue a total of 15,915 Common Shares for the interim interest, assuming an F-22 84 DENBURY RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) approval date and conversion as of October 15, 1996, plus an additional 617,284 Common Shares which would be issued for the principal amount in accordance with the existing terms of the debentures. UNAUDITED QUARTERLY INFORMATION The following table presents unaudited summary financial information on a quarterly basis for 1994 and 1995 and the first two quarters of 1996 (in thousands except per share amounts).
MARCH 31 JUNE 30 SEPT. 30 DEC. 31 -------- ------- -------- ------- 1994 Revenues................................................ $2,574 $ 2,951 $3,400 $ 3,790 Expenses................................................ 2,011 2,351 2,829 3,643 Net income.............................................. 365 369 350 79 Net income per share.................................... 0.03 0.03 0.03 0.00 Cash flow from operations(a)............................ 1,361 1,514 1,665 1,645 1995 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.................................... 0.04 0.00 0.01 0.00 Cash flow from operations(a)............................ 2,112 1,913 2,234 3,135 1996 Revenues................................................ $9,092 $11,682 Expenses................................................ 6,767 9,608 Net income.............................................. 1,380 1,215 Net income per share.................................... 0.06 0.05 Cash flow from operations(a)............................ 6,065 7,238
- --------------- (a) Exclusive of the net change in non-cash working capital balances. F-23 85 INDEPENDENT AUDITORS' REPORT To the Board of Directors of Denbury Resources Inc. We have audited the accompanying statement of revenues and direct operating expenses attributable to certain oil and natural gas properties ("Ottawa Properties") (see Note 1) acquired by Denbury Resources Inc. for the year ended December 31, 1995. This statement is the responsibility of the management of Ottawa Energy, Inc., as operator of the properties. Our responsibility is to express an opinion on this statement based on our audit. We conducted our audit 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 statement is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statement. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. The accompanying statement of revenues and direct operating expenses reflect the revenues and direct operating expenses attributable to the Ottawa Properties as described in Note 1 to the statement and is not intended to be a complete presentation of the revenues and expenses of the Ottawa Properties. In our opinion, the accompanying statement presents fairly, in all material respects, the revenues and direct operating expenses described in Note 1 of the Ottawa Properties for the year ended December 31, 1995, in accordance with generally accepted accounting principles. DELOITTE & TOUCHE Chartered Accountants Calgary, Alberta April 9, 1996 (April 15, 1996 as to Note 1) F-24 86 STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF OTTAWA PROPERTIES
SIX MONTHS ENDED YEAR ENDED JUNE 30, DECEMBER 31, ----------------- 1995 1995 1996 ------------ ------- ------- (AMOUNTS IN THOUSANDS) (UNAUDITED) Revenues: Oil, natural gas and related product sales................... $2,954 $1,492 $1,766 Direct operating expenses: Lease operating expense...................................... 659 297 320 ------ ------ ------ Excess of revenue over direct operating expenses............... $2,295 $1,195 $1,446 ====== ====== ======
The accompanying notes are an integral part of these statements. F-25 87 NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF OTTAWA PROPERTIES 1. THE PROPERTIES The accompanying statements represent the revenues and direct operating expenses attributable to the net interest in producing wells and certain non-producing leases sold to Denbury Resources Inc. ("Denbury"), by Ottawa Energy, Inc. ("Ottawa") for approximately $8.0 million, before adjustments. Denbury closed on $5.6 million of the acquisition on April 15, 1996 and closed on the remainder at the end of April. The properties are located in the states of Texas, Louisiana, and Mississippi. These acquired properties and related operations were included in the Company's consolidated financial statements effective April 1, 1996. 2. BASIS OF PRESENTATION 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, these statements of revenue and direct operating expenses are presented in lieu of the financial statements required under Rule 3-05 of Securities and Exchange Commission Regulation S-X. All of the statements and disclosures are stated in U.S. dollars. The accompanying statements of revenues and direct operating expenses represent Ottawa's net ownership interest in the properties acquired by Denbury 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 Denbury. 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 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. 3. CONTINGENT LIABILITIES Given the nature of the properties acquired and as stipulated in the purchase agreement, Denbury is subject to loss contingencies pursuant to existing or expected environmental laws, regulations, and leases covering the acquired properties. 4. OIL AND NATURAL GAS RESERVES INFORMATION (UNAUDITED) Unaudited reserve information as of December 31, 1994 and December 31, 1995 related to the properties being acquired is presented in the table below.
OIL GAS OIL AND NATURAL GAS RESERVE QUANTITIES (MBBL) (MMCF) ----------------------------------------------------------------- ------- ------- Proved Developed and Undeveloped Reserves: December 31, 1994.............................................. 1,049.2 3,228.0 Production.................................................. (144.8) (615.5) ------- ------- December 31, 1995.............................................. 904.4 2,612.5 ======= ======= Proved Developed Reserves: As of December 31, 1994........................................ 514.5 3,228.0 As of December 31, 1995........................................ 743.3 2,612.5
F-26 88 NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF OTTAWA PROPERTIES -- (CONTINUED) The standardized measure of discounted future net cash flows ("Standardized Measure") relating to oil and natural gas reserves being acquired is calculated in accordance with Statement of Financial Accounting Standards No. 69. The Standardized Measure has been prepared assuming year-end selling prices adjusted for future fixed and determinable contractual price changes, year-end development and production costs and a 10% annual discount rate. The reserves and the related Standardized Measure at December 31, 1995, derived from the July 1, 1996 oil and natural gas reserve report prepared by Netherland & Sewell, were adjusted for production during 1995 and, in addition, the Standardized Measure was also adjusted for price changes to derive reserves and the Standardized Measure as of December 31, 1994. 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 oil and natural gas properties.
