10-Q 1 denbury2dq10q2003.txt 2ND QUARTER 10-Q - 2003 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, 2003 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 75-2815171 (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, 2003 ----- ---------------------------- Common Stock, $.001 par value 54,016,047
DENBURY RESOURCES INC.
INDEX Page ---- Part I. Financial Information ------------------------------ Item 1. Financial Statements Independent Accountants' Report 3 Consolidated Balance Sheets at June 30, 2003 (Unaudited) and December 31, 2002 4 Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2003 and 2002 (Unaudited) 5 Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2003 and 2002 (Unaudited) 6 Consolidated Statements of Comprehensive Income (Loss) for the Six Months Ended June 30, 2003 and 2002 (Unaudited) 7 Notes to Consolidated Financial Statements 8-18 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 19-33 Item 3. Quantitative and Qualitative Disclosures about Market Risk 34 Item 4. Controls and Procedures 34 Part II. Other Information --------------------------- Item 4. Submission of Matters to a Vote of Security Holders 34 Item 6. Exhibits and Reports on Form 8-K 35 Signatures 36
2 PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS ----------------------------- INDEPENDENT ACCOUNTANTS' REPORT To the Board of Directors of Denbury Resources Inc.: We have reviewed the accompanying condensed consolidated balance sheet of Denbury Resources Inc. and subsidiaries (the "Company") as of June 30, 2003, and the related condensed consolidated statements of operations for the three-month and six-month periods ended June 30, 2003 and 2002, and of cash flows and comprehensive income (loss) for the six-month periods then ended. These financial statements are the responsibility of the Company's management. We conducted our reviews in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and of making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of Denbury Resources Inc. and subsidiaries as of December 31, 2002 and the related consolidated statements of operations, stockholders' equity, and cash flows for the year then ended (not presented herein); and in our report dated March 3, 2003, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2002 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived. As discussed in Note 3 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. /s/ Deloitte & Touche LLP Dallas, Texas August 7, 2003 3
DENBURY RESOURCES INC. CONSOLIDATED BALANCE SHEETS (Amounts in thousands except share amounts) (Unaudited) June 30, December 31, 2003 2002 --------------- --------------- ASSETS CURRENT ASSETS Cash and cash equivalents $ 19,348 $ 23,940 Accrued production receivable 35,886 34,458 Related party accrued production receivable - Genesis 4,279 3,334 Trade and other receivables 19,990 16,846 Other current assets 5,534 - Deferred tax asset 31,642 49,886 ------------ ----------- Total current assets 116,679 128,464 ------------ ----------- PROPERTY AND EQUIPMENT Oil and natural gas properties (using full cost accounting) Proved 1,331,593 1,245,896 Unevaluated 47,701 45,736 CO2 properties and equipment 74,808 62,370 Less accumulated depletion and depreciation (650,441) (609,917) ------------ ----------- Net property and equipment 803,661 744,085 ------------ ----------- INVESTMENT IN GENESIS 2,237 2,224 OTHER ASSETS 22,108 20,519 ------------ ----------- TOTAL ASSETS $ 944,685 $ 895,292 ============ =========== LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable and accrued liabilities $ 53,360 $ 49,281 Oil and gas production payable 21,048 17,309 Derivative liabilities 45,377 29,289 ------------ ----------- Total current liabilities 119,785 95,879 ------------ ----------- LONG-TERM LIABILITIES Long-term debt 333,106 344,889 Asset retirement liabilities 40,185 6,845 Derivative liabilities 13,063 6,281 Deferred tax liability 54,571 71,663 Other 2,762 2,938 ------------ ----------- Total long-term liabilities 443,687 432,616 ------------ ----------- STOCKHOLDERS' EQUITY Preferred stock, $.001 par value, 25,000,000 shares authorized; none issued and outstanding - - Common stock, $.001 par value, 100,000,000 shares authorized; 53,973,381 and 53,539,329 shares issued and outstanding at June 30, 2003 and December 31, 2002, respectively 54 54 Paid-in capital in excess of par 399,709 395,906 Retained earnings (accumulated deficit) 16,319 (9,875) Accumulated other comprehensive loss (34,869) (19,288) ------------ ----------- Total stockholders' equity 381,213 366,797 ------------ ----------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 944,685 $ 895,292 ============ =========== (See accompanying Notes to Consolidated Financial Statements)
4 DENBURY RESOURCES INC. CONSOLIDATED STATEMENTS OF OPERATIONS (Amounts in thousands except per share amounts) (Unaudited)
Three Months Ended Six Months Ended June 30, June 30, --------------------------- ------------------------- 2003 2002 2003 2002 ------------- ------------- ------------ ------------ REVENUES Oil, natural gas and related product sales Unrelated parties $ 83,575 $ 67,600 $ 182,886 $ 118,510 Related party - Genesis 11,177 3,514 23,590 3,514 CO2 sales 2,445 1,896 4,634 3,386 Gain (loss) on settlements of derivative contracts (13,356) 12 (41,041) 2,648 Interest and other income 347 411 551 822 ----------- ----------- --------- ---------- Total revenues 84,188 73,433 170,620 128,880 ----------- ----------- --------- ---------- EXPENSES Lease operating expenses 23,048 17,124 45,450 32,552 Production taxes and marketing expenses 3,467 3,297 7,363 5,911 CO2 operating expenses 534 362 851 529 General and administrative expenses 3,376 3,294 7,167 6,510 Interest 6,227 6,572 12,688 13,226 Loss on early retirement of debt 17,629 - 17,629 - Depletion and depreciation 23,130 24,205 46,683 47,131 Amortization of derivative contracts and other non-cash hedging adjustments (751) (1,012) (2,261) (2,093) ----------- ----------- --------- ---------- Total expenses 76,660 53,842 135,570 103,766 ----------- ----------- --------- ---------- EQUITY IN NET INCOME OF GENESIS 35 20 51 20 ----------- ----------- --------- ---------- INCOME BEFORE INCOME TAXES 7,563 19,611 35,101 25,134 INCOME TAX PROVISION (BENEFIT) Current income taxes (1,093) 33 1,637 (448) Deferred income taxes 3,527 6,080 9,882 7,538 ----------- ----------- --------- ---------- INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 5,129 13,498 23,582 18,044 ----------- ----------- --------- ---------- CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF INCOME TAXES OF $1,600 - - 2,612 - ----------- ----------- --------- ---------- NET INCOME $ 5,129 $ 13,498 $ 26,194 $ 18,044 =========== =========== ========= ========== NET INCOME PER COMMON SHARE - BASIC Income before cumulative effect of change in accounting principle $ 0.10 $ 0.25 $ 0.44 $ 0.34 Cumulative effect of change in accounting principle - - 0.05 - ----------- ----------- --------- ---------- Net income per common share - basic $ 0.10 $ 0.25 $ 0.49 $ 0.34 =========== =========== ========= ========== NET INCOME PER COMMON SHARE - DILUTED Income before cumulative effect of change in accounting principle $ 0.09 $ 0.25 $ 0.42 $ 0.33 Cumulative effect of change in accounting principle - - 0.05 - ----------- ----------- --------- ---------- Net income per common share - diluted $ 0.09 $ 0.25 $ 0.47 $ 0.33 =========== =========== ========= ========== WEIGHTED AVERAGE COMMON SHARES OUTSTANDING: Basic 53,815 53,158 53,728 53,077 Diluted 55,337 54,301 55,186 54,024 (See accompanying Notes to Consolidated Financial Statements)
5
DENBURY RESOURCES INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (Amounts in thousands) (Unaudited) Six Months Ended June 30, ----------------------------- 2003 2002 --------- --------- CASH FLOW FROM OPERATING ACTIVITIES: Net income $ 26,194 $ 18,044 Adjustments needed to reconcile to net cash flow provided by operations: Depreciation, depletion and amortization 46,683 47,131 Amortization of derivative contracts and other non-cash hedging adjustments (2,261) (2,093) Deferred income taxes 9,882 7,538 Loss on early retirement of debt 17,629 - Amortization of debt issue costs and other 840 1,327 Cumulative effect of change in accounting principle (2,612) - Changes in assets and liabilities: Accrued production receivable (2,373) (6,066) Trade and other receivables (3,144) 18,616 Derivative assets - 7,836 Other assets 5 (210) Accounts payable and accrued liabilities 2,214 (33,267) Oil and gas production payable 3,739 (38) Other liabilities (745) (214) --------- --------- NET CASH PROVIDED BY OPERATIONS 96,051 58,604 --------- --------- CASH FLOW USED FOR INVESTING ACTIVITIES: Oil and natural gas expenditures (70,709) (49,650) Acquisitions of oil and gas properties (9,624) (2,268) Investment in Genesis - (2,040) Acquisitions of CO2 assets and capital expenditures (13,373) (5,934) Proceeds from oil and gas property sales 28,154 4,552 Increase in restricted cash (356) (3,543) Net purchases of other assets (6,973) (315) --------- --------- NET CASH USED FOR INVESTING ACTIVITIES (72,881) (59,198) --------- --------- CASH FLOW FROM FINANCING ACTIVITIES: Bank repayments (125,000) (10,000) Bank borrowings 85,000 5,130 Repayment of subordinated debt obligations, including redemption premium (209,000) - Issuance of subordinated debt, net of discount 223,054 - Issuance of common stock 2,970 2,143 Debt issuance costs (4,786) - --------- --------- NET CASH USED FOR FINANCING ACTIVITIES (27,762) (2,727) --------- --------- NET DECREASE IN CASH AND CASH EQUIVALENTS (4,592) (3,321) Cash and cash equivalents at beginning of period 23,940 23,496 --------- --------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 19,348 $ 20,175 ========= ========= SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for interest $ 13,371 $ 12,120 Cash paid (refunded) during the period for income taxes 184 (1,305) (See accompanying Notes to Consolidated Financial Statements) 6
DENBURY RESOURCES INC. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Amounts in thousands) (Unaudited) Six Months Ended June 30, ------------------------------- 2003 2002 ------------- ------------- Net income $ 26,194 $ 18,044 Other comprehensive income (loss), net of income tax: Change in fair value of derivative contracts (14,179) (17,397) Amortization of derivative contracts 366 3,227 Reclassification adjustments related to derivative contracts (1,768) (4,546) ------------- ------------- COMPREHENSIVE INCOME (LOSS) $ 10,613 $ (672) ============= ============= (See accompanying Notes to Consolidated Financial Statements) 7
