-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, SxJgopCTMsOp4wEQrMfzUAh9duL+eTd7wnSSnMpncGeJ04aqxqRmhAr/QOTVlKSJ /eCrioIrsIvrWBOatzT9eA== 0000899078-04-000736.txt : 20041109 0000899078-04-000736.hdr.sgml : 20041109 20041108180643 ACCESSION NUMBER: 0000899078-04-000736 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 20040930 FILED AS OF DATE: 20041109 DATE AS OF CHANGE: 20041108 FILER: COMPANY DATA: COMPANY CONFORMED NAME: DENBURY RESOURCES INC CENTRAL INDEX KEY: 0000945764 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 752815171 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-12935 FILM NUMBER: 041126975 BUSINESS ADDRESS: STREET 1: 5100 TENNYSON PARKWAY STREET 2: SUITE 3000 CITY: PLANO STATE: TX ZIP: 75024 BUSINESS PHONE: 9726732000 MAIL ADDRESS: STREET 1: 5100 TENNYSON PARKWAY STREET 2: SUITE 3000 CITY: PLANO STATE: TX ZIP: 75024 FORMER COMPANY: FORMER CONFORMED NAME: NEWSCOPE RESOURCES LTD DATE OF NAME CHANGE: 19950627 10-Q 1 denbury3rdq10q2004.txt 3RD QUARTER 10-Q - 2004 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 September 30, 2004 [ ] Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Commission file number 1-12935 DENBURY RESOURCES INC. (Exact name of Registrant as specified in its charter) Delaware 20-0467835 (State or other jurisdictions of (I.R.S. Employer incorporation or organization) Identification No.) 5100 Tennyson Parkway Suite 3000 Plano, TX 75024 (Address of principal executive offices) (Zip code) Registrant's telephone number, including area code: (972) 673-2000 Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes [X] No [ ] Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Class Outstanding at October 29, 2004 ----- ------------------------------- Common Stock, $.001 par value 56,355,352
INDEX Page ---- Part I. Financial Information - ------------------------------ Item 1. Financial Statements Unaudited Condensed Consolidated Balance Sheets at September 30, 2004 and December 31, 2003 3 Unaudited Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2004 and 2003 4 Unaudited Condensed Consolidated Statements of Cash Flows for the Three and Nine Months Ended September 30, 2004 and 2003 5 Unaudited Condensed Consolidated Statements of Comprehensive Operations for the Three and Nine months Ended September 30, 2004 and 2003 6 Notes to Unaudited Condensed Consolidated Financial Statements 7-20 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 21-33 Item 3. Quantitative and Qualitative Disclosures about Market Risk 34 Item 4. Controls and Procedures 34 Part II. Other Information --------------------------- Item 1. Legal Proceedings 34 Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 34 Item 3. Defaults Upon Senior Securities N/A Item 4. Submission of Matters to a Vote of Security Holders N/A Item 5. Other Information N/A Item 6. Exhibits 35 Signatures 36
2
DENBURY RESOURCES INC. UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS (Amounts in thousands except share amounts) September 30, December 31, 2004 2003 --------------- -------------- Assets Current assets Cash and cash equivalents $ 93,142 $ 24,188 Short-term investments 31,955 - Accrued production receivables 36,062 33,944 Related party receivable - Genesis 534 6,927 Trade and other receivables 14,218 18,080 Deferred tax asset 31,664 25,016 Derivative assets 1,888 - ---------------- --------------- Total current assets 209,463 108,155 ---------------- --------------- Property and equipment Oil and natural gas properties (using full cost accounting) Proved 1,276,701 1,409,579 Unevaluated 23,171 46,065 CO2 properties and equipment 132,112 85,467 Other 19,035 16,450 Less accumulated depletion and depreciation (687,083) (705,050) ---------------- --------------- Net property and equipment 763,936 852,511 ---------------- --------------- Investment in Genesis 7,034 7,450 Other assets 11,276 14,505 ---------------- --------------- Total assets $ 991,709 $ 982,621 ================ =============== Liabilities and Stockholders' Equity Current liabilities Accounts payable and accrued liabilities $ 64,006 $ 62,349 Oil and gas production payable 22,963 22,215 Payable to Newfield Exploration Company 16,020 - Derivative liabilities 37,796 42,010 ---------------- --------------- Total current liabilities 140,785 126,574 ---------------- --------------- Long-term liabilities Long-term debt 223,348 298,203 Asset retirement obligations 16,620 41,711 Derivative liabilities 1,979 2,603 Deferred revenue - Genesis 24,018 21,468 Deferred tax liability 82,885 68,555 Other 1,444 2,305 ---------------- --------------- Total long-term liabilities 350,294 434,845 ---------------- --------------- Commitments and contingencies Stockholders' equity Common stock, $.001 par value, 100,000,000 shares authorized; 56,443,422 and 54,190,042 shares issued at September 30, 2004 and December 31, 2003, respectively 56 54 Paid-in capital in excess of par 438,417 401,709 Deferred compensation (22,427) - Retained earnings 106,623 46,656 Accumulated other comprehensive loss (20,779) (27,113) Treasury stock, at cost, 64,779 and 8,162 shares at September 30, 2004 and December 31, 2003, respectively (1,260) (104) ---------------- --------------- Total stockholders' equity 500,630 421,202 ---------------- --------------- Total liabilities and stockholders' equity $ 991,709 $ 982,621 ================ =============== (See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
3
DENBURY RESOURCES INC. UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Amounts in thousands except per share amounts) Three Months Ended Nine Months Ended September 30, September 30, ------------------------- -------------------------- 2004 2003 2004 2003 ------------ ------------ ------------- ------------ Revenues and other income Oil, natural gas and related product sales Unrelated parties $ 82,502 $ 78,333 $ 269,482 $ 261,219 Related party - Genesis 20,566 10,463 62,893 34,053 CO2 sales and transportation fees Unrelated parties 307 2,238 910 6,872 Related party - Genesis 1,374 - 3,712 - Loss on settlements of derivative contracts (22,243) (12,031) (54,750) (53,072) Interest income and other 701 412 1,450 963 ------------ ------------ ------------- ------------ Total revenues and other income 83,207 79,415 283,697 250,035 ------------ ------------ ------------- ------------ Expenses Lease operating expenses 19,781 22,400 66,839 67,850 Production taxes and marketing expenses 4,634 3,761 13,215 11,124 Transportation expense - Genesis 266 - 266 - CO2 operating expenses 255 602 608 1,453 General and administrative expenses 6,197 3,445 15,123 10,612 Interest 4,768 5,358 14,917 18,046 Loss on early retirement of debt - - - 17,629 Depletion, depreciation and amortization 20,780 22,566 76,265 69,249 Non-cash hedging adjustments 383 (1,441) 8,347 (3,702) ------------ ------------ ------------- ------------ Total expenses 57,064 56,691 195,580 192,261 ------------ ------------ ------------- ------------ Equity in net income (loss) of Genesis (37) (25) (28) 26 ------------ ------------ ------------- ------------ Income before income taxes 26,106 22,699 88,089 57,800 Income tax provision (benefit) Current income taxes 18,949 (1,514) 22,045 123 Deferred income taxes (11,117) 9,064 6,077 18,946 ------------ ------------ ------------- ------------ Income before cumulative effect of change in accounting principle 18,274 15,149 59,967 38,731 Cumulative effect of change in accounting principle, net of income taxes of $1,600 - - - 2,612 ------------ ------------ ------------- ------------ Net income $ 18,274 $ 15,149 $ 59,967 $ 41,343 ============ ============ ============= ============ Net income per common share - basic Income before cumulative effect of change in accounting principle $ 0.33 $ 0.28 $ 1.10 $ 0.72 Cumulative effect of change in accounting principle - - - 0.05 ------------ ------------ ------------- ------------ Net income per common share - basic $ 0.33 $ 0.28 $ 1.10 $ 0.77 ============ ============ ============= ============ Net income per common share - diluted Income before cumulative effect of change in accounting principle $ 0.32 $ 0.27 $ 1.05 $ 0.70 Cumulative effect of change in accounting principle - - - 0.05 ------------ ------------ ------------- ------------ Net income per common share - diluted $ 0.32 $ 0.27 $ 1.05 $ 0.75 ============ ============ ============= ============ Weighted average common shares outstanding Basic 55,085 54,014 54,740 53,824 Diluted 57,549 55,718 57,020 55,375 (See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
4
DENBURY RESOURCES INC. UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Amounts in thousands) Three Months Ended Nine Months Ended September 30, September 30, -------------------------- -------------------------- 2004 2003 2004 2003 ------------ ------------- ------------ ------------ Cash flow from operating activities: Net income $ 18,274 $ 15,149 $ 59,967 $ 41,343 Adjustments needed to reconcile to net cash flow provided by operations: Depreciation, depletion and amortization 20,780 22,566 76,265 69,249 Non-cash hedging adjustments 383 (1,441) 8,347 (3,702) Deferred income taxes (11,117) 9,064 6,077 18,946 Deferred revenue - Genesis (648) - (1,758) - Deferred compensation - restricted stock 593 - 593 - Loss on early retirement of debt - - - 17,629 Amortization of debt issue costs and other 1,482 273 2,230 1,113 Cumulative effect of change in accounting principle - - - (2,612) Changes in assets and liabilities: Accrued production receivable (412) 3,891 (11,248) 1,518 Trade and other receivables 5,635 3,322 3,862 178 Derivative assets and liabilities - - (7,518) - Other assets (32) 1 (32) 6 Accounts payable and accrued liabilities 15,552 (995) 16,263 1,219 Oil and gas production payable (4,280) (1,540) 748 2,199 Other liabilities (1,444) (501) (2,825) (1,246) ------------ ------------- ------------ ------------ Net cash provided by operations 44,766 49,789 150,971 145,840 ------------ ------------- ------------ ------------ Cash flow provided by investing activities: Oil and natural gas expenditures (35,981) (37,397) (125,745) (108,106) Acquisitions of oil and gas properties (1,663) (1,854) (3,861) (11,478) Acquisitions of CO2 assets and capital expenditures (15,825) (2,635) (42,966) (16,008) Net proceeds from CO2 production payment - Genesis 4,636 - 4,636 - Sale of Denbury Offshore, Inc. 186,753 - 186,753 - Proceeds from oil and gas property sales 380 1,174 1,526 29,328 Increase in restricted cash (119) (211) (470) (567) Purchases of short-term investments (31,957) - (31,957) - Net (purchases) sales of other assets (1,753) 5,428 (2,907) (1,545) ------------ ------------- ------------ ------------ Net cash provided by (used for) investing activities 104,471 (35,495) (14,991) (108,376) ------------ ------------- ------------ ------------ Cash flow from financing activities: Bank repayments (85,000) (6,000) (88,000) (131,000) Bank borrowings - - 13,000 85,000 Repayment of subordinated debt obligations, including redemption premium - - - (209,000) Issuance of subordinated debt, net of discount - - - 223,054 Issuance of common stock 2,425 1,138 11,099 4,108 Purchase of treasury stock (1,052) (641) (2,713) (641) Costs of debt financing (408) (31) (412) (4,817) ------------ ------------- ------------ ------------ Net cash used by financing activities (84,035) (5,534) (67,026) (33,296) ------------ ------------- ------------ ------------ Net increase in cash and cash equivalents 65,202 8,760 68,954 4,168 Cash and cash equivalents at beginning of period 27,940 19,348 24,188 23,940 ------------ ------------- ------------ ------------ Cash and cash equivalents at end of period $ 93,142 $ 28,108 $ 93,142 $ 28,108 ============ ============= ============ ============ Supplemental disclosure of cash flow information: Cash paid during the period for interest $ 176 $ 835 $ 9,639 $ 14,206 Cash paid during the period for income taxes 13,000 - 13,327 184 (See accompanying Notes to Unaudited Condensed Consolidated Financial Statements) 5
DENBURY RESOURCES INC. UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS (Amounts in thousands) Three Months Ended Nine Months Ended September 30, September 30, --------------------------- --------------------------- 2004 2003 2004 2003 ------------ ------------- ------------ ------------- Net income $ 18,274 $ 15,149 $ 59,967 $ 41,343 Other comprehensive income (loss), net of income tax: Change in fair value of derivative contracts, net of tax of $(8,916), $4,020, $(21,586), and $(20,318), respectively (14,547) 6,559 (35,220) (33,151) Reclassification adjustments related to settlements of derivative contracts, net of tax of $9,704, $4,167, $25,474 and $18,956, respectively 15,833 6,798 41,563 30,927 Unrealized loss on securities available-for-sale (9) - (9) - ------------ ------------- ------------ ------------- Comprehensive income $ 19,551 $ 28,506 $ 66,301 $ 39,119 ============ ============= ============ ============= (See accompanying Notes to Unaudited Condensed Consolidated Financial Statements) 6