DECEMBER 31, 1995 ----------------- (AMOUNTS IN THOUSANDS) ----------------- Future cash inflows.................................................. $21,593.7 Future production and development costs.............................. (5,381.4) --------- Future net cash flows undiscounted................................... 16,212.3 10% Annual discount for estimated timing of cash flows............... (5,149.8) --------- Discounted future net cash flows before taxes........................ 11,062.5 Discounted future income taxes....................................... (1,211.0) --------- STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS............. $ 9,851.5 =========
The following are principal sources of change in the standardized measure of discounted future net cash flows:
DECEMBER 31, 1995 ----------------- (AMOUNTS IN THOUSANDS) ----------------- STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AT BEGINNING OF PERIOD.......................................................... $ 9,035.6 Changes resulting from: Net change in prices............................................... 2,548.6 Sales of oil and natural gas produced.............................. (2,295.2) Net change in income taxes......................................... (420.0) Accretion of discount.............................................. 982.6 --------- STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AT END OF PERIOD............................................................. $ 9,851.6 =========
F-27 89 INDEPENDENT AUDITORS' REPORT To the Board of Directors of Denbury Resources Inc. We have audited the accompanying statements of revenues and direct operating expenses attributable to certain oil and natural gas properties ("Amerada Hess Properties") (see Note 1) acquired by Denbury Resources Inc. for the years ended December 31, 1995, 1994 and 1993. These statements are the responsibility of the management of Amerada Hess Corporation, as owner of the properties. Our responsibility is to express an opinion on these statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. The accompanying statements of revenues and direct operating expenses reflect the revenues and direct operating expenses attributable to the Amerada Hess Properties as described in Note 1 to the statements and is not intended to be a complete presentation of the revenues and expenses of the Amerada Hess Properties. In our opinion, the accompanying statements present fairly, in all material respects, the revenues and direct operating expenses of the Amerada Hess Properties described in Note 1 for the years ended December 31, 1995, 1994 and 1993 in accordance with generally accepted accounting principles. DELOITTE & TOUCHE, LLP Dallas, Texas May 22, 1996 (June 21, 1996 as to Note 1) F-28 90 STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF AMERADA HESS PROPERTIES
SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, ----------------------------- ---------------- 1993 1994 1995 1995 1996 ------- ------- ------- ------ ------ (AMOUNTS IN THOUSANDS) (UNAUDITED) Revenues: Oil, natural gas and related product sales... $26,087 $17,787 $18,210 $8,403 $9,893 Direct operating expenses: Lease operating expense...................... 7,908 6,598 7,888 3,497 3,476 ------- ------- ------- ------ ------ Excess of revenues over direct operating expense...................................... $18,179 $11,189 $10,322 $4,906 $6,417 ======= ======= ======= ====== ======
The accompanying notes are an integral part of these statements. F-29 91 NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF AMERADA HESS PROPERTIES 1. THE PROPERTIES The accompanying statements represent the revenues and direct operating expenses attributable to the net interest in producing wells and certain non-producing leases sold to Denbury Resources Inc. ("Denbury"), by Amerada Hess Corporation ("Amerada Hess") for approximately $42.0 million, before adjustments totaling approximately $5 million which included a purchase price reduction for interim net cash flow from January 1, 1996, the effective date. The properties are located in the states of Louisiana, Mississippi, Alabama, and Ohio. The acquisition closed in June 1996. These acquired properties and related operations were included in the Company's consolidated financial statements effective May 1, 1996. 2. BASIS OF PRESENTATION 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, these statements of revenues and direct operating expenses are presented in lieu of the financial statements required under Rule 3-05 of Securities and Exchange Commission Regulation S-X. All of the statements and disclosures are stated in U.S. dollars. The accompanying statements of revenues and direct operating expenses represent Amerada Hess's net ownership interest in the properties acquired by Denbury 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 Denbury. 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 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. 3. CONTINGENT LIABILITIES Given the nature of the properties acquired and as stipulated in the purchase agreement, Denbury is subject to loss contingencies, if any, pursuant to existing or expected environmental laws, regulations, and leases covering the acquired properties. F-30 92 NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF AMERADA HESS PROPERTIES -- (CONTINUED) 4. OIL AND NATURAL GAS RESERVES INFORMATION (UNAUDITED) Unaudited reserve information related to the properties being acquired is presented in the table below and is derived from the July 1, 1996 oil and natural gas reserve report prepared by Netherland & Sewell, and calculated as of December 31, 1995, 1994 and 1993 and January 1, 1993 by adding production for 1996, 1995, 1994 and 1993 to the July 1, 1996 amount.
