-----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, MqTZiplOeDcCGN7nUGlZMRAd3edQYx1wqUAAir48eyIos7fu8sEjVrVTn8uokcP6 UsLstsJeNH0p3DkWIv4Jow== 0000899078-04-000546.txt : 20040809 0000899078-04-000546.hdr.sgml : 20040809 20040809172118 ACCESSION NUMBER: 0000899078-04-000546 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 20040630 FILED AS OF DATE: 20040809 FILER: COMPANY DATA: COMPANY CONFORMED NAME: DENBURY RESOURCES INC CENTRAL INDEX KEY: 0000945764 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 752815171 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-12935 FILM NUMBER: 04962328 BUSINESS ADDRESS: STREET 1: 5100 TENNYSON PARKWAY STREET 2: SUITE 3000 CITY: PLANO STATE: TX ZIP: 75024 BUSINESS PHONE: 9726732000 MAIL ADDRESS: STREET 1: 5100 TENNYSON PARKWAY STREET 2: SUITE 3000 CITY: PLANO STATE: TX ZIP: 75024 FORMER COMPANY: FORMER CONFORMED NAME: NEWSCOPE RESOURCES LTD DATE OF NAME CHANGE: 19950627 10-Q 1 denbury2ndq10q2004.txt 2ND QUARTER 2004 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (Mark One) [X] Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the quarterly period ended June 30, 2004 [ ] Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Commission file number 1-12935 DENBURY RESOURCES INC. (Exact name of Registrant as specified in its charter) Delaware 20-0467835 (State or other jurisdictions of (I.R.S. Employer incorporation or organization) Identification No.) 5100 Tennyson Parkway Suite 3000 Plano, TX 75024 (Address of principal executive offices) (Zip code) Registrant's telephone number, including area code: (972) 673-2000 Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No__ Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes [X] No__ Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Class Outstanding at July 31, 2004 ----- ---------------------------- Common Stock, $.001 par value 55,037,839
INDEX Page ---- Part I. Financial Information - ------------------------------ Item 1. Financial Statements Unaudited Condensed Consolidated Balance Sheets at June 30, 2004 and December 31, 2003 3 Unaudited Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2004 and 2003 4 Unaudited Condensed Consolidated Statements of Cash Flows for the Three and Six Months Ended June 30, 2004 and 2003 5 Unaudited Condensed Consolidated Statements of Comprehensive Operations for the Three and Six Months Ended June 30, 2004 and 2003 6 Notes to Unaudited Condensed Consolidated Financial Statements 7-17 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 18-30 Item 3. Quantitative and Qualitative Disclosures about Market Risk 30 Item 4. Controls and Procedures 30 Part II. Other Information --------------------------- Item 1. Legal Proceedings N/A Item 2. Changes in Securities, Use of Proceeds, and Issuer Purchases of Equity Securities 30 Item 3. Defaults Upon Senior Securities N/A Item 4. Submission of Matters to a Vote of Security Holders 30-31 Item 5. Other Information N/A Item 6. Exhibits and Reports on Form 8-K 31 Signatures 32
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DENBURY RESOURCES INC. UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS (Amounts in thousands except share amounts) June 30, December 31, 2004 2003 -------------- -------------- Assets Current assets Cash and cash equivalents $ 27,940 $ 24,188 Accrued production receivables 41,041 33,944 Related party accrued production receivable - Genesis 10,666 6,927 Trade and other receivables 19,853 18,080 Deferred tax asset 35,094 25,016 Derivative assets 5,053 - -------------- --------------- Total current assets 139,647 108,155 -------------- --------------- Property and equipment Oil and natural gas properties (using full cost accounting) Proved 1,501,122 1,409,579 Unevaluated 45,681 46,065 CO2 properties and equipment 112,717 85,467 Other 17,571 16,450 Less accumulated depletion and depreciation (758,911) (705,050) -------------- --------------- Net property and equipment 918,180 852,511 -------------- --------------- Investment in Genesis 7,188 7,450 Other assets 16,169 14,505 -------------- --------------- Total assets $ 1,081,184 $ 982,621 ============== =============== Liabilities and Stockholders' Equity Current liabilities Accounts payable and accrued liabilities $ 62,840 $ 62,349 Oil and gas production payable 27,243 22,215 Derivative liabilities 41,202 42,010 -------------- --------------- Total current liabilities 131,285 126,574 -------------- --------------- Long-term liabilities Long-term debt 308,300 298,203 Asset retirement obligations 43,076 41,711 Derivative liabilities 2,470 2,603 Deferred revenue - Genesis 20,362 21,468 Deferred tax liability 95,810 68,555 Other 1,774 2,305 -------------- --------------- Total long-term liabilities 471,792 434,845 -------------- --------------- Stockholders' equity Common stock, $.001 par value, 100,000,000 shares authorized; 55,112,836 and 54,190,042 shares issued at June 30, 2004 and December 31, 2003, respectively 55 54 Paid-in capital in excess of par 412,423 401,709 Retained earnings 88,349 46,656 Accumulated other comprehensive loss (22,056) (27,113) Treasury stock, at cost, 38,265 and 8,162 shares at June 30, 2004 and December 31, 2003, respectively (664) (104) -------------- --------------- Total stockholders' equity 478,107 421,202 -------------- --------------- Total liabilities and stockholders' equity $ 1,081,184 $ 982,621 ============== =============== (See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
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DENBURY RESOURCES INC. UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Amounts in thousands except per share amounts) Three Months Ended Six Months Ended June 30, June 30, ------------------------- ------------------------- 2004 2003 2004 2003 ------------ ------------ ------------ ------------ Revenues and other income Oil, natural gas and related product sales Unrelated parties $ 95,706 $ 83,575 $ 186,980 $ 182,886 Related party - Genesis 23,365 11,177 42,327 23,590 CO2 sales and transportation fees Unrelated parties 319 2,445 603 4,634 Related party - Genesis 1,261 - 2,338 - Loss on settlements of derivative contracts (18,239) (13,356) (32,507) (41,041) Interest income and other 330 347 749 551 ------------ ------------ ------------ ------------ Total revenues and other income 102,742 84,188 200,490 170,620 ------------ ------------ ------------ ------------ Expenses Lease operating expenses 24,530 23,048 47,058 45,450 Production taxes and marketing expenses 4,514 3,467 8,581 7,363 CO2 operating expenses 209 534 353 851 General and administrative expenses 4,178 3,376 8,926 7,167 Interest 5,068 6,227 10,149 12,688 Loss on early retirement of debt - 17,629 - 17,629 Depletion, depreciation and amortization 28,161 23,130 55,485 46,683 Amortization of derivative contracts and other non-cash hedging adjustments 7,146 (751) 7,964 (2,261) ------------ ------------ ------------ ------------ Total expenses 73,806 76,660 138,516 135,570 ------------ ------------ ------------ ------------ Equity in net income of Genesis 102 35 9 51 ------------ ------------ ------------ ------------ Income before income taxes 29,038 7,563 61,983 35,101 Income tax provision (benefit) Current income taxes 977 (1,093) 3,096 1,637 Deferred income taxes 8,672 3,527 17,194 9,882 ------------ ------------ ------------ ------------ Income before cumulative effect of change in accounting principle 19,389 5,129 41,693 23,582 Cumulative effect of change in accounting principle, net of income taxes of $1,600 - - - 2,612 ------------ ------------ ------------ ------------ Net income $ 19,389 $ 5,129 $ 41,693 $ 26,194 ============ ============ ============ ============ Net income per common share - basic Income before cumulative effect of change in accounting principle $ 0.35 $ 0.10 $ 0.76 $ 0.44 Cumulative effect of change in accounting principle - - - 0.05 ------------ ------------ ------------ ------------ Net income per common share - basic $ 0.35 $ 0.10 $ 0.76 $ 0.49 ============ ============ ============ ============ Net income per common share - diluted Income before cumulative effect of change in accounting principle $ 0.34 $ 0.09 $ 0.73 $ 0.42 Cumulative effect of change in accounting principle - - - 0.05 ------------ ------------ ------------ ------------ Net income per common share - diluted $ 0.34 $ 0.09 $ 0.73 $ 0.47 ============ ============ ============ ============ Weighted average common shares outstanding Basic 54,744 53,815 54,566 53,728 Diluted 57,102 55,337 56,739 55,186 (See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
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DENBURY RESOURCES INC. UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Amounts in thousands) Three Months Ended Six Months Ended June 30, June 30, --------------------- ---------------------- 2004 2003 2004 2003 -------- --------- --------- --------- Cash flow from operating activities: Net income $ 19,389 $ 5,129 $ 41,693 $ 26,194 Adjustments needed to reconcile to net cash flow provided by operations: Depreciation, depletion and amortization 28,161 23,130 55,485 46,683 Amortization of derivative contracts and other non-cash hedging adjustments 7,146 (751) 7,964 (2,261) Deferred income taxes 8,672 3,527 17,194 9,882 Deferred revenue - Genesis (599) - (1,110) - Loss on early retirement of debt - 17,629 - 17,629 Amortization of debt issue costs and other 285 325 748 840 Cumulative effect of change in accounting principle - - - (2,612) Changes in assets and liabilities: Accrued production receivable (3,410) 13,492 (10,836) (2,373) Trade and other receivables (546) (1,911) (1,773) (3,144) Derivative assets and liabilities (7,518) - (7,518) - Other assets - 335 - 5 Accounts payable and accrued liabilities (1,012) 561 711 2,214 Oil and gas production payable 3,230 (131) 5,028 3,739 Other liabilities (588) (793) (1,381) (745) -------- --------- --------- --------- Net cash provided by operations 53,210 60,542 106,205 96,051 -------- --------- --------- --------- Cash flow used for investing activities: Oil and natural gas expenditures (42,014) (38,041) (89,764) (70,709) Acquisitions of oil and gas properties (2,035) (5,931) (2,198) (9,624) Acquisitions of CO2 assets and capital expenditures (6,938) (6,469) (27,141) (13,373) Proceeds from oil and gas property sales 634 1,788 1,146 28,154 Increase in restricted cash (148) (210) (351) (356) Net purchases of other assets (850) (5,879) (1,154) (6,973) -------- --------- --------- --------- Net cash used for investing activities (51,351) (54,742) (119,462) (72,881) -------- --------- --------- --------- Cash flow from financing activities: Bank repayments - (15,000) (3,000) (125,000) Bank borrowings 5,000 75,000 13,000 85,000 Repayment of subordinated debt obligations, including redemption premium - (209,000) - (209,000) Issuance of subordinated debt, net of discount - (3) - 223,054 Issuance of common stock 4,795 1,645 8,674 2,970 Purchase of treasury stock (918) - (1,661) - Costs of debt financing (4) (264) (4) (4,786) -------- --------- --------- --------- Net cash provided (used) by financing activities 8,873 (147,622) 17,009 (27,762) -------- --------- --------- --------- Net increase (decrease) in cash and cash equivalents 10,732 (141,822) 3,752 (4,592) Cash and cash equivalents at beginning of period 17,208 161,170 24,188 23,940 -------- --------- --------- --------- Cash and cash equivalents at end of period $ 27,940 $ 19,348 $ 27,940 $ 19,348 ======== ========= ========= ========= Supplemental disclosure of cash flow information: Cash paid during the period for interest $ 514 $ 3,111 $ 9,463 $ 13,371 Cash paid during the period for income taxes 600 184 327 184 (See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
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DENBURY RESOURCES INC. UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS (Amounts in thousands) Three Months Ended Six Months Ended June 30, June 30, -------------------- --------------------- 2004 2003 2004 2003 -------- -------- -------- -------- Net income $ 19,389 $ 5,129 $ 41,693 $ 26,194 Other comprehensive income (loss), net of income tax: Change in fair value of derivative contracts, net of tax of $(5,926), $(8,269), $(12,671), and $(24,338), respectively (9,669) (13,491) (20,673) (39,710) Reclassification adjustments related to settlements of derivative contracts, net of tax of $10,348, $4,668, $15,770 and $14,789, respectively 16,884 7,615 25,730 24,129 -------- -------- -------- -------- Comprehensive income (loss) $ 26,604 $ (747) $ 46,750 $ 10,613 ======== ======== ======== ======== (See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
6 DENBURY RESOURCES INC. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 1. BASIS OF PRESENTATION Interim Financial Statements The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the instructions to Form 10-Q and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. Unless indicated otherwise or the context requires, the terms "we," "our," "us," "Denbury" or "Company" refer to Denbury Resources Inc. and its subsidiaries. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2003. Any capitalized terms used but not defined in these Notes to Unaudited Condensed Consolidated Financial Statements have the same meaning given to them in the Form 10-K. Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the fiscal year. In management's opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments (of a normal recurring nature) necessary to present fairly the consolidated financial position of Denbury as of June 30, 2004 and the consolidated results of its operations and cash flows for the three and six month periods ended June 30, 2004 and 2003. Certain prior period items have been reclassified to make the classification consistent with the classification in the most recent quarter. Stock-based Compensation We issue stock options to all of our employees under our stock option plan, which we account for utilizing the recognition and measurement principles of Accounting Principles Board Opinion 25, "Accounting for Stock Issued to Employees," and its related interpretations. Under these principles we do not recognize any stock-based employee compensation for stock option grants, as long as the exercise price is equal to the fair value of the underlying common stock on the date of grant. The following table illustrates the effect on net income and net income per common share as if we had applied the fair value recognition and measurement provisions of Statement of Financial Accounting Standards ("SFAS") No. 123, "Accounting for Stock-Based Compensation," as amended by SFAS No. 148, in accounting for our stock option plan.
