UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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þ | | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31,June 30, 2011
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o | | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number:001-12935
DENBURY RESOURCES INC.
(Exact name of registrant as specified in its charter)
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Delaware
| | 20-0467835 |
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(State or other jurisdictions of incorporation or organization) | | 20-0467835 (I.R.S. Employer Identification No.) |
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5320 Legacy Drive Plano, TX
| | 75024 |
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(Address of principal executive offices) | | 75024 (Zip Code) |
Registrant’s telephone number, including area code:(972) 673-2000
Not applicable
(Former name, former address and former fiscal year, if changed since last report)
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.
Yesþ Noo
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yesþ Noo
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
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Large accelerated filerþ | | Accelerated filer o | | Non-accelerated filer o | | Smaller reporting company Accelerated filero |
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| | | | Non-accelerated filero(Do not check if a smaller reporting company) | | Smaller reporting companyo |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
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Class | | Outstanding at April 29,August 1, 2011 |
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Common Stock, $.001 par value | | 401,887,373402,350,295 |
DENBURY RESOURCES INC.
INDEX
2
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except par value and share data)
| | | | | | | | | |
| | March 31, | | December 31, | | | | | | | | |
| | June 30, | | December 31, | |
| | 2011 | | 2010 | | 2011 | | 2010 | |
ASSETS | ASSETS | |
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Current assets | | |
| | |
Cash and cash equivalents | | $ | 127,857 | | $ | 381,869 | | | $ | 121,792 | | $ | 381,869 | |
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Accrued production receivable | | 264,150 | | 223,584 | | | 255,034 | | 223,584 | |
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Trade and other receivables, net of allowance of $471 and $456, respectively | | 138,026 | | 114,149 | | |
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Trade and other receivables, net of allowance of $486 and $456, respectively | | | 153,018 | | 114,149 | |
Short-term investments | | 99,733 | | 93,020 | | | 88,220 | | 93,020 | |
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Derivative assets | | 19,345 | | 24,242 | | | 19,322 | | 24,242 | |
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Deferred tax assets | | 72,552 | | 27,454 | | | 22,097 | | 27,454 | |
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Total current assets | | 721,663 | | 864,318 | | | 659,483 | | 864,318 | |
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Property and equipment | | |
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Oil and natural gas properties (using full cost accounting) | | |
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Proved | | 6,238,629 | | 6,042,442 | | | 6,508,928 | | 6,042,442 | |
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Unevaluated | | 912,267 | | 870,130 | | | 952,452 | | 870,130 | |
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CO2 and other non-hydrocarbon gases - properties and pipelines | | 1,940,392 | | 1,901,662 | | |
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CO2 and other non-hydrocarbon gases properties | | | 572,957 | | 523,423 | |
Pipelines and plants | | | 1,445,214 | | 1,378,239 | |
Other property and equipment | | 132,692 | | 120,641 | | | 138,671 | | 120,641 | |
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Less accumulated depletion, depreciation, amortization, and impairment | | | (2,295,952 | ) | | | (2,197,517 | ) | | | (2,403,741 | ) | | | (2,197,517 | ) |
| | | | | |
| | | | | | |
Net property and equipment | | 6,928,028 | | 6,737,358 | | | 7,214,481 | | 6,737,358 | |
| | | | | | | | | |
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Derivative assets | | 9,203 | | 12,919 | | | 17,609 | | 12,919 | |
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Goodwill | | 1,232,418 | | 1,232,418 | | | 1,232,418 | | 1,232,418 | |
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Other assets | | 220,107 | | 218,050 | | | 215,432 | | 218,050 | |
| | | | | |
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Total assets | | $ | 9,111,419 | | $ | 9,065,063 | | | $ | 9,339,423 | | $ | 9,065,063 | |
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LIABILITIES AND STOCKHOLDERS’ EQUITY | LIABILITIES AND STOCKHOLDERS’ EQUITY | |
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Current liabilities | | |
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Accounts payable and accrued liabilities | | $ | 246,145 | | $ | 345,998 | | | $ | 333,953 | | $ | 345,998 | |
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Oil and gas production payable | | 161,471 | | 143,145 | | | 172,837 | | 143,145 | |
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Derivative liabilities | | 218,341 | | 78,184 | | | 81,627 | | 78,184 | |
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Current maturities of long-term debt | | 8,446 | | 7,948 | | | 8,622 | | 7,948 | |
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Other liabilities | | 4,070 | | 4,070 | | | 4,070 | | 4,070 | |
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Total current liabilities | | 638,473 | | 579,345 | | | 601,109 | | 579,345 | |
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Long-term liabilities | | |
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Long-term debt, net of current portion | | 2,344,781 | | 2,416,208 | | | 2,288,112 | | 2,416,208 | |
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Asset retirement obligations | | 83,576 | | 81,290 | | | 86,109 | | 81,290 | |
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Derivative liabilities | | 47,745 | | 29,687 | | | 3,378 | | 29,687 | |
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Deferred taxes | | 1,589,912 | | 1,547,992 | | | 1,687,839 | | 1,547,992 | |
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Other liabilities | | 25,567 | | 29,834 | | | 24,562 | | 29,834 | |
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Total long-term liabilities | | 4,091,581 | | 4,105,011 | | | 4,090,000 | | 4,105,011 | |
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Commitments and contingencies (Note 7) | | |
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Stockholders’ equity | | |
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Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding | | - | | - | | | — | | — | |
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Common stock, $.001 par value, 600,000,000 shares authorized; 402,155,781 and 400,291,033 shares issued, respectively | | 402 | | 400 | | |
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Common stock, $.001 par value, 600,000,000 shares authorized; 402,508,885 and 400,291,033 shares issued, respectively | | | 403 | | 400 | |
Paid-in capital in excess of par | | 3,061,793 | | 3,045,937 | | | 3,074,335 | | 3,045,937 | |
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Retained earnings | | 1,321,952 | | 1,336,142 | | | 1,581,198 | | 1,336,142 | |
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Accumulated other comprehensive income (loss) | | 3,692 | | | (488 | ) | |
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Treasury stock, at cost, 298,707 and 78,524 shares, respectively | | | (6,474 | ) | | | (1,284 | ) | |
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Accumulated other comprehensive loss | | | | (3,429 | ) | | | (488 | ) |
Treasury stock, at cost, 193,177 and 78,524 shares, respectively | | | | (4,193 | ) | | | (1,284 | ) |
| | | | | | |
Total stockholders’ equity | | 4,381,365 | | 4,380,707 | | | 4,648,314 | | 4,380,707 | |
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Total liabilities and stockholders’ equity | | $ | 9,111,419 | | $ | 9,065,063 | | | $ | 9,339,423 | | $ | 9,065,063 | |
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See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.Statements
3
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
| | | | | | | | | |
| | Three Months Ended | |
| |
| | March 31, | | | | | | | | | | | | | | | | |
| | Three Months Ended | | Six Months Ended | |
| | 2011 | | 2010 | | June 30, | | June 30, | |
| | | 2011 | | 2010 | | 2011 | | 2010 | |
Revenues and other income | | |
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Oil, natural gas, and related product sales | | $ | 506,192 | | $ | 330,886 | | | $ | 591,099 | | $ | 488,028 | | $ | 1,097,291 | | $ | 818,914 | |
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CO2 sales and transportation fees | | 4,924 | | 4,497 | | | 5,343 | | 4,690 | | 10,267 | | 9,187 | |
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Gain on sale of interests in Genesis | | - | | 101,568 | | | — | | | (28 | ) | | — | | 101,540 | |
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Interest income and other income | | 3,049 | | 1,870 | | | 4,955 | | 4,520 | | 8,004 | | 6,390 | |
| | | | | |
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Total revenues and other income | | 514,165 | | 438,821 | | | 601,397 | | 497,210 | | 1,115,562 | | 936,031 | |
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Expenses | | |
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Lease operating expenses | | 127,097 | | 96,220 | | | 129,932 | | 127,743 | | 257,029 | | 223,963 | |
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Production taxes and marketing expenses | | 32,751 | | 19,317 | | | 39,688 | | 38,100 | | 72,439 | | 57,417 | |
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CO2 discovery and operating expenses | | 2,154 | | 1,368 | | | 1,869 | | 1,681 | | 4,023 | | 3,049 | |
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General and administrative | | 43,846 | | 32,709 | | | 30,900 | | 31,192 | | 74,746 | | 63,901 | |
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Interest, net of amounts capitalized of $10,957 and $21,312, respectively | | 48,777 | | 26,416 | | |
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Interest, net of amounts capitalized of $13,194, $23,850, $24,151 and $45,162, respectively | | | 42,249 | | 43,483 | | 91,026 | | 69,899 | |
Depletion, depreciation, and amortization | | 93,594 | | 81,872 | | | 103,495 | | 129,209 | | 197,089 | | 211,081 | |
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Derivatives expense (income) | | 170,750 | | | (41,225 | ) | |
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Derivatives income | | | | (172,904 | ) | | | (128,674 | ) | | | (2,154 | ) | | | (169,899 | ) |
Loss on early extinguishment of debt | | 15,783 | | - | | | 348 | | — | | 16,131 | | — | |
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Transaction and other costs related to the Encore Merger | | 2,359 | | 44,999 | | | 2,018 | | 22,784 | | 4,377 | | 67,783 | |
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Total expenses | | 537,111 | | 261,676 | | | 177,595 | | 265,518 | | 714,706 | | 527,194 | |
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Income (loss) before income taxes | | | (22,946 | ) | | 177,145 | | |
Income before income taxes | | | 423,802 | | 231,692 | | 400,856 | | 408,837 | |
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Income tax provision (benefit) | | |
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Income tax provision | | |
Current income taxes | | | (848 | ) | | 669 | | | 12,028 | | 6,941 | | 11,180 | | 7,610 | |
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Deferred income taxes | | | (7,908 | ) | | 76,272 | | | 152,528 | | 74,422 | | 144,620 | | 150,694 | |
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Consolidated net income (loss) | | | (14,190 | ) | | 100,204 | | |
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Consolidated net income | | | 259,246 | | 150,329 | | 245,056 | | 250,533 | |
Less: net income attributable to noncontrolling interest | | - | | | (3,316 | ) | | — | | | (14,962 | ) | | — | | | (18,278 | ) |
| | | | | | | | | | | | | |
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Net income (loss) attributable to Denbury stockholders | | $ | (14,190 | ) | | $ | 96,888 | | |
Net income attributable to Denbury stockholders | | | $ | 259,246 | | $ | 135,367 | | $ | 245,056 | | $ | 232,255 | |
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Net income (loss) per common share | | |
| | |
Net income per common share | | |
Basic | | $ | (0.04 | ) | | $ | 0.33 | | | $ | 0.65 | | $ | 0.34 | | $ | 0.62 | | $ | 0.67 | |
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Diluted | | $ | (0.04 | ) | | $ | 0.32 | | | $ | 0.64 | | $ | 0.34 | | $ | 0.61 | | $ | 0.66 | |
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Weighted average common shares outstanding | | |
| | |
Basic | | 397,386 | | 294,143 | | | 398,631 | | 395,548 | | 398,032 | | 345,126 | |
| | |
Diluted | | 397,386 | | 299,224 | | | 403,919 | | 400,867 | | 403,703 | | 350,326 | |
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
4
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
| | | | | | |
| | Three Months Ended | |
| |
| | March 31, | | | | | | | | |
| | Six Months Ended | |
| | 2011 | | 2010 | | June 30, | |
| | | 2011 | | 2010 | |
Cash flows from operating activities | | |
| | |
Consolidated net income (loss) | | $ | (14,190 | ) | | $ | 100,204 | | |
| | |
Consolidated net income | | | $ | 245,056 | | $ | 250,533 | |
Adjustments needed to reconcile to net cash provided by operating activities | | |
| | |
Depletion, depreciation, and amortization | | 93,594 | | 81,872 | | | 197,089 | | 211,081 | |
| | |
Deferred income taxes | | | (7,908 | ) | | 76,272 | | | 144,620 | | 150,694 | |
| | |
Gain on sale of interests in Genesis | | - | | | (101,568 | ) | | — | | | (101,540 | ) |
| | |
Stock-based compensation | | 10,201 | | 7,806 | | | 18,132 | | 17,130 | |
| | |
Non-cash fair value derivative adjustments | | 172,338 | | | (101,026 | ) | | | (11,508 | ) | | | (226,899 | ) |
| | |
Loss on early extinguishment of debt | | 15,783 | | - | | | 16,131 | | — | |
| | |
Other, net | | 1,399 | | 2,410 | | | 5,755 | | 5,871 | |
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Changes in operating assets and liabilities: | | |
| | |
Changes in operating assets and liabilities | | |
Accrued production receivable | | | (44,243 | ) | | | (12,125 | ) | | | (35,068 | ) | | 52,075 | |
| | |
Trade and other receivables | | | (20,160 | ) | | 30,854 | | | | (28,258 | ) | | 10,058 | |
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Other assets | | | (5,773 | ) | | | (2,775 | ) | | | (2,920 | ) | | | (3,134 | ) |
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Accounts payable and accrued liabilities | | | (90,382 | ) | | 21,971 | | | | (48,471 | ) | | 12,066 | |
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Oil and natural gas production payable | | 18,770 | | 13,394 | | | 30,135 | | 11,236 | |
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Other liabilities | | | (4,597 | ) | | | (4,121 | ) | | | (7,340 | ) | | | (4,880 | ) |
| | | | | |
| | | | | | |
Net cash provided by operating activities | | 124,832 | | 113,168 | | | 523,353 | | 384,291 | |
| | | | | | | | | |
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Cash flows used for investing activities | | |
Oil and natural gas capital expenditures | | | (190,296 | ) | | | (92,647 | ) | | | (471,601 | ) | | | (317,173 | ) |
| | |
Acquisitions of oil and natural gas properties | | | (29,801 | ) | | | (340 | ) | | | (32,482 | ) | | | (24,243 | ) |
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Cash paid in Encore Merger, net of cash acquired | | - | | | (801,489 | ) | | — | | | (801,489 | ) |
| | |
CO2 and other non-hydrocarbon gases - capital expenditures, including pipelines | | | (66,157 | ) | | | (72,647 | ) | |
| | |
Deposit received on divesture of Southern Assets | | - | | 45,000 | | |
| | |
CO2 and other non-hydrocarbon gases capital expenditures | | | | (31,731 | ) | | | (44,274 | ) |
Pipelines and plants capital expenditures | | | | (98,669 | ) | | | (108,177 | ) |
Net proceeds from sales of oil and natural gas properties and equipment | | | — | | 881,344 | |
Net proceeds from sale of interests in Genesis | | - | | 162,622 | | | — | | 162,622 | |
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Other | | 1,211 | | | (4,826 | ) | | 1,643 | | | (7,224 | ) |
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| | | | | | |
Net cash used for investing activities | | | (285,043 | ) | | | (764,327 | ) | | | (632,840 | ) | | | (258,614 | ) |
| | | | | | | | | |
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Cash flows from financing activities | | |
Bank repayments | | | (130,000 | ) | | | (625,000 | ) | | | (130,000 | ) | | | (1,514,000 | ) |
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Bank borrowings | | 130,000 | | 1,025,000 | | | 130,000 | | 1,149,000 | |
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Repayment of senior subordinated notes | | | (469,552 | ) | | | (508,182 | ) | | | (525,000 | ) | | | (609,424 | ) |
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Premium paid on repayment of senior subordinated notes | | | (13,137 | ) | | | (6,257 | ) | | | (13,137 | ) | | | (7,214 | ) |
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Net proceeds from issuance of senior subordinated notes | | 400,000 | | 1,000,000 | | | 400,000 | | 1,000,000 | |
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Escrowed funds for redemption of senior subordinated notes | | - | | | (65,566 | ) | |
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Net proceeds from issuance of common stock | | | 9,203 | | 5,540 | |
Costs of debt financing | | | (8,441 | ) | | | (76,129 | ) | | | (13,274 | ) | | | (76,232 | ) |
| | |
ENP distributions to noncontrolling interest | | | — | | | (12,209 | ) |
Other | | | (2,671 | ) | | | (4,113 | ) | | | (8,382 | ) | | | (14,255 | ) |
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Net cash provided by (used for) financing activities | | | (93,801 | ) | | 739,753 | | |
Net cash used for financing activities | | | | (150,590 | ) | | | (78,794 | ) |
| | | | | | | | | |
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Net increase (decrease) in cash and cash equivalents | | | (254,012 | ) | | 88,594 | | | | (260,077 | ) | | 46,883 | |
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Cash and cash equivalents at beginning of period | | 381,869 | | 20,591 | | | 381,869 | | 20,591 | |
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Cash and cash equivalents at end of period | | $ | 127,857 | | $ | 109,185 | | | $ | 121,792 | | $ | 67,474 | |
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See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
5
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS
(In thousands)
| | | | | | | | |
| | Three Months Ended | |
| | | | | | | | |
| | March 31, |
| | | | | | | | |
| | 2011 | | 2010 |
| | | | | | | | |
Consolidated net income (loss) | | $ | (14,190 | ) | | $ | 100,204 | |
| | | | | | | | |
Other comprehensive income (loss), net of income tax: | | | | | | | | |
| | | | | | | | |
Net unrealized gains on available-for-sale securities, net of tax of $2,550 | | | 4,163 | | | | - | |
| | | | | | | | |
Interest rate lock derivative contracts reclassified to income,
net of tax of $11 in each period | | | 17 | | | | 17 | |
| | | | | | | | |
Change in deferred hedge loss on interest rate swaps, net of tax of $10 | | | - | | | | (27 | ) |
| | | | |
| | | | | | | | |
Consolidated comprehensive income (loss) | | | (10,010 | ) | | | 100,194 | |
| | | | | | | | |
Less: comprehensive income attributable to noncontrolling interest | | | - | | | | (3,285 | ) |
| | | | |
| | | | | | | | |
Comprehensive income (loss) attributable to Denbury stockholders | | $ | (10,010 | ) | | $ | 96,909 | |
| | | | |
| | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Six Months Ended | |
| | June 30, | | | June 30, | |
| | 2011 | | | 2010 | | | 2011 | | | 2010 | |
Consolidated net income | | $ | 259,246 | | | $ | 150,329 | | | $ | 245,056 | | | $ | 250,533 | |
Other comprehensive income, net of income tax | | | | | | | | | | | | | | | | |
Net unrealized loss on available-for-sale securities, net of tax of $(4,375) and $(1,824), respectively | | | (7,139 | ) | | | — | | | | (2,976 | ) | | | — | |
Interest rate lock derivative contracts reclassified to income, net of tax of $10, $10, $21, and $21, respectively | | | 18 | | | | 17 | | | | 35 | | | | 34 | |
Change in deferred hedge loss on interest rate swaps, net of tax of $8 and $18, respectively | | | — | | | | (60 | ) | | | — | | | | (87 | ) |
| | | | | | | | | | | | |
Consolidated comprehensive income | | | 252,125 | | | | 150,286 | | | | 242,115 | | | | 250,480 | |
Less: comprehensive income attributable to noncontrolling interest | | | — | | | | (14,950 | ) | | | — | | | | (18,235 | ) |
| | | | | | | | | | | | |
Comprehensive income attributable to Denbury stockholders | | $ | 252,125 | | | $ | 135,336 | | | $ | 242,115 | | | $ | 232,245 | |
| | | | | | | | | | | | |
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.Statements
6
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 1. Basis of Presentation
Organization and Nature of Operations
We are a growing independent oil and natural gas company. We are the largest oil and natural gas producer in both Mississippi and Montana, own the largest reserves of CO2 used for tertiary oil recovery east of the Mississippi River, and hold significant operating acreage in the Rocky Mountain and Gulf Coast regions. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with our most significant emphasis on our CO2 tertiary recovery operations.
Interim Financial Statements
The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by accounting principles generally acceptedAccounting Principles Generally Accepted in the United States (“U.S. GAAP”) for complete financial statements. 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, 2010. Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.
Accounting measurements at interim dates inherently involve greater reliance on estimates than at year endyear-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 year. In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of March 31,June 30, 2011, our consolidated results of operations for the three and six months ended March 31,June 30, 2011 and 2010, and our consolidated cash flows for the threesix months ended March 31,June 30, 2011 and 2010. Certain prior period items have been reclassified to make the classification consistent with the classification in the most recent quarter.
Noncontrolling Interest
From March 9, 2010 throughto December 31, 2010, we owned approximately 46% of Encore Energy Partners LP (“ENP”) outstanding common units and 100% of Encore Energy Partners GP LLC (“GP LLC”), which was ENP’s general partner. Considering the presumption of control of GP LLC in accordance with theConsolidationtopic of the Financial Accounting Standards Board Codification (“FASC”), the results of operations and cash flows of ENP were consolidated with those of Denbury for this period. On December 31, 2010, we sold all of our ownership interests in ENP and, therefore, we havedid not consolidatedconsolidate ENP in our Unaudited Condensed Consolidated Balance Sheets as of December 31, 2010 and June 30, 2011, nor do our Unaudited Condensed Consolidated StatementStatements of Operations for the three and six months ended June 30, 2011 or our Unaudited Condensed Consolidated Statement of Cash Flows for the threesix months ended March 31,June 30, 2011 include ENP’s results of operations or cash flows. As presented in the Unaudited Condensed Consolidated StatementStatements of Operations for the three and six months ended March 31,June 30, 2010, “Net income attributable to noncontrolling interest” of $3.3$15.0 million and $18.3 million, respectively, represents ENP’s results of operations attributable to third-party ENP limited partner interest owners, other than Denbury, for the portion of that period for which we consolidated ENP.
Net Income Per Common Share
Basic net income per common share is computed by dividing net income attributable to our stockholders 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 of the potential dilution from stock options, stock appreciation rights (“SARs”), unvested restricted stock, and unvested performance equity awards. For the three and six months ended March 31,June 30, 2011 and 2010, there were no adjustments to net income attributable to our stockholders 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 periods indicated:
7
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
| | | | | | | | | |
| | Three Months Ended | | | | | | | | | | | | | | | | | |
| | March 31, | | | Three Months Ended | | Six Months Ended | |
| | June 30, | | June 30, | |
In thousands | | 2011 | | | 2010 | | | 2011 | | 2010 | | 2011 | | 2010 | |
| | |
Basic weighted average common shares | | 397,386 | | 294,143 | | | 398,631 | | 395,548 | | 398,032 | | 345,126 | |
Potentially dilutive securities: | | |
Stock options and SARs | | - | | 3,690 | | | 3,946 | | 3,980 | | 4,251 | | 3,835 | |
Performance equity awards | | - | | 477 | | | 23 | | 146 | | 12 | | 312 | |
Restricted stock | | - | | 914 | | | 1,319 | | 1,193 | | 1,408 | | 1,053 | |
| | | | | | | | | | | | | |
Diluted weighted average common shares | | 397,386 | | 299,224 | | | 403,919 | | 400,867 | | 403,703 | | 350,326 | |
| | | | | | | | | | | | | |
Basic weighted average common shares excludes 3.4 million and 3.6 million shares for the three and six months ended ended June 30, 2011, respectively, and 3.5 million shares and 3.43.3 million shares at March 31, 2011for the three and six months ended June 30, 2010, respectively, of unvested restricted stock. As these restricted shares vest or become retirement eligible, they will be included in the shares outstanding used to calculate basic net income per common share, although all restricted stock is issued and outstanding upon grant. For purposes of calculating diluted weighted average common shares, unvested restricted stock is included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, adjusted for any estimated future tax consequences recognized directly in equity.