DENBURY RESOURCES INC. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 1. BASIS OF PRESENTATION Interim Financial Statements The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the instructions to Form 10-Q and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. Unless indicated otherwise or the context requires, the terms "we," "our," "us," "Denbury" or "Company" refer to Denbury Resources Inc. and its subsidiaries. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2003. Any capitalized terms used but not defined in these Notes to Unaudited Condensed Consolidated Financial Statements have the same meaning given to them in the Form 10-K. Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the fiscal year. In management's opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments (of a normal recurring nature) necessary to present fairly the consolidated financial position of Denbury as of September 30, 2004 and the consolidated results of its operations and cash flows for the three and nine month periods ended September 30, 2004 and 2003. Certain prior period items have been reclassified to make the classification consistent with the classification in the most recent quarter. Short-term Investments The Company invests in highly liquid debt securities with strong credit ratings. Debt securities with a maturity greater than three months, but less than one year, at the time of purchase are considered to be short-term investments. The Company classifies its short-term investments in debt securities as available-for-sale in accordance with the provisions of Statement of Financial Accounting Standards No. 115, "Accounting for Certain Investments in Debt and Equity Securities." These debt securities are carried at fair market value, with unrealized gains and losses reported in stockholders' equity as a component of Accumulated Other Comprehensive Income (Loss). Non-Expense 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 No. 25, "Accounting for Stock Issued to Employees," and its related interpretations. Under these principles we do not recognize any stock-based employee compensation for stock option grants, as long as the exercise price is equal to the fair value of the underlying common stock on the date of grant. The following table illustrates the effect on net income and net income per common share as if we had applied the fair value recognition and measurement provisions of Statement of Financial Accounting Standards ("SFAS") No. 123, "Accounting for Stock-Based Compensation," as amended by SFAS No. 148, in accounting for our stock option plan. 7 DENBURY RESOURCES INC. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended Nine Months Ended September 30, September 30, -------------------------- ------------------------- 2004 2003 2004 2003 ------------ ------------ ------------ ------------ Net income: (thousands) Net income, as reported............................................ $ 18,274 $ 15,149 $ 59,967 $ 41,343 Add: stock-based compensation expense included in reported net income, net of related tax effects........................... 368 - 368 - Less: stock-based compensation expense applying fair value based method, net of related tax effects ........................ 1,764 1,005 5,236 2,638 ------------ ------------ ------------ ------------ Pro-forma net income .............................................. $ 16,878 $ 14,144 $ 55,099 $ 38,705 ============ ============ ============ ============ Net income per common share As reported: Basic ........................................................... $ 0.33 $ 0.28 $ 1.10 $ 0.77 Diluted.......................................................... 0.32 0.27 1.05 0.75 Pro forma: Basic ........................................................... $ 0.31 $ 0.26 $ 1.01 $ 0.72 Diluted ......................................................... 0.30 0.26 0.97 0.71
Recently Issued Accounting Standards In September 2004, the Financial Accounting Standards Board ("FASB") issued a FASB staff position that clarified the position that SFAS No. 142, "Goodwill and Other Intangible Assets," does not apply to the drilling and mineral rights of oil and gas producing entities that account for such rights in accordance with SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." In question was whether acquired contractual mineral interests, both proved and undeveloped, should be classified separately as "intangible assets" on the balance sheet apart from other oil and gas property costs. Denbury and virtually all other companies in the oil and gas industry have historically included purchased contractual mineral rights in oil and gas properties on the balance sheet. The FASB staff position has no impact on the classification of Denbury's oil and gas property balances. In September 2004, the SEC issued Staff Accounting Bulletin No. 106 (SAB 106), which clarifies the calculation of the full cost ceiling and depreciation, depletion, and amortization ("DD&A") of oil and gas properties in conjunction with accounting for asset retirement obligations ("ARO") under SFAS No. 143. SAB 106 does not change our accounting for our full cost ceiling test or our calculation of DD&A for our oil and gas properties, as we are in compliance with the SEC views expressed in SAB 106. In July 2004, the Emerging Issues Task Force of the FASB issued EITF 04-05, "Investor's Accounting for an Investment in a Limited Partnership When the Investor is the Sole General Partner and the Limited Partners Have Certain Rights." In question is what rights held by the limited partners preclude consolidation of the limited partnership by the sole general partner. The Task Force noted that in practice differing views have evolved concerning this issue and it has asked the FASB staff to develop this issue for discussion at a future date. Denbury is the general partner of Genesis Energy, L.P. ("Genesis") and currently does not consolidate Genesis in its financial results based primarily on certain rights of the limited partners. Depending on the outcome of the discussions of the Task Force in future meetings, the outcome could impact whether or not Denbury consolidates Genesis. See Note 9, "Related Party Transactions - Genesis" for further information regarding Denbury's accounting for its investment in Genesis. 2. SALE OF DENBURY OFFSHORE, INC. On July 20, 2004, we closed the sale of Denbury Offshore, Inc., a subsidiary that held our offshore assets, for $200 million (before adjustments) to Newfield Exploration Company. The sale price was based on the asset value of the offshore assets as of April 1, 2004, which means that the net operating cash flow (defined as revenue less operating expenses and capital expenditures) from these properties which we received between April 1st and closing, as well as expenses of the sale and other contractual adjustments, reduced the purchase price to approximately $187 million. At September 30, 2004, we owed Newfield approximately $16.0 million that primarily consisted of accrued production 8 DENBURY RESOURCES INC. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS receivables from our offshore assets on July 20, 2004 (the closing date) that we collected on their behalf. The money was paid to Newfield during October 2004. We may have minor adjustments to the sale price in the fourth quarter of 2004 related to final settlement of the interim period net operating cash flow and other contractual arrangements in the sale agreement. We excluded two significant items from the sale: (i) a recently drilled discovery well at High Island A-6 and (ii) certain deep rights at West Delta 27. If not sold beforehand, the well at High Island A-6 should be on production late this year, and we sold a substantial portion of the deep rights at West Delta 27 for $1.8 million but retained a carried interest in a deep exploratory well. Our third quarter results include production, revenue, operating expenses, and capital expenditures of the offshore properties for the first 19 days of July preceding their sale on July 20th. Production for these 19 days totaled 1,885 BOE/d, which generated approximately $5.3 million of net operating revenue (revenue less operating expenses). We also recorded approximately $18 million of current income taxes relating to the sale and paid approximately $1.4 million of employee severance costs during the third quarter (in addition to the $1.0 million of severance recorded and paid during the first half of the year). We used $85 million of the sales proceeds to retire our bank debt, leaving approximately $70 million of cash remaining from the sale after payment of expenses related to the transaction. Our offshore properties made up approximately 12.5% of our year-end 2003 proved reserves (approximately 96 Bcfe as of December 31, 2003) and represented approximately 25% of our 2004 second quarter production (9,114 BOE/d). 3. ASSET RETIREMENT OBLIGATIONS On January 1, 2003, we adopted the provisions of SFAS No. 143, "Accounting for Asset Retirement Obligations." In general, our future asset retirement obligations relate to future costs associated with plugging and abandonment of our oil and natural gas wells, dismantling our offshore production platforms, and removal of equipment and facilities from leased acreage and returning such land to its original condition. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred, discounted to its present value using our credit adjusted risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset. Prior to the adoption of this new standard, we recognized a provision for our asset retirement obligations each period as part of our depletion and depreciation calculation, based on the unit-of-production method. The adoption of SFAS No. 143 on January 1, 2003, required us to record (i) a $41.0 million liability for our future asset retirement obligations (an increase of $34.1 million in our liability for asset retirement obligations that we had recorded at December 31, 2002), (ii) a $34.4 million increase in oil and natural gas properties, (iii) a $3.9 million decrease in accumulated depreciation and depletion, and (iv) a $2.6 million gain as a cumulative effect adjustment of a change in accounting principle, net of taxes of $1.6 million. The following table summarizes the changes in our asset retirement obligations for the nine months ended September 30, 2004.
Nine Months Ended September 30, 2004 --------------------- (in thousands) Beginning asset retirement obligation, as of 12/31/2003....... $ 43,812 Liabilities incurred during period............................ 1,548 Liabilities settled during period............................. (1,926) Liabilities sold during the period............................ (25,338) Accretion expense............................................. 1,971 --------------------- Ending asset retirement obligation, as of 9/30/2004........... $ 20,067 =====================
9 DENBURY RESOURCES INC. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Liabilities sold during the period represent the asset retirement obligation associated with our offshore assets held by Denbury Offshore, Inc., which was sold in July 2004. At September 30, 2004, $3.4 million of our asset retirement obligation was classified in "Accounts payable and accrued liabilities" under current liabilities in our Condensed Consolidated Balance Sheets. We hold cash and liquid investments in escrow accounts that are legally restricted for certain of our asset retirement obligations. The balances of these escrow accounts were $6.3 million at September 30, 2004, and $9.5 million at December 31, 2003 and are included in "Other assets" in our Unaudited Condensed Consolidated Balance Sheets. 4. NET INCOME PER COMMON SHARE Basic net income per common share is computed by dividing net income by the weighted average number of shares of common stock outstanding during the period. Diluted net income per common share is calculated in the same manner but also considers the impact on net income and common shares for the potential dilution from stock options, unvested restricted stock, and any other convertible securities outstanding. For the three and nine month periods ended September 30, 2004 and 2003, there were no adjustments to net income for purposes of calculating diluted net income per common share. 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 nine month periods ended September 30, 2004 and 2003 (shares in thousands).