Three Months Ended Six Months Ended June 30, June 30, -------------------------- --------------------- 2004 2003 2004 2003 -------- ------- -------- -------- Net income: (thousands) Net income, as reported...................................... $ 19,389 $ 5,129 $ 41,693 $ 26,194 Less: stock-based compensation expense applying fair value based method, net of related tax effects .................. 1,796 869 3,472 1,634 -------- ------- -------- -------- Pro-forma net income ........................................ $ 17,593 $ 4,260 $ 38,221 $ 24,560 ======== ======= ======== ======== Net income per common share As reported: Basic ..................................................... $ 0.35 $ 0.10 $ 0.76 $ 0.49 Diluted.................................................... 0.34 0.09 0.73 0.47 Pro forma: Basic ..................................................... $ 0.32 $ 0.08 $ 0.70 $ 0.46 Diluted ................................................... 0.32 0.08 0.70 0.45
2. NEW ACCOUNTING STANDARDS In July 2004, the Financial Accounting Standards Board ("FASB") issued a proposed FASB staff position that clarified the position that SFAS No. 142, "Goodwill and Other Intangible Assets," does not apply to the drilling and mineral rights of oil and gas producing entities that account for such rights in accordance with SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas 7 DENBURY RESOURCES INC. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Producing Companies." In question was whether acquired contractual mineral interests, both proved and undeveloped, should be classified separately as "intangible assets" on the balance sheet apart from other oil and gas property costs. Denbury and virtually all other companies in the oil and gas industry have historically included purchased contractual mineral rights in oil and gas properties on the balance sheet. The proposed FASB staff position will have no impact on the classification of Denbury's oil and gas property balances if the proposed staff position is adopted in its current state. 3. ASSET RETIREMENT OBLIGATIONS On January 1, 2003, we adopted the provisions of SFAS No. 143, "Accounting for Asset Retirement Obligations." In general, our future asset retirement obligations relate to future costs associated with plugging and abandonment of our oil and natural gas wells, dismantling our offshore production platforms, and removal of equipment and facilities from leased acreage and returning such land to its original condition. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred, discounted to its present value using our credit adjusted risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset. Prior to the adoption of this new standard, we recognized a provision for our asset retirement obligations each period as part of our depletion and depreciation calculation, based on the unit-of-production method. The adoption of SFAS No. 143 on January 1, 2003, required us to record (i) a $41.0 million liability for our future asset retirement obligations (an increase of $34.1 million in our liability for asset retirement obligations that we had recorded at December 31, 2002), (ii) a $34.4 million increase in oil and natural gas properties, (iii) a $3.9 million decrease in accumulated depreciation and depletion, and (iv) a $2.6 million gain as a cumulative effect adjustment of a change in accounting principle, net of taxes of $1.6 million. The following table summarizes the changes in our asset retirement obligations for the six months ended June 30, 2004.
Six Months Ended June 30, 2004 ---------------- (in thousands) Beginning asset retirement obligation, as of 12/31/2003.... $ 43,812 Liabilities incurred during period......................... 1,254 Liabilities settled during period.......................... (1,647) Accretion expense.......................................... 1,542 ---------------- Ending asset retirement obligation......................... $ 44,961 ================
At June 30, 2004, $1.9 million of our asset retirement obligation was classified in "Accounts payable and accrued liabilities" under current liabilities in our Condensed Consolidated Balance Sheets. We hold cash and liquid investments in escrow accounts that are legally restricted for certain of our asset retirement obligations. The balances of these escrow accounts were $9.9 million at June 30, 2004, and $9.5 million at December 31, 2003 and are included in "Other assets" in our Condensed Consolidated Balance Sheets. 4. NET INCOME PER COMMON SHARE Basic net income per common share is computed by dividing net income by the weighted average number of shares of common stock outstanding during the period. Diluted net income per common share is calculated in the same manner but also considers the impact on net income and common shares for the potential dilution from stock options and any other convertible securities outstanding. For the three and six month periods ended June 30, 2004 and 2003, there were no adjustments to net income for purposes of calculating diluted net income per common share. 8 DENBURY RESOURCES INC. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The following is a reconciliation of the weighted average common shares used in the basic and diluted net income per common share calculations for the three and six month periods ended June 30, 2004 and 2003 (shares in thousands).
Three Months Ended Six Months Ended June 30, June 30, ------------------------------- -------------------------- 2004 2003 2004 2003 ---------------- -------------- ------------- ------------ Weighted average common shares - basic....... 54,744 53,815 54,566 53,728 Potentially dilutive securities: Stock options.............................. 2,358 1,522 2,173 1,458 ---------------- -------------- ------------- ------------ Weighted average common shares - diluted..... 57,102 55,337 56,739 55,186 ================ ============== ============= ============
For the three months ended June 30, 2004 and 2003, common stock options to purchase approximately 32,000 and 1.0 million shares of common stock, and for the six months ended June 30, 2004 and 2003, common stock options to purchase approximately 361,000 and 1.0 million shares of common stock, respectively, were outstanding but excluded from the diluted net income per common share calculations, as the exercise prices of the options exceeded the average market price of the Company's common stock during these periods and were anti-dilutive to the calculations. 5. STOCK REPURCHASE PLAN In August 2003, we adopted a stock repurchase plan (the "Plan") to purchase shares of our common stock on the NYSE in order for such repurchased shares to be reissued to our employees who participate in Denbury's Employee Stock Purchase Plan. The Plan provides for purchases through an independent broker of 50,000 shares of Denbury's common stock per fiscal quarter for a period of approximately twelve months, or a total of 200,000 shares, during the period beginning August 13, 2003 and ending on July 31, 2004. In May 2004, the Board of Directors renewed the Plan for another year, for the period beginning July 1, 2004 and ending June 30, 2005. Purchases are to be made at prices and times determined at the discretion of the independent broker, provided however that no purchases may be made during the last ten business days of a fiscal quarter. During 2003, we purchased 100,000 shares at an average cost of $12.77 per share and from January 1, 2004 through June 30, 2004, we purchased 100,000 shares at an average cost of $16.61 per share. Through June 30, 2004, we have reissued 161,735 (80.9%) of these shares under Denbury's Employee Stock Purchase Plan. 6. RELATED PARTY TRANSACTIONS - GENESIS Interest in and Transactions with Genesis Denbury is the general partner and owns an aggregate of 9.25% interest in Genesis Energy, L.P. ("Genesis"), a publicly traded master limited partnership. Genesis has three primary lines of business: crude oil gathering and marketing, pipeline transportation, primarily in Mississippi, Texas, Alabama and Florida, and wholesale marketing of carbon dioxide. We are accounting for our 9.25% ownership in Genesis under the equity method of accounting as we have significant influence over the limited partnership; however, our control is limited under the limited partnership agreement and therefore we do not consolidate Genesis. Our equity in Genesis' net income for the three months ended June 30, 2004 and 2003 was $102,000 and $35,000, respectively, and for the six months ended June 30, 2004 and 2003 was $9,000 and $51,000, respectively. Genesis Energy, Inc., the general partner of which we own 100%, has guaranteed the bank debt of Genesis, which was $5.5 million as of June 30, 2004, and which debt includes $20.6 million in letters of credit of which $10.7 million are for Denbury's benefit to secure purchases of oil from Denbury. There are no guarantees by Denbury or any of its other subsidiaries of the debt of Genesis or of Genesis Energy, Inc. 9 DENBURY RESOURCES INC. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Genesis has historically been a purchaser of our crude oil and we anticipate future purchases of our crude oil production by Genesis. At June 30, 2004 and December 31, 2003, we had a production receivable from Genesis of $10.7 million and $6.9 million, respectively. We recorded oil sales to Genesis of $23.4 million and $11.2 million for the three months ended June 30, 2004 and 2003, respectively, and $42.3 million and $23.6 million for the six months ended June 30, 2004 and 2003, respectively. Denbury received other miscellaneous payments from Genesis during the 2004 period, including $60,000 in director fees for certain executive officers of Denbury that are board members of Genesis, and $253,000 in pro rata distributions from Genesis. CO2 Volumetric Production Payment In November 2003, we sold 167.5 Bcf of CO2 to Genesis for $24.9 million ($23.9 million as adjusted for interim cash flows from the September 1, 2003 effective date and for transaction costs) under a volumetric production payment ("VPP"). This sale included the assignment to Genesis of three of our existing long-term commercial CO2 supply agreements with our industrial customers, which represented approximately 60% of our then current industrial CO2 sales volumes. Pursuant to the VPP, Genesis may take up to 52.5 MMcf/d of CO2 through 2009, 43.0 MMcf/d from 2010 through 2012, and 25.2 MMcf/d to the end of the term. We have recorded the net proceeds of the sale as deferred revenue and will recognize such revenue as CO2 is delivered during the term of the VPP. At June 30, 2004, $22.5 million was recorded as deferred revenue ($2.1 million in current liabilities and $20.4 million long term). During the three and six months ended June 30, 2004, we recognized deferred revenue of $0.6 million and $1.1 million, respectively, for deliveries under the VPP. We provide Genesis with certain processing and transportation services in connection with this agreement for a fee of $0.16 per Mcf of CO2 delivered to their industrial customers, which resulted in $0.7 million and $1.2 million in revenue to Denbury for the three and six months ended June 30, 2004, respectively. Summarized financial information of Genesis Energy, L.P. (amounts in thousands):
Three Months Ended June 30, Six Months Ended June 30, ---------------------------- --------------------------- 2004 2003 2004 2003 --------- --------- --------- --------- Revenues................................. $ 232,107 $ 146,670 $ 431,019 $ 322,352 Cost of sales............................ 230,619 145,763 430,143 320,521 Other income (expenses).................. (389) 983 (782) 938 --------- --------- --------- --------- Net income............................... $ 1,099 $ 1,890 $ 94 $ 2,769 ========= ========= ========= =========
June 30, December 31, 2004 2003 -------- -------- Current assets............................... $ 82,606 $ 88,211 Non-current assets........................... 58,771 58,904 -------- -------- Total assets .............................. $141,377 $147,115 ======== ======== Current liabilities ......................... $ 85,763 $ 87,244 Non-current liabilities...................... 5,500 7,000 Partners' capital............................ 50,114 52,871 -------- -------- Total liabilities and partners' capital.... $141,377 $147,115 ======== ========
