e10vq
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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þ |
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Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the quarterly period ended September 30, 2009
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o |
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Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
Commission file number 1-12935
DENBURY RESOURCES INC.
(Exact name of Registrant as specified in its charter)
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Delaware
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20-0467835 |
(State or other jurisdictions of
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(I.R.S. Employer |
incorporation or organization)
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Identification No.) |
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5100 Tennyson Parkway |
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Suite 1200 |
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Plano, TX
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75024 |
(Address of principal executive offices)
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(Zip code) |
Registrants telephone number, including area code: (972) 673-2000
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
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). Yes þ No o
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 filer þ |
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Accelerated filer o |
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Non-accelerated filer o
(Do not check if a smaller reporting company) |
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Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act
Rule 12b-2). Yes o No þ
Indicate the number of shares outstanding of each of the issuers classes of common stock, as of
the latest practicable date.
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Class |
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Outstanding at October 31, 2009 |
Common Stock, $.001 par value
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249,823,000 |
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except shares)
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September 30, |
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December 31, |
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2009 |
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2008 |
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Assets |
Current assets |
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Cash and cash equivalents |
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$ |
21,689 |
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$ |
17,069 |
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Accrued production receivable |
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91,477 |
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67,805 |
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Trade and other receivables, net of allowance of $409 and $377 |
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77,454 |
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80,579 |
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Derivative assets |
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17,900 |
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249,746 |
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Current deferred tax assets |
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5,637 |
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Total current assets |
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214,157 |
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415,199 |
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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 |
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3,468,060 |
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3,386,606 |
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Unevaluated |
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213,170 |
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235,403 |
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CO2 properties, equipment and pipelines |
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1,422,981 |
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899,542 |
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Other |
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80,015 |
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70,328 |
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Less accumulated depletion, depreciation and impairment |
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(1,763,902 |
) |
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(1,589,682 |
) |
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Net property and equipment |
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3,420,324 |
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3,002,197 |
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Deposits on property under option or contract |
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48,917 |
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Other assets |
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52,343 |
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43,357 |
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Goodwill |
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138,830 |
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Investment in Genesis |
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77,606 |
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80,004 |
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Total assets |
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$ |
3,903,260 |
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$ |
3,589,674 |
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Liabilities and Stockholders Equity |
Current liabilities |
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Accounts payable and accrued liabilities |
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$ |
188,420 |
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$ |
202,633 |
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Oil and gas production payable |
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86,038 |
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85,833 |
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Derivative liabilities |
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74,614 |
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Deferred revenue Genesis |
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4,070 |
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4,070 |
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Deferred tax liability |
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89,024 |
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Current maturities of long-term debt |
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4,698 |
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4,507 |
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Total current liabilities |
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357,840 |
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386,067 |
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Long-term liabilities |
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Long-term debt Genesis |
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250,681 |
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251,047 |
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Long-term debt |
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945,380 |
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601,720 |
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Asset retirement obligations |
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47,149 |
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43,352 |
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Deferred revenue Genesis |
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16,796 |
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19,957 |
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Deferred tax liability |
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458,940 |
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433,210 |
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Derivative liabilities |
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12,496 |
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Other |
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23,319 |
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14,253 |
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Total long-term liabilities |
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1,754,761 |
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1,363,539 |
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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, $.001 par value, 600,000,000 shares authorized; 250,082,892 and
248,005,874 shares issued at September 30, 2009 and December 31, 2008, respectively |
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250 |
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248 |
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Paid-in capital in excess of par |
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734,398 |
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707,702 |
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Retained earnings |
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1,060,923 |
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1,139,575 |
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Accumulated other comprehensive loss |
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(575 |
) |
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(627 |
) |
Treasury
stock, at cost, 278,986 and 446,287 shares at September 30, 2009 and December 31, 2008, respectively |
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(4,337 |
) |
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(6,830 |
) |
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Total stockholders equity |
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1,790,659 |
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1,840,068 |
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Total liabilities and stockholders equity |
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$ |
3,903,260 |
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$ |
3,589,674 |
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See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
3
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
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Three Months Ended |
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Nine Months Ended |
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September 30, |
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September 30, |
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2009 |
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2008 |
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2009 |
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2008 |
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Revenues and other income |
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Oil, natural gas and related product sales |
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$ |
221,321 |
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$ |
402,108 |
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$ |
600,942 |
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$ |
1,128,548 |
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CO2 sales and transportation fees |
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3,659 |
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3,471 |
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9,708 |
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9,705 |
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Interest income and other |
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434 |
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1,895 |
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1,948 |
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3,525 |
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Total revenues |
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225,414 |
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407,474 |
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612,598 |
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1,141,778 |
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Expenses |
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Lease operating expenses |
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83,300 |
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85,308 |
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241,908 |
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228,134 |
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Production taxes and marketing expenses |
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8,555 |
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17,104 |
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24,294 |
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50,978 |
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Transportation expense Genesis |
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1,906 |
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2,231 |
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6,143 |
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5,623 |
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CO2 operating expenses |
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1,047 |
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1,240 |
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3,442 |
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2,836 |
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General and administrative |
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24,038 |
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15,005 |
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79,828 |
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45,821 |
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Interest, net of amounts capitalized of $20,872, $6,713,
$48,699, and $19,524, respectively |
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9,859 |
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10,906 |
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36,960 |
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|
23,988 |
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Depletion, depreciation and amortization |
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53,525 |
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56,324 |
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|
177,145 |
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|
160,896 |
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Commodity derivative expense (income) |
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3,757 |
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(62,007 |
) |
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|
177,061 |
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43,591 |
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Abandoned acquisition costs |
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30,426 |
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30,426 |
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Total expenses |
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185,987 |
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|
156,537 |
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|
746,781 |
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592,293 |
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Equity in net income of Genesis |
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1,835 |
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2,780 |
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|
5,802 |
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3,796 |
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|
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|
Income (loss) before income taxes |
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|
41,262 |
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|
253,717 |
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|
(128,381 |
) |
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|
553,281 |
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Income tax provision (benefit) |
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Current income taxes |
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(6,160 |
) |
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|
12,689 |
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18,140 |
|
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|
44,769 |
|
Deferred income taxes |
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20,537 |
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|
83,480 |
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(67,869 |
) |
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|
163,909 |
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Net income (loss) |
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$ |
26,885 |
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$ |
157,548 |
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$ |
(78,652 |
) |
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$ |
344,603 |
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Net income (loss) per common share basic |
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$ |
0.11 |
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$ |
0.64 |
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$ |
(0.32 |
) |
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$ |
1.41 |
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Net income (loss) per common share diluted |
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$ |
0.11 |
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$ |
0.63 |
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$ |
(0.32 |
) |
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$ |
1.36 |
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Weighted average common shares outstanding |
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|
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Basic |
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|
246,795 |
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|
244,426 |
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|
|
246,156 |
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|
|
243,604 |
|
Diluted |
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|
252,189 |
|
|
|
251,831 |
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|
|
246,156 |
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|
|
252,708 |
|
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
4
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
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Nine Months Ended |
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September 30, |
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|
2009 |
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|
2008 |
|
Cash flow from operating activities: |
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Net income (loss) |
|
$ |
(78,652 |
) |
|
$ |
344,603 |
|
Adjustments needed to reconcile to net cash flow provided by operations: |
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|
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|
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|
Depletion, depreciation and amortization |
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|
177,145 |
|
|
|
160,896 |
|
Deferred income taxes |
|
|
(67,869 |
) |
|
|
163,909 |
|
Deferred revenue Genesis |
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|
(3,161 |
) |
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|
(3,383 |
) |
Stock-based compensation |
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|
25,450 |
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|
10,979 |
|
Non-cash fair value derivative adjustments |
|
|
323,510 |
|
|
|
(17,048 |
) |
Founders retirement compensation |
|
|
6,350 |
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|
Other |
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|
5,601 |
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|
|
(2,921 |
) |
Changes in assets and liabilities related to operations: |
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|
|
|
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|
Accrued production receivable |
|
|
(23,672 |
) |
|
|
(10,620 |
) |
Trade and other receivables |
|
|
2,609 |
|
|
|
(46,330 |
) |
Other assets |
|
|
(210 |
) |
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|
188 |
|
Accounts payable and accrued liabilities |
|
|
38,757 |
|
|
|
9,069 |
|
Oil and gas production payable |
|
|
205 |
|
|
|
24,385 |
|
Other liabilities |
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|
371 |
|
|
|
(956 |
) |
|
|
|
|
|
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|
Net cash provided by operating activities |
|
|
406,434 |
|
|
|
632,771 |
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|
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|
Cash flow used for investing activities: |
|
|
|
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|
Oil and natural gas capital expenditures |
|
|
(289,815 |
) |
|
|
(436,114 |
) |
Acquisitions of oil and natural gas properties |
|
|
(197,534 |
) |
|
|
(4,262 |
) |
CO2 capital expenditures, including pipelines |
|
|
(543,536 |
) |
|
|
(211,917 |
) |
Net purchases of other assets |
|
|
(10,967 |
) |
|
|
(20,703 |
) |
Net proceeds from sales of oil and gas properties and equipment |
|
|
303,450 |
|
|
|
48,948 |
|
Other |
|
|
2,012 |
|
|
|
6,371 |
|
|
|
|
|
|
|
|
Net cash used for investing activities |
|
|
(736,390 |
) |
|
|
(617,677 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from financing activities: |
|
|
|
|
|
|
|
|
Bank repayments |
|
|
(606,000 |
) |
|
|
(222,000 |
) |
Bank borrowings |
|
|
551,000 |
|
|
|
72,000 |
|
Income tax benefit from equity awards |
|
|
2,713 |
|
|
|
17,362 |
|
Pipeline financing Genesis |
|
|
493 |
|
|
|
225,311 |
|
Issuance of subordinated debt |
|
|
389,827 |
|
|
|
|
|
Issuance of common stock |
|
|
10,595 |
|
|
|
11,687 |
|
Costs of debt financing |
|
|
(10,080 |
) |
|
|
|
|
Other |
|
|
(3,972 |
) |
|
|
(4,251 |
) |
|
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
334,576 |
|
|
|
100,109 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents |
|
|
4,620 |
|
|
|
115,203 |
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of period |
|
|
17,069 |
|
|
|
60,107 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
21,689 |
|
|
$ |
175,310 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Supplemental disclosure of cash flow information: |
|
|
|
|
|
|
|
|
Cash paid for interest, net of amounts capitalized |
|
$ |
14,114 |
|
|
$ |
10,435 |
|
Cash paid (refunded) for income taxes |
|
|
(4,894 |
) |
|
|
70,349 |
|
Interest capitalized |
|
|
48,699 |
|
|
|
19,524 |
|
Increase (decrease) in liabilities for capital expenditures |
|
|
(54,830 |
) |
|
|
24,273 |
|
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 |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Net income (loss) |
|
$ |
26,885 |
|
|
$ |
157,548 |
|
|
$ |
(78,652 |
) |
|
$ |
344,603 |
|
Other comprehensive income, net of income tax: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of interest rate lock derivative contracts
designated as a hedge, net of tax of $-, $-, $- and
$49, respectively |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12 |
|
Interest rate lock derivative contracts reclassified to income,
net of taxes of $11, $11, $32 and $573, respectively |
|
|
17 |
|
|
|
16 |
|
|
|
52 |
|
|
|
934 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss) |
|
$ |
26,902 |
|
|
$ |
157,564 |
|
|
$ |
(78,600 |
) |
|
$ |
345,549 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
6
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 1. Basis of Presentation
Interim Financial Statements
The accompanying unaudited condensed consolidated financial statements of Denbury
Resources Inc. and its subsidiaries have been prepared in accordance with the instructions to Form
10-Q and do not include all of the information and footnotes required by accounting principles
generally accepted in the United States for complete financial statements. Unless indicated
otherwise or the context requires, the terms we, our, us, Denbury or Company refer to
Denbury Resources Inc. and its subsidiaries. These financial statements and the notes thereto
should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31,
2008. Any capitalized terms used but not defined in these Notes to Unaudited Condensed Consolidated
Financial Statements have the same meaning given to them in the Form 10-K.
Accounting measurements at interim dates inherently involve greater reliance on estimates
than at year end and the results of operations for the interim periods shown in this report are not
necessarily indicative of results to be expected for the fiscal year. In managements opinion, the
accompanying unaudited condensed consolidated financial statements include all adjustments (of a
normal recurring nature) necessary to present fairly the consolidated financial position of Denbury
as of September 30, 2009, the consolidated results of its operations for the three and nine month
periods ended September 30, 2009 and 2008 and cash flows for the nine months ended September 30,
2009 and 2008. Certain prior period items have been reclassified to make the classification
consistent with the classification in the most recent quarter. We have evaluated events that
occurred subsequent to September 30, 2009 through November 9, 2009, the financial statement
issuance date.
Net Income (Loss) Per Common Share
Basic net income (loss) per common share is computed by dividing net income (loss) by the
weighted average number of shares of common stock outstanding during the period. Diluted net income
per common share is calculated in the same manner but also considers the impact on net income and
common shares for the potential dilution from stock options, stock appreciation rights (SARs),
non-vested restricted stock and any other convertible securities outstanding. For the three and
nine month periods ended September 30, 2009 and 2008, there were no adjustments to net income
(loss) for purposes of calculating diluted net income (loss) per common share. The following is a
reconciliation of the weighted average common shares used in the basic and diluted net income
(loss) per common share calculations for the three and nine month periods ended September 30, 2009
and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
In thousands |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Weighted average common shares basic |
|
|
246,795 |
|
|
|
244,426 |
|
|
|
246,156 |
|
|
|
243,604 |
|
Potentially dilutive securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options and SARs |
|
|
4,006 |
|
|
|
6,035 |
|
|
|
|
|
|
|
7,439 |
|
Restricted stock |
|
|
1,388 |
|
|
|
1,370 |
|
|
|
|
|
|
|
1,665 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares diluted |
|
|
252,189 |
|
|
|
251,831 |
|
|
|
246,156 |
|
|
|
252,708 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The weighted average common shares basic amount excludes 2,454,168 shares at September 30,
2009 and 2,242,699 shares at September 30, 2008, of non-vested restricted stock that is subject to
future vesting over time. As these restricted shares vest, they will be included in the shares
outstanding used to calculate basic net income (loss) per common share (although all restricted
stock is issued and outstanding upon grant). For purposes of calculating weighted average common
shares diluted during the three months ended September 30, 2009 and the three and nine months
ended September 30, 2008, the non-vested restricted stock is included in the computation using the
treasury stock method, with the proceeds equal to the average unrecognized compensation during the
period, adjusted for any estimated future tax consequences recognized directly in equity.
7
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
The following securities were not included in the computation of diluted net earnings per
share as their effect would have been anti-dilutive:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
In thousands |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Stock options and SARs |
|
|
3,654 |
|
|
|
1,028 |
|
|
|
10,813 |
|
|
|
1,011 |
|
Restricted stock |
|
|
79 |
|
|
|
|
|
|
|
2,930 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
3,733 |
|
|
|
1,028 |
|
|
|
13,743 |
|
|
|
1,011 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2 Pipelines
CO2 pipelines are used for transportation of CO2
to our tertiary floods from our CO2 source field located near Jackson,
Mississippi. We are continuing expansion of our CO2 pipeline infrastructure
with several pipelines currently under construction. At September 30, 2009 and December 31, 2008,
we had $870.4 million and $402.0 million of costs, respectively, related to pipeline construction
in progress, recorded under CO2 properties, equipment and pipelines in our
Unaudited Condensed Consolidated Balance Sheets. Pipeline construction in progress increased during
2009 primarily due to ongoing construction of our Green Pipeline. These costs of
CO2 pipelines under construction were not being depreciated at September 30,
2009 or December 31, 2008. Depreciation will commence as each segment of pipeline is placed into
service. Each pipeline is depreciated on a straight-line basis over its estimated useful life as
determined for GAAP purposes, which ranges between 20 to 30 years.
Goodwill
Goodwill represents the excess of the purchase price over the estimated fair value of the
net assets acquired in the acquisition of a business. Goodwill is not amortized, but rather it is
tested for impairment annually during the fourth quarter and also when events or changes in
circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below
carrying value. The impairment test requires allocating goodwill and other assets and liabilities
to reporting units. In the case of Denbury, we have only one reporting unit. The fair value of the
reporting unit is determined and compared to the book value of the reporting unit. If the fair
value of the reporting unit is less than the book value, including goodwill, the recorded goodwill
is impaired to its implied fair value with a charge to operating expense. We recorded goodwill
during 2009 in conjunction with our Hastings Field acquisition (see Note 2, Acquisitions and
Divestitures).
Recently Adopted Accounting Pronouncements
FASB Accounting Standards CodificationTM. In June 2009, the Financial Accounting Standards Board (FASB) introduced the FASB
Accounting Standards CodificationTM (FASC) as the new source of
authoritative U.S. generally accepted accounting principles (GAAP) for nongovernmental entities.
The Company applied the new guidance to our financial statements issued for the nine months ended
September 30, 2009. This standard did not have any impact on the Companys financial position or
results of operations.
Subsequent Events. In May 2009, the FASB issued guidance under the Subsequent Events
topic of the FASC to establish accounting standards for events that occur after the balance sheet
date but before financial statements are issued or are available to be issued. The new guidance
does not significantly change current practice but does require companies to disclose the date
through which subsequent events were evaluated and whether or not that date was the date the
financial statements were issued or available for issuance. The Company adopted the new guidance
upon its issuance with no resulting impact on the Companys financial position or results of
operations.
Business Combinations. In December 2007, the FASB issued guidance under the Business
Combinations topic of the FASC to establish principles and requirements for how an acquirer
recognizes and measures in its financial statements, the identifiable assets
8
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
acquired, the liabilities assumed, any noncontrolling interest in the acquiree and the goodwill
acquired. The guidance also establishes disclosure requirements to enable the evaluation of the
nature and financial effects of the business combination. We adopted the new guidance on January 1,
2009 and applied the guidance to an acquisition that we made during the first quarter (see Note 2,
Acquisitions and Divestitures).
Equity Method Accounting. In November 2008, the FASB issued guidance in the Investments
- Equity Company and Joint Ventures topic of the FASC to clarify how the application of equity
method accounting will be affected by newly issued guidance on business combinations and
noncontrolling interests in consolidated financial statements. The new guidance clarifies that an
entity shall continue to use the cost accumulation model for its equity method investments. It also
confirms past accounting practices related to the treatment of contingent consideration and
impairment. Additionally, it requires an equity method investor to account for a share issuance by
an investee as if the investor had sold a proportionate share of the investment. This guidance was
effective January 1, 2009, applies prospectively and did not have any impact on our financial
position or results of operations.
Noncontrolling Interests. In December 2007, the FASB issued guidance under
Consolidations topic of the FASC which establishes accounting and reporting standards for
ownership interests in subsidiaries held by parties other than the parent, the amount of
consolidated net income attributable to the parent and to the noncontrolling interest, changes in a
parents ownership interest, and the valuation of retained noncontrolling equity investments when a
subsidiary is deconsolidated. The new guidance also establishes disclosure requirements that
clearly identify and distinguish between the interests of the parent and the interests of the
noncontrolling owners. We adopted this guidance on January 1, 2009 and, since we currently do not
have any noncontrolling interests, the adoption did not have any impact on our financial position
or results of operations.