Three Months Ended Nine Months Ended September 30, September 30, ------------------------------- -------------------------- 2004 2003 2004 2003 ---------------- -------------- ------------- ------------ Weighted average common shares - basic....... 55,085 54,014 54,740 53,824 Potentially dilutive securities: Stock options.............................. 2,434 1,704 2,280 1,551 Restricted stock........................... 30 - - - ---------------- -------------- ------------- ------------ Weighted average common shares - diluted..... 57,549 55,718 57,020 55,375 ================ ============== ============= ============
For purposes of calculating basic net income per share common share, the 1,140,000 shares of non-vested restricted stock outstanding at September 30, 2004, are excluded from the calculation. As these shares vest, they will be included in the basic net income per common share calculation. However, the non-vested restricted stock is included in the computation of diluted net income per common share using the treasury stock method. In applying the treasury stock method, there is no exercise price to be paid, however, proceeds are equal to the average unrecognized compensation during the period adjusted for any estimated future tax consequences that will be recognized directly in equity. The shares are weighted appropriately for the period they are outstanding. These shares of restricted stock were issued in August and September 2004, and as a result they do not have a significant impact on the current period. These shares may result in greater dilution in future periods, depending on the market price of our common stock during those periods. For the three months ended September 30, 2004 and 2003, stock options to purchase approximately 32,000 and 1.0 million shares of common stock, and for the nine months ended September 30, 2004 and 2003, stock options to purchase approximately 63,000 and 1.0 million shares of common stock, respectively, were outstanding but excluded from the diluted net income per common share calculations, as the exercise prices of the options exceeded the average market price of the Company's common stock during these periods and were anti-dilutive to the calculations. 10 DENBURY RESOURCES INC. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 5. RESTRICTED STOCK During the third quarter of 2004, the Compensation Committee of the Board of Directors awarded the officers and independent directors of the Company 1,140,000 shares of restricted stock granted under the Company's 2004 Omnibus Stock and Incentive Plan. The holders of these shares have all of the rights and privileges of owning the shares (including voting rights) except that the holders are not entitled to delivery of the certificates until certain requirements are met. With respect to the 1,100,000 shares of restricted stock granted to officers of Denbury, the vesting restrictions on those shares are as follows: i) 65% of the awards vest 20% per year over five years and, ii) 35% of the awards vest upon retirement. With respect to the 65% of the awards that vest over five years, on each annual vesting date, 66-2/3% of the vested shares may be delivered to the holder with the remaining 33-1/3% retained and held in escrow until the holder's separation from the Company. With respect to the 40,000 restricted shares issued to Denbury's independent board members, the shares vest 20% per year over five years. For these shares, on each annual vesting date, 40% of such vested shares may be delivered to the holder with the remaining 60% retained and held in escrow until the holder's separation from the Company. All restricted shares vest upon death, disability or a change in control. Upon issuance of the 1,140,000 shares of restricted stock pursuant to the 2004 Omnibus Stock and Incentive Plan, deferred compensation expense of $23.0 million, the market value of the shares on the date of grant, was recorded as a reduction to shareholders' equity. This expense will be amortized over the applicable five year or retirement date vesting periods. The compensation expense recorded with respect to the restricted shares during the three months ended September 30, 2004, was $593,000. 6. STOCK REPURCHASE PLAN In August 2003, we adopted a stock repurchase plan (the "Plan") to purchase shares of our common stock on the NYSE in order for such repurchased shares to be reissued to our employees who participate in Denbury's Employee Stock Purchase Plan. The Plan provides for purchases through an independent broker of 50,000 shares of Denbury's common stock per fiscal quarter for a period of approximately twelve months, or a total of 200,000 shares, during the period beginning August 13, 2003 and ending on July 31, 2004. In May 2004, the Board of Directors renewed the Plan for another year, for the period beginning July 1, 2004 and ending June 30, 2005. Purchases are to be made at prices and times determined at the discretion of the independent broker, provided however that no purchases may be made during the last ten business days of a fiscal quarter. During 2003, we purchased 100,000 shares at an average cost of $12.77 per share and from January 1, 2004 through September 30, 2004, we purchased 150,000 shares at an average cost of $18.09 per share. Through September 30, 2004, we have reissued 185,221 (74%) of these shares under Denbury's Employee Stock Purchase Plan. 7. INDEBTEDNESS
September 30, December 31, 2004 2003 ------------------ ----------------- (in thousands) 7.5% Senior Subordinated Notes due 2013.......... $ 225,000 $ 225,000 Discount on Senior Subordinated Notes............ (1,652) (1,797) Senior bank loan................................. - 75,000 ------------------ ----------------- Total debt................................... $ 223,348 $ 298,203 ================== =================
On September 1, 2004, we entered into a new bank credit agreement which modified the prior agreement by (i) creating a structure wherein the commitment amount and borrowing base amount are no longer the same, (ii) improving our credit pricing by reducing the interest rate chargeable at certain levels of borrowing, (iii) extending the term by three years to April 30, 2009, (iv) reducing the collateral requirements, (v) authorizing up to $20 million of possible future CO2 volumetric production payment transactions with Genesis Energy, and (vi) other minor modifications and corrections. Under the new agreement, our borrowing base was initially set at $200 million, a $25 million increase over the prior borrowing base of $175 million, with an initial commitment amount of $100 million. The borrowing base represents the amount we 11 DENBURY RESOURCES INC. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS can borrow from a credit standpoint based on our assets, as confirmed by the banks, while the commitment amount is the amount we asked the banks to commit to fund pursuant to the terms of the credit agreement. The banks have the option to participate in any borrowing request made by us in excess of the commitment amount, up to the borrowing base limit, although they are not obligated to fund any amount in excess of $100 million, the commitment amount. The advantage to us is that we will pay commitment fees on the commitment amount, not the borrowing base, thus lowering our overall cost of available credit. 8. SHORT-TERM INVESTMENTS The following is a summary of current available-for-sale marketable securities at September 30, 2004 (in thousands):
September 30, 2004 ---------------------------------------------------------- Gross Gross Amortized Unrealized Unrealized Estimated Cost Gains Losses Fair Value ---------------------------------------------------------- Certificate of deposits............................ $ 2,000 $ - $ - $ 2,000 Government and agency obligations.................. 14,939 - 17 14,922 Other debt securities.............................. 15,030 22 19 15,033 ---------------------------------------------------------- Total current available-for-sale securities... $31,969 $ 22 $ 36 $31,955 ==========================================================
9. RELATED PARTY TRANSACTIONS - GENESIS Interest in and Transactions with Genesis Denbury is the general partner of and owns an aggregate 9.25% interest in Genesis Energy, L.P. ("Genesis"), a publicly traded master limited partnership. Genesis has three primary lines of business: crude oil gathering and marketing, pipeline transportation, primarily in Mississippi, Texas, Alabama and Florida, and wholesale marketing of carbon dioxide. We are accounting for our 9.25% ownership in Genesis under the equity method of accounting as we have significant influence over the limited partnership; however, our control is limited under the limited partnership agreement and therefore we do not consolidate Genesis. Our equity in Genesis' net income (loss) for the three months ended September 30, 2004 and 2003 was $(37,000) and $(25,000), respectively, and for the nine months ended September 30, 2004 and 2003 was $(28,000) and $26,000, respectively. Genesis Energy, Inc., the general partner of which we own 100%, has guaranteed the bank debt of Genesis, which was $15 million as of September 30, 2004, plus $15.3 million in letters of credit. There are no guarantees by Denbury or any of its other subsidiaries of the debt of Genesis or of Genesis Energy, Inc. Over the past several years and even prior to our investment in Genesis we sold certain of our oil production to Genesis. Beginning in September 2004, we discontinued most direct sales of our oil production to Genesis and instead, we utilize their common carrier pipeline to transport certain of our Mississippi oil production to an ultimate sales point where it is sold to a third party purchaser. In return, we pay Genesis a transportation fee for the use of their pipeline and trucking services. For the three and nine months ended September 30, 2004, we expensed $266,000 under this transportation agreement. At December 31, 2003, we had a receivable from Genesis of $6.9 million and $0.5 million at September 30, 2004. At September 30, 2004, we had an accounts payable to Genesis of $402,000 for transportation expenses and interim cash flows for the volumetric production payment that closed in August 2004. We recorded oil sales to Genesis of $20.6 million and $10.5 million for the three months ended September 30, 2004 and 2003, respectively, and $62.9 million and $34.1 million for the nine months ended September 30, 2004 and 2003, respectively. Denbury received other miscellaneous payments from Genesis during the 2004 period, including $90,000 in director fees for certain executive officers of Denbury that are board members of Genesis, and $373,000 in pro rata distributions from Genesis. 12 DENBURY RESOURCES INC. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS CO2 Volumetric Production Payments In November 2003, we sold 167.5 Bcf of CO2 to Genesis for $24.9 million ($23.9 million as adjusted for interim cash flows from the September 1, 2003 effective date and for transaction costs) under a volumetric production payment ("VPP"). This sale included the assignment to Genesis of three of our existing long-term commercial CO2 supply agreements with our industrial customers, which represented approximately 60% of our then current industrial CO2 sales volumes. Pursuant to the VPP, Genesis may take up to 52.5 MMcf/d of CO2 through 2009, 43.0 MMcf/d from 2010 through 2012, and 25.2 MMcf/d to the end of the term. On August 26, 2004, we closed on another transaction with Genesis, selling them a 33.0 Bcf volumetric production payment ("VPPII") of CO2 for $4.8 million ($4.6 million as adjusted for interim cash flows from the July 1 effective date and for transaction costs) along with a related long-term supply agreement with an industrial customer. Pursuant to the VPPII, Genesis may take up to 9 MMcf/d of CO2 to the end of the contract term. We have recorded the net proceeds of these volumetric production payment sales as deferred revenue and will recognize such revenue as CO2 is delivered during the term of the VPP and VPPII. At September 30, 2004, $26.5 million was recorded as deferred revenue ($2.5 million in current liabilities and $24.0 million long term). During the three and nine months ended September 30, 2004, we recognized deferred revenue of $0.7 million and $1.8 million, respectively, for deliveries under the VPP and VPPII. We provide Genesis with certain processing and transportation services in connection with these agreements for a fee of $0.16 per Mcf of CO2 delivered to their industrial customers, which resulted in $0.7 million and $1.9 million in revenue to Denbury for the three and nine months ended September 30, 2004, respectively. Summarized financial information of Genesis Energy, L.P. (amounts in thousands):
Three Months Ended September 30, Nine Months Ended September 30, --------------------------------------- ------------------------------------- 2004 2003 2004 2003 ----------------- -------------------- ----------------- ------------------- Revenues.................................. $ 250,736 $ 157,094 $ 681,755 $ 479,446 Cost of sales............................. 250,892 158,503 681,035 479,024 Other income (expenses)................... (238) 196 (1,020) 1,134 ----------------- -------------------- ----------------- ------------------- Net income (loss) ........................ $ (394) $ (1,213) $ (300) $ 1,556 ================= ==================== ================= =================== September 30, December 31, 2004 2003 ----------------- -------------------- Current assets............................ $ 82,225 $ 88,211 Non-current assets........................ 65,000 58,904 ----------------- -------------------- Total assets ............................. $ 147,225 $ 147,115 ================= ==================== Current liabilities ...................... $ 83,932 $ 87,244 Non-current liabilities................... 15,000 7,000 Partners' capital......................... 48,293 52,871 ----------------- -------------------- Total liabilities and partners' capital... $ 147,225 $ 147,115 ================= ====================
10. PRODUCT PRICE HEDGING CONTRACTS We enter into various financial contracts to hedge our exposure to commodity price risk associated with anticipated future oil and natural gas production. We do not hold or issue derivative financial instruments for trading purposes. These contracts have historically consisted of price floors, collars and fixed price swaps. We generally attempt to hedge between 33% and 75% of our anticipated production each year to provide us with a reasonably certain amount of cash flow to cover most of our budgeted exploration and development expenditures without incurring significant debt, although our hedging percentage may vary relative to our debt levels. For example, when our debt levels are high, we may hedge a higher percentage of our production than when our debt levels are low. When we make an acquisition, we attempt to hedge a large 13 DENBURY RESOURCES INC. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS percentage, up to 100%, of the forecasted production for the subsequent one to three years following the acquisition in order to help provide us with a minimum return on our investment. Much of our hedging activity has been with collars, although for the 2002 COHO acquisition we also used swaps in order to lock in the prices used in our economic forecasts. In the second quarter of 2004, we purchased price floors or puts relating to a portion of our 2005 oil production, allowing us to retain any upside from increases in commodity prices. All of the mark-to-market valuations used for our financial derivatives are provided by external sources and are based on prices that are actively quoted. We manage and control market and counterparty credit risk through established internal control procedures which are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures, and diversification. The following is a summary of the net loss on our commodity hedge settlements which are recorded in "Revenues and other income" in our Condensed Consolidated Statements of Operations (amounts in thousands):