7. PRODUCT PRICE HEDGING CONTRACTS We enter into various financial contracts to hedge our exposure to commodity price risk associated with anticipated future oil and natural gas production. We do not hold or issue derivative financial instruments for trading purposes. These contracts have historically consisted of price floors, collars and fixed price swaps. We generally attempt to hedge between 33% and 75% of our anticipated production each year to provide us with a reasonably certain amount of cash flow to cover most of our budgeted exploration and development expenditures without incurring significant debt, although our hedging percentage may vary relative to our debt levels. For example, when our debt levels are high, we may hedge a higher percentage of our production than when our debt levels are low. When we make an acquisition, we attempt to hedge a large percentage, up to 100%, of the forecasted production for the subsequent one to three years following the acquisition in order to help provide us with a minimum return on our investment. Much of our hedging activity has been with collars, although for the 2002 COHO acquisition, we also used swaps in order to lock in the prices used in our economic forecasts. In the second quarter of 2004, we purchased price floors or puts relating to a portion of 10 DENBURY RESOURCES INC. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS our 2005 oil production, allowing us to retain any upside from increases in commodity prices. All of the mark-to-market valuations used for our financial derivatives are provided by external sources and are based on prices that are actively quoted. We manage and control market and counterparty credit risk through established internal control procedures which are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures, and diversification. The following is a summary of the net loss on our commodity hedge settlements which are recorded in "Revenues" in our Condensed Consolidated Statements of Operations (amounts in thousands):
Three Months Ended Six Months Ended June 30, June 30, ------------------------------- ------------------------- 2004 2003 2004 2003 --------------- -------------- ------------ ------------ Oil hedge contracts $ (9,795) $ (2,633) $ (20,316) $ (11,371) Gas hedge contracts (4,929) (10,723) (8,676) (29,670) Contracts not qualifying for hedge accounting (3,515) - (3,515) - --------------- -------------- ------------ ------------ Net loss $ (18,239) $(13,356) $ (32,507) $ (41,041) =============== ============== ============ ============
The following is a summary of "Amortization of derivative contracts and other non-cash hedging adjustments," included in our Condensed Consolidated Statements of Operations (amounts in thousands):
Three Months Ended Six Months Ended June 30, June 30, --------------- --------------- 2004 2003 2004 2003 ----- ---- ---- ---- Hedge ineffectiveness (income) expense on contracts qualifying for hedge accounting $ (785) $ 321 $ 33 $ (138) Amortization of contract premiums - 297 - 591 Reclassification of accumulated other comprehensive income balance and adjustments to fair value associated with termination of contracts designated to offshore production 8,112 - 8,112 - Adjustments to fair value and amortization of ineffecitve hedge no longer qualifying for hedge accounting 1,349 - 1,349 - Adjustments to fair value associated with contracts to be transferred in sale of offshore production (1,530) - (1,530) - Amortization of terminated Enron-related hedges over the original contract periods - (1,369) - (2,714) ------ ------ ------- -------- $7,146 $ (751) $ 7,964 $ (2,261) ====== ====== ========= ========
Upon reaching a verbal agreement on the offshore property sale, subject primarily to the purchaser's further due diligence, we entered into natural gas swaps on a total of 23.6 Bcf for the period of July 2004 through December 2005, covering the anticipated natural gas production from our offshore properties for that period, with the understanding with the prospective purchaser that these hedges would be transferred to the purchaser upon closing. These swaps did not qualify for hedge accounting and by August 6, 2004, we had assigned them to the purchaser of the offshore properties. The mark to market adjustment on these contracts from the time of purchase through June 30, 2004 totaled approximately $1.5 million. At about the same time, with the expectation that the offshore transaction would be consummated, we retired, by purchasing offsetting contracts, 20 MMcf/d of our natural gas hedges for July to December of 2004, at a cost of approximately $3.9 million. Since the natural gas hedges we retired were not the same as those hedges previously designated for offshore production, we recognized a charge to earnings in the second quarter of 2004 of approximately $8.1 million, representing the then current mark to market value of the offshore hedges. The difference between this charge and the amount paid to retire 20 MMcf/d will be reversed over the remainder of 2004. We also had minor charges and credits for hedge ineffectiveness and a net charge for a portion of our oil hedges that are no longer considered 11 DENBURY RESOURCES INC. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS effective during the second quarter of 2004, resulting in a net charge of $7.1 million for the quarter and $8.0 million for the six months ended June 30, 2004. During the three and six months ended June 30, 2003, we had minor charges or credits relating to the hedge ineffectiveness, charges for the amortization of contract premiums, and credits relating to the reclassification of amounts out of "Accumulated other comprehensive loss" into income relating to our former Enron hedges, resulting in a net credit of $751,000 for the three months and $2.3 million for the six months ended June 30, 2003. Derivative Contracts designated as a hedge of forecasted production at June 30, 2004: Crude Oil Contracts: - -------------------
NYMEX Contract Prices Per Bbl ----------------------------- Collar Prices ---------------------- Fair Value at Type of Contract and Period Bbls/d Swap Price Floor Price Floor Ceiling June 30, 2004 - -------------------------------- ----------- ------------ ------------ ---------- ----------- ----------------- Swap Contracts (in thousands) July 2004 - Dec. 2004 4,500 $ 23.00 $ - $ - $ - $ (11,363) July 2004 - Dec. 2004 2,500 22.89 - - - (6,363) Jan. 2005 - Dec. 2005 7,500 - 27.50 - - 2,781
Natural Gas Contracts: - ---------------------
NYMEX Contract Prices Per MMBtu ------------------------------- Collar Prices ---------------------- Fair Value at Type of Contract and Period MMBtu/d Swap Price Floor Price Floor Ceiling June 30, 2004 - -------------------------------- ----------- ------------ ------------ ---------- ----------- ----------------- Collar Contracts (in thousands) July 2004 - Dec. 2004 30,000 $ - $ - $ 3.50 $ 4.45 $ (10,406) July 2004 - Dec. 2004 10,000 - - 3.00 5.82 (1,271) Jan. 2005 - Dec. 2005 15,000 - - 3.00 5.50 (5,534)
12 DENBURY RESOURCES INC. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Derivative Contracts not designated as a hedge: Crude Oil Contracts: - -------------------
NYMEX Contract Prices Per Bbl ----------------------------- Contract discontinued from hedge accounting due to failing ongoing effectiveness assessment Collar Prices ---------------------- Fair Value at Type of Contract and Period Bbls/d Swap Price Floor Price Floor Ceiling June 30, 2004 - ---------------------------------------------------------------------------------------------------------------- (in thousands) July 2004 - Dec. 2004 2,500 $ 23.08 $ - $ - $ - $ (6,276)
Natural Gas Contracts: - ---------------------
NYMEX Contract Prices Per MMBtu ------------------------------- Contracts purchased for planned divestiture Collar Prices ---------------------- Fair Value at Type of Contract and Period MMBtu/d Swap Price Floor Price Floor Ceiling June 30, 2004 - -------------------------------- ------------------------------------------------------------------------------- (in thousands) July 2004 - Dec. 2004 21,200 $ 6.50 $ - $ - $ - $ 644 July 2004 - Dec. 2004 23,000 6.44 - - - 601 Jan. 2005 - Oct. 2005 19,800 6.18 - - - 270 Jan. 2005 - Dec. 2005 26,000 6.11 - - - 15 Offsetting Contracts Collar Prices ---------------------- Fair Value at Type of Contract and Period MMBtu/d Call Price Put Price Floor Ceiling June 30, 2004 - -------------------------------- ----------- ------------ ------------ ---------- ----------- ----------------- (in thousands) July 2004 - Dec. 2004 15,000 $ - $ - $ 3.00 $ 5.87 $ (1,822) July 2004 - Dec. 2004 15,000 5.87 - - - 1,822 July 2004 - Dec. 2004 5,000 - - 3.00 5.82 (636) July 2004 - Dec. 2004 5,000 5.82 3.00 - - 636
At June 30, 2004, our derivative contracts were recorded at their fair value, which was a net liability of $36.9 million. To the extent our hedges are considered effective, this fair value liability, net of income taxes, is included in "Accumulated other comprehensive loss" reported under Stockholders' equity in our Condensed Consolidated Balance Sheets. The balance in accumulated other comprehensive loss of $22.1 million at June 30, 2004, represents the deficit in the fair market value of our derivative contracts as compared to the cost of our hedges, net of income taxes. Of the $22.1 million in accumulated other comprehensive loss as of June 30, 2004, $19.3 million relates to current hedging contracts that will expire within the next 12 months. 8. CONDENSED CONSOLIDATING FINANCIAL INFORMATION On December 29, 2003, we amended the indenture for our 7.5% Senior Subordinated Notes due 2013 to reflect our new holding company organizational structure. As part of this restructuring, our indenture was amended so that both Denbury Resources Inc. (the new holding company) and Denbury Onshore, LLC (formerly the parent company and now a wholly-owned subsidiary) became co-obligors on our subordinated debt. Prior to this restructure, Denbury Resources Inc., as the parent company, was the sole obligor. Our subordinated debt is fully and unconditionally guaranteed by Denbury Resources Inc.'s significant subsidiaries. Genesis Energy, Inc., the subsidiary that holds the Company's investment in Genesis Energy, L.P., is not a guarantor of our subordinated debt. Our equity interest in the results of operations of Genesis is reflected through the equity method by one of our significant subsidiaries, Denbury Gathering & Marketing. The following is condensed consolidating financial information for Denbury Resources Inc., Denbury Onshore, LLC, and significant subsidiaries: 13 DENBURY RESOURCES INC. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Condensed Consolidating Balance Sheets
June 30, 2004 ---------------------------------------------------------------------------- Denbury Denbury Resources Inc. Onshore LLC Denbury (Parent and Co- (Issuer and Co- Guarantor Resources Inc. Obligor) Obligor) Subsidiaries Eliminations Consolidated -------------- --------------- ------------- -------------- --------------- Amounts in thousands ASSETS Current assets..................................... $ 7,029 $ 98,141 $ 34,477 $ - $ 139,647 Property and equipment ............................ - 618,265 299,915 - 918,180 Investment in subsidiaries (equity method)......... 468,014 - 240,814 (701,640) 7,188 Other assets....................................... - 11,623 4,546 - 16,169 -------------- --------------- ------------- -------------- --------------- Total assets ................................. $ 475,043 $ 728,029 $ 579,752 $ (701,640) $ 1,081,184 ============== =============== ============= ============== =============== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities................................ $ 76 $ 127,912 $ 3,297 $ - $ 131,285 Long-term liabilities ............................. (3,140) 366,491 108,441 - 471,792 Stockholders' equity .............................. 478,107 233,626 468,014 (701,640) 478,107 -------------- --------------- ---------------------------- --------------- Total liabilities and stockholders' equity.... $ 475,043 $ 728,029 $ 579,752 $ (701,640) $ 1,081,184 ============== =============== ============= ============== ===============
December 31, 2003 ----------------------------------------------------------------------------- Denbury Denbury Resources Inc. Onshore LLC Denbury (Parent and Co- (Issuer and Co- Guarantor Resources Inc. Obligor) Obligor) Subsidiaries Eliminations Consolidated -------------- --------------- ------------- -------------- --------------- Amounts in thousands ASSETS Current assets .................................... $ 1 $ 85,109 $ 23,045 $ - $ 108,155 Property and equipment ............................ - 560,038 292,473 - 852,511 Investment in subsidiaries (equity method) ........ 421,201 - 210,803 (624,554) 7,450 Other assets ...................................... - 11,186 3,319 - 14,505 -------------- --------------- ------------- -------------- --------------- Total assets.................................. $ 421,202 $ 656,333 $ 529,640 $ (624,554) $ 982,621 ============== =============== ============= ============== =============== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities................................ $ - $ 119,364 $ 7,210 $ - $ 126,574 Long-term liabilities ............................. - 333,616 101,229 - 434,845 Stockholders' equity............................... 421,202 203,353 421,201 (624,554) 421,202 -------------- --------------- ------------- -------------- --------------- Total liabilities and stockholders' equity.... $ 421,202 $ 656,333 $ 529,640 $ (624,554) $ 982,621 ============== =============== ============= ============== ===============
14 DENBURY RESOURCES INC. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Condensed Consolidating Statements of Operations
