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 March 31, 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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75024 |
Suite 1200
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(Zip code) |
Plano, TX |
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(Address of principal executive offices) |
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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 o 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 April 30, 2009 |
Common Stock, $.001 par value
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248,856,000 |
INDEX
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40 |
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Part I. Financial Information
Item 1. Financial Statements
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except shares)
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March 31, |
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December 31, |
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2009 |
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2008 |
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Assets
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Current assets |
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Cash and cash equivalents |
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$ |
18,207 |
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$ |
17,069 |
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Accrued production receivable |
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75,138 |
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67,805 |
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Trade and other receivables, net of allowance of $392 and $377 |
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95,435 |
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80,579 |
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Derivative assets |
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172,732 |
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249,746 |
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Total current assets |
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361,512 |
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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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3,569,837 |
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3,386,606 |
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Unevaluated |
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245,599 |
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235,403 |
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CO2 properties, equipment and pipelines |
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1,063,200 |
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899,542 |
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Other |
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74,136 |
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70,328 |
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Less accumulated depletion, depreciation and impairment |
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(1,651,187 |
) |
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(1,589,682 |
) |
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Net property and equipment |
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3,301,585 |
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3,002,197 |
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Deposits on properties under option or contract |
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48,917 |
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Other assets |
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133,061 |
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123,361 |
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Goodwill |
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138,737 |
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Total assets |
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$ |
3,934,895 |
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$ |
3,589,674 |
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Liabilities and Stockholders Equity
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Current liabilities |
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Accounts payable and accrued liabilities |
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$ |
130,610 |
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$ |
202,633 |
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Oil and gas production payable |
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85,829 |
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85,833 |
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Derivative liabilities |
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18,113 |
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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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53,188 |
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89,024 |
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Current maturities of long-term debt |
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4,562 |
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4,507 |
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Total current liabilities |
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296,372 |
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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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250,662 |
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251,047 |
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Long-term debt |
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1,006,987 |
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601,720 |
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Asset retirement obligations |
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46,394 |
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43,352 |
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Deferred revenue Genesis |
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18,974 |
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19,957 |
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Deferred tax liability |
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458,010 |
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433,210 |
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Derivative liabilities |
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11,224 |
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Other |
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14,639 |
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14,253 |
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Total long-term liabilities |
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1,806,890 |
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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, $.001 par value, 600,000,000 shares authorized;
249,181,816 and 248,005,874 shares issued at March 31, 2009 and
December 31, 2008, respectively |
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249 |
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248 |
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Paid-in capital in excess of par |
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716,375 |
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707,702 |
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Retained earnings |
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1,121,278 |
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1,139,575 |
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Accumulated other comprehensive loss |
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(609 |
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(627 |
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Treasury stock, at cost, 376,063 and 446,287 shares at March 31,
2009 and
December 31, 2008, respectively |
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(5,660 |
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(6,830 |
) |
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Total stockholders equity |
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1,831,633 |
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1,840,068 |
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Total liabilities and stockholders equity |
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$ |
3,934,895 |
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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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March 31, |
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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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$ |
168,069 |
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$ |
313,197 |
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CO2 sales and transportation fees |
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3,165 |
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2,851 |
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Interest income and other |
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2,525 |
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1,287 |
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Total revenues |
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173,759 |
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317,335 |
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Expenses |
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Lease operating expenses |
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74,950 |
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66,001 |
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Production taxes and marketing expenses |
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7,000 |
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15,186 |
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Transportation expense Genesis |
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2,192 |
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1,550 |
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CO2 operating expenses |
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1,300 |
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1,143 |
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General and administrative |
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22,655 |
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16,005 |
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Interest, net of interest capitalized of
$12,373 and $7,266, respectively |
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12,197 |
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4,941 |
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Depletion, depreciation and amortization |
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61,925 |
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49,839 |
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Commodity derivative expense |
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20,515 |
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46,781 |
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Total expenses |
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202,734 |
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201,446 |
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Income (loss) before income taxes |
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(28,975 |
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115,889 |
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Income tax provision (benefit) |
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Current income taxes |
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173 |
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21,236 |
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Deferred income taxes |
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(10,851 |
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21,651 |
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Net income (loss) |
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$ |
(18,297 |
) |
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$ |
73,002 |
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Net income (loss) per common share basic |
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$ |
(0.07 |
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$ |
0.30 |
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Net income (loss) per common share diluted |
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$ |
(0.07 |
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$ |
0.29 |
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Weighted average common shares outstanding |
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Basic |
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245,573 |
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242,757 |
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Diluted |
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245,573 |
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252,109 |
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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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Three Months Ended |
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March 31, |
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2009 |
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2008 |
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Cash flow from operating activities: |
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Net income (loss) |
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$ |
(18,297 |
) |
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$ |
73,002 |
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Adjustments needed to reconcile to net cash flow provided by
operations: |
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Depreciation, depletion and amortization |
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61,925 |
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49,839 |
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Deferred income taxes |
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(10,851 |
) |
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21,651 |
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Deferred revenue Genesis |
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(983 |
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(1,044 |
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Stock-based compensation |
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5,537 |
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3,886 |
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Non-cash fair value derivative adjustments |
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106,380 |
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39,128 |
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Other |
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(551 |
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281 |
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Changes in assets and liabilities relating to operations: |
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Accrued production receivable |
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(7,333 |
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(6,034 |
) |
Trade and other receivables |
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(15,590 |
) |
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(8,359 |
) |
Other assets |
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(26 |
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(838 |
) |
Accounts payable and accrued liabilities |
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(10,192 |
) |
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16,486 |
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Oil and gas production payable |
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(5 |
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17,634 |
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Other liabilities |
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2,605 |
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625 |
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Net cash provided by operating activities |
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112,619 |
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206,257 |
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Cash flow used for investing activities: |
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Oil and natural gas capital expenditures |
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(98,325 |
) |
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(156,302 |
) |
Acquisitions of oil and natural gas properties |
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(199,163 |
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(402 |
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Change in accrual for capital expenditures |
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(64,922 |
) |
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(9,609 |
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CO2 capital expenditures, including pipelines |
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(163,655 |
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(42,526 |
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Distributions from Genesis |
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2,312 |
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1,250 |
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Net proceeds from sales of oil and gas properties and equipment |
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18,357 |
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54,225 |
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Net purchases of other assets |
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(4,112 |
) |
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(10,279 |
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Other |
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(31 |
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(45 |
) |
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Net cash used for investing activities |
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(509,539 |
) |
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(163,688 |
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Cash flow from financing activities: |
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Bank repayments |
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(330,000 |
) |
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(91,000 |
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Bank borrowings |
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345,000 |
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52,000 |
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Income tax benefit from equity awards |
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668 |
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5,414 |
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Issuance of subordinated debt |
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389,827 |
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Issuance of common stock |
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3,455 |
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5,154 |
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Costs of debt financing |
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(9,970 |
) |
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Other |
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(922 |
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(205 |
) |
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Net cash provided by (used for) financing activities |
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398,058 |
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(28,637 |
) |
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Net increase in cash and cash equivalents |
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1,138 |
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13,932 |
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Cash and cash equivalents at beginning of period |
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17,069 |
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60,107 |
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Cash and cash equivalents at end of period |
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$ |
18,207 |
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$ |
74,039 |
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Supplemental disclosure of cash flow information: |
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Cash paid during the period for interest |
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$ |
7,215 |
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$ |
2,050 |
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Cash paid (refunded) during the period for income taxes |
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(3,833 |
) |
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2,630 |
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Interest capitalized |
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12,373 |
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|
7,266 |
|
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
5
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF
COMPREHENSIVE OPERATIONS
(In thousands)
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Three Months Ended |
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March 31, |
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2009 |
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|
2008 |
|
Net income (loss) |
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$ |
(18,297 |
) |
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$ |
73,002 |
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Other comprehensive income (loss), net of income tax: |
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Change in fair value of interest rate lock contracts designated as a hedge,
net of tax of $- and ($252), respectively |
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(480 |
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Interest rate lock derivative contracts reclassified to income, net of
taxes of
$11 and $11, respectively |
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18 |
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18 |
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Comprehensive income (loss) |
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$ |
(18,279 |
) |
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$ |
72,540 |
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|
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 March 31, 2009 and the consolidated results of its operations and cash flows for the three
month periods ended March 31, 2009 and 2008. Certain prior period items have been reclassified to
make the classification consistent with the classification in the most recent quarter.
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, non-vested stock
appreciation rights (SARs), non-vested restricted stock and any other convertible securities
outstanding. For the three months ended March 31, 2009 and 2008, there were no adjustments to net
income for purposes of calculating diluted net income per common share. Since we were in a loss
position for the three months ended March 31, 2009, the potentially dilutive securities were
excluded from the calculation of diluted earnings per share as the shares would have had an
anti-dilutive effect. 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 month
periods ended March 31, 2009 and 2008.
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Three Months Ended |
|
|
March 31, |
In thousands |
|
2009 |
|
2008 |
Weighted average common shares basic |
|
|
245,573 |
|
|
|
242,757 |
|
Potentially dilutive securities: |
|
|
|
|
|
|
|
|
Stock options and SARs |
|
|
|
|
|
|
7,995 |
|
Restricted stock |
|
|
|
|
|
|
1,357 |
|
|
|
|
|
|
|
|
|
|
Weighted average common shares diluted |
|
|
245,573 |
|
|
|
252,109 |
|
|
|
|
|
|
|
|
|
|
The weighted average common shares basic amount excludes 2.9 million shares in 2009 and 2.7
million shares in 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 per common share (although all restricted stock is issued and outstanding upon
grant). For purposes of calculating weighted average common shares diluted, 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. The dilution impact of these shares on our
earnings per share calculation may increase in future periods, depending on the market price of our
common stock during those periods.
7
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
For the three months ended March 31, 2009 and 2008, stock options and SARs to purchase
approximately 9.0 million and 693,000 shares of common stock, respectively, were outstanding but
excluded from the diluted net income (loss) per common share calculation, as their exercise prices
exceeded the average market price of the Companys common stock during this period and would be
anti-dilutive to the calculation or the Company was in a net loss position and the shares would be
anti-dilutive.
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 March 31, 2009 and December 31, 2008, we had $553.3 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. These
costs of CO2 pipelines under construction were not being depreciated at March 31, 2009
or December 31, 2008. Depreciation will commence as each pipeline is placed into service.
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 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 each 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.