The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income per share as their effect would have been anti-dilutive:
| | | | | | | | | |
| | Three Months Ended | | |
| | | | | | | | | | | | | | | | |
| | March 31, | | | Three Months Ended | | Six Months Ended | |
| | June 30, | | June 30, | |
In thousands | | 2011 | | 2010 | | | 2011 | | 2010 | | 2011 | | 2010 | |
| | |
Stock options and SARs | | 12,641 | | 5,465 | | | 2,412 | | 4,223 | | 2,297 | | 4,785 | |
Restricted stock | | 3,453 | | 1,371 | | | 24 | | 35 | | 15 | | 413 | |
Short-term Investments
Short-term investments are available-for-sale securities recorded at fair value with any unrealized gains or losses included in accumulated other comprehensive income. At March 31,June 30, 2011 and December 31, 2010, short-term investments consisted entirely of our investment in Vanguard Natural Resources LLC (“Vanguard”) common units obtained as partial consideration for the sale of our interests in ENP to a subsidiary of Vanguard on December 31, 2010. The cost basis of this investment is $93.0 million, and under the terms of the sale agreement with Vanguard we are restricted from divesting these Vanguard common units until July 31, 2011. In the first quarter of 2011 wemillion. We received distributions of $1.8$1.7 million and $3.5 million on the Vanguard common units we own for the three and six months ended June 30, 2011, respectively, which distributions are included in “Interest income and other income” on our Unaudited Condensed Consolidated StatementStatements of Operations for the three months ended March 31, 2011.Operations. The unrealized gainloss on our short-term investment of $4.2$7.1 million net(net of taxesa tax benefit of $2.6$4.4 million) and $3.0 million (net of a tax benefit of $1.8 million) for the three and six months ended June 30, 2011, respectively, is included in our Unaudited Condensed Consolidated StatementStatements of Comprehensive Operations for the three months ended March 31, 2011.Operations.
Recently AdoptedIssued Accounting Pronouncements
We have reviewed recentlyIn May 2011, the Financial Accounting Standards Board (“FASB”) issued accounting pronouncements that becameAccounting Standards Update (“ASU”) 2011-04,Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs, (“ASU 2011-04”). ASU 2011-04 amends the FASCFair Value Measurementstopic by providing a consistent definition and measurement of fair value, as well as similar disclosure requirements between U.S. GAAP and International Financial Reporting Standards. ASU 2011-04 changes certain fair value measurement principles, clarifies the application of existing fair value measurements and expands the fair value disclosure requirements, particularly for Level 3 fair value measurements. ASU 2011-04 will be effective during the three months ended March 31, 2011, and have determined that none wouldfor our fiscal year beginning January 1, 2012. The adoption of ASU 2011-04 is not expected to have a material impacteffect on our consolidated financial statements, but may require additional disclosures.
8
DENBURY RESOURCES INC.
Notes to our Unaudited Condensed Consolidated Financial Statements.Statements
In June 2011, the FASB issued ASU 2011-05,Presentation of Comprehensive Income, (“ASU 2011-05”). ASU 2011-05 requires the presentation of comprehensive income in either 1) a continuous statement of comprehensive income or 2) two separate but consecutive statements. ASU 2011-05 will be effective for our fiscal year beginning January 1, 2012. Since ASU 2011-05 will only amend presentation requirements, it will not have a material effect on our consolidated financial statements.
9
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 2. Acquisitions and Divestitures
2010 Merger with Encore Acquisition Company
On March 9, 2010, we acquired Encore Acquisition Company (“Encore”) pursuant to the Encore Merger Agreement entered into with Encore on October 31, 2009. The Encore Merger Agreement provided for a stock and cash transaction valued at approximately $4.8 billion at the acquisition date, including the assumption of debt and the value of the noncontrolling interest in ENP (the “Encore Merger”). Under the Encore Merger Agreement, Encore was merged with and into Denbury, with Denbury surviving the Encore Merger.
8
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
For the three months ended June 30, 2010 and for the period from the March 9, 2010 Encore acquisition date to March 31,June 30, 2010, we recognized $59.7$200.6 million and $43.9$260.9 million, respectively, of oil, natural gas sales and related product sales related to the Encore Merger. For the three months ended June 30, 2010 and for the period from March 9, 2010 to June 30, 2010, we recognized $137.8 million and $180.7 million, respectively, of net field operating income (oil, natural gas and related product sales less lease operating expenses, and production taxes and marketing expenses), respectively, related to the Encore Merger. We recognized a total of $2.4$2.0 million and $45.0$22.8 million of transaction and other costs related to the Encore Merger (primarily advisory, legal, accounting, due diligence, integration and severance costs) for the three months ended March 31,June 30, 2011 and 2010, respectively, and $4.4 million and $67.8 million of such costs for the six months ended June 30, 2011 and 2010, respectively.
2010 Acquisition of Reserves in Rocky Mountain Region at Riley Ridge
In October 2010, we acquired a 42.5% non-operated working interest in the Riley Ridge Federal Unit (“Riley Ridge”), located in the LaBarge Field of southwestern Wyoming, for $132.3 million after preliminary closing adjustments. Riley Ridge contains natural gas resources, as well as helium and CO2 resources. The purchase includesincluded a working interest in a gas plant, which is currently under construction, which will separate the helium and natural gas from the commingled gas stream. The acquisition also includesincluded approximately 33% of the CO2 mineral rights in an additional 28,000 acres adjoining the Riley Ridge Unit. We own a non-operating interest in those 28,000 acres.
TheThis acquisition of Riley Ridge meets the definition of a business under the FASCBusiness Combinationstopic. The purchase price allocation for the acquisition of interests in Riley Ridge Field is preliminary and subject to revision pending finalization of closing adjustments. The following table presents a summary of the preliminary fair value of these Riley Ridge assets acquired:acquired and liabilities assumed:
| | | | |
In thousands | | |
| | | | |
Oil and natural gas properties | | $ | 19,646 | |
CO2 and other non-hydrocarbon gases - properties and pipelines (CO2 properties)
| | | 10,907 | |
CO2 and other non-hydrocarbon gases - properties and pipelines (Riley Ridge plant)
| | | 72,070 | |
Prepaid construction and drilling costs | | | 9,346 | |
Other assets | | | 19,300 | |
Asset retirement obligations | | | (472 | ) |
Goodwill | | | 1,460 | |
| | |
Total | | $ | 132,257 | |
| | |
| | | | |
In thousands | | | | |
Oil and natural gas properties | | $ | 19,646 | |
CO2 and other non-hydrocarbon gases properties | | | 10,907 | |
Pipelines and plants | | | 72,070 | |
Prepaid construction and drilling costs | | | 9,346 | |
Other assets | | | 19,300 | |
Asset retirement obligations | | | (472 | ) |
Goodwill | | | 1,460 | |
| | | |
Total | | $ | 132,257 | |
| | | |
On August 1, 2011, we acquired the remaining working interest in Riley Ridge and an additional interest in the adjoining acreage and became the operator of both projects; see Note 8,Subsequent Event, for more information.
Pro Forma Information
Had the Encore Merger and October 2010 Riley Ridge acquisition both occurred on January 1, 2010, our combined pro forma revenuerevenues and net income for the three and six months ended March 31,June 30, 2010, would have been as follows:
10
| | | | |
In thousands, except per share amounts | | |
| | | | |
Pro forma total revenues | | $ | 615,271 | |
Pro forma net income attributable to Denbury stockholders | | | 112,489 | |
Pro forma net income per common share: | | | | |
Basic | | $ | 0.28 | |
Diluted | | | 0.28 | |
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
| | | | | | | | |
| | Pro Forma Results | |
| | Three Months Ended | | | Six Months Ended | |
In thousands, except per share amounts | | June 30, 2010 | | | June 30, 2010 | |
Pro forma total revenues | | $ | 497,210 | | | $ | 1,112,481 | |
Pro forma net income attributable to Denbury stockholders | | | 135,494 | | | | 247,423 | |
Pro forma net income per common share: | | | | | | | | |
Basic | | $ | 0.34 | | | $ | 0.63 | |
Diluted | | | 0.34 | | | | 0.62 | |
2010 Sale of Interests in Genesis
In February 2010, we sold our interest in Genesis Energy, LLC, the general partner of Genesis Energy, L.P. (“Genesis”), for net proceeds of approximately $84 million. In March 2010, we sold all of our Genesis common units in a secondary public offering for net proceeds of approximately $79 million. We recognized a pre-tax gain of approximately $101.5 million ($63.0 million after tax) on these dispositions.
9
DENBURY RESOURCES INC.2010 Sale of Southern Assets
Notes In May 2010, we sold certain non-strategic legacy Encore properties primarily located in the Permian Basin, the Mid-continent area and the East Texas Basin (the “Southern Assets”) to Unaudited Condensed Consolidated Financial StatementsQuantum Resources Management, LLC for consideration of $892.1 million after closing adjustments. We did not record a gain or loss on the sale in accordance with the full cost method of accounting.
Note 3. Long-Term Debt
The following table shows the components of our long-term debt:
| | | | | | | | |
| | June 30, | | | December 31, | |
In thousands | | 2011 | | | 2010 | |
Bank Credit Agreement | | $ | — | | | $ | — | |
71/2% Senior Subordinated Notes due 2013, including discount of $437 | | | — | | | | 224,563 | |
71/2% Senior Subordinated Notes due 2015, including premium of $427 | | | — | | | | 300,427 | |
91/2% Senior Subordinated Notes due 2016, including premium of $13,222 and $14,589, respectively | | | 238,142 | | | | 239,509 | |
93/4% Senior Subordinated Notes due 2016, including discount of $19,996 and $22,139, respectively | | | 406,354 | | | | 404,211 | |
81/4% Senior Subordinated Notes due 2020 | | | 996,273 | | | | 996,273 | |
6⅜% Senior Subordinated Notes due 2021 | | | 400,000 | | | | — | |
Other Subordinated Notes, including premium of $37 and $41, respectively | | | 3,842 | | | | 3,848 | |
NEJD financing | | | 165,550 | | | | 167,331 | |
Free State financing | | | 80,953 | | | | 81,188 | |
Capital lease obligations | | | 5,620 | | | | 6,806 | |
| | | | | | |
Total | | | 2,296,734 | | | | 2,424,156 | |
Less current obligations | | | (8,622 | ) | | | (7,948 | ) |
| | | | | | |
Long-term debt and capital lease obligations | | $ | 2,288,112 | | | $ | 2,416,208 | |
| | | | | | |
The parent company, Denbury Resources Inc. (“DRI”), is the sole issuer of all of our outstanding senior subordinated notes. DRI has no independent assets or operations. All of our 100% owned subsidiaries, other than minor subsidiaries, fully and unconditionally guarantee our senior subordinated debt as of the periods indicated:jointly and severally.
| | | | | | | | |
| | March 31, | | | December 31, | |
|
In thousands | | 2011 | | | 2010 | |
| | | | | | | | |
Bank Credit Agreement | | $ | - | | | $ | - | |
|
71/2% Senior Subordinated Notes due 2013, including discount of $96 and $437, respectively (1) | | | 55,352 | | | | 224,563 | |
|
71/2% Senior Subordinated Notes due 2015, including premium of $427 | | | - | | | | 300,427 | |
91/2% Senior Subordinated Notes due 2016, including premium of $13,906 and $14,589, respectively | | | 238,826 | | | | 239,509 | |
|
93/4% Senior Subordinated Notes due 2016, including discount of $21,067 and $22,139, respectively | | | 405,283 | | | | 404,211 | |
|
81/4% Senior Subordinated Notes due 2020 | | | 996,273 | | | | 996,273 | |
|
63/8% Senior Subordinated Notes due 2021 | | | 400,000 | | | | - | |
|
Other Subordinated Notes, including premium of $39 and $41, respectively | | | 3,845 | | | | 3,848 | |
|
NEJD financing | | | 166,452 | | | | 167,331 | |
|
Free State financing | | | 80,979 | | | | 81,188 | |
|
Capital lease obligations | | | 6,217 | | | | 6,806 | |
| | | | |
|
Total | | | 2,353,227 | | | | 2,424,156 | |
|
Less current obligations | | | 8,446 | | | | 7,948 | |
| | | | |
|
Long-term debt and capital lease obligations | | $ | 2,344,781 | | | $ | 2,416,208 | |
| | | | |
| | |
(1) | | These notes were repurchased on April 1, 2011. |
Bank Credit Agreement
OnIn March 9, 2010, we entered into a $1.6 billion revolving credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and 23 other lenders as party thereto (the “Bank Credit Agreement”) with a maturity date of March 2014.. Availability under the Bank Credit Agreement is subject to a borrowing base (currently $1.6 billion) which is re-determinedredetermined semi-annually on or prior to May 1 and November 1 and upon requested special redeterminations. We expect our semi-annual redetermination to be finalized in mid-May 2011. We currently do not anticipate any reduction in our borrowing base as a result of this redetermination.
The borrowing base is adjusted at the banks’ discretion and is based in part upon external factors over which we have no control. If the borrowing base were to be less than outstanding borrowings under the Bank Credit Agreement, we would be required to repay the deficit over a period of four months. We incur
11
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
In May 2011, we entered into the Fifth Amendment to the Bank Credit Agreement (the “Amendment”). The Amendment reconfirms our current borrowing base of $1.6 billion, extends the maturity of the Bank Credit Agreement from March 2014 to May 2016, reduces the applicable margin on outstanding borrowings, reduces the letter of credit fee and adjusts the maximum permitted ratio of debt to adjusted EBITDA. Under the Amendment, the margin on outstanding Eurodollar loans bears interest at the Eurodollar rate (as defined in the Bank Credit Agreement) plus the applicable margin of 1.5% to 2.5% (previously 2.0% to 3.0%) based on the ratio of outstanding borrowings to the borrowing base, and the base rate loans bear interest at the base rate (as defined in the Bank Credit Agreement) plus the applicable margin of 0.5% to 1.5% (previously 1.0% to 1.5%) based on the ratio of outstanding borrowings to the borrowing base. The Amendment also prescribes a commitment fee ofranging between 0.375% and 0.5% on the unused portion of the credit facility or if less, the borrowing base. Loans underbase, and adjusts the Bank Credit Agreement mature in March 2014. We had no borrowings outstanding on the Bank Credit Agreement asmaximum permitted ratio of March 31, 2011.debt to adjusted EBITDA of Denbury and its subsidiaries from 4.0x to 4.25x.
63/86⅜% Senior Subordinated Notes due 2021
In February 2011, we issued $400 million of 63/86⅜% Senior Subordinated Notes due 2021 (“2021 Notes”). The 2021 Notes, which carry a coupon rate of 6.375%, were sold at par. The net proceeds of approximately $393 million were used to repurchase a portion of our outstanding 2013 Notes and 2015 Notes (seeRedemption of our 2013 and 2015 Notesbelow).
10
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
The 2021 Notes mature on August 15, 2021, and interest is payable on February 15 and August 15 of each year, beginning August 15, 2011. We may redeem the 2021 Notes in whole or in part at our option beginning August 15, 2016 at the following redemption prices: 103.188% on or after August 15, 2016; 102.125% on or after August 15, 2017; 101.062% on or after August 15, 2018; and 100% on or after August 15, 2019. Prior to August 15, 2014, we may, at our option, redeem up to an aggregate of 35% of the principal amount of the 2021 Notes at a price of 106.375% with the proceeds of certain equity offerings. In addition, at any time prior to August 15, 2016, we may redeem 100% of the principal amount of the 2021 Notes at a price equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest. The indenture contains certain restrictions on our ability to incur additional debt, pay dividends on our common stock, make investments, create liens on our assets, engage in transactions with our affiliates, transfer or sell assets, consolidate or merge, or sell substantially all of our assets. The 2021 Notes are not subject to any sinking fund requirements. All of our subsidiaries, other than minor subsidiaries, fully and unconditionally guarantee this debt jointly and severally.
Redemption of our 2013 and 2015 Notes
On February 3, 2011, we commenced cash tender offers to purchase $225all $225.0 million principal amount of our 2013 Notes and $300all $300.0 million principal amount of our 2015 Notes. By March 3, 2011, uponUpon expiration of the tender offers on March 3, 2011, we accepted for purchase $169.6 million in principal of the 2013 Notes at 100.625% of par, and $220.9 million in principal of the 2015 Notes forat 104.125% of par. We called the remaining 2013 and 2015 Notes, repurchasing all of the remaining outstanding 2015 Notes ($79.1 million) at 103.75% of par on March 21, 2011 and repurchasing all of the remaining outstanding 2013 Notes ($55.4 million) at par on April 1, 2011. During the first quarter of 2011, weWe recognized a $15.8$0.3 million and $16.1 million loss during the three and six months ended June 30, 2011 associated with the first quarter of 2011 debt repurchases, which is included in our income statementUnaudited Condensed Consolidated Statements of Operations under the caption “Loss on early extinguishment of debt”.
Note 4. Derivative Instruments and Hedging Activities
Oil and Natural Gas Derivative Contracts
We do not apply hedge accounting treatment to our oil and natural gas derivative contracts, and therefore the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the cash settlements of expired contracts are shown under “Derivatives expense (income)” in our Unaudited Condensed Consolidated Statements of Operations.
12
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
From time to time, we enter into various oil and natural gas derivative contracts to provide an economic hedge of 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 consisted of price floors, collars and fixed price swaps. The production that we hedge has varied from year to year depending on our levels of debt and financial strength and expectation of future commodity prices. We currently employ a strategy to hedge a portion of our forecasted production for a period generally ranging from approximately 12 to 18 months in advance, as we believe it is important to protect our future cash flow to provide a level of assurance for our capital spending in those future periods in light of current worldwide economic uncertainties.uncertainties and commodity price volatility.
We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures, and diversification. All of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement.