OIL GAS ESTIMATED QUANTITIES OF PROVED RESERVES (MBBL) (MMCF) ---------------------------------------------------------------- -------- -------- January 1, 1993............................................... 8,528.7 15,060.5 Production................................................. (1,219.0) (3,391.4) -------- -------- December 31, 1993............................................. 7,309.7 11,669.1 Production................................................. (965.9) (2,303.6) -------- -------- December 31, 1994............................................. 6,343.8 9,365.5 Production................................................. (939.7) (2,540.7) -------- -------- December 31, 1995............................................. 5,404.1 6,824.8 ======== ======== Proved Developed Reserves: As of January 1, 1993......................................... 7,948.7 14,994.9 As of December 31, 1993....................................... 6,729.7 11,603.5 As of December 31, 1994....................................... 5,763.8 9,299.9 As of December 31, 1995....................................... 4,824.1 6,759.2
F-31 93 NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF AMERADA HESS PROPERTIES -- (CONTINUED) 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 being acquired is calculated in accordance with Statement of Financial Accounting Standards No. 69. The Standardized Measure has been prepared assuming year-end selling prices adjusted for future fixed and determinable contractual price changes, year-end development and production costs and a 10% annual discount rate. The reserves and the related Standardized Measure at December 31, 1995, derived from the July 1, 1996 oil and natural gas reserve report prepared by Netherland & Sewell, were adjusted for production during 1996, 1995, 1994, and 1993 and, in addition, the Standardized Measure was also adjusted for price changes to derive reserves and the Standardized Measure as of December 31, 1995, 1994 and 1993. 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. Since the purchase price is approximately equal to the Standardized Measure of discounted future net cash flows, a tax provision has not been included.
DECEMBER 31, -------------------------------- 1993 1994 1995 -------- -------- -------- (AMOUNTS IN THOUSANDS) Future cash inflows.................................. $147,473 $129,686 $111,476 Future production and development costs.............. (61,493) (54,895) (47,007) -------- -------- -------- Future net cash flows undiscounted................... 85,980 74,791 64,469 10% annual discount for estimated timing of cash flows.............................................. (34,497) (27,683) (14,978) -------- -------- -------- STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS.............................................. $ 51,483 $ 47,108 $ 49,491 ======== ======== ========
The following are principal sources of changes in the standardized measure of discounted future net cash flows:
YEAR ENDED DECEMBER 31, -------------------------------- 1993 1994 1995 -------- -------- -------- (AMOUNTS IN THOUSANDS) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AT BEGINNING OF PERIOD....................... $ 81,869 $ 51,483 $ 47,108 Changes resulting from: Net change in prices............................... (20,393) 1,666 7,993 Sales of oil and natural gas produced.............. (18,179) (11,189) (10,321) Accretion of discount.............................. 8,186 5,148 4,711 -------- -------- -------- STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AT END OF PERIOD............................. $ 51,483 $ 47,108 $ 49,491 ======== ======== ========
F-32 94 August 10, 1996 Mr. Matthew W. Deso Denbury Management, Inc. Suite 200 17304 Preston Road Dallas, Texas 75252 Dear Mr. Deso: In accordance with your request, we have estimated the proved reserves and future revenue, as of July 1, 1996, to the Denbury Management, Inc. (DMI) interest in certain oil and gas properties located in Alabama, Louisiana, Mississippi, Ohio, and Texas as listed in the accompanying tabulations. These properties include those acquired from Amerada Hess Corporation (AHC) effective January 1, 1996, as well as those acquired in other transactions during the first half of 1996. For the purposes of this report, all DMI properties except those acquired from AHC are referred to as the Corporate Properties. This report has been prepared using constant prices and costs and conforms to the guidelines of the Securities and Exchange Commission (SEC). As presented in the accompanying summary projections, Tables I through IV, we estimate the net reserves and future net revenue to the DMI interest, as of July 1, 1996, to be:
Net Reserves Future Net Revenue ------------------------ ----------------------------- Oil Gas Present Worth Category (Barrels) (MCF) Total at 10% --------------------------------- ---------- ---------- ------------ ------------- Proved Developed Producing...................... 5,787,264 21,115,993 $104,619,100 $ 83,585,700 Non-Producing.................. 4,651,331 36,935,535 131,825,700 74,257,900 Proved Undeveloped............... 1,285,964 7,755,584 26,543,100 17,411,800 ---------- ---------- ------------ ------------ Total Proved........... 11,724,559 65,807,112 $262,987,900 $ 175,255,400
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. This report includes summary projections of reserves and revenue for each reserve category. For the purposes of this report, the term "lease" refers to a single economic projection. A-1 95 The estimated reserves and future revenue shown in this report are for proved developed producing, proved developed non-producing, and proved undeveloped reserves. In accordance with SEC guidelines, our estimates do not include any value for probable or possible reserves which may exist 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. As requested, oil prices used in this report are based on a July 1, 1996 NYMEX Cushing West Texas Intermediate posted price of $20.00 per barrel, adjusted by lease for gravity, transportation fees, and regional posted price differentials. The sulfur and natural gas liquids prices used for the Lambeth 7-14 located in Big Escambia Creek Field, Alabama, are $43.30 per long ton and $14.60 per barrel, respectively. The natural gas liquids price for Gibson Field, Louisiana, is $14.97 barrel. Gas prices used in this report are based on a July 1, 1996 NYMEX Henry Hub price of $2.65 per MMBTU, adjusted by lease for transportation fees and regional spot market price differentials. Oil, sulfur, 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 AHC. 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; A-2 96 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. 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. 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.; 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 Frederic D. Sewell A-3 DMA:MMD 97 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- 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 THE SELLING SHAREHOLDER. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR A SOLICITATION OF AN OFFER TO BUY ANY SECURITIES OTHER THAN THE SECURITIES TO WHICH IT RELATES NOR DOES IT CONSTITUTE AN OFFER OR SOLICITATION BY ANYONE IN ANY JURISDICTION IN WHICH SUCH OFFER OR SOLICITATION WOULD BE UNLAWFUL OR TO ANY PERSON TO WHOM IT IS UNLAWFUL TO MAKE SUCH OFFER OR SOLICITATION. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY OFFER OR SALE MADE HEREUNDER AT ANY TIME SHALL IMPLY THAT INFORMATION HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO THE DATE HEREOF. --------------------- TABLE OF CONTENTS