Recently Adopted Accounting Pronouncements
Business Combinations. In December 2007, the FASB issued Statement of Financial Accounting
Standards (SFAS) No. 141 (Revised 2008), Business Combinations. SFAS No. 141(R) establishes
principles and requirements for how an acquirer recognizes and measures in its financial statements
the identifiable assets acquired, the liabilities assumed, any noncontrolling interest in the
acquiree and the goodwill acquired. SFAS No. 141(R) also establishes disclosure requirements to
enable the evaluation of the nature and financial effects of the business combination. We adopted
this statement on January 1, 2009. We have applied SFAS 141(R) to an acquisition that we made
during the first quarter (see Note 2 Hastings Field Acquisition).
Equity Method Accounting. In November 2008, the FASB reached a consensus on Emerging Issues
Task Force (EITF) Issue No. 08-6, Equity Method Investment Accounting Considerations (EITF 08-6),
which was issued to clarify how the application of equity method accounting will be affected by
SFAS No. 141(R) and SFAS No. 160. EITF 08-6 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 the use of the impairment model under
Accounting Principles Board (APB) Opinion No. 18, The Equity Method of Accounting for Investments
in Common Stock (APB No. 18). 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 Issue was effective January 1, 2009, and applies prospectively.
Noncontrolling Interests. In December 2007, the FASB issued SFAS No. 160, Noncontrolling
Interests in Consolidated Financial Statementsan amendment of ARB No. 51. SFAS No. 160
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. SFAS No. 160 also
establishes disclosure requirements that clearly identify and distinguish between the interests of
the parent and the interests of the noncontrolling owners. We adopted SFAS No. 160 on January 1,
2009. Since we currently do not have any noncontrolling interests, the adoption of SFAS No. 160
did not have any impact on our financial position or results of operations.
8
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Disclosures about Derivative Instruments and Hedging Activities. In March 2008, the FASB
issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activitiesan
amendment of SFAS No. 133. SFAS No. 161 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. SFAS No. 161 also requires entities to disclose additional information
about the amounts and location of derivatives located within the financial statements, how the
provisions of SFAS No. 133 have been applied, and the impact that hedges have on an entitys
financial position, financial performance, and cash flows. We adopted the disclosure
requirement of SFAS No. 161 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. On February 12, 2008, the FASB issued FASB Staff Position (FSP) SFAS No.
157-2 which delayed the effective date of SFAS No. 157 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 FSP FASB No. 157-2 on January 1,
2009. The adoption of this FSP did not have any impact on our financial position or results of
operations.
Recently Issued Accounting Pronouncements
In April 2009, the FASB issued three FASB Staff Positions to provide additional
application guidance and enhance disclosures regarding fair value measurements and impairments
of securities. FSP SFAS No. 157-4, Determining Fair Value When the Volume and Level of
Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions
That Are Not Orderly, provides guidelines for making fair value measurements more consistent
with the principles presented in SFAS No. 157. FSP SFAS No. 107-1 and APB 28-1, Interim
Disclosures about Fair Value of Financial Instruments, enhances consistency in financial
reporting by increasing the frequency of fair value disclosures, FSP SFAS No. 115-2 and SFAS
No. 124-2, Recognition and Presentation of Other-Than-Temporary Impairments, provides
additional guidance designed to create greater clarity and consistency in accounting for and
presenting impairment losses on securities. These three FSPs are effective for interim and
annual periods ending after June 15, 2009. We are currently evaluating the impact the new
rules may have on our financial condition or results of operations.
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 that allow companies to disclose their probable and possible reserves to investors.
The current rules limit disclosure to only proved reserves. The new disclosure requirements also
require companies that have an audit performed on their reserves to report the independence and
qualifications of the auditor of the reserve estimates, and to 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 calculated using an average price
based upon the prior 12-month period. The new oil and gas reporting requirements are effective for
annual reports on Forms 10-K for fiscal years ending on or after December 31, 2009, with early
adoption not permitted. We are currently evaluating the impact the new rules may have on our
financial condition or results of operations.
Note 2. 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 totalling $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 deposit plus purchase price, adjusted for interim net cash flows between the effective date and closing date of
the acquisition (including minor purchase price adjustments), totaled approximately $248.2 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
9
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
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 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 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 SFAS No. 141(R), Business
Combinations. As such, we estimated the fair value of this property as of the acquisition date,
as defined in SFAS No. 141(R) to be the date on which the acquirer obtains control of the acquiree, which
for this acquisition is February 2, 2009 (the closing date). SFAS No. 157, Fair Value
Measurements, 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). Further, SFAS No. 157 emphasizes that a fair value
measurement should be 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 that the fair value of these properties
on the acquisition date to be approximately $107.0 million. This measurement resulted in the
recognition of goodwill totaling $138.7 million. SFAS No. 141(R) 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 and the acquisition date of February 2, 2009. 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, SFAS No. 157 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 SFAS No. 157 refers to 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 $107.0
million to evaluated properties in the full cost pool and $2.4 million (net) 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 $138.7 million was
assigned to this single reporting unit. All of the goodwill is deductible for tax purposes as
property cost. This purchase price allocation is preliminary and subject to adjustment as the final closing statement is not complete.
The transaction related costs (legal, accounting, due diligence, etc.) have been expensed in
accordance with the provisions of SFAS No. 141(R). 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 month periods ended March 31, 2009 or 2008.
10
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
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.
The following table summarizes the changes in our asset retirement obligations for the three
months ended March 31, 2009.
|
|
|
|
|
|
|
Three Months Ended |
|
Amounts in thousands |
|
March 31, 2009 |
|
Beginning asset retirement obligation |
|
$ |
45,064 |
|
Liabilities incurred and assumed during period |
|
|
2,513 |
|
Revisions in estimated retirement obligations |
|
|
504 |
|
Liabilities settled during period |
|
|
(971 |
) |
Accretion expense |
|
|
827 |
|
|
|
|
|
Ending asset retirement obligation |
|
$ |
47,937 |
|
|
|
|
|
At March 31, 2009 and December 31, 2008, $1.5 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 three months ended March 31, 2009 were primarily related to the Hastings Field
acquisition (see Note 2 Hastings Field Acquisition). We have 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 $7.4 million at March 31, 2009 and December 31, 2008, and
are included in Other assets in our Unaudited Condensed Consolidated Balance Sheets.
11
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 4. Notes Payable and Long-term Indebtedness
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
Amounts in thousands |
|
2009 |
|
|
2008 |
|
9.75% Senior Subordinated Notes due 2016 |
|
$ |
420,000 |
|
|
$ |
|
|
Discount on Senior Subordinated Notes due 2016 |
|
|
(29,637 |
) |
|
|
|
|
7.5% Senior Subordinated Notes due 2015 |
|
|
300,000 |
|
|
|
300,000 |
|
Premium on Senior Subordinated Notes due 2015 |
|
|
578 |
|
|
|
599 |
|
7.5% Senior Subordinated Notes due 2013 |
|
|
225,000 |
|
|
|
225,000 |
|
Discount on Senior Subordinated Notes due 2013 |
|
|
(777 |
) |
|
|
(826 |
) |
NEJD financing Genesis |
|
|
172,899 |
|
|
|
173,618 |
|
Free State financing Genesis |
|
|
77,246 |
|
|
|
76,634 |
|
Senior bank loan |
|
|
90,000 |
|
|
|
75,000 |
|
Capital lease obligations Genesis |
|
|
4,360 |
|
|
|
4,544 |
|
Capital lease obligations |
|
|
2,542 |
|
|
|
2,705 |
|
|
|
|
|
|
|
|
Total |
|
|
1,262,211 |
|
|
|
857,274 |
|
Less current obligations |
|
|
4,562 |
|
|
|
4,507 |
|
|
|
|
|
|
|
|
Long-term debt and capital lease obligations |
|
$ |
1,257,649 |
|
|
$ |
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 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 Hastings Field Acquisition). 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.
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 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, subsequent to March 31, 2009 we obtained an amendment to the credit agreement from our
lenders to explicitly permit these guarantees and waive any possible previous technical violations of
this provision.
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
12
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
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. Our investment in
Genesis is included in Other Assets in our Unaudited Condensed Consolidated Balance Sheets.
Denbury received cash distributions from Genesis of $2.3 million and $1.3 million during the three
months ended March 31, 2009 and 2008, respectively. We also received $51,000 and $30,000 during
the three months ended March 31, 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.
At March 31, 2009, the balance of our equity investment in Genesis was $79.6 million. Based
on quoted market values of Genesis publicly traded limited partnership units at March 31, 2009,
the estimated market value of our publicly traded common units of Genesis was approximately $41.2
million. Since the general partner units we hold are not publicly traded, there is not a readily
available market value for these units. Due to the capital market conditions during the latter
part of 2008 and in 2009, we have reviewed the value of our investment in Genesis as of March 31,
2009 for impairment. Based upon this review, and the current and future expected cash flows of
Genesis, we do not believe the investment balance is impaired.
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. The
compensation agreements provide Genesis management with the ability to earn up to an approximate
17% interest in the incentive distributions that Genesis Energy, LLC will receive from Genesis.
These awards have a mandatory redemption feature upon termination of employment that requires a
cash payment to be made by Genesis Energy, LLC (guaranteed by us) to the holder of the award. The
awards have a graded vesting of 25% per year from the date of the award. Under the provisions of SFAS 123(R), the estimated fair value
of the mandatory redemption feature of these awards will be recorded as a liability at each
reporting date, initially recognized over the four year vesting period on an accelerated basis due to the graded vesting feature, with the changes
in this liability recorded as compensation expense in General and administrative expenses in our
Unaudited Condensed Consolidated Statement of Operations. As of March 31, 2009, we had
approximately $2.5 million recorded as an estimated long-term fair value liability for these awards
in our Unaudited Condensed Consolidated Balance Sheet which does not represent the contractual amount payable under these awards at March 31, 2009. During the three months ended March 31,
2009, we recorded approximately $2.6 million in General and administrative expenses on our
Unaudited Condensed Consolidated Statement of Operations of which $2.5 million was associated with
the estimated fair value of these awards and $80,000 was for cash payments made under these awards.
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 March 31, 2009, we have
recorded $172.9 million for the NEJD financing and $77.2 million for the Free State financing as
debt, $3.1 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. In the first
three months of 2009 and 2008, we expensed $2.2 million and $1.5 million, respectively, for these
transportation services.
13
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
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. The pipelines held under these capital leases are classified
as property and equipment and are amortized using the straight-line method over the lease terms.
Lease amortization is included in depreciation expense. The related obligations are recorded as
debt. At March 31, 2009 and December 31, 2008 we had $4.4 million and $4.5 million, respectively,
of capital lease obligations with Genesis recorded as liabilities in our Unaudited Condensed
Consolidated Balance Sheets.