DENBURY RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. BASIS OF PRESENTATION Interim Financial Statements The accompanying unaudited 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, 2002. Any capitalized terms used but not defined in these Notes to 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 our opinion, the accompanying unaudited 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, 2003 and the consolidated results of its operations and cash flows for the three and six month periods ended June 30, 2003 and 2002. Certain prior period items have been reclassified to make the classification consistent with this quarter. 2. NEW ACCOUNTING STANDARDS See Note 3 regarding our change in accounting related to our adoption of Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations." In November 2002, the Financial Accounting Standards Board ("FASB") issued Interpretaton ("FIN") No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness by Others." FIN No. 45 requires that a guarantor must recognize, at the inception of the guarantee, a liability for the fair value of the obligation that it has undertaken in issuing a guarantee. FIN No. 45 also addresses the disclosure requirements that a guarantor must include in its financial statements for guarantees issued. The initial recognition and measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. We have made all relevant disclosures regarding our guarantees. On January 1, 2003, we adopted the provisions of SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." SFAS No. 145 changes the method of reporting gains or losses on the early extinguishment of debt. Prior to SFAS No. 145, gains or losses on the early extinguishment of debt were required to be classified in a company's statement of operations as an extraordinary item, net of the related income tax effect. SFAS No. 145 considers the use of early debt extinguishment to generally be a risk management strategy and states that its effects should be reflected as income or expense from continuing operations, except in rare cases where the extinguishment of debt could be considered unusual or infrequent and would therefore be classified as an extraordinary item. In April 2003, we retired our $200 million of Senior Subordinated Notes Due 2008, and recorded a $17.6 million loss, before income taxes, on the early retirement of this debt (see Note 7 for further information regarding this debt retirement). In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 requires that a liability be recognized for exit and disposal costs only when the liability has been incurred and when it can be measured at fair value. The statement is effective for exit and disposal activities that are initiated after December 31, 2002. We adopted this statement in the first quarter of 2003 and it has not had any effect on our financial statements. In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." SFAS No. 149 amends and clarifies certain accounting and reporting for derivative 8 DENBURY RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS instruments. This statement is effective for contracts entered into or modified after June 30, 2003. We will adopt this statement in the third quarter of 2003 and it should not have any impact on our financial statements. SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets," became effective July 1, 2001 and January 1, 2002, respectively. It is our understanding that the Securities and Exchange Commission has raised questions as to the proper application by registrants in the oil and gas industry of the provisions of SFAS No. 141 and SFAS No. 142 and that the FASB and representatives from the SEC are currently in discussions regarding this issue. In question is whether the acquisition of contractual mineral interests, including both proved and undeveloped, should be classified separately as "intangible assets" on the balance sheet apart from other oil and gas property costs. Currently, 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. Until we receive further guidance regarding this issue, we will continue to include mineral interests as oil and gas properties on our balance sheet for mineral interests acquired subsequent to June 30, 2001. Based on the limited guidance pertaining to this issue, we have not calculated the potential balance sheet reclassification at this time. The provisions of SFAS No. 141 and 142 impact only the balance sheet and associated footnote disclosure, and any reclassifications, if necessary, would not impact the Company's results of operations or cash flows. 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. 9 DENBURY RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The following pro forma data summarizes Denbury's net income and net income per common share as if we had applied the provisions of SFAS No. 143 in prior periods, and as if we had removed the first quarter 2003 cumulative effect adjustment for the adoption of SFAS No. 143:
Three Months Ended Six Months Ended June 30, June 30, Year Ended December 31, --------------------- -------------------- ------------------------------ 2003 2002 2003 2002 2002 2001 2000 ---------- ---------- ---------- --------- --------- --------- --------- NET INCOME: (THOUSANDS) Net income, as reported ............... $ 5,129 $ 13,498 $ 26,194 $ 18,044 $ 46,795 $ 56,550 $ 142,227 Pro forma adjustments to reflect retroactive adoption of SFAS 143.. - 130 (2,612) (125) 473 503 306 ---------- ---------- ---------- --------- --------- --------- --------- Pro forma net income................ $ 5,129 $ 13,628 $ 23,582 $ 17,919 $ 47,268 $ 57,053 $ 142,533 ========== ========== ========== ========= ========= ========= ========= NET INCOME PER COMMON SHARE: As reported: Basic........................... $ 0.10 $ 0.25 $ 0.49 $ 0.34 $ 0.88 $ 1.15 $ 3.10 Diluted......................... 0.09 0.25 0.47 0.33 0.86 1.12 3.07 Pro forma: Basic.......................... $ 0.10 $ 0.26 $ 0.44 $ 0.34 $ 0.89 $ 1.16 $ 3.11 Diluted......................... 0.09 0.25 0.42 0.33 0.87 1.13 3.08
The following table summarizes the changes in our asset retirement obligations for the six months ended June 30, 2003.
Six Months Ended June 30, 2003 -------------------------- (in thousands) Beginning asset retirement obligation, as of December 31, 2002.. $ 6,845 Cumulative effect adjustment for SFAS 143, January 1, 2003....... 34,110 Liabilities incurred during period............................... 909 Liabilities settled during period................................ (1,318) Accretion expense................................................ 1,504 --------------------- Ending asset retirement obligation............................... $ 42,050 =====================
At June 30, 2003, $1.9 million of our asset retirement obligation was classified in "Accounts payable and accrued liabilities" under current liabilities in our Consolidated Balance Sheets. We have escrow accounts that are legally restricted for certain of our asset retirement obligations. The balances of these escrow accounts were $9.0 million at June 30, 2003, and $8.7 million at December 31, 2002 and are included in "Other assets" in our Consolidated Balance Sheets. If we had adopted SFAS No. 143 as of January 1, 2002, we estimate that our asset retirement obligations at that date would have been $34.1 million, based on the same assumptions used in our calculation of our obligations at January 1, 2003. 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, 2003 and 2002, there were no adjustments to net income for purposes of calculating diluted net income per common share. 10 DENBURY RESOURCES INC. NOTES TO 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, 2003 and 2002.
Three Months Ended Six Months Ended June 30, June 30, ----------------------------- ----------------------------- 2003 2002 2003 2002 -------------- ------------- -------------- ------------ (in thousands) (in thousands) Weighted average common shares - basic 53,815 53,158 53,728 53,077 Potentially dilutive securities: Stock options 1,522 1,143 1,458 947 -------------- ------------- -------------- ------------ Weighted average common shares - diluted 55,337 54,301 55,186 54,024 ============== ============= ============== ============
For the three months ended June 30, 2003 and 2002, common stock options to purchase approximately 1.0 million and 1.7 million shares of common stock, and for the six months ended June 30, 2003 and 2002, common stock options to purchase approximately 1.0 million and 2.3 million shares of common stock, respectively, were outstanding but excluded from the diluted net income per common share calculations. Common stock options with exercise prices in excess of our average market stock price during the respective periods are excluded from the diluted net income per common share calculation, as their impact would be anti-dilutive to our calculation. 5. SALE OF LAUREL FIELD In February 2003, we sold Laurel Field, acquired in the COHO acquisition in August 2002, for approximately $26.1 million and other consideration which included an interest in Atchafalaya Bay Field (where we already owned an interest) and seismic over that area. At December 31, 2002, Laurel Field had approximately 7.4 MMBbls of proved reserves. 6. STOCK-BASED COMPENSATION We issue stock options to all of our employees under our stock option plan, which we account for utilizing the recognition and measurement principles of Accounting Principles Board Opinion 25, "Accounting for Stock Issued to Employees," and its related interpretations. Under these principles, we do not recognize any stock-based employee compensation for stock option grants, as long as the exercise price is equal to the underlying common stock on the date of grant. The following table illustrates the effect on net income and net income per common share if we had applied the fair value recognition and measurement provisions of SFAS No. 123, "Accounting for Stock- Based Compensation," in accounting for our stock option plan. 11 DENBURY RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended Six Months Ended June 30, June 30, ------------------------- -------------------------- 2003 2002 2003 2002 ------------ ------------ ------------ ------------ NET INCOME: (THOUSANDS) Net Income, as reported ..................................$ 5,129 $ 13,498 $ 26,194 $ 18,044 Less: stock-based compensation expense applying fair value based method, net of related tax effects... 869 651 1,634 1,359 ------------ ------------ ------------ ------------ Pro forma net income...................................$ 4,260 $ 12,847 $ 24,560 $ 16,685 ============ ============ ============ ============ NET INCOME PER COMMON SHARE: As reported: Basic..................................................$ 0.10 $ 0.25 $ 0.49 $ 0.34 Diluted................................................ 0.09 0.25 0.47 0.33 Pro forma: Basic..................................................$ 0.08 $ 0.24 $ 0.46 $ 0.31 Diluted................................................ 0.08 0.24 0.45 0.31
7. INDEBTEDNESS
June 30, December 31, 2003 2002 --------------- --------------- (Amounts in thousands) (Unaudited) 9% Senior Subordinated Notes Due 2008...................................$ - $ 125,000 9% Series B Senior Subordinated Notes Due 2008.......................... - 75,000 7.5% Senior Subordinated Notes Due 2013................................. 225,000 - Senior bank loan........................................................ 110,000 150,000 Discount on Senior Subordinated Notes.................................. (1,894) (5,111) --------------- --------------- Total debt..........................................................$ 333,106 $ 344,889 =============== ===============
Issuance of 7.5% Senior Subordinated Notes Due 2013 On March 25, 2003, we issued $225 million of 7.5% Senior Subordinated Notes Due 2013 in a Rule 144A private offering. The notes were priced at 99.135% of par and we used most of our $218.4 million of net proceeds from the offering, after underwriting and issuance costs to retire our existing $200 million of 9% Senior Subordinated Notes Due 2008, including the Series B notes, (see "Redemption of 9% Senior Subordinated Notes due 2008 (Including Series B Notes)" below). The notes mature on April 1, 2013 and interest on the notes is payable each April 1 and October 1, commencing October 1, 2003. We may redeem the notes at our option beginning April 1, 2008 at the following redemption prices: 103.75% after April 1, 2008, 102.5% after April 1, 2009, 101.25% after April 1, 2010, and at 100% after April 1, 2011 and thereafter. In addition, prior to April 1, 2006, we may redeem up to 35% of the notes at a redemption price of 107.5% with net cash proceeds from a stock offering. The indenture under which the notes were issued is essentially the same as the indenture covering our previously outstanding 9% notes. The indenture contains certain restrictions on our ability to incur additional debt, pay dividends on our common stock, make investments, create liens on our assets, engage in transactions with our affiliates, transfer or sell assets and to consolidate or merge substantially all of our assets. The notes are not subject to any sinking fund requirements. 