11
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
The following is a summary of “Derivatives expense (income)” included in the accompanying Unaudited Condensed Consolidated Statements of Operations for the periods indicated:
| | | | | | | | |
| | Three Months Ended |
|
| | March 31, |
In thousands | | 2011 | | 2010 |
Oil | | | | | | | | |
Payment on settlements of derivative contracts | | $ | 5,028 | | | $ | 63,550 | |
Fair value adjustments to derivative contracts - expense (income) | | | 167,064 | | | | (61,821 | ) |
| | | | | | |
Total derivative expense - oil | | | 172,092 | | | | 1,729 | |
Natural Gas | | | | | | | | |
Receipt on settlements of derivative contracts | | | (6,616 | ) | | | (3,749 | ) |
Fair value adjustments to derivative contracts - expense (income) | | | 5,274 | | | | (39,018 | ) |
| | | | | | |
Total derivative income - natural gas | | | (1,342 | ) | | | (42,767 | ) |
Ineffectiveness on interest rate swaps | | | - | | | | (187 | ) |
| | | | | | |
Derivative expense (income) | | $ | 170,750 | | | $ | (41,225 | ) |
| | | | | | |
12
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Fair Value of Commodity Derivative Contracts Not Classified as Hedging Instruments
The following tables present the fair value of our commodity derivative contracts:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Estimated Fair Value |
| | |
| | | | | | | | | | NYMEX Contract Prices Per Bbl | | Asset (Liability) |
| | |
| | | | Type of | | | | | | Weighted Average Price | | March 31, | | December 31, |
| | |
Year | | Months | | Contract | | Bbls/d | | Swap | | Floor | | Ceiling | | 2011 | | 2010 |
| | | | | | | | | | | | | | | | | | | | | | (In thousands) |
Oil Contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2011 | | Jan - Mar | | Swap | | | 625 | | | $ | 79.18 | | | $ | - | | | $ | - | | | $ | - | | | $ | (737 | ) |
| | | | Collar | | | 43,500 | | | | - | | | | 67.25 | | | | 95.80 | | | | - | | | | (3,656 | ) |
| | | | Put | | | 6,625 | | | | - | | | | 69.53 | | | | - | | | | - | | | | 79 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Total Jan - Mar 2011
| | | 50,750 | | | | | | | | | | | | | | | | - | | | | (4,314 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Apr - June | | Swap | | | 625 | | | | 79.18 | | | | - | | | | - | | | | (1,593 | ) | | | (827 | ) |
| | | | Collar | | | 43,500 | | | | - | | | | 70.34 | | | | 100.20 | | | | (34,918 | ) | | | (12,113 | ) |
| | | | Put | | | 6,625 | | | | - | | | | 69.53 | | | | - | | | | 16 | | | | 499 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Total Apr - June 2011
| | | 50,750 | | | | | | | | | | | | | | | | (36,495 | ) | | | (12,441 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | July - Sept | | Swap | | | 625 | | | | 79.18 | | | | - | | | | - | | | | (1,656 | ) | | | (865 | ) |
| | | | Collar | | | 42,500 | | | | - | | | | 70.35 | | | | 100.09 | | | | (48,434 | ) | | | (17,308 | ) |
| | | | Put | | | 6,625 | | | | - | | | | 69.53 | | | | - | | | | 170 | | | | 1,026 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Total July - Sept 2011
| | | 49,750 | | | | | | | | | | | | | | | | (49,920 | ) | | | (17,147 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Oct - Dec | | Swap | | | 625 | | | | 79.18 | | | | - | | | | - | | | | (1,658 | ) | | | (871 | ) |
| | | | Collar | | | 45,500 | | | | - | | | | 70.33 | | | | 101.74 | | | | (53,941 | ) | | | (18,878 | ) |
| | | | Put | | | 6,625 | | | | - | | | | 69.53 | | | | - | | | | 477 | | | | 1,445 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Total Oct - Dec 2011
| | | 52,750 | | | | | | | | | | | | | | | | (55,122 | ) | | | (18,304 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2012 | | Jan - Mar | | Swap | | | 625 | | | | 81.04 | | | | - | | | | - | | | | (1,502 | ) | | | (741 | ) |
| | | | Collar | | | 52,000 | | | | - | | | | 70.00 | | | | 106.86 | | | | (55,070 | ) | | | (19,065 | ) |
| | | | Put | | | 625 | | | | - | | | | 65.00 | | | | - | | | | 51 | | | | 123 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Total Jan - Mar 2012
| | | 53,250 | | | | | | | | | | | | | | | | (56,521 | ) | | | (19,683 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Apr-June | | Swap | | | 625 | | | | 81.04 | | | | - | | | | - | | | | (1,450 | ) | | | (726 | ) |
| | | | Collar | | | 53,000 | | | | - | | | | 70.00 | | | | 119.44 | | | | (29,230 | ) | | | (3,288 | ) |
| | | | Put | | | 625 | | | | - | | | | 65.00 | | | | - | | | | 78 | | | | 151 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Total Apr - June 2012
| | | 54,250 | | | | | | | | | | | | | | | | (30,602 | ) | | | (3,863 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | July-Sept | | Swap | | | 625 | | | | 81.04 | | | | - | | | | - | | | | (1,402 | ) | | | (719 | ) |
| | | | Collar | | | 48,000 | | | | - | | | | 80.00 | | | | 127.70 | | | | (6,663 | ) | | | - | |
| | | | Put | | | 625 | | | | - | | | | 65.00 | | | | - | | | | 103 | | | | 178 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Total July - Sept 2012
| | | 49,250 | | | | | | | | | | | | | | | | (7,962 | ) | | | (541 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Oct - Dec | | Swap | | | 625 | | | | 81.04 | | | | - | | | | - | | | | (1,356 | ) | | | (709 | ) |
| | | | Collar | | | 48,000 | | | | - | | | | 80.00 | | | | 127.70 | | | | (6,014 | ) | | | - | |
| | | | Put | | | 625 | | | | - | | | | 65.00 | | | | - | | | | 117 | | | | 191 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Total Oct - Dec 2012
| | | 49,250 | | | | | | | | | | | | | | | | (7,253 | ) | | | (518 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Total Oil Contracts
| | $ | (243,875 | ) | | $ | (76,811 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Six Months Ended | |
| | June 30, | | | June 30, | |
In thousands | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
Oil | | | | | | | | | | | | | | | | |
Payment on settlements of derivative contracts | | $ | 16,972 | | | $ | 13,829 | | | $ | 22,000 | | | $ | 77,379 | |
Fair value adjustments to derivative contracts — expense (income) | | | (187,194 | ) | | | (145,099 | ) | | | (20,130 | ) | | | (206,920 | ) |
| | | | | | | | | | | | |
Total derivative expense (income) — oil | | | (170,222 | ) | | | (131,270 | ) | | | 1,870 | | | | (129,541 | ) |
Natural Gas | | | | | | | | | | | | | | | | |
Receipt on settlements of derivative contracts | | | (6,030 | ) | | | (16,630 | ) | | | (12,646 | ) | | | (20,379 | ) |
Fair value adjustments to derivative contracts — expense (income) | | | 3,348 | | | | 19,909 | | | | 8,622 | | | | (19,109 | ) |
| | | | | | | | | | | | |
Total derivative expense (income) — natural gas | | | (2,682 | ) | | | 3,279 | | | | (4,024 | ) | | | (39,488 | ) |
Ineffectiveness on interest rate swaps | | | — | | | | (683 | ) | | | — | | | | (870 | ) |
| | | | | | | | | | | | |
Derivative income | | $ | (172,904 | ) | | $ | (128,674 | ) | | $ | (2,154 | ) | | $ | (169,899 | ) |
| | | | | | | | | | | | |
13
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Estimated Fair Value |
| | |
| | | | | | | | | | Contract Prices Per MMBtu | | Asset (Liability) |
| | |
| | | | Type of | | | | | | Weighted Average Price | | March 31, | | December 31, |
| | |
Year | | Months | | Contract | | MMBtu/d | | Swap | | Floor | | Ceiling | | 2011 | | 2010 |
| | | | | | | | | | | | | | | | | | | | | | (In thousands) |
Natural Gas Contracts: | | | | | | | | | | | | | | | | | | | | | | | | | |
2011 | | Jan - Mar | | Swap | | | 33,500 | | | $ | 6.27 | | | $ | - | | | $ | - | | | $ | - | | | $ | 5,846 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Total Jan-Mar 2011
| | | 33,500 | | | | | | | | | | | | | | | | - | | | | 5,846 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Apr-Jun | | Swap | | | 33,500 | | | | 6.27 | | | | - | | | | - | | | | 5,841 | | | | 5,637 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Total Apr-June 2011
| | | 33,500 | | | | | | | | | | | | | | | | 5,841 | | | | 5,637 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | July - Sept | | Swap | | | 33,500 | | | | 6.27 | | | | - | | | | - | | | | 5,327 | | | | 5,300 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Total July-Sept 2011
| | | 33,500 | | | | | | | | | | | | | | | | 5,327 | | | | 5,300 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Oct - Dec | | Swap | | | 33,500 | | | | 6.27 | | | | - | | | | - | | | | 4,615 | | | | 4,409 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Total Oct - Dec 2011
| | | 33,500 | | | | | | | | | | | | | | | | 4,615 | | | | 4,409 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2012 | | Jan - Dec | | Swap | | | 20,000 | | | | 6.53 | | | | - | | | | - | | | | 11,753 | | | | 11,618 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Total Jan - Dec 2012
| | | 20,000 | | | | | | | | | | | | | | | | 11,753 | | | | 11,618 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Total Natural Gas Contracts
| | | 27,536 | | | | 32,810 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total Commodity Derivative Contracts
| | $ | (216,339 | ) | | $ | (44,001 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Commodity Derivative Contracts Not Classified as Hedging Instruments AsThe following tables present outstanding commodity derivative contracts with respect to future production as of March 31, 2011 and December 31, 2010, we had $21.2 million and $26.7 million, respectively, of deferred premiums payable, which relate to various oil and natural gas floor contracts and are payable on a monthly basis from April 2011 to January 2013. These premiums are excluded from the above tables.June 30, 2011:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | NYMEX Contract Prices Per Bbl | |
| | | | | | Type of | | | | | | | | | | | Weighted Average Price | | | | |
Year | | Months | | | Contract | | | Bbls/d | | | Swap | | | Floor | | | Ceiling | |
Oil Contracts | | | | | | | | | | | | | | | | | | | | | | | | |
2011 | | July - Sept | | Swap | | | 625 | | | | 79.18 | | | | — | | | | — | |
| | | | | | Collar | | | 42,500 | | | | — | | | | 70.35 | | | | 100.09 | |
| | | | | | Put | | | 6,625 | | | | — | | | | 69.53 | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Total July - Sept 2011 | | | 49,750 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Oct - Dec | | Swap | | | 625 | | | | 79.18 | | | | — | | | | — | |
| | | | | | Collar | | | 45,500 | | | | — | | | | 70.33 | | | | 101.74 | |
| | | | | | Put | | | 6,625 | | | | — | | | | 69.53 | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Total Oct - Dec 2011 | | | 52,750 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
2012 | | Jan - Mar | | Swap | | | 625 | | | | 81.04 | | | | — | | | | — | |
| | | | | | Collar | | | 52,000 | | | | — | | | | 70.00 | | | | 106.86 | |
| | | | | | Put | | | 625 | | | | — | | | | 65.00 | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Total Jan - Mar 2012 | | | 53,250 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Apr-June | | Swap | | | 625 | | | | 81.04 | | | | — | | | | — | |
| | | | | | Collar | | | 53,000 | | | | — | | | | 70.00 | | | | 119.44 | |
| | | | | | Put | | | 625 | | | | — | | | | 65.00 | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Total Apr - June 2012 | | | 54,250 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | July-Sept | | Swap | | | 625 | | | | 81.04 | | | | — | | | | — | |
| | | | | | Collar | | | 53,000 | | | | — | | | | 80.00 | | | | 128.57 | |
| | | | | | Put | | | 625 | | | | — | | | | 65.00 | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Total July - Sept 2012 | | | 54,250 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Oct - Dec | | Swap | | | 625 | | | | 81.04 | | | | — | | | | — | |
| | | | | | Collar | | | 53,000 | | | | — | | | | 80.00 | | | | 128.57 | |
| | | | | | Put | | | 625 | | | | — | | | | 65.00 | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Total Oct - Dec 2012 | | | 54,250 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
14
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
| | | | | | | | | | | | | | | | |
| | | | | | Type of | | | | | | | Weighted Average Swap | |
Year | | Months | | | Contract | | | MMBtu/d | | | Price per MMBtu | |
Natural Gas Contracts | | | | | | | | | | | | | | | | |
2011 | | July - Sept | | Swap | | | 33,500 | | | $ | 6.27 | |
| | | | | | | | | | | | | | | |
| | | | | | Total July-Sept 2011 | | | 33,500 | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | Oct - Dec | | Swap | | | 33,500 | | | | 6.27 | |
| | | | | | | | | | | | | | | |
| | | | | | Total Oct - Dec 2011 | | | 33,500 | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
2012 | | Jan - Dec | | Swap | | | 20,000 | | | | 6.53 | |
| | | | | | | | | | | | | | | |
| | | | | | Total Jan - Dec 2012 | | | 20,000 | | | | | |
| | | | | | | | | | | | | | | |
Additional Disclosures about Derivative Instruments
At March 31,June 30, 2011 and December 31, 2010, we had derivative financial instruments recorded in our Unaudited Condensed Consolidated Balance Sheets as follows:
| | | | | | | | | | | | | | | | | | | |
| | Estimated Fair Value | | Estimated Fair Value | |
| | Asset (Liability) | | Asset (Liability) | |
| | March 31, | December 31, | | | June 30, | | December 31, | |
Type of Contract | | Balance Sheet Location | | 2011 | 2010 | | | Balance Sheet Location | | 2011 | | 2010 | |
| | (In thousands) | | | (In thousands) | |
Derivatives not designated as hedging instruments: | | | | |
Derivative asset: | | | | |
Derivatives not designated as hedging instruments | | |
Derivative asset | | |
Oil contracts | | Derivative assets - current | | $ | 714 | | $ | | 3,050 | | | Derivative assets — current | | $ | 1,462 | | $ | 3,050 | |
Natural gas contracts | | Derivative assets - current | | 18,631 | | 21,192 | | | Derivative assets — current | | 17,860 | | 21,192 | |
Oil contracts | | Derivative assets - long-term | | 298 | | 1,301 | | | Derivative assets — long-term | | 11,281 | | 1,301 | |
Natural gas contracts | | Derivative assets - long-term | | 8,905 | | 11,618 | | | Derivative assets — long-term | | 6,328 | | 11,618 | |
| | | | |
Derivative liability: | | | | |
Derivative liability | | |
Oil contracts | | Derivative liabilities - current | | | (198,772) | | | | (55,256) | | | Derivative liabilities — current | | | (67,196 | ) | | | (55,256 | ) |
Deferred premiums | | Derivative liabilities - current | | | (19,569) | | | | (22,928) | | | Derivative liabilities — current | | | (14,431 | ) | | | (22,928 | ) |
Oil contracts | | Derivative liabilities - long-term | | | (46,115) | | | | (25,906) | | | Derivative liabilities — long-term | | | (2,228 | ) | | | (25,906 | ) |
Deferred premiums | | Derivative liabilities - long-term | | | (1,630) | | | | (3,781) | | | Derivative liabilities — long-term | | | (1,150 | ) | | | (3,781 | ) |
| | | | | | | | | | | | | |
Total derivatives not designated as hedging instruments | | | | $ | (237,538) | | $ | | (70,710) | | | $ | (48,074 | ) | | $ | (70,710 | ) |
| | | | | | | | | | | | | |
Note 5. Fair Value Measurements
Fair Value Hierarchy
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:
15
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
| • | | Level 1 -— Quoted prices in active markets for identical assets or liabilities as of the reporting date. |
|
| • | | Level 2 -— Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded oil and natural gas derivatives that are based on NYMEX pricing. |
|
| • | | Level 3 -— Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Instruments in this category include non-exchange-traded natural gas derivatives swaps that are based on regional pricing other than NYMEX (i.e.(e.g., Houston Ship Channel). |
15
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and Denbury’s credit quality for liability positions. Denbury usesWe use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.
The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of the periods indicated:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using: | | | Fair Value Measurements Using: | |
| | Significant | | | | | | | Significant | | | | | |
| | Quoted Prices | | Other | | Significant | | | | | Quoted Prices | | Other | | Significant | | | |
| | in Active | | Observable | | Unobservable | | | | | in Active | | Observable | | Unobservable | | | |
| | Markets | | Inputs | | Inputs | | | | | Markets | | Inputs | | Inputs | | | |
In thousands | | (Level 1) | | (Level 2) | | (Level 3) | | Total | | | (Level 1) | | (Level 2) | | (Level 3) | | Total | |
March 31, 2011 | | |
Assets: | | |
June 30, 2011 | | |
Assets | | |
Short-term investments | | $ | 99,733 | | $ | - | | $ | - | | $ | 99,733 | | | $ | 88,220 | | $ | — | | $ | — | | $ | 88,220 | |
Oil and natural gas derivative contracts | | - | | 13,202 | | 15,346 | | 28,548 | | | — | | 30,293 | | 6,638 | | 36,931 | |
Liabilities: | | |
Liabilities | | |
Oil and natural gas derivative contracts | | - | | | (244,887) | | | - | | | (244,887) | | | — | | | (69,424 | ) | | — | | | (69,424 | ) |
| | | | | | | | | | | | | | | | | | |
Total | | $ | 99,733 | | $ | (231,685) | | | $ | 15,346 | | $ | (116,606) | | | $ | 88,220 | | $ | (39,131 | ) | | $ | 6,638 | | $ | 55,727 | |
| | | | | | | | | | | | | | | | | | |
| | |
December 31, 2010 | | |
Assets: | | |
Assets | | |
Short-term investments | | $ | 93,020 | | $ | - | | $ | - | | $ | 93,020 | | | $ | 93,020 | | $ | — | | $ | — | | $ | 93,020 | |
Oil derivative contracts | | - | | 20,683 | | 16,478 | | 37,161 | | |
Liabilities: | | |
Oil and natural gas derivative contracts | | | — | | 20,683 | | 16,478 | | 37,161 | |
Liabilities | | |
Oil and natural gas derivative contracts | | - | | | (81,162) | | | - | | | (81,162) | | | — | | | (81,162 | ) | | — | | | (81,162 | ) |
| | | | | | | | | | | | | | | | | | |
Total | | $ | 93,020 | | $ | (60,479) | | | $ | 16,478 | | $ | 49,019 | | | $ | 93,020 | | $ | (60,479 | ) | | $ | 16,478 | | $ | 49,019 | |
| | | | | | | | | | | | | | | | | | |
16
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the three and six months ended March 31,June 30, 2011 and 2010:
| | | | | | | |
| | Fair Value Measurements Using Significant | | |
| | | |
| | Unobservable Inputs (Level 3) | | |
| | | | | | | | | | | | | | | | |
| | Three Months Ended | | Three Months Ended | | | Three Months Ended | | Six Months Ended | |
| | | | June 30, | | June 30, | |
In thousands | | March 31, 2011 | | March 31, 2010 | | | 2011 | | 2010 | | 2011 | | 2010 | |
Balance, beginning of period | | $ | 16,478 | | $ | - | | | $ | 15,346 | | $ | 50,518 | | $ | 16,478 | | $ | — | |
Unrealized gains on commodity derivative contracts included in earnings | | 310 | | 14,773 | | |
Unrealized gains/(losses) on commodity derivative contracts included in earnings | | | | (7,386 | ) | | 126 | | | (7,076 | ) | | 14,899 | |
Commodity derivative contracts acquired from Encore | | - | | 38,093 | | | — | | — | | — | | 38,093 | |
Receipts on settlement of commodity derivative contracts | | | (1,442) | | | | (2,348) | | | | (1,322 | ) | | | (10,361 | ) | | | (2,764 | ) | | | (12,709 | ) |
| | | | | | | | | | | | | | |
Balance, end of period | | $ | 15,346 | | $ | 50,518 | | | 6,638 | | 40,283 | | $ | 6,638 | | $ | 40,283 | |
| | | | | | | | | | | | | | |
Since we do not use hedge accounting for our commodity derivative contracts, any gains and losses on our assets and liabilities are included in “Derivatives expense (income)”income” in the accompanying Unaudited Condensed Consolidated Statements of Operations.
17
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
The following table sets forth the fair value of financial instruments that are not recorded at fair value in our Unaudited Condensed Consolidated Financial Statements:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | March 31, 2011 | | December 31, 2010 | | | June 30, 2011 | | December 31, 2010 | |
| | Carrying | | Estimated | | Carrying | | Estimated | | | Carrying | | Estimated | | Carrying | | Estimated | |
In thousands, except percentages | | Amount | | Fair Value | | Amount | | Fair Value | | |
| | |
71/2% Senior Subordinated Notes due 2013 (1) | | $ | 55,352 | | $ | 55,448 | | $ | 224,563 | | $ | 228,375 | | |
In thousands | | | Amount | | Fair Value | | Amount | | Fair Value | |
71/2% Senior Subordinated Notes due 2013 | | | $ | — | | $ | — | | $ | 224,563 | | $ | 228,375 | |
71/2% Senior Subordinated Notes due 2015 | | - | | - | | 300,427 | | 310,500 | | | — | | — | | 300,427 | | 310,500 | |
91/2% Senior Subordinated Notes due 2016 | | 238,826 | | 253,597 | | 239,509 | | 249,661 | | | 238,142 | | 249,942 | | 239,509 | | 249,661 | |
93/4% Senior Subordinated Notes due 2016 | | 405,283 | | 480,710 | | 404,211 | | 475,380 | | | 406,354 | | 476,446 | | 404,211 | | 475,380 | |
81/4% Senior Subordinated Notes due 2020 | | 996,273 | | 1,113,335 | | 996,273 | | 1,080,956 | | | 996,273 | | 1,085,938 | | 996,273 | | 1,080,956 | |
63/8% Senior Subordinated Notes due 2021 | | 400,000 | | 410,000 | | - | | - | | |
| | |
| | |
| | | |
(1) These notes were repurchased on April 1, 2011. | | |
6⅜% Senior Subordinated Notes due 2021 | | | 400,000 | | 400,000 | | — | | — | |
The fair values of our senior subordinated notes are based on quoted market prices. We have other financial instruments consisting primarily of cash, cash equivalents and short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.
Note 6. Supplemental Information
Accounts Payable and Accrued Liabilities
The following table summarizes our accounts payable and accrued liabilities as of the periods indicated:
| | | | | | | | | | | | | | |
| | March 31, | | December 31, | | | June 30, | | December 31, | |
In thousands | | 2011 | | 2010 | | | 2011 | | 2010 | |
Accounts payable | | $ | 53,754 | | $ | 47,660 | | | $ | 72,830 | | $ | 47,660 | |
Accrued exploration and development costs | | 75,967 | | 101,758 | | | 96,910 | | 101,758 | |
Accrued compensation | | 17,820 | | 39,757 | | | 26,760 | | 39,757 | |
Accrued lease operating expense | | | 25,100 | | 23,557 | |
Accrued interest | | 31,405 | | 57,077 | | | 61,166 | | 57,077 | |
Taxes payable | | 7,198 | | 34,371 | | | 16,537 | | 34,371 | |
Other | | 60,001 | | 65,375 | | | 34,650 | | 41,818 | |
| | | | | | | | | | |
Total | | $ | 246,145 | | $ | 345,998 | | | $ | 333,953 | | $ | 345,998 | |
| | | | | | | | | | |
Supplemental Cash Flow Information
The following table sets forth supplemental cash flow information for the periods indicated:
| | | | | | | | | | | | | | |
| | As of | | | Six Months Ended | |
| | March 31, | | | June 30, | |
In thousands | | 2011 | | 2010 | | | 2011 | | 2010 | |
Cash paid for interest, net of amounts capitalized | | $ | 66,172 | | $ | 21,962 | | |
Interest capitalized | | 10,957 | | 21,312 | | |
Cash paid for interest, expensed | | | $ | 72,774 | | $ | 43,296 | |
Cash paid for interest, capitalized | | | 24,151 | | 45,162 | |
Cash paid for income taxes | | 19,933 | | 8,030 | | | 31,072 | | 11,920 | |
Cash received for income tax refunds | | 222 | | 12,625 | | | 20,841 | | 13,093 | |
Increase (decrease) in accrued liabilities for capital expenditures | | | (12,503) | | | 32,399 | | |
Increase in liabilities for capital expenditures | | | 25,141 | | 46,170 | |
Issuance of Denbury common stock in connection with the Encore Merger | | - | | 2,085,681 | | | — | | 2,085,681 | |
1718
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 7. Commitments and Contingencies
In March 2011, we entered into three long-term supply contracts to purchase CO2 from future anthropogenic sources in the Gulf Coast and Rocky Mountain regions. The three contracts are in addition to the previously disclosed long-term supply contracts Denbury currently has in place in the Gulf Coast, Rocky Mountain and Midwest regions. Under the three new contracts, Denbury will purchase 100% of the CO2 captured from the DKRW Advanced Fuels LLC’s Medicine Bow Fuel and Power LLC (“MBFP”) project in Medicine Bow, Wyoming, purchase 70% of the CO2 captured from Mississippi Power Company’s Kemper County Integrated Gasification Combined Cycle (“IGCC”) project in Mississippi, and purchase 100% of the CO2 captured from an undisclosed sourceby Air Products LLC (“Air Products”) at a third-party refinery in the Gulf Coast region.Port Arthur, Texas. These new contracts each have an initial term of 15 to 16 years and include options to extend the term. We estimate that these new sources will supply approximately 365 MMcf/d of CO2 for our enhanced oil recovery operations, although under certain circumstances, we may be obligated to purchase up to 460 MMcf/d, a portion of which would be at a reduced price per Mcf. We expect to begin taking delivery of approximately 200 MMCF/d of CO2 from the MBFP project in late 2014 or early 2015, 115 MMcf/d of CO2 from the IGCC project by 2014, and 50 MMcf/d of CO2 from a Gulf Coast region sourceAir Products in late 2012. Our aggregate maximum purchase obligation for CO2 purchased under these three contracts would be approximately $110 million per year (assuming purchases of 460 MMcf/d), plus transportation, assuming a $100 per barrel NYMEX oil price. The purchase price of CO2 will fluctuate based on the changes in the price of oil. These
As is the case with all of our long-term supply contracts to purchase CO2purchase, the three agreements entered into in March are subject to various contingencies. The IGCC and Air Products plants are currently being constructed and MBFP is in the initial stages of construction but its completion is still contingent on completion or modificationupon securing debt financing and equity commitments and receipt of the respective plants by their operators.all necessary consents and approvals.
In the third quarter of 2008, we obtained approval from the National Office of the Internal Revenue Service (“IRS”) to change our method of tax accounting for certain assets used in our tertiary oilfield recovery operations. As a result of the approved change in method of tax accounting, beginning with the 2007 tax year we began to deduct, rather than capitalize, such costs for tax purposes, and applied for tax refunds associated with such change for our 2004 and 2006 tax years. Notwithstanding its consent to our change in tax accounting in 2008, the IRS subsequently exercised its prerogative to challenge the tax accounting method we used. In late January 2011, we received a Technical Advice Memorandum (“TAM”) issued by the IRS National Office disapproving our method of accounting and revoking its consent to our change, on a prospective basis only, commencing January 1, 2011. As a result of the prospective nature of the IRS’s determination, there should be no change in our position with respect to the deductibility of these costs for 2007, 2008, 2009 and 2010. However, refund claims of $10.6 million for tax years through 2006 are pending and are subject to review by the Joint Committee on Taxation of the U.S. Congress. We are unable to assess the outcome of any such review, nor how that outcome may affect the other years covered by the TAM.
We are subject to audits for sales and use taxes and severance taxes in the various states in which we operate, and from time to time receive assessments for potential taxes that we may owe. We have received a $15.0 million assessment from the Mississippi taxing authority for use tax, penalties and interest covering the 2004-2007 period. We believe this assessment is significantly in excess of any amounts owed and we are appealing the assessment. We do not believe the outcome of this matter will have a material adverse impacteffect on the Company.our financial position or results of operations.
We are involved in various lawsuits, claims and other regulatory proceedings incidental to our businesses. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows, litigation is subject to inherent uncertainties. If an unfavorable ruling were to occur, there exists the possibility of a material adverse impact on our net income in the period in which the ruling occurs. We provide accruals for litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated.
18
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 8. Condensed Consolidating Financial InformationSubsequent Event
Denbury’s subordinated debt is fullyOn August 1, 2011, we acquired the remaining 57.5% working interest in Riley Ridge and unconditionally guaranteed jointly and severally by certaina working interest of its subsidiaries, except that with respect to Denbury’s $55 million of 7½% Senior Subordinated Notes due 2013 that remained outstanding at March 31, 2011, Denbury Resources Inc. and Denbury Onshore, LLC were co-obligors at March 31, 2011. These 7½% Notes have since been redeemed and are no longer outstanding. Except as notedapproximately 33% in the first sentence of this paragraph, Denbury Resources Inc. is the sole issuer and Denbury Onshore, LLC is28,000 acres adjacent to Riley Ridge. As a subsidiary guarantor. In the caseresult of the 6¼% Notes,transaction, we became the 6% Notes,operator of both projects. The purchase price was approximately $191 million, including a $15 million contingent payment to be paid at the 7¼% Notestime the property’s gas processing facility is operational and meets specific performance conditions, plus customary closing adjustments including payment for capital expenditures incurred between the 9½% Notes previously issued by Encore, Denbury is the sole issuer by virtueeffective date of the fact that it ispurchase (April 1, 2011) and closing. We expect the successor in interestgas processing facility to Encore with respect to all such notes. Each subsidiary guarantor andbe operational during the subsidiary that was a co-obligor are wholly-owned, directly or indirectly, by Denbury Resources Inc.