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 March 31, 2009 and December 31, 2008 $23.0
million and $24.0 million, respectively, was recorded as deferred revenue, of which $4.1 million
was included in current liabilities at both March 31, 2009 and December 31, 2008. We recognized
deferred revenue of $1.0 million for each of the three months ended March 31, 2009 and 2008, 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 $1.2 million and $1.3 million for the three months ended March 31, 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 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, and in order to protect our liquidity in the
event that commodity prices continue to decline, during early October 2008 we purchased oil
derivative contracts for 2009 with a floor price of $75 per Bbl and a ceiling price of $115 per Bbl
for total consideration of $15.5 million. In March 2009, we entered into crude oil swap contracts
covering 25,000 Bbls/d for the first quarter of 2010 at a weighted average price of $51.85 per
barrel, and crude oil collar contracts covering 25,000 Bbls/d for the second quarter of 2010 with a
weighted average floor price of $50.00 per Bbl and a weighted average ceiling price of $74.60 per
Bbl. Also during March 2009, we entered into natural gas derivative swap contracts covering 55,000
MMBtu/d for 2010 at a weighted average price of $5.66 per MMBtu, and 40,000 MMBtu/d for 2011 at a
weighted average price of $6.21 per MMBtu.
At March 31, 2009, our oil and natural gas derivative contracts were recorded at their fair
value, which was a net asset of $143.4 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. We have included an estimate of nonperformance risk in the fair value measurement
of our oil and natural gas derivative contracts as required by SFAS No. 157. We have measured the
nonperformance risk based upon credit default swaps or credit spreads. At March 31, 2009 and
December 31, 2008, the fair value of our oil and natural gas derivative contracts was reduced by
$1.7 million and $3.7 million, respectively, for estimated nonperformance risk.
14
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
The following is a summary of Commodity derivative expense included in our Unaudited
Condensed Consolidated Statements of Operations:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
Amounts in thousands |
|
2009 |
|
|
2008 |
|
Receipt (payment) on settlements of
derivative contracts oil |
|
$ |
85,836 |
|
|
$ |
(7,392 |
) |
Receipt (payment) on settlements of
derivative contracts gas |
|
|
|
|
|
|
(656 |
) |
Fair value adjustments to derivative
contracts expense |
|
|
(106,351 |
) |
|
|
(38,733 |
) |
|
|
|
|
|
|
|
Commodity derivative expense |
|
$ |
(20,515 |
) |
|
$ |
(46,781 |
) |
|
|
|
|
|
|
|
Fair Value of Crude Oil Derivative Contracts Not Classified as Hedging Instruments under SFAS No.
133:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value |
|
|
NYMEX Contract Prices Per Bbl |
|
Asset (Liability) |
|
|
|
|
|
|
|
|
|
|
Collar Prices |
|
March 31, |
|
December 31, |
Type of Contract and Period |
|
Bbls/d |
|
Swap Price |
|
Floor |
|
Ceiling |
|
2009 |
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
Collar Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
April 2009 Dec. 2009 |
|
|
30,000 |
|
|
|
|
|
|
$ |
75.00 |
|
|
$ |
115.00 |
|
|
$ |
172,732 |
|
|
$ |
249,746 |
|
April 2010 June 2010 |
|
|
5,000 |
|
|
|
|
|
|
|
50.00 |
|
|
|
76.00 |
|
|
|
(94 |
) |
|
|
|
|
April 2010 June 2010 |
|
|
10,000 |
|
|
|
|
|
|
|
50.00 |
|
|
|
73.15 |
|
|
|
(884 |
) |
|
|
|
|
April 2010 June 2010 |
|
|
5,000 |
|
|
|
|
|
|
|
50.00 |
|
|
|
76.40 |
|
|
|
(49 |
) |
|
|
|
|
April 2010 June 2010 |
|
|
5,000 |
|
|
|
|
|
|
|
50.00 |
|
|
|
74.30 |
|
|
|
(297 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jan. 2010 March 2010 |
|
|
6,667 |
|
|
$ |
52.50 |
|
|
|
|
|
|
|
|
|
|
|
(4,305 |
) |
|
|
|
|
Jan. 2010 March 2010 |
|
|
3,333 |
|
|
|
52.20 |
|
|
|
|
|
|
|
|
|
|
|
(2,237 |
) |
|
|
|
|
Jan. 2010 March 2010 |
|
|
5,000 |
|
|
|
52.10 |
|
|
|
|
|
|
|
|
|
|
|
(3,398 |
) |
|
|
|
|
Jan. 2010 March 2010 |
|
|
5,000 |
|
|
|
50.90 |
|
|
|
|
|
|
|
|
|
|
|
(3,907 |
) |
|
|
|
|
Jan. 2010 March 2010 |
|
|
5,000 |
|
|
|
51.45 |
|
|
|
|
|
|
|
|
|
|
|
(3,674 |
) |
|
|
|
|
Fair Value of Natural Gas Derivative Contracts Not Classified as Hedging Instruments under SFAS No.
133:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value |
|
|
NYMEX Contract |
|
Asset (Liability) |
|
|
Prices Per MMBtu/d |
|
March 31, |
|
December 31, |
Type of Contract and Period |
|
MMBtu/d |
|
Swap Price |
|
2009 |
|
2008 |
|
|
|
|
|
|
|
|
|
|
(In thousands) |
Swap Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jan. 2010 Dec. 2010 |
|
|
45,000 |
|
|
$ |
5.67 |
|
|
$ |
(3,826 |
) |
|
$ |
|
|
Jan. 2010 Dec. 2010 |
|
|
10,000 |
|
|
|
5.65 |
|
|
|
(925 |
) |
|
|
|
|
Jan. 2011 Dec. 2011 |
|
|
10,000 |
|
|
|
6.27 |
|
|
|
(1,254 |
) |
|
|
|
|
Jan. 2011 Dec. 2011 |
|
|
10,000 |
|
|
|
6.25 |
|
|
|
(1,301 |
) |
|
|
|
|
Jan. 2011 Dec. 2011 |
|
|
20,000 |
|
|
|
6.16 |
|
|
|
(3,186 |
) |
|
|
|
|
15
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Additional Disclosures about Derivative Instruments:
At March 31, 2009 and December 31, 2008, we had derivative financial instruments under SFAS
No. 133 recorded in our Unaudited Condensed Consolidated Balance Sheets as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value |
|
|
|
|
|
|
|
Asset (Liability) |
|
|
|
|
|
|
|
March 31, |
|
|
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 |
|
$ |
172,732 |
|
|
$ |
249,746 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Liability |
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil contracts |
|
Derivative liability current |
|
|
(17,521 |
) |
|
|
|
|
Natural Gas contracts |
|
Derivative liability current |
|
|
(592 |
) |
|
|
|
|
Crude Oil contracts |
|
Derivative liability long-term |
|
|
(1,324 |
) |
|
|
|
|
Natural Gas contracts |
|
Derivative liability long-term |
|
|
(9,900 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives
not designated as
hedging instruments |
|
|
|
$ |
143,395 |
|
|
$ |
249,746 |
|
|
|
|
|
|
|
|
|
|
|
|
For the three months ended March 31, 2009 and 2008, the effect on income of derivative
financial instruments under SFAS No. 133 was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Gain / (Loss) |
|
|
|
|
|
|
|
Recognized in Income For |
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
Location of Gain/(Loss) |
|
|
March 31, |
|
|
March 31, |
|
Type of Contract |
|
Recognized in Income |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
(In thousands) |
|
Derivatives not designated as hedging
instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Contracts |
|
Commodity derivative expense |
|
$ |
(10,025 |
) |
|
$ |
(4,754 |
) |
Natural Gas Contracts |
|
Commodity derivative expense |
|
|
(10,490 |
) |
|
|
(42,027 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total derivatives
not designated as
hedging instruments |
|
|
|
$ |
(20,515 |
) |
|
$ |
(46,781 |
) |
|
|
|
|
|
|
|
|
|
|
|
16
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 7. Fair Value Measurements
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 March 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at March 31, 2009 Using: |
|
|
|
|
|
|
|
Significant |
|
|
|
|
|
|
|
|
|
Quoted Prices |
|
|
Other |
|
|
Significant |
|
|
|
|
|
|
in Active |
|
|
Observable |
|
|
Unobservable |
|
|
|
|
|
|
Markets |
|
|
Inputs |
|
|
Inputs |
|
|
|
|
Amounts in thousands |
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
|
Total |
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural
gas derivative
contracts |
|
$ |
|
|
|
$ |
172,732 |
|
|
$ |
|
|
|
$ |
172,732 |
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural
gas derivative
contracts |
|
|
|
|
|
|
(29,337 |
) |
|
|
|
|
|
|
(29,337 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
|
|
|
$ |
143,395 |
|
|
$ |
|
|
|
$ |
143,395 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Note 6, Derivative Instruments and Hedging Activities for further information about
these contracts.