PAGE ---- Prospectus Summary.................... 3 Risk Factors.......................... 10 Concurrent Offerings.................. 16 Use of Proceeds....................... 16 Price Range of Common Shares and Dividend Policy..................... 17 Capitalization........................ 18 Pro Forma Operating Results........... 19 Selected Consolidated Financial Data................................ 22 Management's Discussion and Analysis of Financial Condition and Results of Operations....................... 23 Business and Properties............... 29 Management............................ 44 Interests of Management in Certain Transactions........................ 48 Security Ownership of Certain Beneficial Owners and Management.... 50 Description of Capital Stock.......... 51 Canadian Taxation and the Investment Canada Act.......................... 52 Shares Eligible for Future Sale....... 54 Underwriting.......................... 55 Plan of Distribution for the TPG Offering............................ 56 Service and Enforcement of Legal Process............................. 56 Legal Matters......................... 56 Experts............................... 57 Available Information................. 57 Glossary.............................. 58 Index to Consolidated Financial Statements.......................... F-1 Letter of Netherland, Sewell & Associates, Inc..................... A-1
- -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- 4,400,000 SHARES [DRI LOGO] COMMON STOCK ----------------------- PROSPECTUS ----------------------- DONALDSON, LUFKIN & JENRETTE SECURITIES CORPORATION PRUDENTIAL SECURITIES INCORPORATED JOHNSON RICE & COMPANY L.L.C. REPRESENTATIVES OF THE UNDERWRITERS - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- 98 PART II INFORMATION NOT REQUIRED IN PROSPECTUS ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION The estimated expenses in connection with the issuance and distribution of the securities being registered (other than underwriting discounts and commissions) are set forth in the following itemized table: SEC Registration Fee...................................................... $ * NASD Filing Fee........................................................... * Nasdaq National Market.................................................... * Toronto Stock Exchange Listing Fee........................................ * Transfer Agent's Fees..................................................... * Blue Sky Fees and Expenses................................................ * Accounting Fees........................................................... * Legal Fees................................................................ * Engineering Fees.......................................................... * Printing.................................................................. * Miscellaneous............................................................. * -------- Total........................................................... $ * ========
- --------------- * To be completed by amendment ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS Section 124(1) of the Canada Business Corporations Act ("CBCA") provides that, except in respect of an action by or on behalf of a corporation or body corporate to procure a judgment in its favor, a corporation may indemnify a director or officer of the corporation, a former director or officer of the corporation or a person who acts or acted at the corporation's request as a director or officer of a body corporate of which the corporation is or was a shareholder or creditor, and his heirs and legal representatives, against all costs, charges, and expenses, including an amount paid to settle an action or satisfy a judgment, reasonably incurred by him in respect of any civil, criminal or administrative action or proceeding to which he is made a party by reason of being or having been a director or officer of such corporation or body corporate, if: (a) he acted honestly and in good faith with a view to the best interests of the corporation; and (b) in a case of a criminal or administrative action or proceeding that is enforced by a monetary penalty, he had reasonable grounds for believing that his conduct was lawful. Section 124(2) of the CBCA provides that even if such a person is named in an action by or on behalf of the corporation or body corporate to procure a judgment in its favor, a corporation may indemnify such a person with court approval if such person meets the standards set forth in Section 124(1). Additionally, a person named in Section 124(1) is entitled to indemnity from the corporation if the person seeking indemnity: (a) was substantially successful on the merits in his defense of the action or proceeding; and (b) fulfills the conditions set forth above. Section 5.02 of the Company's Bylaws contains the same standards set forth in Section 124(1), but makes indemnification in such circumstances mandatory by the Company. In addition to the above provisions, the Company has also entered into an indemnity agreement with its officers and directors, which, subject to the CBCA, sets forth the procedures by which a person may seek indemnity and clarifies the situations in which a person may be entitled to indemnity by the Company. II-1 99 Effective in September 1996, the Corporation modified the directors and officers insurance covering each of its officers and directors. The insurance provides up to $10 million of coverage for the officers and directors with deductibles ranging from zero to $350,000, depending on the type of claim, and $10 million coverage for the Corporation with a 25% co-insurance provision. The Corporation has paid for 100% of the cost of this insurance. ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES During the last three years, the Company issued a total of 2,845,285 warrants to purchase Common Shares. All of these warrants were issued to residents of the United States, except for 284,866 of the 1,228,285 Special Warrants issued on April 24, 1995, which were sold to Canadian residents, as indicated in the chart below. Of those warrants issued, 1,400,000 warrants are still outstanding and 1,445,285 were converted to Common Shares, which are currently outstanding. The following table sets forth certain details with respect to the issuance of such securities. None of the information in this Item 15 has been adjusted to reflect the one-for-two reverse split of the Common Shares to be submitted to the shareholders of the Company for approval on October 9, 1996.