All intercompany investments in, loans due to/from, subsidiary equity, revenues, and expenses between Denbury Resources Inc., Denbury Onshore, LLC, guarantor subsidiaries, and non-guarantor subsidiaries are shown prior to consolidation with Denbury Resources Inc. and then eliminated to arrive at consolidated totals per the accompanying Unaudited Condensed Consolidated Financial Statements.fourth quarter of 2011.
19
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Balance Sheets
| | | | | | | | | | | | | | | | | | | | | | | | |
| | March 31, 2011 | |
| | Denbury | | | Denbury | | | | | | | | | | | | | | |
|
| | Resources Inc. | | | Onshore, LLC | | | | | | | | | | | | | | |
|
| | (Parent and | | | (Issuer and | | | Guarantor | | | Non-Guarantor | | | | | | | Consolidated | |
|
In thousands | | Co-Obligor) | | | Co-Obligor) | | | Subsidiaries | | | Subsidiaries | | | Eliminations | | | Total | |
ASSETS | | | | | | | | | | | | | | | | | | | | | | | | |
Current assets: | | | | | | | | | | | | | | | | | | | | | | | | |
Cash and cash equivalents | | $ | 3,947 | | | $ | 119,569 | | | $ | 3,630 | | | $ | 711 | | | $ | - | | | $ | 127,857 | |
Other current assets | | | 476,986 | | | | 559,354 | | | | 461,605 | | | | - | | | | (904,139) | | | | 593,806 | |
| | | | | | | | | | | | | | | | | | |
Total current assets | | | 480,933 | | | | 678,923 | | | | 465,235 | | | | 711 | | | | (904,139) | | | | 721,663 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Property and equipment: | | | | | | | | | | | | | | | | | | | | | | | | |
Oil and natural gas properties (using full cost accounting): | | | | | | | | | | | | | | | | | | | | | | | - | |
Proved | | | - | | | | 6,238,629 | | | | - | | | | - | | | | - | | | | 6,238,629 | |
Unevaluated | | | - | | | | 912,267 | | | | - | | | | - | | | | - | | | | 912,267 | |
CO2 and other non-hydrocarbon gases - properties and pipelines | | | - | | | | 707,008 | | | | 1,223,900 | | | | 9,484 | | | | - | | | | 1,940,392 | |
Other property and equipment | | | - | | | | 128,421 | | | | 4,271 | | | | - | | | | - | | | | 132,692 | |
Less accumulated depletion, depreciation, amortization, and impairment | | | - | | | | (2,267,862) | | | | (28,090) | | | | - | | | | - | | | | (2,295,952) | |
| | | | | | | | | | | | | | | | | | |
Net property and equipment | | | - | | | | 5,718,463 | | | | 1,200,081 | | | | 9,484 | | | | - | | | | 6,928,028 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Derivative assets | | | - | | | | 9,203 | | | | - | | | | - | | | | - | | | | 9,203 | |
Goodwill | | | 1,061,123 | | | | 171,295 | | | | - | | | | - | | | | - | | | | 1,232,418 | |
Other assets | | | 549,334 | | | | 144,456 | | | | 7 | | | | 33 | | | | (473,723) | | | | 220,107 | |
Investment in subsidiaries (equity method) | | | 4,354,965 | | | | 2,666 | | | | 4,369,801 | | | | - | | | | (8,727,432) | | | | - | |
| | | | | | | | | | | | | | | | | | |
Total assets | | $ | 6,446,355 | | | $ | 6,725,006 | | | $ | 6,035,124 | | | $ | 10,228 | | | $ | (10,105,294) | | | $ | 9,111,419 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
LIABILITIES AND EQUITY | | | | | | | | | | | | | | | | | | | | | | | | |
Current liabilities | | $ | 20,764 | | | $ | 901,331 | | | $ | 609,794 | | | $ | 10,723 | | | $ | (904,139) | | | $ | 638,473 | |
Long-term debt, net of current portion | | | 2,044,226 | | | | 726,905 | | | | - | | | | - | | | | (426,350) | | | | 2,344,781 | |
Asset retirement obligations | | | - | | | | 83,576 | | | | - | | | | - | | | | - | | | | 83,576 | |
Derivative liabilities | | | - | | | | 47,745 | | | | - | | | | - | | | | - | | | | 47,745 | |
Deferred taxes | | | - | | | | 569,597 | | | | 1,067,688 | | | | - | | | | (47,373) | | | | 1,589,912 | |
Other liabilities | | | - | | | | 22,890 | | | | 2,677 | | | | - | | | | - | | | | 25,567 | |
| | | | | | | | | | | | | | | | | | |
Total liabilities | | | 2,064,990 | | | | 2,352,044 | | | | 1,680,159 | | | | 10,723 | | | | (1,377,862) | | | | 4,730,054 | |
Total equity | | | 4,381,365 | | | | 4,372,962 | | | | 4,354,965 | | | | (495) | | | | (8,727,432) | | | | 4,381,365 | |
| | | | | | | | | | | | | | | | | | |
Total liabilities and equity | | $ | 6,446,355 | | | $ | 6,725,006 | | | $ | 6,035,124 | | | $ | 10,228 | | | $ | (10,105,294) | | | $ | 9,111,419 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2010 | |
| | Denbury | | | Denbury | | | | | | | | | | | | | | |
|
| | Resources Inc. | | | Onshore, LLC | | | | | | | | | | | | | | |
|
| | (Parent and | | | (Issuer and | | | Guarantor | | | Non-Guarantor | | | | | | | Consolidated | |
|
In thousands | | Co-Obligor) | | | Co-Obligor) | | | Subsidiaries | | | Subsidiaries | | | Eliminations | | | Total | |
ASSETS | | | | | | | | | | | | | | | | | | | | | | | | |
Current assets: | | | | | | | | | | | | | | | | | | | | | | | | |
Cash and cash equivalents | | $ | 457 | | | $ | 380,273 | | | $ | 1,139 | | | $ | - | | | $ | - | | | $ | 381,869 | |
Other current assets | | | 144,247 | | | | 487,942 | | | | 449,871 | | | | - | | | | (599,611) | | | | 482,449 | |
| | | | | | | | | | | | | | | | | | |
Total current assets | | | 144,704 | | | | 868,215 | | | | 451,010 | | | | - | | | | (599,611) | | | | 864,318 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Property and equipment: | | | | | | | | | | | | | | | | | | | | | | | | |
Oil and natural gas properties (using full cost accounting): | | | | | | | | | | | | | | | | | | | | | | | - | |
Proved | | | - | | | | 6,042,442 | | | | - | | | | - | | | | - | | | | 6,042,442 | |
Unevaluated | | | - | | | | 870,130 | | | | - | | | | - | | | | - | | | | 870,130 | |
CO2 and other non-hydrocarbon gases - properties and pipelines | | | - | | | | 681,963 | | | | 1,216,841 | | | | 2,858 | | | | - | | | | 1,901,662 | |
Other property and equipment | | | - | | | | 116,370 | | | | 4,271 | | | | - | | | | - | | | | 120,641 | |
Less accumulated depletion, depreciation, amortization and impairment | | | - | | | | (2,177,040) | | | | (20,477) | | | | - | | | | - | | | | (2,197,517) | |
| | | | | | | | | | | | | | | | | | |
Net property and equipment | | | - | | | | 5,533,865 | | | | 1,200,635 | | | | 2,858 | | | | - | | | | 6,737,358 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Derivative assets | | | - | | | | 12,919 | | | | - | | | | - | | | | - | | | | 12,919 | |
Goodwill | | | 1,061,123 | | | | 171,295 | | | | - | | | | - | | | | - | | | | 1,232,418 | |
Other assets | | | 830,454 | | | | 144,333 | | | | 7 | | | | - | | | | (756,744) | | | | 218,050 | |
Investment in subsidiaries (equity method) | | | 4,332,347 | | | | 2,666 | | | | 4,357,128 | | | | - | | | | (8,692,141) | | | | - | |
| | | | | | | | | | | | | | | | | | |
Total assets | | $ | 6,368,628 | | | $ | 6,733,293 | | | $ | 6,008,780 | | | $ | 2,858 | | | $ | (10,048,496) | | | $ | 9,065,063 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
LIABILITIES AND EQUITY | | | | | | | | | | | | | | | | | | | | | | | | |
Current liabilities | | $ | 43,654 | | | | 517,686 | | | | 614,388 | | | | 3,228 | | | | (599,611) | | | | 579,345 | |
Long-term debt, net of current portion | | | 1,944,267 | | | | 1,198,291 | | | | - | | | | - | | | | (726,350) | | | | 2,416,208 | |
Asset retirement obligations | | | - | | | | 81,290 | | | | - | | | | - | | | | - | | | | 81,290 | |
Derivative liabilities | | | - | | | | 29,687 | | | | - | | | | - | | | | - | | | | 29,687 | |
Deferred taxes | | | - | | | | 516,319 | | | | 1,062,045 | | | | 22 | | | | (30,394) | | | | 1,547,992 | |
Other liabilities | | | - | | | | 29,834 | | | | - | | | | - | | | | - | | | | 29,834 | |
| | | | | | | | | | | | | | | | | | |
Total liabilities | | | 1,987,921 | | | | 2,373,107 | | | | 1,676,433 | | | | 3,250 | | | | (1,356,355) | | | | 4,684,356 | |
Total equity | | | 4,380,707 | | | | 4,360,186 | | | | 4,332,347 | | | | (392) | | | | (8,692,141) | | | | 4,380,707 | |
| | | | | | | | | | | | | | | | | | |
Total liabilities and equity | | $ | 6,368,628 | | | $ | 6,733,293 | | | $ | 6,008,780 | | | $ | 2,858 | | | $ | (10,048,496) | | | $ | 9,065,063 | |
| | | | | | | | | | | | | | | | | | |
20
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Statements The acquisition of Operations
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2011 | |
| | Denbury | | | Denbury | | | | | | | | | | | | | | |
| | |
| | Resources Inc. | | | Onshore, LLC | | | | | | | | | | | | | | |
| | |
| | (Parent and | | | (Issuer and | | | Guarantor | | | Non-Guarantor | | | | | | | Consolidated | |
| | |
In thousands | | Co-Obligor) | | | Co-Obligor) | | | Subsidiaries | | | Subsidiaries | | | Eliminations | | | Total | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Revenues and other income: | | | | | | | | | | | | | | | | | | | | | | | | |
Oil, natural gas, and related product sales | | $ | - | | | $ | 506,192 | | | $ | - | | | $ | - | | | $ | - | | | $ | 506,192 | |
CO2 sales and transportation fees | | | - | | | | 3,733 | | | | 22,217 | | | | - | | | | (21,026) | | | | 4,924 | |
Interest income and other | | | 32,433 | | | | 3,047 | | | | 8,594 | | | | - | | | | (41,025) | | | | 3,049 | |
| | | | | | | | | | | | | | | | | | |
Total revenues | | | 32,433 | | | | 512,972 | | | | 30,811 | | | | - | | | | (62,051) | | | | 514,165 | |
| | | | | | | | | | | | | | | | | | |
Expenses: | | | | | | | | | | | | | | | | | | | | | | | | |
Lease operating expenses | | | - | | | | 145,846 | | | | - | | | | - | | | | (18,749) | | | | 127,097 | |
Production taxes and marketing expenses | | | - | | | | 32,751 | | | | - | | | | - | | | | - | | | | 32,751 | |
CO2 discovery and operating expenses | | | - | | | | 1,809 | | | | 2,622 | | | | - | | | | (2,277) | | | | 2,154 | |
General and administrative | | | 191 | | | | 42,553 | | | | 945 | | | | 157 | | | | - | | | | 43,846 | |
Interest, net of amounts capitalized | | | 50,321 | | | | 12,647 | | | | (301) | | | | - | | | | (13,890) | | | | 48,777 | |
Depletion, depreciation, and amortization | | | - | | | | 92,212 | | | | 1,382 | | | | - | | | | - | | | | 93,594 | |
Derivatives expense | | | - | | | | 170,750 | | | | - | | | | - | | | | - | | | | 170,750 | |
Loaa on early extinguishment of debt | | | 13,670 | | | | 2,113 | | | | - | | | | - | | | | - | | | | 15,783 | |
Transaction costs and other related to the Encore Merger | | | - | | | | 123 | | | | 2,236 | | | | - | | | | - | | | | 2,359 | |
| | | | | | | | | | | | | | | | | | |
Total expenses | | | 64,182 | | | | 500,804 | | | | 6,884 | | | | 157 | | | | (34,916) | | | | 537,111 | |
| | | | | | | | | | | | | | | | | | |
Income (loss) before income taxes | | | (31,749) | | | | 12,168 | | | | 23,927 | | | | (157) | | | | (27,135) | | | | (22,946) | |
Income tax provision (benefit) | | | (17,661) | | | | 3,574 | | | | 5,386 | | | | (55) | | | | - | | | | (8,756) | |
| | | | | | | | | | | | | | | | | | |
Consolidated net income (loss) | | $ | (14,088) | | | $ | 8,594 | | | $ | 18,541 | | | $ | (102) | | | $ | (27,135) | | | $ | (14,190) | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2010 | |
| | Denbury | | | Denbury | | | | | | | | | | | | | | |
| | |
| | Resources Inc. | | | Onshore, LLC | | | | | | | | | | | | | | |
| | |
| | (Parent and | | | (Issuer and | | | Guarantor | | | Non-Guarantor | | | | | | | Consolidated | |
| | |
In thousands | | Co-Obligor) | | | Co-Obligor) | | | Subsidiaries | | | Subsidiaries | | | Eliminations | | | Total | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Revenues and other income: | | | | | | | | | | | | | | | | | | | | | | | | |
Oil, natural gas, and related product sales | | $ | - | | | $ | 270,571 | | | $ | 47,881 | | | $ | 12,434 | | | $ | - | | | $ | 330,886 | |
CO2 sales and transportation fees | | | - | | | | 4,497 | | | | - | | | | - | | | | - | | | | 4,497 | |
Gain on sale of interests in Genesis | | | - | | | | (160) | | | | 101,728 | | | | | | | | - | | | | 101,568 | |
Interest income and other | | | 127,106 | | | | 827 | | | | (7,446) | | | | 4 | | | | (118,621) | | | | 1,870 | |
| | | | | | | | | | | | | | | | | | |
Total revenues | | | 127,106 | | | | 275,735 | | | | 142,163 | | | | 12,438 | | | | (118,621) | | | | 438,821 | |
| | | | | | | | | | | | | | | | | | |
Expenses: | | | | | | | | | | | | | | | | | | | | | | | | |
Lease operating expenses | | | - | | | | 85,884 | | | | 7,552 | | | | 2,784 | | | | - | | | | 96,220 | |
Production taxes and marketing expenses | | | - | | | | 12,277 | | | | 5,653 | | | | 1,387 | | | | - | | | | 19,317 | |
CO2 discovery and operating expenses | | | - | | | | 1,360 | | | | 8 | | | | - | | | | - | | | | 1,368 | |
General and administrative | | | 118 | | | | 26,683 | | | | 5,227 | | | | 681 | | | | - | | | | 32,709 | |
Interest, net of amounts capitalized | | | 33,828 | | | | 13,944 | | | | (6,418) | | | | 1,079 | | | | (16,017) | | | | 26,416 | |
Depletion, depreciation, and amortization | | | - | | | | 65,025 | | | | 13,748 | | | | 3,099 | | | | - | | | | 81,872 | |
Derivatives income | | | - | | | | (31,638) | | | | (5,817) | | | | (3,770) | | | | - | | | | (41,225) | |
Transaction costs and other related to the Encore Merger | | | | | | | 43,809 | | | | 252 | | | | 938 | | | | - | | | | 44,999 | |
| | | | | | | | | | | | | | | | | | |
Total expenses | | | 33,946 | | | | 217,344 | | | | 20,205 | | | | 6,198 | | | | (16,017) | | | | 261,676 | |
| | | | | | | | | | | | | | | | | | |
Income before income taxes | | | 93,160 | | | | 58,391 | | | | 121,958 | | | | 6,240 | | | | (102,604) | | | | 177,145 | |
Income tax provision (benefit) | | | (7,044) | | | | 66,871 | | | | 17,101 | | | | 13 | | | | - | | | | 76,941 | |
| | | | | | | | | | | | | | | | | | |
Consolidated net income (loss) | | | 100,204 | | | | (8,480) | | | | 104,857 | | | | 6,227 | | | | (102,604) | | | | 100,204 | |
| | | | | | | | | | | | | | | | | | |
Less: net income attributable to noncontrolling interest | | | - | | | | - | | | | - | | | | (3,316) | | | | - | | | | (3,316) | |
| | | | | | | | | | | | | | | | | | |
Consolidated net income (loss) attributable to Denbury stockholders | | $ | 100,204 | | | $ | (8,480) | | | $ | 104,857 | | | $ | 2,911 | | | $ | (102,604) | | | $ | 96,888 | |
| | | | | | | | | | | | | | | | | | |
21
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating StatementsRiley Ridge meets the definition of Cash Flowsa business under the FASCBusiness Combinations
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2011 | |
| | Denbury | | | Denbury | | | | | | | | | | | | | | |
| | |
| | Resources Inc. | | | Onshore, LLC | | | | | | | | | | | | | | |
| | |
| | (Parent and | | | (Issuer and | | | Guarantor | | | Non-Guarantor | | | | | | | Consolidated | |
| | |
In thousands | | Co-Obligor) | | | Co-Obligor) | | | Subsidiaries | | | Subsidiaries | | | Eliminations | | | Total | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Cash flow from operating activities: | | | | | | | | | | | | | | | | | | | | | | | | |
Net cash provided by (used for) operating activities | | $ | (74,995) | | | $ | 476,567 | | | $ | 30,785 | | | $ | 5,549 | | | $ | (313,074) | | | $ | 124,832 | |
| | | | | | | | | | | | | | | | | | |
Cash flow used for investing activities: | | | | | | | | | | | | | | | | | | | | | | | | |
Oil and natural gas capital expenditures | | | - | | | | (190,296) | | | | - | | | | - | | | | - | | | | (190,296) | |
Acquisitions of oil and natural gas properties | | | - | | | | (29,801) | | | | - | | | | - | | | | - | | | | (29,801) | |
CO2 and other non-hydrocarbon gases - capital expenditures, including pipelines | | | - | | | | (33,025) | | | | (28,294) | | | | (4,838) | | | | - | | | | (66,157) | |
Other | | | - | | | | 1,211 | | | | - | | | | - | | | | - | | | | 1,211 | |
| | | | | | | | | | | | | | | | | | |
Net cash used for investing activities | | | - | | | | (251,911) | | | | (28,294) | | | | (4,838) | | | | - | | | | (285,043) | |
| | | | | | | | | | | | | | | | | | |
Cash flow from financing activities: | | | | | | | | | | | | | | | | | | | | | | | | |
Bank repayments | | | (130,000) | | | | - | | | | - | | | | - | | | | - | | | | (130,000) | |
Bank borrowings | | | 130,000 | | | | - | | | | - | | | | - | | | | - | | | | 130,000 | |
Repayment of senior subordinated notes | | | (300,000) | | | | (469,552) | | | | - | | | | - | | | | 300,000 | | | | (469,552) | |
Premium paid on repayment of senior subordinated notes | | | (12,078) | | | | (13,137) | | | | - | | | | - | | | | 12,078 | | | | (13,137) | |
Net proceeds from issuance of senior subordinated debt | | | 400,000 | | | | - | | | | - | | | | - | | | | - | | | | 400,000 | |
Costs of debt financing | | | (8,441) | | | | - | | | | - | | | | - | | | | - | | | | (8,441) | |
Other | | | (996) | | | | (2,671) | | | | - | | | | - | | | | 996 | | | | (2,671) | |
| | | | | | | | | | | | | | | | | | |
Net cash provided by (used for) financing activities | | | 78,485 | | | | (485,360) | | | | - | | | | - | | | | 313,074 | | | | (93,801) | |
| | | | | | | | | | | | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | 3,490 | | | | (260,704) | | | | 2,491 | | | | 711 | | | | - | | | | (254,012) | |
Cash and cash equivalents at beginning of period | | | 457 | | | | 380,273 | | | | 1,139 | | | | - | | | | - | | | | 381,869 | |
| | | | | | | | | | | | | | | | | | |
Cash and cash equivalents at end of period | | $ | 3,947 | | | $ | 119,569 | | | $ | 3,630 | | | $ | 711 | | | $ | - | | | $ | 127,857 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2010 | |
| | Denbury | | | Denbury | | | | | | | | | | | | | | |
| | |
| | Resources Inc. | | | Onshore, LLC | | | | | | | | | | | | | | |
| | |
| | (Parent and | | | (Issuer and | | | Guarantor | | | Non-Guarantor | | | | | | | Consolidated | |
| | |
In thousands | | Co-Obligor) | | | Co-Obligor) | | | Subsidiaries | | | Subsidiaries | | | Eliminations | | | Total | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Cash flow from operating activities: | | | | | | | | | | | | | | | | | | | | | | | | |
Net cash provided by operating activities | | $ | 3,173 | | | $ | 219,573 | | | $ | 190,852 | | | $ | 6,882 | | | $ | (307,312) | | | $ | 113,168 | |
| | | | | | | | | | | | | | | | | | |
Cash flow used for investing activities: | | | | | | | | | | | | | | | | | | | | | | | | |
Oil and natural gas capital expenditures | | | - | | | | (70,061) | | | | (22,262) | | | | (324) | | | | - | | | | (92,647) | |
Acquisitions of oil and natural gas properties | | | - | | | | (503) | | | | 455 | | | | (292) | | | | - | | | | (340) | |
Cash paid in Encore Merger, net of cash acquired | | | (830,310) | | | | - | | | | 15,705 | | | | 13,116 | | | | - | | | | (801,489) | |
CO2 and other non-hydrocarbon gases - capital expenditures, including pipelines | | | - | | | | (37,011) | | | | (35,636) | | | | - | | | | - | | | | (72,647) | |
Deposit received on divesture of Southern Assets | | | 45,000 | | | | - | | | | - | | | | - | | | | - | | | | 45,000 | |
Net proceeds from sales of oil and gas properties and equipment | | | - | | | | 23,537 | | | | 139,085 | | | | - | | | | - | | | | 162,622 | |
Investments in subsidiaries (equity method) | | | (305,646) | | | | - | | | | - | | | | - | | | | 305,646 | | | | - | |
Other | | | - | | | | (4,799) | | | | (27) | | | | - | | | | - | | | | (4,826) | |
| | | | | | | | | | | | | | | | | | |
Net cash provided by (used for) investing activities | | | (1,090,956) | | | | (88,837) | | | | 97,320 | | | | 12,500 | | | | 305,646 | | | | (764,327) | |
| | | | | | | | | | | | | | | | | | |
Cash flow from financing activities: | | | | | | | | | | | | | | | | | | | | | | | | |
Bank repayments | | | - | | | | (350,000) | | | | (265,000) | | | | (10,000) | | | | - | | | | (625,000) | |
Bank borrowings | | | 800,000 | | | | 225,000 | | | | - | | | | - | | | | - | | | | 1,025,000 | |
Repayment of senior subordinated notes | | | (508,182) | | | | - | | | | - | | | | - | | | | - | | | | (508,182) | |
Premium paid on repayment of senior subordinated notes | | | (6,257) | | | | | | | | | | | | | | | | | | | | (6,257) | |
Net proceeds from issuance of senior subordinated debt | | | 1,000,000 | | | | - | | | | - | | | | - | | | | - | | | | 1,000,000 | |
Escrowed Funds for senior subordinated notes redemption | | | (65,566) | | | | - | | | | - | | | | - | | | | - | | | | (65,566) | |
Costs of debt financing | | | (76,129) | | | | - | | | | - | | | | - | | | | - | | | | (76,129) | |
Other | | | (1,666) | | | | (2,139) | | | | (1,974) | | | | - | | | | 1,666 | | | | (4,113) | |
| | | | | | | | | | | | | | | | | | |
Net cash provided by (used for) financing activities | | | 1,142,200 | | | | (127,139) | | | | (266,974) | | | | (10,000) | | | | 1,666 | | | | 739,753 | |
| | | | | | | | | | | | | | | | | | |
Net increase in cash and cash equivalents | | | 54,417 | | | | 3,597 | | | | 21,198 | | | | 9,382 | | | | - | | | | 88,594 | |
Cash and cash equivalents at beginning of period | | | 24 | | | | 20,281 | | | | 286 | | | | - | | | | - | | | | 20,591 | |
| | | | | | | | | | | | | | | | | | |
Cash and cash equivalents at end of period | | $ | 54,441 | | | $ | 23,878 | | | $ | 21,484 | | | $ | 9,382 | | | $ | - | | | $ | 109,185 | |
| | | | | | | | | | | | | | | | | | |
Note 9. Subsequent Events
Redemptiontopic. We will account for our acquisition of our 2013 Notes
On February 3, 2011, we commenced cash tender offers to purchase $225 million principal amountRiley Ridge under the acquisition method of our 2013 Notes. By March 3, 2011, upon expirationaccounting, which will result in the allocation of the tender offers, we accepted for purchase $169.6 million in principal amountprice to the assets acquired and liabilities assumed based on their estimated fair values at the date of the 2013 Notes at 100.625% of par. On April 1, 2011, we repurchased all $55.4 million of our 2013 Notes remaining outstanding at par in accordanceacquisition, with the terms ofexcess purchase price, if any, being recognized as goodwill. We have not yet completed our indenture. See Note 3,Long-Term Debt,initial calculation necessary to the Unaudited Condensed Consolidated Financial Statements for more information.make this allocation.