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:
17
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2009 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and |
|
|
(Issuer and |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
Amounts in thousands |
|
Co-Obligor) |
|
|
Co-Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
439,078 |
|
|
$ |
354,030 |
|
|
$ |
16,045 |
|
|
$ |
(447,641 |
) |
|
$ |
361,512 |
|
Property and equipment |
|
|
|
|
|
|
3,228,472 |
|
|
|
73,113 |
|
|
|
|
|
|
|
3,301,585 |
|
Investment in subsidiaries (equity
method) |
|
|
1,353,882 |
|
|
|
|
|
|
|
1,297,345 |
|
|
|
(2,651,227 |
) |
|
|
|
|
Other assets |
|
|
741,289 |
|
|
|
205,259 |
|
|
|
56,169 |
|
|
|
(730,919 |
) |
|
|
271,798 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
2,534,249 |
|
|
$ |
3,787,761 |
|
|
$ |
1,442,672 |
|
|
$ |
(3,829,787 |
) |
|
$ |
3,934,895 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
11,675 |
|
|
$ |
646,475 |
|
|
$ |
85,862 |
|
|
$ |
(447,641 |
) |
|
$ |
296,372 |
|
Long-term liabilities |
|
|
690,941 |
|
|
|
1,843,941 |
|
|
|
2,928 |
|
|
|
(730,919 |
) |
|
|
1,806,890 |
|
Stockholders equity |
|
|
1,831,633 |
|
|
|
1,297,345 |
|
|
|
1,353,882 |
|
|
|
(2,651,227 |
) |
|
|
1,831,633 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilties and
stockholders equity |
|
$ |
2,534,249 |
|
|
$ |
3,787,761 |
|
|
$ |
1,442,672 |
|
|
$ |
(3,829,787 |
) |
|
$ |
3,934,895 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and |
|
|
(Issuer and |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
Amounts in thousands |
|
Co-Obligor) |
|
|
Co-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 |
|
|
|
|
|
|
|
1,313,656 |
|
|
|
(2,685,003 |
) |
|
|
|
|
Other assets |
|
|
312,239 |
|
|
|
114,372 |
|
|
|
56,002 |
|
|
|
(310,335 |
) |
|
|
172,278 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 liabilties and
stockholders equity |
|
$ |
2,141,637 |
|
|
$ |
3,497,259 |
|
|
$ |
1,412,900 |
|
|
$ |
(3,462,122 |
) |
|
$ |
3,589,674 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2009 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and |
|
|
(Issuer and |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
Amounts in thousands |
|
Co-Obligor) |
|
|
Co-Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Revenues |
|
$ |
10,858 |
|
|
$ |
172,060 |
|
|
$ |
1,699 |
|
|
$ |
(10,858 |
) |
|
$ |
173,759 |
|
Expenses |
|
|
11,673 |
|
|
|
198,964 |
|
|
|
2,955 |
|
|
|
(10,858 |
) |
|
|
202,734 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before the following: |
|
|
(815 |
) |
|
|
(26,904 |
) |
|
|
(1,256 |
) |
|
|
|
|
|
|
(28,975 |
) |
Equity in net earnings of
subsidiaries |
|
|
(17,482 |
) |
|
|
|
|
|
|
(16,330 |
) |
|
|
33,812 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes |
|
|
(18,297 |
) |
|
|
(26,904 |
) |
|
|
(17,586 |
) |
|
|
33,812 |
|
|
|
(28,975 |
) |
Income tax provision (benefit) |
|
|
|
|
|
|
(10,574 |
) |
|
|
(104 |
) |
|
|
|
|
|
|
(10,678 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(18,297 |
) |
|
$ |
(16,330 |
) |
|
$ |
(17,482 |
) |
|
$ |
33,812 |
|
|
$ |
(18,297 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2008 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and |
|
|
(Issuer and |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
Amounts in thousands |
|
Co-Obligor) |
|
|
Co-Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Revenues |
|
$ |
5,625 |
|
|
$ |
311,619 |
|
|
$ |
5,716 |
|
|
$ |
(5,625 |
) |
|
$ |
317,335 |
|
Expenses |
|
|
5,745 |
|
|
|
194,897 |
|
|
|
6,429 |
|
|
|
(5,625 |
) |
|
|
201,446 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before the following: |
|
|
(120 |
) |
|
|
116,722 |
|
|
|
(713 |
) |
|
|
|
|
|
|
115,889 |
|
Equity in net earnings of
subsidiaries |
|
|
73,104 |
|
|
|
|
|
|
|
73,805 |
|
|
|
(146,909 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
72,984 |
|
|
|
116,722 |
|
|
|
73,092 |
|
|
|
(146,909 |
) |
|
|
115,889 |
|
Income tax provision (benefit) |
|
|
(18 |
) |
|
|
42,917 |
|
|
|
(12 |
) |
|
|
|
|
|
|
42,887 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
73,002 |
|
|
$ |
73,805 |
|
|
$ |
73,104 |
|
|
$ |
(146,909 |
) |
|
$ |
73,002 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2009 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and |
|
|
(Issuer and |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
Amounts in thousands |
|
Co-Obligor) |
|
|
Co-Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Cash flow from operations |
|
$ |
|
|
|
$ |
110,784 |
|
|
$ |
1,835 |
|
|
$ |
|
|
|
$ |
112,619 |
|
Cash flow from investing
activities |
|
|
(384,328 |
) |
|
|
(509,539 |
) |
|
|
|
|
|
|
384,328 |
|
|
|
(509,539 |
) |
Cash flow from financing
activities |
|
|
384,328 |
|
|
|
398,058 |
|
|
|
|
|
|
|
(384,328 |
) |
|
|
398,058 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash |
|
|
|
|
|
|
(697 |
) |
|
|
1,835 |
|
|
|
|
|
|
|
1,138 |
|
Cash, beginning of period |
|
|
24 |
|
|
|
16,898 |
|
|
|
147 |
|
|
|
|
|
|
|
17,069 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, end of period |
|
$ |
24 |
|
|
$ |
16,201 |
|
|
$ |
1,982 |
|
|
$ |
|
|
|
$ |
18,207 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2008 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and |
|
|
(Issuer and |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
Amounts in thousands |
|
Co-Obligor) |
|
|
Co-Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Cash flow from operations |
|
$ |
(10 |
) |
|
$ |
205,010 |
|
|
$ |
1,257 |
|
|
$ |
|
|
|
$ |
206,257 |
|
Cash flow from investing
activities |
|
|
(10,541 |
) |
|
|
(163,688 |
) |
|
|
|
|
|
|
10,541 |
|
|
|
(163,688 |
) |
Cash flow from financing
activities |
|
|
10,541 |
|
|
|
(28,637 |
) |
|
|
|
|
|
|
(10,541 |
) |
|
|
(28,637 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash |
|
|
(10 |
) |
|
|
12,685 |
|
|
|
1,257 |
|
|
|
|
|
|
|
13,932 |
|
Cash, beginning of period |
|
|
34 |
|
|
|
58,343 |
|
|
|
1,730 |
|
|
|
|
|
|
|
60,107 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, end of period |
|
$ |
24 |
|
|
$ |
71,028 |
|
|
$ |
2,987 |
|
|
$ |
|
|
|
$ |
74,039 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20
DENBURY RESOURCES INC.
Item 2. 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 reserves of carbon dioxide (CO2) used for
tertiary oil recovery east of the Mississippi River, own significant operating acreage in the
Barnett Shale play near Fort Worth, Texas, and properties in 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 operations. 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 Aledo, Texas.
Operating Highlights. During the first quarter of 2009 we recorded a net loss of $18.3
million, our first quarterly loss in ten years, as compared to net income of $73.0 million in the
first quarter of 2008. Although we achieved record oil and natural gas production during the first
quarter of 2009, lower commodity prices reduced our revenues by approximately $200.4 million, and
we recorded a non-cash fair value charge on our derivative commodity contracts of $106.4 million
(approximately $65.9 million after tax).
Our oil and natural gas production for the first quarter of 2009 averaged 53,408 BOE/d, a 19%
increase over first quarter 2008 levels, and an 11% sequential increase over levels in the fourth
quarter of 2008. Our production growth was primarily due to production increases in both our
tertiary oil fields and the Barnett Shale, and the volumes added by the Hastings Field acquisition
that we completed in early February 2009 (see Purchase of Hastings Field below). Our tertiary
oil production averaged 22,583 BOE/d during the first quarter of 2009, a 32% increase over the
17,156 BOE/d average for tertiary production in the first quarter of 2008, and a 3% increase over
the 21,874 BOE/d average during the fourth quarter of 2008. Production in the Barnett Shale
increased to 14,932 BOE/d for the first quarter of 2009, compared to 12,801 BOE/d during the first
quarter of 2008, a 17% increase year-over-year, due primarily to additional sales of natural gas
liquids that were produced during the third and fourth quarters of 2008, but not sold until the
first quarter of 2009 due to plant shutdowns caused by Hurricane Ike. The acquisition of Hastings
Field added 1,562 BOE/d to our first quarter 2009 production average. (See Results of Operations
Operating Results Production for further discussion on the changes in our production
volumes).
Despite the increase in our oil and natural gas production volumes in the first quarter of
2009, our oil and natural gas revenues were 46% lower in the first quarter of 2009 than in the
prior year first quarter, as our average price received on a per BOE basis was approximately 54%
lower in the current year period. The commodity price volatility, which began during the second
half of 2008, continued through the first quarter of 2009. NYMEX oil prices moved from $44.60 per
barrel at December 31, 2008 to as low as $34.00 per barrel in mid-February, and up to $49.66 per
barrel as of March 31, 2009. NYMEX natural gas prices have continued their downward trend, falling
from $5.62 per Mcf at December 31, 2008 to $3.78 per Mcf as of March 31, 2009.
Cash settlements on our oil commodity derivative contracts, which are not included in our oil
and natural gas revenues, were $85.8 million received in the first quarter of 2009, as compared to
a cash payment of $8.0 million in the first quarter of 2008. The non-cash fair value adjustments
associated with our derivative contracts resulted in a $106.4 million charge in the first quarter
of 2009 versus $38.7 million in the 2008 period.
21
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Our lease operating expenses on a gross basis for the first quarter of 2009 were approximately
14% higher than in the first quarter of 2008, but approximately 6% lower than in the fourth quarter
of 2008. On a per BOE basis, our lease operating expenses were approximately 3% lower than in the
first quarter of 2008 and approximately 13% lower than in the fourth quarter of 2008. With the
lower commodity price environment, we have focused our efforts on improving our operating
efficiency. These efforts, along with the reduction in our cost of CO2 due to lower oil
prices and higher production volumes, have resulted in lower per BOE lease operating costs in the
first quarter of 2009. Our gross general and administrative costs were approximately $6.7 million
(42%) higher than in the first quarter of 2008, due primarily to higher employee costs, and the
expensing of $2.6 million associated with our compensation arrangement for certain management of
Genesis (see further discussion below under Results of Operations Production Expenses and
Results of Operations General and Administrative Expenses). Interest expense also increased
in the first quarter of 2009 primarily due to higher average debt levels and a higher average cost
of money (i.e. higher interest rates), partially offset by higher levels of capitalized interest
during the first quarter of 2009.
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 1,562 BOE/d during the first
quarter of 2009, representing approximately two months of production.
We have recorded the acquisition of Hastings Field in accordance with SFAS No. 141(R), Business
Combinations, which became effective for acquisitions after December 31, 2008. Based on these new
rules, we have allocated $107.0 million of the $248.2 million adjusted purchase price to proved
properties, approximately $2.4 million to land, oilfield equipment and other related assets, and
the remaining $138.7 million to goodwill. See further discussion on this acquisition in Note 2 to
the Unaudited Condensed Consolidated Financial Statements.
Management Succession Plan. On February 5, 2009, our Board of Directors adopted a management
succession plan under which our current executive officers will assume new roles on or about June
30, 2009. Gareth Roberts, the Companys founder, will relinquish his position as President and CEO
and become Co-Chairman of the Board of Directors and will assume a non-officer role as the
Companys Chief Strategist. Phil Rykhoek, currently Senior Vice President and Chief Financial
Officer, will become CEO; Tracy Evans, currently Senior Vice President Reservoir Engineering,
will become President and Chief Operating Officer; and Mark Allen, currently Vice President and
Chief Accounting Officer, will become Senior Vice President and Chief Financial Officer.