Disclosures about Derivative Instruments and Hedging Activities. In March 2008, the FASB
issued guidance under the Derivatives and Hedging topic of the FASC which requires entities that
utilize derivative instruments to provide qualitative disclosures about their objectives and
strategies for using such instruments, as well as any details of credit risk related contingent
features contained within derivatives. The guidance also requires entities to disclose additional
information about the amounts and location of derivatives within the financial statements, how the
provisions of accounting guidance related to derivatives and hedging have been applied, and the
impact that hedges have on an entitys financial position, financial performance, and cash flows.
We adopted the disclosure requirement beginning January 1, 2009 (see Note 6, Derivative
Instruments and Hedging Activities). The adoption of this statement did not have any impact on our
financial position or results of operations.
Fair Value Measurements. In 2006, the FASB issued guidance which defined fair value,
established a framework for measuring fair value and expanded disclosures about fair value
measurements. In February 2008, the FASB delayed the effective date of the new guidance for all
nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at
fair value in the financial statements on a recurring basis (at least annually). We adopted the new
guidance on January 1, 2009. The adoption of this guidance did not have any impact on our financial
position or results of operations.
In April 2009, the FASB issued new rules to provide additional application guidance and
enhance disclosures regarding fair value measurements and impairments of securities. The FASB
enhanced its guidance under the Fair Value Measurements and Disclosures topic of the FASC to 1)
determine fair value when the volume and level of activity for an asset or liability have
significantly decreased and 2) identify transactions that are not orderly. The FASB issued
guidance under the Financial Instruments topic of the FASC to enhance consistency in financial
reporting by increasing the frequency of fair value disclosures. The FASB also issued guidance in
the Investments Debt and Equity Securities topic of the FASC to provide additional guidance to
create greater clarity and consistency in accounting for and presenting impairment losses on
securities. The new guidance was effective for interim and annual periods ending after June 15,
2009. Although adoption of the guidance enhanced our interim financial statement disclosures, it
did not have any impact on our financial position or results of operations.
In August 2009, the FASB issued guidance under the Fair Value Measurements and Disclosures
topic of the FASC to provide additional guidance on measuring the fair value of liabilities. The
new guidance was effective for the Company on October 1, 2009 and did not have any impact on the
Companys financial position or results of operations.
Recently Issued Accounting Pronouncements
Modernization of Oil and Gas Reporting. On December 31, 2008, the Securities and Exchange
Commission adopted major revisions to its rules governing oil and gas company reporting
requirements. These include provisions that permit the use of new technologies to determine proved
reserves, and allow companies to disclose their probable and possible reserves to investors. The
9
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
current rules limit disclosure to only proved reserves. The new rules also require companies that
have an audit performed on their reserves to report the independence and qualifications of the
reserve auditor, and file reports when a third party reserve engineer is relied upon to prepare
reserve estimates. The new rules also require that oil and gas reserves be reported and the full
cost ceiling value be calculated using an average price based upon the prior twelve-month period.
The new oil and gas reporting requirements are effective for annual reports on Form 10-K for fiscal
years ending on or after December 31, 2009. In September 2009, the FASB issued an exposure draft of
a proposed accounting standard update to the Extractive Industries Oil and Gas topic of the
FASC that would align the FASBs oil and gas reserve estimation and disclosure requirements with
the new SEC rule revisions. As written, the proposed amendments would be effective for periods
ending on or after December 31, 2009. We are currently evaluating the impact the new rules may have
on our financial condition or results of operations.
Transfers of Financial Assets. In June 2009, the FASB issued guidance related to the
accounting for transfers of financial assets. The guidance removes the concept of a qualifying
special-purpose entity (QSPE) from FASC topic, Transfers and Servicing, creates a new unit of
account definition that must be met for transfers of portions of financial assets to be eligible
for sale accounting, clarifies the de-recognition criteria for a transfer to be accounted for as a
sale, changes the amount of recognized gains or losses on the transfer of financial assets
accounted for as a sale when beneficial interests are received by the transferor and introduces new
disclosure requirements. The new guidance is effective for us beginning January 1, 2010. We do not
anticipate the adoption will have a material impact on our financial condition or results of
operations.
Consolidation of Variable Interest Entities. In June 2009, the FASB issued guidance to
eliminate the exemption in the Consolidation topic of the FASC for QSPEs, introduce a new
approach for determining who should consolidate a variable interest entity and change the
requirement as to when it is necessary to reassess who should consolidate a variable interest
entity. This standard is effective for us beginning January 1, 2010. We are currently evaluating
the impact the new rule may have on our financial condition or results of operations.
Note 2. Acquisitions and Divestitures
Hastings Field Acquisition
During November 2006, we entered into an agreement with a subsidiary of Venoco, Inc.,
that gave us an option to purchase their interest in Hastings Field, a strategically significant
potential tertiary flood candidate located near Houston, Texas. We exercised the purchase option
prior to September 2008, and closed the acquisition during February 2009. As consideration for the
option agreement, during 2006 through 2008, we made cash payments totaling $50 million which we
recorded as a deposit. The purchase price of approximately $196 million, which was paid in cash,
was determined as of January 1, 2009 (the effective date) with closing on February 2, 2009. The
final closing adjustments were completed during the three months ended September 30, 2009. The
final closing price, adjusted for interim net cash flows between the effective date and closing
date of the acquisition (including minor purchase price adjustments), totaled $246.8 million.
Under the terms of the agreement, Venoco, Inc., the seller, retained a 2% override and a
reversionary interest of approximately 25% following payout, as defined in the option agreement.
The Hastings Field proved reserves were not included in the Companys year-end 2008 proved
reserves. We plan to commence flooding the field with CO2 beginning in 2011,
after completion of our Green Pipeline currently under construction and construction of field
recycling facilities. Under the agreement, we are required to make aggregate net cumulative capital
expenditures in this field of approximately $179 million prior to December 31, 2014 as follows:
$26.8 million by December 31, 2010, $71.5 million by December 31, 2011, $107.2 million by
December 31, 2012, $142.9 million by December 31, 2013, and $178.7 million by December 31, 2014. If
we fail to spend the required amounts by the due dates, we are required to make a cash payment
equal to 10% of the cumulative shortfall at each applicable date. Further, we are committed to
inject at least an average of 50 MMcf/day of CO2 (total of purchased and
recycled) in the West Hastings Unit for the 90 day period prior to January 1, 2013. If such
injections do not occur, we must either (1) relinquish our rights to initiate (or continue)
tertiary operations and reassign to Venoco all assets previously purchased for the value of such
assets at that time based upon the discounted value of the fields proved reserves using a 20%
discount rate, or (2) make an additional payment of $20 million in January 2013, less any payments
made for failure to meet the capital spending requirements as of December 31, 2012, and a
$30 million payment for each subsequent year (less amounts paid for capital expenditure shortfalls)
until the CO2 injection rate in the Hastings Field equals or exceeds the
minimum required injection rate.
This acquisition of Hastings Field qualifies as a business under FASC Business
Combinations topic. As such, we estimated the fair value of this property as of the acquisition
date, as defined in the FASC is the date on which the acquirer obtains control of the
10
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
acquiree, which for this acquisition is February 2, 2009 (the closing date). The FASC Fair Value
Measurements and Disclosures topic defines fair value as 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 (often referred to as the exit price). The fair value measurement is based
on the assumptions of market participants and not those of the reporting entity. Therefore,
entity-specific intentions should not impact the measurement of fair value unless those assumptions
are consistent with market participant views.
In applying these accounting principles, we estimated the fair value of these
properties on the acquisition date to be approximately $105.6 million. This measurement resulted in
the recognition of goodwill totaling $138.8 million. The FASC defines goodwill as an asset
representing the future economic benefits arising from other assets acquired in a business
combination that are not individually identified and separately recognized. For this acquisition,
goodwill is the excess of the cash paid to acquire the Hastings Field over the acquisition date
estimated fair value. This resultant goodwill is due primarily to two factors. The first factor is
the decrease in the NYMEX oil and natural gas futures prices between the effective date of
January 1, 2009, which is the date at which the acquisition price was determined, and the
acquisition date of February 2, 2009, which is the date at which the assets were valued for
accounting purposes. The purchase agreement provided that the Hastings reserves be valued using the
NYMEX oil and gas futures prices on the effective date of January 1, 2009. The second factor is the
estimated fair value assigned to the estimated oil reserves recoverable through a
CO2 enhanced oil recovery (EOR) project. Denbury has one of the few known
significant natural sources of CO2 in the United States, and the largest known
source east of the Mississippi river. This source of CO2 that we own will allow
Denbury to carry out CO2 EOR activities in this field at a much lower cost than
other market participants. However, FASC Fair Value Measurements and Disclosures topic does not
allow entity-specific assumptions in the measurement of fair value. Therefore, we estimated the
fair value of the oil reserves recoverable through CO2 EOR using an estimated
cost of CO2 to other market participants. This assumption of a higher cost of
CO2 resulted in an estimated fair value of the projected
CO2 EOR reserves that would not have been economically viable and therefore no
value has been assigned to undeveloped properties in this acquisition.
The fair value of Hastings Field was based on significant inputs not observable in the
market, which FASC Fair Value Measurements and Disclosures topic defines as Level 3 inputs. Key
assumptions include (1) NYMEX oil and natural gas futures (this input is observable),
(2) projections of the estimated quantities of oil and natural gas reserves, (3) projections of
future rates of production, (4) timing and amount of future development and operating costs,
(5) projected cost of CO2 to a market participant, (6) projected recovery
factors and, (7) risk adjusted discount rates. The fair value of these properties was assigned to
the assets and liabilities acquired, which included $105.6 million to evaluated properties in the
full cost pool and net $2.4 million for land, oilfield equipment and other related assets. Denbury
applies SEC full cost accounting rules, under which the acquisition cost of oil and gas properties
are recognized on a cost center basis (country), of which Denbury has only one cost center (United
States). The goodwill of $138.8 million was assigned to this single reporting unit. All of the
goodwill is deductible for tax purposes as property cost.
The transaction related costs (legal, accounting, due diligence, etc.) have been
expensed. We have not presented any pro forma information for the acquired business as the pro
forma effect was not material to our results of operations for the three or nine month periods
ended September 30, 2009 or 2008.
Sale of Barnett Shale Assets
In May 2009, we entered into an agreement to sell 60% of our Barnett Shale natural gas
assets to Talon Oil and Gas LLC, a privately held company, for $270 million (before closing
adjustments). We closed on approximately three-quarters of the sale in June 2009 and closed on the
remainder of the sale in July 2009. Net proceeds were $259.8 million (after preliminary closing
adjustments, and net of $8.1 million for natural gas swaps transferred in the sale). The agreement
has an effective date of June 1, 2009, and consequently operating net revenues after June 1, net of
capital expenditures, along with any other purchase price adjustments, were adjustments to the
selling price. We did not record a gain or loss on the sale in accordance with the full cost method
of accounting. We have not presented pro forma information for the disposal as the pro forma effect
was not material.
Note 3. Asset Retirement Obligations
In general, our future asset retirement obligations relate to future costs associated
with plugging and abandonment of our oil, natural gas and CO2 wells, removal of
equipment and facilities from leased acreage and land restoration. The fair value of a liability
for an asset retirement is recorded in the period in which it is incurred, discounted to its
present value using our credit adjusted risk-free interest rate, and a corresponding amount
capitalized by increasing the carrying amount of the related long-lived asset. The liability is
accreted each period, and the capitalized cost is depreciated over the useful life of the related
asset.
11
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
The following table summarizes the changes in our asset retirement obligations for the nine
months ended September 30, 2009.
|
|
|
|
|
|
|
Nine Months Ended |
|
In thousands |
|
September 30, 2009 |
|
Balance, beginning of period |
|
$ |
45,064 |
|
Liabilities incurred and assumed during period |
|
|
3,085 |
|
Revisions in estimated retirement obligations |
|
|
1,640 |
|
Liabilities settled during period |
|
|
(2,930 |
) |
Accretion expense |
|
|
2,460 |
|
Sales |
|
|
(1,008 |
) |
|
|
|
|
Balance, end of period |
|
$ |
48,311 |
|
|
|
|
|
At September 30, 2009 and December 31, 2008, $1.2 million and $1.7 million, respectively,
of our asset retirement obligation was classified in Accounts payable and accrued liabilities
under current liabilities in our Unaudited Condensed Consolidated Balance Sheets. Liabilities
incurred during the nine month period ended September 30, 2009 are primarily related to the
Hastings Field acquisition and sales during the period are primarily related to the Barnett Shale
natural gas assets (see Note 2, Acquisitions and Divestitures). We hold cash and liquid
investments in escrow accounts that are legally restricted for certain of our asset retirement
obligations. The balances of these escrow accounts were $7.5 million at September 30, 2009 and $7.4
million at December 31, 2008, respectively, and are included in Other assets in our Unaudited
Condensed Consolidated Balance Sheets.
Note 4. Notes Payable and Long-Term Indebtedness
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
In thousands |
|
2009 |
|
|
2008 |
|
9.75% Senior Subordinated Notes due 2016 |
|
$ |
426,350 |
|
|
$ |
|
|
Discount on Senior Subordinated Notes due 2016 |
|
|
(27,495 |
) |
|
|
|
|
7.5% Senior Subordinated Notes due 2015 |
|
|
300,000 |
|
|
|
300,000 |
|
Premium on Senior Subordinated Notes due 2015 |
|
|
535 |
|
|
|
599 |
|
7.5% Senior Subordinated Notes due 2013 |
|
|
225,000 |
|
|
|
225,000 |
|
Discount on Senior Subordinated Notes due 2013 |
|
|
(680 |
) |
|
|
(826 |
) |
NEJD financing Genesis |
|
|
171,408 |
|
|
|
173,618 |
|
Free State financing Genesis |
|
|
79,336 |
|
|
|
76,634 |
|
Senior bank loan |
|
|
20,000 |
|
|
|
75,000 |
|
Capital lease obligations Genesis |
|
|
3,978 |
|
|
|
4,544 |
|
Capital lease obligations |
|
|
2,327 |
|
|
|
2,705 |
|
|
|
|
|
|
|
|
Total |
|
|
1,200,759 |
|
|
|
857,274 |
|
Less current obligations |
|
|
4,698 |
|
|
|
4,507 |
|
|
|
|
|
|
|
|
Long-term debt and capital lease obligations |
|
$ |
1,196,061 |
|
|
$ |
852,767 |
|
|
|
|
|
|
|
|
Issuance of 9.75% Senior Subordinated Notes due 2016
On February 13, 2009, we issued $420 million of 9.75% Senior Subordinated Notes due 2016
(2016 Notes). The 2016 Notes, which carry a coupon rate of 9.75%, were sold at a discount
(92.816% of par), which equates to an effective yield to maturity of approximately 11.25%. The net
proceeds of $381.4 million were used to repay most of our then-outstanding borrowings under our
bank credit facility, which increased from the December 31, 2008 balance, primarily associated with
the funding of the Hastings Field acquisition (see Note 2, Acquisitions and Divestitures). In
conjunction with this debt offering we amended our bank credit facility in
early February 2009, which, among other things, allowed us to issue these senior subordinated
notes.
12
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
In June 2009, we issued an additional $6.35 million of 2016 Notes to our founder, Gareth
Roberts, as part of a Founders Retirement Agreement. In connection with this issuance, we recorded
compensation expense of $6.35 million in General and administrative expense in our Unaudited
Condensed Consolidated Statement of Operations during the second quarter.
The 2016 Notes mature on March 1, 2016, and interest on the 2016 Notes is payable March 1
and September 1 of each year beginning on September 1, 2009. We may redeem the 2016 Notes in whole
or in part at our option beginning March 1, 2013, at the following redemption prices: 104.875%
after March 1, 2013, 102.4375% after March 1, 2014, and 100%, after March 1, 2015. In addition, we
may at our option, redeem up to an aggregate of 35% of the 2016 Notes before March 1, 2012 at a
price of 109.75%. 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 2016 Notes are not subject to any sinking fund requirements.
All of our significant subsidiaries fully and unconditionally guarantee this debt.
Senior Bank Loan
To clarify that Denbury entities are allowed to guarantee obligations of other Denbury
entities, in May 2009 we amended our Sixth Amended and Restated Credit Agreement, the instrument
governing our Senior Bank Loan, to explicitly permit these guarantees and waive any possible
previous technical violations of this provision.
In June 2009 we again amended our Senior Bank Loan agreement in connection with the sale of
our Barnett Shale natural gas properties and (i) reduced our borrowing base from $1.0 billion to
$900 million and (ii) allowed for an additional percentage of our forecasted production to be
hedged through June 30, 2009. The amendment did not impact the banks commitment amount, which
remains at $750 million.
On November 1, 2009, Denbury and Encore Acquisition Company announced that they had entered
into a definitive merger agreement pursuant to which Denbury will acquire Encore in a stock and
cash transaction. Denbury received a commitment letter from J.P. Morgan Securities Inc. and
JPMorgan Chase Bank, N.A., subject to certain funding conditions, for a proposed new $1.6 billion
senior secured revolving credit facility with a term of four years, the proceeds from which would
be used to pay down our existing Senior Bank Loan and other related financing. See Managements Discussion and Analysis of
Financial Condition and Result of Operations Overview Definitive Merger Agreement to Acquire
Encore Acquisition Company for further details.
Note 5. Related Party Transactions Genesis
Interest in and Transactions with Genesis
Denburys subsidiary, Genesis Energy, LLC, is the general partner of, and together with
Denburys other subsidiaries, owns an aggregate 12% interest in Genesis Energy, L.P. (Genesis), a
publicly traded master limited partnership. Genesis business is focused on the mid-stream segment
of the oil and natural gas industry in the Gulf Coast area of the United States, and its activities
include gathering, marketing and transportation of crude oil and natural gas, refinery services,
wholesale marketing of CO2, and supply and logistic services.
We account for our 12% ownership in Genesis under the equity method of accounting as we
have significant influence over the limited partnership; however, our control is limited under the
limited partnership agreement and therefore we do not consolidate Genesis. Denbury received cash
distributions from Genesis of $8.2 million and $4.9 million during the nine months ended September
30, 2009 and 2008, respectively. We also received $0.2 million and $0.1 million during the nine
months ended September 30, 2009 and 2008, respectively, as directors fees for certain officers of
Denbury that are board members of Genesis. There are no guarantees by Denbury or any of its other
subsidiaries of the debt of Genesis or of Genesis Energy, LLC.
Incentive Compensation Agreement
In late December 2008, our subsidiary, Genesis Energy, LLC, entered into agreements with
three members of Genesis management, for the purpose of providing them incentive compensation,
which agreements make them Class B Members in Genesis Energy, LLC. The compensation agreements
provide Genesis management with the ability to earn up to an approximate aggregate 17% interest in
the incentive distributions that Genesis Energy, LLC receives (commencing in 2009) from Genesis.
The percentage
13
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
interest in the incentive distribution earned in any given period can vary based upon the Cash
Available Before Reserves (CABR) per unit as generated by Genesis (excluding any transactions
between Genesis and the Company) over each of the three individuals base amount of CABR per unit
as stated in their compensation agreement, subject to vesting and other requirements. As the amount
of CABR per unit increases, the members share of the incentive distributions increases, up to a
maximum aggregate 17% in any given period.