AGGREGATE AMOUNT AND TITLE OF OFFERING SECURITY ISSUED DATE ISSUED PURCHASER(S) PRICE EXEMPTION - ----------------------- ----------------- -------------------- ------------- --------------- 67,000 Special December 17, 1993 Bodel, Inc. Cdn. $268,000 sec.4(2)-Rule Warrant(1) 144A 117,000 Special April 24, 1995 State Street $274,950 sec.4(2)-Rule Warrant(2) Research(3) 506 159,576 Special April 24, 1995 Virginia Retirement $375,003 sec.4(2)-Rule Warrant(2) System 506 53,191 Special April 24, 1995 Monsanto Master $124,998 sec.4(2)-Rule Warrant(2) Trust #22-85716 506 53,191 Special April 24, 1995 City of Detroit $124,988 sec.4(2)-Rule Warrant(2) Policeman & Fireman 506 #97301 53,191 Special April 24, 1995 Montgomery County $124,988 sec.4(2)-Rule Warrant(2) Employee Ret. 506 72,100 Special April 24, 1995 Mackenzie Financial $169,435 sec.4(2)-Rule Warrant(2) Corporation(4) 506 212,766 Special April 24, 1995 Roytor & Co.(4) $500,000 sec.4(2)-Rule Warrant(2) 506 170,213 Special April 24, 1995 Drakes Landing $400,000 sec.4(2)-Rule Warrant(2) Associates, L.P. 506 170,213 Special April 24, 1995 JDN Partners $400,000 sec.4(2)-Rule Warrant(2) 506 100,000 Special April 24, 1995 Mr. Michael A. $235,000 sec.4(2)-Rule Warrant(2) Nicolais 506 66,844 Special April 24, 1995 Southcoast Capital $20,614 sec.4(2)-Rule Warrant(2) Corp. 506 300,000 Common Share May 5, 1995 Internationale (5) sec.4(2)-Rule Purchase Nederlanden (U.S.) 506 Warrant Capital Corporation 1,250,000 Common Share December 21, 1995 T.P.G. Advisors, $625,000 sec.4(2)-Rule Purchase Inc. and 506 Warrant affiliates(6)
- --------------- (1) Underlying Common Shares were issued for no additional consideration in March 1994. (2) Underlying Common Shares were issued for no additional consideration in August 1995. II-2 100 (3) State Street Research has declined to exercise its contractual registration rights with respect to the 117,000 Common Shares underlying these 117,000 Special Warrants. (4) Canadian resident. (5) Issued pursuant to the refinancing of the Company's Credit Facility with Internationale Nederlanden (U.S.) Capital Corporation in April 1995. As of the date hereof, 150,000 of these common share purchase warrants have been exercised. (6) T.P.G. Advisors, Inc. is not the owner of record of these securities. However, T.P.G. Advisors, Inc. is the general partner of TPG GenPar, L.P., which in turn is the general partner of TPG Partners, L.P. and TPG Parallel, L.P., which are the direct beneficial owner of these securities. On December 21, 1995, in the same transaction described in the table above in which the Company issued 1,250,000 Common Share Purchase Warrants to TPG Advisors, Inc. and certain of its affiliates, the Company issued 8,333,333 Common Shares and 1,500,000 Convertible Preferred Shares to TPG Advisors, Inc. and certain of its affiliates for aggregate consideration of $24,375,000 and $15,000,000, respectively. Additionally, the Company issued 666,666 Common Shares to Tortuga Investment Corp. as a financial advisory fee in connection with the same transaction. The Company also issued a total of 13,284,999 Common Shares in Canada in private transactions between the Company and Canadian citizens or corporations during the period January 1, 1993, through December 31, 1995. In July 1993, the Company issued 1,885,000 Common Shares upon the conversion of the same number of Special Warrants sold to 27 institutional and eight individual investors in a private placement at the price of Cdn. $4.25 per Special Warrant. In October 1993, the Company issued 1,000,000 Common Shares upon the exercise of the same number of Special Warrants sold to 24 institutional investors in a private placement at the price of Cdn. $6.00 per Special Warrant. In March 1994, the Company issued 1,400,000 Common Shares upon the exercise of the same number of Special Warrants sold to various private places at the price of Cdn. $4.00 per Special Warrant. The Company also issued convertible debentures to three Canadian residents in 1994 and 1995. In April of 1994, the Company issued Cdn. $1,500,000 and Cdn. $500,000 principal amount of 6.75% Unsecured, Convertible, Redeemable Debentures to Tortuga Investment Corp. and Lintex Holdings Ltd., respectively, in private placements. Additionally, in January 1995, the Company issued Cdn. $2,000,000, $250,000 and $250,000 principal amount of 9.5% Unsecured, Convertible, Redeemable Debentures, to Ronald G. Greene, Royal Trust of Canada and Mackenzie Financial Corporation, respectively, in a private placement. As of the closing of this Offering none of the debentures described in this paragraph will be outstanding. In addition, the Company issued 1,001,000 options to purchase Common Shares during 1993, at prices ranging from Cdn. $3.70 to $7.75 per share, 277,500 options during 1994 at prices ranging from Cdn. $3.40 to $4.15 per share and 549,000 options during 1995 at prices ranging from Cdn. $3.80 to $4.25 per share to certain employees, officers and directors under the Company's Employee Stock Option Plan. The Company issued 552,375, 192,500 and 20,000 Common Shares to certain employees, officers and directors upon the exercise of stock options granted pursuant to the Company's Employee Stock Option Plan in 1993, 1994 and 1995, respectively. All of the above transactions with U.S. residents were exempt from registration under the Securities Act of 1933 (the "Act") in reliance on either Section 4(2) of the Act or Regulation D promulgated thereunder as transactions by an issuer not involving any public offering, or Rule 701 promulgated under Section 3(b) of the Act as transactions pursuant to compensatory benefit plans and contracts relating to compensation as provided under such Rule 701. The recipients of securities in each such transaction represented their intentions to acquire the securities for investment only and not with a view to or for sale in connection with any distribution thereof and appropriate legends were affixed to the same share certificates issued in such transactions. All of the above transactions with Canadian residents were exempt from registration under the Act, pursuant to Regulation S, promulgated under such Act. II-3 101 ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES (a) EXHIBITS.