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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and in our Annual Report on Form 10-K for the year ended December 31, 2010, along withManagement’s Discussion and Analysis of Financial Condition and Results of Operationscontained 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. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction withRisk Factorsunder Item 1A of this report, along withForward-Looking Informationat the end of this section for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
Overview
We are a growing independent oil and natural gas company. We are the largest oil and natural gas producer in both Mississippi and Montana, own the largest CO2 reserves used for tertiary oil recovery east of the Mississippi River, and hold significant operating acreage in the Rocky Mountain and Gulf Coast regions. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis on our CO2 tertiary recovery operations.
Operating Highlights.The acquisition of Encore Acquisition Company (the “Encore Merger”) on March 9, 2010, has had a significant impact on nearly every aspect of our business, including oil and natural gas production, revenues and operating expenses. Accordingly, the Encore Merger impacts the comparability of our first quarter 2010 financial results for the first six months of 2010 to those in the first quartersix months of 2011, which is more fully discusseddetailed throughout the following discussion and analysis. Our first quarter 2010 financial results for the first six months of 2010 include the results of operations forof Encore from the date of the acquisition on March 9, 2010 through March 31,June 30, 2010. Additionally, starting in May 2010 and throughout 2010the remainder of that year, we disposed of non-strategic Encore properties and our ownership interests in Encore Energy Partners LP (“ENP”).
Second Quarter Operating Highlights.We recognized a net lossincome of $14.2$259.2 million, or $0.04$0.65 per basic common share, during the firstsecond quarter of 2011 as compared to net income of $96.9$135.4 million, or $0.33$0.34 per basic common share, during the firstsecond quarter of 2010. This decreaseincrease between the two periods is primarily attributable to (1) non-cash fair value losses for our commodity derivatives of $172.3 million in the first quarter of 2011 compared to gains of $100.8 million in 2010, resulting in a $273.1 million negative change between the comparable quarters ($169.3 million after tax), (2) a $101.6 million gain on the sale of Genesis in the first quarter of 2010 ($63.0 million after tax), and (3) a $15.8 million loss in the first quarter of 2011 associated with repurchases of senior subordinated notes ($9.8 million after tax). Partially offsetting these decreases was an increase in oil and gas revenues of $175.3 million due to increased volumes attributable to a full quarter of production from the properties retained from the Encore Merger (versus 22 days of production in the first quarter of 2010), increased tertiary production, and higher oil prices. In-line with higher production volumes, our operating expenses increased across the board. Interest expense also increased significantly due to our additional debt incurred in conjunction with the Encore Merger.to:
| • | | A $103.1 million ($63.9 million after tax), or 21%, increase in revenue, made up of $214.4 million of additional revenue from higher realized commodity prices in the 2011 second quarter, partially offset by a decrease of $111.3 million of revenue primarily attributable to the absence in the most recent quarter of production from properties sold starting in May 2010; |
|
| • | | A $58.6 million increase in the non-cash fair value adjustment in the mark-to-market valuation of our commodities derivatives, principally attributable to oil futures (non-cash income of $183.8 million in the second quarter of 2011 compared to $125.2 million of such non-cash income in the second quarter of 2010); and |
|
| • | | $22.8 million of transaction and other costs related to the Encore Merger incurred in the 2010 period ($14.1 million after tax), which costs were negligible in the most recent quarter. |
During the firstsecond quarter of 2011, our oil and natural gas production, which was 92% oil, averaged 63,60464,919 BOE/d compared to 53,12584,111 BOE/d produced during the firstsecond quarter of 2010. This 10,479 BOE/d of additionaldrop in production is primarily attributable to (1) incremental average productionthe sale of 14,400 BOE/d from Rocky Mountain region properties acquired in the Encore Merger, and (2) increased tertiary production between the two quarters, offset by (3) a decrease of 6,750 BOE/d due to the sales of non-strategic legacy Encore assets and our interests in ENP after(which together had production of 20,526 BOE/d in last year’s second quarter), which were sold starting in May 2010, partially offset by increases in our quarterly tertiary and Bakken production. Our tertiary oil production averaged 30,771 Bbls/d during the second quarter of 2011, up 8% over the 28,507 Bbls/d during the second quarter a year earlier. Tertiary oil production was essentially flat sequentially (down 0.2%, or 54 Bbls/d) for the second quarter. Our Bakken oil production averaged 7,626 BOE/d during the second quarter of 2011, up 69% over production of 4,500 BOE/d during the second quarter of 2010 and sequentially up 33% from levels in the first quarter of 2010.2011. SeeResults of Operations — CO2 Operations andResults of Operations — Operating Results — Productionfor more information.
21
Tertiary oil production averaged 30,825 Bbls/d during the first quarterDENBURY RESOURCES INC.
Management’s Discussion and Analysis of 2011, representing a 14% increase over our average tertiary oil production of 27,023 Bbls/d during the first quarter of 2010. However, tertiary oil production was down slightly from the 31,139 Bbls/d produced during the fourth quarter of 2010. SeeFinancial Condition and Results of Operations — CO2 Operationsfor more information.
Oil prices during the firstsecond quarter of 2011 were considerably higher than prices during the firstsecond quarter of 2010. Our average oil and natural gas price received per BOE, excluding the impact of commodity derivative contracts, was $88.42$100.06 per BOE during the firstsecond quarter of 2011, compared to $69.21$63.76 per BOE during the firstsecond quarter of 2010, a 28%57% increase between the two periods. Including the impact of cash settlements on our commodity derivative contracts, our average oil and natural gas price per BOE was $88.70$98.21 per BOE during the firstsecond quarter of 2011 compared to $56.70$64.13 per BOE during the firstsecond quarter of 2010.
23
DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Debt Refinancing.In February 2011, we issued, at par, $400 million of 63/8% Senior Subordinated Notes due 2021. The net proceeds, together with cash on hand, were used to repurchase $525 million in principal amount of our outstanding 2013 Notes and 2015 Notes. Also, in February, we commenced cash tender offers to purchase $225 million principal amount of our 2013 Notes and $300 million principal amount of our 2015 Notes. Upon expiration of the tender offers in March 2011, we accepted for purchase $169.6 million in principal of the 2013 Notes at 100.625% of par and $220.9 million in principal of the 2015 Notes at 104.125% of par. We called the remaining 2013 and 2015 Notes, repurchased all of the remaining outstanding 2015 Notes at 103.75% of par on March 21, 2011 and repurchased all of the remaining outstanding 2013 Notes at par on April 1, 2011.2010, a 53% increase. During the firstsecond quarter of 2011, our oil price differentials (our received net oil price compared to NYMEX West Texas Intermediate (“WTI”) prices) improved significantly from a negative $4.13 per Bbl in the second quarter of 2010 to a positive $3.72 per Bbl in the second quarter of 2011, primarily due to the favorable price differential for crude oil sold under Louisiana Light Sweet (“LLS”) index pricing. SeeResults of Operations — Operating Results — Oil and Natural Gas Revenuesbelow for more information.
August 2011 Acquisition of Remaining Working Interest in Riley Ridge.On August 1, 2011, we recognizedacquired the remaining 57.5% working interest in the Riley Ridge Federal Unit (“Riley Ridge”) and a $15.8working interest of approximately 33% in the 28,000 acres adjacent to Riley Ridge. As a result of the transaction, we became the operator of both projects. The purchase price was approximately $191 million, losswhich includes a $15 million contingent payment to be paid at the time the property’s gas processing facility is operational and meets specific performance conditions, plus customary closing adjustments, including payments for capital expenditures incurred between the effective date of the purchase (April 1, 2011) and closing. We currently expect the gas processing facility to be operational with the first production of natural gas and helium from Riley Ridge during the fourth quarter of 2011. The CO2will be re-injected into the reservoir until we have completed an additional separation facility and a CO2pipeline to the field, which is expected to be completed in four or five years.
Combining this acquisition with the interest in Riley Ridge that we acquired in October 2010, we estimate that our total ownership at Riley Ridge currently contains estimated proved reserves of 435 Bcf of natural gas, 15.5 Bcf of helium and 2.4 Tcf of CO2. The adjacent 28,000 acres is estimated to contain additional probable reserves of 250 to 300 Bcf of natural gas, 9.5 to 11.5 Bcf of helium and 2.0 to 2.2 Tcf of CO2, net to our interest. The first production of natural gas and helium from Riley Ridge is expected to begin late in the fourth quarter of 2011, with initial production of CO2 expected in four to five years following construction of both additional facilities to separate the CO2 from the remaining gas stream, and a CO2 pipeline to the field.
Addition of Proved Oil and Natural Gas Reserves.We added 30.9 MMBOE of estimated proved reserves during the first six months. These reserve additions include 28.1 MMBOE of estimated proved reserves at our Bakken properties, and minor revisions to our other properties. These additions do not include estimated proved reserves of approximately 250 Bcf of natural gas (41.7 MMBOE) associated with the debt repurchases, includedRiley Ridge acquisitions completed in our income statement under the caption “Loss on early extinguishment of debt”.August discussed above.
March 2011 CO2Purchase Contracts.In March 2011, we entered into three long-term supply contracts to purchase CO2 from future anthropogenic sources in the Gulf Coast and Rocky Mountain regions. The three contracts are in addition to the previously disclosed long-term supply contracts Denbury currently has in place in the Gulf Coast, Rocky Mountain and Midwest regions. We will purchase 100% of the CO2 captured from the DKRW Advanced Fuels LLC’s Medicine Bow Fuel and Power LLC (“MBFP”) project in Medicine Bow, Wyoming, purchase 70% of the CO2 captured from Mississippi Power Company’s Kemper County Integrated Gasification Combined Cycle (“IGCC”) project in Mississippi, and purchase 100% of the CO2captured fromby Air Products LLC (“Air Products”) at a third-party refinery in Port Arthur, Texas. These three contracts each have an undisclosed source ininitial term of 15 to 16 years and include options to extend the Gulf Coast region.term. We estimate that these three sources will supply approximately 365 MMcf/d of CO2 for our enhanced oil recovery operations, although under certain circumstances, we may be obligated to purchase up to 460 MMcf/d, a portion of which would be at a reduced price per Mcf. We expect to begin taking delivery of approximately 200 MMCF/d of CO2 from the MBFP project in late 2014 or early 2015, 115 MMcf/d of CO2 from the IGCC project byin 2014, and 50 MMcf/d of CO2 from a Gulf Coast region sourceAir Products in late 2012. Our aggregate maximum purchase obligation for CO2 purchased under these three contracts would be approximately $110 million per year (assuming purchases of 460 MMcf/d), plus transportation, assuming a $100 per barrel NYMEX oil price. The purchase price of CO2 will fluctuate based on the changes in the price of oil. These
As is the case with all of our long-term supply contracts to purchase CO2, the three agreements entered into in March are subject to various contingencies. Construction on the IGCC and MBFP plants is in the initial stages and additional construction under the MBFP agreement is contingent upon securing debt financing and equity commitments and receipt of all necessary consents and approvals. The Air Products agreement is also contingent upon third party approvals for the necessary utilities and infrastructure.
22
DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
February 2011 Debt Refinancing.In February 2011, we issued, at par, $400 million of 6⅜% Senior Subordinated Notes due 2021. The net proceeds, together with cash on hand, were used to partially fund the repurchase of $525 million in principal amount of our outstanding 2013 Notes and 2015 Notes in cash tender offers to purchase agreements are contingent on completion or modification$225 million principal amount of our 2013 Notes and $300 million principal amount of our 2015 Notes. In the first quarter of 2011, we accepted for purchase $169.6 million in principal of the respective plants by their operators.2013 Notes at 100.625% of par and $220.9 million in principal of the 2015 Notes at 104.125% of par. We redeemed the remaining outstanding 2015 Notes at 103.75% of par during the first quarter of 2011 and all of the remaining outstanding 2013 Notes at par on April 1, 2011. During the three and six months ended June 30, 2011, we recognized $0.3 million and $16.1 million, respectively, of loss associated with the debt repurchases, included in our income statements under the caption “Loss on early extinguishment of debt”.
Capital Resources and Liquidity
In MarchJune 2011, commensurate with higher oil prices,when we signed the agreement to acquire the remaining interest in Riley Ridge, which closed in August 2011, our Board of Directors approved ana $50 million increase in our 2011 capital spending budget from $1.1 billionfor development of the Riley Ridge plant, increasing our projected 2011 oil and gas capital investments to $1.3$1.35 billion, excluding capitalized interest, tertiary start-up costs, acquisitions and divestitures, and net of equipment leases. Our current 2011 capital budget includes the following:
| • | | $450 million allocated for tertiary oil field expenditures; |
|
| • | | $350 million in the Bakken area of North Dakota; |
|
| • | | $250 million to be spent on our CO2 pipelines; |
|
| • | | $150200 million to be spent on CO2sources in the Jackson Dome and Riley Ridge areas; and |
|
| • | | $100 million on drilling, completion and other development activities in our other areas. |
This estimate also assumes that we fund approximately $60 million of budgeted equipment purchases with operating leases, which is dependent upon securing acceptable financing. Our net capital expenditures would increase by the amount of any shortfall in operating leases for this purchased equipment, and we anticipate funding any such additional capital expenditures under our Bank Credit Agreement.
Based on oil and natural gas commodity futures prices in early MayAugust 2011 and our current production forecasts, excluding acquisition costs, our 2011 capital budget, including capitalized interest and tertiary start-up costs, is $100$150 million to $200$250 million greater than our anticipated cash flow from operations. These expenditures will be funded with our excess cash on hand or, if necessary, borrowings under our $1.6 billion Bank Credit Agreement under which currently has no outstanding borrowings.
24
DENBURY RESOURCES INC.
Management’s Discussionat August 4, 2011, we had drawn $125 million, all of which was used as part of the funding of our August 1, 2011 Riley Ridge acquisition discussed above. Another potential source of funds would be proceeds if we should sell the units in Vanguard Natural Resources LLP units acquired in the sale of ENP, which have ranged in value between approximately $80 million and Analysis$100 million during the second quarter of Financial Condition and Results of Operations2011.
We continually monitor our capital spending and anticipated cash flows and believe that we can adjust our capital spending up or down depending on cash flows; however, any such reduction in capital spending could reduce our anticipated production levels in future years. For 2011, we have contracted for certain capital expenditures, including construction ofimpact the Greencore pipeline, processing facilities at Riley Ridge, and several drilling rigs, and therefore we cannot eliminate alltiming of our future production. There are potential limitations on the amount of capital commitmentsspending we can eliminate without penalties (refer toManagement’s Discussion and Analysis –— Capital Resources and Liquidity -— Off-Balance Sheet Arrangements — Commitments and Obligationsin our Annual Report on Form 10-K for the year ended December 31, 2010, for further information regarding these commitments). Seeand seeCO2Purchase Contractsabove andOff-Balance Sheet Arrangementsbelow for further information regarding additional commitments entered into during 2011). In addition to the potential flexibility in 2011. We believe that our $1.6capital spending plans, we have approximately $1.4 billion Bank Credit Agreementof unused liquidity under our bank credit line and have significant oil derivative contracts, which provide a $70 floor price floors through mid-2012 and an $80 floor price for the second halfend of 2012 on approximately 80%-85% of our currently anticipated proved oil production,(see Note 4 to the Unaudited Condensed Consolidated Financial Statements), which together should provide us with adequate liquidity and flexibility to meet our near-term capital spending plans if oil prices were to decrease significantly.
Our capital spending estimate also assumes that we fund approximately $60 million of budgeted equipment purchases with operating leases, the amount of which is dependent upon securing acceptable financing. Through August 1, 2011, we have funded approximately $27 million of these budgeted equipment purchases with operating leases. Our net capital expenditures would increase by the amount of any shortfall in operating leases for this purchased equipment, and we anticipate funding any such additional capital expenditures under our Bank Credit Agreement.
23
DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
In May 2011, we entered into our Fifth Amendment to the Bank Credit Agreement, reconfirming our current borrowing base of $1.6 billion, extending the maturity from March 2014 to May 2016, reducing certain margins and letter of credit fees, and adjusting the maximum permitted ratio of debt to adjusted EBITDA. See further discussion in Note 3 to the Unaudited Condensed Consolidated Financial Statements.
Capital Expenditure Summary.The following table of capital expenditures includes accrued capital for the threesix month periods of 2011 and 2010.2010:
| | | | | | | | | | | | | | |
| | Three Months Ended | | | Six Months Ended | |
| | March 31, | | | June 30, | |
In thousands | | 2011 | | 2010 | | | 2011 | | 2010 | |
Oil and natural gas exploration and development: | | |
Drilling | | $ | 91,732 | | $ | 48,261 | | | $ | 244,466 | | $ | 155,503 | |
Geological, geophysical, and acreage | | 6,666 | | 6,994 | | | 14,339 | | 15,121 | |
Facilities | | 51,814 | | 37,710 | | | 123,742 | | 73,712 | |
Recompletions | | 47,402 | | 28,536 | | | 104,878 | | 91,534 | |
Capitalized interest | | 7,700 | | 5,743 | | | 18,652 | | 13,681 | |
| | | | | | | | | | |
Total oil and natural gas exploration and development expenditures | | 205,314 | | 127,244 | | | 506,077 | | 349,551 | |
CO2 and other non-hydrocarbon gases - capital expenditures: | | |
Pipelines and facilities | | 24,737 | | 42,973 | | |
Acreage, geological and drilling | | 10,615 | | 11,907 | | |
CO2 and other non-hydrocarbon gases capital expenditures: | | |
Drilling | | | 28,768 | | 27,113 | |
Geological, geophysical, and acreage | | | 10,195 | | 4,299 | |
Facilities | | | 13,737 | | 12,245 | |
| | | | | | |
Total CO2 and other non-hydrocarbon gases capital expenditures | | | 52,700 | | 43,657 | |
| | | | | | |
Pipelines and plants capital expenditures: | | |
Pipelines and plants | | | 61,292 | | 92,500 | |
Capitalized interest | | 3,257 | | 15,569 | | | 5,499 | | 31,481 | |
| | | | | | | | | | |
Total CO2 and other non-hydrocarbon gases capital expenditures | | 38,609 | | 70,449 | | |
Total pipelines and plants capital expenditures | | | 66,791 | | 123,981 | |
| | | | | | | | | | |
Total capital expenditures excluding acquisitions | | 243,923 | | 197,693 | | | 625,568 | | 517,189 | |
| | | | | | | | | | |
Oil and natural gas property acquisitions | | 29,801 | | 340 | | | 32,482 | | 24,243 | |
Consideration for Encore Merger(1) | | - | | 2,952,515 | | |
Consideration for the Encore Merger(1) | | | — | | 2,952,515 | |
| | | | | | | | | | |
Total | | $ | 273,724 | | $ | 3,150,548 | | | $ | 658,050 | | $ | 3,493,947 | |
| | | | | | | | | | |
| | |
(1) | | Consideration given in the Encore Merger includes $2.09 billion for the fair value of Denbury common stock issued. |
Our capital expenditures for the first threesix months of 2011 were funded with $124.8$523.4 million of cash flow from operations and the remainder with cash on hand at the beginning of the period. Our capital expenditures for the first threesix months of 2010, excluding the Encore Merger, were funded with $113.2$384.3 million of cash flow from operations andalong with proceeds from the sale of our interests in Genesis.Genesis and the Southern Assets.
Off-Balance Sheet Arrangements.Our obligations that are not currently recorded on our balance sheet consist of our operating leases and various obligations for development and exploratory expenditures arising from purchase agreements, our capital expenditure program, or other transactions common to our industry. In addition, in order to recover our proved undeveloped reserves, we must also fund the associated future development costs as forecasted in our proved reserve reports. Our derivative contracts, which are recorded at fair value in our balance sheets, are discussed in Notes 4 and 5 to the Unaudited Condensed Consolidated Financial Statements.
In April 2011, we entered into three long-term drilling contracts. Our total commitment under these contracts is approximately $93 million, with $9 million expected to be paid during the remainder of 2011, $31 million in both 2012 and 2013, and $22 million in 2014.
2524
DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
In AprilMay 2011, we entered into three long-term drilling contracts.an agreement with Elk Petroleum to acquire a 65% working interest in Grieve Field, a planned CO2 enhanced oil recovery project located in Wyoming. Denbury will invest the first $28.5 million of capital and operating costs in Phase 1. In Phase 2 of the project, Denbury may fund, at Elk’s option, Elk’s 35% share of the next $34.3 million of capital and operating costs, with Denbury recouping its Phase 2 expenditures (plus interest) out of Elk’s 35% working interest share of production from the project. In connection with that agreement, we were assigned a CO2 purchase and CO2 transportation contract to purchase CO2 reserves from Exxon Mobil Corporation’s La Barge facility and transport the CO2 to Grieve Field beginning in March of 2012. Our totalannual commitment under thesethe CO2 purchase and transportation contracts is approximately $55.8$16 million with $5.2annually for 2 years and approximately $25 million expected to be paidannually for the remaining 8 years (assuming a $100 per barrel NYMEX oil price).
Our commitments and obligations consist of those detailed as of December 31, 2010 in 2011, $18.6 million in both 2012 and 2013, and $13.4 million in 2014.