12 DENBURY RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Redemption of 9% Senior Subordinated Notes Due 2008 (Including Series B Notes) On March 18, 2003, we issued the required 30-day notice to call our existing $200 million of 9% Senior Subordinated Notes Due 2008. On April 16, 2003, we redeemed the $200 million of notes at an aggregate cost of $209.0 million, including a $9.0 million call premium. As a result of this early redemption, we recorded a before tax charge to earnings in the second quarter of 2003 of $17.6 million, which includes the $9.0 million call premium and the write-off of the remaining discount and debt issuance costs associated with these notes. Senior Bank Loan Our bank borrowing base was reaffirmed at $220 million as part of an amendment to our credit agreement completed in early May 2003. In addition, the amendment modified the hedging provisions to increase the amount of production we can hedge to a maximum of 85% of our forecasted production from our proved reserves for the current year, 70% of the forecasted production for the subsequent year, 55% of the forecasted production for the third year and 40% of the forecasted production for the fourth year. The amendment also permits us to borrow up to $20 million in a bond issue from a Mississippi governmental authority, resulting in the exemption from or reduction of sales and ad valorem taxes on CO2 facilities we build in the next two years in Mississippi. This bond funding arrangement was completed in May 2003. Any borrowings in this bond issuance will be purchased by the banks in our credit facility, will be part of our outstanding borrowings under our credit line and will accrue interest and be repaid on the same basis as our bank line. In early August 2003, our bank agreement was amended again to increase the percentage of our oil production that may be hedged for the remainder of 2003, from 85% to 90%. At June 30, 2003, we had $110.0 million outstanding under our bank credit facility, leaving us approximately $110.0 million of borrowing capacity. We also had letters of credit outstanding in the amount of $820,000 at June 30, 2003. 8. RELATED PARTY TRANSACTIONS - GENESIS Through certain of our subsidiaries, since May 14, 2002 we have been the general partner of Genesis Energy, L.P. ("Genesis"), a publicly traded master limited partnership. Our subsidiary general partner has a 2% interest in Genesis. Genesis has two primary lines of business: crude oil gathering and marketing, and pipeline transportation, primarily in Mississippi, Texas, Alabama and Florida. We account for our 2% ownership in Genesis under the equity method, as we have significant influence over the limited partnership; however, our control is limited under the general partnership agreement and therefore we do not consolidate Genesis. Our equity in Genesis' net income for the three and six month periods ended June 30, 2003 was $35,000 and $51,000, respectively. For the first six months of 2003, Genesis has paid Denbury $60,000 for directors' fees for the services of the four Denbury officers that serve on the board of directors of the general partner of Genesis, and $38,000 of distributions. Genesis Energy, Inc., the general partner of which we indirectly own 100%, has guaranteed the bank debt of Genesis, which was $6.0 million as of June 30, 2003, and also included $26.4 million in letters of credit, of which $8.2 million are for Denbury's benefit to secure purchases from Denbury. There are no guarantees by Denbury or any of its other subsidiaries of the debt of Genesis or of Genesis Energy, Inc. Genesis has historically been a purchaser of our crude oil and we anticipate future purchases of our crude oil production by Genesis. For the six month period ended June 30, 2003, we recorded sales to Genesis of $23.6 million and at June 30, 2003, had a production receivable from Genesis of $4.3 million. Sales to Genesis for the period May 14, 2002 to June 30, 2002 were $3.5 million. 13 DENBURY RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Summarized financial information of Genesis Energy, L.P. is as follows (amounts in thousands):
Three Months Six Months Ended Ended June 30, 2003 June 30, 2003 -------------------- -------------------- Revenues.................................. $ 219,949 $ 481,831 Cost of sales............................. 214,090 470,717 Other expenses............................ 3,969 8,345 -------------------- -------------------- Net income................................ $ 1,890 $ 2,769 ==================== ==================== June 30, December 31, 2003 2002 -------------------- -------------------- Current assets............................ $ 85,417 $ 92,097 Non-current assets........................ 46,714 45,440 -------------------- -------------------- Total assets.............................. $ 132,131 $ 137,537 ==================== ==================== Current liabilities....................... $ 87,946 $ 96,220 Non-current liabilities................... 6,000 5,500 Partners' capital......................... 38,185 35,817 -------------------- -------------------- Total liabilities and partners' capital... $ 132,131 $ 137,537 ==================== ====================
9. 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 50% 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. 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. 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. The following is a summary of the net gain (loss) representing cash receipts and payments on our hedge settlements:
Three Months Ended Six Months Ended June 30, June 30, ------------------------------------ ----------------------------------------- 2003 2002 2003 2002 ----------------- ----------------- ------------------ ------------------- (in thousands) Oil hedge contracts $ (2,633) $ - $ (11,371) $ 462 Gas hedge contracts (10,723) 12 (29,670) 2,186 ----------------- ----------------- ------------------ ------------------- Net gain (loss) $ (13,356) $ 12 $ (41,041) $ 2,648 ================= ================= ================== ===================
14 DENBURY RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Some of our derivative contracts require us to pay a premium which we amortize over the contract periods. This expense is included in "Amortization of derivative contracts and other non-cash hedging adjustments" in our Consolidated Statements of Operations. For the six months ended June 30, 2003 and 2002, we recorded premium amortization expense of $591,000 and $5.1 million, respectively. Also, for the six months ended June 30, 2003, we reclassified $2.7 million related to our former Enron hedges (discussed below) out of accumulated other comprehensive income into income and recorded a gain from hedge ineffectiveness of $138,000 which is also included in "Amortization of derivative contracts and other non-cash hedging adjustments."
HEDGING CONTRACTS AT JUNE 30, 2003 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, 2003 -------------------------------- ------------ ------------ ------------- ------------ ----------- ------------------ Collar Contracts (in thousands) July 2003 - Dec. 2003 10,000 $ - $ - $ 20.00 $ 30.00 $ (1,800) Swap Contracts July 2003 - Dec. 2003 2,500 24.25 - - - (2,149) July 2003 - Dec. 2003 2,000 24.30 - - - (1,701) July 2003 - Dec. 2003 2,000 25.70 - - - (1,187) Jan. 2004 - Dec. 2004 2,500 22.89 - - - (2,660) Jan. 2004 - Dec. 2004 4,500 23.00 - - - (4,608) Jan. 2004 - Dec. 2004 2,500 23.08 - - - (2,488)
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, 2003 -------------------------------- ----------- ------------ ------------ ------------ ------------ ----------------- Collar Contracts (in thousands) July 2003 - Dec. 2003 45,000 $ - $ - $ 2.75 $ 4.00 $ (13,168) July 2003 - Dec. 2003 25,000 - - 2.75 4.07 (7,017) Jan. 2004 - Dec. 2004 30,000 - - 3.50 4.45 (10,834) Jan. 2004 - Dec. 2004 15,000 - - 3.00 5.87 (2,580) Jan. 2004 - Dec. 2004 15,000 - - 3.00 5.82 (2,642) Jan. 2005 - Dec. 2005 15,000 - - 3.00 5.50 (2,556) Swap Contracts July 2003 - Dec. 2003 10,000 3.905 - - - (3,050)
At June 30, 2003, our derivative contracts were recorded at their fair value, which was a net liability of $58.4 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 Consolidated Balance Sheets. The balance in accumulated other comprehensive loss of $34.9 million at June 30, 2003, represents the deficit in the fair market value of our derivative contracts as compared to the cost of our hedges, net of income taxes, and also includes the remaining accumulated other comprehensive income of $1.4 million relating to the Enron hedges that ceased to qualify for hedge accounting treatment when Enron filed for bankruptcy. This $1.4 million relating to the former Enron hedges will be reclassified out of accumulated other comprehensive income during the remainder of 2003, over the periods that the hedges would have otherwise expired. Of the $34.9 million in accumulated other comprehensive loss as of June 30, 2003, $28.1 million relates to current hedging contracts that will expire within the next 12 months. 15 DENBURY RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 10. CONDENSED CONSOLIDATING FINANCIAL INFORMATION As of August 2001, all of the Company's subordinated debt securities were fully and unconditionally guaranteed by Denbury Resources Inc.'s significant subsidiaries. Condensed consolidating financial information for Denbury Resources Inc. and its significant subsidiaries as of June 30, 2003 and December 31, 2002 and for the three and six months ended June 30, 2003 and 2002 is as follows:
Condensed Consolidating Balance Sheets June 30, 2003 (Unaudited) --------------------------------------------------------------- Denbury Denbury Resources Resources Inc. (Parent Guarantor Inc. Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated -------------- ------------- ------------- -------------- ASSETS Current assets..................................$ 77,948 $ 38,731 $ - $ 116,679 Property and equipment.......................... 531,629 272,032 - 803,661 Investment in subsidiaries (equity method)...... 217,128 2,237 (217,128) 2,237 Other assets.................................... 18,203 3,905 - 22,108 -------------- ------------- ------------- -------------- Total assets...............................$ 844,908 $ 316,905 $ (217,128) $ 944,685 ============== ============= ============= ============== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities.............................$ 105,144 $ 14,641 $ - $ 119,785 Long-term liabilities........................... 358,551 85,136 - 443,687 Stockholders' equity............................ 381,213 217,128 (217,128) 381,213 -------------- ------------- ------------- -------------- Total liabilities and stockholders' equity.$ 844,908 $ 316,905 $ (217,128) $ 944,685 ============== ============= ============= ============== December 31, 2002 --------------------------------------------------------------- Denbury Denbury Resources Resources Inc. (Parent Guarantor Inc. Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated -------------- ------------- -------------- -------------- ASSETS Current assets..................................$ 111,063 $ 17,401 $ - $ 128,464 Property and equipment.......................... 528,754 215,331 - 744,085 Investment in subsidiaries (equity method)...... 169,309 2,224 (169,309) 2,224 Other assets.................................... 16,881 3,638 - 20,519 -------------- ------------- -------------- -------------- Total assets...............................$ 826,007 $ 238,594 $ (169,309) $ 895,292 ============== ============= ============== ============== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities.............................$ 87,101 $ 8,778 $ - $ 95,879 Long-term liabilities........................... 372,109 60,507 - 432,616 Stockholders' equity............................ 366,797 169,309 (169,309) 366,797 -------------- ------------- -------------- -------------- Total liabilities and stockholders' equity.$ 826,007 $ 238,594 $ (169,309) $ 895,292 ============== ============= ============== ==============
16 DENBURY RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidating Statements of Operations Three Months Ended June 30, 2003 (Unaudited) ------------------------------------------------------------------ Denbury Denbury Resources Resources Inc. (Parent Guarantor Inc. Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated --------------- -------------- -------------- -------------- 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 (loss) before income taxes............ 3,921 11,581 (7,939) 7,563 Income tax provision (benefit)............... (1,208) 3,642 - 2,434 --------------- -------------- -------------- -------------- Net income (loss)............................$ 5,129 $ 7,939 $ (7,939) $ 5,129 =============== ============== ============== ==============