EXHIBIT NUMBER EXHIBIT - -------------------- ------------------------------------------------------------------------ 1(a)** -- Form of Underwriting Agreement. 3(a)* -- Form of Articles of Amendment to be filed prior to the closing of the offering made under this Registration Statement. 3(b) -- Articles of Continuance of the Company, as amended (incorporated by reference as Exhibits 3(a), 3(b), 3(c), 3(d) of the Registrant's Registration Statement on Form F-1 dated August 25, 1995) and Exhibit 4(e) of the Registrant's Registration Statement on Form S-8 dated February 2, 1996). 3(c) -- General By-Law No. 1: A By-Law Relating Generally to the Conduct of the Affairs of the Company, as amended (incorporated by reference as Exhibit 3(e) of the Registrant's Registration Statement on Form F-1 dated August 25, 1995 and Exhibit 4(d) of the Registrant's Registration Statement on Form S-8 dated February 2, 1996). 4(a) -- "Common Shares" section of Schedule "A" to Articles of Amendment of Newscope Resources Limited dated December 13, 1990, exhibited in full at 3(a) (incorporated by reference as Exhibit 4(a) of the Registrant's Registration Statement on Form F-1 dated August 25, 1995). 4(b) -- Section 1.05 of General By-Law No. 1, exhibited in full at 3(b) (incorporated by reference as Exhibit 4(b) of the Registrant's Registration Statement on Form F-1 dated August 25, 1995). 4(c) -- Pages 8-14 of General By-Law No. 1, exhibited in full at 3(b) (incorporated by reference as Exhibit 4(c) of the Registrant's Registration Statement on Form F-1 dated August 25, 1995). 4(d) -- Newscope Resources Ltd. Unsecured 6.75% Convertible Debenture due April 15, 1999 (incorporated by reference as Exhibit 4(d) of the Registrant's Registration Statement on Form F-1 dated August 25, 1995). 4(e) -- Newscope Resources Ltd. Unsecured 9.5% Convertible Debenture due January 13, 2000 (incorporated by reference as Exhibit 4(e) of the Registrant's Registration Statement on Form F-1 dated August 25, 1995). 4(f) -- "Series Provisions Attaching to the Convertible Preferred Shares, Series A" section of Schedule "A" to the Articles of Amendment of the Company dated December 21, 1995, exhibited in full at 3(a) (incorporated by reference as Exhibit 4(e) of the Registrant's Registration Statement on Form S-8 dated February 2, 1996). 5(a)** -- Opinion of Burnet, Duckworth & Palmer. 5(b)** -- Opinion of Jenkens & Gilchrist, a Professional Corporation. 10(a) -- Shelf Registration Agreement dated April 24, 1995, by and among Newscope Resources Ltd. and holders of Special Warrants (incorporated by reference as Exhibit 10(a) of the Registrant's Registration Statement on Form F-1 dated August 25, 1995). 10(b) -- Credit Agreement between Denbury Management Inc., (Borrower), Denbury Resources Inc., (Guarantor), Denbury Holdings, Ltd., (Guarantor), and NationsBank of Texas N.A. as agent, dated May 31, 1996 (incorporated by reference as Exhibit 10(b) of the Registrant's Post-effective Amendment No. 2 to Form F-1 on Form S-1 dated June 25, 1996). 10(c)* -- Common Share Purchase Warrant representing right of Internationale Nederlanden (U.S.) Capital Corporation to purchase 150,000 Common Shares of Newscope Resources Ltd.