Three Months Ended Nine Months Ended September 30, September 30, ------------------------------ ---------------------------- 2004 2003 2004 2003 --------------- ------------- ------------ ------------- Oil hedge contracts................................. $ (13,455) $ (4,009) $ (33,771) $ (15,380) Gas hedge contracts................................. (4,010) (8,022) (12,686) (37,692) Contracts not qualifying for hedge accounting....... (4,778) - (8,293) - --------------- ------------- ------------ ------------- Net loss........................................ $ (22,243) $ (12,031) $ (54,750) $ (53,072) =============== ============= ============ =============
The following is a summary of "Non-cash hedging adjustments," included in our Condensed Consolidated Statements of Operations (amounts in thousands):
Three Months Ended Nine Months Ended September 30, September 30, ---------------------- ---------------------- 2004 2003 2004 2003 ----------- ---------- ----------- ---------- Hedge ineffectiveness (income) expense on contracts qualifying for hedge accounting...............................................$ (1,551) $ (375) $ (1,518) $ (513) Amortization of contract premiums..................................... - 300 - 891 Reclassification of accumulated other comprehensive income balance and adjustments to fair value associated with termination of contracts designated to offshore production..................... 1,206 - 9,318 - Adjustments to fair value and amortization of ineffective hedge no longer qualifying for hedge accounting.......................... 1,747 - 3,096 - Adjustments to fair value associated with contracts transferred in sale of offshore production......................... (1,019) - (2,549) - Amortization of terminated Enron-related hedges over the original contract periods................................................... - (1,366) - (4,080) ----------- ---------- ----------- ---------- $ 383 $ (1,441) $ 8,347 $ (3,702) =========== ========== =========== ==========
Upon reaching a verbal agreement on our offshore property sale, subject primarily to the purchaser's further due diligence, we entered into natural gas swaps on a total of 23.6 Bcf for the period of July 2004 through December 2005, covering the anticipated natural gas production from our offshore properties for that period, with the tacit understanding with the prospective purchaser that these hedges would be transferred to the purchaser upon closing. These swaps did not qualify for hedge accounting and during the third quarter of 2004 we assigned them to the purchaser of the offshore properties. The mark to market adjustment on these contracts from the time of purchase through the date they were assigned to the purchaser totaled approximately $2.5 million. At about the same time, with the expectation that the offshore transaction would be consummated, we retired, by purchasing offsetting contracts, 20 MMcf/d of our natural gas hedges for July to December of 2004, at a cost of approximately $3.9 million. Since the natural gas hedges we retired were not the same as those 14 DENBURY RESOURCES INC. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS hedges previously designated for offshore production, we recognized a charge to earnings in the second quarter of 2004 of approximately $8.1 million, representing the then current mark to market value of the offshore hedges. The difference between this charge and the amount paid to retire 20 MMcf/d will be reversed over the remainder of 2004. We also had minor charges and credits for hedge ineffectiveness and a net charge for a portion of our oil hedges that are no longer considered effective during the third quarter of 2004, resulting in a net charge of $0.4 million for the quarter and $8.3 million for the nine months ended September 30, 2004. During 2003, we had minor charges or credits relating to the hedge ineffectiveness, charges for the amortization of contract premiums, and credits relating to the reclassification of amounts out of "Accumulated other comprehensive loss" into income relating to our former Enron hedges, resulting in a net credit of $1.4 for the three months and $3.7 million for the nine months ended September 30, 2003. Derivative Contracts designated as a hedge of forecasted production at September 30, 2004:
Crude Oil Contracts: - ------------------- NYMEX Contract Prices Per Bbl ----------------------------- Collar Prices ---------------------- Fair Value at Type of Contract and Period Bbls/d Swap Price Floor Price Floor Ceiling September 30, 2004 - -------------------------------- ----------- ------------ ------------ ---------- ----------- -------------------- (in thousands) Swap Contracts Oct. 2004 - Dec. 2004 4,500 $ 23.00 $ - $ - $ - $ (10,716) Oct. 2004 - Dec. 2004 2,500 22.89 - - - (5,978) Floor Contract Jan. 2005 - Dec. 2005 7,500 - 27.50 - - 251 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 September 30, 2004 - -------------------------------- ----------- ------------ ------------ ---------- ----------- -------------------- Collar Contracts (in thousands) Oct. 2004 - Dec. 2004 30,000 $ - $ - $ 3.50 $ 4.45 $ (6,001) Oct. 2004 - Dec. 2004 10,000 - - 3.00 5.82 (900) Jan. 2005 - Dec. 2005 15,000 - - 3.00 5.50 (8,480)
15 DENBURY RESOURCES INC. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Derivative Contracts not designated as a hedge:
Crude Oil Contracts: - ------------------- NYMEX Contract Prices Per Bbl ----------------------------- Contract discontinued from hedge accounting due to failing ongoing effectiveness assessment Collar Prices ---------------------- Fair Value at Type of Contract and Period Bbls/d Swap Price Floor Price Floor Ceiling September 30, 2004 - -------------------------------- ----------- ------------ ------------ ---------- ----------- --------------------- (in thousands) Swap Contract Oct. 2004 - Dec. 2004 2,500 $ 23.08 $ - $ - $ - $ (5,935)
Natural Gas Contracts: - --------------------- NYMEX Contract Prices Per MMBtu ------------------------------- Offsetting Contracts Collar Prices ---------------------- Fair Value at Period MMBtu/d Call Price Put Price Floor Ceiling September 30, 2004 - -------------------------------- ----------- ------------ ------------ ---------- ----------- --------------------- (in thousands) Oct. 2004 - Dec. 2004 15,000 $ - $ - $ 3.00 $ 5.87 $ (1,315) Oct. 2004 - Dec. 2004 15,000 5.87 - - - 1,315 Oct. 2004 - Dec. 2004 5,000 - - 3.00 5.82 (450) Oct. 2004 - Dec. 2004 5,000 5.82 3.00 - - 450
At September 30, 2004, our derivative contracts were recorded at their fair value, which was a net liability of $37.8 million. To the extent our hedges are considered effective, this fair value liability, net of income taxes, is included in "Accumulated other comprehensive loss" reported under Stockholders' equity in our Condensed Consolidated Balance Sheets. The balance in accumulated other comprehensive loss of $20.8 million at September 30, 2004, represents the deficit in the fair market value of our derivative contracts as compared to the cost of our hedges, net of income taxes. Of the $20.8 million in accumulated other comprehensive loss as of September 30, 2004, $18.2 million relates to current hedging contracts that will expire within the next 12 months. 11. UNAUDITED CONDENSED CONSOLIDATING FINANCIAL INFORMATION On December 29, 2003, we amended the indenture for our 7.5% Senior Subordinated Notes due 2013 to reflect our new holding company organizational structure. As part of this restructuring, our indenture was amended so that both Denbury Resources Inc. (the new holding company) and Denbury Onshore, LLC (formerly the parent company and now a wholly-owned subsidiary) became co-obligors on our subordinated debt. Prior to this restructure, Denbury Resources Inc., as the parent company, was the sole obligor. Our subordinated debt is fully and unconditionally guaranteed by Denbury Resources Inc.'s significant subsidiaries. Genesis Energy, Inc., the subsidiary that holds the Company's investment in Genesis Energy, L.P., is not a guarantor of our subordinated debt. Our equity interest in the results of operations of Genesis is reflected through the equity method by one of our significant subsidiaries, Denbury Gathering & Marketing. The following is condensed consolidating financial information for Denbury Resources Inc., Denbury Onshore, LLC, and significant subsidiaries: 16 DENBURY RESOURCES INC. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Unaudited Condensed Consolidating Balance Sheets
September 30, 2004 --------------------------------------------------------------------------- Denbury Denbury Resources Inc. Onshore, LLC Denbury (Parent and Co- (Issuer and Co- Guarantor Resources Inc. Obligor) Obligor) Subsidiaries Eliminations Consolidated -------------- --------------- ------------- -------------- --------------- Amounts in thousands ASSETS Current assets.................................... $ 1 $ 194,312 $ 16,117 $ (967) $ 209,463 Property and equipment ........................... - 763,153 3,897 (3,114) 763,936 Investment in subsidiaries (equity method)........ 500,629 - 480,615 (974,210) 7,034 Other assets...................................... - 11,276 - - 11,276 -------------- --------------- ------------- -------------- --------------- Total assets ................................. $ 500,630 $ 968,741 $ 500,629 $ (978,291) $ 991,709 ============== =============== ============= ============== =============== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities............................... $ - $ 141,752 $ - $ (967) $ 140,785 Long-term liabilities ............................ - 353,408 - (3,114) 350,294 Stockholders' equity ............................. 500,630 473,581 500,629 (974,210) 500,630 -------------- --------------- ---------------------------- --------------- Total liabilities and stockholders' equity.... $ 500,630 $ 968,741 $ 500,629 $ (978,291) $ 991,709 ============== =============== ============= ============== ===============
December 31, 2003 --------------------------------------------------------------------------- Denbury Denbury Resources Inc. Onshore, LLC Denbury (Parent and Co- (Issuer and Co- Guarantor Resources Inc. Obligor) Obligor) Subsidiaries Eliminations Consolidated -------------- --------------- ------------- -------------- --------------- Amounts in thousands ASSETS Current assets ................................... $ 1 $ 85,109 $ 23,045 $ - $ 108,155 Property and equipment ........................... - 560,038 292,473 - 852,511 Investment in subsidiaries (equity method) ....... 421,201 - 210,803 (624,554) 7,450 Other assets ..................................... - 11,186 3,319 - 14,505 -------------- --------------- ------------- -------------- --------------- Total assets.................................. $ 421,202 $ 656,333 $ 529,640 $ (624,554) $ 982,621 ============== =============== ============= ============== =============== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities............................... $ - $ 119,364 $ 7,210 $ - $ 126,574 Long-term liabilities ............................ - 333,616 101,229 - 434,845 Stockholders' equity.............................. 421,202 203,353 421,201 (624,554) 421,202 -------------- --------------- ------------- -------------- --------------- Total liabilities and stockholders' equity ... $ 421,202 $ 656,333 $ 529,640 $ (624,554) $ 982,621 ============== =============== ============= ============== ===============
17 DENBURY RESOURCES INC. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Unaudited Condensed Consolidating Statements of Operations
Three Months Ended September 30, 2004 --------------------------------------------------------------------------- Denbury Denbury Resources Inc. Onshore, LLC Denbury (Parent and Co- (Issuer and Co- Guarantor Resources Inc. Obligor) Obligor) Subsidiaries Eliminations Consoldiated -------------- ---------------- ------------ -------------- --------------- Amounts in thousands Revenues.................................. $ - $ 77,199 $ 6,008 $ - $ 83,207 Expenses ................................. 42 51,873 5,149 - 57,064 -------------- ---------------- ------------ -------------- --------------- Income (loss) before the following: (42) 25,326 859 - 26,143 Equity in net earnings of subsidiaries ... 18,299 - 20,625 (38,961) (37) -------------- ---------------- ------------ -------------- --------------- Income before income taxes................ 18,257 25,326 21,484 (38,961) 26,106 Income tax provision (benefit)............ (17) 4,664 3,185 - 7,832 -------------- ---------------- ------------ -------------- --------------- Net income ............................... $ 18,274 $ 20,662 $ 18,299 $ (38,961) $ 18,274 ============== ================ ============ ============== ===============
Three Months Ended September 30, 2003 ----------------------------------------------------------- Denbury Resources Inc. Denbury (Parent and Guarantor Resources Inc. Issuer) Subsidiaries Eliminations Consolidated --------------- ------------ -------------- --------------- Amounts in thousands Revenues................................................ $ 58,045 $ 21,370 $ - $ 79,415 Expenses................................................ 42,803 13,888 - 56,691 --------------- ------------ -------------- --------------- Income before the following: 15,242 7,482 - 22,724 Equity in net earnings (loss) of subsidiaries .......... 5,000 (25) (5,000) (25) --------------- ------------ -------------- --------------- Income before income taxes.............................. 20,242 7,457 (5,000) 22,699 Income tax provision ................................... 5,093 2,457 - 7,550 --------------- ------------ -------------- --------------- Net income.............................................. $ 15,149 $ 5,000 $ (5,000) $ 15,149 =============== ============ ============== ===============
18 DENBURY RESOURCES INC. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Unaudited Condensed Consolidating Statements of Operations (continued)
Nine Months Ended September 30, 2004 --------------------------------------------------------------------------- Denbury Denbury Resources Inc. Onshore, LLC Denbury (Parent and Co- (Issuer and Guarantor Resources Inc. Obligor) Obligor) Subsidiaries Eliminations Consolidated -------------- ---------------- ------------ -------------- --------------- Amounts in thousands Revenues................................. $ - $ 220,211 $ 63,486 $ - $ 283,697 Expenses ................................ 130 157,751 37,699 - 195,580 -------------- ---------------- ------------ -------------- --------------- Income (loss) before the following: (130) 62,460 25,787 - 88,117 Equity in net earnings of subsidiaries .. 60,051 - 45,743 (105,822) (28) -------------- ---------------- ------------ -------------- --------------- Income before income taxes............... 59,921 62,460 71,530 (105,822) 88,089 Income tax provision (benefit)........... (46) 16,689 11,479 - 28,122 -------------- ---------------- ------------ -------------- --------------- Net income .............................. $ 59,967 $ 45,771 $ 60,051 $ (105,822) $ 59,967 ============== ================ ============ ============== ===============
Nine Months Ended September 30, 2003 ------------------------------------------------------------ Denbury Resources Inc. Denbury (Parent and Guarantor Resources Inc. Issuer) Subsidiaries Eliminations Consolidated --------------- -------------- ------------- --------------- Amounts in thousands Revenues................................................. $ 173,895 $ 76,140 $ - $ 250,035 Expenses................................................. 149,706 42,555 - 192,261 --------------- -------------- ------------- --------------- Income before the following: 24,189 33,585 - 57,774 Equity in net earnings of subsidiaries ................ 21,434 26 (21,434) 26 --------------- -------------- ------------- --------------- Income before income taxes and cumulative effect of a change in accounting principle.. 45,623 33,611 (21,434) 57,800 Income tax provision..................................... 8,261 10,808 - 19,069 --------------- -------------- ------------- --------------- Net income before cumulative effect of a change in accounting principle................................... 37,362 22,803 (21,434) 38,731 Cumulative effect of a change in accounting principle, net of income taxes.................................... 3,981 (1,369) - 2,612 --------------- -------------- ------------- --------------- Net income............................................... $ 41,343 $ 21,434 $ (21,434) $ 41,343 =============== ============== ============= ===============