Three Months Ended June 30, 2002 (Unaudited) ------------------------------------------------------------------ Denbury Denbury Resources Resources Inc. (Parent Guarantor Inc. Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated --------------- -------------- -------------- -------------- Revenues.....................................$ 57,116 $ 16,317 $ - $ 73,433 Expenses..................................... 40,456 13,386 - 53,842 --------------- -------------- -------------- -------------- Income before the following: 16,660 2,931 - 19,591 Equity in net earnings of subsidiaries.. 1,842 20 (1,842) 20 --------------- -------------- -------------- -------------- Income (loss) before income taxes............ 18,502 2,951 (1,842) 19,611 Income tax provision......................... 5,004 1,109 - 6,113 --------------- -------------- -------------- -------------- Net income (loss)............................$ 13,498 $ 1,842 $ (1,842) $ 13,498 =============== ============== ============== ==============
Six Months Ended June 30, 2003 (Unaudited) ------------------------------------------------------------------ Denbury Denbury Resources Resources Inc. (Parent Guarantor Inc. Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated --------------- -------------- -------------- -------------- 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 (loss) before income taxes and cumulative effect of a change in accounting principal.................................. 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 principal............. 22,213 17,803 (16,434) 23,582 Cumulative effect of a change in accounting principal, net of income taxes............. 3,981 (1,369) - 2,612 --------------- -------------- -------------- -------------- Net income (loss)............................$ 26,194 $ 16,434 $ (16,434) $ 26,194 =============== ============== ============== ==============
17 DENBURY RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Six Months Ended June 30, 2002 (Unaudited) ------------------------------------------------------------------ Denbury Denbury Resources Resources Inc. (Parent Guarantor Inc. Amounts in thousands and Issuer) Subsidiaries Eliminations Consolidated --------------- -------------- --------------- -------------- Revenues.....................................$ 102,449 $ 26,431 $ - $ 128,880 Expenses..................................... 78,873 24,893 - 103,766 --------------- -------------- --------------- -------------- Income before the following: 23,576 1,538 - 25,114 Equity in net earnings of subsidiaries.... 950 20 (950) 20 --------------- -------------- --------------- -------------- Income before income taxes................... 24,526 1,558 (950) 25,134 Income tax provision......................... 6,482 608 - 7,090 --------------- -------------- --------------- -------------- Net income (loss)............................$ 18,044 $ 950 $ (950) $ 18,044 =============== ============== =============== ==============
Condensed Consolidating Statements of Cash Flows Six Months Ended June 30, 2003 (Unaudited) ------------------------------------------------------------------ Denbury Denbury Resources Inc. Resources (Parent and Guarantor Inc. Amounts in thousands Issuer) Subsidiaries Eliminations Consolidated ----------------- -------------- -------------- -------------- 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 ================= ============== ============== ==============
Six Months Ended June 30, 2002 (Unaudited) ------------------------------------------------------------------- Denbury Denbury Resources Inc. Resources (Parent and Guarantor Inc. Amounts in thousands Issuer) Subsidiaries Eliminations Consolidated ----------------- -------------- -------------- --------------- Cash flow from operations....................$ 50,742 $ 7,862 $ - $ 58,604 Cash flow from investing activities.......... (54,424) (4,774) - (59,198) Cash flow from financing activities.......... (2,727) - - (2,727) ----------------- -------------- -------------- --------------- Net increase (decrease) in cash.............. (6,409) 3,088 - (3,321) Cash, beginning of period.................... 17,052 6,444 - 23,496 ----------------- -------------- -------------- --------------- Cash, end of period..........................$ 10,643 $ 9,532 $ - $ 20,175 ================= ============== ============== ===============
18 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, 2002, 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 a growing 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, hold key operating acreage onshore Louisiana and have a growing presence in the offshore Gulf of Mexico areas. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling, and proven engineering extraction processes. Our corporate headquarters are in Dallas, Texas, and we have three primary field offices located in Houma and Covington, Louisiana, and Laurel, Mississippi. Debt Refinancing In late March 2003, we issued $225 million of 7.5% Senior Subordinated Notes due 2013 to refinance our $200 million of then existing 9% Senior Subordinated Notes due 2008. The subordinated debt was refinanced to take advantage of the currently attractive interest rates and to extend the maturity of our long-term debt an additional five years. We estimate that we will save approximately $2.6 million per year in interest expense as a result of this refinancing. The total cost of the refinancing was approximately $15.6 million, consisting of the debt issue discount, underwriters commission and other expenses totaling approximately $6.6 million, and a $9.0 million call premium to retire the old notes. The old notes were not retired until April 16, 2003, at the end of the required thirty day notice period to call the old notes. We had a pre-tax charge to earnings in the second quarter of 2003 of approximately $17.6 million from the early retirement of the old 9% notes, made up of the $9.0 million call premium and the write-off of unamortized discount of $4.8 million and debt issue costs of $3.8 million. The proceeds from the new issue were used to retire the old 9% subordinated notes in April 2003. CAPITAL RESOURCES AND LIQUIDITY During the first six months of 2003, we spent $70.7 million on oil and natural gas exploration and development expenditures, $13.4 million on CO2 capital investments and acquisitions, and approximately $9.6 million on oil and natural gas property acquisitions, for total capital expenditures of approximately $93.7 million. In addition, during the first half of 2003 we incurred approximately $15.6 million of costs for the subordinated debt refinancing (see "Debt Refinancing" above). We sold Laurel Field, effective as of January 31, 2003, for net cash proceeds of $26.1 million plus other additional consideration, and sold other minor properties, resulting in aggregate sales proceeds during the first six months of $28.2 million. Laurel Field had been acquired as part of the acquisition of properties from COHO in August 2002 and had approximately 7.4 MMBbls of proven reserves as of December 31, 2002. The $81.1 million of net total expenditures (including the $15.6 million of debt refinancing costs) was funded by $96.1 million of cash flow from operations, with the excess cash flow used to reduce our total debt by approximately $15.0 million. At June 30, 2003, we had $335 million of total debt outstanding, consisting of $225 million of recently issued 7.5% subordinated notes and $110 million of bank debt. One of our financial goals is to limit our leverage. We generally measure leverage by a debt-to-cash flow ratio, cash flow being defined as cash flow from operations. Our target is a debt-to-cash flow ratio of 2 to 1 or less, using a moderate price deck. In today's commodity price environment, we interpret that to be oil prices around $25.00 per Bbl and natural gas prices around $3.50 per Mcf. Based on these price assumptions and anticipated production levels, we anticipate reaching our targeted debt-to-cash flow ratio during 2003 if our total debt is reduced to $300 million. Since our last significant acquisition in the third quarter of 2002, we have used a portion of our cash flow from operations and proceeds from property sales to reduce our bank debt. We repaid approximately $25 million during the fourth quarter of 2002, approximately $15 million during the first half of 2003, and had $15.6 million not been used to pay for costs of our 19 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS subordinated debt refinancing, that amount would have also been used to reduce debt during the first half of 2003. Even with the incremental debt from the refinancing, we expect to achieve our debt goal of $300 million during the latter part of 2003 through the application of excess cash flow from operations, assuming that commodity prices do not decrease significantly. We may also accomplish our goal in part with cash generated by the potential sale of a portion of our CO2 reserves and a portion of the associated industrial contracts to Genesis Energy, L.P. during the latter part of 2003. We, along with Genesis, are still investigating the feasibility and requirements of a potential transaction, which if consummated could generate between $15 million and $30 million of cash for us. Our bank borrowing base was reaffirmed at $220 million as part of an amendment to our credit agreement completed in early May 2003. The May amendment also modified the hedging provisions to increase the amount of production we can hedge to a maximum of 85% of our forecasted production from our proved reserves for the current year (as defined in the amendment and which may include up to 18 months), 70% of the forecasted production for the subsequent year, 55% of the forecasted production for the third year and 40% of the forecasted production for the fourth year. The amendment also allowed us to borrow up to $20 million in a bond issue from a Mississippi governmental authority, resulting in the exemption or reduction of sales and ad valorem taxes on CO2 facilities we build during the next two years in Mississippi. This bond funding arrangement was completed in May 2003. Any borrowings in this bond issue will be purchased by the banks in our credit facility, will be part of our outstanding borrowings under our credit line and will accrue interest and be repaid on the same basis as our bank line. In early August 2003, our bank agreement was amended again to increase the percentage of our oil production that may be hedged for the remainder of 2003, from 85% to 90%. Our next bank borrowing base redetermination will be as of October 1st, based on June 30, 2003 assets. We do not anticipate any significant changes to our borrowing base at this next review, although we cannot be certain, as there are several subjective aspects to the borrowing base determination. We anticipate that our capital spending during 2003, excluding any possible acquisitions, will be equal to or less than our cash flow generated from operations, a goal we have met each year since 1999. Our 2003 budget was recently increased by $5.0 million, and is currently approximately $143 million, including approximately $7.7 million of projects carried over from 2002 and excluding acquisitions. Based on current projections, using futures prices in place as of the first part of August 2003, this exploration and development spending level is expected to be as much as $40 million to $50 million below our 2003 forecasted cash flow. Initially, we plan to use any excess funds generated from operations to pay down debt or to fund, in whole or in part, our current year acquisitions. We may also consider further increasing our budget if it appears certain that we can reach our $300 million debt target by year-end. We review our capital expenditure budget every quarter and make adjustments as necessary to reflect changes in commodity prices and successes or failures in our drilling program. As a result, since 1999, we have been able to