Please refer toour 2010 Form 10-K underManagement’s Discussion and Analysis of Financial Condition and Results of Operationsand the section entitled-Off-Balance Sheet Arrangements –— Commitments and Obligations contained in our Annual Report on Form 10-K for, plus the year ended December 31, 2010 for further information regarding our commitmentslong-term drilling contracts described above, the Grieve Field obligations detailed above, and obligations. Also seeOverview –the three CO2Purchase Contractsfor discussion of additional purchase contracts we entered into during the first quarter of 2011.2011, which CO2 purchase contracts are subject to numerous contingencies, as discussed underOverview — CO2Purchase Contractsabove.
Results of Operations
CO2 Operations
Our focus on CO2operations is the primary strategy of our business and operations. We believe that there are significant additional oil reserves and production that can be obtained through the use of CO2, and we have outlined certain of this potential in our Annual Report on Form 10-K for the year ended December 31, 2010 and other public disclosures. In addition to its long-term effect, our focus on these types of operations impacts certain trends in our current and near-term operating results. Please refer toManagement’s Discussion and Analysis of Financial Condition and Results of Operationsand the section entitledCO2 Operationscontained in our Annual Report on Form 10-K for the year ended December 31, 2010 for further information regarding these matters.
During the firstsecond quarter of 2011, our CO2 production at Jackson Dome averaged 1,021992 MMcf/d as compared to an average of 802768 MMcf/d produced during the second quarter of 2010 and 1,021 MMcf/d produced during the first quarter of 2010 and 974 MMcf/d produced during the fourth quarter of 2010.2011. We used 91% of this production, or 926903 MMcf/d, in our tertiary operations during the firstsecond quarter of 2011, and sold the balance to our industrial customers, or to Genesis pursuant to our volumetric production payments. Refer toManagement’s Discussion and Analysis of Financial Condition and Results of Operations –— Capital Resources and Liquidity –— Off-Balance Sheet Arrangements –— Commitments and Obligationsin our Annual Report on Form 10-K for the year ended December 31, 2010 for further discussion on our CO2 delivery obligations. We recognized a negative proven CO2 reserve revision during the second quarter of approximately 239 Bcf at our Jackson Dome Dri-Dock prospect. This revision was a result of the second well in this formation not being a productive well and analysis of the reprocessed seismic data, which showed incremental faulting in the Dri-Dock reservoir. Even with this downward revision, we still anticipate that we have sufficient CO2reserves to develop our current Gulf Coast enhanced oil recovery program and we are continuing to drill additional wells to increase our productive capability and to test the significant probable and possible reserves at Jackson Dome. At December 31, 2010, our proven CO2 reserves at Jackson Dome were approximately 7.1 Tcf.
We spent approximately $0.25$0.27 per Mcf in operating expenses to produce our CO2 during the first threesix months of 2011, whichcomprised of $0.25 per Mcf during the first quarter of 2011 and $0.28 per Mcf during the second quarter of 2011. This rate is up significantly from our $0.20$0.22 per Mcf cost during the first three monthssecond quarter of 2010, due primarily to increased CO2 royalty expense as a result of higher oil prices (to which CO2 royalties are tied).
2625
DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following table summarizes our tertiary oil production and tertiary lease operating expense per Bbl for each quarter in 2010 and the first quarterand second quarters of 2011:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Average Daily Production (Bbls/d) | | Average Daily Production (Bbls/d) | |
| | First | | Second | | Third | | Fourth | | | | First | | | First | | Second | | Third | | Fourth | | | First | | Second | |
| | Quarter | | Quarter | | Quarter | | Quarter | | | | Quarter | | | Quarter | | Quarter | | Quarter | | Quarter | | | Quarter | | Quarter | |
Tertiary Oil Field | | 2010 | | 2010 | | 2010 | | 2010 | | | | 2011 | | | 2010 | | 2010 | | 2010 | | 2010 | | | 2011 | | 2011 | |
| | | | | | |
Phase 1: | | | | | | |
Brookhaven | | 3,416 | | 3,277 | | 3,323 | | 3,699 | | | | 3,664 | | | 3,416 | | 3,277 | | 3,323 | | 3,699 | | | 3,664 | | 3,213 | |
McComb area | | 2,289 | | 2,160 | | 2,484 | | 2,433 | | | | 2,161 | | | 2,289 | | 2,160 | | 2,484 | | 2,433 | | | 2,161 | | 1,983 | |
Mallalieu area | | 3,443 | | 3,628 | | 3,279 | | 3,164 | | | | 2,925 | | | 3,443 | | 3,628 | | 3,279 | | 3,164 | | | 2,925 | | 2,646 | |
Other | | 2,817 | | 3,282 | | 3,343 | | 3,361 | | | | 3,290 | | | 2,817 | | 3,282 | | 3,343 | | 3,361 | | | 3,290 | | 3,196 | |
Phase 2: | | | | | | |
Heidelberg | | 1,708 | | 1,857 | | 2,806 | | 3,422 | | | | 3,374 | | | 1,708 | | 1,857 | | 2,806 | | 3,422 | | | 3,374 | | 3,548 | |
Eucutta | | 3,792 | | 3,625 | | 3,284 | | 3,286 | | | | 3,247 | | | 3,792 | | 3,625 | | 3,284 | | 3,286 | | | 3,247 | | 3,114 | |
Soso | | 3,213 | | 3,207 | | 3,016 | | 2,828 | | | | 2,582 | | | 3,213 | | 3,207 | | 3,016 | | 2,828 | | | 2,582 | | 2,317 | |
Martinville | | 927 | | 764 | | 606 | | 586 | | | | 500 | | | 927 | | 764 | | 606 | | 586 | | | 500 | | 416 | |
Phase 3: | | | | | | |
Tinsley | | 4,419 | | 5,248 | | 6,024 | | 6,614 | | | | 6,567 | | | 4,419 | | 5,248 | | 6,024 | | 6,614 | | | 6,567 | | 6,990 | |
Phase 4: | | | | | | |
Cranfield | | 936 | | 811 | | 855 | | 1,043 | | | | 991 | | | 936 | | 811 | | 855 | | 1,043 | | | 991 | | 1,085 | |
Phase 5: | | | | | | |
Delhi | | 63 | | 648 | | 511 | | 703 | | | | 1,524 | | | 63 | | 648 | | 511 | | 703 | | | 1,524 | | 2,263 | |
| | | | | | | |
Total tertiary oil production | | 27,023 | | 28,507 | | 29,531 | | 31,139 | | | | 30,825 | | | 27,023 | | 28,507 | | 29,531 | | 31,139 | | | 30,825 | | 30,771 | |
| | | | | | | |
| | | | | | |
Tertiary operating expense per Bbl | | $ | 22.67 | | $ | 21.37 | | $ | 22.54 | | $ | 22.26 | | | | $ | 25.40 | | | $ | 22.67 | | $ | 21.37 | | $ | 22.54 | | $ | 22.26 | | | $ | 25.40 | | $ | 23.35 | |
| | | | | | |
Oil production from our tertiary operations increased to an average of 30,82530,771 Bbls/d during the firstsecond quarter of 2011, a 14%an 8% increase over our firstsecond quarter of 2010 tertiary production level of 27,02328,507 Bbls/d, primarily due to production growth in response to continued expansion of the tertiary floods in the Tinsley, Heidelberg and Delhi Fields. Offsetting these production gains were declines in our Mallalieu, Soso,more mature Phase 1 and Eucutta Fields, production from which has most likely peaked and will likely continue to decline in the future.Phase 2 fields (excluding Heidelberg).
The production growth rate at a tertiary flood varies from quarter to quarter as a tertiary field’s production may increase rapidly when wells respond to the CO2, plateau temporarily, and then resume its growth as additional areas of the field are developed. During a tertiary flood life cycle, facility capacity is increased from time to time, which occasionally requires temporary shutdowns during installation, thereby causing temporary declines in production. We also find it difficult to precisely predict when any given well will respond to the injected CO2 as the CO2 seldom travels through the rock consistently due to lack of heterogeneity in the oil bearingoil-bearing formations. We find all these fluctuations to be normal, and generally expect oil production at a tertiary field to increase over time until the entire field is developed, albeit sometimes in inconsistent patterns. These types of fluctuations were most noticeable at Tinsley and Heidelberg Fields in the first quarter of 2011, two of our fields which have exhibited strong production growth in recent periods. We expect our tertiary production to resume itsThese fields resumed their growth later this year, asduring the second quarter of 2011 and these temporary fluctuations have not changed our overall outlook for these fields.
With the Green Pipeline complete, weWe initiated CO2 injections at Oyster Bayou and Hastings Fields during June 2010 and December 2010, respectively. We currently anticipate tertiary production responses at Hastings Field in late 2011, or early 2012, depending on the date of completion ofassuming our CO2 recycle facilities at this field.field are completed on schedule. We anticipate first production at Oyster Bayou Field late in the first quarter of 2012, also dependant on the completion of CO2 recycle facilities. We received the regulatory approvals required to commence construction of the CO2 recycling facilities at Hastings and Oyster Bayou Fields in the fourth quarter of 2010, after extensive unforeseen regulatory delays, and began construction of these facilities in the first quarter of 2011.
27
DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
During the firstsecond quarter of 2011, operating costs for our tertiary properties averaged $23.35 per Bbl, down 8% from our first quarter 2011 average of $25.40 per Bbl, compareddue primarily to lower workover expenses between the respective periods, but 9% higher than our firstsecond quarter of 2010 average cost of $22.67$21.37 per Bbl, due primarily to higher utility and CO2costs. CO2 costs increased due to a 37% increase in injection volumes, primarily related to the ramping up of tertiary activity at our Heidelberg, Tinsley and Delhi fields, and a fourth quarter27% increase in the cost of 2010 average of $22.26 per Bbl. The per Bbl increase quarter to quarter was primarily due to increases in utilities, CO2costs (which areis variable and partially tied to oil prices), and workover expenses.. On a per Bbl basis, our cost of CO2 increased by $0.69from $5.05 per Bbl from $4.89during the second quarter of 2010 to $5.62 per Bbl during the second quarter of 2011 but remained relatively consistent with the $5.58 per Bbl level of these costs during the first quarter of 2010 to $5.58 per Bbl during the first quarter of 2011 and increased $0.03 from $5.55 per Bbl during the fourth quarter of 2010 due to slightly lower CO2injection levels at our tertiary producing fields. First2011. Second quarter of 2011 workover expenses increased $1.32of $2.53 per Bbl over thealso increased from second quarter of 2010 workover expenses of $1.62 per Bbl but decreased from first quarter of 20102011 levels and $1.39of $3.75 per Bbl over fourth quarter of 2010 levels as we acceleratedcompleted planned mechanical integrity test repairs at Brookhaven Field rather than performingand completed other workovers at Soso and Eucutta during the work throughout the year as originally planned.first quarter of 2011. For any specific field, we expect our tertiary lease operating expense per Bbl to be high initially and then decrease as production increases, ultimately leveling off until production begins to decline in the latter life of the field, when lease operating expense per Bblbarrel will again increase.
26
DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Operating Results
Certain of our operating results and statistics for the comparative second quarters and first threesix months of 2011 and 2010 are included in the following table:
| | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | Three Months Ended | | Six Months Ended | |
| | March 31, | | June 30, | | June 30, | |
In thousands, except per share and unit data | | 2011 | | 2010(1) | | 2011 | | 2010(1) | | 2011 | | 2010(1) | |
| | | | | |
Operating results: | | |
Net income (loss) attributable to Denbury stockholders | | $ | (14,190 | ) | | $ | 96,888 | | |
Net income (loss) per common share - basic | | | (0.04 | ) | | 0.33 | | |
Net income (loss) per common share - diluted | | | (0.04 | ) | | 0.32 | | |
Net income attributable to Denbury stockholders | | | $ | 259,246 | | $ | 135,367 | | $ | 245,056 | | $ | 232,255 | |
Net income per common share — basic | | | 0.65 | | 0.34 | | 0.62 | | 0.67 | |
Net income per common share — diluted | | | 0.64 | | 0.34 | | 0.61 | | 0.66 | |
Cash flow from operations | | 124,832 | | 113,168 | | | 398,521 | | 271,123 | | 523,353 | | 384,291 | |
Average daily production volumes: | | |
Bbls/d | | 58,460 | | 44,309 | | | 59,538 | | 65,942 | | 59,002 | | 55,185 | |
Mcf/d | | 30,866 | | 52,892 | | | 32,283 | | 109,014 | | 31,579 | | 81,108 | |
BOE/d | | 63,604 | | 53,125 | | | 64,919 | | 84,111 | | 64,265 | | 68,703 | |
Operating revenues: | | |
Oil sales | | $ | 492,838 | | $ | 305,204 | | | $ | 575,928 | | $ | 443,984 | | $ | 1,068,766 | | $ | 749,188 | |
Natural gas sales | | 13,354 | | 25,682 | | | 15,171 | | 44,044 | | 28,525 | | 69,726 | |
| | | | | | | | | | | | | |
Total oil and natural gas sales | | $ | 506,192 | | $ | 330,886 | | | $ | 591,099 | | $ | 488,028 | | $ | 1,097,291 | | $ | 818,914 | |
| | | | | | | | | | | | | |
Commodity derivative contracts:(2) | | |
Net cash receipts (payments) on settlement of commodity derivative contracts | | $ | 1,588 | | $ | (59,801 | ) | | $ | (10,942 | ) | | $ | 2,801 | | $ | (9,354 | ) | | $ | (57,000 | ) |
Non-cash fair value adjustment income (expense) | | | (172,338 | ) | | 100,839 | | |
Non-cash fair value adjustment income | | | 183,846 | | 125,190 | | 11,508 | | 226,029 | |
| | | | | | | | | | | | | |
Total income (expense) from commodity derivative contracts | | $ | (170,750 | ) | | $ | 41,038 | | |
Total income from commodity derivative contracts | | | $ | 172,904 | | $ | 127,991 | | $ | 2,154 | | $ | 169,029 | |
| | | | | | | | | | | | | |
Operating expenses: | | |
Lease operating | | $ | 127,097 | | $ | 96,220 | | | $ | 129,932 | | $ | 127,743 | | $ | 257,029 | | $ | 223,963 | |
Production taxes and marketing | | 32,751 | | 19,317 | | | 39,688 | | 38,100 | | 72,439 | | 57,417 | |
| | | | | | | | | | | | | |
Total production expenses | | $ | 159,848 | | $ | 115,537 | | | $ | 169,620 | | $ | 165,843 | | $ | 329,468 | | $ | 281,380 | |
| | | | | | | | | | | | | |
Unit prices - including impact of derivative settlements:(2) | | |
Unit prices — including impact of derivative settlements: (2) | | |
Oil price per Bbl | | $ | 92.72 | | $ | 60.60 | | | $ | 103.17 | | $ | 71.68 | | $ | 98.02 | | $ | 67.26 | |
Natural gas price per Mcf | | 7.19 | | 6.18 | | | 7.22 | | 6.12 | | 7.20 | | 6.14 | |
Unit prices - excluding impact of derivative settlements:(2) | | |
Unit prices — excluding impact of derivative settlements: (2) | | |
Oil price per Bbl | | $ | 93.67 | | $ | 76.53 | | | $ | 106.30 | | $ | 73.99 | | $ | 100.08 | | $ | 75.00 | |
Natural gas price per Mcf | | 4.81 | | 5.40 | | | 5.16 | | 4.44 | | 4.99 | | 4.75 | |
Oil and natural gas operating revenues and expenses per BOE: | | |
Oil and natural gas revenues | | $ | 88.42 | | $ | 69.21 | | | $ | 100.06 | | $ | 63.76 | | $ | 94.33 | | $ | 65.85 | |
| | | | | | | | | | | | | |
| | |
Oil and natural gas lease operating expenses | | $ | 22.20 | | $ | 20.12 | | | $ | 21.99 | | $ | 16.69 | | $ | 22.10 | | $ | 18.01 | |
Oil and natural gas production taxes and marketing expense | | 5.72 | | 4.04 | | | 6.72 | | 4.98 | | 6.23 | | 4.62 | |
| | | | | | | | | | | | | |
Total oil and natural gas production expenses | | $ | 27.92 | | $ | 24.16 | | | $ | 28.71 | | $ | 21.67 | | $ | 28.33 | | $ | 22.63 | |
| | | | | | | | | | | | | |
| | |
(1) | | Includes the results of operations of Encore properties and ENP from March 9, 2010 through March 31, 2010.the end of the period. |
|
(2) | | See Item 3,Qualitative and Quantitative Disclosures about Market Risk,for additional information concerning our commodity derivative contracts. |
2827
DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Production.Average daily production by area for each of the four quarters of 2010 and for the first quarterand second quarters of 2011 are shown below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Average Daily Production (BOE/d) | | Average Daily Production (BOE/d) | |
| | First | | Pro Forma | | Second | | Third | | Fourth | | | | First | | | First | | Pro Forma | | Second | | Third | | Fourth | | | First | | Second | |
| | Quarter | | First Quarter | | Quarter | | Quarter | | Quarter | | | | Quarter | | | Quarter | | First Quarter | | Quarter | | Quarter | | Quarter | | | Quarter | | Quarter | |
Operating Area | | 2010(1) | | 2010(2) | | 2010 | | 2010 | | 2010 | | | | 2011 | | | 2010(1) | | 2010(2) | | 2010 | | 2010 | | 2010 | | | 2011 | | 2011 | |
| | | | | | |
Gulf Coast Region: | | | | | | |
Tertiary oil fields | | 27,023 | | 27,023 | | 28,507 | | 29,531 | | 31,139 | | | | 30,825 | | | 27,023 | | 27,023 | | 28,507 | | 29,531 | | 31,139 | | | 30,825 | | 30,771 | |
Non-tertiary fields: | | | | | | |
Mississippi | | 7,829 | | 7,829 | | 8,967 | | 7,965 | | 7,293 | | | | 7,586 | | | 7,829 | | 7,829 | | 8,967 | | 7,965 | | 7,293 | | | 7,586 | | 7,333 | |
Texas | | 5,235 | | 5,235 | | 5,148 | | 4,824 | | 4,564 | | | | 4,371 | | | 5,235 | | 5,235 | | 5,148 | | 4,824 | | 4,564 | | | 4,371 | | 4,202 | |
Louisiana | | 662 | | 662 | | 775 | | 714 | | 687 | | | | 767 | | | 662 | | 662 | | 775 | | 714 | | 687 | | | 767 | | 659 | |
Alabama and other | | 997 | | 997 | | 1,078 | | 1,091 | | 1,026 | | | | 1,026 | | | 997 | | 997 | | 1,078 | | 1,091 | | 1,026 | | | 1,026 | | 1,084 | |
| | | | | | | | | | | | | | | | | | | | | |
Total Gulf Coast Region | | 41,746 | | 41,746 | | 44,475 | | 44,125 | | 44,709 | | | | 44,575 | | | 41,746 | | 41,746 | | 44,475 | | 44,125 | | 44,709 | | | 44,575 | | 44,049 | |
| | | | | | |
Rocky Mountain Region: | | | | | | |
Cedar Creek Anticline | | 2,537 | | 9,830 | | 9,967 | | 9,791 | | 9,328 | | | | 9,163 | | | 2,537 | | 9,830 | | 9,967 | | 9,791 | | 9,328 | | | 9,163 | | 8,925 | |
Bakken | | 890 | | 3,549 | | 4,500 | | 4,657 | | 5,193 | | | | 5,728 | | | 890 | | 3,549 | | 4,500 | | 4,657 | | 5,193 | | | 5,728 | | 7,626 | |
Bell Creek | | 252 | | 966 | | 997 | | 994 | | 957 | | | | 890 | | | 252 | | 966 | | 997 | | 994 | | 957 | | | 890 | | 936 | |
Paradox | | 173 | | 675 | | 702 | | 738 | | 716 | | | | 635 | | | 173 | | 675 | | 702 | | 738 | | 716 | | | 635 | | 690 | |
Other | | 777 | | 2,925 | | 2,944 | | 2,889 | | 2,809 | | | | 2,613 | | | 777 | | 2,925 | | 2,944 | | 2,889 | | 2,809 | | | 2,613 | | 2,693 | |
| | | | | | | | | | | | | | | | | | | | | |
Total Rocky Mountain Region | | 4,629 | | 17,945 | | 19,110 | | 19,069 | | 19,003 | | | | 19,029 | | | 4,629 | | 17,945 | | 19,110 | | 19,069 | | 19,003 | | | 19,029 | | 20,870 | |
| | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
Total Continuing Production | | 46,375 | | 59,691 | | 63,585 | | 63,194 | | 63,712 | | | | 63,604 | | | 46,375 | | 59,691 | | 63,585 | | 63,194 | | 63,712 | | | 63,604 | | 64,919 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | |
Disposed Properties: | | | | | | |
Legacy Encore properties | | 4,479 | | 17,853 | | 11,684 | | 5,906 | | 4,156 | | | | - | | | 4,479 | | 17,853 | | 11,684 | | 5,906 | | 4,156 | | | — | | — | |
ENP | | 2,271 | | 9,034 | | 8,842 | | 8,630 | | 8,567 | | | | - | | | 2,271 | | 9,034 | | 8,842 | | 8,630 | | 8,567 | | | — | | — | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | |
Total Production | | 53,125 | | 86,578 | | 84,111 | | 77,730 | | 76,435 | | | | 63,604 | | | 53,125 | | 86,578 | | 84,111 | | 77,730 | | 76,435 | | | 63,604 | | 64,919 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | |
| | | |
| | |
(1) | | Includes production of Encore and ENP from March 9, 2010 through March 31, 2010. |
|
| (2) | | Represents pro forma production assuming we had reported the production from the Encore Merger beginning January 1, 2010. |
As outlined in the above table, continuingContinuing production during the three months ended March 31,June 30, 2011 increased 7%1,334 BOE/d over the comparable 2010 production levels, and continuing production when including Encore’s pre-merger production increased from 61,649 BOE/d during the first quarterhalf of 2010 pro forma production levels.to 64,265 BOE/d during the first half of 2011. These increases were primarily due to the additional production from a 14% increase in our tertiary production and a 61% increase in productionincreases from the Bakken partiallyand our tertiary oil fields (see a discussion of our tertiary operations inCO2 Operationsabove), offset by normal declines in most of our other properties or declines resulting from a conversion of a portion of the field to a tertiary flood.non-tertiary properties. Additionally, our production from the Cedar Creek Anticline generally declines in periods of increasing prices due to a net profits interest associated with this production. Total production decreased 23% between the second quarters of 2010 and 2011 due to the sale of non-strategic legacy Encore properties during May 2010 through December 2010, as well as the sale of our interests in ENP in December 2010. On a year-to-date basis, total production decreased 6% between the first six months of 2010 and 2011 due primarily to the sale of the non-strategic Encore assets during 2010.
Production from our Bakken properties averaged 5,7287,626 BOE/d in the firstsecond quarter of 2011, a 61%69% increase from firstsecond quarter 2010 pro forma production levels and an increase of over 10% as33% compared to fourthfirst quarter 20102011 production levels. The production increases in the Bakken are due to a gradual acceleration of our drilling activities in the area, as we have increased our operated drilling rigs from two, at the time of the Encore acquisition in March 2010, to five operated rigs.rigs currently. We anticipate adding a sixth rig late in the third quarter or early fourth quarter of 2011 to test our acreage in the Almond area, and will likely add a seventh rig by the end of 2011. OurDuring the first quartersix months of 2011, we drilled and completed 16 operated wells in the Bakken. Our Bakken production for the first six months of 2011 was negatively impacted by severe winter weather and flooding which caused delays in well completions.completions and curtailments in oil production.
28
DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Our production during both the three and six months ended June 30, 2011 was 92% oil, as compared to 78% and 80%, during the three and six months ended June 30, 2010, respectively. This increase is due to the sales of the non-strategic Encore properties and ENP properties in 2010, which had a higher percentage of natural gas production, and increases in our tertiary and Bakken production, which are primarily oil.