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.
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 which began during mid-2008, we have taken additional
measures during the first quarter of 2009 to improve our liquidity. During February 2009, we issued
$420 million of 9.75% Senior Subordination Notes, and in March 2009 we entered into additional
commodity derivative contracts for 2010 and 2011 to protect our cash flow. We used the $381.4
million proceeds from the Notes issuance to repay the majority of our then outstanding bank debt,
freeing up our credit line for future capital needs. The new commodity derivative contracts include
crude oil swaps covering 25,000 Bbls/d during the first quarter of 2010 at a weighted average price
of $51.85 per barrel, crude oil collars covering
22
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
25,000 Bbls/d during the second quarter of 2010 with a floor price of $50.00 per barrel and a
weighted average ceiling price of $74.60 per barrel, natural gas swaps for calendar year 2010
covering 55,000 MMBtu/d at a weighted average price of $5.66 per MMBtu and natural gas swaps for
calendar year 2011 covering 40,000 MMBtu/d at a weighted average price of $6.21 per MMBtu.
We currently estimate our 2009 capital spending will be approximately $750 million, plus $201
million for the already closed Hastings Field acquisition. Our current 2009 capital budget
includes approximately $485 million relating to 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 May 8, 2009, we have completed approximately $18 million of these
leases, and expect to close on an additional $20 million around mid-year. If we do not enter into
$100 million of operating leases during 2009, our capital expenditures would increase accordingly,
and we would anticipate funding those additional capital expenditures with our bank credit line.
The 2009 budget incorporates significantly reduced spending in the Barnett Shale and in other
conventional areas such as the Heidelberg Selma Chalk, and a slower development program for our
tertiary operations. Based on our current cash flow projections using $50.00 per barrel for oil and
$5.00 per Mcf for natural gas prices, and including the expected cash settlements on our 2009 oil
derivative contracts, we anticipate our projected 2009 capital expenditures 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. We have funded a portion of this shortfall with the approximately $381.4 million of net proceeds from our February 2009 subordinated debt issuance, and anticipate
funding the remainder of this shortfall under our bank credit line.
As part of our semi-annual bank review, on April 1, 2009 our borrowing base and commitment
amount were reaffirmed at $1.0 billion 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 a total bank debt balance by the
end of 2009 of between $150 million and $250 million,
leaving us $500 million to $600 million of
availability on our $750 million commitment amount.
We may raise additional capital during 2009 if it is possible to do so in a reasonably
economic manner. Such additional capital sources could include the sale or joint venture of
assets, a volumetric production payment, additional operating leases, or other options that become
available during the year. We continually monitor our capital spending and anticipated cash flows
and believe that we can adjust our capital spending up or down depending on cash flows; however,
any such reduction in capital spending could reduce our anticipated production levels in future
years. For 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 Operation- Off-Balance Sheet
Arrangements Commitments and Obligations in our 2008 Form 10-K for further information
regarding these commitments).
Based on our long-term models, we expect our future capital spending needs to be less in the
future than they have been in recent years, excluding any potential acquisitions. Therefore, if
commodity prices remain at current levels after 2009, we anticipate that we will be able to match
our capital spending with our projected cash flow from operations to preserve our liquidity to the
extent we deem necessary, although any such spending reductions would most likely lower our
anticipated rate of production growth.
23
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Sources and Uses of Capital Resources
|
|
|
|
|
|
|
|
|
Capital Expenditure Summary |
|
Three Months Ended |
|
|
|
March 31, |
|
Amounts in thousands |
|
2009 |
|
|
2008 |
|
Oil and natural gas exploration and development |
|
|
|
|
|
|
|
|
Drilling |
|
$ |
20,588 |
|
|
$ |
67,291 |
|
Geological, geophysical and acreage |
|
|
3,791 |
|
|
|
4,942 |
|
Facilities |
|
|
52,964 |
|
|
|
44,342 |
|
Recompletions |
|
|
16,940 |
|
|
|
33,744 |
|
Capitalized interest |
|
|
4,042 |
|
|
|
5,983 |
|
|
|
|
|
|
|
|
Total oil and natural gas exploration and
development expenditures |
|
|
98,325 |
|
|
|
156,302 |
|
Oil and natural gas property acquisitions |
|
|
199,163 |
|
|
|
402 |
|
|
|
|
|
|
|
|
Total oil and natural gas capital expenditures |
|
|
297,488 |
|
|
|
156,704 |
|
CO2 capital expenditures |
|
|
|
|
|
|
|
|
CO2 pipelines |
|
|
143,508 |
|
|
|
15,398 |
|
CO2 producing fields |
|
|
11,816 |
|
|
|
25,845 |
|
Capitalized interest |
|
|
8,331 |
|
|
|
1,283 |
|
|
|
|
|
|
|
|
Total CO2 capital expenditures |
|
|
163,655 |
|
|
|
42,526 |
|
|
|
|
|
|
|
|
Total |
|
$ |
461,143 |
|
|
$ |
199,230 |
|
|
|
|
|
|
|
|
Our first quarter 2009 capital expenditures were funded with $112.6 million of cash flow from
operations, $15.0 million of net bank borrowings and $381.4 million of proceeds from the February
2009 issuance of 9.75% Senior Subordinated Notes. Our first quarter 2008 capital expenditures were
essentially funded with $206.3 million of cash flow from operations, as the $48.9 million of
proceeds from the second closing on our Louisiana property sale was used to reduce bank debt by
$39.0 million during the first quarter, with the balance of funds from the property sale primarily
used to fund other assets.
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 our proved reserve reports. Our derivative contracts,
which are recorded at fair value in our balance sheets, 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/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.
24
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
We currently have long-term commitments to purchase CO2 from seven proposed
gasification plants, three 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 1.0 Bcf/d to 1.7 Bcf/d. Due to the current economic conditions, the earliest we would
expect any plant to be completed and providing CO2 would be 2013, 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 sources (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 seven plants are built, the aggregate purchase obligation for this CO2 would be
around $210 million per year, assuming a $50 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 the CO2 volumes from the seven proposed
plants that we currently have contracts with. 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, including 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.
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 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 plan to drill one additional CO2 source well to further increase
our production capacity and reserves. We estimate that we are currently capable of producing
between 900 MMcf/d and 1 Bcf/d of CO2. During the first quarter of 2009, our
CO2 production averaged 732 MMcf/d, as compared to an average of approximately 554
MMcf/d during the first quarter of 2008. We used 87% of this production, or 640 MMcf/d, in our
tertiary operations during the first quarter of 2009, and sold the balance to our industrial
customers or to Genesis pursuant to our volumetric production payments.
We spent approximately $0.14 per Mcf to produce our CO2 during the first quarter of
2009, lower than our 2008 first quarter average of $0.22 per Mcf, primarily due to reduced royalty
expense as a result of lower oil prices (to which royalties are principally tied) during the first
quarter of 2009. Our estimated total cost per thousand cubic feet of CO2 during the
first quarter of 2009 was approximately $0.23, after inclusion of depreciation and amortization
expense, also down from the 2008 first quarter average total cost of $0.30 per Mcf.
25
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
In addition to our natural source of CO2 and the proposed gasification plants
discussed above (see Off-Balance Sheet Arrangements Commitments and Obligations), we have
ongoing discussions with owners of existing plants of various types that emit CO2 and we
may be able to purchase their volumes. In order to capture such volumes, we (or the plant owner)
would need to install additional equipment, which include 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 anticipated 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 supplies and
demands.
The following table summarizes our tertiary oil production and tertiary lease operating
expense per barrel for each quarter in 2008 and the first quarter of 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (BOE/d) |
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
First |
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
|
Quarter |
Tertiary Oil Field |
|
2008 |
|
2008 |
|
2008 |
|
2008 |
|
|
2009 |
|
|
|
|
Phase I: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brookhaven |
|
|
2,638 |
|
|
|
2,714 |
|
|
|
2,772 |
|
|
|
3,178 |
|
|
|
|
3,451 |
|
Little Creek area |
|
|
1,807 |
|
|
|
1,661 |
|
|
|
1,556 |
|
|
|
1,706 |
|
|
|
|
1,619 |
|
Mallalieu area |
|
|
6,099 |
|
|
|
6,260 |
|
|
|
5,339 |
|
|
|
5,056 |
|
|
|
|
4,490 |
|
McComb area |
|
|
1,632 |
|
|
|
1,818 |
|
|
|
2,061 |
|
|
|
2,092 |
|
|
|
|
2,246 |
|
Lockhart Crossing |
|
|
|
|
|
|
|
|
|
|
182 |
|
|
|
555 |
|
|
|
|
607 |
|
Phase II: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Martinville |
|
|
793 |
|
|
|
715 |
|
|
|
736 |
|
|
|
1,213 |
|
|
|
|
1,118 |
|
Eucutta |
|
|
2,699 |
|
|
|
2,933 |
|
|
|
3,262 |
|
|
|
3,538 |
|
|
|
|
3,813 |
|
Soso |
|
|
1,488 |
|
|
|
1,885 |
|
|
|
2,358 |
|
|
|
2,704 |
|
|
|
|
2,705 |
|
Phase III: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tinsley |
|
|
|
|
|
|
675 |
|
|
|
1,518 |
|
|
|
1,832 |
|
|
|
|
2,390 |
|
Phase IV: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cranfield |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
144 |
|
|
|
|
|
|
|
Total tertiary oil production |
|
|
17,156 |
|
|
|
18,661 |
|
|
|
19,784 |
|
|
|
21,874 |
|
|
|
|
22,583 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tertiary operating expense
per Bbl |
|
$ |
20.81 |
|
|
$ |
24.67 |
|
|
$ |
26.81 |
|
|
$ |
21.86 |
|
|
|
$ |
20.48 |
|
|
|
|
|
Oil production from our tertiary operations averaged 22,583 BOE/d in the first quarter of
2009, a 32% increase over our first quarter 2008 tertiary production level of 17,156 BOE/d and a 3%
sequential increase over the fourth quarter 2008 average tertiary production level of 21,874 BOE/d.