keep our capital spending (excluding acquisitions) at levels equal to or below our cash flow from operations. Although we have a significant inventory of development and exploration projects in-house, on a long-term basis we will need to make acquisitions in order to continue our growth and to replace our production. Our primary focus to date in 2003 has been the purchase of incremental interest in fields that we already own. We are also continuing to pursue small acquisitions that are near our CO2 pipeline in Western Mississippi and Southern Louisiana, plus individual fields in the Gulf of Mexico. Although we now control most of the fields along our CO2 pipeline, there are a few remaining smaller fields with potential that we do not control. Also, we have targeted the acquisition of offshore blocks, which generally consist of one or two fields, where we see additional potential based on our review of 3D seismic or other geologic and geophysical data. Although we are continuing to review acquisitions in our other core areas, including larger acquisitions, this activity is a lower priority for us in 2003 than has been the case historically, given our substantial inventory of projects in-house and our goal of reducing our debt level. Any acquisitions that we make will likely be funded with either our excess cash flow or bank debt. 20 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Commitments and Obligations Our obligations that are not currently recorded on our balance sheet are our operating leases, which primarily relate to our office space and minor equipment leases, and various obligations for development and exploratory expenditures arising from purchase agreements 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, 2003, consisted of $6.0 million of debt and $26.4 million in letters of credit, $8.2 million of which are for Denbury's benefit) and we have delivery obligations to deliver CO2 to our industrial customers. In August 2003, we expect to close on a lease financing of certain equipment at our tertiary recycling facility at Mallalieu Field, with a total present value of approximately $6.0 million (the June 30, 2003 balance of $5.5 million was classified as "Other current assets" in the balance sheet). Lease payments will be approximately $900,000 per year for the next seven years, with an option to prepay the lease after six years. Our hedging obligations are discussed in Note 9 to the Consolidated Financial Statements. Otherwise, neither the amounts nor the terms of any other commitment or contingent obligation has changed significantly from the year-end 2002 amounts reflected in our 2002 Form 10-K filed in March 2003. The significant changes to our debt obligations, which are recorded on our balance sheet, are discussed above under "Debt Refinancing" and Capital Resources and Liquidity. Please refer to Management's Discussion and Analysis of Financial Condition and Results of Operations contained in our 2002 Form 10-K for further information regarding our commitments and obligations. RESULTS OF OPERATIONS CO2 Operations During late July and early August 2003, we upgraded our CO2 facility at Jackson Dome, increasing the CO2 processing capacity of our facility by approximately 50%, from around 200 MMcf/d to approximately 300 MMcf/d. This upgrade was performed several months ahead of our original schedule to handle the higher than expected production volumes from our CO2 wells drilled during late 2002 and early 2003. At the same time, we increased the size of our CO2 processing facility at Mallalieu Field, increasing the amount of CO2 that we can recycle at that field from approximately 28 MMcf/d to approximately 108 MMcf/d. During July, we completed our third CO2 well drilled during the last twelve months, the Barksdale, which coupled with the upgraded Jackson Dome facility, increases our CO2 production capabilities to approximately 220 MMcf/d, approximately double the production capacity of one year ago. Since our CO2 wells have been performing at higher production rates than originally anticipated, the third CO2 well originally scheduled for 2003 has been postponed until very late in the year, or perhaps even early in 2004. Based on our inventory of potential tertiary recovery projects, we will need to drill additional CO2 wells in 2004 and beyond to further increase our CO2 production capacity to an estimated target rate of 350 MMcf/d in order to develop the oil fields along our CO2 pipeline as planned, or perhaps to potentially even higher levels if we expand our tertiary operations to other parts of the region. Although we believe that our plans and projections are reasonable and achievable, there could be unforeseen delays or problems in the future which could delay our overall tertiary development program. We believe that such delays, if any, should only be temporary. As of December 31, 2002, based on a report prepared by DeGolyer and MacNaughton, we estimate that we have approximately 1.6 trillion cubic feet of usable CO2 reserves. Oil production from our CO2 tertiary recovery activities increased 4% over first quarter 2003 levels to 4,522 Bbls/d in the second quarter of 2003, representing approximately 24% of our total corporate oil production during the second quarter. This increase occurred in spite of a leak in a newly installed CO2 pipeline during the second quarter which forced us to significantly curtail our CO2 production and corresponding injections for approximately ten days. Our experience has indicated that any time that our CO2 production and associated injections are curtailed, there is a corresponding drop in our oil production from these projects. While second quarter tertiary oil production was higher than comparable production in the first quarter, it was less than originally anticipated, primarily due to curtailed CO2 production and injections as a result of the pipeline leak. While our CO2 production capability is ahead of schedule, as noted in the first 21 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS paragraph of this section, the required expansion of our CO2 facility will have a negative impact on our CO2 injections during the third quarter of 2003. The expansion required a complete shutdown of the facility for approximately one week, thereby reducing our CO2 injections. While the operation was a success and helps us expand our program in the future, the temporary shutdown is expected to have a negative short-term effect on our tertiary oil production, and as such, we do not expect our average daily tertiary oil production to increase during the third quarter of 2003. This effect is expected to be temporary and we expect tertiary oil production to resume its escalation during the fourth quarter of 2003. We spent approximately $0.14 per Mcf to produce our CO2 during the second quarter of 2003, slightly higher than the 2002 average of $0.13 per Mcf, primarily due to higher royalty expenses, as certain of our royalty payments increase if the price of oil increases beyond a certain threshold, but less than first quarter 2003 CO2 costs of $0.16 per Mcf, primarily due to the recent higher production rates. The higher cost per Mcf of CO2 during 2003 contributed to a corresponding increase in the operating costs of our tertiary projects, as did electricity and other expenses, as we continue to inject and recycle higher volumes of CO2 each quarter. For the second quarter of 2003, our operating costs for our tertiary properties averaged $10.69 per BOE, higher than our 2002 average of $10.05 per BOE. Our tertiary recovery fields are expected to average between $9 and $10 per BOE in operating expenses over the life of the field, although the cost per BOE is usually higher at the beginning of each operation as there is a time lag between the initial injection of the CO2 into the reservoir and the response of increased oil production. This compares to a cost of around $5 per BOE for a more traditional oil property without secondary or tertiary operations. Operating Results Our operating results for the first six months and second quarter of 2003, excluding the loss on early retirement of debt in the second quarter of 2003 relating to the subordinated debt refinancing, were slightly better than our results for the comparable periods of the prior year, primarily due to the higher commodity prices, particularly natural gas, partially offset by higher overall expenses. 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" and Note 3 to the Consolidated Financial Statements. The adoption of SFAS No. 143 is recorded as a cumulative effect adjustment of a change in accounting principle, net of income taxes, in our Consolidated Statements of Operations and is listed below on both a gross dollar and per share basis. 22 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Three Months Ended Six Months Ended June 30, June 30, -------------------------------------------------------- --------------------------- --------------------------- AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS 2003 2002 2003 2002 -------------------------------------------------------- ------------ ------------- ------------- ------------ Income before cumulative effect of change in accounting principle $ 5,129 $ 13,498 $ 23,582 $ 18,044 Cumulative effect of change in accounting principal, net of income tax expense of $1,600 - - 2,612 - ------------ ------------- ------------- ------------ Net income $ 5,129 $ 13,498 $ 26,194 $ 18,044 ============ ============= ============= ============ Net income per common share - basic: Income before cumulative effect of change in accounting principle $ 0.10 $ 0.25 $ 0.44 $ 0.34 Cumulative effect of change in accounting principle - - 0.05 - ------------ ------------- ------------- ------------ Net income per common share - basic $ 0.10 $ 0.25 $ 0.49 $ 0.34 ============ ============= ============= ============ Net income per common share - diluted: Income before cumulative effect of change in accounting principle $ 0.09 $ 0.25 $ 0.42 $ 0.33 Cumulative effect of change in accounting principle - - 0.05 - ------------ ------------- ------------- ------------ Net income per common share - diluted $ 0.09 $ 0.25 $ 0.47 $ 0.33 ============ ============= ============= ============ RECONCILIATION OF GAAP AND NON-GAAP MEASURES Adjusted cash flow from operations (see below) $ 48,989 $ 43,423 $ 96,355 $ 71,947 Net change in assets and liabilities relating to operations 11,553 3,149 (304) (13,343) ------------ ------------- ------------- ------------ Cash flow from operations (1) $ 60,542 $ 46,572 $ 96,051 $ 58,604 ============ ============= ============= ============
(1) Net cash flow provided by operations as per the 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 summarized from our Consolidated Statements of Cash Flows. In our discussion of cash flow from operations herein, we have elected to discuss the two primary components of cash flow provided by operations. Adjusted cash flow from operations 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 period. We also use this measure because the collection of our receivables or payment of our obligations generally have 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 second quarter of 2003 we generated approximately $11.6 million of cash by reducing our net working capital. This reduction primarily relates to the collection in April of unusually high dollar amounts of accrued production receivables at March 23 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 31, 2003, due to high natural gas prices for March production of approximately $9.28 per MMBtu. Similarly, we used a significant amount of cash flow from operations in the first half of 2002 to fund a $13.3 million increase in working capital, primarily relating to a significant reduction of our payables and accrued liabilities in early 2002 following a high level of drilling and exploitation activity late in 2001. While both are components of the GAAP measure, we believe that it makes sense to discuss them independently. Certain of our operating results and statistics for the comparative first six months and second quarters of 2003 and 2002 are included in the following table.