19 DENBURY RESOURCES INC. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Unaudited Condensed Consolidating Statements of Cash Flows
Nine Months Ended September 30, 2004 ---------------------------------------------------------------------------- Denbury Denbury Resources Inc. Onshore, LLC Denbury (Parent and Co- (Issuer and Co- Guarantor Resources Inc. Obligor) Obligor) Subsidiaries Eliminations Consolidated ---------------- --------------- ------------- -------------- -------------- Amounts in thousands Cash flow from operations................. $ (8,386) $ 317,322 $ (157,965) $ - $ 150,971 Cash flow from investing activities....... - (172,986) 157,995 - (14,991) Cash flow from financing activities....... 8,386 (75,412) - - (67,026) ---------------- --------------- ------------- -------------- -------------- Net increase in cash...................... - 68,924 30 - 68,954 Cash, beginning of period................. 1 24,174 13 - 24,188 ---------------- --------------- ------------- -------------- -------------- Cash, end of period....................... $ 1 $ 93,098 $ 43 $ - $ 93,142 ================ =============== ============= ============== ==============
Nine Months Ended September 30, 2003 ----------------------------------------------------------- Denbury Resources Inc. Denbury (Parent and Guarantor Resources Inc. Issuer) Subsidiaries Eliminations Consolidated --------------- ------------- -------------- -------------- Amounts in thousands Cash flow from operations..................... $ 103,242 $ 42,598 $ - $ 145,840 Cash flow from investing activities........... (75,379) (32,997) - (108,376) Cash flow from financing activities........... (33,296) - - (33,296) --------------- ------------- -------------- -------------- Net increase (decrease) in cash .............. (5,433) 9,601 - 4,168 Cash, beginning of period..................... 20,281 3,659 - 23,940 --------------- ------------- -------------- -------------- Cash, end of period........................... $ 14,848 $ 13,260 $ - $ 28,108 =============== ============= ============== ==============
12. LITIGATION We, along with two other companies have been named in a lawsuit entitled "J. Paulin Duhe, Inc. vs. Texaco, Inc., et al," Cause No. 101,227, filed within the last year in the 16th Judicial District Court, Division "E", Terrebonne Parish, Louisiana, seeking unspecified monetary amounts for alleged surface and groundwater contamination affecting, and asking for restoration of, the lands that are part of our Iberia Field in Iberia Parish, Louisiana. The first oil and natural gas well was drilled on this property in 1921. We acquired this property approximately four years ago and have an indemnification from the prior owner, which we anticipate will cover us from most environmental damages that occurred prior to the time that we purchased the property. We have not yet been able to determine our potential exposure in this case. We plan to vigorously defend this lawsuit, as well as seek indemnification from the prior owners if necessary. 20 DENBURY RESOURCES INC. Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - -------------------------------------------------------------------------------- You should read the following in conjunction with our financial statements contained herein and our Form 10-K for the year ended December 31, 2003, along with Management's Discussion and Analysis of Financial Condition and Results of Operations contained in such Form 10-K. Any terms used but not defined in the following discussion have the same meaning given to them in the Form 10-K. We are an independent oil and gas company engaged in acquisition, development and exploration activities in the U.S. Gulf Coast region. We are the largest oil and natural gas producer in Mississippi, own the largest reserves of carbon dioxide ("CO2") used for tertiary oil recovery east of the Mississippi River, and hold significant operating acreage onshore Louisiana and in the Barnett Shale play in Texas. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling, and proven engineering extraction processes, including secondary and tertiary recovery operations. Our corporate headquarters are in Plano, Texas (a suburb of Dallas), and we have two primary field offices located in Houma, Louisiana, and Laurel, Mississippi. Overview EXPANSION OF OUR TERTIARY OPERATIONS. Since we acquired our first carbon dioxide tertiary flood in Mississippi five years ago, we have gradually increased our emphasis on these types of operations. We particularly like this play because of its risk profile, rate of return and lack of competition in our operating area. Generally, from East Texas to Florida, there are no known significant natural sources of carbon dioxide except our own, and these large volumes of CO2 that we own drive the play. Please refer to the sections entitled "Overview" and "CO2 Operations" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in our 2003 Form 10-K for further information regarding these operations, their potential, and the ramifications of this change in focus. In late August 2004, we announced that we had commenced the acquisition of leases and right-of-way for the construction of an 84-mile pipeline to transport CO2 from our CO2 source fields located near Jackson, Mississippi to planned tertiary recovery operations in East Mississippi, initially terminating at Eucutta Field. We are still reviewing financing options for the pipeline, expected to cost approximately $45 million, but plan to pay for this line over time through either long-term project financing, payment of a throughput transportation charge or a long-term lease. We anticipate that the pipeline will be ready for use during the first half of 2006. We also announced the completion of our fourth CO2 well drilled during 2004, confirming the addition of an estimated 300 Bcf of proved CO2 reserves, resulting in an estimated total increase in proved CO2 reserves during 2004 of approximately 1.0 Tcf. This increase in CO2 reserves is sufficient to satisfy the projected CO2 requirements of our initially planned tertiary recovery operations in Eastern Mississippi (what we have labeled as "Phase II" of our tertiary recovery operations). Phase II will initially consist of tertiary recovery operations at six oil fields in that region, but we ultimately plan to expand these operations to several other oil fields in the area, which also would be serviced by the new pipeline. In conjunction with these plans, we have updated our development schedule and targeted oil production from tertiary recovery operations. Our revised model projects a 28% compounded increase in our tertiary recovery oil production between 2003 and 2010, increasing from 4,670 BOE/d in 2003 to a projected 34,000 BOE/d in 2011. The model assumes that the first production from tertiary recovery operations in Eastern Mississippi will occur in 2007. During 2004, oil production from our tertiary recovery operations has averaged 6,318 BOE/d, 6,603 BOE/d, and 6,967 BOE/d during the first, second and third quarters respectively, and is expected to increase similarly in the fourth quarter. SALE OF OFFSHORE OPERATIONS. On July 20, 2004, we closed the sale of Denbury Offshore, Inc., a subsidiary that held our offshore assets, for $200 million (before adjustments) to Newfield Exploration Company. The sale price was based on the asset value of the offshore assets as of April 1, 2004, which means that the net operating cash flow (defined as revenue less operating expenses and capital expenditures) from these properties which we received between April 1st and closing, as well as expenses of the sale and other contractual adjustments, reduced the purchase price to approximately $187 million. At September 30, 2004, we owed Newfield approximately $16.0 million that primarily consisted of Denbury Offshore accrued production receivables on July 20, 2004 (closing date) that we collected on their behalf. This amount was reflected as a payable to Newfield in the Unaudited Condensed Consolidated Balance Sheet and was paid to Newfield in October 2004. 21 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS We excluded two significant items from the sale: (i) a recently drilled discovery well at High Island A-6 and (ii) certain deep rights at West Delta 27. If not sold beforehand, the well at High Island A-6 should be on production late this year, and we sold a substantial portion of the deep rights at West Delta 27 for $1.8 million but retained a carried interest in a deep exploratory well. Our third quarter results include production, revenues, operating expenses, and capital expenditures of the offshore properties for the first 19 days of July preceding their sale. Production for these 19 days totaled 1,885 BOE/d which generated approximately $5.3 million of net operating revenue (revenue less operating expenses). We also recorded approximately $18 million of current income taxes relating to the sale and paid approximately $1.4 million of employee severance costs during the third quarter (in addition to the $1.0 million of severance recorded and paid during the first half of the year). We used $85 million of the sales proceeds to retire our bank debt, leaving approximately $70 million of cash remaining from the sale after payment of expenses related to the transaction. We increased our 2004 exploration and development budget by $28 million to $213 million as a result of the additional cash generated from the sale and expect to spend the cash generated from the offshore sale over the next one to two years. Our offshore properties made up approximately 12.5% of our year-end 2003 proved reserves (approximately 96 Bcfe as of December 31, 2003) and represented approximately 25% (9,114 BOE/d) of our 2004 second quarter production. OPERATING RESULTS. As a result of the sale of our offshore properties early in the third quarter of 2004, our total production during this quarter was significantly reduced, contributing to a 6% decline in net income when compared to 2004's second quarter production. Cash flow from operations for the quarter declined even more significantly (53%), primarily due to the $18 million of current income taxes due on the sale. On a pro forma basis, excluding the impact of the offshore operations during the third quarter as outlined above, net income would have been approximately $16.5 million, with a pro forma adjusted cash flow from operations (non-GAAP measure, see "Results of Operations - Operating Results" below) of approximately $44.0 million. In summary, the effect of higher commodity prices was more than offset by the loss of offshore production and related net operating income from those operations. Payments on our commodity hedges continued to be a significant outflow, totaling $22.2 million for the third quarter of 2004, and hedge payments are expected to be even higher in the fourth quarter of 2004 based on current commodity prices, after which they will drop significantly as most of the out-of-the-money hedges expire by the end of 2004. Depreciation and amortization expense declined in the third quarter of 2004 as compared to the second quarter of 2004, primarily as a result of the proceeds from the offshore sale being credited to the full cost pool. When comparing the respective third quarters of 2003 and 2004, higher commodity prices in the 2004 period more than offset the lower production, resulting in a 21% increase in net income in 2004. See "Results of Operations" for a more thorough discussion of our operating results. Capital Resources and Liquidity During the first nine months of 2004, we spent $125.8 million on oil and natural gas exploration and development expenditures, $35.2 million on CO2 exploration and development expenditures, and approximately $11.6 million on property acquisitions (principally CO2 producing assets), for total capital expenditures of approximately $172.6 million. We funded these expenditures with $151.0 million of cash flow from operations, with the balance funded with net proceeds from the offshore sale. We also paid back all of our bank debt during the period with the offshore sale proceeds, leaving us with approximately $93.1 million of cash and $32.0 million of short-term investments as of September 30, 2004, although $16.0 million of this cash was refunded to Newfield in October 2004 (see "Sale of Offshore Operations" above). During the third quarter of 2004, we closed on another transaction with Genesis Energy, L.P. ("Genesis"), selling to them a 33.0 Bcf volumetric production payment of CO2 for $4.8 million along with a related long-term CO2 supply agreement with an industrial customer, further increasing our cash position. Adjusted cash flow from operations (a non-GAAP measure defined as cash flow from operations before changes in assets and liabilities as discussed below under "Results of Operations-Operating Results") was $151.7 million for the first nine months of 2004. At September 30, 2004, we had outstanding $225 million (principal amount) of 7.5% subordinated notes due in 2013, no bank debt, and net working capital on hand of $68.7 million. On September 1, 2004, we entered into a new bank credit agreement which modified the prior agreement by (i) creating a structure wherein the commitment amount and borrowing base amount are no longer the same, (ii) improving our credit pricing by reducing the interest rate chargeable at certain levels of borrowing, (iii) extending the term by three years to April 30, 2009, (iv) reducing the collateral requirements, (v) authorizing up to $20 million of possible future CO2 volumetric production payment transactions with Genesis 22 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Energy, and (vi) other minor modifications and corrections. Under the new agreement, our borrowing base was initially set at $200 million, a $25 million increase over the prior borrowing base of $175 million, with an initial commitment amount of $100 million. The borrowing base represents the amount we can borrow from a credit standpoint based on our assets, as confirmed by the banks, while the commitment amount is the amount we asked the banks to commit to fund pursuant to the terms of the credit agreement. The banks have the option to participate in any borrowing request made by us in excess of the commitment amount, up to the borrowing base limit, although they are not obligated to fund any amount in excess of $100 million, the commitment amount. The advantage to us is that we will pay commitment fees on the commitment amount, not the borrowing base, thus lowering our overall cost of available credit. Even with our recently increased capital budget for 2004, we do not expect to spend any significant amount of our cash on hand for our budgeted operations given high commodity prices. For 2005, we have set a preliminary capital budget of $260 million, which at current commodity prices will be $50 to $60 million less than anticipated cash flow from operations. This 2005 capital budget excludes the $45 million estimated cost of the CO2 pipeline being constructed to East Mississippi for which we plan to obtain some sort of long-term financing, effectively paying for the cost of this pipeline over time (see "Expansion of our tertiary operations" under "Overview" above). We plan to invest our remaining cash generated from the offshore sale and any cash potentially generated from operations in excess of our capital budget (such amount being highly dependent on commodity prices) over the next one to two years on property acquisitions, particularly those that have future tertiary potential. Although we now control most of the fields along our existing CO2 pipeline, there are several fields in East Mississippi that could be acquired to expand our planned tertiary operations there, plus we are continuing to seek additional interests in the fields that we currently own. Further, we would