This increase is the result of tertiary fields that commenced production after the first quarter
of 2008, mainly Tinsley and Lockhart Crossing Fields, and from production increases during 2009 at
almost every other tertiary field, except Little Creek and Mallalieu Fields. Little Creek is a
mature field that is experiencing normal decline, and the decline at Mallalieu Field is primarily
due to current CO2 recycle volumes exceeding the plant capacity there. We are current
expanding the capacity of the facility and expect it to be operational in the third or fourth
quarter of 2009. Once the recycle capacity is expanded we would expect production at Mallalieu
Field to plateau. We had a minimal amount of oil production from Cranfield Field during the first
quarter of 2009 and we expect initial production from Heidelberg Field during the second half of
2009. We also anticipate initiating CO2 injections at Delhi field (Phase V) during the
second quarter of 2009, following the completion of the Delta Pipeline from Tinsley to Delhi Field,
which is currently undergoing testing. However, we currently do not anticipate any tertiary
production response at Delhi Field until the first half of 2010.
26
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
During the first quarter of 2009, our operating costs for our tertiary properties averaged
$20.48 per BOE, lower than the prior years first quarter average of $20.81 per BOE, and our fourth
quarter 2008 average of $21.86 per BOE. While costs have increased on a gross basis due to the new
tertiary floods and ongoing expansion of existing floods, they have decreased on a per BOE basis
due to the increased production and reductions in our CO2 costs discussed above. For
any specific field, we expect our tertiary lease operating expense per BOE to initially be high,
until production increases significantly, and then level off until production begins to decline.
Operating Results
As summarized in the Overview section above and discussed in more detail below, the slight
decline in overall expenses and the 19% increase in production quantities in the first quarter of
2009 as compared to the same quarter in 2008, was more than offset by decreased commodity prices,
which when coupled with a $106.4 million non-cash fair value charge on our derivative contracts,
result in a net loss during the first quarter of 2009.
Certain of our operating results and statistics for the comparative first quarters of 2009 and
2008 are included in the following table.
27
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
March 31, |
|
Amounts in thousands except per share and unit data |
|
2009 |
|
|
2008 |
|
|
Operating results |
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(18,297 |
) |
|
$ |
73,002 |
|
Net income (loss) per common share basic |
|
|
(0.07 |
) |
|
|
0.30 |
|
Net income (loss) per common share diluted |
|
|
(0.07 |
) |
|
|
0.29 |
|
Cash flow from operations |
|
|
112,619 |
|
|
|
206,257 |
|
|
|
|
|
|
|
|
|
|
Average daily production volumes |
|
|
|
|
|
|
|
|
Bbls/d |
|
|
37,640 |
|
|
|
30,164 |
|
Mcf/d |
|
|
94,613 |
|
|
|
88,419 |
|
BOE/d (1) |
|
|
53,408 |
|
|
|
44,900 |
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
133,265 |
|
|
$ |
250,441 |
|
Natural gas sales |
|
|
34,804 |
|
|
|
62,756 |
|
|
|
|
|
|
|
|
Total oil and natural gas sales |
|
$ |
168,069 |
|
|
$ |
313,197 |
|
|
|
|
|
|
|
|
|
Oil and natural gas derivative contracts (2) |
|
|
|
|
|
|
|
|
Cash receipt (payment) on settlement of derivative contracts |
|
$ |
85,836 |
|
|
$ |
(8,048 |
) |
Non-cash fair value adjustment expense |
|
|
(106,351 |
) |
|
|
(38,733 |
) |
|
|
|
|
|
|
|
Total expense from oil and gas derivative contracts |
|
$ |
(20,515 |
) |
|
$ |
(46,781 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
74,950 |
|
|
$ |
66,001 |
|
Production taxes and marketing expenses (3) |
|
|
9,192 |
|
|
|
16,736 |
|
|
|
|
|
|
|
|
Total production expenses |
|
$ |
84,142 |
|
|
$ |
82,737 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-tertiary CO2 operating margin |
|
|
|
|
|
|
|
|
CO2 sales and transportation fees (4) |
|
$ |
3,165 |
|
|
$ |
2,851 |
|
CO2 operating expenses |
|
|
(1,300 |
) |
|
|
(1,143 |
) |
|
|
|
|
|
|
|
Non-tertiary CO2 operating margin |
|
$ |
1,865 |
|
|
$ |
1,708 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit prices including impact of derivative
settlements (2) |
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
64.68 |
|
|
$ |
88.55 |
|
Gas price per Mcf |
|
|
4.09 |
|
|
|
7.72 |
|
|
|
|
|
|
|
|
|
|
Unit prices excluding impact of
derivative settlements (2) |
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
39.34 |
|
|
$ |
91.24 |
|
Gas price per Mcf |
|
|
4.09 |
|
|
|
7.80 |
|
|
|
|
|
|
|
|
|
|
Oil and natural gas operating revenues and
expenses per BOE (1) |
|
|
|
|
|
|
|
|
Oil and natural gas revenues |
|
$ |
34.97 |
|
|
$ |
76.65 |
|
|
|
|
|
|
|
|
Oil and natual gas lease operating expenses |
|
$ |
15.59 |
|
|
$ |
16.15 |
|
Oil and natural gas production taxes and marketing expenses |
|
|
1.91 |
|
|
|
4.10 |
|
|
|
|
|
|
|
|
Total oil and natural gas production expenses |
|
$ |
17.50 |
|
|
$ |
20.25 |
|
|
|
|
|
|
|
|
|
|
|
(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 $1.0 million for both periods associated with volumetric production payments and
$1.2 million and $1.3 million for 2009 and 2008, respectively, of transportation income, both from Genesis. |
28
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Production: Average daily production by area for each of the quarters of 2008 and the first
quarter of 2009 is listed in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (BOE/d) |
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
First |
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
|
Quarter |
Operating Area |
|
2008 |
|
2008 |
|
2008 |
|
2008 |
|
|
2009 |
|
|
|
|
|
|
Tertiary oil fields |
|
|
17,156 |
|
|
|
18,661 |
|
|
|
19,784 |
|
|
|
21,874 |
|
|
|
|
22,583 |
|
Mississippi non-CO2 floods |
|
|
12,128 |
|
|
|
11,617 |
|
|
|
11,694 |
|
|
|
12,150 |
|
|
|
|
11,904 |
|
Texas |
|
|
13,522 |
|
|
|
14,068 |
|
|
|
12,701 |
|
|
|
12,576 |
|
|
|
|
17,063 |
|
Onshore Louisiana |
|
|
905 |
|
|
|
663 |
|
|
|
512 |
|
|
|
418 |
|
|
|
|
708 |
|
Alabama and other |
|
|
1,189 |
|
|
|
1,296 |
|
|
|
1,222 |
|
|
|
1,219 |
|
|
|
|
1,150 |
|
|
|
|
|
|
|
Total Company |
|
|
44,900 |
|
|
|
46,305 |
|
|
|
45,913 |
|
|
|
48,237 |
|
|
|
|
53,408 |
|
|
|
|
|
|
|
As outlined in the above table, production in the first quarter of 2009 increased 19% over
first quarter 2008 levels and 11% over fourth quarter 2008 levels, primarily due to increased
production from our tertiary operations and the Barnett Shale, and due to the acquisition of
Hastings field in February, 2009. The increase in tertiary operations is discussed above under
Results of Operations CO2 Operations.
Our Texas Barnett Shale production increased 2,131 BOE/d (17%) from the prior years first
quarter level and increased 2,699 BOE/d (22%) over the fourth quarter of 2008 production level,
primarily due to additional sales of natural gas liquids that were produced during the third and
fourth quarters of 2008, but not sold until the first quarter of 2009 due to plant shutdowns caused
by Hurricane Ike. Generally, throughout 2008 and continuing into the first quarter of 2009, our
production in the Barnett area has been relatively flat, with minor changes up or down each
quarter. As a result of our curtailed drilling there in 2009, we expect our Barnett Shale
production to gradually decrease throughout the remainder of 2009. Hastings Field, acquired in
early February 2009, contributed 1,562 BOE/d to our Texas production during the first quarter 2009.
Production from our Mississippi-non-CO2 floods is approximately the same as in the prior
years first quarter as this area is on a gradual decline due to normal depletion; however, our
drilling activity in the Sharon Field (natural gas) in the latter part of 2008 has helped offset
the gradual declines in oil production.
Oil and Natural Gas Revenues: Due to the extreme volatility in oil and natural gas prices, our
oil and natural gas revenues dropped sharply in the first quarter of 2009 as compared to these
revenues in the first quarter of 2008, offset in part by a steady increase in production, as seen
in the following table:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
Amounts in thousands |
|
2009 vs. 2008 |
|
|
|
|
|
|
Percentage |
|
|
Increase |
|
Increase |
|
|
(Decrease) In |
|
(Decrease) In |
|
|
Revenues |
|
Revenues |
Change in revenues due to: |
|
|
|
|
|
|
|
|
Increase in production |
|
$ |
55,254 |
|
|
|
18 |
% |
Decrease in commodity prices |
|
|
(200,382 |
) |
|
|
(64 |
%) |
|
Total decrease in revenues |
|
$ |
(145,128 |
) |
|
|
(46 |
%) |
|
29
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Excluding any impact of our hedging activities, our net realized commodity prices and NYMEX
differentials were as follows during the first three months of 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
March 31, |
|
|
2009 |
|
2008 |
Net
Realized Prices: |
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
39.34 |
|
|
$ |
91.24 |
|
Natural gas price per Mcf |
|
|
4.09 |
|
|
|
7.80 |
|
Price per BOE |
|
|
34.97 |
|
|
|
76.65 |
|
|
|
|
|
|
|
|
|
|
NYMEX
Differentials: |
|
|
|
|
|
|
|
|
Oil per Bbl |
|
$ |
(3.99 |
) |
|
$ |
(6.50 |
) |
Natural Gas per Mcf |
|
|
(0.41 |
) |
|
|
(0.92 |
) |
Our Company-wide oil price NYMEX differential improved in the first quarter of 2009 as
compared to the 2008 period due primarily to the decrease in oil prices, and was generally
consistent with our oil price NYMEX differential of $3.59 per Bbl in the fourth quarter of 2008.