Three Months Ended Six Months Ended June 30, June 30, ---------------------------------------------------------------------------------------- ------------------------- 2003 2002 2003 2002 --------------------------------------------------------------------------- ------------ ------------- ----------- AVERAGE DAILY PRODUCTION VOLUME Bbls 18,957 17,921 19,259 17,831 Mcf 96,558 105,634 97,857 105,680 BOE(1) 35,050 35,526 35,569 35,444 OPERATING REVENUES AND EXPENSES (THOUSANDS) Oil sales $ 43,922 $ 37,404 $ 96,135 $ 65,237 Natural gas sales 50,830 33,710 110,341 56,787 Gain (loss) on settlements of derivative contracts (13,356) 12 (41,041) 2,648 ------------- ------------ ------------- ----------- Total oil and natural gas revenues $ 81,396 $ 71,126 $ 165,435 $ 124,672 ============= ============ ============= =========== Lease operating expenses $ 23,048 $ 17,124 $ 45,450 $ 32,552 Production taxes and marketing expenses 3,466 3,297 7,362 5,911 ------------- ------------ ------------- ----------- Total production expenses $ 26,514 $ 20,421 $ 52,812 $ 38,463 ============= ============ ============= =========== CO2 sales to industrial customers $ 2,445 $ 1,896 $ 4,634 $ 3,386 CO2 operating costs 534 362 851 529 ------------- ------------ ------------- ----------- CO2 operating margin $ 1,911 $ 1,534 $ 3,783 $ 2,857 ============= ============ ============= =========== UNIT PRICES-INCLUDING IMPACT OF HEDGES Oil price per barrel ("Bbl") $ 23.93 $ 22.94 $ 24.32 $ 20.36 Gas price per thousand cubic feet ("Mcf") 4.56 3.51 4.55 3.08 UNIT PRICES-EXCLUDING IMPACT OF HEDGES Oil price per Bbl $ 25.46 $ 22.94 $ 27.58 $ 20.21 Gas price per Mcf 5.78 3.51 6.23 2.97 OIL AND GAS OPERATING REVENUES AND EXPENSES PER BOE (1): Oil and natural gas revenues (before hedging) $ 29.71 $ 22.00 $ 32.07 $ 19.02 ============= ============ ============= =========== Oil and gas lease operating costs $ 7.23 $ 5.30 $ 7.06 $ 5.07 Oil and gas production taxes and marketing expenses 1.08 1.02 1.15 0.92 ------------- ------------ ------------- ----------- Total oil and gas production expenses $ 8.31 $ 6.32 $ 8.21 $ 5.99 ------------------------------------------------------------- ============= ============ ============= ===========
(1) Barrel of oil equivalent using the ratio of one barrel of oil to 6 Mcf of natural gas ("BOE"). 24 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 2002 and the first and second quarters of 2003 is listed in the following table.
Average Daily Production (BOE/d) -------------------------------------------------------------------- ------------- First Second Third Fourth First Second Quarter Quarter Quarter Quarter Quarter Quarter Operating Area 2002 2002 2002 2002 2003 2003 --------------------------------- ----------- ------------ ------------ ------------- ------------- ------------- Mississippi - non-CO2 floods 12,423 12,124 13,232 15,703 14,537 13,600 Mississippi - CO2 floods 3,839 4,278 3,895 3,863 4,345 4,522 Onshore Louisiana 8,405 7,717 8,224 7,859 8,509 8,231 Offshore Gulf of Mexico 10,550 11,229 9,863 8,287 8,544 8,537 Other 144 178 292 182 158 160 ----------- ------------ ------------ ------------- ------------- ------------- Total Company 35,361 35,526 35,506 35,894 36,093 35,050 --------------------------------- =========== ============ ============ ============= ============= =============
When comparing production in the first half and second quarters of 2002 and 2003, the COHO acquisition in August of 2002 (Mississippi - non-CO2 flood properties) was the single biggest source of production growth, adding 2,127 BOE/d to the second quarter of 2003 average production rate, net of the acquisition property (Laurel Field) sold in January 2003 (see paragraph below). We also benefited from a 375 BOE/d (9%) increase and 244 BOE/d (6%) increase in our tertiary recovery projects when comparing the respective first six months and second quarters of 2002 and 2003, respectively. Almost completely offsetting these increases were general production declines from normal depletion, coupled with less than expected production increases from first half 2003 exploration and development results and unexpected delays offshore and temporary CO2 curtailments (see CO2 Operations above. The net result was that overall production was almost the same when comparing the respective periods in 2002 and 2003. During the first quarter of 2003, we sold Laurel Field, a Mississippi non-CO2 flood property that had average production of between 1,500 and 1,700 BOE/d since we acquired it in August 2002. The field was sold effective January 31, 2003, causing a decrease in our first quarter 2003 production, as compared to the fourth quarter of 2002, by approximately 1,100 BOE/d, and reducing second quarter 2003 production by the full 1,500 to 1,700 BOE/d. Production in our first and second quarters of 2003 was also negatively affected by mechanical failures in two of our onshore Louisiana natural gas wells, reducing production by approximately 500 BOE/d in the first quarter and approximately 400 BOE/d in the second quarter. While both of these wells are currently producing, one well, the Leon Hebert Heirs, is still producing only at approximately 75% of its original rate, or about 200 BOE/d less than its average historical rate. We plan to leave the well at this reduced rate for a period of time in order to minimize the possibility of additional problems. Early in the third quarter, we drilled an exploratory discovery well at North Lirette Field, the Exxon Fee #1, which is currently producing at approximately 7.5 MMcf/d, net to us. We have preliminarily estimated that this initial discovery well developed between 10 and 15 Bcf of new proved reserves, net to us. We are currently drilling a second well to test further potential in this area, which is expected to be completed in late third quarter or early fourth quarter of 2003. The preliminary estimates of reserves and production from this discovery initially appear to more than make up for our less than expected exploration results during the first half of the year. 25 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Five offshore wells scheduled for the first seven months of 2003 have been delayed while waiting for partner approvals and clearance of other logistical issues. We have up to six wells scheduled for the last five months of 2003, although due to the timing, these wells will not have a meaningful production impact in 2003. The net effect of these schedule changes was minor to the second quarter production, but is expected to impact originally forecasted third and fourth quarter production by approximately 800 and 900 BOE/d, respectively. The installation of production facilities at North Padre Island, the Company's year-end 2002 discovery, is still on schedule, and this field is expected to commence production during the fourth quarter. With regard to specific fields, production increased at Heidelberg Field, a Mississippi non-CO2 flood property and our single largest field, from 7,458 BOE/d in the second quarter of 2002 to 7,612 BOE/d in the second quarter of 2003, as a result of incremental natural gas production from several wells drilled at Heidelberg during the last twelve months. During the second quarter of 2003, natural gas production averaged 10.4 MMcf/d, making Heidelberg Field our second largest natural gas field (as measured by current quarter production). Production at Thornwell Field averaged 2,820 BOE/d (mostly natural gas) during the second quarter of 2003, down from 3,479 BOE/d during the comparable quarter of 2002. Most of the production at Thornwell Field is short-lived natural gas production that fluctuates with drilling activity. During 2003, we have drilled three wells at Thornwell Field area, one of which was unsuccessful. We are continuing development and exploration activities at Thornwell Field in 2003, although at a lower level than in 2002. Our production for the second quarter of 2003 was weighted slightly towards oil (54%), primarily due to the mechanical problems with two onshore Louisiana natural gas wells, less than expected results in natural gas wells drilled or re-worked during the first six months of 2003, and delays in drilling offshore, all as discussed above. Due to the these issues, it appears that we will remain weighted slightly towards oil throughout 2003, unless we make any acquisitions that are predominately oil or predominantly natural gas. OIL AND NATURAL GAS REVENUES: Oil and natural gas revenues, net of hedge receipts and payments, for the second quarter of 2003 increased $10.3 million, or 14%, from the comparable quarter of 2002, but decreased when comparing the second quarter of 2003 with the first quarter of 2003. The increase in oil and natural gas revenues when comparing the two second quarters was primarily due to the increase in commodity prices, which increased these revenues by $24.6 million, or 34%, from levels in the prior year quarter. This increase was partially offset by a slight decrease in production volumes, which decreased these revenues by $0.9 million, or 1%. In addition, significant losses on the settlements of derivative contracts reduced these revenues by $13.4 million, or 19%, when comparing the two second quarters. Oil and natural gas revenues, net of hedge receipts and payments, for the first half of 2003 increased $40.8 million, or 33%, from the comparable first half of 2002, also primarily due to the increase in commodity prices, which increased revenues by $84.0 million, or 67%, from levels in the first half of 2002. Production volumes were almost identical between the respective first six months, causing only a slight increase in revenue of $400,000. These increases were partially offset by significant losses on the settlements of derivative contracts, which reduced revenues by $43.6 million, or 35%, when comparing the two respective first halves. Our realized natural gas prices (excluding hedges) for the second quarter and first half of 2003 averaged $5.78 per Mcf and $6.23 per Mcf respectively, a 65% and 110% increase from the average of $3.51 per Mcf and $2.97 per Mcf realized during the second quarter and first half of 2002. Our realized oil prices (excluding hedges) for the second quarter and first half of 2003 averaged $25.46 per Bbl and $27.58 per Bbl, respectively, an 11% and 36% increase from the $22.94 per Bbl and $20.21 per Bbl average realized in the second quarter and first half of 2002. Under our hedges, we paid out a sizable portion of our increase in revenues due to commodity prices, with the payment of $13.4 million on our hedges in the second quarter of 2003 and $41.0 million in the first half of 2003, as compared to collections of $12,000 on our commodity hedges in the second quarter of 2002 and $2.6 million in the first half of 2002. 