Oil and Natural Gas Revenues.Although our production for the three and six months ended June 30, 2011 declined from comparable 2010 levels due to the asset sales discussed above (partially offset during the six-month period by lower production in 2010 prior to the Encore Merger which closed in March 2010), our oil and natural gas revenues increased significantly in the current periods due to higher oil prices. These changes in oil and natural gas revenues, excluding any impact of our commodity derivative contracts, are reflected in the following table:
| | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | | Six Months Ended June 30, | |
| | 2011 vs. 2010 | | | 2011 vs. 2010 | |
| | | | | | Percentage | | | | | | | Percentage | |
| | Increase | | | Increase | | | | | | | Increase | |
| | (Decrease) in | | | (Decrease) in | | | Increase (Decrease) | | | (Decrease) in | |
In thousands | | Revenues | | | Revenues | | | in Revenues | | | Revenues | |
Change in oil and natural gas revenues due to: | | | | | | | | | | | | | | | | |
Increase in commodity prices | | $ | 214,398 | | | | 44 | % | | $ | 331,259 | | | | 40 | % |
Decrease in production | | | (111,327 | ) | | | (23 | %) | | | (52,882 | ) | | | (6 | %) |
| | | | | | | | | | | | |
Total increase in oil and natural gas revenues | | $ | 103,071 | | | | 21 | % | | $ | 278,377 | | | | 34 | % |
| | | | | | | | | | | | |
Excluding any impact of our commodity derivative contracts, our net realized commodity prices and NYMEX differentials were as follows during the first and second quarters and first six month periods of 2011 and 2010:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Three Months Ended | | | Six Months Ended | |
| | March 31, | | | June 30, | | | June 30, | |
| | 2011 | | | 2010 | | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
Net Realized Prices: | | | | | | | | | | | | | | | | | | | | | | | | |
Oil price per Bbl | | $ | 93.67 | | | $ | 76.53 | | | $ | 106.30 | | | $ | 73.99 | | | $ | 100.08 | | | $ | 75.00 | |
Natural gas price per Mcf | | | 4.81 | | | | 5.40 | | | | 5.16 | | | | 4.44 | | | | 4.99 | | | | 4.75 | |
Price per BOE | | | 88.42 | | | | 69.21 | | | | 100.06 | | | | 63.76 | | | | 94.33 | | | | 65.85 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
NYMEX Differentials: | | | | | | | | | | | | | | | | | | | | | | | | |
Oil per Bbl | | $ | (0.59 | ) | | $ | (2.08 | ) | | $ | 3.72 | | | $ | (4.13 | ) | | $ | 1.64 | | | $ | (3.36 | ) |
Natural gas per Mcf | | | 0.61 | | | | 0.37 | | | | 0.78 | | | | 0.09 | | | | 0.70 | | | | 0.06 | |
During the second quarter of 2011, our oil price differentials improved significantly, primarily due to the favorable price differential for crude oil sold under LLS index pricing. Company-wide oil price differentials in the second quarter of 2011 were $3.72 per Bbl above NYMEX, as compared to an average negative differential of $4.13 per Bbl below NYMEX in the second quarter of 2010 and an average negative differential of $0.59 per Bbl during the first quarter of 2011. Our oil price differential in the second quarter of 2010 reflected production from the non-strategic Encore properties sold in 2010, which typically received lower oil prices than our legacy production. During the latter part of the first quarter, the LLS index price increased significantly more than NYMEX prices, causing the LLS differential to increase significantly, and it remained high throughout the second quarter. For the second quarter of 2011, this LLS differential averaged a positive $15.32 per barrel on a trade-month basis, as compared to a $9.28 positive differential in the first quarter of 2011 and a more typical $3.21 positive differential in
29
DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Our production during the three months ended March 31, 2011 was 92% oil as compared to 83% during the three months ended March 31, 2010. This increase is due to the sales of the non-strategic Encore properties and ENP properties in the second half of 2010, which had a higher percentage of natural gas production.
Oil and Natural Gas Revenues.Due to the significant increase in oil prices between the first three months of 2010 and 2011, our oil and natural gas revenues increased sharply during the first quarter of 2011 as compared to revenues in the first quarter of 2010. These changes in oil and natural gas revenues, excluding any impact of our commodity derivative contracts, are reflected in the following table:
| | | | | | | | |
| | Three Months Ended March 31, |
| | 2011 vs. 2010 |
| | | | | | Percentage |
| | Increase in | | Increase in |
In thousands | | Revenues | | Revenues |
| | | | |
Change in oil and natural gas revenues due to: | | | | | | | | |
Increase in commodity prices | | $ | 110,042 | | | | 33 | % |
Increase in production | | | 65,264 | | | | 20 | % |
| | | | |
Total increase in oil and natural gas revenues | | $ | 175,306 | | | | 53 | % |
| | | | |
Excluding any impact of our commodity derivative contracts, our net realized commodity prices and NYMEX differentials were as follows during the first three month period of 2011 and 2010:
| | | | | | | | |
| | Three Months Ended | |
| | March 31, |
| | 2011 | | 2010 |
| | | | |
Net Realized Prices: | | | | | | | | |
Oil price per Bbl | | $ | 93.67 | | | $ | 76.53 | |
Natural gas price per Mcf | | | 4.81 | | | | 5.40 | |
Price per BOE | | | 88.42 | | | | 69.21 | |
| | | | | | | | |
NYMEX Differentials: | | | | | | | | |
Oil per Bbl | | $ | (0.59 | ) | | $ | (2.08 | ) |
Natural gas per Mcf | | | 0.61 | | | | 0.37 | |
Our oil NYMEX differential improved during the three months ended March 31, 2011 as compared to our differential in the comparable period of 2010, primarily due to the favorable differential for crude oil sold under Light Louisiana Sweet (“LLS”) index prices, which are the sales prices for approximately 40% of our oil production. During the latter part of the first quarter, the LLS index price increased significantly more than increases in the NYMEX West Texas Intermediate crude oil price, trading as high as $20 over NYMEX. For the first quarter of 2011 this LLS-to-NYMEX differential averaged a positive $9.52 per barrel on a trade-month basis, as compared to a $4.07 differential in the fourth quarter of 2010 and a more typical $2.06 in the first quarter of 2010. While this differential is a significant portion of the pricing formula for approximately 40% of our oil production, other factors may prevent us from realizing the full differential. It is uncertain how long this LLS-to-NYMEXLLS differential will remain at this level. Ourlevel, Because our derivative contracts are based on NYMEX prices, they do not impact the differential we receive. We currently sell approximately (a) 40% of our crude oil based on the LLS index price, differential inalthough due to contract provisions we may not realize the first quarterfull differential; (b) approximately 40% based on WTI prices; and (c) approximately 20% based on various other indexes, most of 2010 was $2.08 per Bbl below NYMEX, which reflected onlyalso improved relative to WTI, but to a partial period for the acquired Encore properties, which typically receive lower oil prices than our legacy production.
30
DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operationslesser degree.
Commodity Derivative Contracts.The following tables summarize the impact that our commodity derivative contracts had on our operating results for the three and six months ended March 31,June 30, 2011 and 2010:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, | | Three Months Ended June 30, | |
| | 2011 | | 2010 | | 2011 | | 2010 | | 2011 | | 2010 | | 2011 | | 2010 | | 2011 | | 2010 | | 2011 | | 2010 | |
| | Oil | | Natural Gas | | Total Commodity | | Oil | | Natural Gas | | | |
In thousands | | Derivative Contracts | | Derivative Contracts | | Derivative Contracts | | Derivative Contracts | | Derivative Contracts | | Total Commodity Derivative Contracts | |
| | | | | | | |
Non-cash fair value gain (loss) | | $ | (167,064 | ) | | $ | 61,821 | | $ | (5,274 | ) | | $ | 39,018 | | $ | (172,338 | ) | | $ | 100,839 | | | $ | 187,194 | | $ | 145,099 | | $ | (3,348 | ) | | $ | (19,909 | ) | | $ | 183,846 | | $ | 125,190 | |
Cash settlement receipts (payments) | | | (5,028 | ) | | | (63,550 | ) | | 6,616 | | 3,749 | | 1,588 | | | (59,801 | ) | | | (16,972 | ) | | | (13,829 | ) | | 6,030 | | 16,630 | | | (10,942 | ) | | 2,801 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Total | | $ | (172,092 | ) | | $ | (1,729 | ) | | $ | 1,342 | | $ | 42,767 | | $ | (170,750 | ) | | $ | 41,038 | | | $ | 170,222 | | $ | 131,270 | | $ | 2,682 | | $ | (3,279 | ) | | $ | 172,904 | | $ | 127,991 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Six Months Ended June 30, | |
| | 2011 | | | 2010 | | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | Oil | | | Natural Gas | | | | |
In thousands | | Derivative Contracts | | | Derivative Contracts | | | Total Commodity Derivative Contracts | |
Non-cash fair value gain (loss) | | $ | 20,130 | | | | 206,920 | | | | (8,622 | ) | | | 19,109 | | | $ | 11,508 | | | $ | 226,029 | |
Cash settlement receipts (payments) | | | (22,000 | ) | | | (77,379 | ) | | | 12,646 | | | | 20,379 | | | | (9,354 | ) | | | (57,000 | ) |
| | | | | | | | | | | | | | | | | | |
Total | | $ | (1,870 | ) | | $ | 129,541 | | | $ | 4,024 | | | $ | 39,488 | | | $ | 2,154 | | | $ | 169,029 | |
| | | | | | | | | | | | | | | | | | |
Changes in commodity prices and the expiration of contracts cause fluctuations in the estimated fair value of our commodity derivative contracts. Because we do not utilize hedge accounting for our commodity derivative contracts, the changes in fair value of these contracts, as outlined above, are recognized currently in the income statement. See Notes 4 and 5 to the Unaudited Condensed Consolidated Financial Statements for additional information regarding our commodity derivative contracts.
Production Expenses.Our lease operating expenses increased approximately 32% between2% during the three months ended March 31,June 30, 2011 andcompared to the same period in 2010 primarily as a result of:of the increased CO2 injections as we continued to ramp up tertiary activities at Tinsley, Heidelberg and Delhi fields during 2010 and 2011, the cost of CO2 (which are variable and partially tied to oil prices) and workover expenses on our tertiary operations (see discussion of those expenses underCO2 Operations), offset by the sale of the non-strategic legacy Encore and ENP properties during 2010.
| • | | the completion of the Encore Merger on March 9, 2010; |
|
| • | | our increasing emphasis on tertiary operations and additional tertiary fields moving into the productive phase (see discussion of those expenses underCO2 Operations); |
|
| • | | higher CO2costs, primarily due to increasing oil prices (see discussion of those expenses underCO2 Operations); |
|
| • | | increasing personnel and related costs resulting primarily from the Encore Merger; and |
|
| • | | increased workover costs primarily in our CO2operations (see discussion of those expenses underCO2 Operations). |
The 15% increase in lease operating expense during the six months ended June 30, 2011 compared to 2010 was further impacted by the inclusion in the 2011 period of a full six months of lease operating expense related to properties acquired in the Encore Merger on March 9, 2010. Lease operating expense per BOE averaged $22.20$21.99 per BOE and $22.10 per BOE for the three and six months ended March 31,June 30, 2011, as compared to $20.12$16.69 per BOE and $18.01 per BOE for the same periodperiods in 2010. These increases from the respective prior periods are attributable to the sale of the non-strategic Encore and ENP properties from May 2010 through December 2010, which generally had a lower operating cost per BOE than Denbury’s legacy properties. However, second quarter 2011 lease operating expenses per BOE decreased from $22.20 per BOE in the first quarter of 2011. Our tertiary operating costs, which have historically been higher than our company-wide operating costs, averaged $25.40$23.35 per BOE and $24.37 per BOE during the three and six months ended March 31,June 30, 2011, compared to $22.67$21.37 per BOE and $22.00 per BOE for the same periodperiods in 2010. SeeCO2 Operationsfor a more detailed discussion.
Production taxes and marketing expenses generally change in proportion to commodity prices and production volumes, and as such, increased 70% during the three months ended March 31, 2011, as compared to the same period in 2010. This compares to an increase in oil and natural gas revenues of 53% during the three months ended March 31, 2011. The addition of properties in other operating areas acquired in the Encore Merger also affected these costs. Transportation and plant processing fees increased approximately $1.4 million during the three months ended March 31, 2011 and 2010, primarily due to the addition of properties in other operating areas acquired in the Encore Merger.
General and Administrative Expenses
General and administrative (“G&A”) expenses increased on both a gross and per BOE basis between the three months ended March 31, 2011 and 2010 as set forth below:
| | | | | | | | |
| | Three Months Ended |
| | March 31, |
In thousands, except per BOE data and employees | | 2011 | | 2010 |
| | | | |
Gross cash G&A expense | | $ | 67,697 | | | $ | 48,274 | |
Gross stock-based compensation | | | 11,337 | | | | 9,939 | |
State franchise taxes | | | 1,159 | | | | 1,070 | |
Operator labor and overhead recovery charges | | | (29,716 | ) | | | (22,045 | ) |
Capitalized exploration and development costs | | | (6,631 | ) | | | (4,529 | ) |
| | | | |
Net G&A expense | | $ | 43,846 | | | $ | 32,709 | |
| | | | |
G&A per BOE: | | | | | | | | |
Net cash G&A expense | | $ | 5.86 | | | $ | 4.84 | |
Net stock-based compensation | | | 1.60 | | | | 1.78 | |
State franchise taxes | | | 0.20 | | | | 0.22 | |
| | | | |
Net G&A expense | | $ | 7.66 | | | $ | 6.84 | |
| | | | |
Employees as of March 31 | | | 1,182 | | | | 1,251 | |
| | | | |
3130
DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Generally, production taxes change in relation to oil and natural gas revenues, and marketing expenses change in relation to production volumes. The 21% increase in oil and natural gas revenues between the second quarters of 2010 and 2011 contributed to severance taxes increasing from $28.7 to $33.4 million, respectively. Likewise, the 34% increase in oil and natural gas revenues between the first six months of 2010 and 2011 contributed to severance taxes increasing from $43.6 million to $60.9 million, respectively. These severance tax increases in both comparative periods were partially offset by lower marketing expenses primarily attributable to lower production volumes in 2011.
General and Administrative Expenses (“G&A”)
| | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Six Months Ended | |
| | June 30, | | | June 30, | |
In thousands, except per BOE data and employees | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
Gross cash G&A expense | | $ | 60,137 | | | $ | 57,909 | | | $ | 127,834 | | | $ | 106,183 | |
Gross stock-based compensation | | | 9,687 | | | | 7,363 | | | | 21,024 | | | | 17,302 | |
State franchise taxes | | | 1,668 | | | | 965 | | | | 2,827 | | | | 2,035 | |
Operator labor and overhead recovery charges | | | (31,423 | ) | | | (29,086 | ) | | | (61,139 | ) | | | (51,131 | ) |
Capitalized exploration and development costs | | | (9,169 | ) | | | (5,959 | ) | | | (15,800 | ) | | | (10,488 | ) |
| | | | | | | | | | | | |
Net G&A expense | | $ | 30,900 | | | $ | 31,192 | | | $ | 74,746 | | | $ | 63,901 | |
| | | | | | | | | | | | |
G&A per BOE: | | | | | | | | | | | | | | | | |
Net cash G&A expense | | $ | 3.73 | | | $ | 3.15 | | | $ | 4.78 | | | $ | 3.81 | |
Net stock-based compensation | | | 1.22 | | | | 0.79 | | | | 1.41 | | | | 1.17 | |
State franchise taxes | | | 0.28 | | | | 0.13 | | | | 0.24 | | | | 0.16 | |
| | | | | | | | | | | | |
Net G&A expense | | $ | 5.23 | | | $ | 4.07 | | | $ | 6.43 | | | $ | 5.14 | |
| | | | | | | | | | | | |
Employees as of June 30 | | | 1,283 | | | | 1,304 | | | | 1,283 | | | | 1,304 | |
| | | | | | | | | | | | |
Gross cash G&A expenses increased $19.4$2.2 million (40%(4%) and $21.7 million (20%) during the three and six months ended March 31,June 30, 2011, respectively, as compared to the same periodperiods of 2010,2010. The increase between the comparative second quarters is reflective of higher salary costs which we consider necessary in order to remain competitive in our industry. The year-to-date comparative increase is primarily due toimpacted by increased expense resulting from the Encore Merger which closedas the 2010 period includes the effect of the Encore Merger beginning on the acquisition date, March 9, 2010. The number of employees at March 31,June 30, 2011, compared to March 31,June 30, 2010, decreased slightly, by 6%2%, as manyprimarily due to the departure of Encore transition employees who did not accept permanent positions with Denbury and who completed their pre-defined transition period in early 2011.period. However, compensation and personnel costs were less for the three months ended March 31, 2010, as the compensation and personnel costs for Encore employees were included in our G&A expenses beginning March 9, 2010, the date of the Encore Merger. Priorprior to the Encore Merger, on March 9, 2010, our headcount was 856 employees. The largest increases were related to personnel costs, including salaries, payroll taxes and our 401(k) match. Wage increases also contributed to the increase in G&A, as we consider this necessary in order to remain competitive in our industry.
Additional expense attributable to the legacy Encore office leases and the new Denbury headquarters lease, together with related moving costs, contributed to the higher cash G&A expense during the first quartersix months of 2011. Additionally, stock-based compensation expense increased $1.4$2.3 million for the second quarter 2011 when compared to levels in the same period of 2010, due primarily to the effect of Encore’s employees being included for a full quarterhigher compensation levels.
Gross cash G&A expenses decreased $7.6 million, or 11% from levels in 2011 versus only 22 days during the first quarter of 2010.2011, due primarily to lower compensation and employee-related costs and lower professional fees in the current quarter. The first quarter of 2011 included higher payroll tax burdens and 401(k) matching contribution associated with bonus payouts, the true-up of long-term incentive compensation estimates, incremental costs associated with relocating our headquarters and higher professional fees associated with year-end work.
The increase in gross G&A expense during the three and six months ended March 31,June 30, 2011, as compared to those costs in the same periodperiods of 2010, was offset in part by an increase in operator overhead recovery charges. Our well operating agreements allow us, when we are the operator, to charge a well with a specified overhead rate during the drilling phase and also to charge a monthly fixed overhead rate for each producing well. As a result of additional operated wells from acquisitions, additional tertiary operations, drilling activity during the past year, and increased compensation expense, the amount we recovered as operator labor and overhead charges increased by 35%8% and 20% during the three and six months ended March 31,June 30, 2011, as compared to the same periodperiods in 2010. Capitalized exploration and development costs also increased between the periods, primarily due to increased compensation costs.costs subject to capitalization.
31
DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The net effect of these changes resulted in a 34% increase1% decrease (a 12%29% increase on a per BOE basis) in G&A expense between the comparable firstsecond quarters of 2011 and 2010. Lower production in the most recent quarter attributable to the 2010 sale of properties was the primary factor relating to the higher cost per BOE, as any cost savings as a result of the property sales were offset by other expenses, including compensation increases effective at the beginning of 2011 and incremental expense attributable to the legacy Encore office leases and the new Denbury headquarters noted above.
Interest and Financing Expenses
| | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | Three Months Ended | | Six Months Ended | |
| | March 31, | | June 30, | | June 30, | |
In thousands, except per BOE data and interest rates | | 2011 | | 2010 | | 2011 | | 2010 | | 2011 | | 2010 | |
| | | | | |
Cash interest expense | | $ | 54,206 | | $ | 44,974 | | |
Non-cash interest expense | | 5,528 | | 2,754 | | |
Cash interest | | | $ | 50,509 | | $ | 60,966 | | $ | 104,715 | | $ | 105,940 | |
Non-cash interest | | | 4,934 | | 6,367 | | 10,462 | | 9,121 | |
Less: capitalized interest | | | (10,957 | ) | | | (21,312 | ) | | | (13,194 | ) | | | (23,850 | ) | | | (24,151 | ) | | | (45,162 | ) |
| | | | | | | | | | | | | |
Interest expense | | $ | 48,777 | | $ | 26,416 | | |
Interest expense, net | | | $ | 42,249 | | $ | 43,483 | | $ | 91,026 | | $ | 69,899 | |
| | | | | | | | | | | | | |
Interest income and other | | $ | (3,049 | ) | | $ | 1,870 | | | $ | 4,955 | | $ | 4,520 | | $ | 8,004 | | $ | 6,390 | |
Net cash interest expense and other income per BOE (1) | | $ | 7.10 | | $ | 4.67 | | | $ | 5.54 | | $ | 4.43 | | $ | 6.31 | | $ | 4.53 | |
Average debt outstanding | | $ | 2,514,621 | | $ | 2,225,700 | | | $ | 2,305,104 | | $ | 3,152,564 | | $ | 2,409,284 | | $ | 2,689,894 | |
Average interest rate (2) | | | 8.3 | % | | | 8.1 | % | | | 8.8 | % | | | 7.7 | % | | | 8.7 | % | | | 7.9 | % |
| | |
(1) | | Cash interest expense less capitalized interest less interest income and other income on a per BOE basis. |
|
(2) | | Includes commitment fees but excludes debt issue costs and amortization of discount and premium. |
InterestCash interest expense increased $22.4decreased $10.5 million during the three months ended March 31,month period ending June 30, 2011, as compared to the same period in 2010, primarily due to the increasea decrease in our average debt outstanding to financeoutstanding. Our debt level increased in early 2010 as a result of the Encore Merger which closedand decreased throughout 2010 and in March 2010, a portion of which wasearly 2011 as we repaid during 2010debt with proceeds from the sale of non-strategic legacy Encore assets and our ENP ownership interest. The increase inYear-to-date cash interest expense betweenremained relatively consistent with that incurred in the comparativesame period in 2010. The decrease in cash interest expense during both the three and six month comparative periods was also attributable to a 49% decrease in ouroffset by lower capitalized interest relating primarily to the Green Pipeline, which was completed and placed into service duringat the second halfend of June 2010.
32
DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
| | | | | | | | |
Depletion, Depreciation, and Amortization | | | |
| | Three Months Ended | |
| | March 31, | |
In thousands, except per BOE data | | 2011 | | | 2010 | |
Depletion, depreciation, and amortization (“DD&A”) of oil and natural gas properties | | $ | 82,086 | | | $ | 71,197 | |
Depletion and depreciation of CO2 assets | | | 4,590 | | | | 5,300 | |
Asset retirement obligations | | | 1,563 | | | | 1,107 | |
Depreciation of other fixed assets | | | 5,355 | | | | 4,268 | |
| | | | | | |
Total DD&A | | $ | 93,594 | | | $ | 81,872 | |
| | | | | | |
| | | | | | | | |
DD&A per BOE: | | | | | | | | |
Oil and natural gas properties | | $ | 14.61 | | | $ | 15.12 | |
CO2 assets and other fixed assets | | | 1.74 | | | | 2.00 | |
| | | | | | |
Total DD&A cost per BOE | | $ | 16.35 | | | $ | 17.12 | |
| | | | | | |
Depletion, Depreciation, and Amortization | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Six Months Ended | |
| | June 30, | | | June 30, | |
In thousands, except per BOE data | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
Depletion, depreciation, and amortization (“DD&A”) of oil and natural gas properties | | $ | 91,961 | | | $ | 116,034 | | | $ | 174,047 | | | $ | 187,231 | |
Depletion and depreciation of CO2 assets | | | 4,588 | | | | 5,680 | | | | 9,178 | | | | 10,980 | |
Asset retirement obligations | | | 1,696 | | | | 1,692 | | | | 3,259 | | | | 2,799 | |
Depreciation of other fixed assets | | | 5,250 | | | | 5,803 | | | | 10,605 | | | | 10,071 | |
| | | | | | | | | | | | |
Total DD&A | | $ | 103,495 | | | $ | 129,209 | | | $ | 197,089 | | | $ | 211,081 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
DD&A per BOE: | | | | | | | | | | | | | | | | |
Oil and natural gas properties | | $ | 15.85 | | | $ | 15.38 | | | $ | 15.24 | | | $ | 15.28 | |
CO2 assets and other fixed assets | | | 1.67 | | | | 1.50 | | | | 1.70 | | | | 1.69 | |
| | | | | | | | | | | | |
Total DD&A cost per BOE | | $ | 17.52 | | | $ | 16.88 | | | $ | 16.94 | | | $ | 16.97 | |
| | | | | | | | | | | | |
Depletion of oil and natural gas properties increaseddecreased on an absolute dollars basis during the three and six months ended March 31,June 30, 2011 as compared to the same periodperiods of 2010, primarily due to the sale of non-strategic legacy Encore Merger. However,assets and our ownership interests in ENP during 2010. Depletion of oil and gas properties increased on a per BOE basis our DD&A expense decreased from quarter-to-quarterduring the second quarter of 2011 compared to 2010, primarily due to higher finding and development costs per barrel associated with the incremental production attributable to the properties acquired from Encore, the acquisition of Riley Ridge,Bakken capital program and higher tertiary productionupward revisions in the first quarter of 2011.estimated future development costs.