like to add additional phases or areas of tertiary operations by acquiring other old oil fields in other parts of our region of operations, building a CO2 pipeline to those areas and initiating additional tertiary floods. We accelerated the pace and expenditures on our tertiary operations following the offshore sale, and plan to continue to do so to the extent that it is economic and practical. We also may seek conventional development and exploration projects in our areas of operations. Off-Balance Sheet Arrangements Commitments and Obligations Our obligations that are not currently recorded on our balance sheet are our operating leases and various obligations for development and exploratory expenditures arising from purchase agreements, our capital expenditure program, or other transactions common to our industry. Further, one of our subsidiaries, the general partner of Genesis Energy, L.P., has guaranteed the bank debt of Genesis (which as of September 30, 2004, consisted of $15 million of debt and $15.3 million in letters of credit), and we have delivery obligations to deliver CO2 to our industrial customers. Our hedging obligations are discussed in Note 11 to the Unaudited Condensed Consolidated Financial Statements. In addition, in order to recover our undeveloped proved reserves, we must also fund the associated future development costs forecasted in our proved reserve reports. As a result of the sale of our offshore properties (see "Sale of offshore operations" under "Overview"), we repaid all of our bank debt and reduced our future development costs on our proved reserves by approximately $82.0 million and our asset retirement obligations by approximately $25.3 million. Most of our other commitments or contingent obligations have not changed significantly from the year-end 2003 amounts reflected in our Form 10-K filed in March 2004. Please refer to Management's Discussion and Analysis of Financial Condition and Results of Operations contained in our 2003 Form 10-K for further information regarding our commitments and obligations. Results of Operations CO2 Operations Our CO2 operations are becoming an ever-increasing part of our business and operations, including the recent planned expansion of our operations into East Mississippi (see "Overview" section above). We believe that there are significant additional oil reserves and production that can be obtained through the use of CO2, and we have outlined certain of this potential in our annual report and other public disclosures. In addition to its long-term effect, this shift in focus impacts certain trends in our current and near-term operating results, such as a general delay between expenditures and resultant production, higher operating costs and improved oil prices. Please refer to Management's 23 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Discussion and Analysis of Financial Condition and Results of Operations and the section entitled "CO2 Operations" contained in our 2003 Form 10-K for further information regarding these issues. During the first three quarters of 2004, we drilled or sidetracked four additional CO2 wells. During that period, our CO2 production averaged 229.7 MMcf/d, of which 64%, or 147.9 MMcf/d, was used in our tertiary operations, with the balance sold to our industrial customers or to Genesis pursuant to our volumetric production payments with Genesis. We believe that with the latest CO2 wells, we are capable of producing approximately 350 MMcf/d of CO2. Based on preliminary reserve estimates, we estimate that we now have approximately 2.6 Tcf of proven CO2 reserves, a significant increase from our 1.6 Tcf of proven CO2 reserves as of December 31, 2003. With the success of these last two CO2 wells, we should have sufficient CO2 reserves for our planned expansion of CO2 operations into East Mississippi. A 3-D seismic shoot over the Jackson Dome area is currently underway to help us delineate our future CO2 drilling efforts there. We plan to further expand and increase our CO2 reserves and production capability in order to provide enough CO2 for the anticipated growth in our tertiary operations, a significant focus area for us for the foreseeable future. Our oil production from our CO2 tertiary recovery activities in the third quarter of 2004 increased 6% over second quarter 2004 levels and 65% over third quarter 2003 levels, to an average of 6,967 Bbls/d in the third quarter of 2004, with most of the increase since the third quarter of 2003 occurring at Mallalieu and McComb Fields. Production at Mallalieu averaged 3,410 Bbls/d during the third quarter of 2004, as compared to 3,172 Bbls/d in the prior quarter and 1,388 Bbls/d during the third quarter of 2003. McComb Field averaged 427 Bbls/d during the third quarter, as compared to 121 Bbls/d in the second quarter of 2004 and effectively zero prior to that. Partially offsetting these increases was a slight decline during the current quarter at Little Creek Field. We expect our tertiary oil production to continue to grow through the last quarter of 2004 to a projected average of approximately 6,800 Bbls/d for the year. Late in 2004, we expect to commence CO2 injections at two new tertiary floods, Brookhaven and Smithdale Fields, although no incremental oil production is expected from these fields until late 2005. We spent approximately $0.12 per Mcf to produce our CO2 during the first nine months of 2004, less than the 2003 period average of $0.15 per Mcf, as we did not have any significant workover costs on CO2 wells during the first nine months of 2004. However, as a result of continued high oil prices, CO2 royalty expenses increased, partially offsetting other operating expense savings, as certain of our CO2 royalty payments increase if the price of oil increases beyond a certain threshold. Our total cost per thousand cubic feet of CO2 during the first nine months of 2004 was approximately $0.21, after inclusion of depreciation and amortization expense, still significantly less than the $0.39 per thousand cubic feet that we would have paid had we been paying under the purchase contract that existed at the time we acquired the CO2 properties in February 2001. For the first nine months of 2004, our operating costs for our tertiary properties averaged $9.84 per BOE, less than the $11.20 per BOE average in the first nine months of 2003 and our 2003 annual average of $11.34 per BOE. The savings were a result of the lower cost to produce CO2 (discussed above) and higher oil production levels. Our net operating margin from the sale of CO2 to industrial customers decreased in the first nine months of 2004 to $4.0 million, down from $5.4 million during the first nine months of 2003, primarily related to the volumetric production payment we sold to Genesis at a lower average price per thousand cubic foot than we received from the industrial customers in the prior year. We received cash from the two Genesis volumetric production payments when the transactions were consummated in the fourth quarter of 2003 and third quarter of 2004. Thus, $1.8 million of our industrial sale revenue was non-cash recognition of deferred revenue. Operating Results As summarized in the "Overview" section above, the reduced production resulting from the sale of our offshore properties and the related income taxes attributable thereto resulted in lower cash flow from operations and earnings in the third quarter of 2004 than in the prior quarters of 2004. Earnings and cash flow were higher in the 2004 periods than in the comparable periods in 2003 as higher commodity prices more than offset lower production. During the first quarter of 2003, we implemented SFAS No. 143, "Accounting for Asset Retirement Obligations," as more fully discussed below under "Depletion, Depreciation and Amortization." The adoption of SFAS No. 143 was recorded as a cumulative effect adjustment of a change in accounting principle, net of income taxes, in our Unaudited Condensed Consolidated Statements of Operations and its impact is shown below on both a gross and per share basis. 24 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Three Months Ended Nine Months Ended September 30, September 30, - ------------------------------------------------------------------ ---------------------------- --------------------------- Amounts in thousands, except per share amounts 2004 2003 2004 2003 - ------------------------------------------------------------------ ------------- ------------- ------------- ------------ Income before cumulative effect of a change in accounting principle $ 18,274 $ 15,149 $ 59,967 $ 38,731 Cumulative effect of a change in accounting principle, net of income tax expense of $1,600 - - - 2,612 ------------- ------------- ------------- ------------ Net income $ 18,274 $ 15,149 $ 59,967 $ 41,343 - ------------------------------------------------------------------ ============= ============= ============= ============ Net income per common share - basic: Income before cumulative effect of a change in accounting principle $ 0.33 $ 0.28 $ 1.10 $ 0.72 Cumulative effect of a change in accounting principle - - - 0.05 ------------- ------------- ------------- ------------ Net income per common share - basic $ 0.33 $ 0.28 $ 1.10 $ 0.77 - ------------------------------------------------------------------ ============= ============= ============= ============ Net income per common share - diluted: Income before cumulative effect of a change in accounting principle $ 0.32 $ 0.27 $ 1.05 $ 0.70 Cumulative effect of a change in accounting principle - - - 0.05 ------------- ------------- ------------- ------------ Net income per common share - diluted $ 0.32 $ 0.27 $ 1.05 $ 0.75 - ------------------------------------------------------------------ ============= ============= ============= ============ Adjusted cash flow from operations (see below) $ 29,747 $ 45,611 $ 151,721 $ 141,966 Net change in assets and liabilities relating to operations 15,019 4,178 (750) 3,874 - ------------------------------------------------------------------ ------------- ------------- ------------- ------------ Cash flow from operations (1) $ 44,766 $ 49,789 $ 150,971 $ 145,840 - ------------------------------------------------------------------ ============= ============= ============= ============ (1) Net cash flow provided by operations as per the Unaudited Condensed Consolidated Statements of Cash Flows.
Adjusted cash flow from operations is a non-GAAP measure that represents cash flow provided by operations before changes in assets and liabilities as presented in our Unaudited Condensed Consolidated Statements of Cash Flows. Cash flow from operations is the GAAP measure as presented in our Unaudited Condensed Consolidated Statements of Cash Flows. In our discussion herein, we have elected to discuss these two components of cash flow provided by operations separately. Adjusted cash flow from operations, the non-GAAP measure, measures the cash flow earned or incurred from operating activities without regard to the collection or payment of associated receivables or payables. We believe that this is important to consider separately, as we believe it can often be a better way to discuss changes in operating trends in our business caused by changes in production, prices, operating costs, and so forth, without regard to whether the earned or incurred item was collected or paid during that period. We also use this measure because the collection of our receivables or payment of our obligations has not been a significant issue for our business, but merely a timing issue from one period to the next, with fluctuations generally caused by significant changes in commodity prices or significant changes in drilling activity. The net change in assets and liabilities relating to operations is also important as it does require or provide additional cash for use in our business; however, we prefer to discuss its effect separately. For instance, during the third quarter of 2004, we collected accrued production receivables related to offshore production that existed as of the closing date of the sale of Denbury Offshore, Inc. that were for the benefit of Newfield Exploration Company, the purchaser (see "Overview - Sale of offshore operations"). As of September 30, 2004, we owed Newfield approximately $16.0 million for these receivables and other sale adjustments, the primary reason for the $15.0 million net change in assets and liabilities relating to operations above for the third quarter of 2004. During the first nine months of 2004, we spent $7.5 million (in the second quarter) to acquire 7,500 Bbls/d of oil puts or floors for 2005 and to retire 20 MMcf/d of natural gas hedges for the balance of 2004, although this amount was more than offset by the payable to Newfield at September 30, 2004. During the comparable periods in 2003, additional cash flow was generated by changes in our working capital balances, primarily decreases in various receivables and increases in various payables. 25 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Certain of our operating results and statistics for the comparative third quarters and first nine months of 2004 and 2003 are included in the following table.
Three Months Ended Nine Months Ended September 30, September 30, - ---------------------------------------------------------------- --------------------------- ---------------------------- 2004 2003 2004 2003 - ---------------------------------------------------------------- ------------- ------------ ------------- ------------- Average daily production volumes Bbls/d 19,206 18,051 19,114 18,852 Mcf/d 62,708 90,393 91,028 95,341 BOE/d (1) 29,657 33,116 34,285 34,742 Operating revenues and expenses (thousands) Oil sales $ 68,144 $ 44,863 $ 181,198 $ 140,998 Natural gas sales 34,924 43,933 151,177 154,274 Loss on settlements of derivative contracts (2) (22,243) (12,031) (54,750) (53,072) ------------- ------------ ------------- ------------- Total oil and natural gas revenues $ 80,825 $ 76,765 $ 277,625 $ 242,200 ============= ============ ============= ============= Lease operating expenses $ 19,781 $ 22,400 $ 66,839 $ 67,850 Production taxes and marketing expenses (3) 4,900 3,761 13,481 11,124 ------------- ------------ ------------- ------------- Total production expenses $ 24,681 $ 26,161 $ 80,320 $ 78,974 ============= ============ ============= ============= CO2 sales and transportation fees (4) $ 1,681 $ 2,238 $ 4,622 $ 6,872 CO2 operating expenses 255 602 608 1,453 ------------- ------------ ------------- ------------- CO2 operating margin $ 1,426 $ 1,636 $ 4,014 $ 5,419 ============= ============ ============= ============= Unit prices - including impact of hedges Oil price per Bbl $ 28.25 $ 24.60 $ 26.58 $ 24.41 Gas price per Mcf 5.36 4.32 5.55 4.48 Unit prices - excluding impact of hedges Oil price per Bbl $ 38.57 $ 27.01 $ 34.60 $ 27.40 Gas price per Mcf 6.05 5.28 6.06 5.93 Oil and gas operating revenues and expenses per BOE (1): Oil and natural gas revenues (excluding hedges) $ 37.78 $ 29.14 $ 35.38 $ 31.13 ------------- ------------ ------------- ------------- Oil and gas lease operating expenses $ 7.25 $ 7.35 $ 7.11 $ 7.15 Oil and gas production taxes and marketing expense 1.80 1.23 1.44 1.17 ------------- ------------ ------------- ------------- Total oil and gas production expenses $ 9.05 $ 8.58 $ 8.55 $ 8.32 - ---------------------------------------------------------------- ============= ============ ============= ============= (1) Barrel of oil equivalent using the ratio of one barrel of oil to 6 Mcf of natural gas ("BOE"). (2) See also "Market Risk Management" below for informationconcerning the Company's hedging transactions. (3) For the three and nine monthsended September 30, 2004, includes transportation expenses paid to Genesis of $0.3 million. (4) For three and nine months ended September 30, 2004, includes deferred revenue of $0.7 million and $1.8 million, respectively, associated with a volumetric production payment and $0.7 million and $1.9 million, respectively, of transportation income from Genesis.
26 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS PRODUCTION: Production by area for each of the quarters of 2003 and the first three quarters of 2004 is listed in the following table.