The amount payable under the award in the event of an employee termination is the present
value of the members share of forecasted incentive distributions assuming the then current level
of distributions continue into perpetuity. The award agreement dictates that the members share of
future incentive distributions be discounted back to the payment date using a discount rate equal
to the current distribution yield of market comparable general partners of master limited
partnerships.
The awards vest 25% on each anniversary grant date. The awards are mandatorily redeemable
upon termination of employment or change in control and require the membership interests of the
holders of the awards to be redeemed for cash (or in certain circumstances Genesis limited
partnership units) by Genesis Energy, LLC. The estimated fair value of these awards is measured
each reporting period and recorded as a liability to the extent vested. Changes in the liability
are recorded as compensation expense in General and administrative expenses in our Unaudited
Condensed Consolidated Statement of Operations. We use the graded attribution method to recognize
the share-based compensation expense associated with these awards. As of September 30, 2009, we had
approximately $8.8 million recorded as a liability for these awards in our Unaudited Condensed
Consolidated Balance Sheet. We recorded approximately $3.6 million in the three month period ended
September 30, 2009 and $9.1 million in the nine month period ended September 30, 2009 in General
and administrative expenses on our Unaudited Condensed Consolidated Statement of Operations, of
which $0.1 million and $0.3 million in the three and nine month periods, respectively, relate to
cash payments made under these awards and $3.5 million and $8.8 million, respectively, are
associated with the fair value of the award.
The fair value of these awards is estimated using a discounted cash flow analysis which
includes assumptions regarding a number of variables, including Genesis managements estimates of
future CABR generated by Genesis, the distribution yield of market comparable publicly-traded
general partners of master limited partnerships and a discount rate which considers the risk of
forecasted items being realized, the time value of money and the risk of nonperformance by Denbury.
The fair value estimation does not represent the contractual amounts payable under these awards at a particular reporting date.
NEJD Pipeline and Free State Pipeline Transactions
On May 30, 2008, we closed on two transactions with Genesis involving our Northeast
Jackson Dome (NEJD) pipeline system and Free State Pipeline, which included a long-term
transportation service agreement for the Free State Pipeline and a 20-year financing lease for the
NEJD system. We have recorded both of these transactions as financing leases. At September 30,
2009, we have recorded $171.4 million for the NEJD financing and $79.3 million for the Free State
financing as debt, $3.2 million of which was recorded in current liabilities on our Unaudited
Condensed Consolidated Balance Sheet. At December 31, 2008, we had $173.6 million for the NEJD
pipeline and $76.6 million for the Free State Pipeline recorded as debt, of which $3.0 million was
included in current liabilities in our Unaudited Condensed Consolidated Balance Sheet (see Note 4,
Notes Payable and Long-Term Indebtedness).
Oil Sales and Transportation Services
We utilize Genesis trucking services and common carrier pipeline to transport certain of
our crude oil production to sales points where it is sold to third party purchasers. We expensed
$1.9 million and $2.2 million for these transportation services during the three
months ended September 30, 2009 and 2008, respectively, and $6.1 million and $5.6 million during
the nine months ended September 30, 2009 and 2008, respectively.
Transportation Leases
We have pipeline transportation agreements with Genesis to transport our crude oil from
certain of our fields in Southwest Mississippi, and to transport CO2 from our
main CO2 pipeline to Brookhaven Field for our tertiary operations. We have
accounted for these agreements as capital leases. At September 30, 2009 and December 31, 2008, we
had $4.0 million and $4.5 million, respectively, of capital lease obligations with Genesis recorded
as liabilities in our Unaudited Condensed Consolidated Balance Sheets.
14
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
CO2 Volumetric Production Payments
During 2003 through 2005, we sold 280.5 Bcf of CO2 to Genesis under
three separate volumetric production payment agreements. We have recorded the net proceeds of these
volumetric production payment sales as deferred revenue and recognize such revenue as
CO2 is delivered under the volumetric production payments. At September 30,
2009 and December 31, 2008, $20.9 million and $24.0 million, respectively, was recorded as deferred
revenue, of which $4.1 million was included in current liabilities at both September 30, 2009 and
December 31, 2008. We recognized deferred revenue of $1.2 million for both the three month periods
ended September 30, 2009 and 2008, respectively, and $3.2 million and $3.4 million during the nine
month periods ended September 30, 2009 and 2008, respectively, for deliveries under these
volumetric production payments. We provide Genesis with certain processing and transportation
services in connection with transporting CO2 to their industrial customers for
a fee of approximately $0.20 per Mcf of CO2. For these services, we recognized
revenues of $1.5 million for both the three months ended September 30, 2009 and 2008, respectively,
and $4.0 million and $4.1 million for the nine months ended September 30, 2009 and 2008,
respectively.
Note 6. 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 Commodity derivative expense (income) in our Unaudited
Condensed Consolidated Statements of Operations.
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.
As a result of the recent economic conditions, in the fall of 2008 we entered into oil
derivative contracts for 2009 in order to protect our liquidity in the event that commodity prices
continued to decline. Since that time, we have entered into oil and natural gas commodity
contracts each quarter for a portion of our forecasted production in the following year. We have
entered into these contracts to provide us a more predictable cash flow for the following year to
protect our capital investment program in that subsequent year.
At September 30, 2009, our oil and natural gas derivative contracts were recorded at
their fair value, which was a net liability of $69.2 million. All of the mark-to-market valuations
used for our oil and natural gas derivatives are provided by external sources and are based on
prices that are actively quoted. We manage and control market and counterparty credit risk through
established internal control procedures 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 derivative contracts are with parties that are lenders
under our Senior Bank Loan.
The following is a summary of Commodity derivative expense (income) included in our
Unaudited Condensed Consolidated Statements of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
In thousands |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Receipt (payment) on settlements of derivative contracts oil |
|
$ |
18,527 |
|
|
$ |
(11,186 |
) |
|
$ |
146,365 |
|
|
$ |
(30,709 |
) |
Receipt (payment) on settlements of derivative contracts gas |
|
|
|
|
|
|
(12,886 |
) |
|
|
|
|
|
|
(30,005 |
) |
Fair value adjustments to derivative contracts income (expense) |
|
|
(22,284 |
) |
|
|
86,079 |
|
|
|
(323,426 |
) |
|
|
17,123 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative income (expense) |
|
$ |
(3,757 |
) |
|
$ |
62,007 |
|
|
$ |
(177,061 |
) |
|
$ |
(43,591 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
15
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Fair Value of Crude Oil Derivative Contracts Not Classified as Hedging Instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value |
|
|
NYMEX Contract Prices Per Bbl |
|
Asset (Liability) |
|
|
|
|
|
|
|
|
Collar Prices |
|
September 30, |
|
December 31, |
Type of Contract and Period |
|
Bbls/d |
|
Swap Price |
|
Floor |
|
Ceiling |
|
2009 |
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
Collar Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oct. 2009 - Dec.
2009 |
|
30,000 |
|
|
|
|
|
$ |
75.00 |
|
|
$ |
115.00 |
|
|
$ |
17,900 |
|
|
$ |
249,746 |
|
April 2010 - June
2010 |
|
5,000 |
|
|
|
|
|
|
50.00 |
|
|
|
76.00 |
|
|
|
(2,995 |
) |
|
|
|
|
April 2010 - June
2010 |
|
10,000 |
|
|
|
|
|
|
50.00 |
|
|
|
73.15 |
|
|
|
(7,186 |
) |
|
|
|
|
April 2010 - June
2010 |
|
5,000 |
|
|
|
|
|
|
50.00 |
|
|
|
76.40 |
|
|
|
(2,916 |
) |
|
|
|
|
April 2010 - June
2010 |
|
5,000 |
|
|
|
|
|
|
50.00 |
|
|
|
74.30 |
|
|
|
(3,343 |
) |
|
|
|
|
July 2010 - Sept.
2010 |
|
2,500 |
|
|
|
|
|
|
55.00 |
|
|
|
80.10 |
|
|
|
(1,095 |
) |
|
|
|
|
July 2010 - Sept.
2010 |
|
10,000 |
|
|
|
|
|
|
55.00 |
|
|
|
80.00 |
|
|
|
(4,416 |
) |
|
|
|
|
July 2010 - Sept.
2010 |
|
7,500 |
|
|
|
|
|
|
60.00 |
|
|
|
80.40 |
|
|
|
(2,320 |
) |
|
|
|
|
July 2010 - Sept.
2010 |
|
5,000 |
|
|
|
|
|
|
60.00 |
|
|
|
81.05 |
|
|
|
(1,430 |
) |
|
|
|
|
Oct. 2010 - Dec.
2010 |
|
5,000 |
|
|
|
|
|
|
60.00 |
|
|
|
89.70 |
|
|
|
(594 |
) |
|
|
|
|
Oct. 2010 - Dec.
2010 |
|
10,000 |
|
|
|
|
|
|
60.00 |
|
|
|
89.50 |
|
|
|
(1,238 |
) |
|
|
|
|
Oct. 2010 - Dec.
2010 |
|
5,000 |
|
|
|
|
|
|
60.00 |
|
|
|
89.00 |
|
|
|
(682 |
) |
|
|
|
|
Oct. 2010 - Dec.
2010 |
|
5,000 |
|
|
|
|
|
|
60.00 |
|
|
|
88.75 |
|
|
|
(714 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jan. 2010 - March
2010 |
|
6,667 |
|
$ |
52.50 |
|
|
|
|
|
|
|
|
|
|
|
(11,687 |
) |
|
|
|
|
Jan. 2010 - March
2010 |
|
3,333 |
|
|
52.20 |
|
|
|
|
|
|
|
|
|
|
|
(5,930 |
) |
|
|
|
|
Jan. 2010 - March
2010 |
|
5,000 |
|
|
52.10 |
|
|
|
|
|
|
|
|
|
|
|
(8,941 |
) |
|
|
|
|
Jan. 2010 - March
2010 |
|
5,000 |
|
|
50.90 |
|
|
|
|
|
|
|
|
|
|
|
(9,469 |
) |
|
|
|
|
Jan. 2010 - March
2010 |
|
5,000 |
|
|
51.45 |
|
|
|
|
|
|
|
|
|
|
|
(9,227 |
) |
|
|
|
|
Fair Value of Natural Gas Derivative Contracts Not Classified as Hedging Instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value |
|
|
NYMEX Contract |
|
Liability |
|
|
Prices Per MMBtu |
|
September 30, |
|
December 31, |
Type of Contract and Period |
|
MMBtu/d |
|
Swap Price |
|
2009 |
|
2008 |
|
|
|
|
|
|
|
|
|
|
(In thousands) |
Swap Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jan. 2010 - Dec.
2010 |
|
|
39,000 |
|
|
$ |
5.67 |
|
|
$ |
(7,289 |
) |
|
$ |
|
|
Jan. 2011 - Dec.
2011 |
|
|
10,000 |
|
|
|
6.27 |
|
|
|
(1,977 |
) |
|
|
|
|
Jan. 2011 - Dec.
2011 |
|
|
10,000 |
|
|
|
6.25 |
|
|
|
(2,026 |
) |
|
|
|
|
Jan. 2011 - Dec.
2011 |
|
|
7,000 |
|
|
|
6.16 |
|
|
|
(1,635 |
) |
|
|
|
|
16
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Additional Disclosures about Derivative Instruments:
At September 30, 2009 and December 31, 2008, we had derivative financial instruments
recorded in our Unaudited Condensed Consolidated Balance Sheets as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value |
|
|
|
|
|
|
|
Asset (Liability) |
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
Type of Contract |
|
Balance Sheet Location |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
(In thousands) |
|
Derivatives not designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Asset |
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil contracts |
|
Derivative assets - current |
|
$ |
17,900 |
|
|
$ |
249,746 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Liability |
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil contracts |
|
Derivative liability - current |
|
|
(70,955 |
) |
|
|
|
|
Natural Gas contracts |
|
Derivative liability - current |
|
|
(3,659 |
) |
|
|
|
|
Crude Oil contracts |
|
Derivative liability - long-term |
|
|
(3,228 |
) |
|
|
|
|
Natural Gas contracts |
|
Derivative liability - long-term |
|
|
(9,268 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives not designated as hedging instruments |
|
|
|
|
|
$ |
(69,210 |
) |
|
$ |
249,746 |
|
|
|
|
|
|
|
|
|
|
|
|
For the three and nine months ended September 30, 2009 and 2008, the net effect on income
of derivative financial instruments was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Gain/(Loss) |
|
|
Amount of Gain/(Loss) |
|
|
|
|
|
|
|
Recognized in Income For |
|
|
Recognized in Income For |
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
Location of Gain/(Loss) |
|
|
September 30, |
|
|
September 30, |
|
Type of Contract |
|
Recognized in Income |
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
(In thousands) |
|
Derivatives not designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Contracts |
Crude Oil Contracts |
|
Commodity derivative income (expense) |
|
$ |
(2,323 |
) |
|
$ |
11,466 |
|
|
$ |
(159,664 |
) |
|
$ |
(12,976 |
) |
Natural Gas Contracts |
|
Commodity derivative income (expense) |
|
|
(1,434 |
) |
|
|
50,541 |
|
|
|
(17,397 |
) |
|
|
(30,615 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives not designated as hedging instruments |
|
|
$ |
(3,757 |
) |
|
$ |
62,007 |
|
|
$ |
(177,061 |
) |
|
$ |
(43,591 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 7. Fair Value Measurements
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.
17
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
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:
Level 1 Quoted prices in active markets for identical assets or liabilities as of the
reporting date. During 2008 and the first nine months of 2009, we had no level 1 recurring measurements.
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
such as over-the-counter swaps. We have included an estimate of nonperformance risk in the fair
value measurement of our oil and natural gas derivative contracts. We have measured nonperformance
risk based upon credit default swaps or credit spreads. At September 30, 2009 and December 31,
2008, the fair value of our oil and natural gas derivative contracts was reduced by $2.8 million
and $3.7 million, respectively, for estimated nonperformance risk.
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 managements best estimate of fair value.
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 September
30, 2009 and December 31, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using: |
|
|
|
|
|
|
|
Significant |
|
|
|
|
|
|
|
|
|
Quoted Prices |
|
|
Other |
|
|
Significant |
|
|
|
|
|
|
in Active |
|
|
Observable |
|
|
Unobservable |
|
|
|
|
|
|
Markets |
|
|
Inputs |
|
|
Inputs |
|
|
|
|
In thousands |
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
|
Total |
|
|
September 30, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil derivative contracts |
|
$ |
|
|
|
$ |
17,900 |
|
|
$ |
|
|
|
$ |
17,900 |
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
derivative contracts |
|
|
|
|
|
|
(87,110 |
) |
|
|
|
|
|
|
(87,110 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
|
|
|
$ |
(69,210 |
) |
|
$ |
|
|
|
$ |
(69,210 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil derivative contracts |
|
$ |
|
|
|
$ |
249,746 |
|
|
$ |
|
|
|
$ |
249,746 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
|
|
|
$ |
249,746 |
|
|
$ |
|
|
|
$ |
249,746 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2009 |
|
December 31, 2008 |
|
|
Carrying |
|
Estimated |
|
Carrying |
|
Estimated |
In thousands |
|
Amount |
|
Fair Value |
|
Amount |
|
Fair Value |
9.75% Senior Subordinated Notes due 2016 |
|
$ |
398,855 |
|
|
$ |
453,000 |
|
|
$ |
|
|
|
$ |
|
|
7.5% Senior Subordinated Notes due 2015 |
|
|
300,535 |
|
|
|
298,000 |
|
|
|
300,599 |
|
|
|
213,000 |
|
7.5% Senior Subordinated Notes due 2013 |
|
|
224,320 |
|
|
|
225,000 |
|
|
|
224,174 |
|
|
|
171,000 |
|
Senior Bank Loan |
|
|
20,000 |
|
|
|
18,500 |
|
|
|
75,000 |
|
|
|
64,000 |
|
The fair values of our senior subordinated notes are based on quoted market prices. The
carrying value of our Senior Bank Loan is approximately fair value based on the fact that it is
subject to short-term floating interest rates that approximate the rates available to us for those
periods. We adjusted the estimated fair value measurement of our Senior Bank Loan for estimated
nonperformance risk. This estimated nonperformance risk totaled approximately $1.5 million and
$11.0 million at September 30, 2009 and December 31, 2008, respectively, and was determined
utilizing industry credit default swaps. We have other financial instruments consisting primarily
of cash, cash equivalents, short-term receivables and payables that approximate fair value due to
the nature of the instrument and the relatively short maturities.