II-4 102
EXHIBIT NUMBER EXHIBIT - -------------------- ------------------------------------------------------------------------ 10(d) -- Registration Rights Agreement dated May 5, 1995, between Internationale Nederlanden (U.S.) Capital Corporation and Newscope Resources Ltd. (incorporated by reference as Exhibit 10(d) of the Registrant's Registration Statement on Form F-1 dated August 25, 1995). 10(e) -- Special Warrant Indenture between Newscope Resources Ltd. and the R-M Trust Company dated as of April 24, 1995 (incorporated by reference as Exhibit 10(e) of the Registrant's Registration Statement on Form F-1 dated August 25, 1995). 10(f) -- Denbury Resources Inc. Stock Option Plan (incorporated by reference as Exhibit 4(f) of the Registrant's Registration Statement on Form S-8 dated February 2, 1996). 10(g) -- Denbury Resources Inc. Stock Purchase Plan (incorporated by reference as Exhibit 4(g) of the Registrant's Registration Statement on Form S-8 dated February 2, 1996). 10(h) -- Form of indemnification agreement between Newscope Resources Ltd. and its officers and directors (incorporated by reference as Exhibit 10(h) of the Registrant's Form 10-K for the year ended December 31, 1995). 10(i) -- Securities Purchase Agreement and exhibits between Newscope Resources Ltd. and TPG Partners, L.P. as of November 13, 1995 (incorporated by reference as Exhibit 10(i) of the Registrant's Form 10-K for the year ended December 31, 1995). 10(j) -- First Amendment to the November 13, 1995 Securities Purchase Agreement between Newscope Resources Ltd. and TPG Partners, L.P. as of December 21, 1995 (incorporated by reference on Exhibit 10(j) of the Registrant's Form 10-K for the year ended December 31, 1995). 10(k)** -- Stock Purchase Agreement between TPG Partners, L.P. and Denbury Resources Inc. 21 -- List of Subsidiaries of Denbury Resources Inc. (incorporated by reference on Exhibit 21 of the Registrant's Form 10-K for the year ended December 31, 1995). 23(a)* -- Consent of Deloitte & Touche. 23(b)* -- Consent of Deloitte & Touche LLP. 23(c)* -- Consent of The Scotia Group. 23(d)* -- Consent of Netherland, Sewell and Associates. 23(e)** -- Consent of Burnet, Duckworth & Palmer. 23(f)** -- Consent of Jenkens & Gilchrist, a Professional Corporation (contained in its opinion filed as Exhibit 5(b)).
- --------------- * Previously filed. ** To be filed by amendment. (b) FINANCIAL STATEMENTS AND SCHEDULES. Financial statements filed as a part of this report are listed in the Index to Financial Statements appearing herein on page F-1. ITEM 17. UNDERTAKINGS Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the provisions described in Item 14 above, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person II-5 103 in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue. The undersigned registrant hereby undertakes: (1) For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective. (2) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offer thereof. II-6 104 SIGNATURES Pursuant to the requirements of the Securities Act of 1933, as amended, Denbury Resources Inc., the Registrant, has duly caused this Registration Statement No. 333-12005 to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Dallas, Texas, on the 2nd day of October, 1996. DENBURY RESOURCES INC. By: /s/ PHIL RYKHOEK ------------------------------- Phil Rykhoek Chief Financial Officer Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed by the following persons in the capacities and on the dates indicated, in multiple counterparts with the effect of one original. Each person whose signature appears below as a signatory to this Registration Statement constitutes and appoints Gareth Roberts and Phil Rykhoek, or either one of them, his true and lawful attorney-in-fact and agent with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Registration Statement, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agent, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and agent or his substitute may lawfully do or cause to be done by virtue hereof.
SIGNATURES TITLE DATE - --------------------------------------------- ---------------------------- ----------------- GARETH ROBERTS* President and Chief October 2, 1996 --------------------------------- Executive Officer and Gareth Roberts Director (Principal Executive Officer) /s/ PHIL RYKHOEK Chief Financial Officer and October 2, 1996 --------------------------------- Secretary and Authorized Phil Rykhoek Representative (Principal Financial and Accounting Officer) RONALD G. GREENE* Chairman of the Board and October 2, 1996 --------------------------------- Director Ronald G. Greene WIELAND WETTSTEIN* Director October 2, 1996 --------------------------------- Wieland Wettstein DAVID M. STANTON* Director October 2, 1996 --------------------------------- David M. Stanton *By: /s/ PHIL RYKHOEK --------------------------------- Phil Rykhoek Attorney-in-Fact pursuant to power of attorney contained in original filing of this Registration Statement
II-7 105 SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT INDEPENDENT AUDITORS' REPORT To the Shareholders of Denbury Resources Inc. (Formerly Newscope Resources Ltd.) We have audited the consolidated financial statements of Denbury Resources Inc. (Formerly Newscope Resources Ltd.) as at December 31, 1995 and 1994 and for each of the three years in the period ended December 31, 1995 and have issued our report thereon dated February 23, 1996, such consolidated financial statements and report are included elsewhere in this registration statement on Form S-1. Our audits also included the Schedule I -- Condensed Financial Information of Denbury Resources Inc. listed in Item 16. This financial statement schedule is the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. We conducted our audits in accordance with the auditing standards generally accepted in Canada 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 misstatements. An audit also 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 used by management, as well as evaluating the overall financial statement presentation. In our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein. DELOITTE & TOUCHE Chartered Accountants Calgary, Alberta February 23, 1996 S-1 106 SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT DENBURY RESOURCES INC. (FORMERLY NEWSCOPE RESOURCES LTD.) UNCONSOLIDATED BALANCE SHEETS (AMOUNTS IN THOUSANDS OF U.S. DOLLARS) ASSETS