Average Daily Production (BOE/d) ----------------------------------------------------------------------------------------- First Second Third Fourth First Second Third Quarter Quarter Quarter Quarter Quarter Quarter Quarter Operating Area 2003 2003 2003 2003 2004 2004 2004 - ---------------------------------------------------------------------------------------------------------------------------- Mississippi - non-CO2 floods 14,537 13,600 13,367 13,066 12,754 13,048 12,969 Mississippi - CO2 floods 4,345 4,522 4,227 5,579 6,318 6,603 6,967 Onshore Louisiana 8,700 8,417 8,024 8,812 8,825 7,492 7,033 Other 158 160 312 268 229 345 803 ------------------------------------------------------------------------------------- Total Production excl. Offshore 27,740 26,699 25,930 27,725 28,126 27,488 27,772 Offshore Gulf of Mexico 8,353 8,351 7,186 6,865 8,521 9,114 1,885 ------------------------------------------------------------------------------------- Total Denbury 36,093 35,050 33,116 34,590 36,647 36,602 29,657 - ---------------------------------------=====================================================================================
As a result of the sale of our offshore properties in July 2004, third quarter production included only 19 days of offshore production, and thus third quarter production was less than production in all of the prior periods listed in the table above. Production for the third quarter of 2004 was also negatively impacted by Hurricane Ivan, which forced the shutdown of production at several of our fields for a few days as a result of several power outages. Adjusting for the offshore sale, overall production increased 7% on a BOE/d basis in the third quarter of 2004 as compared to production in the third quarter of 2003 and increased 4% for the first nine months of 2004 as compared to the same prior year period. However, several factors that caused fluctuations between the various periods should be noted. During the first quarter of 2003 (effective January 31), we sold Laurel Field, a Mississippi non-CO2 flood property that had average production of between 1,500 and 1,700 BOE/d since we acquired it in August 2002. Eliminating the one month of Laurel Field production in 2003 reduces the variance from first quarter 2003 production for Mississippi - non-CO2 floods by approximately 526 BOE/d. The balance of the decline in this operating area is primarily related to natural field depletion at several of our fields. Production increased slightly in this area in the second quarter of 2004, as compared to production in the prior quarter, as a result of additional natural gas drilling in the Selma Chalk formation at Heidelberg Field. During the third quarter of 2004, production in this area was virtually unchanged from levels in the second quarter. Natural gas production at this field averaged 13.5 MMcf/d in the third quarter of 2004 and 14.8 MMcf/d in the second quarter of 2004, higher than both the 11.0 MMcf/d of production in the first quarter and an average of 10.3 MMcf/d of production during 2003, making Heidelberg Field our single largest natural gas producing field for the last two quarters. As more fully discussed in "CO2 Operations" above, oil production from our tertiary operations continued to increase in the third quarter of 2004, averaging 6,967 Bbls/d, representing 36% of our third quarter corporate oil production and 25% of our total corporate production on a BOE basis pro forma to give effect to the offshore sale. Production from our offshore properties averaged 1,885 BOE/d in the third quarter, representing the production during the first 19 days of July prior to closing the sale on July 20, 2004. Production declines in our onshore Louisiana properties essentially offset the increases in other areas, declining 6% from second quarter 2004 levels and 12% from third quarter 2003 levels. Production at Thornwell, an onshore Louisiana field, averaged 1,104 BOE/d during the third quarter of 2004, down from 1,403 BOE/d in the prior quarter and 2,092 BOE/d in the third quarter of 2003. Production from this field is in a steep decline due to its short-lived nature, and is expected to further decline in the future. In spite of its short remaining life, we have generated a good return on investment at Thornwell, with a net profit to date (operating revenues less operating expenses and capital expenditures) through September 30, 2004 of $35.3 million. We have also begun to experience some declines at Lirette Field, another onshore Louisiana field, decreasing from 2,593 BOE/d in the second quarter of 2004 to 2,133 BOE/d in the third quarter, 27 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS although relatively close to the third quarter of 2003 production average of 2,284 BOE/d. This field is also expected to continue its decline in the near future. These two onshore Louisiana fields are expected to have the steepest decline rates of any of our properties. Our production in the Barnett Shale increased in the third quarter to approximately 800 BOE/d from 344 BOE/d in the second quarter and 307 BOE/d in the third quarter of 2003. The production increase was the result of three recently drilled horizontal wells, with four more wells scheduled for the last portion of 2004 and 25 wells tentatively scheduled for 2005. OIL AND NATURAL GAS REVENUES: Oil and natural gas revenues, net of hedge payments, for the third quarter of 2004 increased $4.1 million, or 5%, from revenues in the comparable quarter of 2003, all as a result of higher commodity prices, partially offset by lower production as a result of the sale of our offshore properties, and by higher payments on our hedges. When comparing the respective nine-month periods, revenues were also higher in 2004, primarily as a result of higher commodity prices. Production was almost the same for the comparable nine-month periods and hedge payments were slightly higher in 2004 than in 2003. Cash payments on our hedges were $22.2 million in the third quarter of 2004 and $54.8 million year to date, up 85% on a quarterly basis from the $12.0 million paid during the third quarter of 2003, and up 3% from the $53.1 million paid during the first nine months of 2003. See "Market Risk Management" for additional information regarding our hedging activities. Record high average commodity prices on a per BOE basis in the third quarter of 2004 increased revenues 31% or $23.5 million between the respective third quarters of 2004 and 2003. The 10% decrease in production in the third quarter of 2004 offset increased oil and natural gas revenues for the two periods, by $9.3 million, or 12%. Higher hedge payments further reduced revenue by $10.2 million or 13% between the respective third quarters. While both oil and natural gas prices were higher in the third quarter of 2004 as compared to those in the third quarter of 2003, the increase in oil prices was the most significant, with an increase in our average net oil price (before hedging) of $11.56 per Bbl, a 43% increase. When comparing the respective nine month periods, the same factors were involved, as higher commodity prices were partially offset by lower production and higher hedge payments. Higher commodity prices on a per BOE basis in the first nine months of 2004 increased revenues 16% or $39.9 million between the respective nine month periods. The 1% decrease in production in the first nine months of 2004 decreased oil and natural gas revenues between the two periods by $2.8 million, or 1%. Higher hedge payments in the first nine months of 2004 further decreased revenue by $1.7 million or 1% between the respective nine month periods. PRODUCTION EXPENSES: During the first three quarters of 2004, our workover expenses have been at normal levels and approximately $3.4 million less than during the comparable period in 2003, although we had higher than normal repairs and maintenance on offshore platforms during the first portion of 2004. As an example, during the first half of 2003, we incurred $2.9 million on two individually significant workovers relating to mechanical failures of two onshore Louisiana wells. Operating expenses on our tertiary operations increased from $13.3 million in the first nine months of 2003 to $17.9 million in the comparable period of 2004 as a result of increased activity at Mallalieu and McComb Fields. However, with the 52% higher production from these tertiary operations between the same periods, operating expenses for our tertiary operations on a per BOE basis decreased from $11.20 per BOE in the first nine months of 2003 to $9.84 per BOE in the first nine months of 2004. Nonetheless, our tertiary operations are resulting in steadily increasing costs per BOE on a total corporate basis as our tertiary operations constitute a more significant portion of our total production and operations. The balance of cost increases is generally attributable to higher energy costs to operate the properties and general cost inflation in our industry. In general, we expect our operating costs per BOE to increase through the end of 2004 and beyond as the operating costs of our tertiary operations are higher than for our other operations and as our tertiary operations become a larger and larger percentage of our total operations. Production taxes and marketing expenses generally change in proportion to commodity prices and production and as such, were higher in the third quarter of 2004 following record high commodity prices. The sale of our offshore properties also contributed to the increase in production taxes and marketing expenses on a per BOE basis during the third quarter of 2004, as most of our offshore properties were tax exempt. 28 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS General and Administrative Expenses General and administrative ("G&A") expenses increased 101% on a per BOE basis between the respective third quarters and 44% between the respective first nine month periods, as set forth below:
Three Months Ended Nine Months Ended September 30, September 30, - ------------------------------------------------- ----------------------------------- ------------------------- 2004 2003 2004 2003 - ------------------------------------------------- ---------------- ---------------- ------------ ------------ Net G&A expense (thousands) Gross G&A expenses $ 13,562 $ 10,748 $ 38,015 $ 33,152 State franchise taxes 295 378 783 1,099 Operator overhead charges (6,465) (6,359) (19,959) (19,382) Capitalized exploration costs (1,195) (1,322) (3,716) (4,257) ---------------- ---------------- ------------ ------------ Net G&A expense $ 6,197 $ 3,445 $ 15,123 $ 10,612 ================ ================ ============ ============ Average G&A cost per BOE $ 2.27 $ 1.13 $ 1.61 $ 1.12 Employees as of September 30 369 369 369 369 - ------------------------------------------------- ---------------- ---------------- ------------ ------------
Gross G&A expenses increased $2.8 million, or 26%, between the respective third quarters and $4.9 million, or 15%, between the respective first nine months. The single largest component of this increase relates to approximately $1.4 million and $2.4 million of employee severance payments in the third quarter and first nine months of 2004, respectively, for the offshore professional and technical staff terminated in conjunction with our offshore property sale. We also incurred additional G&A expenses associated with our corporate restructuring in December 2003, compliance with the requirements of the Sarbanes-Oxley Act, the sale of stock by the Texas Pacific Group in March 2004, and overall increases in most other categories of G&A due to general cost inflation. During the third quarter of 2004, we granted a total of 1.1 million shares of restricted stock to our officers and independent directors, generating deferred compensation expense of approximately $23.0 million, the market value of the shares on the date of grant. A portion of this restricted stock vests over five years and a smaller portion vests upon retirement (in addition to vesting upon death, disability or a change of control). We are amortizing the $23.0 million of compensation expense of this restricted stock over the five year vesting period and over the projected retirement date vesting period, expensing approximately $593,000 during the third quarter of 2004. We estimate that amortized compensation expense for the restricted stock will be approximately $1.0 million per quarter through 2006. As a result of the personnel reductions in our offshore area, our capitalized exploration costs decreased slightly in the third quarter of 2004 as compared to the level of those costs in the same period in 2003, partially offset by slightly higher overhead recoveries resulting from incremental development activity. The change in net G&A was similar to the change in gross G&A between the respective periods. On a per BOE basis, G&A costs increased parallel to the change in gross cost, and for the respective third quarters, further increased as a result of the lower overall production in the third quarter of 2004 as a result of the sale of our offshore properties. 29 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Interest and Financing Expenses
Three Months Ended Nine Months Ended September 30, September 30, - ---------------------------------------------------- ------------------------------- -------------------------- Amounts in thousands, except per BOE amounts 2004 2003 2004 2003 - ---------------------------------------------------- -------------- ---------------- ------------- ------------ Interest expense $ 4,768 $ 5,358 $ 14,917 $ 18,046 Non-cash interest expense (304) (226) (757) (1,025) -------------- ---------------- ------------- ------------ Cash interest expense 4,464 5,132 14,160 17,021 Interest and other income (701) (412) (1,450) (963) -------------- ---------------- ------------- ------------ Net cash interest expense $ 3,763 $ 4,720 $ 12,710 $ 16,058 ============== ================ ============= ============ Average net cash interest expense per BOE $ 1.38 $ 1.55 $ 1.35 $ 1.69 Average interest rate (1) 7.3% 6.2% 6.6% 6.5% Average debt outstanding $ 243,478 $ 332,913 $ 286,139 $ 350,670 - ---------------------------------------------------- -------------- ---------------- ------------- ------------ (1) Includes commitment fees but excludes amortization of discount and debt issue costs.
Interest expense for the third quarter and first nine months of 2004 decreased from levels in the comparable periods of 2003 primarily due to lower average debt levels as a result of our $50 million reduction in debt during 2003 and the payoff of our bank debt in the third quarter of 2004 with the proceeds from our offshore property sale. Our non-cash interest expense for the nine month comparative periods decreased as a result of the subordinated debt refinancing in March 2003, which eliminated the amortization of discount on our old subordinated debt, which was higher than the discount and related amortization on our new subordinated debt issue. Depletion, Depreciation and Amortization
Three Months Ended Nine Months Ended September 30, September 30, - --------------------------------------------------- ------------------------------- -------------------------- Amounts in thousands, except per BOE amounts 2004 2003 2004 2003 - --------------------------------------------------- -------------- ---------------- ------------- ------------ Depletion and depreciation $ 18,658 $ 20,805 $ 69,357 $ 64,234 Depletion and depreciation of CO2 assets 1,200 635 3,577 1,665 Accretion of asset retirement obligations 429 752 1,971 2,255 Depreciation of other fixed assets 493 374 1,360 1,095 -------------- ---------------- ------------- ------------ Total DD&A $ 20,780 $ 22,566 $ 76,265 $ 69,249 ============== ================ ============= ============ DD&A per BOE: Oil and natural gas properties $ 7.00 $ 7.08 $ 7.59 $ 7.01 CO2 assets and other fixed assets 0.62 0.33 0.53 0.29 - --------------------------------------------------- -------------- ---------------- ------------- ------------ Total DD&A cost per BOE $ 7.62 $ 7.41 $ 8.12 $ 7.30 - --------------------------------------------------- ============== ================ ============= ============
In total, our depletion, depreciation and amortization ("DD&A") rate on a per BOE basis increased 3% between the respective third quarters, primarily due to the higher percentage of expenditures on offshore properties during 2003 and the first six months of 2004, which have higher overall finding and development costs. In addition, certain of our future development cost estimates have increased to reflect the rising costs in the industry, contributing to the increase in our DD&A rate during 2004. The 2004 rates are more comparable to the DD&A rate of $8.00 per BOE during the fourth quarter of 2003 than to the DD&A rate for the first nine months of 2003. Our DD&A rate on a per BOE basis in the third quarter of 2004 decreased to $7.62 per BOE, down from $8.46 per BOE in the second quarter of 2004 primarily as a result of the sale of our offshore properties, the proceeds of which were credited to the full cost pool. We adjust our DD&A rate each quarter based on our updated oil and natural gas reserve estimates, and thus our DD&A rate could change significantly in the future. Our DD&A rate for our CO2 and other fixed assets increased in the third quarter to 30 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS $0.62 per BOE as compared to $0.51 per BOE in the second quarter of 2004, as a result of the additional cost incurred drilling CO2 wells during the quarter and higher associated future development costs, partially offset by an increase in CO2 reserves. Income Taxes
Three Months Ended Nine Months Ended September 30, September 30, - ------------------------------------------------------------- --------------------------------- ---------------------------- Amounts in thousands, except per BOE amounts and tax rates 2004 2003 2004 2003 - ------------------------------------------------------------- ---------------- ---------------- ------------- -------------- Income tax provision Current income tax expense (benefit) $ 18,949 $ (1,514) $ 22,045 $ 123 Deferred income tax expense (benefit) (11,117) 9,064 6,077 18,946 ---------------- ---------------- ------------- ------------- Total income tax expense $ 7,832 $ 7,550 $ 28,122 $ 19,069 ================ ================ ============= ============= Average income tax expense per BOE $ 2.87 $ 2.48 $ 2.99 $ 2.01 Effective tax rate 30.0% 33.3% 31.9% 33.0% - ------------------------------------------------------------- ---------------- ---------------- ------------- -------------
Our income tax provision for the respective periods was based on an estimated statutory tax rate of 38%. The net effective tax rate was lower than the statutory rates, primarily due to the recognition of enhanced oil recovery credits which lowered our overall tax rate. The current income tax expense represents our anticipated alternative minimum cash taxes that we cannot offset with our regular tax net operating loss carryforwards or our enhanced oil recovery credits. During the third quarter of 2004, we recognized approximately $18.0 million of current income taxes as a result of the sale of our offshore properties which was a gain for income tax purposes. The taxes on the offshore sale were primarily alternative minimum taxes as we were able to offset the related regular tax with our net operating loss carryfowards. As of September 30, 2004, we had utilized all of our tax net operating loss carryforwards. The deferred income tax benefit recognized in the third quarter of 2004 is primarily related to the net impact of the adjustments to temporary differences associated with the sale of Denbury Offshore. Per BOE Data The following table summarizes our cash flow, DD&A and results of operations on a per BOE basis for the comparative periods. Each of the individual components are discussed above.