Note 8. Condensed Consolidating Financial Information
Our subordinated debt is fully and unconditionally guaranteed jointly and severally by
all of Denbury Resources Inc.s subsidiaries other than minor subsidiaries, except that with
respect to our $225 million of 7.5% Senior Subordinated Notes due 2013, Denbury Resources Inc. and
Denbury Onshore, LLC are co-obligors. Except as noted in the foregoing sentence, Denbury Resources
Inc. is the sole issuer and Denbury Onshore, LLC is a subsidiary guarantor. The results of our
equity interest in Genesis are reflected through the equity method by one of our subsidiaries,
Denbury Gathering & Marketing. Each subsidiary guarantor and the subsidiary co-obligor are 100%
owned, directly or indirectly, by Denbury Resources Inc. The following is condensed consolidating
financial information for Denbury Resources Inc., Denbury Onshore, LLC, and subsidiary guarantors:
19
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2009 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
In thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
454,421 |
|
|
$ |
211,151 |
|
|
$ |
18,440 |
|
|
$ |
(469,855 |
) |
|
$ |
214,157 |
|
Property and equipment |
|
|
|
|
|
|
3,278,493 |
|
|
|
141,831 |
|
|
|
|
|
|
|
3,420,324 |
|
Investment in subsidiaries (equity method) |
|
|
1,296,596 |
|
|
|
24,315 |
|
|
|
1,294,644 |
|
|
|
(2,537,949 |
) |
|
|
77,606 |
|
Other assets |
|
|
747,676 |
|
|
|
180,361 |
|
|
|
2,555 |
|
|
|
(739,419 |
) |
|
|
191,173 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
2,498,693 |
|
|
$ |
3,694,320 |
|
|
$ |
1,457,470 |
|
|
$ |
(3,747,223 |
) |
|
$ |
3,903,260 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
8,644 |
|
|
$ |
668,979 |
|
|
$ |
150,072 |
|
|
$ |
(469,855 |
) |
|
$ |
357,840 |
|
Long-term liabilities |
|
|
699,390 |
|
|
|
1,783,988 |
|
|
|
10,802 |
|
|
|
(739,419 |
) |
|
|
1,754,761 |
|
Stockholders equity |
|
|
1,790,659 |
|
|
|
1,241,353 |
|
|
|
1,296,596 |
|
|
|
(2,537,949 |
) |
|
|
1,790,659 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
2,498,693 |
|
|
$ |
3,694,320 |
|
|
$ |
1,457,470 |
|
|
$ |
(3,747,223 |
) |
|
$ |
3,903,260 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
In thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
458,051 |
|
|
$ |
408,940 |
|
|
$ |
14,992 |
|
|
$ |
(466,784 |
) |
|
$ |
415,199 |
|
Property and equipment |
|
|
|
|
|
|
2,973,947 |
|
|
|
28,250 |
|
|
|
|
|
|
|
3,002,197 |
|
Investment in subsidiaries (equity method) |
|
|
1,371,347 |
|
|
|
24,901 |
|
|
|
1,368,759 |
|
|
|
(2,685,003 |
) |
|
|
80,004 |
|
Other assets |
|
|
312,239 |
|
|
|
89,471 |
|
|
|
899 |
|
|
|
(310,335 |
) |
|
|
92,274 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
2,141,637 |
|
|
$ |
3,497,259 |
|
|
$ |
1,412,900 |
|
|
$ |
(3,462,122 |
) |
|
$ |
3,589,674 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
970 |
|
|
$ |
810,476 |
|
|
$ |
41,405 |
|
|
$ |
(466,784 |
) |
|
$ |
386,067 |
|
Long-term liabilities |
|
|
300,599 |
|
|
|
1,373,127 |
|
|
|
148 |
|
|
|
(310,335 |
) |
|
|
1,363,539 |
|
Stockholders equity |
|
|
1,840,068 |
|
|
|
1,313,656 |
|
|
|
1,371,347 |
|
|
|
(2,685,003 |
) |
|
|
1,840,068 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
2,141,637 |
|
|
$ |
3,497,259 |
|
|
$ |
1,412,900 |
|
|
$ |
(3,462,122 |
) |
|
$ |
3,589,674 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2009 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
In thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Revenues |
|
$ |
16,247 |
|
|
$ |
225,415 |
|
|
$ |
(1 |
) |
|
$ |
(16,247 |
) |
|
$ |
225,414 |
|
Expenses |
|
|
17,763 |
|
|
|
182,412 |
|
|
|
2,059 |
|
|
|
(16,247 |
) |
|
|
185,987 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before the following: |
|
|
(1,516 |
) |
|
|
43,003 |
|
|
|
(2,060 |
) |
|
|
|
|
|
|
39,427 |
|
Equity in net earnings of subsidiaries |
|
|
28,401 |
|
|
|
212 |
|
|
|
30,613 |
|
|
|
(57,391 |
) |
|
|
1,835 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
26,885 |
|
|
|
43,215 |
|
|
|
28,553 |
|
|
|
(57,391 |
) |
|
|
41,262 |
|
Income tax provision |
|
|
|
|
|
|
14,225 |
|
|
|
152 |
|
|
|
|
|
|
|
14,377 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
26,885 |
|
|
$ |
28,990 |
|
|
$ |
28,401 |
|
|
$ |
(57,391 |
) |
|
$ |
26,885 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2008 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
In thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Revenues |
|
$ |
5,625 |
|
|
$ |
407,461 |
|
|
$ |
13 |
|
|
$ |
(5,625 |
) |
|
$ |
407,474 |
|
Expenses |
|
|
5,745 |
|
|
|
155,578 |
|
|
|
839 |
|
|
|
(5,625 |
) |
|
|
156,537 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before the following: |
|
|
(120 |
) |
|
|
251,883 |
|
|
|
(826 |
) |
|
|
|
|
|
|
250,937 |
|
Equity in net earnings of subsidiaries |
|
|
157,658 |
|
|
|
362 |
|
|
|
159,209 |
|
|
|
(314,449 |
) |
|
|
2,780 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
157,538 |
|
|
|
252,245 |
|
|
|
158,383 |
|
|
|
(314,449 |
) |
|
|
253,717 |
|
Income tax provision (benefit) |
|
|
(10 |
) |
|
|
95,454 |
|
|
|
725 |
|
|
|
|
|
|
|
96,169 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
157,548 |
|
|
$ |
156,791 |
|
|
$ |
157,658 |
|
|
$ |
(314,449 |
) |
|
$ |
157,548 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Statements of Operations (continued)
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Nine Months Ended September 30, 2009 |
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Denbury |
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Denbury |
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Resources Inc. |
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Onshore, LLC |
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Denbury |
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(Parent and Co- |
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(Issuer and Co- |
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Guarantor |
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Resources Inc. |
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In thousands |
|
Obligor) |
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|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
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|
Consolidated |
|
Revenues |
|
$ |
42,967 |
|
|
$ |
612,597 |
|
|
$ |
1 |
|
|
$ |
(42,967 |
) |
|
$ |
612,598 |
|
Expenses |
|
|
46,816 |
|
|
|
735,599 |
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|
|
7,333 |
|
|
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(42,967 |
) |
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|
746,781 |
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Loss before the following: |
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(3,849 |
) |
|
|
(123,002 |
) |
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|
(7,332 |
) |
|
|
|
|
|
|
(134,183 |
) |
Equity in net earnings of subsidiaries |
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|
(74,803 |
) |
|
|
628 |
|
|
|
(67,180 |
) |
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|
147,157 |
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|
|
5,802 |
|
|
|
|
|
|
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Loss before income taxes |
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(78,652 |
) |
|
|
(122,374 |
) |
|
|
(74,512 |
) |
|
|
147,157 |
|
|
|
(128,381 |
) |
Income tax provision (benefit) |
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|
|
|
|
|
(50,020 |
) |
|
|
291 |
|
|
|
|
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|
|
(49,729 |
) |
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|
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|
|
|
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|
|
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|
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Net loss |
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$ |
(78,652 |
) |
|
$ |
(72,354 |
) |
|
$ |
(74,803 |
) |
|
$ |
147,157 |
|
|
$ |
(78,652 |
) |
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Nine Months Ended September 30, 2008 |
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Denbury |
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Denbury |
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Resources Inc. |
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Onshore, LLC |
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Denbury |
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(Parent and Co- |
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(Issuer and Co- |
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|
Guarantor |
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|
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|
|
Resources Inc. |
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In thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
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|
Consolidated |
|
Revenues |
|
$ |
16,875 |
|
|
$ |
1,141,745 |
|
|
$ |
33 |
|
|
$ |
(16,875 |
) |
|
$ |
1,141,778 |
|
Expenses |
|
|
17,236 |
|
|
|
589,461 |
|
|
|
2,471 |
|
|
|
(16,875 |
) |
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|
592,293 |
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Income (loss) before the following: |
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(361 |
) |
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|
552,284 |
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(2,438 |
) |
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|
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|
549,485 |
|
Equity in net earnings of subsidiaries |
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|
344,933 |
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|
|
540 |
|
|
|
348,301 |
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|
|
(689,978 |
) |
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|
3,796 |
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Income before income taxes |
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344,572 |
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|
552,824 |
|
|
|
345,863 |
|
|
|
(689,978 |
) |
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|
553,281 |
|
Income tax provision (benefit) |
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|
(31 |
) |
|
|
207,779 |
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|
930 |
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|
208,678 |
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Net income |
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$ |
344,603 |
|
|
$ |
345,045 |
|
|
$ |
344,933 |
|
|
$ |
(689,978 |
) |
|
$ |
344,603 |
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Condensed Consolidating Statements of Cash Flows
Denbury Resources Inc. (Parent) has no independent assets or operations. Denbury Onshore,
LLC is our operating subsidiary. Cash flow activity of Denbury Resources Inc. consists of
intercompany loans between Denbury Resources Inc. and Denbury Onshore, LLC to service the parent
company issued debt. This intercompany cash flow activity is eliminated in consolidation. Cash flow
activity of Denbury Onshore, LLC combined with the other guarantor subsidiaries is presented in our
Unaudited Condensed Consolidated Statements of Cash Flows.
22
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
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Nine Months Ended September 30, 2009 |
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Denbury |
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Denbury |
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Resources Inc. |
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Onshore, LLC |
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Denbury |
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(Parent and Co- |
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|
(Issuer and Co- |
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Guarantor |
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|
Resources Inc. |
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In thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
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Eliminations |
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|
Consolidated |
|
Cash flow from operations |
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$ |
|
|
|
$ |
406,192 |
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$ |
242 |
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$ |
|
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$ |
406,434 |
|
Cash flow from investing activities |
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(409,293 |
) |
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(736,390 |
) |
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|
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|
409,293 |
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|
(736,390 |
) |
Cash flow from financing activities |
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|
409,293 |
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|
334,576 |
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(409,293 |
) |
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334,576 |
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Net increase in cash |
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4,378 |
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|
242 |
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|
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|
4,620 |
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Cash, beginning of period |
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|
24 |
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|
16,898 |
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|
147 |
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|
17,069 |
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Cash, end of period |
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$ |
24 |
|
|
$ |
21,276 |
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$ |
389 |
|
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$ |
|
|
|
$ |
21,689 |
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Nine Months Ended September 30, 2008 |
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|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
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|
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|
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|
Resources Inc. |
|
|
Onshore, LLC |
|
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|
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|
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|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
In thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Cash flow from operations |
|
$ |
(10 |
) |
|
$ |
622,674 |
|
|
$ |
10,107 |
|
|
$ |
|
|
|
$ |
632,771 |
|
Cash flow from investing activities |
|
|
(25,344 |
) |
|
|
(612,064 |
) |
|
|
(5,613 |
) |
|
|
25,344 |
|
|
|
(617,677 |
) |
Cash flow from financing activities |
|
|
25,344 |
|
|
|
100,109 |
|
|
|
|
|
|
|
(25,344 |
) |
|
|
100,109 |
|
|
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|
|
|
|
|
|
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|
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|
Net increase (decrease) in cash |
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(10 |
) |
|
|
110,719 |
|
|
|
4,494 |
|
|
|
|
|
|
|
115,203 |
|
Cash, beginning of period |
|
|
34 |
|
|
|
58,343 |
|
|
|
1,730 |
|
|
|
|
|
|
|
60,107 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, end of period |
|
$ |
24 |
|
|
$ |
169,062 |
|
|
$ |
6,224 |
|
|
$ |
|
|
|
$ |
175,310 |
|
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Note 9. Subsequent Event
On October 31, 2009, the Company entered into a definitive merger agreement pursuant to which
the Company will acquire Encore Acquisition Company (NYSE: EAC) (Encore). Under the terms of the
definitive agreement, Encore stockholders will receive $50.00 per share for each share of Encore
common stock, comprised of $15.00 in cash and $35.00 in Denbury common stock subject to both an
election feature and a collar mechanism on the stock portion of the
consideration. Consummation of the merger is subject to customary
conditions. See
Managements Discussion and Analysis of Financial Condition and Results of Operations Overview -
Definitive Merger Agreement to Acquire Encore Acquisition Company for further details on the terms
of this agreement.
23
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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Item 2. |
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Managements 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 Form 10-K for the year ended
December 31, 2008, along with Managements Discussion and Analysis of Financial Condition and
Results of Operations contained in such Form 10-K. Any terms used but not defined in the following
discussion have the same meaning given to them in the Form 10-K. Our discussion and analysis
includes forward-looking information that involves risks and uncertainties and should be read in
conjunction with Risk Factors under Item 1A of this report, along with Forward-Looking
Information at 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 engaged in acquisition,
development and exploration activities in the U.S. Gulf Coast region. We are the largest oil and
natural gas producer in Mississippi, own the largest carbon dioxide (CO2)
reserves east of the Mississippi River used for tertiary oil recovery, hold interests in the
Barnett Shale play near Fort Worth, Texas, and properties onshore in Louisiana, Alabama and
Southeast Texas. Our goal is to increase the value of acquired properties through a combination of
exploitation, drilling, and proven engineering extraction processes, with our most significant
emphasis relating to tertiary recovery. Our corporate headquarters are in Plano, Texas (a suburb of
Dallas), and we have four primary field offices located in Laurel, Mississippi; McComb,
Mississippi; Jackson, Mississippi; and Pearland, Texas.
Third
Quarter Operating Highlights. During the third quarter of 2009,
we recorded net income of
$26.9 million, or $0.11 per basic common share, as compared to net income of $157.5 million, or
$0.64 per basic common share, in the comparative third quarter of 2008. The reduction in net
income between the periods is primarily due to lower oil and natural gas commodity prices coupled
with reduced natural gas production due to the sale of 60% of the Companys Barnett Shale natural
gas assets in mid-2009, and a $108.4 million net decrease in the fair value changes in commodity
derivative contracts in the comparative periods.
Oil and natural gas production for the third quarter of 2009 averaged 42,659 BOE/d, a 10%
increase from third quarter 2008 production, after adjusting for the 2009 sale of 60% of the
Companys Barnett Shale natural gas assets. The increase over the prior year third quarter period
was primarily due to a 23% increase in tertiary oil production and production from Hastings Field
(2,083 BOE/d in the current year quarter), which we acquired in February 2009, offset in
part by the expected decrease in our non-tertiary Mississippi production. The
non-tertiary Mississippi production decline was primarily from the Selma Chalk natural gas
production as a result of limited drilling activity in 2009 and non-tertiary Heidelberg oil
as additional areas of the field were shut-in in order to expand the tertiary flooding to those
areas. On a sequential quarterly basis, our oil and natural gas production decreased 4%, primarily
due to the decreases in non-tertiary Mississippi production offset in part by a slight increase in
our tertiary production.
During
the third quarter of 2009, our tertiary production averaged 24,347 Bbls/d,
which included 829 Bbls/d from tertiary production response at Heidelberg Field. During the
quarter, we also had strong production increases compared to the prior quarter, at Tinsley
(averaging 3,558 Bbls/d, a 5% increase), Soso (averaging 2,813 Bbls/d, a 9% increase), Lockhart
Crossing (averaging 882 Bbls/d, a 26% increase), and Cranfield (averaging 572 Bbls/d, a 69%
increase). These increases were offset in part by planned downtime at Mallalieu Field for facility
expansion during the quarter, and we also expanded our facilities at Tinsley Field,
earlier than originally planned, reducing the production rate of growth at that field during the
third quarter.
In addition to the decrease in our third quarter 2009 production due to the Barnett Shale
sale, our oil and natural gas revenues were 45% lower in the third quarter of 2009 than in the
prior year third quarter, as the average price we received for our production on a per BOE basis
was 41% lower in the current year period. Since over 80% of our production is oil, oil prices have
a much larger impact on our revenues than natural gas prices. NYMEX oil prices moved from $44.60
per barrel at December 31, 2008 to as low as $34.00 per barrel in mid-February 2009, up to $49.66
per barrel at March 31, 2009, $69.89 per barrel at June 30, 2009 and $70.61 per barrel at September
30, 2009. NYMEX natural gas prices have decreased from year-end 2008, falling from $5.62 per Mcf at
December 31, 2008 to $3.78 per Mcf at March 31, 2009, $3.84 per Mcf at June 30, 2009, then
recovering slightly, and ending the third quarter 2009 at $4.84 per Mcf.
Cash settlements received on our commodity derivative contracts, which are not included
in our oil and natural gas revenues, were $18.5 million in the third quarter of 2009, as compared
to payments of $24.1 million in the third quarter of 2008, the prior year amount comprised of
payments made of $11.2 million on oil derivative contracts and $12.9 million on natural gas
derivative contracts.
24
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Definitive Merger Agreement to Acquire Encore Acquisition Company. On November 1,
2009, Denbury and Encore Acquisition Company (NYSE: EAC) (Encore) announced that they had entered
into a definitive merger agreement pursuant to which Denbury will acquire Encore in a stock and
cash transaction valued at approximately $4.5 billion, including the assumption of debt and the
value of the minority interest in Encore Energy Partners LP (NYSE: ENP) (Encore MLP). The
combined company will continue to be known as Denbury Resources Inc. and will be headquartered in
Plano, Texas.
The Agreement and Plan of Merger by and between Denbury and Encore dated October 31, 2009 (the
Merger Agreement) was unanimously approved by the boards of directors of both Denbury and Encore.
The Merger Agreement contemplates a merger (the Merger) whereby Encore will be merged with and
into Denbury, with Denbury surviving the Merger. The Merger is subject to the stockholders of each
of Denbury and Encore approving the Merger, including approval by Denburys stockholders of the
issuance of Denbury common stock to be used as Merger consideration.
Under the agreement, Encore stockholders will receive $50.00 per share for each share of
Encore common stock, comprised of $15.00 in cash and $35.00 in Denbury common stock subject to both
an election feature and a collar mechanism on the stock portion of the consideration as set forth
in more detail below.
Merger Agreement
Exchange Ratio
In calculating the exchange ratio range for the collar mechanism, the Denbury common stock was
initially valued at $15.10 per share. The collar mechanism is limited to a 12% upward or downward
movement in the Denbury share price. The final number of Denbury shares to be issued will be
adjusted based on the volume weighted average price of Denbury common stock on the NYSE for the 20
day trading period ending on the second day prior to closing. Based on this mechanism, if Denbury
stock trades between $13.29 and $16.91, the Encore stockholders will receive between 2.0698 and
2.6336 shares of Denbury common stock for each of their shares of Encore common stock, but not
higher or lower than these share amounts if Denbury common stock trades outside this range. If
Denbury common stock trades outside of this range, the value of the shares of Denbury received will
represent either more or less than $35 per share.
Encore stockholders will also have an option to elect to receive all stock or all cash,
subject to a proration feature, such that if Denbury stock trades within this range, the overall
mix of consideration will be 70% Denbury common stock and 30% cash in the aggregate. Subject to
proration, Encore stockholders electing to receive all cash will receive $50 per share in cash, and
Encore stockholders electing to receive only Denbury common stock will receive for each Encore
share between 2.9568 and 3.7622 shares of Denbury common stock. In addition, upon completion of
the Merger, all Encore stock options will fully vest and their value will be paid in cash. All
Encore restricted stock will vest and each holder will have the opportunity to make the same
elections as other holders of Encore common stock as described above, except for shares of Encore
restricted stock granted as a 2009 bonus pursuant to the Encore annual incentive program, which
will be converted into restricted shares of Denbury common stock.
Covenants
The Merger Agreement contains customary covenants by each party to the Merger Agreement. Such
covenants include, among others, covenants that both Denbury and Encore will operate their
respective businesses in the ordinary course and in a manner consistent with past practices,
subject to limited exceptions, and covenants by both Denbury and Encore that their respective
boards of directors not change their recommendations to the stockholders of each of them to vote in
favor of the Merger, subject to exceptions specified in the Merger Agreement. Encore has also
agreed not to solicit or initiate discussions with third parties regarding other proposals to
acquire Encore and to certain restrictions on its ability to respond to any such proposal.
Conditions to Closing
Consummation of the Merger is subject to customary conditions, including, among others, (a)
the approval of the stockholders of each of Denbury and Encore, (b) the absence of any material
adverse effect, (c) the expiration or early termination of the applicable Hart-Scott-Rodino Act
waiting period, (d) the absence of any order or injunction prohibiting the consummation of the
Merger, (e) the effectiveness of the registration statement of Denbury filed on Form S-4, (f) the
approval of the listing of the shares of Denbury common stock to be issued in the Merger on the New
York Stock Exchange, (g) the accuracy of the parties respective representations and warranties as
set forth in the Merger Agreement, subject, as to certain of the representations and warranties as
specified in the Merger Agreement, to materiality, (h) the receipt of legal opinions stating, among
other things, that the Merger will constitute a reorganization under Section 368(a) of the Internal
Revenue Code of 1986, as amended, (i) the receipt of all approvals or reviews required by federal
and state regulatory authorities and (j) financing.