DECEMBER 31, --------------------- 1994 1995 ------- ------- Current assets Cash and cash equivalents............................................ $ 7 $ 8 Trade and other receivables.......................................... 2 7 ------- ------- Total current assets................................................. 9 15 ------- ------- Investment in subsidiaries (equity method)............................. 25,890 70,130 Loan receivable from subsidiary........................................ 1,521 1,563 Other assets........................................................... 19 28 ------- ------- Total assets................................................. $27,439 $71,736 ======= ======= LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities Accounts payable and accrued liabilities............................. $ 20 $ 9 Long-term debt......................................................... 1,457 3,226 ------- ------- 1,477 3,235 ------- ------- 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 -- 22,857,619 shares at December 31, 1995 and 12,609,335 shares at December 31, 1994............................ 23,239 50,064 Retained earnings.................................................... 2,723 3,437 ------- ------- Total shareholders' equity........................................ 25,962 53,501 ------- ------- Total liabilities and shareholders' equity................... $27,439 $71,736 ======= =======
See Notes to Financial Statements. S-2 107 SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT DENBURY RESOURCES INC. UNCONSOLIDATED STATEMENTS OF INCOME (AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS) (U.S. DOLLARS)
YEAR ENDED DECEMBER 31, ---------------------------------- 1993 1994 1995 ------ ------- ------- Revenues Oil, natural gas and related product sales............... $ 618 $ -- $ -- Interest income.......................................... 44 1 460 ------ ------- ------- Total revenues........................................ 662 1 460 ------ ------- ------- Expenses Production............................................... 161 -- -- General and administrative............................... 214 149 178 Interest................................................. 9 76 282 Depletion and depreciation............................... 179 2 -- ------ ------- ------- Total expenses................................... 563 227 460 ------ ------- ------- Income before the following................................ 99 (226) -- Equity in net earnings of subsidiaries................... 670 1,389 714 Gain on sale of Canadian properties...................... 966 -- -- ------ ------- ------- Income before income taxes................................. 1,735 1,163 714 Provision for federal income taxes......................... -- -- -- ------ ------- ------- Net income................................................. $1,735 $ 1,163 $ 714 ====== ======= ======= Net income per common share................................ $ 0.17 $ 0.09 $ 0.05 ====== ======= ======= Average number of common shares outstanding................ 9,980 12,480 13,739 ====== ======= =======
See Notes to Financial Statements. S-3 108 SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT DENBURY RESOURCES INC. UNCONSOLIDATED STATEMENTS OF CASH FLOWS (AMOUNTS IN THOUSANDS OF U.S. DOLLARS)
YEAR ENDED DECEMBER 31, ------------------------------- 1993 1994 1995 -------- ------- -------- Cash flow from operating activities: Net income.................................................. $ 1,735 $ 1,163 $ 714 Adjustments needed to reconcile to net cash flow provided by operations: Depreciation, depletion and amortization................. 179 11 17 Gain on sale of Canadian properties...................... (966) -- -- Equity on net earnings of subsidiaries................... (670) (1,389) (714) -------- ------- -------- 278 (215) 17 Changes in working capital items relating to operations: Trade and other receivables.............................. 212 8 (4) Accounts payable and accrued liabilities................. (203) (77) (12) -------- ------- -------- Net cash flow provided by operations.......................... 287 (284) 1 -------- ------- -------- Cash flow from investing activities: Investments in subsidiaries.............................. (19,381) (1,518) (43,569) Proceeds on disposal of Canadian properties.............. 3,129 -- -- Net purchases of other assets............................ (41) (15) 7 -------- ------- -------- Net cash used for investing activities........................ (16,293) (1,533) (43,562) -------- ------- -------- Cash flow from financing activities: Issuance of subordinated debt............................ -- 1,451 1,772 Issuance of common stock................................. 15,148 367 26,825 Issuance of preferred stock.............................. -- -- 15,000 Costs of debt financing.................................. -- -- (35) -------- ------- -------- Net cash provided by financing activities..................... 15,148 1,818 43,562 -------- ------- -------- Net increase (decrease) in cash and cash equivalents.......... (858) 1 1 Cash and cash equivalents at beginning of year................ 864 6 7 -------- ------- -------- Cash and cash equivalents at end of year...................... $ 6 $ 7 $ 8 ======== ======= ======== Supplemental disclosure of cash flow information: Cash paid during the year for interest................... $ 9 $ 76 $ 282
See Notes to Financial Statements. S-4 109 DENBURY RESOURCES INC. SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRATION NOTES TO FINANCIAL STATEMENTS NOTE 1. ACCOUNTING POLICIES Consolidation -- The financial statements of Denbury Resources Inc. reflect the investment in subsidiaries using the equity method. Income Taxes -- No provision for income taxes has been made in the Statement of Income because the Company has losses for Canadian tax purposes. NOTE 2. CONSOLIDATED FINANCIAL STATEMENTS Reference is made to the Consolidated Financial Statements and related notes of Denbury Resources Inc. and Subsidiaries for additional information. NOTE 3. DEBT AND GUARANTEES Information on the long-term debt of Denbury Resources Inc. is disclosed in Note 3 to the Consolidated Financial Statements. Denbury Resources Inc. has guaranteed the subsidiaries' bank credit line. NOTE 4. DIVIDENDS RECEIVED Subsidiaries' of Denbury Resources Inc. do not make formal cash dividend declarations and distributions to the parent and are currently restricted from doing so under the subsidiaries bank loan agreement. S-5 -----END PRIVACY-ENHANCED MESSAGE-----