26 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS During 2002, we received an average discount to NYMEX prices on our oil production of approximately $3.73 per Bbl, ranging from $3.30 to $4.25 per Bbl on a quarterly basis. During 2003, the first quarter discount was $4.22 per Bbl while the discount during the second quarter improved to $3.47 per Bbl, one of the lowest discounts we have experienced in our recent corporate history. This is similar to the trend in 2002, during which the lowest discount for the year was during the second quarter. Although this has had little impact to date on our year-over-year comparisons, it does have a significant impact on our cash flow from quarter to quarter, as it directly impacts our net realized oil price. While this discount is difficult to predict, as it fluctuates due to several different market factors, we do not anticipate that it will remain at the second quarter level for the rest of 2003. Long term, we expect our average discount to gradually improve from our historically high levels, as a larger percentage of our oil production will come from our tertiary recovery operations, which produce a light, sweet oil that receives a price that approximates NYMEX prices. On a weighted average net price per BOE, we received $7.71 and $13.05 per BOE more for our production (excluding hedges) in the second quarter and first half of 2003, respectively, than in the comparable periods of 2002. However, we paid out approximately $4.19 per BOE and $6.37 per BOE on our oil and natural gas hedges in the same 2003 periods, respectively, as compared to minor cash receipts in the prior year quarter and $0.41 per BOE of receipts in the prior year first half, reducing our net realized price increase to approximately $3.52 per BOE between the respective second quarters and approximately $6.27 per BOE between the respective first six months. PRODUCTION EXPENSES: Lease operating expenses increased to $7.23 per BOE and $7.06 per BOE in the second quarter and first half of 2003, respectively, from $5.30 per BOE and $5.07 per BOE in the comparable periods of 2002, both of which were also higher than our fourth quarter 2002 average of $6.34 per BOE. The costs of the two workovers relating to mechanical failures at two onshore Louisiana gas wells discussed above, totaling approximately $850,000 in the first quarter and $2.0 million in the second quarter of 2003, were the biggest source of the increase, although continued high expenses on the properties acquired from COHO, continued expansion of CO2 tertiary projects (which typically have a higher than average cost per BOE), along with higher lease fuel costs caused by high natural gas prices, also contributed to the higher than historical level of operating costs. We anticipate that our lease operating expenses on a per BOE basis will be lower during the last half of the year, assuming a return to normal operating parameters. Production taxes and marketing expenses also increased to $1.08 per BOE and $1.15 per BOE in the second quarter and first half of 2003, respectively, from $1.02 per BOE and $0.92 per BOE in the comparable periods of 2002, primarily due to higher commodity prices. General and Administrative Expenses General and administrative ("G&A") expenses increased 4% and 10% on a per BOE basis between the respective second quarters and respective first six months, as set forth below:
Three Months Ended Six Months Ended June 30, June 30, ------------------------------------------- --------------------------------- -------------------------------- 2003 2002 2003 2002 ------------------------------------------- --------------- --------------- -------------- --------------- NET G&A EXPENSE (THOUSANDS) Gross G&A expenses $ 10,971 $ 9,471 $ 22,403 $ 18,980 State franchise taxes 358 361 721 728 Operator overhead charges (6,508) (5,345) (13,023) (10,548) Capitalized exploration costs (1,445) (1,193) (2,934) (2,650) --------------- --------------- -------------- --------------- Net G&A expense $ 3,376 $ 3,294 $ 7,167 $ 6,510 =============== =============== ============== =============== Average G&A expense per BOE $ 1.06 $ 1.02 $ 1.11 $ 1.01 Employees as of June 30 369 332 369 332 ------------------------------------------- --------------- -------------- -------------- ---------------
27 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Gross G&A expenses increased $1.5 million and $3.4 million, or 16% and 18%, between the second quarters and first six months of 2002 and 2003, respectively. The largest components of this increase relate to expenses associated with the recent sale of stock by the Texas Pacific Group in the first quarter of 2003, higher year-end expenses than in the prior year for engineering fees and audit fees, incremental expenses associated with the requirements of the Sarbanes-Oxley Act and an overall increase in personnel and associated expenses. The increase in gross G&A is offset in part by an increase in operator overhead recovery charges and capitalized exploration costs in 2003. Our well operating agreements allow us, when we are the operator, to charge a well with a specified overhead rate during the drilling phase and also charge a monthly fixed overhead rate for each producing well. As a result of the additional operated wells from our recent acquisitions and drilling activity during the past year, the amount we recovered as operator overhead charges increased by 22% and 23% between the respective second quarters and first six months of 2002 and 2003, respectively. Capitalized exploration costs increased slightly between the comparable periods in 2002 and 2003, along with the increase in employees, employee related costs and certain administrative overhead costs. The net effect of the increase in gross G&A expenses, operator overhead charges and capitalized exploration costs was a 2% and 10% increase in net G&A expense between the respective second quarters and first six months. On a per BOE basis, G&A expenses increased 4% and 10% in the second quarter and first half of 2003 as compared to the comparable periods of 2002. Interest and Financing Expenses
Three Months Ended Six Months Ended June 30, June 30, ----------------------------------------------------- ----------------------------- --------------------------- AMOUNTS IN THOUSANDS, EXCEPT PER BOE AMOUNTS 2003 2002 2003 2002 ----------------------------------------------------- -------------- ------------- ------------ ------------ Interest expense $ 6,227 $ 6,572 $ 12,688 $ 13,226 Non-cash interest expense (296) (650) (799) (1,301) -------------- ------------- ------------ ------------ Cash interest expense 5,931 5,922 11,889 11,925 Interest and other income (347) (411) (551) (822) -------------- ------------- ------------ ------------ Net cash interest expense $ 5,584 $ 5,511 $ 11,338 $ 11,103 ============== ============= ============ ============ Average net cash interest expense per BOE $ 1.75 $ 1.70 $ 1.76 $ 1.73 Average interest rate (1) 6.5% 6.9% 6.6% 7.0% Average debt outstanding $ 367,747 $ 342,593 $ 359,696 $ 342,502 ----------------------------------------------------- -------------- ------------- ------------ ------------
(1) Includes commitment fees but excludes amortization of debt issue costs. Interest expense for the second quarter of 2003 decreased from levels in the comparable prior year period primarily due to (i) lower overall interest rates, in part due to the refinancing of our subordinated debt (see "Debt Refinancing" above), as our average outstanding debt balance was 7% higher in the second quarter of 2003, and (ii) reduced debt issue cost amortization resulting from the complete amortization of costs associated with the original maturity of our bank credit line in December 2002. The primary reason for the higher average debt levels in the second quarter of 2003 was that both issues of subordinated debt were outstanding for 16 days during the quarter due to the mechanics of the required 30 day notice to call the old notes. Partially offsetting the interest expense savings was a slight decrease in our interest and other income in the second quarter of 2003. We expect a further decrease in interest expense as a result of the refinancing of our subordinated debt, which is expected to save approximately $2.6 million per year in interest expense. This decrease will not be fully recognized until the third quarter of 2003, as the old subordinated debt was not retired until April 16, 2003. Interest expense decreased between the respective six month periods for similar reasons, although the decrease was not as substantial on a percentage basis as in the comparable second quarters, as the subordinated debt refinancing was not completed until April 16, 2003. 28 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Depletion, Depreciation and Amortization
Three Months Ended Six Months Ended June 30, June 30, ---------------------------------------------------- ----------------------------- ----------------------------- AMOUNTS IN THOUSANDS, EXCEPT PER BOE AMOUNTS 2003 2002 2003 2002 ---------------------------------------------------- ------------- ------------- ------------- -------------- Depletion and depreciation $ 21,449 $ 22,383 $ 43,429 $ 43,599 Depreciation of CO2 assets 592 613 1,030 1,139 Accretion of discount on asset retirement obligations 684 - 1,503 - Site restoration provision - 789 - 1,563 Depreciation of other fixed assets 405 420 721 830 ------------- ------------- ------------- -------------- Total DD&A $ 23,130 $ 24,205 $ 46,683 $ 47,131 ============= ============= ============= ============== DD&A per BOE: Oil and natural gas properties $ 6.94 $ 7.17 $ 6.98 $ 7.04 CO2 assets and other fixed assets 0.31 0.32 0.27 0.31 ------------- ------------- ------------- -------------- Total DD&A cost per BOE $ 7.25 $ 7.49 $ 7.25 $ 7.35 --------------------------------------------------- ============= ============= ============= ==============
In total, our depletion, depreciation and amortization ("DD&A") rate on a per BOE basis was almost the same in the second quarters and first six months of 2003 and 2002, and similar to the average rate per BOE during 2002. Our DD&A rate is evaluated each quarter and is adjusted to our best estimate of projected reserves at year-end, and estimated production and capital expenditures for the full year 2003. Based on the ultimate outcome of these factors, we adjust our DD&A computation for the full year in the fourth quarter. Although, as previously stated, our exploration results in the first six months of 2003 were not as good as expected; however, we have had recent success in a new discovery at Lirette Field and we have up to an additional five exploratory wells planned for the remainder of 2003. Also, we are in the process of expanding our tertiary recovery properties and expect that we will be able to add additional reserves by year-end. Based on our current estimates related to these items, we have left our DD&A rate unchanged from the first quarter of 2003. However, depending on the outcome of these estimates and other factors that could change before year-end 2003, our DD&A rate could change significantly in the last half of 2003. Effective January 1, 2003, we adopted Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations." 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 that the corresponding amount be 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. If the liability is settled for an amount other than the recorded amount, the difference is recorded to the full cost pool, unless significant. The adoption of this statement resulted in a $2.6 million benefit to net income during the first quarter of 2003 and was recorded as a cumulative effect of a change in accounting principle in our Consolidated Statements of Operations. As part of the adoption, we ceased accruing for site reclamation costs, as had been our practice in the past, and recorded a $41.0 million liability representing the estimated present value of our retirement obligations, with a $34.4 million increase to oil and natural gas properties. On an undiscounted basis, we estimated that our retirement obligations as of January 1, 2003 to be $81.8 million, with an estimated salvage value of $43.3 million, also on an undiscounted basis. DD&A is calculated on the increase to oil and natural gas properties, net of estimated salvage value. We also include the accretion of discount on the asset retirement obligation in our DD&A expense. 29 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Income Taxes