25
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
In connection with the Merger Agreement, Denbury received a commitment letter from J.P. Morgan
Securities Inc. and JPMorgan Chase Bank, N.A., subject to certain funding conditions, for a
proposed new $1.6 billion senior secured revolving credit facility with a term of four years and a
$1.25 billion bridge facility that will be available to the extent Denbury does not secure
alternate financing prior to the end of the bridge takedown period. The bridge facility, if drawn,
will initially mature on the first anniversary of the closing of the Merger, at which time the
maturity of any outstanding loans thereunder will be automatically extended to the seventh
anniversary of the closing of the Merger, except to the extent they have been previously exchanged
by the lender for exchange notes due on such seventh anniversary. The new debt financing will be
used to pay the cash consideration in the Merger, repay amounts outstanding under Denburys current
$900 million revolving credit facility and potentially retire and replace $825 million of Encores
outstanding subordinated notes, all of which have a change of control put option at 101%, replace
Encores existing bank facility which has approximately $180 million currently drawn and
outstanding, and for other fees and expenses. Denbury has also received a commitment from J. P.
Morgan Securities Inc. and JP Morgan Chase Bank to fund a new $375 million senior secured revolving
credit facility to replace an existing Encore MLP revolving loan facility should Denbury and Encore
be unable to obtain a waiver of covenants and amendment to such loan facility to allow for the
Merger. Fee letters executed in connection with the bank commitment letter provide for Denbury to
pay up to approximately $50 million in fees if the loans do not close.
Termination
The Merger Agreement contains certain termination rights for both Denbury and Encore, including,
among others, if the Merger is not completed by May 31, 2010. In the event of a termination of the
Merger Agreement under certain circumstances, Encore may be required to pay Denbury a termination
fee of either $60 million or $120 million, or Denbury may be required to pay Encore a termination
fee of either $60 million, $120 million or $300 million, in each case depending on the
circumstances of the termination. In addition, Encore is obligated to reimburse Denbury for up to
$10 million of its expenses related to the Merger if specified termination events occur.
Sale of Barnett Shale Natural Gas Assets. In May 2009, we entered into an agreement to
sell 60% of our Barnett Shale assets to Talon Oil and Gas LLC, a privately held company, for $270
million (before closing adjustments). The effective date under the agreement was June 1, 2009, and
consequently operating net revenues after June 1, net of capital expenditures, along with any other
purchase price adjustments, were adjustments to the selling price. On June 30, 2009, we completed
approximately three-quarters of the sale, and closed the remaining portion of the sale on July 15,
2009. Net proceeds were $259.8 million (after closing adjustments, and net of $8.1 million for
natural gas swaps transferred in the sale). We used the net proceeds from the sale to repay bank
debt. We did not record a gain or loss on the sale in accordance with the full cost method of
accounting.
Recent Management Changes. On June 30, 2009, under a management succession plan adopted
by our Board of Directors and announced on February 5, 2009, Gareth Roberts, the Companys founder,
relinquished his position as President and CEO and became Co-Chairman of the Board of Directors and
assumed a non-officer role as the Companys Chief Strategist. Phil Rykhoek, previously Senior Vice
President and Chief Financial Officer, became Chief Executive Officer; Tracy Evans, previously
Senior Vice President Reservoir Engineering, became President and Chief Operating Officer; and
Mark Allen, previously Vice President and Chief Accounting Officer, became Senior Vice President
and Chief Financial Officer.
In connection with Mr. Roberts retirement as CEO and President of the Company,
Mr. Roberts and the Company entered into a Founders Retirement Agreement (the Agreement). Under
this Agreement, Mr. Roberts received compensation of (i) $3.65 million in cash, plus (ii) the
Company issued him $6.35 million of the Companys 9.75% Senior Subordinated Notes due 2016. As part
of the Agreement, there are restrictions that prohibit Mr. Roberts from trading the Notes for two
years, and he has entered into a non-compete arrangement with the Company through 2013. Mr. Roberts
will continue to provide services to the Company as Co-Chairman of the Board of Directors and in a
non-officer role as Chief Strategist.
Purchase of Hastings Field. On February 2, 2009, we closed the acquisition of Hastings
Field located near Houston, Texas for approximately $201 million in cash. Hastings Field is a
significant potential tertiary oil flood that we plan to flood with CO2
delivered from Jackson Dome using our Green Pipeline, which is currently under
construction. We originally entered into an agreement in November 2006 with a subsidiary of Venoco,
Inc., that gave us the option to purchase their interest in the Hastings Field. As consideration
for the purchase option, we made total payments of $50 million which makes our aggregate purchase
price $251 million. The seller retained a 2% override and reversionary interest of approximately
25% following payout, as defined in the purchase agreement. We plan to commence flooding the field
with CO2 beginning in 2011, after completion of our Green Pipeline and
construction of field recycling facilities. Under the purchase agreement, we are required to make
net capital expenditures in this field totaling $179 million over the next six years, including our
first obligation of $26.8 million during 2010, and are committed to begin CO2
injections averaging 50 MMcf/d by the fourth quarter of 2012. Production from this field averaged
2,083 BOE/d during the third quarter of 2009, all of which was non-tertiary production.
26
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
We have recorded the acquisition of Hastings Field in accordance with the Financial
Accounting Standards Board (FASB) Accounting Standards CodificationTM (FASC)
Business Combinations topic, which became effective for acquisitions after December 31, 2008.
Based on these new rules, we have allocated $105.6 million of the $246.8 million adjusted purchase
price to proved properties, approximately $2.4 million to land, oilfield equipment and other
related assets, and the remaining $138.8 million to goodwill. See further discussion on this
acquisition in Note 2 to the Unaudited Condensed Consolidated Financial Statements.
Subordinated Debt Issuance. On February 13, 2009, we issued $420 million of 9.75% Senior
Subordinated Notes due 2016 (the Notes). The Notes were sold to the public at 92.816% of par,
plus accrued interest from February 13, 2009, which equates to an effective yield to maturity of
approximately 11.25% (before offering expenses). Interest on the Notes will be paid on March 1 and
September 1 of each year, beginning September 1, 2009. The Notes will mature on March 1, 2016. We
used the net proceeds from the offering of approximately $381.4 million to repay most of the then
outstanding debt on our bank credit facility. We issued an additional $6.35 million of Notes to
Mr. Roberts on June 30, 2009 (see Recent Management Changes above).
Capital Resources and Liquidity
In a continuing effort to mitigate the effects of the deterioration in the capital
markets and the steep decline in commodity prices in the last half of 2008, we have taken
additional measures during the first nine months of 2009 to improve our liquidity. In
February 2009, we issued $420 million of 9.75% Senior Subordination Notes and in June and
July 2009, we completed the sale of 60% of our Barnett Shale assets. We used the $381.4 million
proceeds from the February Notes issuance to repay the majority of our then-outstanding bank debt,
and we did the same with the proceeds from our recent Barnett Shale sale, freeing up our credit
line for future capital needs. We also entered into additional commodity derivative contracts for
2010 to protect our cash flow. Our derivative contracts as of September 30, 2009 are included in
Note 6 to the Unaudited Condensed Consolidated Financial Statements.
Subsequent to September 30, 2009, we entered into additional costless collar crude oil
commodity derivative contracts to protect our cash flows during 2010 as follows: 5,000
barrels per day during the first quarter of 2010 with a floor price of $70 per barrel and a ceiling
price of $92.20 per barrel; 5,000 barrels per day during the second quarter of 2010 with a floor
price of $70 per barrel and a ceiling price of $95.25 per barrel; and 5,000 barrels per day during the
third and fourth quarters of 2010 with a floor price of $70 per barrel and a ceiling price of
$96.50 per barrel. Also, in light of the recently announced
acquisition of Encore and our desire to protect our cash flows given
the increased debt levels we expect in connection with the acquisition,
we recently entered into costless collar crude oil commodity
derivative contracts for 25,000 barrels per day during 2011 with a floor price of $70 per barrel and
a ceiling price of $102.58 per barrel.
We currently estimate our 2009 capital spending will be approximately $750 million,
excluding capitalized interest and net of equipment leases, plus $201 million spent for our
February 2009 Hastings Field acquisition. Our current 2009 capital budget includes approximately
$500 million to be spent on our CO2 pipelines, the majority of which will be
spent on the Green Pipeline. The budget also assumes that we fund approximately $100 million of
budgeted equipment purchases with operating leases, which is dependent upon securing acceptable
financing. Through September 30, 2009, we have completed approximately $44 million of these leases.
If we do not enter into a total of $100 million of operating leases during 2009, our net capital
expenditures would increase accordingly, and we would anticipate funding those additional capital
expenditures under our bank credit line.
Based on our current cash flow projections using futures prices as of the end of
October 2009, and including the expected cash settlements on our 2009 oil derivative contracts, we
anticipate that these projected 2009 capital expenditure amounts of
approximately $750 million, plus our already closed $201 million
Hastings acquisition, could, in the aggregate, exceed projected cash
flow by as much as $450 million to
$550 million. This shortfall should be covered by the $381.4 million of net proceeds from our
February 2009 subordinated debt issuance and the estimated $259.8 million of net proceeds (after
closing adjustments and net of $8.1 million for natural gas swaps transferred in the sale) from the
sale of 60% of our Barnett Shale properties.
As
part of our semi-annual bank review, on October 1, 2009 our
bank borrowing base and commitment amounts were left unchanged at $900
million and $750 million, respectively. The borrowing base represents the amount that can be borrowed from
a credit standpoint while the commitment amount is the amount the banks have committed to fund
pursuant to the terms of the credit agreement. We anticipate this credit line will be sufficient
for our 2009 plans, and do not expect our bank credit line to be reduced by our banks unless
commodity prices were to decrease significantly from current levels. Based on current projections,
we expect to have little or no bank debt drawn at the end of 2009
assuming we achieve our $100 million budgeted equipment leasing
program, leaving up to $750 million
available on our bank line.
Although
we have not yet set our capital budget for 2010, we do expect to
utilize the net proceeds from our Barnett Shale sale to increase our
capital spending above our projected 2010 cash flow levels. We have
structured the financing for our proposed acquisition with Encore to
provide us with an estimated level of liquidity similar to that
expected before the acquisition. We currently do not anticipate raising any additional capital during 2009 unless needed
for an acquisition or alternate financing associated with the
recently announced merger discussed above in
Overview Definitive Merger Agreement to Acquire Encore Acquisition Company. We continually
monitor our capital spending and anticipated cash flows and believe that we can adjust our capital
27
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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 2009, we have contracted for certain
capital expenditures, including construction of most of the Green Pipeline already in progress and
two drilling rigs, and therefore the portion of capital that we could eliminate without significant
penalty is limited (refer to Managements Discussion and Analysis of Financial Condition and
Results of Operations Off-Balance Sheet Arrangements Commitments and Obligations in our 2008
Form 10-K for further information regarding these commitments).
Sources and Uses of Capital Resources
Capital Expenditure Summary
The following table of capital expenditures includes accrued capital for each period. Our
cash expenditures were $54.8 million higher in the 2009 period and $24.3 million lower in the 2008
period than the amounts listed below due to the increase (decrease) in our capital accruals in
those periods.
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
September 30, |
|
In thousands |
|
2009 |
|
|
2008 |
|
Oil and natural gas exploration and development: |
|
|
|
|
|
|
|
|
Drilling |
|
$ |
41,150 |
|
|
$ |
186,249 |
|
Geological, geophysical and acreage |
|
|
10,713 |
|
|
|
14,084 |
|
Facilities |
|
|
136,556 |
|
|
|
117,423 |
|
Recompletions |
|
|
56,251 |
|
|
|
104,476 |
|
Capitalized interest |
|
|
10,440 |
|
|
|
13,639 |
|
|
|
|
|
|
|
|
Total oil and natural gas exploration and development expenditures |
|
|
255,110 |
|
|
|
435,871 |
|
Oil and gas property acquisitions |
|
|
197,534 |
|
|
|
4,262 |
|
|
|
|
|
|
|
|
Total oil and natural gas capital expenditures |
|
|
452,644 |
|
|
|
440,133 |
|
|
|
|
|
|
|
|
CO2 capital expenditures |
|
|
|
|
|
|
|
|
CO2 pipelines |
|
|
456,590 |
|
|
|
139,890 |
|
CO2 producing fields |
|
|
28,562 |
|
|
|
90,658 |
|
Capitalized interest |
|
|
38,259 |
|
|
|
5,885 |
|
|
|
|
|
|
|
|
Total CO2 capital expenditures |
|
|
523,411 |
|
|
|
236,433 |
|
|
|
|
|
|
|
|
Total |
|
$ |
976,055 |
|
|
$ |
676,566 |
|
|
|
|
|
|
|
|
During the first nine months of 2009, we have recorded approximately $833 million of
cash used for capital expenditures, which includes $49 million in capitalized interest and $44
million that was subsequently leased in sale leaseback transactions. In addition, our liabilities
for capital expenditures were approximately $55 million lower at September 30, 2009 than at December
31, 2008, representing cash outflows related to our capital
expenditures actually incurred in 2008. These
amounts net together resulting in $685 million of our $750 million capital budget. In addition, we
have approximately $55 million of equipment available for sale leaseback financings for the
remainder of 2009, which if completed, would leave
$120 million of our 2009 capital expenditure budget available
for the fourth quarter.
If we do not complete the full $55 million of remaining equipment leases in 2009, it is likely that we would
carry those over into 2010.
Our capital expenditures for the first nine months of 2009 were funded with
$406.4 million of cash flow from operations, $259.8 million of net proceeds from the sale of a
portion of our Barnett Shale natural gas assets and $381.4 million of proceeds from the
February 2009 issuance of 9.75% Senior Subordinated Notes. Our capital expenditures for the first
nine months of 2008 were funded with $632.8 million of cash flow from operations, $225 million from
the dropdown of CO2 pipelines to Genesis, and $48.9 million from the proceeds
from the second closing on our Louisiana property sale.
28
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Off-Balance Sheet Arrangements
Commitments and Obligations
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 the proved reserve reports. Our derivative contracts are
discussed in Note 6 to the Unaudited Condensed Consolidated Financial Statements.
On February 2, 2009, we closed our $201 million purchase of Hastings Field. Under the
agreement, we are required to make aggregate net cumulative capital expenditures in this field of
approximately $179 million over the next six years cumulating as follows: $26.8 million by December
31, 2010, $71.5 million by December 31, 2011, $107.2 million by December 31, 2012, $142.9 million
by December 31, 2013, and $178.7 million by December 31, 2014. If we fail to spend the required
amounts by the due dates, we are required to make a cash payment equal to 10% of the cumulative
shortfall at each applicable date. Further, we are committed to injecting at least an average of 50
MMcf/d of CO2 (total of purchased and recycled) in the West Hastings Unit for
the 90 day period prior to January 1, 2013. If such injections do not occur, we must either (1)
relinquish our rights to initiate (or continue) tertiary operations and reassign to Venoco all
assets previously purchased for the value of such assets at that time based upon the discounted
value of the fields proved reserves using a 20% discount rate, or (2) make an additional payment
of $20 million in January 2013, less any payments made for failure to meet the capital spending
requirements as of December 31, 2012, and a $30 million payment for each subsequent year (less
amounts paid for capital expenditure shortfalls) until the CO2 injection rate
in the Hastings Field equals or exceeds the minimum required injection rate.
We currently have long-term commitments to purchase CO2 from eight
proposed gasification plants, four of which are in the Gulf Coast region and four in the Midwest
region (Illinois, Indiana and Kentucky). The Midwest plants are not only conditioned on the
specific plants being constructed, but also upon Denbury contracting additional volumes of
CO2 for purchase in the general area of the proposed plants that would provide
an acceptable economic return on the CO2 pipeline that we would need to
construct to transport these volumes to our existing CO2 pipeline system. If
all of these plants were to be built, these CO2 sources are currently
anticipated to provide us with aggregate CO2 volumes of 1.2 Bcf/d to 1.9 Bcf/d.
Due to the current economic conditions, the earliest we would expect any plant to be completed and
providing
CO2 would be 2014, and there is some doubt as to whether they will be
constructed at all. The base price of CO2 per Mcf from these
CO2 sources varies by plant and location, but is generally higher than our most
recent all-in cost of CO2 from our natural source (Jackson Dome) using current
oil prices. Prices for CO2 delivered from these projects are expected to be
competitive with the cost of our natural CO2 after adjusting for our share of
potential carbon emissions reduction credits using estimated futures prices of carbon emissions
reduction credits. If all eight plants are built, the aggregate purchase obligation for this
CO2 would be around $280 million per year, assuming a $70 per barrel oil price,
before any potential savings from our share of carbon emissions reduction credits. All of the
contracts have price adjustments that fluctuate based on the price of oil. Construction has not yet
commenced on any of these plants, and their construction is contingent on the satisfactory
resolution of various issues, including financing. While it is likely that not every plant
currently under contract will be constructed, there are several other plants under consideration
that could provide CO2 to us that would either supplement or replace some of
the CO2 volumes from the eight proposed plants for which we currently have
CO2 output purchase contracts. We are having ongoing discussions with several
of these other potential sources.
Neither the amounts nor the terms of any other commitments or contingent obligations have
changed significantly from the year-end amounts reflected in our 2008 Form 10-K filed in March 2009
other than as discussed above, and other than our commitments associated with our recently
announced acquisition of Encore, discussed above in Overview Definitive Merger Agreement to
Acquire Encore Acquisition Company, including the fee letters executed in connection with the bank
commitment letter that provide for Denbury to pay up to approximately $50 million in fees if the
loans do not close, and our February 2009 subordinated debt issuance discussed in Overview
Subordinated Debt Issuance. Please refer to Managements Discussion and Analysis of Financial
Condition and Results of Operations Off-Balance Sheet Arrangements Commitments and
Obligations contained in our 2008 Form 10-K for further information regarding our commitments and
obligations.
29
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Results of Operations
CO2 Operations
Our focus on CO2 operations is becoming an ever-increasing part of
our business and operations. We believe that there are significant additional oil reserves and
production that can be obtained through the use of CO2, and we have outlined
certain of this potential in our 2008 annual report 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 to Managements Discussion and Analysis of Financial
Condition and Results of Operations and the section entitled CO2 Operations
contained in our 2008 Form 10-K for further information regarding these matters.
During 2009, we drilled one additional CO2 source well to further
increase our production capacity and reserves at Jackson Dome. Preliminary estimates of CO2 reserves added
during the third quarter are 358 Bcf of CO2 as a result
of drilling and completing the Kuriger Trust well at Gluckstadt Field. We estimate that
we are currently capable of producing between 900 MMcf/d and 1 Bcf/d of CO2.
During the third quarter of 2009, our CO2 production averaged 629
MMcf/d, as compared to an average of approximately 630 MMcf/d during the third quarter of 2008. We
used 86% of this production, or 539 MMcf/d, in our tertiary operations during the third quarter of
2009, and sold the balance to our industrial customers or to Genesis pursuant to our volumetric
production payments. During the third quarter of 2009, we
shutdown for maintenance two tertiary fields (Tinsley and Mallalieu Fields) which resulted in
our CO2 production being slightly curtailed during the quarter. Also, because
we had a delay in the commissioning of the Delhi pipeline, with the resultant delay in initiating
CO2 injections at the Delhi Field, we did not require an increase in our CO2
production during the third quarter of 2009. However, we plan to initiate CO2
injections at Delhi Field during November 2009, which will
increase our tertiary oil field
CO2 requirements, so we expect a corresponding increase in our
CO2 production volumes going forward.