Our natural gas NYMEX differentials are generally caused by movement in the NYMEX natural gas
prices during a 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 in the above
table is 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 first three months of
2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2009 |
|
2008 |
|
|
Non-Cash |
|
|
|
|
|
Non-Cash |
|
|
|
|
Fair Value |
|
Cash |
|
Fair Value |
|
Cash |
|
|
Adjustment |
|
Settlements |
|
Adjustment |
|
Settlements |
|
|
Income/ |
|
Receipt/ |
|
Income/ |
|
Receipt/ |
Amounts in thousands |
|
(expense) |
|
(payment) |
|
(expense) |
|
(payment) |
|
|
|
|
|
Oil derivative contracts |
|
$ |
(95,861 |
) |
|
$ |
85,836 |
|
|
$ |
2,638 |
|
|
$ |
(7,392 |
) |
Natural gas derivative contracts |
|
|
(10,490 |
) |
|
|
|
|
|
|
(41,371 |
) |
|
|
(656 |
) |
|
|
|
|
|
Total |
|
$ |
(106,351 |
) |
|
$ |
85,836 |
|
|
$ |
(38,733 |
) |
|
$ |
(8,048 |
) |
|
|
|
|
|
The change in commodity prices and the expiration of contracts cause fluctuations in the
mark-to-market 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 first quarter of 2009, we
recognized total non-cash fair value expense of $106.4 million. Of this amount, $77.0 million
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 first quarter of 2009 was made up of $18.9 million of charges on the oil derivative
contracts we entered into in March 2009, and $10.5 million on our new natural gas swaps. (See Note
6 to the Unaudited Condensed Consolidated Financial Statements for a summary of our oil and natural
gas derivative contracts.) During the first quarter of 2008, we recognized non-cash fair
value income of $2.6 million on our oil derivative contracts and non-cash fair value expense of
$41.4 million on our natural gas derivative contracts.
During the first quarter of 2009, we received cash settlements of $85.8 million on our oil
derivative contracts. During the first quarter of 2008, we made cash payments of $7.4 million on
our oil derivative contracts and $0.7 million on our natural gas derivative contracts, giving us a
total change between the two periods of $93.9 million.
30
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Production Expenses: Our lease operating expenses increased between the comparable first
quarters on a gross basis as a result of (i) our increasing emphasis on tertiary operations (see
discussion of those expenses under CO2 Operations above), (ii) increased personnel and
related costs, (iii) higher electrical costs to operate our properties and (iv) increasing lease
payments for certain equipment in our tertiary operating facilities. Our lease operating expenses
decreased on a per BOE basis between the comparable first quarters due in part to a 19% increase in
production year-over-year and in part to 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
with levels of available cash flow, 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 over
time. During the first quarter of 2009, Company-wide lease operating costs averaged $15.59 per
BOE, down from $16.15 per BOE during the first quarter of 2008 and down from $17.90 per BOE in the
fourth quarter of 2008.
Production taxes and marketing expenses generally change in proportion to changes in commodity
prices and production volumes, and therefore were lower in the first quarter of 2009 than in the
comparable quarter of 2008. Transportation and plant processing fees increased approximately $0.9
million in the first quarter of 2009 as compared to those expenses in the first quarter of 2008,
largely associated with incremental production and incremental plant processing fees related to our
Barnett Shale production.
General and Administrative Expenses
General and administrative (G&A) expenses increased 42% between the respective first
quarters as set forth below:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
Net G&A expense (thousands) |
|
2009 |
|
|
2008 |
|
Gross cash G&A expense |
|
$ |
35,367 |
|
|
$ |
29,668 |
|
Gross stock-based compensation |
|
|
6,140 |
|
|
|
4,497 |
|
Incentive compensation for Genesis management |
|
|
2,593 |
|
|
|
|
|
State franchise taxes |
|
|
1,115 |
|
|
|
828 |
|
Operator labor and overhead recovery charges |
|
|
(18,986 |
) |
|
|
(15,953 |
) |
Capitalized exploration and development costs |
|
|
(3,574 |
) |
|
|
(3,035 |
) |
|
|
|
|
|
|
|
Net G&A expense |
|
$ |
22,655 |
|
|
$ |
16,005 |
|
|
|
|
|
|
|
|
G&A per BOE: |
|
|
|
|
|
|
|
|
Net cash
G&A expense |
|
$ |
2.86 |
|
|
$ |
2.86 |
|
Net
stock-based compensation |
|
|
1.08 |
|
|
|
0.86 |
|
Incentive
compensation for Genesis management |
|
|
0.54 |
|
|
|
|
|
State
franchise tax |
|
|
0.23 |
|
|
|
0.20 |
|
|
|
|
|
|
|
|
Net G&A
expense |
|
$ |
4.71 |
|
|
$ |
3.92 |
|
|
|
|
|
|
|
|
Employees as
of March 31 |
|
|
817 |
|
|
|
701 |
|
Gross
cash G&A expenses increased $5.7 million, or 19%, between the first quarters of 2008 and
2009. Approximately $4.6 million of the increase in gross cash G&A expenses is related to increases in
compensation and personnel related costs, due primarily to the increase in the number of employees
and salary increases, which we consider necessary in order to remain competitive in our industry.
During 2008, we increased our employee count by 16% and we further increased our employee count by
approximately 3% during the first quarter of 2009 due in part to our Hastings Field acquisition.
Stock compensation expense was approximately $6.1 million for the
first quarter of 2009 and $4.5 million for the first quarter of 2008.
Also adding to the year-over-year increase in net G&A expense was a $2.6 million charge
relating to incentive compensation awards for the management of Genesis. 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. Based on current estimates of fair value under the provisions of SFAS 123(R), we would anticipate accruing up to $10.4 million for
these awards in 2009. 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
31
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Transactions Genesis to the Unaudited Condensed Consolidated Financial
Statements for further information regarding these incentive compensation awards.
These increases in G&A were offset in part by an increase in operator labor and overhead
recovery charges in the first quarter of 2009. Our well operating agreements allow us, as
operator, to charge labor to a well and to charge a specified overhead rate during the drilling
phase and also to charge a monthly fixed overhead rate for each producing well. As a result of
additional operated wells from acquisitions, additional tertiary operations, drilling activity
during the past year and increased compensation expense, the amount we recovered as operator labor
and overhead charges increased by 19% between the first quarters of 2008 and 2009. Capitalized
exploration and development costs also increased by approximately 18% between the comparable
periods in 2008 and 2009, primarily due to additional personnel and increased compensation costs.
The net effect was a 42% increase in net G&A expense between the respective first quarters.
On a per BOE basis, net G&A expense increased 20% in the first quarter of 2009 as compared to levels of
those costs in the first quarter of 2008, as higher production offset a portion of the increase in
gross costs.
Interest and Financing Expenses
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
Amounts in thousands, except per BOE data |
|
2009 |
|
|
2008 |
|
Cash interest expense |
|
$ |
23,284 |
|
|
$ |
11,800 |
|
Non-cash interest expense |
|
|
1,286 |
|
|
|
407 |
|
Less: Capitalized interest |
|
|
(12,373 |
) |
|
|
(7,266 |
) |
|
|
|
|
|
|
|
Interest expense |
|
$ |
12,197 |
|
|
$ |
4,941 |
|
|
|
|
|
|
|
|
Interest and other income |
|
$ |
2,525 |
|
|
$ |
1,287 |
|
Average net cash interest expense per BOE (1) |
|
$ |
2.15 |
|
|
$ |
0.84 |
|
Average debt outstanding |
|
$ |
1,133,786 |
|
|
$ |
661,809 |
|
Average interest rate (2) |
|
|
8.2 |
% |
|
|
7.1 |
% |
|
|
|
|
|
|
|
|
|
|
(1) |
|
Cash interest expense less capitalized interest, less interest and other income on a BOE basis. |
|
(2) |
|
Includes commitment fees but excludes amortization of premium, discount and debt issue costs. |
Interest expense increased $7.3 million, or 147%, comparing the first quarters of 2008 and
2009. Interest expense has increased due to a higher average level of debt resulting from the
acquisition of Hastings in early February 2009 and other borrowings to fund our development
program, coupled with an increase in our average interest rate on our debt. Our average interest
rate increased as a result of the two pipeline dropdown transactions with Genesis, 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.
The increase in our interest expense attributable to higher debt and interest costs was
offset in part by a 70% increase in capitalized interest between the two periods. Our interest
capitalization continues to increase because of our growing balance of unevaluated property
expenditures, expenditures on our CO2 pipeline projects and higher interest rates.
32
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Depletion, Depreciation and Amortization (DD&A)
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
Amounts in thousands, except per BOE data |
|
2009 |
|
|
2008 |
|
Depletion and depreciation of oil and natural gas
properties |
|
$ |
53,451 |
|
|
$ |
44,190 |
|
Depletion and depreciation of CO2 assets |
|
|
4,542 |
|
|
|
3,022 |
|
Asset retirement obligations |
|
|
827 |
|
|
|
762 |
|
Depreciation of other fixed assets |
|
|
3,105 |
|
|
|
1,865 |
|
|
|
|
|
|
|
|
Total DD&A |
|
$ |
61,925 |
|
|
$ |
49,839 |
|
|
|
|
|
|
|
|
DD&A per BOE: |
|
|
|
|
|
|
|
|
Oil and natural gas properties |
|
$ |
11.29 |
|
|
$ |
11.00 |
|
CO2 assets and other fixed assets |
|
|
1.59 |
|
|
|
1.20 |
|
|
|
|
|
|
|
|
Total DD&A cost per BOE |
|
$ |
12.88 |
|
|
$ |
12.20 |
|
|
|
|
|
|
|
|
Our depletion, depreciation and amortization rate for oil and natural gas properties
on a per BOE basis decreased 5% from the fourth quarter 2008 DD&A rate of $11.92 per BOE, and
increased 3% between the respective first quarters. The decrease in our oil and natural gas DD&A
rate from the fourth quarter of 2008 is primarily due to the $226.0 million ($140.1 million net of
taxes) full cost pool ceiling test write-down recognized at the end of 2008. The increase in the
DD&A rate between the respective first quarters is due to increased production and capital
spending, offset in part by the year-end 2008 write-down and to the addition of approximately 88.9
MMBOE of proved reserves during 2008.
We adjust our DD&A rate each quarter for significant changes in our estimates of oil and
natural gas reserves and costs, and thus our DD&A rate could change significantly in the future.
We did not record any additional tertiary oil reserves during the first quarter 2009. Assuming
that we continue to see an increase in the level of tertiary production response at Cranfield Field
during the second quarter of 2009, we would expect to recognize proved reserves associated with our
CO2 flood at Cranfield Field during the second quarter of 2009.
Our DD&A rate for our CO2 and other fixed assets increased in the first quarter of
2009 as compared to the rate in the comparable quarter of 2008, primarily as a result of the Delta
(Jackson Dome to Tinsley) and Heidelberg CO2 pipelines being placed into service during
2008, and due to the expansion of our corporate office space, also during 2008. At March 31, 2009,
we had $553.3 million of costs related to CO2 pipelines under construction. These costs
were not being depreciated at March 31, 2009. Depreciation of these pipelines will commence as each pipeline is placed into service.