Three Months Ended Nine Months Ended September 30, September 30, - --------------------------------------------------------------- ------------------------- ------------------------- Per BOE data 2004 2003 2004 2003 - --------------------------------------------------------------- ------------ ------------ ------------ ------------ Revenues $ 37.78 $ 29.14 $ 35.38 $ 31.13 Loss on settlements of derivative contracts (8.15) (3.95) (5.83) (5.60) Lease operating expenses (7.25) (7.35) (7.11) (7.15) Production taxes and marketing expenses (1.80) (1.23) (1.44) (1.17) - --------------------------------------------------------------- ------------ ------------ ------------ ------------ Production netback 20.58 16.61 21.00 17.21 CO2 operating margin 0.55 0.54 0.43 0.57 General and administrative expenses (2.27) (1.13) (1.61) (1.12) Net cash interest expense (1.38) (1.55) (1.35) (1.69) Current income taxes and other (6.57) 0.50 (2.32) - Net changes in assets and liabilities relating to operations 5.50 1.37 (0.08) 0.40 - --------------------------------------------------------------- ------------ ------------ ------------ ------------ Cash flow from operations 16.41 16.34 16.07 15.37 DD&A (7.62) (7.41) (8.12) (7.30) Deferred income taxes 4.07 (2.97) (0.65) (2.00) Non-cash hedging adjustments 0.14 0.47 (0.89) 0.39 Early retirement of subordinated debt - - - (1.86) Cumulative effect of change in accounting principle - - - 0.28 Changes in assets and liabilities and other non-cash items (6.30) (1.46) (0.03) (0.52) - --------------------------------------------------------------- ------------ ------------ ------------ ------------ Net income $ 6.70 $ 4.97 $ 6.38 $ 4.36 - --------------------------------------------------------------- ============ ============ ============ ============
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 - ------------------------------------- ----------- ----------- ---------- ----------- ----------- ----------- ----------- 2004- Carrying Fair Amounts in thousands 2005 2006 2007 2008 Thereafter Value Value - ------------------------------------- ----------- ----------- ---------- ----------- ----------- ----------- ----------- Fixed rate debt: 7.5% subordinated debt, net of discount, due 2013........... $ - $ - $ - $ - $ 225,000 $ 223,348 $ 238,500 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 33% and 75% of our anticipated production each year to provide us with a reasonably certain amount of cash flow to cover most of our budgeted exploration and development expenditures without incurring significant debt, although our hedging percentage may vary relative to our debt levels. For example, when our debt levels are high, we may hedge a higher percentage of our production than when our debt levels are low. When we make a significant acquisition, we attempt to hedge a large percentage, up to 100%, of the forecasted production for the subsequent one to three years following the acquisition in order to help provide us with a minimum return on our investment. Much of our hedging activity has been with collars, although for the 2002 COHO acquisition, we also used swaps in order to lock in the prices used in our economic forecasts. In the second quarter of 2004, we purchased price floors or puts relating to a portion of our 2005 oil production, allowing us to retain any upside from increases in commodity prices. All of the mark-to-market valuations used for our financial derivatives are provided by external sources and are based on prices that are actively quoted. We manage and control market and counterparty credit risk through established internal control procedures which are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures, and diversification. Upon reaching a verbal agreement on the offshore property sale, subject primarily to the purchaser's further due diligence, we entered into natural gas swaps on a total of 23.6 Bcf for the period of July 2004 through December 2005, covering the anticipated natural gas production from our offshore properties for that period, with the tacit understanding with the prospective purchaser that these hedges would be transferred to the purchaser upon closing. These swaps did not qualify for hedge accounting and during the third quarter of 2004 we assigned them to the purchaser of the offshore properties. At about the same time, with the expectation that the offshore transaction would be consummated, we retired, by purchasing offsetting contracts, 20 MMcf/d of our natural gas hedges for July to December of 2004, at a cost of approximately $3.9 million. This transaction, and the related hedge accounting designation changes and associated fair market value adjustments, were the primary reasons for the $8.3 million net charge to earnings for the first nine months of 2004 relating to our derivative contracts. At September 30, 2004, our derivative contracts were recorded at their fair value, which was a net liability of approximately $37.8 million, a decrease of approximately $6.8 million from the $44.6 million fair value liability recorded as of December 31, 2003. This decrease in our net liability is a result of the termination of nine months of derivative contracts due to the passage of time, partially offset by an increase in the liability as a result of higher oil and natural gas commodity prices between December 31, 2003 and September 30, 2004. Information regarding our current hedging positions is included in Note 11 to the Unaudited Condensed Consolidated Financial Statements. 32 DENBURY RESOURCES INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Although we have hedged less of our production in 2004 than in 2003 (approximately 60% of our total production in 2004 as compared to approximately 80% in 2003), we expect our total hedge payments for 2004 to be higher than in 2003 due to the significantly higher oil prices in 2004 and lower hedged prices. For 2005 production, through September 30, 2004 we had purchased 15.0 MMcf/d of natural gas collars with a floor of $3.00 per MMBtu and a ceiling of approximately $5.50 per MMBtu and 7,500 Bbls/d of oil puts or floors with a floor price of $27.50, acquired at a total cost of approximately $3.6 million. Since these most recent hedges are puts or price floors, the maximum out-of-pocket exposure is the cost of the put. Based on NYMEX natural gas futures prices at September 30, 2004, we would expect to make future cash payments of $14.5 million on our natural gas commodity hedges. If natural gas futures prices were to decline by 10%, we would expect to pay $8.4 million under our natural gas commodity hedges, and if futures prices were to increase by 10% we would expect to pay $20.5 million. Based on NYMEX crude oil futures prices at September 30, 2004, we would expect to pay $22.9 million on our crude oil commodity hedges. If crude oil futures prices were to decline by 10%, we would expect to pay $18.6 million, and if crude oil futures prices were to increase by 10%, we would expect to pay $27.1 million under our crude oil commodity hedges. Most of our hedges that have a ceiling price expire by the end of 2004. Critical Accounting Policies For a discussion of our critical accounting policies, which are related to property, plant and equipment, depletion and depreciation, oil and natural gas reserves, asset retirement obligations, income taxes and hedging activities, and which remain unchanged, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" in our annual report on Form 10-K for the year ended December 31, 2003. 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 Item 3. Quantitative and Qualitative Disclosures about Market Risk - ------------------------------------------------------------------- The information required by Item 3 is set forth under "Market Risk Management" in Management's Discussion and Analysis of Financial Condition and Results of Operations. Item 4. Controls and Procedures - -------------------------------- Denbury maintains disclosure controls and procedures designed to ensure that information required to be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms. Our chief executive officer and chief financial officer have evaluated our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q and have determined that such disclosure controls and procedures are effective in all material respects in providing to them on a timely basis material information required to be disclosed in this quarterly report. There have been no significant changes in internal controls over financial reporting during the period covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, Denbury's internal controls over financial reporting. Part II. Other Information Item 1. Legal Proceedings - -------------------------- We, along with two other companies have been named in a lawsuit entitled "J. Paulin Duhe, Inc. vs. Texaco, Inc., et al," Cause No. 101,227, filed within the last year in the 16th Judicial District Court, Division "E", Terrebonne Parish, Louisiana, seeking unspecified monetary amounts for alleged surface and groundwater contamination affecting, and asking for restoration of, the lands that are part of our Iberia Field in Iberia Parish, Louisiana. The first oil and natural gas well was drilled on this property in 1921. We acquired this property approximately four years ago and have an indemnification from the prior owner, which we anticipate will cover us from most environmental damages that occurred prior to the time that we purchased the property. We have not yet been able to determine our potential exposure in this case. We plan to vigorously defend this lawsuit, as well as seek indemnification from the prior owners if necessary. Item 2. Unregistered Sales of Equity Securities and Use of Proceeds - -------------------------------------------------------------------- Presented below is information on repurchases by Denbury of its common stock during 2004:
ISSUER PURCHASES OF EQUITY SECURITIES - --------------------------------------------------------------------------------------------------------------- (c) Total Number of (d) Maximum Number (a) Total Shares Purchased of Shares that May Number of (b) Average as Part of Publicly Yet Be Purchased Shares Price Paid Announced Plans or Under the Plans or Period Purchased per Share Programs Programs - --------------------------------------------------------------------------------------------------------------- January 1 through 31, 2004 - - - 100,000 February 1 through 29, 2004 50,000 $ 14.87 50,000 50,000 March 1 through 31, 2004 - - - 50,000 April 1 through 30, 2004 25,000 $ 18.74 25,000 25,000 May 1 through 31, 2004 25,000 $ 17.96 25,000 - June 1 through 30, 2004 - - - - July 1 through 31, 2004 40,000 $ 21.31 40,000 160,000 August 1 through 31, 2004 10,000 $ 20.00 10,000 150,000 September 1 through 30, 2004 - - - 150,000 Total 150,000 $ 18.09 150,000 150,000 - ---------------------------------------------------------------------------------------------------------------
34 In August 2003, we adopted a stock repurchase plan (the "Plan") to purchase shares of our common stock on the NYSE in order for such repurchased shares to be reissued to our employees who participate in Denbury's Employee Stock Purchase Plan. The Plan provides for purchases through an independent broker of 50,000 shares of Denbury's common stock per fiscal quarter for a period of approximately twelve months, or a total of 200,000 shares, beginning August 13, 2003 and ending on July 31, 2004. In May 2004, the Board of Directors renewed the Plan for another year and three months, beginning July 1, 2004 and ending September 30, 2005 covering another 200,000 shares at the same 50,000 shares per quarter rate. Purchases are to be made at prices and times determined at the discretion of the independent broker, provided however that no purchases may be made during the last ten business days of a fiscal quarter. Item 6. Exhibits -----------------
Exhibits: -------- 31(a)* Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31(b)* Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32* Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
* Filed herewith. 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: November 8, 2004 36 EX-31 2 denbury3rdq10q2004ex31a.txt EXHIBIT 31(A) Exhibit 31(a) CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Gareth Roberts, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Denbury Resources Inc. (the "registrant"); 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. November 8, 2004 /s/ Gareth Roberts ------------------------------------- Gareth Roberts President and Chief Executive Officer EX-31 3 denbury3rdq10q2004ex31b.txt EXHIBIT 31(B) Exhibit 31(b) CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Phil Rykhoek, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Denbury Resources Inc. (the "registrant"); 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. November 8, 2004 /s/ Phil Rykhoek ---------------------------------------------- Phil Rykhoek Sr. Vice President and Chief Financial Officer EX-32 4 denbury3rdq10q2004ex32.txt EXHIBIT 32 Exhibit 32 Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 In connection with the accompanying Quarterly Report on Form 10-Q for the quarter ended September 30, 2004 (the "Report") of Denbury Resources Inc. ("Denbury") as filed with the Securities and Exchange Commission on November 8, 2004, each of the undersigned, in his capacity as an officer of Denbury, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge: 1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and 2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Denbury. Dated: November 8, 2004 /s/ Gareth Roberts ---------------------------------------------- Gareth Roberts President and Chief Executive Officer Dated: November 8, 2004 /s/ Phil Rykhoek ---------------------------------------------- Phil Rykhoek Sr. Vice President and Chief Financial Officer -----END PRIVACY-ENHANCED MESSAGE-----