We spent approximately $0.16 per Mcf to produce our CO2 during the
first nine months of 2009, comprised of $0.14 per Mcf during the first quarter of 2009, $0.18 per
Mcf during the second quarter of 2009, and $0.19 per Mcf during the third quarter of 2009. This
rate is down significantly from $0.25 per Mcf during the first nine months of 2008, due primarily
to decreased CO2 royalty expense as a result of lower oil prices (upon which
royalties are based) in the first nine months of 2009. Our estimated total cost per thousand cubic
feet of CO2 during the first nine months of 2009 was approximately $0.25, after
inclusion of depreciation and amortization expense, down from the 2008 first nine months average of
$0.33 per Mcf. Our estimated total cost per thousand cubic feet of CO2 during
the third quarter of 2009 was approximately $0.27, after inclusion of depreciation and amortization
expense.
We recently announced that we have initiated a comprehensive feasibility study of a
possible long-term CO2 pipeline project which would connect proposed
gasification plants in the Midwest to the Companys existing CO2 pipeline
infrastructure in Mississippi or Louisiana. Two of the proposed plants are in the term sheet
negotiation phase of a U.S. Department of Energy Loan Guarantee Program (see Off-Balance Sheet
Obligations Commitments and Obligations) which still require successful finalization of
negotiations with the Department of Energy (DOE) to receive such guarantees. The Illinois
Department of Commerce and Economic Opportunity has provided financial assistance for the
feasibility study for the Illinois portion of the pipeline. The feasibility study is expected to
determine the most likely pipeline route, the estimated costs of constructing such a pipeline, and
review regulatory, legal and permitting requirements. Our current preliminary estimates suggest
this would be a 500 to 700 mile pipeline system with a preliminary cost estimate of approximately
$1.0 billion, based on the cost of other pipelines recently built or under construction by the
Company. It is estimated that the study will be completed in the fourth quarter of 2009, following
which, we will evaluate external market conditions, potential financing opportunities and
construction of the proposed gasification projects, and make a decision as to whether or not we
will take initial steps to build such a pipeline.
A third proposed gasification plant for which Denbury has a CO2
output purchase contract, was also selected by the loan guarantee program. The Company plans to
commence a pipeline study for this plant proposed to be built along the Gulf Coast of Mississippi,
which would likely be a 110 mile pipeline that connects to the existing Free State Pipeline.
In addition to our natural source of CO2 and the proposed
gasification plants discussed above (see Off-Balance Sheet Arrangements Commitments and
Obligations), we continue to have ongoing discussions with owners of existing plants of various
types that emit CO2 which we may be able to purchase. In order to capture such
volumes, we (or the plant owner) would need to install additional equipment, which includes at a
minimum, compression and dehydration facilities. Most of these existing plants emit relatively
small volumes of CO2, generally less than the proposed gasification plants, but
such volumes may still be attractive if the source is located near our Green Pipeline. The capture
of CO2 could also be influenced by potential federal legislation, which could
impose economic penalties for the emission of CO2. We believe that we are a
likely purchaser of CO2 produced in our area of operations because of the scale
of our tertiary operations, our CO2 pipeline infrastructure, and our large
natural source of CO2 (Jackson
Dome), which can act as a swing CO2 source to balance CO2 supply and demand.
30
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
The following table summarizes our tertiary oil production and tertiary lease operating
expense per barrel for each quarter in 2008 and the first, second and third quarters of 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (BOE/d) |
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
First |
|
Second |
|
Third |
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
|
Quarter |
|
Quarter |
|
Quarter |
Tertiary Oil Field |
|
2008 |
|
2008 |
|
2008 |
|
2008 |
|
|
2009 |
|
2009 |
|
2009 |
|
|
|
|
Phase I: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brookhaven |
|
|
2,638 |
|
|
|
2,714 |
|
|
|
2,772 |
|
|
|
3,178 |
|
|
|
|
3,451 |
|
|
|
3,466 |
|
|
|
3,397 |
|
Little Creek area |
|
|
1,807 |
|
|
|
1,661 |
|
|
|
1,556 |
|
|
|
1,706 |
|
|
|
|
1,619 |
|
|
|
1,560 |
|
|
|
1,356 |
|
Mallalieu area |
|
|
6,099 |
|
|
|
6,260 |
|
|
|
5,339 |
|
|
|
5,056 |
|
|
|
|
4,490 |
|
|
|
4,264 |
|
|
|
3,679 |
|
McComb area |
|
|
1,632 |
|
|
|
1,818 |
|
|
|
2,061 |
|
|
|
2,092 |
|
|
|
|
2,246 |
|
|
|
2,429 |
|
|
|
2,473 |
|
Lockhart Crossing |
|
|
|
|
|
|
|
|
|
|
182 |
|
|
|
555 |
|
|
|
|
607 |
|
|
|
698 |
|
|
|
882 |
|
Phase II: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eucutta |
|
|
2,699 |
|
|
|
2,933 |
|
|
|
3,262 |
|
|
|
3,538 |
|
|
|
|
3,813 |
|
|
|
4,145 |
|
|
|
4,068 |
|
Heidelberg |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
250 |
|
|
|
829 |
|
Martinville |
|
|
793 |
|
|
|
715 |
|
|
|
736 |
|
|
|
1,213 |
|
|
|
|
1,118 |
|
|
|
951 |
|
|
|
720 |
|
Soso |
|
|
1,488 |
|
|
|
1,885 |
|
|
|
2,358 |
|
|
|
2,704 |
|
|
|
|
2,705 |
|
|
|
2,589 |
|
|
|
2,813 |
|
Phase III: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tinsley |
|
|
|
|
|
|
675 |
|
|
|
1,518 |
|
|
|
1,832 |
|
|
|
|
2,390 |
|
|
|
3,402 |
|
|
|
3,558 |
|
Phase IV: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cranfield |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
144 |
|
|
|
338 |
|
|
|
572 |
|
|
|
|
|
|
|
Total tertiary oil production |
|
|
17,156 |
|
|
|
18,661 |
|
|
|
19,784 |
|
|
|
21,874 |
|
|
|
|
22,583 |
|
|
|
24,092 |
|
|
|
24,347 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tertiary operating expense per Bbl |
|
$ |
20.81 |
|
|
$ |
24.67 |
|
|
$ |
26.81 |
|
|
$ |
21.86 |
|
|
|
$ |
20.48 |
|
|
$ |
20.86 |
|
|
$ |
23.14 |
|
|
|
|
|
|
|
Oil production from our tertiary operations increased to an average of 24,347
Bbls/d in the third quarter of 2009, a 23% increase over our third quarter 2008 tertiary production
level of 19,784 Bbls/d and a 1% increase over our second quarter 2009 tertiary production level.
These increases are the result of the production growth in our more recent floods such as Tinsley,
Lockhart Crossing, Cranfield and Heidelberg Fields, where production has increased every quarter as
the CO2 floods have been expanded and production response occurs across the
fields. We had our first production response from Cranfield Field during the first quarter of 2009
and our first response from Heidelberg Field in the second quarter of 2009, a little earlier than
anticipated. The Tinsley field has been one of our top performing tertiary oil fields. During 2009,
CO2
injection was initiated in the lower half of Tinsley Phase 2 and all
of Tinsley Phase 3. After reaching optimum
bottom hole pressure (BHP) late in the third quarter of 2009, and after a planned shutdown to
increase facility fluid handling capacity, approximately twenty-one shut-in wells will be turned to
production. The tertiary oil production in Tinsley is expected to increase as the oil cut increases
over time in these twenty-one wells. The declines at Mallalieu Field are partially due to
CO2 recycle volumes exceeding the plant capacity, which limited production
volumes. We have expanded the capacity of the facility, with it becoming operational early in the
fourth quarter of 2009. Now that the recycle capacity has been expanded, we expect production at
Mallalieu Field to plateau. Additionally, the second quarter decline at Soso Field was largely due
to water handling limitations that have recently been addressed and we saw production increases at
Soso Field during the third quarter of 2009. The Delhi pipeline is essentially complete, and we
anticipate initiating CO2 injections at Delhi Field (Phase V) during November
2009. We currently anticipate tertiary production response at Delhi Field around mid-year
2010.
During the third quarter of 2009, our operating costs for our tertiary properties
averaged $23.14 per Bbl, lower than the prior years third quarter average of $26.81 per Bbl, but
higher than our second quarter 2009 average of $20.86 per Bbl. For the first nine months of 2009,
the operating costs on our tertiary properties averaged $21.53 per Bbl as compared to $24.25 per
Bbl in the prior year period. Our costs have increased on a gross basis due to our new tertiary
floods and ongoing expansion of existing floods, but they have decreased on a per Bbl basis from
the third quarter and first nine months of 2008, primarily due to our increased production and to
the reduced cost of CO2 in the current year periods. On a per Bbl basis, our
cost of CO2 decreased by $2.70 per BOE, from $6.95 per Bbl in the third quarter
of 2008 to $4.25 per Bbl in the third quarter of 2009, primarily due to the reduction in oil prices
to which our CO2 costs are partially tied. In addition, our workover costs were
$1.89 lower on a per BOE basis in the third quarter of 2009 than in the
31
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
prior year period. The increase in operating costs from the second quarter of 2009 on a per BOE
basis is primarily due to our new floods in Cranfield and Heidelberg, and to an increase in
workover expenses between the sequential periods of $0.80 per barrel. In addition, the cost of our
CO2 increased in the current quarter as a result of higher oil prices, as
discussed above. For any specific field, we expect our tertiary lease operating expense per BOE to
be high initially, then decrease as production increases, ultimately leveling off until production
begins to decline toward the latter life of the field, when lease operating expense per BOE will
again increase.
Operating Results
As summarized in the Overview section above and discussed in more detail below, our
operating results for the third quarter and first nine months of 2009 were significantly lower as
compared to the same periods in the prior year. The primary factors impacting our operating results
were lower oil and natural gas commodity prices in the current year periods, decreased production,
due mainly to the sale of 60% of our Barnett Shale natural gas assets, non-cash losses associated
with fair value changes in our oil and natural gas derivative contracts and generally higher costs,
which are explained in more detail below.
Certain of our operating results and statistics for the comparative third quarters and
first nine months of 2009 and 2008 are included in the following table.
32
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
In thousands, except per share and unit data |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Operating results |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
26,885 |
|
|
$ |
157,548 |
|
|
$ |
(78,652 |
) |
|
$ |
344,603 |
|
Net income (loss) per common share basic |
|
|
0.11 |
|
|
|
0.64 |
|
|
|
(0.32 |
) |
|
|
1.41 |
|
Net income (loss) per common share diluted |
|
|
0.11 |
|
|
|
0.63 |
|
|
|
(0.32 |
) |
|
|
1.36 |
|
Cash flow from operations |
|
|
145,645 |
|
|
|
262,442 |
|
|
|
406,434 |
|
|
|
632,771 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production volumes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bbls/d |
|
|
34,926 |
|
|
|
31,078 |
|
|
|
36,819 |
|
|
|
30,859 |
|
Mcf/d |
|
|
46,399 |
|
|
|
89,009 |
|
|
|
75,523 |
|
|
|
89,087 |
|
BOE/d(1) |
|
|
42,659 |
|
|
|
45,913 |
|
|
|
49,406 |
|
|
|
45,707 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
208,128 |
|
|
$ |
321,965 |
|
|
$ |
529,563 |
|
|
$ |
899,368 |
|
Natural gas sales |
|
|
13,193 |
|
|
|
80,143 |
|
|
|
71,379 |
|
|
|
229,180 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas sales |
|
$ |
221,321 |
|
|
$ |
402,108 |
|
|
$ |
600,942 |
|
|
$ |
1,128,548 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas derivative contracts(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash receipt (payment) on settlement of derivative contracts |
|
$ |
18,527 |
|
|
$ |
(24,072 |
) |
|
$ |
146,365 |
|
|
$ |
(60,714 |
) |
Non-cash fair value adjustment income (expense) |
|
|
(22,284 |
) |
|
|
86,079 |
|
|
|
(323,426 |
) |
|
|
17,123 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income (expense) from oil and natural gas derivative contracts |
|
$ |
(3,757 |
) |
|
$ |
62,007 |
|
|
$ |
(177,061 |
) |
|
$ |
(43,591 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
83,300 |
|
|
$ |
85,308 |
|
|
$ |
241,908 |
|
|
$ |
228,134 |
|
Production taxes and marketing expenses (3) |
|
|
10,461 |
|
|
|
19,335 |
|
|
|
30,437 |
|
|
|
56,601 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production expenses |
|
$ |
93,761 |
|
|
$ |
104,643 |
|
|
$ |
272,345 |
|
|
$ |
284,735 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-tertiary CO2 operating margin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2 sales and transportation fees (4) |
|
$ |
3,659 |
|
|
$ |
3,471 |
|
|
$ |
9,708 |
|
|
$ |
9,705 |
|
CO2 operating expenses |
|
|
(1,047 |
) |
|
|
(1,240 |
) |
|
|
(3,442 |
) |
|
|
(2,836 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-tertiary CO2 operating margin |
|
$ |
2,612 |
|
|
$ |
2,231 |
|
|
$ |
6,266 |
|
|
$ |
6,869 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit prices including impact of derivative settlements(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
70.54 |
|
|
$ |
108.70 |
|
|
$ |
67.25 |
|
|
$ |
102.74 |
|
Gas price per Mcf |
|
|
3.09 |
|
|
|
8.21 |
|
|
|
3.46 |
|
|
|
8.16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit prices excluding impact of derivative settlements(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
64.77 |
|
|
$ |
112.61 |
|
|
$ |
52.68 |
|
|
$ |
106.37 |
|
Gas price per Mcf |
|
|
3.09 |
|
|
|
9.79 |
|
|
|
3.46 |
|
|
|
9.39 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas operating revenues and expenses per BOE(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenues |
|
$ |
56.39 |
|
|
$ |
95.20 |
|
|
$ |
44.55 |
|
|
$ |
90.11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas lease operating expenses |
|
$ |
21.22 |
|
|
$ |
20.20 |
|
|
$ |
17.94 |
|
|
$ |
18.22 |
|
Oil and natural gas production taxes and marketing expense |
|
|
2.67 |
|
|
|
4.58 |
|
|
|
2.26 |
|
|
|
4.52 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas production expenses |
|
$ |
23.89 |
|
|
$ |
24.78 |
|
|
$ |
20.20 |
|
|
$ |
22.74 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas (BOE). |
|
(2) |
|
See also Market Risk Management below for information concerning the Companys derivative transactions. |
|
(3) |
|
Includes Transportation expense Genesis. |
|
(4) |
|
Includes deferred revenue of $1.2 million for each of the three month periods ended September 30, 2009 and 2008 and $3.2 million and $3.4 million
for the nine month periods ended September 30, 2009 and 2008, respectively, associated with volumetric production payments with Genesis. Also
includes transportation income from Genesis of $1.5 million for each of the three month periods ended September 30, 2009 and 2008 and $4.0 million
and $4.1 million for the nine month periods ended September 30, 2009 and 2008. |
33
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Production: Production by area for each of the quarters of 2008 and the first,
second and third quarters of 2009 is listed in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (BOE/d) |
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
First |
|
Second |
|
Third |
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
|
Quarter |
|
Quarter |
|
Quarter |
Operating Area |
|
2008 |
|
2008 |
|
2008 |
|
2008 |
|
|
2009 |
|
2009 |
|
2009 |
|
|
|
|
|
|
Tertiary oil fields |
|
|
17,156 |
|
|
|
18,661 |
|
|
|
19,784 |
|
|
|
21,874 |
|
|
|
|
22,583 |
|
|
|
24,092 |
|
|
|
24,347 |
|
Mississippi non-CO2 floods |
|
|
12,128 |
|
|
|
11,617 |
|
|
|
11,694 |
|
|
|
12,150 |
|
|
|
|
11,904 |
|
|
|
10,043 |
|
|
|
8,931 |
|
Texas |
|
|
13,522 |
|
|
|
14,068 |
|
|
|
12,701 |
|
|
|
12,576 |
|
|
|
|
17,063 |
|
|
|
16,088 |
|
|
|
7,579 |
|
Onshore Louisiana |
|
|
905 |
|
|
|
663 |
|
|
|
512 |
|
|
|
418 |
|
|
|
|
708 |
|
|
|
885 |
|
|
|
699 |
|
Alabama and other |
|
|
1,189 |
|
|
|
1,296 |
|
|
|
1,222 |
|
|
|
1,219 |
|
|
|
|
1,150 |
|
|
|
1,161 |
|
|
|
1,103 |
|
|
|
|
|
|
|
Total Company |
|
|
44,900 |
|
|
|
46,305 |
|
|
|
45,913 |
|
|
|
48,237 |
|
|
|
|
53,408 |
|
|
|
52,269 |
|
|
|
42,659 |
|
|
|
|
|
|
|
As outlined in the above table, production in the third quarter of 2009 averaged
42,659 BOE/d, a 10% increase from third quarter 2008 production levels after adjusting for the sale
of 60% of our Barnett Shale natural gas assets. The increase over the prior year third quarter was
primarily due to a 23% increase in tertiary oil production, and production from Hastings Field
which the Company acquired in February 2009, offset in part by the expected decrease in the
Companys non-tertiary Mississippi production. The increase in our tertiary operations is discussed
above under Results of Operations CO2 Operations.
Our Texas Barnett Shale production averaged 4,948 BOE/d during the third quarter of 2009.
As discussed previously, we have recently sold 60% of our interests in the Barnett Shale so our
fourth quarter 2009 production will be reduced correspondingly. The acquisition of Hastings Field
in February 2009 added 2,083 BOE/d during the third quarter of 2009 and 1,946 BOE/d during the
first nine months of 2009 to our Texas area production.
Production in the Mississippi non-CO2 floods area has decreased
from third quarter and first nine month 2008 levels, as well as from second quarter 2009 levels.
Most of this decrease is due to the expected gradual decline in Heidelberg Field due to depletion,
and less drilling activity developing natural gas in the Selma Chalk. Our drilling activity in
Sharon Field (natural gas) in the latter part of 2008 helped offset the declines in the first
quarter of 2009, but production there declined in the nine months of 2009 as we have not drilled
any additional wells in this field this year.