Under full cost accounting rules, we are required each quarter to perform a ceiling test
calculation. Although we did not have a write-down at March 31, 2009, we anticipate that if prices
remain at these lower levels in subsequent periods, we may be required to record additional
write-downs under the full cost pool ceiling test in the future. The amount of any future
write-down is difficult to predict, and will depend upon oil and natural gas prices at the end of
each period, the incremental proved reserves that may be added each period, and to additional
capital spent.
33
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
Amounts in thousands, except per BOE amounts and tax rates |
|
2009 |
|
|
2008 |
|
Current income tax expense |
|
$ |
173 |
|
|
$ |
21,236 |
|
Deferred income tax expense (benefit) |
|
|
(10,851 |
) |
|
|
21,651 |
|
|
|
|
|
|
|
|
Total income tax expense (benefit) |
|
$ |
(10,678 |
) |
|
$ |
42,887 |
|
|
|
|
|
|
|
|
Average income tax expense (benefit) per BOE |
|
$ |
(2.22 |
) |
|
$ |
10.50 |
|
Effective tax rate |
|
|
36.8 |
% |
|
|
37.0 |
% |
|
|
|
|
|
|
|
Our income tax provision was based on an estimated statutory rate of approximately 38% in both
periods. Our effective tax rate has generally been lower than our estimated statutory rate due to
the impact of certain items such as our domestic production activities deduction. In the first
quarters of both years, the current income tax expense represents our anticipated alternative
minimum cash taxes that we cannot offset with enhanced oil recovery credits. As of December 31,
2008, we had an estimated $44 million of enhanced oil recovery credits to carry forward that we can
utilize to reduce our current income taxes during 2009 or future years.
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 |
|
|
|
March 31, |
|
Per BOE data |
|
2009 |
|
|
2008 |
|
Oil and natural gas revenues |
|
$ |
34.97 |
|
|
$ |
76.65 |
|
Gain (loss) on settlements of derivative contracts |
|
|
17.85 |
|
|
|
(1.97 |
) |
Lease operating expenses |
|
|
(15.59 |
) |
|
|
(16.15 |
) |
Production taxes and marketing expenses |
|
|
(1.91 |
) |
|
|
(4.10 |
) |
|
|
|
|
|
|
|
Production netback |
|
|
35.32 |
|
|
|
54.43 |
|
Non-tertiary CO2 operating margin |
|
|
0.39 |
|
|
|
0.42 |
|
General and administrative expenses |
|
|
(4.71 |
) |
|
|
(3.92 |
) |
Net cash interest expense |
|
|
(2.15 |
) |
|
|
(0.84 |
) |
Current income taxes and other |
|
|
0.93 |
|
|
|
(4.39 |
) |
Changes in assets and liabilities relating to operations |
|
|
(6.35 |
) |
|
|
4.78 |
|
|
|
|
|
|
|
|
Cash flow from operations |
|
|
23.43 |
|
|
|
50.48 |
|
DD&A |
|
|
(12.88 |
) |
|
|
(12.20 |
) |
Deferred income taxes |
|
|
2.26 |
|
|
|
(5.30 |
) |
Non-cash commodity derivative adjustments |
|
|
(22.13 |
) |
|
|
(9.48 |
) |
Changes in assets and liabilities and other non-cash
items |
|
|
5.51 |
|
|
|
(5.63 |
) |
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(3.81 |
) |
|
$ |
17.87 |
|
|
|
|
|
|
|
|
34
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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 $90
million of bank debt outstanding as of March 31, 2009, and $140 million outstanding as of May 8,
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 March 31, 2009, for estimated nonperformance risk in
accordance with SFAS No. 157. This estimated nonperformance risk
totaled approximately $10.6 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 March 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Maturity Dates |
|
Carrying |
|
Fair |
Amounts in thousands |
|
2011 |
|
2013 |
|
2015 |
|
2016 |
|
Value |
|
Value |
Variable rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank debt (weighted average interest rate of 1.77% at
March 31, 2009) |
|
$ |
90,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
90,000 |
|
|
$ |
79,436 |
|
Fixed rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.5% subordinated debt due 2013 (fixed rate of 7.5%) |
|
|
|
|
|
|
225,000 |
|
|
|
|
|
|
|
|
|
|
|
224,223 |
|
|
|
203,625 |
|
7.5% subordinated debt due 2015 (fixed rate of 7.5%) |
|
|
|
|
|
|
|
|
|
|
300,000 |
|
|
|
|
|
|
|
300,578 |
|
|
|
261,000 |
|
9.75% subordinated debt due 2016 (fixed rate of
9.75%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
420,000 |
|
|
|
390,363 |
|
|
|
405,300 |
|
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.
As a result of the current economic conditions and in order to protect our liquidity in the
event that commodity prices continue to decline, during early October 2008, we purchased oil
derivative contracts for 2009 with a floor price of $75 per Bbl and a ceiling price of $115 per Bbl
for total consideration of $15.5 million. The collars cover 30,000 Bbls/d representing
approximately 80% of our currently anticipated 2009 oil production. During March 2009, we entered
into additional commodity derivative contracts to further protect our liquidity. The new commodity
derivative contracts include crude oil swaps covering 25,000 Bbls/d during the first quarter of
2010 at a weighted average price of $51.85 per barrel, crude oil collars covering 25,000 Bbls/d
during the second quarter of 2010 with a floor price of $50.00 per barrel and a weighted average
ceiling price of $74.60 per barrel, natural gas swaps for calendar year 2010 covering 55,000
MMBtu/d at a weighted average price of $5.66 per MMBtu and natural gas swaps for calendar year 2011
covering 40,000 MMBtu/d at a weighted average price of $6.21 per MMBtu.
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. We have included an estimate of
nonperformance risk in the fair value measurement of our oil derivative contracts as required by
SFAS No. 157. In assessing the nonperformance risk of the counterparties to these contracts, we
have measured the risk by using credit default swaps as we believe this data is the most responsive
to current market events. If a counter-party did not have credit default swaps associated with that
specific entity, we utilized industry credit default swaps to estimate
35
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
the fair value of this risk associated with that entity. At March 31, 2009, the fair value of our
oil and natural gas derivative contracts was reduced by $1.7 million for the estimated
nonperformance risk of our counterparties.
For accounting purposes, we do not apply hedge accounting for 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 March 31, 2009, our derivative contracts were recorded at their fair value, which was a net
asset of approximately $143.4 million, a decrease of $106.3 million from the $249.7 million fair
value asset recorded as of December 31, 2008. This change is primarily related to the expiration of
our oil derivative contracts during the first quarter of 2009, and to the oil and natural gas
futures prices as of March 31, 2009 in relation to the new commodity derivative contracts for 2010
and 2011.
Commodity Derivative Sensitivity Analysis
Based on NYMEX crude oil and natural gas futures prices as of March 31, 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:
|
|
|
|
|
|
|
|
|
|
|
Crude Oil |
|
Natural Gas |
|
|
Derivative |
|
Derivative |
|
|
Contracts |
|
Contracts |
|
|
Receipt/ |
|
Receipt/ |
In thousands |
|
(Payment) |
|
(Payment) |
|
Based on: |
|
|
|
|
|
|
|
|
NYMEX futures prices as of March 31, 2009 |
|
$ |
149,916 |
|
|
|
($12,086 |
) |
10% increase in prices |
|
|
91,359 |
|
|
|
(33,705 |
) |
10% decrease in prices |
|
|
208,455 |
|
|
|
9,546 |
|
|
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
SFAS No. 157, Fair Value Measurements 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 1 of 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, |
36
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
assessment of impairment of goodwill, and |
|
|
|
recorded value of derivative instruments. |
Acquisitions
Under the acquisition method of accounting for business combinations in SFAS No. 141(R), 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.
SFAS No. 141(R) 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. SFAS No. 157 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).
Further, SFAS No. 157 emphasizes that a fair value measurement should be 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.
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 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
Goodwill must be tested for impairment at least annually, 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,
37
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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, 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 or
its availability, 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 quarterly 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.
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
We maintain disclosure controls and procedures and 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. 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.
There have been no significant changes in internal controls over financial reporting during
the period covered by this Quarterly Report on Form 10-Q that have materially affected, or are
reasonably likely to materially affect, Denburys internal controls 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.
Item 1A. Risk Factors
Information with respect to risk factors has been incorporated by reference from Item 1.A. 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.
38
DENBURY RESOURCES INC.
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 |
|
Program |
January 1 through 31, 2009 |
|
|
40,091 |
|
|
$ |
12.23 |
|
|
|
|
|
|
|
|
|
February 1 through 28,
2009 |
|
|
468 |
|
|
|
13.75 |
|
|
|
|
|
|
|
|
|
March 1 through 31, 2009 |
|
|
317 |
|
|
|
14.81 |
|
|
|
|
|
|
|
|
|
Total |
|
|
40,876 |
|
|
|
12.27 |
|
|
|
|
|
|
|
|
|
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.
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:
|
|
|
|
|
|
|
10(a)*
|
|
Amendment to Sixth Amended and Restated Credit Agreement dated as of May 4, 2009. |
|
|
|
|
|
|
|
10(b)*
|
|
2009 form of restricted stock award to certain officers that cliff vests on March 31,
2012 pursuant to 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. |
|
|
|
|
|
|
|
10(c)*
|
|
2009 form of restricted stock award without change of control vesting to certain
officers that cliff vests on March 31, 2012 pursuant to 2004 Omnibus Stock and
Incentive Plan for Denbury Resources Inc. |
|
|
|
|
|
|
|
10(d)*
|
|
2009 form of performance share awards to certain officers pursuant to 2004 Omnibus
Stock and Incentive Plan for Denbury Resources Inc. |
|
|
|
|
|
|
|
10(e)*
|
|
2009 form of performance share awards without change of control vesting to certain
officers pursuant to 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. |
|
|
|
|
|
|
|
10(f)*
|
|
2009 form of stock appreciation rights to certain officers that cliff vests on March 31, 2012
pursuant to the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. |
|
|
|
|
|
|
|
10(g)*
|
|
2009 form of stock appreciation
rights without change of control vesting to certain officers pursuant
to the 2004 Omnibus Stock and Incentive Plan for Denbury Resources
Inc. |
|
|
|
|
|
|
|
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. |
39
DENBURY RESOURCES INC.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
|
|
|
|
|
DENBURY RESOURCES INC.
(Registrant)
|
|
|
By: |
/s/ Phil Rykhoek
|
|
|
|
Phil Rykhoek |
|
|
|
Sr. Vice President and Chief Financial Officer |
|
|
|
|
|
By: |
/s/ Mark C. Allen
|
|
|
|
Mark C. Allen |
|
|
|
Vice President and Chief Accounting Officer |
|
Date: May 11, 2009
40