Three Months Ended June 30, 2004 --------------------------------------------------------------------------- Denbury Denbury Resources Inc. Onshore LLC Denbury (Parent and Co- (Issuer and Co- Guarantor Resources Inc. Obligor) Obligor) Subsidiaries Eliminations Consolidated -------------- --------------- ------------- -------------- --------------- Amounts in thousands Revenues.................................... $ - $ 71,928 $ 30,814 $ - $ 102,742 Expenses ................................... 88 56,325 17,393 - 73,806 -------------- ---------------- ------------ -------------- --------------- Income (loss) before the following: (88) 15,603 13,421 - 28,936 Equity in net earnings of subsidiaries ... 19,448 - 10,510 (29,856) 102 -------------- ---------------- ------------ -------------- --------------- Income before income taxes.................. 19,360 15,603 23,931 (29,856) 29,038 Income tax provision (benefit).............. (29) 5,195 4,483 - 9,649 -------------- ---------------- ------------ -------------- --------------- Net income ................................. $ 19,389 $ 10,408 $ 19,448 $ (29,856) $ 19,389 ============== ================ ============ ============== ===============
Three Months Ended June 30, 2003 ----------------------------------------------------------- Denbury Resources Inc. Denbury (Parent and Guarantor Resources Inc. Issuer) Subsidiaries Eliminations Consolidated --------------- ------------ -------------- --------------- Amounts in thousands Revenues................................................... $ 58,565 $ 25,623 $ - $ 84,188 Expenses................................................... 62,583 14,077 - 76,660 --------------- ------------ -------------- --------------- Income (loss) before the following: (4,018) 11,546 - 7,528 Equity in net earnings of subsidiaries .................. 7,939 35 (7,939) 35 --------------- ------------ -------------- --------------- Income before income taxes................................. 3,921 11,581 (7,939) 7,563 Income tax provision (benefit)............................. (1,208) 3,642 - 2,434 --------------- ------------ -------------- --------------- Net income................................................. $ 5,129 $ 7,939 $ (7,939) $ 5,129 =============== ============ ============== ===============
15 DENBURY RESOURCES INC. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Condensed Consolidating Statements of Operations (continued)
Six Months Ended June 30, 2004 --------------------------------------------------------------------------- Denbury Denbury Resources Inc. Onshore LLC Denbury (Parent and Co- (Issuer and Co- Guarantor Resources Inc. Obligor) Obligor) Subsidiaries Eliminations Consolidated -------------- ---------------- ------------ -------------- --------------- Amounts in thousands Revenues................................. $ - $ 143,012 $ 57,478 $ - $ 200,490 Expenses ................................ 88 105,878 32,550 - 138,516 -------------- ---------------- ------------ -------------- --------------- Income (loss) before the following: (88) 37,134 24,928 - 61,974 Equity in net earnings of subsidiaries ... 41,752 - 25,118 (66,861) 9 -------------- ---------------- ------------ -------------- --------------- Income before income taxes................ 41,664 37,134 50,046 (66,861) 61,983 Income tax provision (benefit)............ (29) 12,025 8,294 - 20,290 -------------- ---------------- ------------ -------------- --------------- Net income ............................... $ 41,693 $ 25,109 $ 41,752 $ (66,861) $ 41,693 ============== ================ ============ ============== ===============
Six Months Ended June 30, 2003 ------------------------------------------------------------- Denbury Resources Inc. Denbury (Parent and Guarantor Resources Inc. Issuer) Subsidiaries Eliminations Consolidated ---------------- ------------ ------------- --------------- Amounts in thousands Revenues.................................................. $ 115,850 $ 54,770 $ - $ 170,620 Expenses.................................................. 106,903 28,667 - 135,570 ---------------- ------------ ------------- --------------- Income before the following: 8,947 26,103 - 35,050 Equity in net earnings of subsidiaries ................. 16,434 51 (16,434) 51 ---------------- ------------ ------------- --------------- Income before income taxes and cumulative effect of a change in accounting principle... 25,381 26,154 (16,434) 35,101 Income tax provision...................................... 3,168 8,351 - 11,519 ---------------- ------------ ------------- --------------- Net income before cumulative effect of a change in accounting principle.................................... 22,213 17,803 (16,434) 23,582 Cumulative effect of a change in accounting principle, net of income taxes..................................... 2,612 (1,369) 1,369 2,612 ---------------- ------------ ------------- --------------- Net income................................................ $ 24,825 $ 16,434 $ (15,065) $ 26,194 ================ ============ ============= ===============
16 DENBURY RESOURCES INC. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Condensed Consolidating Statements of Cash Flows
Six Months Ended June 30, 2004 ---------------------------------------------------------------------------- Denbury Denbury Resources Inc. Onshore LLC Denbury (Parent and Co- (Issuer and Co- Guarantor Resources Inc. Obligor) Obligor) Subsidiaries Eliminations Consolidated ---------------- --------------- ------------ -------------- --------------- Amounts in thousands Cash flow from operations.............. $ (7,013) $ 87,668 $ 25,550 $ - $ 106,205 Cash flow from investing activities.... - (93,975) (25,487) - (119,462) Cash flow from financing activities.... 7,013 9,996 - - 17,009 ---------------- --------------- ------------ -------------- --------------- Net increase in cash................... - 3,689 63 - 3,752 Cash, beginning of period.............. 1 24,174 13 - 24,188 ---------------- --------------- ------------ -------------- --------------- Cash, end of period.................... $ 1 $ 27,863 $ 76 $ - $ 27,940 ================ =============== ============ ============== ===============
Six Months Ended June 30, 2003 ----------------------------------------------------------- Denbury Resources Inc. Denbury (Parent and Guarantor Resources Inc. Issuer) Subsidiaries Eliminations Consolidated --------------- ------------- -------------- -------------- Amounts in thousands Cash flow from operations................................ $ 72,219 $ 23,832 $ - $ 96,051 Cash flow from investing activities...................... (49,561) (23,320) - (72,881) Cash flow from financing activities...................... (27,762) - - (27,762) --------------- ------------- -------------- -------------- Net increase (decrease) in cash.......................... (5,104) 512 - (4,592) Cash, beginning of period................................ 20,281 3,659 - 23,940 --------------- ------------- -------------- -------------- Cash, end of period...................................... $ 15,177 $ 4,171 $ - $ 19,348 =============== ============= ============== ==============
9. SUBSEQUENT EVENT - SALE OF DENBURY OFFSHORE, INC. On July 20, 2004, we closed the sale of Denbury Offshore, Inc., a subsidiary that held our offshore assets, for $200 million before adjustments. The sale price was based on the asset value as of April 1, 2004, which means that the net revenue and expenses between April 1st and closing, as well as expenses of the sale and other contractual adjustments, will adjust the purchase price. On July 20, 2004, we received $187.0 million in cash from the purchaser, with such amount subject to a post-closing reconciliation within 90 days. We excluded two significant items from the sale: (i) a recently drilled discovery well at High Island A-6 and (ii) certain deep rights at West Delta 27. The well at High Island A-6 should be on production late this year, if not sold, and we are in the process of selling a substantial portion of the deep rights at West Delta 27 for an anticipated minor amount of cash and a carried interest in a deep exploratory well. We used $85 million of the sales proceeds to retire our bank debt, project that we will pay approximately $22 million in income taxes related to the sale, and expect to have between $70 to $75 million of cash remaining from the sale after payment of these and other expenses related to the transaction. We expect to incur approximately $1.6 million in employee severance expense in the third quarter related to employees terminated in the sale transaction. Also, our bank borrowing base was reduced from $220 million to $175 million as a result of the sale. Our offshore properties made up approximately 12.5% of our year-end 2003 proved reserves (approximately 96 Bcfe as of December 31, 2003) and represented approximately 25% of our 2004 second quarter production (9,114 BOE/d). 17 DENBURY RESOURCES INC. Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - -------------------------------------------------------------------------------- You should read the following in conjunction with our financial statements contained herein and our Form 10-K for the year ended December 31, 2003, along with Management's Discussion and Analysis of Financial Condition and Results of Operations contained in such Form 10-K. Any terms used but not defined in the following discussion have the same meaning given to them in the Form 10-K. We are an independent oil and gas company engaged in acquisition, development and exploration activities in the U.S. Gulf Coast region. We are the largest oil and natural gas producer in Mississippi, own the largest reserves of carbon dioxide ("CO2") used for tertiary oil recovery east of the Mississippi River, and hold significant operating acreage onshore Louisiana. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling, and proven engineering extraction processes, including secondary and tertiary recovery operations. Our corporate headquarters are in Plano, Texas (a suburb of Dallas), and we have two primary field offices located in Houma, Louisiana, and Laurel, Mississippi. Overview Increased focus on tertiary operations. Since we acquired our first carbon dioxide tertiary flood in Mississippi five years ago, we have gradually increased our emphasis on these types of operations. We particularly like this play because of its risk profile, rate of return and lack of competition in our operating area. Generally, from East Texas to Florida, there are no significant natural sources of carbon dioxide except our own, and these large volumes of CO2 that we own drive the play. Please refer to the sections entitled "Overview" and "CO2 Operations" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in our 2003 Form 10-K for further information regarding these operations, their potential, and the ramifications of this change in focus. Sale of offshore operations. On July 20, 2004, we closed the sale of Denbury Offshore, Inc., a subsidiary that held our offshore assets, for $200 million before adjustments. The sale price was based on an asset value as of April 1, 2004, which means that the net revenue and expenses between April 1st and closing, as well as expenses of the sale and other contractual adjustments, will adjust the purchase price. On July 20, 2004, we received $187.0 million in cash from the purchaser, with such amount subject to a post-closing reconciliation within 90 days. We excluded two significant items from the sale: (i) a recently drilled discovery well at High Island A-6 and (ii) certain deep rights at West Delta 27. The well at High Island A-6 should be on production late this year, if not sold, and we are in the process of selling a substantial portion of the deep rights at West Delta 27 for an anticipated minor amount of cash and a carried interest in a deep exploratory well. We used $85 million of the sales proceeds to retire our bank debt, project that we will pay approximately $22 million in income taxes related to the sale, and expect to have between $70 and $75 million of cash remaining from the sale after payment of these and other expenses related to the transaction. We have increased our 2004 exploration and development budget by $20 million to $205 million as a result of the additional cash generated from the sale, and expect our 2005 budget to be at that or a higher level. We expect to spend the cash generated from the offshore sale over the next one to two years. Our offshore properties made up approximately 12.5% of our year-end 2003 proved reserves (approximately 96 Bcfe as of December 31, 2003) and represented approximately 25% of our 2004 second quarter production (9,114 BOE/d). Operating results. Our adjusted cash flow from operations (non-GAAP measure, see "Results of Operations - operating results" below) was close to record levels in the second quarter of 2004, primarily due to record high commodity prices. Net income was strong, but less than in the first quarter of 2004 as a result of $7.1 million of charges relating to our oil and natural gas hedges, primarily caused by the early retirement of 20 MMcf/d of our 2004 natural gas hedges upon our expectation that the offshore sale would be consummated (see "Market Risk Management" for a further discussion). Commodity prices for the quarter were 20% higher than the prices in the comparable quarter in 2003 and production was 4% higher than production levels in the comparable quarter of 2003, but these gains were partially offset by higher hedging payments, operating expenses, general and administrative expenses, and depreciation and amortization expenses in the second quarter of 2004. Net income increased 278% in the second quarter of 2004 to $19.4 million, as compared to the second quarter of 2003, with near-record cash flow from operations of $53.2 million in the second quarter of 2004, compared to $60.5 million in the second quarter of 2003. See "Results of Operations" for a more thorough discussion of our operating results. 