Oil and Natural Gas Revenues: Due to the significant decrease in oil and natural gas
prices between the first nine months of 2008 and 2009, and due to the decrease in production in the
third quarter of 2009 resulting mainly from the sale of 60% of our Barnett Shale natural gas
assets, our oil and natural gas revenues dropped sharply in the third quarter and first nine months
of 2009 as compared to those revenues in the same periods of 2008. These changes in revenues,
excluding any impact of our derivative contracts, are seen in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2009 vs. 2008 |
|
|
2009 vs. 2008 |
|
|
|
|
|
|
|
Percentage |
|
|
|
|
|
|
Percentage |
|
|
|
Increase |
|
|
Increase |
|
|
Increase |
|
|
Increase |
|
|
|
(Decrease) in |
|
|
(Decrease) in |
|
|
(Decrease) in |
|
|
(Decrease) in |
|
In thousands |
|
Revenues |
|
|
Revenues |
|
|
Revenues |
|
|
Revenues |
|
Change in revenues due to: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in production |
|
$ |
(28,492 |
) |
|
|
(7%) |
|
|
$ |
86,895 |
|
|
|
8% |
|
Decrease in commodity prices |
|
|
(152,295 |
) |
|
|
(38%) |
|
|
|
(614,501 |
) |
|
|
(54%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total decrease in revenues |
|
$ |
(180,787 |
) |
|
|
(45%) |
|
|
$ |
(527,606 |
) |
|
|
(46%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Excluding any impact of our derivative contracts, our net realized commodity prices
and NYMEX differentials were as follows during the first, second and third quarters and first nine
month periods of 2008 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Three Months Ended |
|
Three Months Ended |
|
Nine Months Ended |
|
|
March 31, |
|
June 30, |
|
September 30, |
|
September 30, |
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
2009 |
|
2008 |
Net
Realized Prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
39.34 |
|
|
$ |
91.24 |
|
|
$ |
54.53 |
|
|
$ |
114.67 |
|
|
$ |
64.77 |
|
|
$ |
112.61 |
|
|
$ |
52.68 |
|
|
$ |
106.37 |
|
Gas price per Mcf |
|
|
4.09 |
|
|
|
7.80 |
|
|
|
2.98 |
|
|
|
10.55 |
|
|
|
3.09 |
|
|
|
9.79 |
|
|
|
3.46 |
|
|
|
9.39 |
|
Price per BOE |
|
|
34.97 |
|
|
|
76.65 |
|
|
|
44.48 |
|
|
|
98.07 |
|
|
|
56.39 |
|
|
|
95.20 |
|
|
|
44.55 |
|
|
|
90.11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX
Differentials: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil per Bbl |
|
$ |
(3.99 |
) |
|
$ |
(6.50 |
) |
|
$ |
(5.30 |
) |
|
$ |
(9.64 |
) |
|
$ |
(3.47 |
) |
|
$ |
(6.06 |
) |
|
$ |
(4.54 |
) |
|
$ |
(7.23 |
) |
Natural Gas per Mcf |
|
|
(0.41 |
) |
|
|
(0.92 |
) |
|
|
(0.82 |
) |
|
|
(0.92 |
) |
|
|
(0.33 |
) |
|
|
0.77 |
|
|
|
(0.44 |
) |
|
|
(0.35 |
) |
Our Company-wide oil price NYMEX differential
improved in the third quarter and
first nine months of 2009 over our differential in the comparable prior year periods, due primarily
to the decrease in oil prices. Our oil price NYMEX differential
improved in the third
quarter of 2009, as compared to the previous quarter, primarily due
to the reduced natural gas liquid production associated with the sold
Barnett Shale properties which have a significantly higher differential
to NYMEX.
Our natural gas NYMEX differentials are generally caused by movement in the NYMEX natural
gas prices during the month, as most of our natural gas is sold on an index price that is set near
the first of each month. While the percentage change in NYMEX natural gas differentials can be
quite large, these differentials are very seldom more than a dollar above or below NYMEX prices.
Oil and Natural Gas Derivative Contracts: The following table summarizes the impact that
our oil and natural gas derivative contracts had on our operating results for the three and nine
month periods ended September 30, 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-Cash Fair Value |
|
|
Cash Settlements |
|
|
|
Gain/(Loss) |
|
|
Receipt/(Payment) |
|
In thousands |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Crude oil derivative contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First quarter |
|
$ |
(95,861 |
) |
|
$ |
2,638 |
|
|
$ |
85,836 |
|
|
$ |
(7,392 |
) |
Second quarter |
|
|
(189,318 |
) |
|
|
(7,557 |
) |
|
|
42,002 |
|
|
|
(12,131 |
) |
Third quarter |
|
|
(20,850 |
) |
|
|
22,652 |
|
|
|
18,527 |
|
|
|
(11,186 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
September year-to-date |
|
$ |
(306,029 |
) |
|
$ |
17,733 |
|
|
$ |
146,365 |
|
|
$ |
(30,709 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas derivative contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First quarter |
|
$ |
(10,490 |
) |
|
$ |
(41,371 |
) |
|
$ |
|
|
|
$ |
(656 |
) |
Second quarter |
|
|
(5,473 |
) |
|
|
(22,666 |
) |
|
|
|
|
|
|
(16,463 |
) |
Third quarter |
|
|
(1,434 |
) |
|
|
63,427 |
|
|
|
|
|
|
|
(12,886 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
September year-to-date |
|
$ |
(17,397 |
) |
|
$ |
(610 |
) |
|
$ |
|
|
|
$ |
(30,005 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First quarter |
|
$ |
(106,351 |
) |
|
$ |
(38,733 |
) |
|
$ |
85,836 |
|
|
$ |
(8,048 |
) |
Second quarter |
|
|
(194,791 |
) |
|
|
(30,223 |
) |
|
|
42,002 |
|
|
|
(28,594 |
) |
Third quarter |
|
|
(22,284 |
) |
|
|
86,079 |
|
|
|
18,527 |
|
|
|
(24,072 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
September year-to-date |
|
$ |
(323,426 |
) |
|
$ |
17,123 |
|
|
$ |
146,365 |
|
|
$ |
(60,714 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
35
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Changes in commodity prices and the expiration of contracts cause fluctuations in
the estimated fair value of our oil and natural gas derivative contracts. Because we do not
utilize hedge accounting for our commodity derivative contracts, the changes in fair value of these
contracts are recognized currently in the income statement. During the third quarter of 2009, we
recognized total non-cash fair value expense of $22.3 million and for the first nine months of
2009, we recognized total non-cash fair value expense of $323.4 million. Of these amounts,
$21.4 million in the third quarter and $231.8 million in the first nine months of 2009 related to
our 2009 oil collars, partially reversing the $242.2 million gain we recognized on these collars
during the fourth quarter of 2008. The remaining non-cash fair value expense recognized during the
third quarter and first nine months of 2009 was made up of charges on the oil derivative contracts
we entered into during 2009 and on our natural gas swaps entered into during the first half of
2009, which cover a portion of our 2010 and 2011 calendar year production (see Note 6 to the
Unaudited Condensed Consolidated Financial Statements for a summary of our oil and natural gas
derivative contracts). During the third quarter and first nine months of 2008, we recognized
non-cash fair value income of $86.1 million and $17.1 million, respectively, on our oil and natural
gas derivative contracts.
During the third quarter and first nine months of 2009, we received cash settlements of
$18.5 million and $146.4 million on our derivative contracts. During the third quarter and first
nine months of 2008, we made cash payments of $24.1 million and $60.7 million on our derivative
contracts, giving us a total change in earnings impact from both non-cash fair value adjustments
and cash settlements between the two nine-month periods of $133.5 million.
Production Expenses: Our lease operating expenses increased between the comparable first
nine months of 2009 versus 2008 on a gross basis as a result of (i) our increasing emphasis on
tertiary operations and additional tertiary fields moving into the productive phase (see discussion
of those expenses under CO2 Operations above), (ii) the acquisition of
Hastings Field in February 2009, (iii) increased personnel and related costs, (iv) higher
electrical costs to operate our properties and (v) increasing lease payments for certain equipment
in our tertiary operating facilities, offset in part by lower CO2 costs due
primarily to lower oil prices in the 2009 periods. Our lease operating expenses decreased on a per
BOE basis between the comparable first nine months of 2009 versus 2008 due to the lower oil and
natural gas prices, which has helped to lower the cost for certain goods and services and has
reduced our cost for CO2 (see Results of Operations CO2
Operations for a more detailed discussion). We expect our tertiary operating costs to partially
correlate with oil prices, as the price we pay for CO2 is partially tied to oil
prices. Our operating costs have increased during the last few years as oil prices have increased
and the demand for goods and services has steadily risen, but with the recent drop in oil prices,
we expect that lower demand for certain goods and services will gradually cause prices for those
items to decrease or stabilize over time. During the third quarter of 2009, Company-wide lease
operating costs averaged $21.22 per BOE, up from $20.20 per BOE during the third quarter of 2008,
primarily due to the fact that our incremental growth in production quarter-over-quarter (excluding
the sale of a portion of our interest in the Barnett Shale properties) was primarily from higher
cost producing properties such as our tertiary operations and Hastings Field production. On a pro
forma basis, after adjusting our operating results to remove 60% of our Barnett Shale production
and lease operating expense, Company-wide lease operating expense for the first nine months of 2009
would have been approximately $19.71 per BOE, as compared to actual nine months 2009 operating
costs per BOE of $17.94.
Production taxes and marketing expenses generally change in proportion to commodity
prices and production volumes, and therefore were lower in the 2009 periods compared to the 2008
periods, because the severe decrease in commodity prices more than offset our increase in
production. Transportation and plant processing fees were approximately $1.8 million lower in the
third quarter and respective first nine months of 2009 as compared to the same periods in 2008.
General and Administrative Expenses
General and administrative (G&A) expenses increased 60% between the respective third
quarters and 74% between the respective first nine months of 2009 and 2008 as set forth below:
36
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
In thousands, except per BOE data and employees |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Gross cash G&A expense |
|
$ |
36,091 |
|
|
$ |
31,302 |
|
|
$ |
107,565 |
|
|
$ |
90,879 |
|
Employee stock-based compensation |
|
|
6,101 |
|
|
|
4,131 |
|
|
|
18,600 |
|
|
|
12,590 |
|
Founders compensation award |
|
|
|
|
|
|
|
|
|
|
10,000 |
|
|
|
|
|
Incentive compensation for Genesis management |
|
|
3,573 |
|
|
|
|
|
|
|
9,111 |
|
|
|
|
|
State franchise taxes |
|
|
1,102 |
|
|
|
863 |
|
|
|
3,341 |
|
|
|
2,548 |
|
Operator labor and overhead recovery charges |
|
|
(19,333 |
) |
|
|
(18,027 |
) |
|
|
(58,110 |
) |
|
|
(50,788 |
) |
Capitalized exploration and development costs |
|
|
(3,496 |
) |
|
|
(3,264 |
) |
|
|
(10,679 |
) |
|
|
(9,408 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net G&A expense |
|
$ |
24,038 |
|
|
$ |
15,005 |
|
|
$ |
79,828 |
|
|
$ |
45,821 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
G&A per BOE: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash G&A expense |
|
$ |
3.63 |
|
|
$ |
2.57 |
|
|
$ |
3.09 |
|
|
$ |
2.66 |
|
Net stock-based compensation |
|
|
1.30 |
|
|
|
0.78 |
|
|
|
1.16 |
|
|
|
0.80 |
|
Founders compensation award |
|
|
|
|
|
|
|
|
|
|
0.74 |
|
|
|
|
|
Incentive compensation for Genesis management |
|
|
0.91 |
|
|
|
|
|
|
|
0.68 |
|
|
|
|
|
State franchise tax |
|
|
0.28 |
|
|
|
0.20 |
|
|
|
0.25 |
|
|
|
0.20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net G&A expense |
|
$ |
6.12 |
|
|
$ |
3.55 |
|
|
$ |
5.92 |
|
|
$ |
3.66 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employees as of September 30 |
|
|
806 |
|
|
|
768 |
|
|
|
806 |
|
|
|
768 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross cash G&A expenses increased $4.8 million, or 15%, between the respective third
quarters and $16.7 million, or 18%, between the respective first nine months. The majority of the
increases in gross G&A expenses between the respective quarters and first nine month periods
related to increases in compensation and personnel-related costs, due primarily to the increase in
employees and salary increases, which we consider necessary in order to remain competitive in our
industry. Stock compensation expense increased to $6.1 million during the third quarter of 2009
from $4.1 million for the third quarter of 2008, due primarily to the increase in employees and
changes in the mix of compensation awarded to employees. On a nine month basis, stock compensation
was approximately $18.6 million for 2009 and $12.6 million for 2008. As discussed above in
Overview Recent Management Changes, we also expensed $10.0 million in the second quarter of
2009 related to a Founders Retirement Agreement for Gareth Roberts as he retired as CEO and
President of the Company on June 30, 2009.
Also adding to the increase in net G&A expense for the 2009 periods was a charge relating
to incentive compensation awards for the management of Genesis of $3.6 million in the third quarter
of 2009 and $9.1 million in the first nine months of 2009. As incentive compensation for Genesis
management, our subsidiary which is the general partner of Genesis Energy, LP, awarded management
the right to earn an interest in the incentive distributions we receive. These awards are subject
to vesting over four years and achieving future levels of cash available before reserves on a per
unit basis, among other conditions. The annual expense is currently expected to be less in future
years, although it will fluctuate based on future performance and other market conditions. See Note
5, Related Party Transactions Genesis to the Unaudited Condensed Consolidated Financial
Statements for further information regarding these incentive compensation awards.
The increase in gross G&A was offset in part by an increase in operator overhead recovery
charges in the third quarter and first nine months of 2009. 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 overhead charges
increased by 7% between the third quarters of 2008 and 2009 and increased by 14% between the first
nine months of 2008 and 2009. Capitalized exploration and development costs also increased by 7%
between the third quarters of 2008 and 2009 and increased by 14% between the first nine months of
2008 and 2009, primarily as a result of increases in personnel and compensation costs.
The net effect was a 60% increase in net G&A expense between the respective third
quarters and an 74% increase between the first nine months of 2009 and 2008. On a per BOE basis,
G&A costs also increased, although at a higher percentage rate as a result of lower production
resulting from the Barnett Shale sale, increasing 72% in the third quarter of 2009 as compared to
levels in the third quarter of 2008, and 62% when comparing the first nine months of 2009 to the
prior year period.
37
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Interest and Financing Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
In thousands, except per BOE data and interest rates |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Cash interest expense |
|
$ |
28,694 |
|
|
$ |
17,209 |
|
|
$ |
80,296 |
|
|
$ |
42,287 |
|
Non-cash interest expense |
|
|
2,037 |
|
|
|
410 |
|
|
|
5,363 |
|
|
|
1,225 |
|
Less: Capitalized interest |
|
|
(20,872 |
) |
|
|
(6,713 |
) |
|
|
(48,699 |
) |
|
|
(19,524 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
$ |
9,859 |
|
|
$ |
10,906 |
|
|
$ |
36,960 |
|
|
$ |
23,988 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income and other |
|
$ |
434 |
|
|
$ |
1,895 |
|
|
$ |
1,948 |
|
|
$ |
3,525 |
|
Net cash interest expense and other income per BOE (1) |
|
$ |
1.89 |
|
|
$ |
2.10 |
|
|
$ |
2.21 |
|
|
$ |
1.59 |
|
Average debt outstanding |
|
$ |
1,240,827 |
|
|
$ |
780,129 |
|
|
$ |
1,246,266 |
|
|
$ |
713,714 |
|
Average interest rate (2) |
|
|
9.2 |
% |
|
|
8.8 |
% |
|
|
8.6 |
% |
|
|
7.9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Cash interest expense less capitalized interest less interest and other income on BOE basis. |
|
(2) |
|
Includes commitment fees but excludes debt issue costs and amortization of discount and premium. |
Interest expense decreased $1.0 million, or 10%, comparing the third quarters of
2008 and 2009, but increased $13.0 million, or 54%, comparing levels in the first nine months of
2008 and 2009. The decrease in interest expense between the respective third quarters is primarily
a result of increased interest capitalization relating mainly to our CO2
pipelines currently under construction, offset in part by higher average debt levels resulting from
the Hastings Field acquisition in early February 2009 and incremental borrowings to fund our
development program. For the first nine month periods, the increase in our interest expense
attributable to higher debt and higher average interest rates during the period, was offset in part
by an increase in capitalized interest in the 2009 periods, as mentioned above. Our average
interest rate is higher in the current year periods than in the prior year periods as a result of
the two pipeline dropdown transactions with Genesis mid-2008, which were recorded as financing
leases and carry a higher imputed rate of interest, and the February 2009 issuance of $420 million
of 9.75% Senior Subordinated Notes.
Depletion, Depreciation and Amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
In thousands, except per BOE data |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Depletion and depreciation of oil and natural gas properties |
|
$ |
44,935 |
|
|
$ |
48,638 |
|
|
$ |
151,890 |
|
|
$ |
140,648 |
|
Depletion
and depreciation of
CO2 assets |
|
|
4,399 |
|
|
|
4,047 |
|
|
|
12,960 |
|
|
|
10,673 |
|
Asset retirement obligations |
|
|
823 |
|
|
|
762 |
|
|
|
2,460 |
|
|
|
2,286 |
|
Depreciation of other fixed assets |
|
|
3,368 |
|
|
|
2,877 |
|
|
|
9,835 |
|
|
|
7,289 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total DD&A |
|
$ |
53,525 |
|
|
$ |
56,324 |
|
|
$ |
177,145 |
|
|
$ |
160,896 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A per BOE: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties |
|
$ |
11.66 |
|
|
$ |
11.69 |
|
|
$ |
11.44 |
|
|
$ |
11.41 |
|
CO2 assets and other fixed assets |
|
|
1.98 |
|
|
|
1.64 |
|
|
|
1.69 |
|
|
|
1.44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total DD&A cost per BOE |
|
$ |
13.64 |
|
|
$ |
13.33 |
|
|
$ |
13.13 |
|
|
$ |
12.85 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion and depreciation of oil and natural gas properties decreased during the
third quarter of 2009 compared to the same period in 2008 due primarily to decreased production
resulting from the sale of a portion of our Barnett Shale natural gas assets. Depletion and
depreciation of oil and natural gas properties increased during the first nine months of 2009 as
compared to 2008 primarily due to an increased depletion base resulting from capital expenditures
and the transfer of unevaluated costs into the full cost pool late in 2008.
Our depletion, depreciation and amortization (DD&A) rate for oil and natural gas properties
on a per BOE basis remained relatively constant between the respective periods. In the second
quarter of 2009, we booked approximately 10.9 million barrels of incremental oil reserves related
to our tertiary operations at Cranfield Field, as a result of the oil production response to the
CO2
38
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
injections in that field. Correspondingly, we moved approximately $82.4 million from unevaluated
properties to the full cost pool relating to Cranfield, representing the acquisition costs and
development expenditures incurred on the field prior to recognizing proved reserves.
We continually evaluate the performance of our other 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. We currently do not anticipate that any significant
incremental reserves will be recognized in the balance of 2009 as we do not expect any production
from any other new floods before year-end.
Our DD&A rate for our CO2 and other fixed assets increased in the
third quarter of 2009 as compared to the rate in the comparable quarter of 2008 primarily as a
result of the Heidelberg CO2 pipeline being placed into service during 2008,
and due to lower production levels in the third quarter of 2009. At September 30, 2009, we had
$870.4 million of costs related to CO2 pipelines under construction. These
costs were not being depreciated at September 30, 2009. Depreciation of these pipelines will
commence as each segment of pipeline is placed into service.
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, 2009, June 30, 2009 or
September 30, 2009. However, if oil prices were to decrease significantly in subsequent periods, we
may be required to record additional 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. The SEC adopted major revisions to its rules governing oil and gas company reporting
requirements which are effective for us beginning with our December 31, 2009 Form 10-K. Under these
new rules, the full cost ceiling value will be calculated using an average price based on the first
day of every month during the period.