We continually evaluate the performance of our tertiary projects, and if performance indicates that we are reasonably certain of recovering additional reserves from these floods, we recognize those incremental reserves in that quarter. Since we adjust our DD&A rate each quarter based on any changes in our estimates of oil and natural gas reserves and costs, our DD&A rate could change significantly in the future.
Our DD&A expense for our CO2 assets decreased on an absolute basis for the three and six months ended March 31,June 30, 2011 compared to the priorsame periods in 2010 due to proved CO2 reserve increases at Jackson Dome and Riley Ridge at the end of 2010. On a per BOE basis, DD&A expense for our CO2 assets and other fixed assets decreasedincreased for the three months ended March 31,June 30, 2011 compared to those in the prior yearprior-year quarter due to increaseddecreased oil and natural gas production volumes as a result of the sale of non-strategic Encore Merger, which closedproperties and our interests in March 2010, and as a result of proved CO2 reserve additions noted above.ENP during 2010.
Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. We did not have a ceiling test write-down at March 31,June 30, 2011. However, if oil and natural gas prices were to decrease significantly in subsequent periods, we may be required to record write-downs under the full cost pool ceiling test in the future. The possibility and amount of any future write-down is difficult to predict, and will depend upon oil and natural gas prices, the incremental proved reserves that may be added each period, revisions to previous reserve estimates and future capital expenditures, and additional capital spent.
Encore Transaction and Other Costs
FASCBusiness Combinationstopic requires that all transaction-related costs (advisory, legal, accounting, due diligence, integration, etc.) be expensed as incurred. We recognized transaction and other costs of $2.4$2.0 million and $45.0$4.4 million for the three and six months ended March 31,June 30, 2011, and 2010, respectively, associated with the Encore Merger, including $1.8 million and $1.2$3.6 million, respectively, related to severance costs. Transaction and other costs of $22.8 million and $67.8 million for the three and six months ended June 30, 2010, respectively, included $19.5 million and $20.7 million, respectively, of severance costs, and were significantly higher than 2011 levels. We anticipate that these severance costs will decline in the remainder of 2011 as the integration winds down and fewer former Encore transition employees remain.
33
DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
| | | | | | | | |
Income Taxes | | | |
| | Three Months Ended | |
| | March 31, | |
In thousands, except per BOE amounts and tax rates | | 2011 | | | 2010 | |
Current income tax provision (benefit) | | $ | (848) | | | $ | 669 | |
Deferred income tax provision (benefit) | | | (7,908) | | | | 76,272 | |
| | | | | | |
Total income tax provision (benefit) | | $ | (8,756) | | | $ | 76,941 | |
| | | | | | |
Average income tax provision per BOE | | $ | (1.53) | | | $ | 16.09 | |
Effective tax rate | | | 38.2% | | | | 43.4% | |
Income Taxes | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Six Months Ended | |
| | June 30, | | | June 30, | |
In thousands, except per BOE amounts and tax rates | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
Current income tax provision | | $ | 12,028 | | | $ | 6,941 | | | $ | 11,180 | | | $ | 7,610 | |
Deferred income tax provision | | | 152,528 | | | | 74,422 | | | | 144,620 | | | | 150,694 | |
| | | | | | | | | | | | |
Total income tax provision | | $ | 164,556 | | | $ | 81,363 | | | $ | 155,800 | | | $ | 158,304 | |
| | | | | | | | | | | | |
Average income tax provision per BOE | | $ | 27.85 | | | $ | 10.63 | | | $ | 13.39 | | | $ | 12.73 | |
Effective tax rate | | | 38.8 | % | | | 35.1 | % | | | 38.9 | % | | | 38.7 | % |
Our income taxes are based on an estimated statutory rate of approximately 38%. Our effective tax rate for the firstsecond quarter of 2011 was slightly higher compared to our statutory rate, primarily due to nondeductible compensation.expenses. Our effective tax rate for the comparativesecond quarter of 2010 was higher than the historical statutory ratelower due to the remeasurement of our deferred tax liabilities as a result of the May 2010 sale of certain legacy Encore Mergerproperties in the first quarter of 2010 thatPermian Basin, Mid-continent area and East Texas Basin (the “Southern Assets”), which resulted in an additional income tax provisionbenefit of approximately $10 million. During$3 million recorded in the threesecond quarter of 2010. The nondeductible expenses in 2011 and the income tax benefit recorded in 2010 resulted in a slight increase in the effective tax rate, to 38.9%, during the six months ended March 31, 2010,June 30, 2011, as compared to 38.7% in the six months ended June 30, 2010. The current income tax expense representedrepresents our state income taxes primarily related toduring the sale of our interest in Genesis.three and six months ended June 30, 2011 and 2010.
As of March 31,June 30, 2011, we had an estimated $39.8 million of enhanced oil recovery credits to carry forward related to our tertiary operations, and $34.5 million of alternative minimum tax credits that can be utilized to reduce our current income taxes during 2011 or future years. The enhanced oil recovery credits do not begin to expire until 2024. Since the ability to earn additional enhanced oil recovery credits is based upon the level of oil prices, we would not currently expect to earn additional enhanced oil recovery credits unless oil prices were to significantly deteriorate.
In the third quarter of 2008, we obtained approval from the National Office of the Internal Revenue Service (“IRS”) to change our method of tax accounting for certain assets used in our tertiary oilfield recovery operations. As a result of the approved change in method of tax accounting, beginning with the 2007 tax year we began to deduct, rather than capitalize, such costs for tax purposes, and applied for tax refunds associated with such change for our 2004 and 2006 tax years. Notwithstanding its consent to our change in tax accounting in 2008, the IRS subsequently exercised its prerogative to challenge the tax accounting method we used. In late January 2011, we received a Technical Advice Memorandum (“TAM”) issued by the IRS National Office disapproving our method of accounting and revoking its consent to our change, on a prospective basis only, commencing January 1, 2011. Henceforth, beginning with the 2011 tax year, we are returning to capitalizing and depreciating the costs of these assets for tax purposes. As a result of the prospective nature of the IRS’s determination, there should be no change in our position with respect to the deductibility of these costs for 2007, 2008, 2009 and 2010. However, refund claims of $10.6 million for tax years through 2006 are pending and are subject topending review by the Joint Committee on Taxation of the U.S. Congress. We are unable to assess the outcome of any such review, nor how that outcome may affect the other years covered by the TAM.
The current administration in Washington D.C. is attempting to removePresident’s 2012 budget, as well as certain Congressional legislative initiatives, have proposed repealing many tax incentives for the oil and gas industry. Those items that would have the most significant impact on us would include the loss of the domestic manufacturing deduction, as well as the repeal of the immediate expensing of intangible drilling costs and tertiary injectant costs.costs, and the elimination of the percentage depletion allowance. It is uncertain whether these or notsimilar tax law changes will be enacted, and if so what the effective date of any such changes might be, although the current administration will be successful in changing the laws, but ifproposals would not take effect until 2012. If some or all of these proposals were enacted and included us, they were successful, it would likely increase the amount of cash taxes that we pay. Should cash taxes increase significantly, itpay in future periods, and, accordingly, could impact our forecasted 2011 capital expenditure budget.
34
DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Per BOE Data
The following table summarizes our cash flow, DD&A, and results of operations on a per BOE basis for the comparative periods. Each of the individual components is discussed above.
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Three Months Ended | | Six Months Ended | |
| | March 31, | | June 30, | | June 30, | |
Per BOE data | | 2011 | | 2010 | | 2011 | | 2010 | | 2011 | | 2010 | |
Oil and natural gas revenues | | $ | 88.42 | | $ | 69.21 | | | $ | 100.06 | | $ | 63.76 | | $ | 94.33 | | $ | 65.85 | |
Gain (loss) on settlements of derivative contracts | | 0.28 | | | (12.51 | ) | | | (1.85 | ) | | 0.37 | | | (0.80 | ) | | | (4.58 | ) |
Lease operating expenses | | | (22.20 | ) | | | (20.12 | ) | | | (21.99 | ) | | | (16.69 | ) | | | (22.10 | ) | | | (18.01 | ) |
Production taxes and marketing expenses | | | (5.72 | ) | | | (4.04 | ) | | | (6.72 | ) | | | (4.98 | ) | | | (6.23 | ) | | | (4.62 | ) |
| | | | | | | | | | | | | |
Production netback | | 60.78 | | 32.54 | | | 69.50 | | 42.46 | | 65.20 | | 38.64 | |
Non-tertiary CO2 operating margin | | 0.48 | | 0.65 | | | 0.59 | | 0.39 | | 0.53 | | 0.49 | |
General and administrative expenses | | | (7.66 | ) | | | (6.84 | ) | | | (5.23 | ) | | | (4.07 | ) | | | (6.43 | ) | | | (5.14 | ) |
Transaction and other costs related to the Encore Merger | | | (0.41 | ) | | | (9.41 | ) | |
Transactions and other costs related to the Encore Merger | | | | (0.34 | ) | | | (2.98 | ) | | | (0.38 | ) | | | (5.45 | ) |
Net cash interest expense and other income | | | (7.10 | ) | | | (4.67 | ) | | | (5.54 | ) | | | (4.43 | ) | | | (6.31 | ) | | | (4.53 | ) |
Current income taxes and other | | 1.29 | | 1.53 | | | | (0.74 | ) | | 0.10 | | 0.28 | | 0.66 | |
Changes in assets and liabilities relating to operations | | | (25.57 | ) | | 9.87 | | | 9.22 | | 3.95 | | | (7.90 | ) | | 6.23 | |
| | | | | | | | | | | | | |
Cash flow from operations | | 21.81 | | 23.67 | | | 67.46 | | 35.42 | | 44.99 | | 30.90 | |
DD&A | | | (16.35 | ) | | | (17.12 | ) | | | (17.52 | ) | | | (16.88 | ) | | | (16.94 | ) | | | (16.97 | ) |
Deferred income taxes | | 1.38 | | | (15.95 | ) | | | (25.82 | ) | | | (9.72 | ) | | | (12.43 | ) | | | (12.12 | ) |
Gain on sale of interests in Genesis | | - | | 21.24 | | | — | | — | | — | | 8.17 | |
Loss on early extinguishment of debt | | | (2.76 | ) | | - | | | | (0.06 | ) | | — | | | (1.39 | ) | | — | |
Non-cash fair value derivative adjustments | | | (30.11 | ) | | 21.13 | | | 31.12 | | 16.45 | | 0.99 | | 18.25 | |
Net income attributable to noncontrolling interest | | - | | | (0.69 | ) | | — | | 1.95 | | — | | 1.47 | |
Changes in assets and liabilities and other non-cash items | | 23.55 | | | (12.02 | ) | | | (11.30 | ) | | | (9.53 | ) | | 5.85 | | | (11.02 | ) |
| | | | | | | | | | | | | |
Net income (loss) attributable to Denbury stockholders | | $ | (2.48 | ) | | $ | 20.26 | | |
Net income attributable to Denbury stockholders | | | $ | 43.88 | | $ | 17.69 | | $ | 21.07 | | $ | 18.68 | |
| | | | | | | | | | | | | |
Critical Accounting Policies
For additional discussion of our critical accounting policies, which remain unchanged, seeManagement’s Discussion and Analysis of Financial Condition and Results of Operationsin our Annual Report on Form 10-K for the year ended December 31, 2010.
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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Forward-Looking Information
The statements contained in this Quarterly Report on Form 10-Q that are not historical facts, including, but not limited to, statements found in thisManagement’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, forecasted capital expenditures, dates of pipeline construction commencement and completion, drilling activity or methods, acquisition plans and proposals and dispositions, development activities, timing of CO2 injections in tertiary flooding projects, cost savings, capital budgets, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO2 reserves, potential reserves from tertiary operations, hydrocarbon prices, pricing or cost assumptions based on current and projected oil and natural gas prices, liquidity, cash flows, availability of capital, borrowing capacity, regulatory matters, mark-to-market values, competition, long-term forecasts of production, finding costs, rates of return, estimated costs, or changes in costs, future capital expenditures and overall economics and other variables surrounding our operations and future plans. Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “anticipate,” “projected,” “should,” “assume,” “believe,” “target,” 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 us or on our behalf. 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; unexpected difficulties in integrating the operations of Denbury and Encore; effects of our indebtedness; success of our risk management techniques; inaccurate cost estimates; availability of and fluctuations in the prices of goods and services; the uncertainty of drilling results and reserve estimates; operating hazards; disruption of operations and damages from hurricanes or tropical storms; acquisition risks; requirements for capital or its availability; conditions in the financial and credit markets; changes in interest rates; general economic conditions; competition and government regulations; and unexpected delays, as well as the risks and uncertainties inherent in oil and natural gas drilling and production activities or which are otherwise discussed in this quarterly report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in our other public reports, filings and public statements.
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DENBURY RESOURCES INC.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
Long-Term Debt and Interest Rate Sensitivity
We finance some of our acquisitions and other expenditures with fixed and variable ratevariable-rate debt. These debt agreements expose us to market risk related to changes in interest rates. None of our existing debt has any triggers or covenants regarding our debt ratings with rating agencies. The fair value of the subordinated debt is based on quoted market prices. The following table presents the carrying and fair values of our debt, along with average interest rates at March 31,June 30, 2011:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Expected Maturity Dates | | Carrying | | Fair | | | Carrying | | Fair | |
In thousands, except percentages | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 | | 2020 | | 2021 | | Value | | Value | | | 2014 | | 2015 | | 2016 | | 2017 | | 2020 | | 2021 | | Value | | Value | |
Variable rate debt: | | |
Bank Credit Agreement | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | | $ | — | | $ | — | | $ | — | | $ | — | | $ | — | | $ | — | | $ | — | | $ | — | |
Fixed rate debt: | | |
7.5% Senior Subordinated Notes due 2013(1) | | 55,448 | | - | | - | | - | | - | | - | | - | | 55,352 | | 55,448 | | |
9.5% Senior Subordinated Notes due 2016 | | - | | - | | - | | 224,920 | | - | | - | | - | | 238,826 | | 253,597 | | | — | | — | | 224,920 | | — | | — | | — | | 238,142 | | 249,942 | |
9.75% Senior Subordinated Notes due 2016 | | - | | - | | - | | 426,350 | | - | | - | | - | | 405,283 | | 480,710 | | | — | | — | | 426,350 | | — | | — | | — | | 406,354 | | 476,446 | |
8.25% Senior Subordinated Notes due 2020 | | - | | - | | - | | - | | - | | 996,273 | | - | | 996,273 | | 1,113,335 | | | — | | — | | — | | — | | 996,273 | | — | | 996,273 | | 1,085,938 | |
6.375% Senior Subordinated Notes due 2021 | | - | | - | | - | | - | | - | | - | | 400,000 | | 400,000 | | 410,000 | | | — | | — | | — | | — | | — | | 400,000 | | 400,000 | | 400,000 | |
Other Subordinated Notes | | - | | 1,072 | | 485 | | - | | 2,250 | | - | | - | | 3,845 | | 3,807 | | | 1,072 | | 485 | | — | | 2,250 | | — | | — | | 3,843 | | 3,807 | |
| | |
(1) These notes were repurchased on April 1, 2011. See Note 3, Long-Term Debt, to the Unaudited Condensed Consolidated Financial Statements, for further information. |
Commodity Derivative Contracts and Commodity Price Sensitivity
From time to time, we enter into various oil and natural gas derivative contracts to provide an economic hedge of 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 consisted of price floors, collars and fixed price swaps. The production that we hedge has varied from year to year depending on our levels of debt and financial strength and expectation of future commodity prices. We currently employ a strategy to hedge a portion of our forecasted production for a period generally ranging from approximately 12 to 18 months in advance (although we will hedge farther in advance if deemed prudent), as we believe it is important to protect our future cash flow for a short period of time in order to give us time to adjust to commodity price fluctuations, particularly since many of our expenditures have long lead times. See Note 4,Derivative Instruments and Hedging Activities,to the Consolidated Financial Statements for additional information regarding our commodity derivative contracts.
All of the mark-to-market valuations used for our oil and natural gas derivatives are provided by external sources. We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures, and diversification. All of our commodity derivative contracts are with parties that are lenders under our bank credit agreement. We have included an estimate of nonperformance risk in the fair value measurement of our oil and natural gas derivative contracts, which we have measured for nonperformance risk based upon credit default swaps or credit spreads.
For accounting purposes, we do not apply hedge accounting to our commodity derivative contracts. This means that any changes in the fair value of these derivative contracts will be charged to earnings on a quarterly basis instead of charging the effective portion to other comprehensive income and the ineffective portion to earnings.
At March 31,June 30, 2011, our commodity derivative contracts were recorded at their fair value, which was a net liability of approximately $216.3$32.5 million (excluding $21.2$15.6 million of deferred premiums that Denbury is obligated to pay for its derivative contracts, which payments are not subject to changes in commodity prices), a significant change fromwhich is less than the $44.0 million fair value liability recorded at December 31, 2010. This change is primarily related to thechanges in oil futures prices as of Marchbetween December 31, 2011 in relation to the commodity derivative contracts for 2011 through 2012.2010 and June 30, 2011.
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DENBURY RESOURCES INC.
Based on NYMEX crude oil and natural gas futures prices as of March 31,June 30, 2011, and assuming both a 10% increase and decrease thereon, we would expect to make or receive payments on our crude oil and natural gas derivative contracts as seen in the following table:
| | | | | | | | | | | | | | | |
| | Crude Oil | | Natural Gas | | Crude Oil | | Natural Gas | |
| | Derivative | | Derivative | | Derivative | | Derivative | |
| | Contracts | | Contracts | | Contracts | | Contracts | |
In thousands | | (Payment) | | Receipt | | (Payment) | | Receipt | |
| | | | |
Based on: | | |
NYMEX futures prices as of March 31, 2011 | | $ | (120,867 | ) | | $ | 30,033 | | |
NYMEX futures prices as of June 30, 2011 | | | $ | (9,390 | ) | | $ | 24,508 | |
10% increase in prices | | | (308,210 | ) | | 21,692 | | | | (81,222 | ) | | 18,312 | |
10% decrease in prices | | | (11,555 | ) | | 38,358 | | | | (2,952 | ) | | 30,703 | |
Equity Price Sensitivity
Our investment in Vanguard common units is considered an investment in available-for-sale securities, which areis recorded at fair value with any unrealized gains or losses included in accumulated other comprehensive income. This investment is thus subject to equity price sensitivity, as fair value is determined by quoted market prices. We estimate that a hypothetical 10% increase or decrease in quoted market prices for Vanguard common units would result in a $10.0$8.8 million unrealized gain or loss, respectively, as of March 31,June 30, 2011.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures.As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) was performed under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, the Company’s Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of March 31,June 30, 2011, to ensure: that information required to be disclosed in the reports it files and submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and that information that is required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Evaluation of Changes in Internal Control Overover Financial Reporting.Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we have determined that, during the firstsecond quarter of fiscal 2011, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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DENBURY RESOURCES INC.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Information with respect to this item is incorporated by reference from our Annual Report on Form 10-K for the year ended December 31, 2010.
Item 1A. Risk Factors
Information with respect to the risk factors has been incorporated by reference from Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2010. There have been no material changes to the risk factors since the filing of such Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities
The following table summarizes purchases of our common stock during the firstsecond quarter of 2011, consisting entirely of delivery by our employees of shares to us to satisfy their tax withholding requirements related to the vesting of restricted shares and the exercise of stock appreciation rights:
| | | | | | | | | | | | | | | | |
| | | | | | | | | | Total Number of | | | Approximate Dollar | |
| | Total | | | | | | | Shares Purchased | | | Value of Shares | |
| | Number of | | | Average | | | as Part of Publicly | | | that May Yet Be | |
| | Shares | | | Price Paid | | | Announced Plans or | | | Purchased Under the | |
Month | | Purchased | | | per Share | | | Programs | | | Plans or Programs | |
January 2011 | | | 84,250 | | | $ | 19.76 | | | | - | | | $ | - | |
February 2011 | | | 36,513 | | | | 22.46 | | | | - | | | | - | |
March 2011 | | | 208,893 | | | | 24.31 | | | | - | | | | - | |
| | | | | | | | | | | | | |
Total | | | 329,656 | | | | 22.94 | | | | - | | | $ | - | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | Total Number of | | | Approximate Dollar | |
| | Total | | | | | | | Shares Purchased | | | Value of Shares | |
| | Number of | | | Average | | | as Part of Publicly | | | that May Yet Be | |
| | Shares | | | Price Paid | | | Announced Plans or | | | Purchased Under the | |
Month | | Purchased | | | per Share | | | Programs | | | Plans or Programs | |
April 2011 | | | 17,272 | | | $ | 23.97 | | | | — | | | $ | — | |
May 2011 | | | 9,466 | | | | 21.28 | | | | — | | | | — | |
June 2011 | | | 14,479 | | | | 19.95 | | | | — | | | | — | |
| | | | | | | | | | | | | |
Total | | | 41,217 | | | | 21.94 | | | | — | | | $ | — | |
| | | | | | | | | | | | | |
Item 6. Exhibits
| | |
Exhibit | | Description |
10(a)* **3.1 | | FormAmended and Restated Bylaws of 2011 Performance Share Award under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. effective as of June 17, 2011 (incorporated by reference as Exhibit 3.1 of our Form 8-K filed on June 21, 2011). |
10(b)* ** | | Form |
4.1 | | Fifth Amendment to Credit Agreement dated as of March 9, 2010, dated as of May 19, 2011, Performance Cash Award under the 2004 Omnibus Stock and Incentive Plan foramong Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto (incorporated by reference as Exhibit 99.1 of our Form 8-K filed on May 20, 2011). |
| | |
31.1* | | Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | |
31.2* | | 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. |
| | |
101* | | Interactive Data Files. |
| | |
* | | Filed herewith. |
|
** Compensation arrangements. |
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DENBURY RESOURCES INC.
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.
| |
| By: | /s/ Mark C. Allen | |
| | Mark C. Allen | |
| | Senior Vice President, Chief Financial Officer, Treasurer, and Assistant Secretary | |
|
| | |
| By: | /s/ Alan Rhoades | |
| | Alan Rhoades | |
| | Vice President and Chief Accounting Officer | |
|
Date: May 10,August 8, 2011
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