18 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Capital Resources and Liquidity During the first half of 2004, we spent $89.8 million on oil and natural gas exploration and development expenditures, $19.7 million on CO2 exploration and development expenditures, and approximately $9.6 million on property acquisitions (virtually all CO2 related), for total capital expenditures of approximately $119.1 million. We funded these expenditures with $106.2 million of cash flow from operations and $10.0 million of net bank borrowings, with the balance coming from available cash and other sources. Adjusted cash flow from operations (a non-GAAP measure defined as cash flow from operations before the changes in assets and liabilities as discussed below under "Results of Operations-Operating Results") was $122.0 million, with the difference of $15.8 million between the two amounts primarily relating to $7.5 million spent during the second quarter to acquire 7,500 Bbls/d of oil puts or floors for 2005 and to retire 20 MMcf/d of natural gas hedges for the balance of 2004, and a $10.8 million increase in accrued production receivables since year-end as a result of the higher commodity prices during the second quarter of 2004, partially offset by changes in other assets and liabilities. At June 30, 2004, we had total debt of $310 million, consisting of $225 million of 7.5% subordinated notes due in 2013 and $85 million of bank debt. On July 20, 2004, we paid off our bank debt with the proceeds from the sale of our offshore operations (see "Overview - sale of offshore operations"), leaving us with $225 million of outstanding subordinated debt and an estimated $70 to $75 million of incremental cash from the sale, after the anticipated payment of estimated income taxes and other expenses associated with the offshore sale, or net debt of approximately $150 million. Our bank borrowing base was reduced from $220 million to $175 million as result of the sale, all of which was available as of August 9, 2004. Our 2004 capital budget was increased to $205 million, as a result of our additional liquidity after the offshore sale. At current commodity prices, we estimate that we will use only a small portion of the excess cash generated from the offshore sale for these purposes for the remainder of 2004. We are considering another transaction with Genesis Energy, L.P. ("Genesis") to sell them another volumetric production payment of CO2 and assign them most of our remaining long-term CO2 supply agreements with our industrial customers, further increasing our cash position by an estimated $5 million to $10 million. We plan to invest our anticipated excess cash over the next one to two years by accelerating our development of CO2 reserves and deliverability at Jackson Dome, accelerating, to the extent possible, our second phase of tertiary operations planned for East Mississippi, and increasing our expenditures elsewhere in areas such as the Barnett Shale. We are also continuing our search for property acquisitions, particularly those that have future tertiary potential. Although we now control most of the fields along our CO2 pipeline, there are a few remaining smaller fields with this potential that we do not control, and we are continuing to acquire additional interests in the fields that we currently own. We also may seek oil fields in other areas, which may have future tertiary opportunities, as well as conventional development and exploration projects. Off-Balance Sheet Arrangements Commitments and Obligations Our obligations that are not currently recorded on our balance sheet are our operating leases and various obligations for development and exploratory expenditures arising from purchase agreements, our capital expenditure program, or other transactions common to our industry. In addition, in order to recover our undeveloped proved reserves, we must also fund the associated future development costs as forecasted in the proved reserve reports. Further, one of our subsidiaries, the general partner of Genesis Energy, L.P., has guaranteed the bank debt of Genesis (which as of June 30, 2004, consisted of $5.5 million of debt and $20.6 million in letters of credit, $10.7 million of which are for Denbury's benefit) and we have delivery obligations to deliver CO2 to our industrial customers. Our hedging obligations are discussed in Note 7 to the Unaudited Condensed Consolidated Financial Statements. Neither the amounts nor the terms of these commitments or contingent obligations have changed significantly from the year-end 2003 amounts reflected in our Form 10-K filed in March 2004. Please refer to Management's Discussion and Analysis of Financial Condition and Results of Operations contained in our 2003 Form 10-K for further information regarding our commitments and obligations. 19 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Results of Operations CO2 Operations As described in the "Overview" section above, our CO2 operations are becoming an ever-increasing part of our business and operations. We believe that there are significant additional oil reserves and production that can be obtained through the use of CO2, and we have outlined certain of this potential in our annual report and other public disclosures. In addition to its long-term effect, this shift in focus impacts certain trends in our current and near-term operating results. Please refer to Management's Discussion and Analysis of Financial Condition and Results of Operations and the section entitled "CO2 Operations" contained in our 2003 Form 10-K for further information regarding these issues. To date during 2004, we have drilled or sidetracked four additional CO2 wells, two of which were producing as of August 9, 2004, and two of which were still being completed. During the first half of the year, our CO2 production averaged 234.0 MMcf/d. We used 65% of this, or 153.2 MMcf/d, in our tertiary operations, and sold the balance to our industrial customers or to Genesis pursuant to our volumetric production payment. We believe that upon completion of our two latest CO2 wells that our production capacity of CO2 will grow to at least 350 MMcf/d. Based on preliminary reserve estimates, we believe that the last two CO2 wells will increase our proven CO2 reserves by approximately [1.0 Tcf], a significant increase from the 1.6 Tcf of proven CO2 reserves as of December 31 2003. With the success of these last two CO2 wells, we should have sufficient CO2 reserves for our planned expansion of CO2 operations into East Mississippi. We have scheduled a 3-D seismic shoot over the Jackson Dome area in the second half of 2004 to help us delineate our future CO2 drilling efforts there. We plan to further expand and increase our CO2 reserves and production capability in order to provide enough CO2 for our planned expansion of our tertiary operations, a significant focus and growth area for us for the foreseeable future. Our oil production from our CO2 tertiary recovery activities in the second quarter of 2004 increased 5% over first quarter 2004 levels and 46% over second quarter 2003 levels, to 6,603 Bbls/d in the second quarter of 2004, with most of the increase since the second quarter of 2003 occurring at Mallalieu Field. Production at Mallalieu averaged 3,172 Bbls/d during the second quarter of 2004, as compared to 3,105 Bbls/d in the prior quarter and 1,388 Bbls/d during the second quarter of 2003. We expect our tertiary oil production to continue to grow during 2004 to a projected average of approximately 7,000 Bbls/d for the year, with additional increases expected at all three of our ongoing tertiary operations at Mallalieu, Little Creek and McComb Fields. During the second quarter, we have seen our first minor production response from McComb Field as a result of CO2 injections which commenced late in 2003, averaging 121 Bbls/d for the second quarter, although we do not expect oil production from this field to be significant until late in 2004. We spent approximately $0.11 per Mcf to produce our CO2 during the first half of 2004, less than the 2003 average of $0.15 per Mcf, as we did not have any significant workover costs on CO2 wells during the first half of 2004. However, as a result of continued high oil prices, CO2 royalty expenses increased, partially offsetting other operating expense savings, as certain of our CO2 royalty payments increase if the price of oil increases beyond a certain threshold. Our total cost per thousand cubic feet of CO2 during the first half of 2004 was approximately $0.20, after inclusion of depreciation and amortization expense, still significantly less than the $0.37 per thousand cubic feet that would have been paid had we been paying under the purchase contract that existed at the time we acquired the CO2 properties in February 2001. For the first half of 2004, our operating costs for our tertiary properties averaged $9.94 per BOE, less than the $10.56 per BOE average in the first half of 2003 and our 2003 annual average of $11.34 per BOE. The savings were a result of the lower cost to produce CO2 discussed above, higher oil production levels, and the realization of approximately $174,000 from the sale of CO2 Kyoto emission reduction credits generated by the re-injection of CO2. In the first quarter of 2003, we received $232,000 from the sale of emission reduction credits. Our net operating margin from the sale of CO2 to industrial customers decreased in the first half of 2004 to $2.6 million, down from $3.8 million during the first half of 2003, primarily related to the volumetric production payment we sold to Genesis at a lower average price per thousand cubic foot than we received from the industrial customers in the prior year. We received cash from the Genesis volumetric production payment when the transaction was consummated in the fourth quarter of 2003, thus $1.1 million of the industrial sale revenue is non-cash recognition of deferred revenue. 20 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Operating Results As summarized in the "Overview" section above, higher commodity prices and production, partially offset by higher hedge payments and expenses, resulted in near-record quarterly cash flow from operations and strong earnings. During the first quarter of 2003, we implemented SFAS No. 143, "Accounting for Asset Retirement Obligations," as more fully discussed below under "Depletion, Depreciation and Amortization." The adoption of SFAS No. 143 was recorded as a cumulative effect adjustment of a change in accounting principle, net of income taxes, in our Unaudited Condensed Consolidated Statements of Operations and is listed below on both a gross and per share basis.
Three Months Ended Six Months Ended June 30, June 30, - ------------------------------------------------------------------ ---------------------------- --------------------------- Amounts in thousands, except per share amounts 2004 2003 2004 2003 - ------------------------------------------------------------------ ------------- ------------- ------------- ------------ Income before cumulative effect of a change in accounting principle $ 19,389 $ 5,129 $ 41,693 $ 23,582 Cumulative effect of a change in accounting principle, net of income tax expense of $1,600 - - - 2,612 ------------- ------------- ------------- ------------ Net income $ 19,389 $ 5,129 $ 41,693 $ 26,194 - ------------------------------------------------------------------ ------------- ------------- ------------- ------------ Net income per common share - basic: Income before cumulative effect of a change in accounting principle $ 0.35 $ 0.10 $ 0.76 $ 0.44 Cumulative effect of a change in accounting principle - - - 0.05 ------------- ------------- ------------- ------------ Net income per common share - basic $ 0.35 $ 0.10 $ 0.76 $ 0.49 - ------------------------------------------------------------------ ------------- ------------- ------------- ------------ Net income per common share - diluted: Income before cumulative effect of a change in accounting principle $ 0.34 $ 0.09 $ 0.73 $ 0.42 Cumulative effect of a change in accounting principle - - - 0.05 ------------- ------------- ------------- ------------ Net income per common share - diluted $ 0.34 $ 0.09 $ 0.73 $ 0.47 - ------------------------------------------------------------------ ------------- ------------- ------------- ------------ Adjusted cash flow from operations (see below) $ 63,054 $ 48,989 $ 121,974 $ 96,355 Net change in assets and liabilities relating to operations (9,844) 11,553 (15,769) (304) - ------------------------------------------------------------------ ------------- ------------- ------------- ------------ Cash flow from operations (1) $ 53,210 $ 60,542 $ 106,205 $ 96,051 - ------------------------------------------------------------------ ------------- ------------- ------------- ------------ (1) Net cash flow provided by operations as per the Unaudited Condensed Consolidated Statements of Cash Flows.