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
In thousands, except per BOE amounts and tax rates |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Current
income tax expense (benefit) |
|
$ |
(6,160 |
) |
|
$ |
12,689 |
|
|
$ |
18,140 |
|
|
$ |
44,769 |
|
Deferred income tax expense (benefit) |
|
|
20,537 |
|
|
|
83,480 |
|
|
|
(67,869 |
) |
|
|
163,909 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense (benefit) |
|
$ |
14,377 |
|
|
$ |
96,169 |
|
|
$ |
(49,729 |
) |
|
$ |
208,678 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average income tax expense (benefit) per BOE |
|
$ |
3.66 |
|
|
$ |
22.77 |
|
|
$ |
(3.69 |
) |
|
$ |
16.66 |
|
Effective tax rate |
|
|
34.9 |
% |
|
|
37.9 |
% |
|
|
38.7 |
% |
|
|
37.7 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Our income tax provision was based on an estimated statutory rate of approximately
38%. Our effective tax rate has generally been slightly lower than our estimated statutory rate due
to the impact of certain items such as our domestic production activities deduction, offset in part
by compensation arising from certain equity compensation that cannot be deducted for tax purposes
in the same manner as book expense. In the third quarters and first nine months of both years, the
current income tax expense represents our anticipated alternative minimum cash taxes that we cannot
offset with enhanced oil recovery credits. Included in the first nine months of 2009 is
approximately $23 million in current taxes associated with the completion of the sale of a portion
of our Barnett Shale assets. We recognized a current income tax benefit in the third quarter of
2009 and a slightly lower tax rate as a result of return to provision revisions and the estimated
taxes related to the Barnett Shale property sale completed in the second and third quarters of
2009. As of December 31, 2008, after we had booked our return to provision adjustments, we had an
estimated $47 million of enhanced oil recovery credits to carry forward that can be utilized to
reduce our current income taxes during 2009 or future years.
In the second quarter of 2008 we obtained approval from the IRS to change our method of
tax accounting for certain assets used in our tertiary oilfield recovery operations. Although the
overall effects of this accounting change are still under audit, we expect to receive tax refunds
of approximately $10.6 million for tax years through 2007, along with other deferred tax benefits,
and in the second quarter of 2008 we reduced our current income tax expense by approximately $19
million to adjust for the impact of this change through the first six months of 2008. The reduction
in current income tax expense has been offset by a corresponding increase in deferred income tax
expense of approximately the same amount. Although this change is not expected to have a
significant impact on the Companys overall tax rate, it is anticipated that it could defer the
amount of cash taxes the Company might otherwise pay over the next several years.
39
DENBURY RESOURCES INC.
Managements 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 |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
Per BOE data |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Oil and natural gas revenues |
|
$ |
56.39 |
|
|
$ |
95.20 |
|
|
$ |
44.55 |
|
|
$ |
90.11 |
|
Gain (loss) on settlements of derivative contracts |
|
|
4.72 |
|
|
|
(5.70 |
) |
|
|
10.85 |
|
|
|
(4.84 |
) |
Lease operating expenses |
|
|
(21.22 |
) |
|
|
(20.20 |
) |
|
|
(17.94 |
) |
|
|
(18.22 |
) |
Production taxes and marketing expenses |
|
|
(2.67 |
) |
|
|
(4.58 |
) |
|
|
(2.26 |
) |
|
|
(4.52 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Production netback |
|
|
37.22 |
|
|
|
64.72 |
|
|
|
35.20 |
|
|
|
62.53 |
|
Non-tertiary
CO2 operating margin |
|
|
0.67 |
|
|
|
0.53 |
|
|
|
0.46 |
|
|
|
0.55 |
|
General and administrative expenses |
|
|
(6.12 |
) |
|
|
(3.55 |
) |
|
|
(5.92 |
) |
|
|
(3.66 |
) |
Net cash interest expense and other income |
|
|
(1.89 |
) |
|
|
(2.10 |
) |
|
|
(2.21 |
) |
|
|
(1.59 |
) |
Abandoned acquisition costs |
|
|
|
|
|
|
(7.20 |
) |
|
|
|
|
|
|
(2.43 |
) |
Current income taxes and other |
|
|
5.03 |
|
|
|
(2.41 |
) |
|
|
1.26 |
|
|
|
(2.93 |
) |
Changes in assets and liabilities relating to operations |
|
|
2.20 |
|
|
|
12.14 |
|
|
|
1.34 |
|
|
|
(1.94 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from operations |
|
|
37.11 |
|
|
|
62.13 |
|
|
|
30.13 |
|
|
|
50.53 |
|
DD&A |
|
|
(13.64 |
) |
|
|
(13.33 |
) |
|
|
(13.13 |
) |
|
|
(12.85 |
) |
Deferred income taxes |
|
|
(5.23 |
) |
|
|
(19.76 |
) |
|
|
5.03 |
|
|
|
(13.09 |
) |
Non-cash commodity derivative adjustments |
|
|
(5.68 |
) |
|
|
20.38 |
|
|
|
(23.98 |
) |
|
|
1.37 |
|
Changes in assets and liabilities and other non-cash items |
|
|
(5.71 |
) |
|
|
(12.12 |
) |
|
|
(3.88 |
) |
|
|
1.56 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
6.85 |
|
|
$ |
37.30 |
|
|
$ |
(5.83 |
) |
|
$ |
27.52 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Market Risk Management
Debt
We finance some of our acquisitions and other expenditures with fixed and variable rate
debt. These debt agreements expose us to market risk related to changes in interest rates. We had
$20 million of bank debt outstanding as of September 30, 2009. The carrying value of our bank debt
is approximately fair value based on the fact that it is subject to short-term floating interest
rates that approximate the rates available to us for those periods. We adjusted the estimated fair
value measurements of our bank debt at September 30, 2009, for estimated nonperformance risk. This
estimated nonperformance risk totaled approximately $1.5 million and was determined utilizing
industry credit default swaps. None of our existing debt has any triggers or covenants regarding
our debt ratings with rating agencies, although under the NEJD financing lease with Genesis (see
Note 5, Related Party Transactions Genesis to our Unaudited Condensed Consolidated Balance
Sheets) in the event of significant downgrades of our corporate credit rating by the rating
agencies, Genesis can require certain credit enhancements from us, and possibly other remedies
under the lease. 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 September 30, 2009.
40
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Maturity Dates |
|
Carrying |
|
Fair |
In thousands |
|
2011 |
|
2013 |
|
2015 |
|
2016 |
|
Value |
|
Value |
Variable rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank debt (weighted
average interest
rate of 0.02% at
September 30, 2009) |
|
$ |
20,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
20,000 |
|
|
$ |
18,500 |
|
Fixed rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.5% subordinated
debt due 2013
(fixed rate of
7.5%) |
|
|
|
|
|
|
225,000 |
|
|
|
|
|
|
|
|
|
|
|
224,320 |
|
|
|
225,000 |
|
7.5% subordinated
debt due 2015
(fixed rate of
7.5%) |
|
|
|
|
|
|
|
|
|
|
300,000 |
|
|
|
|
|
|
|
300,535 |
|
|
|
298,000 |
|
9.75% subordinated
debt due 2016
(fixed rate of
9.75%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
426,350 |
|
|
|
398,855 |
|
|
|
453,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Natural Gas Derivative Contracts
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. Recently, we have employed a
strategy to hedge a portion of our production looking out 12 to 15 months from each quarter, 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 world-wide economic uncertainties. See
Note 6 to the Unaudited Condensed Consolidated Financial Statements for details regarding our
derivative contracts.
All of the mark-to-market valuations used for our oil and natural gas derivatives are
provided by external sources and are based on prices that are actively quoted. We manage and
control market and counterparty credit risk through established internal control procedures 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 derivative
contracts are with parties that are lenders under our Senior Bank Loan. We have included an
estimate of nonperformance risk in the fair value measurement of our oil and natural gas derivative
contracts. We have measured nonperformance risk based upon credit default swaps or credit spreads.
At September 30, 2009 and December 31, 2008, the fair value of our oil and natural gas derivative
contracts was reduced by $2.8 million and $3.7 million, respectively, for estimated nonperformance
risk.
For accounting purposes, we do not apply hedge accounting to our oil and natural gas
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. Information regarding our current
derivative contract positions and results of our historical derivative activity is included in Note
6 to the Unaudited Condensed Consolidated Financial Statements.
At September 30, 2009, our derivative contracts were recorded at their fair value, which
was a net liability of approximately $69.2 million, a significant change from the $249.7 million
fair value asset recorded at December 31, 2008. This change is primarily related to the expiration
of oil derivative contracts during the first nine months of 2009, and to the oil and natural gas
futures prices as of September 30, 2009 in relation to the new commodity derivative contracts for
2010 and 2011 that we entered into during the first nine months of 2009.
Commodity Derivative Sensitivity Analysis
Based on NYMEX crude oil and natural gas futures prices as of September 30, 2009, 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:
41
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
|
Crude Oil |
|
|
Natural Gas |
|
|
|
Derivative |
|
|
Derivative |
|
|
|
Contracts |
|
|
Contracts |
|
|
|
Receipt/ |
|
|
Receipt/ |
|
In thousands |
|
(Payment) |
|
|
(Payment) |
|
Based on: |
|
|
|
|
|
|
|
|
NYMEX futures prices as of September 30, 2009 |
|
$ |
(35,362 |
) |
|
$ |
(14,010 |
) |
10% increase in prices |
|
|
(82,121 |
) |
|
|
(29,631 |
) |
10% decrease in prices |
|
|
1,120 |
|
|
|
1,600 |
|
|
|
|
|
|
|
|
Critical Accounting Policies
For a discussion of our critical accounting policies, which are related to property,
plant and equipment, depletion and depreciation, oil and natural gas reserves, asset retirement
obligations, income taxes and hedging activities, and which remain unchanged, except as listed
below, see Managements Discussion and Analysis of Financial Condition and Results of Operations
in our annual report on Form 10-K for the year ended December 31, 2008.
Fair Value Estimates
The FASC defines fair value, establishes a framework for measuring fair value and expands
disclosures about fair value measurements. It does not require us to make any new fair value
measurements, but rather establishes a fair value hierarchy that prioritizes the inputs to the
valuation techniques used to measure fair value. Level 1 inputs are given the highest priority in
the fair value hierarchy, as they represent observable inputs that reflect unadjusted quoted prices
for identical assets or liabilities in active markets as of the reporting date, while Level 3
inputs are given the lowest priority, as they represent unobservable inputs that are not
corroborated by market data. Valuation techniques that maximize the use of observable inputs are
favored. See Note 7 to the Unaudited Condensed Consolidated Financial Statements for disclosures
regarding our recurring fair value measurements.
Significant uses of fair value measurements include:
|
|
|
allocation of the purchase price paid to acquire businesses to the
assets acquired and liabilities assumed in those acquisitions, |
|
|
|
|
assessment of impairment of long-lived assets, |
|
|
|
|
assessment of impairment of goodwill, and |
|
|
|
|
recorded value of derivative instruments. |
Acquisitions
Under the acquisition method of accounting for business combinations, the purchase price
paid to acquire a business is allocated to its assets and liabilities based on the estimated fair
values of the assets acquired and liabilities assumed as of the date of acquisition. FASC Business Combinations topic defines the acquisition date as the date on which the acquirer obtains
control of the acquiree, which is usually a date different than the date the economics of the
acquisition are established between the acquirer and the acquiree. FASC Fair Value
Measurements and Disclosures topic defines fair value as 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 (often referred to as the exit price). A fair value measurement is based on the
assumptions of market participants and not those of the reporting entity. Therefore,
entity-specific intentions do not impact the measurement of fair value unless those assumptions are
consistent with market participant views.
The excess of the purchase price over the fair value of the net tangible and identifiable
intangible assets acquired is recorded as goodwill. A significant amount of judgment is involved in
estimating the individual fair values involving property, plant and
42
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
equipment and identifiable intangible assets. We use all available information to make these fair
value determinations and, for certain acquisitions, engage third-party consultants for assistance.
The fair values used to allocate the purchase price of an acquisition are often estimated
using the expected present value of future cash flows method, which requires us to project related
future cash inflows and outflows and apply an appropriate discount rate. The estimates used in
determining fair values are based on assumptions believed to be reasonable but which are inherently
uncertain. Accordingly, actual results may differ from the projected results used to determine fair
value.
Impairment Assessment of Goodwill
We test goodwill for impairment annually during the fourth quarter, or between annual
tests if an event occurs or circumstances change that would more likely than not reduce the fair
value of a reporting unit below its carrying amount. The need to test for impairment can be based
on several indicators, including a significant reduction in prices of oil or natural gas, a
full-cost ceiling write-down of oil and natural gas properties, unfavorable adjustments to
reserves, significant changes in the expected timing of production, other changes to contracts or
changes in the regulatory environment.
Goodwill is tested for impairment at the reporting unit level. Denbury applies SEC
full-cost accounting rules, under which the acquisition cost of oil and gas properties are
recognized on a cost center basis (country), of which Denbury has only one cost center (United
States). Goodwill is assigned to this single reporting unit.
Fair value calculated for the purpose of testing for impairment of our goodwill is
estimated using the expected present value of future cash flows method and comparative market
prices when appropriate. A significant amount of judgment is involved performing these fair value
estimates for goodwill since the results are based on forecasted assumptions. Significant
assumptions include projections of future oil and natural gas prices, projections of estimated
quantities of oil and natural gas reserves, projections of future rates of production, timing and
amount of future development and operating costs, projected availability and cost of
CO2, projected recovery factors of tertiary reserves, and risk-adjusted
discount rates. We base our fair value estimates on projected financial information which we
believe to be reasonable. However, actual results may differ from those projections.
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 this Managements 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, drilling activity or methods, acquisition plans and
proposals and dispositions, development activities, cost savings, production rates and volumes or
forecasts thereof, hydrocarbon reserves, hydrocarbon or expected reserve quantities and values,
potential reserves from tertiary operations, hydrocarbon prices, pricing assumptions based upon
current and projected oil and gas prices, liquidity, regulatory matters, mark-to-market values,
competition, long-term forecasts of production, finding costs, rates of return, estimated costs, or
changes in costs, future sources of capital or bank financing
arrangements, future capital expenditures and overall economics and other variables surrounding
our tertiary 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 managements 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 the
Companys financial condition and results of operations. As a consequence, actual results may
differ materially from expectations, estimates or assumptions expressed in or implied by any
forward-looking statements made by or on behalf of the Company. Among the factors that could cause
actual results to differ materially are: fluctuations of the prices received or demand for the
Companys oil and natural gas, inaccurate cost estimates, fluctuations in the prices of goods and
services, the uncertainty of drilling results and reserve estimates, operating hazards, acquisition
risks, requirements for capital, its availability or its cost, general economic conditions, competition and
government regulations, unexpected delays, as well as the risks and uncertainties inherent in oil
and gas drilling and production activities or which are otherwise discussed in this annual report,
including, without limitation, the portions referenced above, and the uncertainties set forth from
time to time in the Companys other public reports, filings and public statements.
43
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures about Market Risk
The information required by Item 3 is set forth under Market Risk Management in
Managements Discussion and Analysis of Financial Condition and Results of Operations.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures We maintain disclosure controls and
procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934,
consisting of internal controls designed to ensure that information required to be disclosed in our
filings under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported
within the time periods specified in the Securities and Exchange Commissions rules and forms and
that such information is accumulated and communicated to management, including our Chief Executive
Officer and our Chief Financial Officer. Our Chief Executive Officer and Chief Financial Officer
have evaluated our disclosure controls and procedures as of the end of the period covered by this
quarterly report on Form 10-Q and have determined that such disclosure controls and procedures are
effective in ensuring that material information required to be disclosed in this quarterly report
is accumulated and communicated to them and our management to allow timely decisions regarding
required disclosure.
Changes in Internal Control Over Financial Reporting There have been no changes in the
Companys internal control over financial reporting during the most recently completed fiscal
quarter that have materially affected, or are reasonably likely to materially affect, the Companys
internal control over financial reporting.
Part II. Other Information
Item 1. Legal Proceedings
Information with respect to this item has been incorporated by reference from our Form
10-K for the year ended December 31, 2008. There have been no material developments in such legal
proceedings since the filing of such Form 10-K, with the following
exceptions: (1) the counterclaim described under Item 1A in
Part II of our June 30,
2009 Form 10-Q related to natural gas processing and gathering
agreements has since been withdrawn;
and (2) during the first week of November 2009, we have been advised
that several class action complaints have been filed against Encore
Acquisition Company (Encore) and their directors in
connection with our execution of a definitive merger agreement with
Encore on October 31, 2009 (as discussed under
Managements Discussion and Analysis herein), and
that we have also been named in such suits, although we have not
received service of process in any such case.
Item 1A. Risk Factors
Information with respect to the risk factors has been incorporated by reference from
Item 1A of our Form 10-K for the year ended December 31, 2008. There have been no material changes
to the risk factors since the filing of such Form 10-K,
although in connection with our execution of a definitive merger
agreement with Encore on October 31, 2009 (as referenced above)
our conduct pending closure of such merger or the consequences of
such merger may give rise to additional risks beyond those stated in
such Form 10-K, with any such risks to be addressed in detail in the
registration statement on Form S-4 which we will file with the
Commission relating to such merger.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ISSUER PURCHASES OF EQUITY SECURITIES |
|
|
|
|
|
|
|
|
|
|
(c) Total Number of |
|
(d) Maximum Number |
|
|
(a) Total |
|
|
|
|
|
Shares Purchased |
|
of Shares that May |
|
|
|
Number of |
|
(b) Average |
|
as Part of Publicly |
|
Yet Be Purchased |
|
|
Shares |
|
Price Paid |
|
Announced Plans or |
|
Under the Plan Or |
Period |
|
Purchased |
|
per Share |
|
Programs |
|
Programs |
July 1 through 31, 2009 |
|
|
605 |
|
|
$ |
13.74 |
|
|
|
|
|
|
|
|
|
August 1 through 31, 2009 |
|
|
142,306 |
|
|
$ |
16.43 |
|
|
|
|
|
|
|
|
|
September 1 through 30,
2009 |
|
|
6,852 |
|
|
$ |
15.06 |
|
|
|
|
|
|
|
|
|
Total |
|
|
149,763 |
|
|
$ |
16.36 |
|
|
|
|
|
|
|
|
|
These shares were purchased from employees of Denbury who delivered shares to the company
to satisfy their minimum tax withholding requirements related to the vesting of restricted shares.
44
DENBURY RESOURCES INC.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Submission of Matters to a Vote of Security Holders
None.
Item 5. Other Information
None.
Item 6. Exhibits
|
|
|
Exhibits: |
|
|
31(a)*
|
|
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
31(b)*
|
|
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
32*
|
|
Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002. |
101*
|
|
The following financial statements from the Companys Quarterly Report on Form 10-Q for the
quarter ended September 30, 2009, formatted in XBRL: (i) Consolidated Balance Sheets, (ii)
Consolidated Statements of Operations, (iii) Consolidated Statements of Cash Flows, (iv)
Consolidated Statements of Comprehensive Operations. |
45
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
|
|
|
|
|
DENBURY RESOURCES INC.
(Registrant)
|
|
|
By: |
/s/ Mark C. Allen
|
|
|
|
Mark C. Allen |
|
|
|
Sr. Vice President and Chief Financial Officer |
|
|
|
|
|
|
By: |
/s/ Alan Rhoades
|
|
|
|
Alan Rhoades |
|
|
|
Vice President, Accounting |
|
|
Date: November 9, 2009
46