Three Months Ended Six Months Ended June 30, June 30, ---------------------------------------------------------- ------------------------- --------------------------- AMOUNTS IN THOUSANDS, EXCEPT PER BOE AMOUNTS AND TAX RATES 2003 2002 2003 2002 ---------------------------------------------------------- ------------ ----------- ------------ ------------ Current income tax expense (benefit) $ (1,093) $ 33 $ 1,637 $ (448) Deferred income tax expense 3,527 6,080 9,882 7,538 ------------ ----------- ------------ ------------ Total income tax expense $ 2,434 $ 6,113 $ 11,519 $ 7,090 ============ =========== ============ ============ Average income tax expense per BOE $ 0.76 $ 1.89 $ 1.79 $ 1.11 Effective tax rate 32.2% 31.2% 32.8% 28.2% ---------------------------------------------------------- ------------ ----------- ------------ ------------
Our income tax provision for the second quarter and first half of 2002 was based on an estimated effective tax rate of 37%, although we increased this effective rate to 38% in the third quarter of 2002. 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. During 2002, we utilized alternative minimum tax loss carryfowards, virtually eliminating our current tax expense. The current income tax credit in the first six months of 2002 was the result of a tax law change that allowed us to offset 100% of our 2001 alternative minimum taxes with our alternative minimum tax net operating loss carryforwards. Prior to the law change, we were able to offset only 90% of our alternative minimum taxes with these carryforwards. This change resulted in a reclassification of tax expense between current and deferred taxes and did not impact our overall effective tax rate. As of January 1, 2003, we had utilized virtually all of the alternative minimum tax carryforwards and thus recognized current income tax expense for the projected alternative minimum taxes that are expected to be incurred during 2003. 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. 30 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Per BOE Data The following table summarizes the 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 2003 2002 2003 2002 ---------------------------------------------------------- ------------- ------------- ------------ ------------ Revenue $ 29.71 $ 22.00 $ 32.07 $ 19.02 Gain (loss) on settlements of derivative contracts (4.19) - (6.37) 0.41 Lease operating expenses (7.23) (5.30) (7.06) (5.07) Production taxes and marketing expenses (1.08) (1.02) (1.15) (0.92) ---------------------------------------------------------- ------------- ------------- ------------ ------------ Production netback 17.21 15.68 17.49 13.44 Operating cash flow from CO2 operations 0.60 0.47 0.59 0.45 General and administrative expenses (1.06) (1.02) (1.11) (1.01) Net cash interest expense (1.75) (1.70) (1.76) (1.73) Current income taxes and other 0.36 - (0.24) 0.06 Changes in assets and liabilities 3.62 0.98 (0.05) (2.08) ---------------------------------------------------------- ------------- ------------- ------------ ------------ Cash flow from operations 18.98 14.41 14.92 9.13 DD&A (7.25) (7.49) (7.25) (7.35) Deferred income taxes (1.11) (1.88) (1.54) (1.18) Amortization of derivative contracts and other non-cash hedging adjustments 0.24 0.31 0.35 0.33 Early retirement of subordinated debt (5.53) - (2.74) - Cumulative effect of a change in accounting principle - - 0.41 - Changes in assets and liabilities and other non-cash items (3.72) (1.18) (0.08) 1.88 ---------------------------------------------------------- ------------- ------------- ------------ ------------ Net income $ 1.61 $ 4.17 $ 4.07 $ 2.81 ---------------------------------------------------------- ============= ============= ============ ============
NEW ACCOUNTING STANDARDS In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." SFAS No. 149 amends and clarifies certain accounting and reporting for derivative instruments. This statement is effective for contracts entered into or modified after June 30, 2003. We will adopt this statement in the third quarter of 2003 and it should not have any impact on our financial statements. SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets," became effective July 1, 2001 and January 1, 2002, respectively. It is our understanding that the Securities and Exchange Commission has raised questions as to the proper application by registrants in the oil and gas industry of the provisions of SFAS No. 141 and SFAS No. 142 and that the FASB and representatives from the SEC are currently in discussions regarding this issue. In question is whether the acquisition of contractual mineral interests, including both proved and undeveloped, should be classified separately as "intangible assets" on the balance sheet apart from other oil and gas property costs. Currently, 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. Until we receive further guidance regarding this issue, we will continue to include mineral interests as oil and gas properties on our balance sheet for mineral interests acquired subsequent to June 30, 2001. Based on the limited guidance pertaining to this issue, we have not calculated the potential balance sheet reclassification at this time. The provisions of SFAS No. 141 and 142 impact only the balance sheet and associated footnote disclosure, and any reclassifications, if necessary, would not impact the Company's results of operations or cash flows. 31 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 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 ---------------------------------------- ------------------------------------------------ ----------- ----------- Carrying Fair Amounts in Thousands 2003-2005 2006 2007 Thereafter Value Value ---------------------------------------- ----------- ----------- ------------ ----------- ----------- ----------- Variable rate debt: Bank debt.......................... $ - $110,000 $ - $ - $110,000 $110,000 The weighted-average interest rate on the bank debt at June 30, 2003 was 3.0%. Fixed rate debt: 7.5% subordinated debt, net of discount, due 2013............... $ - $ - $ - $225,000 $223,106 $232,875 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. These contracts have historically consisted of price floors, collars and fixed price swaps. We generally attempt to hedge between 50% 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. 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. Our recent hedging activity has been predominately through the purchase of collars, although for the recent COHO acquisition, we also used swaps in order to lock in the prices used in our economic forecasts. 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 counter party credit risk through established internal control procedures which are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counter parties through formal credit policies, monitoring procedures, and diversification. At June 30, 2003, our derivative contracts were recorded at their fair value, which was a net liability of approximately $58.4 million, an increase of approximately $22.8 million from the $35.6 million fair value liability recorded as of December 31, 2002. This change is the result of (i) a decrease in the fair market value of our hedges due to an increase in oil and natural gas commodity prices between December 31, 2002 and June 30, 2003, and (ii) the expiration of certain derivative contracts during 2003 for which we recorded amortization expense of $591,000. Information regarding our current hedging positions is included in Note 9 to the Consolidated Financial Statements. Based on NYMEX natural gas futures prices at June 30, 2003, we would expect to make future cash payments of $40.4 million on our natural gas commodity hedges. If natural gas futures prices were to decline by 10%, the amount we would expect to pay under our natural gas commodity hedges would decrease to $20.9 million, and if futures prices were to increase by 10% we would expect to pay $61.9 million. Based on NYMEX crude oil futures prices at June 30, 2003, we would expect to pay $15.4 million on our crude oil commodity hedges. If crude oil futures prices were to decline by 10%, we would expect to pay $2.9 million, and if crude oil futures prices were to increase by 10%, we would expect to pay $31.5 million under our crude oil commodity hedges. 32 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 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 and hedging activities, and which remain unchanged, see our annual report on Form 10-K for the year ended December 31, 2002. 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. 33 DENBURY RESOURCES INC. 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. 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 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS ------------------------------------------------------------ Denbury's Annual Meeting of Shareholders was held on May 20, 2003 for the purposes of: (1) electing nine Directors of Denbury for one-year terms to expire at the 2004 Annual Meeting of Shareholders, and (2) increasing the number of shares issuable under the Company's Employee Stock Option Plan by 850,000 shares. At the record date, April 4, 2003, 53,741,052 shares of common stock were outstanding and entitled to one vote per share upon all matters submitted at the meeting. Holders of 43,976,489 shares of common stock, representing approximately 82% 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 nine director nominees were re-elected. The votes were cast as follows:
NOMINEES FOR DIRECTORS FOR AGAINST ---------------------- ----------------- ------------------ Ronald G. Greene 43,260,167 716,322 David Bonderman 35,093,388 8,883,101 David I. Heather 43,260,167 716,322 David B. Miller 43,260,167 716,322 William S. Price, III 43,260,167 716,322 Gareth Roberts 36,934,925 7,041,564 Jeffrey Smith 43,260,167 716,322 Wieland F. Wettstein 43,260,167 716,322 Carrie A. Wheeler 43,260,167 716,322
The proposed increase in the shares issuable under the Company's Employee Stock Option Plan was also approved. The votes were cast as follows:
FOR AGAINST ABSTENTIONS ----------------- ---------------- ------------------- 39,975,053 3,491,562 509,874
34 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K DURING THE SECOND QUARTER OF 2003 ---------------------------------------------------------------------------
EXHIBITS: -------- 4(a) Indenture for $225 million of 7-1/2% Senior Subordinated Notes Due 2013 among Denbury Resources Inc., certain of its subsidiaries and JPMorgan Chase Bank as trustee, dated March 25, 2003 (incorporated by reference to Exhibit 4(a) to our Registration Statement No. 333-105233 on Form S-4, dated May 14, 2003). 10(a) Denbury Resources Inc. Amended and Restated Stock Option Plan (incorporated by reference to Exhibit 99 of our Registration Statement No. 333-106253 on Form S-8, dated June 18, 2003). 10(b)* Second Amendment to Third Amended and Restated Credit Agreement. 15* Letter from Independent Accountants as to unaudited interim financial information. 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 May 1, 2003, we filed a Form 8-K which included our press release on our first quarter 2003 earnings. 35 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 12, 2003 36