Adjusted cash flow from operations is a non-GAAP measure that represents cash flow provided by operations before changes in assets and liabilities as presented in our Unaudited Condensed Consolidated Statements of Cash Flows. Cash flow from operations is the GAAP measure as presented in our Unaudited Condensed Consolidated Statements of Cash Flows. In our discussion herein, we have elected to discuss these two components of cash flow provided by operations separately. Adjusted cash flow from operations, the non-GAAP measure, measures the cash flow earned or incurred from operating activities without regard to the collection or payment of associated receivables or payables. We believe that this is important to consider separately, as we believe it can often be a better way to discuss changes in operating trends in our business caused by changes in production, prices, operating costs, and so forth, without regard to whether the earned or incurred item was collected or paid during that year. We also use this measure because the collection of our receivables or payment of our obligations has not been a significant issue for our business, but merely a timing issue from one period to the next, with fluctuations generally caused by significant changes in commodity prices or significant changes in drilling activity. The net change in assets and liabilities relating to operations is also important as it does require or provide additional cash for use in our business; however, we prefer to discuss its effect separately. For instance, as noted above, during the first six months of 2004, we spent $7.5 million (in the second quarter) to acquire 7,500 Bbls/d of oil puts or floors for 2005 and to retire 20 MMcf/d of natural gas hedges for the balance of 2004, and funded a $10.8 million increase in accrued production receivables as a result of the higher commodity prices during the second quarter of 2004, partially 21 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS offset by changes in other assets and liabilities. Conversely in 2003, commodity prices were highest in the first quarter, causing an increase in our accrued production receivables during March 2003 as a result of unusually high natural gas prices that month, with natural gas index prices in the $9.28 per MMBtu range, with such receivables decreasing during the second quarter as commodity prices declined. Certain of our operating results and statistics for the comparative second quarters and first six months of 2004 and 2003 are included in the following table.
Three Months Ended Six Months Ended June 30, June 30, - --------------------------------------------------------------------------------------------- ---------------------------- 2004 2003 2004 2003 - --------------------------------------------------------------------------------------------- ------------- ------------- Average daily production volumes Bbls/d 18,730 18,957 19,067 19,259 Mcf/d 107,230 96,558 105,344 97,857 BOE/d (1) 36,602 35,050 36,624 35,569 Operating revenues and expenses (thousands) Oil sales $ 58,529 $ 43,922 $ 113,054 $ 96,135 Natural gas sales 60,542 50,830 116,253 110,341 Loss on settlements of derivative contracts (2) (18,239) (13,356) (32,507) (41,041) ------------- ------------ ------------- ------------- Total oil and natural gas revenues $ 100,832 $ 81,396 $ 196,800 $ 165,435 ============= ============ ============= ============= Lease operating expenses $ 24,530 $ 23,048 $ 47,058 $ 45,450 Production taxes and marketing expenses 4,514 3,467 8,581 7,363 ------------- ------------ ------------- ------------- Total production expenses $ 29,044 $ 26,515 $ 55,639 $ 52,813 ============= ============ ============= ============= CO2 sales and transportation fees (3) $ 1,580 $ 2,445 $ 2,941 $ 4,634 CO2 operating expenses 209 534 353 851 ------------- ------------ ------------- ------------- CO2 operating margin $ 1,371 $ 1,911 $ 2,588 $ 3,783 ============= ============ ============= ============= Unit prices - including impact of hedges Oil price per Bbl $ 26.56 $ 23.93 $ 25.72 $ 24.32 Gas price per Mcf 5.69 4.56 5.61 4.55 Unit prices - excluding impact of hedges Oil price per Bbl $ 34.34 $ 25.46 $ 32.58 $ 27.58 Gas price per Mcf 6.20 5.78 6.06 6.23 Oil and gas operating revenues and expenses per BOE (1): Oil and natural gas revenues $ 35.75 $ 29.71 $ 34.40 $ 32.07 ============= ============ ============= ============= Oil and gas lease operating expenses $ 7.36 $ 7.23 $ 7.06 $ 7.06 Oil and gas production taxes and marketing expense 1.36 1.08 1.29 1.15 ------------- ------------ ------------- ------------- Total oil and gas production expenses $ 8.72 $ 8.31 $ 8.35 $ 8.21 - --------------------------------------------------------------------------------------------- --------------- -----------
(1) Barrel of oil equivalent using the ratio of one barrel of oil to 6 Mcf of natural gas ("BOE"). (2) See also "Market Risk Management" below for information concerning the Company's hedging transactions. (3) For three and six months ended June 30, 2004, includes deferred revenue of $0.6 million and $1.1 million, respectively, associated with a volumetric production payment and $0.7 million and $1.2 million, respectively, of transportation income from Genesis. 22 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Production: Production by area for each of the quarters of 2003 and the first - ---------- and second quarters of 2004 is listed in the following table.
Average Daily Production (BOE/d) -------------------------------------------------------------------------------- First Second Third Fourth First Second Quarter Quarter Quarter Quarter Quarter Quarter 2003 2003 2003 2003 2004 2004 - ------------------------------------------------------------------------------------------------------------------ Mississippi - non-CO2 floods 14,537 13,600 13,367 13,066 12,754 13,048 Mississippi - CO2 floods 4,345 4,522 4,227 5,579 6,318 6,603 Onshore Louisiana 8,700 8,417 8,024 8,812 8,825 7,492 Offshore Gulf of Mexico 8,353 8,351 7,186 6,865 8,521 9,114 Other 158 160 312 268 229 345 -------------------------------------------------------------------------------- Total Denbury 36,093 35,050 33,116 34,590 36,647 36,602 - ------------------------------------------------------------------------------------------------------------------
Overall production increased 4% on a BOE/d basis in the second quarter of 2004 as compared to the second quarter of 2003, but was relatively stable between the first and second quarters of 2004 and the respective first six months of 2003 and 2004. However, several factors that caused fluctuations between the various periods should be noted. During the first quarter of 2003 (effective January 31), we sold Laurel Field, a Mississippi non-CO2 flood property that had averaged between 1,500 and 1,700 BOE/d since we acquired it in August 2002. Eliminating the one month of Laurel Field production in 2003 reduces the variance in the first quarter to first quarter production for Mississippi - non-CO2 floods by approximately 526 BOE/d. The balance of the decline in this operating area is primarily related to normal depletion at several of our fields. Production increased slightly in this area in the second quarter of 2004, as compared to production in the prior quarter, as a result of additional natural gas drilling in the Selma Chalk formation at Heidelberg Field. Natural gas production at this field averaged 14.8 MMcf/d in the second quarter of 2004, up from 11.0 MMcf/d in the prior quarter and 10.4 MMcf/d in the second quarter of 2003, making Heidelberg Field our single largest natural gas producing field for the most recent quarter. As more fully discussed in "CO2 Operations" above, oil production from our tertiary operations continued to increase in the second quarter of 2004, averaging 6,603 Bbls/d, representing 35% of our second quarter corporate oil production and 24% of our total corporate production on a BOE basis pro forma to give effect to the offshore sale. Production from our offshore properties averaged 9,114 BOE/d in the quarter, the highest level for us since 2002, following an active development program during the last eighteen months. Without significant continued development in this area, production was expected to decrease rapidly in the future had the properties not been sold. Production declines in our onshore Louisiana properties offset the increases in other areas, declining 15% from first quarter 2004 levels and 11% from second quarter 2003 levels. Production at Thornwell, an onshore Louisiana Field, averaged 1,403 BOE/d during the second quarter of 2004, down from 2,526 BOE/d in the prior quarter, and 2,820 BOE/d in the second quarter of 2003. We did not process any liquids this quarter at Thornwell, a decision that is made monthly depending on the relative price of liquids and natural gas, causing part of the decline. More significantly, production from this field is in a steep decline due to its short-lived nature, and is expected to further decline throughout 2004. In spite of its short remaining life, we have generated a good return on investment at Thornwell, with a net profit to date (on a cash basis) through June 30, 2004 of $32.3 million. This field, and our offshore properties just sold, were expected to have the steepest decline rates of any of our properties during the near future. 23 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Oil and Natural Gas Revenues: Oil and natural gas revenues, net of hedge payments, for the second quarter of 2004 increased $24.3 million, or 26%, from the comparable quarter of 2003, primarily as a result of higher commodity prices, plus slightly higher production, partially offset by higher payments on our hedges. When comparing the respective six-month periods, revenues were also higher in 2004, primarily as a result of higher commodity prices. Production was almost the same for the comparable six-month periods and hedge payments were higher in the first half of 2003 than in the first half of 2004 due to unusually high natural prices in March 2003, when natural gas index prices were approximately $9.28 per MMBtu. Cash payments on our hedges were $18.2 million in the second quarter of 2004 and $32.5 million year to date, up 37% on a quarterly basis from the $13.4 million paid during the second quarter of 2003, but down 21% from the $41.0 million paid during the first six months of 2003. See "Market Risk Management" for additional information regarding our hedging activities. Record high average commodity prices on a per BOE basis in the second quarter of 2004 increased revenues 25% or $20.1 million between the respective second quarters of 2004 and 2003. The 4% increase in production in the second quarter of 2004 further increased oil and natural gas revenues for the two periods, by $4.2 million, or 5%. However, higher hedge payments reduced revenue by $4.9 million or 6% between the respective second quarters. While both commodity prices were higher in the second quarter of 2004 as compared to those in the second quarter of 2003, the increase in oil prices was the most significant, with an increase in our average net oil price of $8.88 per Bbl, a 35% increase. Natural gas prices were approximately 7% higher between the two respective periods. When comparing the respective six month periods, higher commodity prices, higher production and lower hedge payments all contributed to higher revenue in the first half of 2004 as compared to revenue in the first half of 2003. Higher commodity prices on a per BOE basis in the first half of 2004 increased revenues 9% or $15.5 million between the respective first six months of 2004 and 2003. The 3% increase in production in the first half of 2004 further increased oil and natural gas revenues for the two periods, by $7.3 million, or 4%. Lower hedge payments in the first half of 2004 increased revenue by $8.5 million or 5% between the respective six month periods. Natural gas prices were almost the same between the respective six month periods, while our average net oil price increased 18%, from $27.58 per Bbl in the first half of 2003 to $32.58 per Bbl in the first half of 2004. Production Expenses: To date in 2004, we have not had significant workover expenses, although we had higher than normal repairs and maintenance on offshore platforms during the period. In comparison, during the first half of 2003, we incurred $2.9 million on two workovers relating to mechanical failures of two onshore Louisiana wells. Operating expenses on our tertiary operations increased from $8.5 million in the first half of 2003 to $11.7 million in the comparable period of 2004 as a result of increased activity at Mallalieu and McComb Fields. However, with the 46% higher production from these tertiary operations, operating expenses for our tertiary operations on a per BOE basis decreased from $10.56 per BOE in the first half of 2003 to $9.94 per BOE in the first half of 2004. Nonetheless, our tertiary operations are resulting in steadily increasing costs per BOE on a corporate basis as our tertiary operations constitute a more significant portion of our total production and operations. The balance of cost increases is generally attributable to higher energy costs to operate the properties and general cost inflation in our industry. In general, we expect our operating costs per BOE to increase throughout 2004 and beyond as the operating costs of our tertiary operations are higher than for our other operations and as tertiary operations become more and more significant. Production taxes and marketing expenses generally change in proportion to commodity prices and production and as such, were higher in the second quarter of 2004 following the record high commodity prices. 24 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS General and Administrative Expenses General and administrative ("G&A") expenses increased 18% on a per BOE basis between the respective second quarters and 21% between the respective first six months, as set forth below:
Three Months Ended Six Months Ended June 30, June 30, - ------------------------------------------------- ----------------------------------- ------------------------- 2004 2003 2004 2003 - ------------------------------------------------- ---------------- ---------------- ------------ ------------ Net G&A expense (thousands) Gross G&A expenses $ 11,773 $ 10,971 $ 24,453 $ 22,403 State franchise taxes 242 358 488 721 Operator overhead charges (6,714) (6,508) (13,494) (13,023) Capitalized exploration costs (1,123) (1,445) (2,521) (2,934) ---------------- ---------------- ------------ ------------ Net G&A expense $ 4,178 $ 3,376 $ 8,926 $ 7,167 ================ ================ ============ ============ Average G&A cost per BOE $ 1.25 $ 1.06 $ 1.34 $ 1.11 Employees as of June 30 395 369 395 369 - ------------------------------------------------- ---------------- ---------------- ------------ ------------
Gross G&A expenses increased $802,000, or 7%, between the respective second quarters and $2.1 million or 9% between the respective first six months. The single largest component of this increase relates to approximately $475,000 and $975,000 of employee severance payments in the second quarter and first half of 2004, respectively, for a portion of the offshore professional and technical staff terminated prior to June 30, 2004 in conjunction with our offshore property sale. We expect the remaining employees dedicated to our offshore operations to be terminated in the third quarter at an estimated cost of approximately $1.6 million. We also incurred additional G&A expenses associated with the corporate restructuring in December 2003, compliance with the requirements of the Sarbanes-Oxley Act, the sale of stock by the Texas Pacific Group in March 2004, and overall increases in most other categories of G&A due to general cost inflation. As a result of the personnel reductions in our offshore area, our capitalized exploration costs decreased slightly in the second quarter of 2004 as compared to the level of those costs in the same period in 2003, partially offset by slightly higher overhead recoveries resulting from incremental development activity. The change in net G&A was similar to the change in gross G&A between the respective periods. On a per BOE basis, G&A costs increased parallel to the change in gross cost as the change in overall production rates was not significant between the periods. Interest and Financing Expenses
Three Months Ended Six Months Ended June 30, June 30, - ---------------------------------------------------- ---------------------------------- ----------------------------- Amounts in thousands, except per BOE amounts 2004 2003 2004 2003 - ---------------------------------------------------- -------------- ---------------- ------------- ------------ Interest expense $ 5,068 $ 6,227 $ 10,149 $ 12,688 Non-cash interest expense (227) (296) (454) (799) -------------- ---------------- ------------- ------------ Cash interest expense 4,841 5,931 9,695 11,889 Interest and other income (330) (347) (749) (551) -------------- ---------------- ------------- ------------ Net cash interest expense $ 4,511 $ 5,584 $ 8,946 $ 11,338 ============== ================ ============= ============ Average net cash interest expense per BOE $ 1.35 $ 1.75 $ 1.34 $ 1.76 Average interest rate (1) 6.3% 6.5% 6.3% 6.6% Average debt outstanding $ 309,286 $ 367,747 $307,703 $359,696 - ---------------------------------------------------- ============== ================ ============= ============ (1) Includes commitment fees but excludes amortization of discount and debt issue costs.
Interest expense for the second quarter and first six months of 2004 decreased from levels in the comparable periods of 2003 primarily due to (i) lower overall interest rates, primarily as a result of our subordinated debt refinancing in 2003, and (ii) lower average debt levels as a result of our $50 million reduction in debt during 2003. Our non-cash interest expense also decreased as a result of the subordinated debt refinancing, which eliminated the amortization of discount on 25 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS our old subordinated debt, which was higher than the discount and related amortization on our new subordinated debt issue. Depletion, Depreciation and Amortization
Three Months Ended Six Months Ended June 30, June 30, - --------------------------------------------------- --------------------------------- -------------------------- Amounts in thousands, except per BOE amounts 2004 2003 2004 2003 - --------------------------------------------------- --------------- -------------- ------------- ------------ Depletion and depreciation $ 25,694 $ 21,449 $ 50,698 $ 43,429 Depletion and depreciation of CO2 assets 1,240 592 2,378 1,030 Accretion of asset retirement obligations 774 684 1,541 1,503 Depreciation of other fixed assets 453 405 868 721 --------------- -------------- ------------- ------------ Total DD&A $ 28,161 $ 23,130 $ 55,485 $ 46,683 =============== ============== ============= ============ DD&A per BOE: Oil and natural gas properties $ 7.95 $ 6.94 $ 7.83 $ 6.98 CO2 assets and other fixed assets 0.51 0.31 0.49 0.27 - --------------------------------------------------- --------------- -------------- ------------- ------------ Total DD&A cost per BOE $ 8.46 $ 7.25 $ 8.32 $ 7.25 - --------------------------------------------------- =============== ============== ============= ============
In total, our depletion, depreciation and amortization ("DD&A") rate on a per BOE basis increased 17% between the respective second quarters, primarily due to the higher percentage of expenditures on offshore properties during 2003 and the first half of 2004, which have higher overall finding and development costs. In addition, certain of our future development cost estimates have increased to reflect the rising costs in the industry, contributing to the increase in our DD&A rate over the first quarter rate. The 2004 rates are more comparable to the DD&A rate of $8.00 per BOE during the fourth quarter of 2003 than to the DD&A rate for the first half of 2003. To date, we have added only a portion of the incremental oil reserves that we expect to add during 2004 from our tertiary operations. As such, our DD&A rate could change significantly in the next six months. We project that our DD&A rate will decrease by $0.70 to $0.80 per BOE in the third quarter as a result of the sale of our offshore properties. We also expect the DD&A rate for our CO2 assets to decrease in the third quarter as a result of the recent increase in CO2 reserves from the two wells being completed, although these savings will be partially offset by the continuing increase in CO2 production volumes. Income Taxes
Three Months Ended Six Months Ended June 30, June 30, - ------------------------------------------------------------- --------------------------------- -------------------------- Amounts in thousands, except per BOE amounts and tax rates 2004 2003 2004 2003 - ------------------------------------------------------------- -------------- --------------- ------------ ------------- Income tax provision Current income tax expense (benefit) $ 977 $ (1,093) $ 3,096 $ 1,637 Deferred income tax expense 8,672 3,527 17,194 9,882 -------------- --------------- ------------ ------------- Total income tax expense $ 9,649 $ 2,434 $ 20,290 $ 11,519 ============== =============== ============ ============= Average income tax expense per BOE $ 2.90 $ 0.76 $ 3.04 $ 1.79 Effective tax rate 33.2% 32.2% 32.7% 32.8% - ------------------------------------------------------------- -------------- --------------- ------------ -------------
Our income tax provision for the respective periods was based on an estimated statutory tax rate of 38%. The net effective tax rate was lower than the statutory rates, primarily due to the recognition of enhanced oil recovery credits which lowered our overall tax expense. The current income tax expense represents our anticipated alternative minimum cash taxes that we cannot offset with our regular tax net operating loss carryforwards or our enhanced oil recovery credits. We recognized a current income tax credit of $1.1 million in the 2003 second quarter due to a downward revision in our 2003 forecast of taxable income at that time. 26 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Per BOE Data The following table summarizes our cash flow, DD&A and results of operations on a per BOE basis for the comparative periods. Each of the individual components are discussed above.
Three Months Ended Six Months Ended June 30, June 30, - --------------------------------------------------------------- -------------------------- ------------------------- Per BOE data 2004 2003 2004 2003 - --------------------------------------------------------------- ------------ ------------ ------------ ------------ Revenues $ 35.75 $ 29.71 $ 34.40 $ 32.07 Loss on settlements of derivative contracts (5.48) (4.19) (4.88) (6.37) Lease operating expenses (7.36) (7.23) (7.06) (7.06) Production taxes and marketing expenses (1.36) (1.08) (1.29) (1.15) - --------------------------------------------------------------- ------------ ------------ ------------ ------------ Production netback 21.55 17.21 21.17 17.49 CO2 operating margin 0.41 0.60 0.39 0.59 General and administrative expenses (1.25) (1.06) (1.34) (1.11) Net cash interest expense (1.35) (1.75) (1.34) (1.76) Current income taxes and other (0.42) 0.36 (0.58) (0.24) Changes in assets and liabilities (2.96) 3.62 (2.37) (0.05) - --------------------------------------------------------------- ------------ ------------ ------------ ------------ Cash flow from operations 15.98 18.98 15.93 14.92 DD&A (8.46) (7.25) (8.32) (7.25) Deferred income taxes (2.60) (1.11) (2.58) (1.54) Amortization of derivative contracts and other non-cash hedging adjustments (2.15) 0.24 (1.19) 0.35 Early retirement of subordinated debt - (5.53) - (2.74) Cumulative effect of change in accounting principle - - - 0.41 Changes in assets and liabilities and other non-cash items 3.05 (3.72) 2.42 (0.08) - --------------------------------------------------------------- -------------------------- ------------ ------------ Net income $ 5.82 $ 1.61 $ 6.26 $ 4.07 - --------------------------------------------------------------- -------------------------- ------------ ------------
Market Risk Management We finance some of our acquisitions and other expenditures with fixed and variable rate debt. These debt agreements expose us to market risk related to changes in interest rates. The following table presents the carrying and fair values of our debt, along with average interest rates. The fair value of our bank debt is considered to be the same as the carrying value because the interest rate is based on floating short-term interest rates. The fair value of the subordinated debt is based on quoted market prices. None of our debt has any triggers or covenants regarding our debt ratings with rating agencies.
Expected Maturity Dates - ----------------------------------------- --------------------------------------------------------------------------------- 2004- Carrying Fair Amounts in thousands 2005 2006 2007 2008 After Value Value - ----------------------------------------- ------- -------- ------- ------- --------- ----------- -------------- Variable rate debt: Bank debt............................... $ - $ 85,000 $ - $ - $ - $ 85,000 $ 85,000 The weighted-average interest rate on the bank debt at June 30, 2004 is 2.6%. Fixed rate debt: 7.5% subordinated debt, net of discount, due 2013............. $ - $ - $ - $ - $ 225,000 $ 223,300 $ 233,438 The interest rate on the subordinated debt is a fixed rate of 7.5%.
We enter into various financial contracts to hedge our exposure to commodity price risk associated with anticipated future oil and natural gas production. We do not hold or issue derivative financial instruments for trading purposes. 27 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS These contracts have historically consisted of price floors, collars and fixed price swaps. We generally attempt to hedge between 33% and 75% of our anticipated production each year to provide us with a reasonably certain amount of cash flow to cover most of our budgeted exploration and development expenditures without incurring significant debt, although our hedging percentage may vary relative to our debt levels. For example, when our debt levels are high, we may hedge a higher percentage of our production than when our debt levels are low. When we make an acquisition, we attempt to hedge a large percentage, up to 100%, of the forecasted production for the subsequent one to three years following the acquisition in order to help provide us with a minimum return on our investment. Much of our hedging activity has been with collars, although for the 2002 COHO acquisition, we also used swaps in order to lock in the prices used in our economic forecasts. In the second quarter of 2004, we purchased price floors or puts relating to a portion of our 2005 oil production, allowing us to retain any upside from increases in commodity prices. All of the mark-to-market valuations used for our financial derivatives are provided by external sources and are based on prices that are actively quoted. We manage and control market and counterparty credit risk through established internal control procedures which are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures, and diversification. Upon reaching a verbal agreement on the offshore property sale, subject primarily to the purchaser's further due diligence, we entered into natural gas swaps on a total of 23.6 Bcf for the period of July 2004 through December 2005, covering the anticipated natural gas production from our offshore properties for that period, with the tacit understanding with the prospective purchaser that these hedges would be transferred to the purchaser upon closing. These swaps did not qualify for hedge accounting and as of August 6, we had assigned them to the purchaser of the offshore properties. At about the same time, with the expectation that the offshore transaction would be consummated, we retired, by purchasing offsetting contracts, 20 MMcf/d of our natural gas hedges for July to December of 2004, at a cost of approximately $3.9 million. This transaction, and the related hedge accounting designation changes and associated fair market value adjustments, was the primary reason for the $7.1 million net charge to earnings in the second quarter of 2004 relating to our derivative contracts. At June 30, 2004, our derivative contracts were recorded at their fair value, which was a net liability of approximately $36.9 million, a decrease of approximately $7.7 million from the $44.6 million fair value liability recorded as of December 31, 2003. This decrease in our net liability is a result of the termination of six months of derivative contracts due to the passage of time, partially offset by an increase in the liability as a result of higher oil and natural gas commodity prices between December 31, 2003 and June 30, 2004. Information regarding our current hedging positions is included in Note 7 to the Unaudited Condensed Consolidated Financial Statements. Although we have hedged less of our production in 2004 than in 2003 (approximately 55% of our total production in 2004 as compared to approximately 80% in 2003), we expect our total hedge payments for 2004 to be about the same as in 2003 due to the currently higher oil prices in 2004 and lower hedged prices. To date for 2005, we have 15.0 MMcf/d of natural gas collars with a floor of $3.00 per MMBtu and a ceiling of approximately $5.50 per MMBtu and 7,500 Bbls/d of oil puts or floors with a floor price of $27.50, acquired at a total cost of approximately $3.6 million. Since these most recent hedges are puts or price floors, the maximum out-of-pocket exposure is the cost of the put. Based on NYMEX natural gas futures prices at June 30, 2004, we would expect to make future cash payments of $13.4 million on our natural gas commodity hedges. If natural gas futures prices were to decline by 10%, we would expect to receive $8.2 million under our natural gas commodity hedges, and if futures prices were to increase by 10% we would expect to pay $36.0 million. Based on NYMEX crude oil futures prices at June 30, 2004, we would expect to pay $24.2 million on our crude oil commodity hedges. If crude oil futures prices were to decline by 10%, we would expect to pay $17.8 million, and if crude oil futures prices were to increase by 10%, we would expect to pay $30.7 million under our crude oil commodity hedges. Critical Accounting Policies For a discussion of our critical accounting policies, which are related to property, plant and equipment, depletion and depreciation, oil and natural gas reserves, asset retirement obligations, income taxes and hedging activities, and which remain unchanged, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" in our annual report on Form 10-K for the year ended December 31, 2003. 28 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Forward-Looking Information The statements contained in this Quarterly Report on Form 10-Q ("Quarterly Report") that are not historical facts, including, but not limited to, statements found in this Management's Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements, as that term is defined in Section 21E of the Securities and Exchange Act of 1934, as amended, that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, capital expenditures, drilling activity, acquisition plans and proposals and dispositions, development activities, cost savings, production efforts and volumes, hydrocarbon reserves, hydrocarbon prices, CO2 production and deliverability, liquidity, regulatory matters and competition. Such forward-looking statements generally are accompanied by words such as "plan," "estimate," "budgeted," "expect," "predict," "anticipate," "projected," "should," "assume," "believe" or other words that convey the uncertainty of future events or outcomes. Such forward-looking information is based upon management's current plans, expectations, estimates and assumptions and is subject to a number of risks and uncertainties that could significantly affect current plans, anticipated actions, the timing of such actions and our financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by or on behalf of the Company. Among the factors that could cause actual results to differ materially are: fluctuations of the prices received or demand for our oil and natural gas, the uncertainty of drilling results and reserve estimates, operating hazards, acquisition risks, requirements for capital, general economic conditions, competition and government regulations, as well as the risks and uncertainties discussed in this Quarterly Report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in the Company's other public reports, filings and public statements. 29 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Item 3. Quantitative and Qualitative Disclosures about Market Risk - ------------------------------------------------------------------- The information required by Item 3 is set forth under "Market Risk Management" in Management's Discussion and Analysis of Financial Condition and Results of Operations. Item 4. Controls and Procedures - -------------------------------- Denbury maintains disclosure controls and procedures designed to ensure that information required to be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms. Our chief executive officer and chief financial officer have evaluated our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q and have determined that such disclosure controls and procedures are effective in all material respects in providing to them on a timely basis material information required to be disclosed in this quarterly report. There have been no significant changes in internal controls over financial reporting during the period covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, Denbury's internal controls over financial reporting. Part II. Other Information Item 2. Change in Securities, Use of Proceeds and Issuer Purchases of Equity Securities - --------------------------------------------------------------------------------
ISSUER PURCHASES OF EQUITY SECURITIES (c) Total Number of (d) Maximum Number (a) Total Shares Purchased of Shares that May Number of (b) Average as Part of Publicly Yet Be Purchased Shares Price Paid Announced Plans or Under the Plan Or Period Purchased per Share Programs Programs - ------------------------------------------------------------------------------------------------------------ January 1 through 31, 2004 - - - 100,000 February 1 through 29, 2004 50,000 $ 14.87 50,000 50,000 March 1 through 31, 2004 - - - 50,000 April 1 through 30, 2004 25,000 $ 18.74 25,000 25,000 May 1 through 31, 2004 25,000 $ 17.96 25,000 100,000 June 1 through 30, 2004 - - - 100,000 Total 100,000 $ 16.61 100,000 100,000 - ------------------------------------------------------------------------------------------------------------
In August 2003, we adopted a stock repurchase plan (the "Plan") to purchase shares of our common stock on the NYSE in order for such repurchased shares to be reissued to our employees who participate in Denbury's Employee Stock Purchase Plan. The Plan provides for purchases through an independent broker of 50,000 shares of Denbury's common stock per fiscal quarter for a period of approximately twelve months, or a total of 200,000 shares, beginning August 13, 2003 and ending on July 31, 2004. In May 2004, the Board of Directors renewed the Plan for another year, beginning July 1, 2004 and ending June 30, 2005. Purchases are to be made at prices and times determined at the discretion of the independent broker, provided however that no purchases may be made during the last ten business days of a fiscal quarter. Item 4. Submission of Matters to a Vote of Security Holders - ------------------------------------------------------------ Denbury's Annual Meeting of Shareholders was held on May 12, 2004 for the purposes of: (1) electing six Directors of Denbury for one-year terms to expire at the 2005 Annual Meeting of Shareholders, and (2) approving a new omnibus stock and incentive plan. At the record date, March 31, 2004, 54,672,960 shares of common stock were outstanding and entitled to one vote per share upon all matters submitted at the meeting. Holders of 46,050,628 shares of common stock, 30 representing approximately 84% of the total issued and outstanding shares of common stock, were present in person or by proxy at the meeting to cast their vote. With respect to the election of directors, all six director nominees were re-elected. All of the directors are elected on an annual basis. The votes were cast as follows:
Nominees for Directors For Withheld - --------------------------- ------------- ---------- Ronald G. Greene 45,908,287 142,341 David I. Heather 45,708,672 341,956 William S. Price, III 45,088,739 961,889 Gareth Roberts 45,893,737 156,891 Wieland F. Wettstein 45,572,972 477,656 Carrie A. Wheeler 45,091,655 958,973
On May 31, 2004, Mr. William S. Price, III and Ms. Carrie A. Wheeler, both principals of the Texas Pacific Group resigned as directors. On June 3, 2004, Mr. Donald D. Wolf was appointed as a director to fill one of the vacancies. The proposed 2004 Omnibus Stock and Incentive Plan was also approved. The votes were cast as follows: For Against Abstentions Broker Non-Votes - --------------- ----------- -------------- -------------------- 33,111,946 4,515,825 273,361 8,149,496 Item 6. Exhibits and Reports on Form 8-K during the Second Quarter of 2004 - --------------------------------------------------------------------------
Exhibits: -------- 31(a)* Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31(b)* Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32* Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
* Filed herewith. Reports on Form 8-K: ------------------- On April 28, 2004, we filed a Form 8-K, which included our press release on our first quarter 2004 earnings. On May 17, 2004, we filed a Form 8-K, as amended on May 24, 2004, which announced the appointment of PricewaterhouseCoopers LLP as the Company's independent auditors for the year ended December 31, 2004, to replace Deloitte & Touche LLP. In addition, the company announced it had renewed its stock purchase plan for another year. On June 3, 2004, we filed a Form 8-K, which announced the resignation of William S. Price, III and Carrie A. Wheeler as directors of the company, and the appointment of Donald S. Wolf to serve as a director of the company. 31 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. DENBURY RESOURCES INC. (Registrant) By: /s/ Phil Rykhoek ---------------------------------------------- Phil Rykhoek Sr. Vice President and Chief Financial Officer By: /s/ Mark C. Allen ---------------------------------------------- Mark C. Allen Vice President and Chief Accounting Officer Date August 9, 2004 32 EX-31 2 denbury2ndq10q2004ex31a.txt EXHIBIT 31(A) Exhibit 31(a) CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Gareth Roberts, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Denbury Resources Inc. (the "registrant"); 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. August 9, 2004 /s/ Gareth Roberts ------------------------------------- Gareth Roberts President and Chief Executive Officer EX-31 3 denbury2ndq10q2004ex31b.txt EXHIBIT 31(B) Exhibit 31(b) CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Phil Rykhoek, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Denbury Resources Inc. (the "registrant"); 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. August 9, 2004 /s/ Phil Rykhoek ---------------------------------------------- Phil Rykhoek Sr. Vice President and Chief Financial Officer EX-32 4 denbury2ndq10q2004ex32.txt EXHIBIT 32 Exhibit 32 Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 In connection with the accompanying Quarterly Report on Form 10-Q for the quarter ended June 30, 2004 (the "Report") of Denbury Resources Inc. ("Denbury") as filed with the Securities and Exchange Commission on August 9, 2004, each of the undersigned, in his capacity as an officer of Denbury, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge: 1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and 2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Denbury. Dated: August 9, 2004 /s/ Gareth Roberts ---------------------------------------------- Gareth Roberts President and Chief Executive Officer Dated: August 9, 2004 /s/ Phil Rykhoek ---------------------------------------------- Phil Rykhoek Sr. Vice President and Chief Financial Officer -----END PRIVACY-ENHANCED MESSAGE-----