FORM 10-Q
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 June 30, 2009
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o |
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Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
Commission file number 1-12935
DENBURY RESOURCES INC.
(Exact name of Registrant as specified in its charter)
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Delaware
(State or other jurisdictions of incorporation or
organization)
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20-0467835
(I.R.S. Employer
Identification No.) |
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5100 Tennyson Parkway
Suite 1200
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Plano, TX
(Address of principal executive offices) |
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75024 (Zip code) |
Registrants telephone number, including area code: (972) 673-2000
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such files).
Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
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Large accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
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Smaller reporting company o |
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(Do not check if a smaller reporting company) |
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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 July 31, 2009 |
Common Stock, $.001 par value |
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249,438,000 |
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except shares)
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June 30, |
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December 31, |
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2009 |
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2008 |
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Assets |
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Current assets |
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Cash and cash equivalents |
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$ |
59,959 |
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$ |
17,069 |
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Accrued production receivable |
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101,325 |
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67,805 |
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Trade and other receivables, net of allowance of $407 and $377 |
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60,798 |
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80,579 |
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Derivative assets |
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39,279 |
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249,746 |
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Total current assets |
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261,361 |
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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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3,484,536 |
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3,386,606 |
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Unevaluated |
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192,727 |
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235,403 |
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CO2 properties, equipment and pipelines |
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1,283,135 |
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899,542 |
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Other |
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77,760 |
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70,328 |
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Less accumulated depletion, depreciation and impairment |
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(1,711,412 |
) |
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(1,589,682 |
) |
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Net property and equipment |
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3,326,746 |
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3,002,197 |
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Deposits on property under option or contract |
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48,917 |
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Other assets |
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131,751 |
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123,361 |
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Goodwill |
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138,740 |
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Total assets |
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$ |
3,858,598 |
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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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$ |
195,904 |
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$ |
202,633 |
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Oil and gas production payable |
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76,259 |
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85,833 |
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Derivative liabilities |
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64,955 |
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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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24,825 |
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89,024 |
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Current maturities of long-term debt |
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4,586 |
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4,507 |
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Total current liabilities |
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370,599 |
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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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250,653 |
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251,047 |
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Long-term debt |
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969,451 |
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601,720 |
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Asset retirement obligations |
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46,289 |
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43,352 |
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Deferred revenue Genesis |
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17,959 |
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19,957 |
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Deferred tax liability |
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408,641 |
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433,210 |
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Derivative liabilities |
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21,372 |
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Other |
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18,699 |
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14,253 |
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Total long-term liabilities |
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1,733,064 |
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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, $.001 par value, 600,000,000 shares authorized;
249,597,135 and 248,005,874 shares issued at June 30,
2009 and
December 31, 2008, respectively |
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249 |
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248 |
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Paid-in capital in excess of par |
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724,968 |
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707,702 |
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Retained earnings |
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1,034,038 |
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1,139,575 |
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Accumulated other comprehensive loss |
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(592 |
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(627 |
) |
Treasury stock, at cost, 247,680 and 446,287 shares at June
30, 2009 and
December 31, 2008, respectively |
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(3,728 |
) |
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(6,830 |
) |
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Total stockholders equity |
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1,754,935 |
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1,840,068 |
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Total liabilities and stockholders equity |
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$ |
3,858,598 |
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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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Six Months Ended |
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June 30, |
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June 30, |
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2009 |
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2008 |
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2009 |
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2008 |
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Revenues and other income |
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Oil, natural gas and related product sales |
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$ |
211,552 |
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$ |
413,243 |
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$ |
379,621 |
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$ |
726,440 |
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CO2 sales and transportation fees |
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2,884 |
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3,383 |
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6,049 |
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6,234 |
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Interest income and other |
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2,956 |
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1,359 |
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5,481 |
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2,646 |
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Total revenues |
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217,392 |
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417,985 |
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391,151 |
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735,320 |
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Expenses |
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Lease operating expenses |
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83,658 |
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76,825 |
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158,608 |
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142,826 |
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Production taxes and marketing expenses |
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8,739 |
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18,688 |
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15,739 |
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33,874 |
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Transportation expense Genesis |
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2,045 |
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1,842 |
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4,237 |
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3,392 |
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CO2 operating expenses |
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1,095 |
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453 |
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2,395 |
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1,596 |
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General and administrative |
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33,135 |
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14,811 |
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55,790 |
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30,816 |
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Interest, net of amounts capitalized of
$15,454, $5,545, $27,827, and $12,811, respectively |
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14,904 |
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8,141 |
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27,101 |
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13,082 |
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Depletion, depreciation and amortization |
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61,695 |
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54,733 |
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|
123,620 |
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104,572 |
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Commodity derivative expense |
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152,789 |
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58,817 |
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173,304 |
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105,598 |
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Total expenses |
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358,060 |
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234,310 |
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560,794 |
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435,756 |
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Income (loss) before income taxes |
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(140,668 |
) |
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183,675 |
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(169,643 |
) |
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299,564 |
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Income tax provision (benefit) |
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Current income taxes |
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24,127 |
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|
10,844 |
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24,300 |
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|
32,080 |
|
Deferred income taxes |
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(77,555 |
) |
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|
58,778 |
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(88,406 |
) |
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|
80,429 |
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Net income (loss) |
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$ |
(87,240 |
) |
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$ |
114,053 |
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$ |
(105,537 |
) |
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$ |
187,055 |
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Net income (loss) per common share basic |
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$ |
(0.35 |
) |
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$ |
0.47 |
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$ |
(0.43 |
) |
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$ |
0.77 |
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Net income (loss) per common share diluted |
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$ |
(0.35 |
) |
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$ |
0.45 |
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$ |
(0.43 |
) |
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$ |
0.74 |
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Weighted average common shares outstanding |
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Basic |
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|
246,084 |
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|
243,623 |
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|
|
245,830 |
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|
243,189 |
|
Diluted |
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|
246,084 |
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|
|
252,401 |
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|
245,830 |
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|
252,603 |
|
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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Six Months Ended |
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June 30, |
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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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$ |
(105,537 |
) |
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$ |
187,055 |
|
Adjustments needed to reconcile to net cash flow provided by
operations: |
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Depletion, depreciation and amortization |
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|
123,620 |
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|
104,572 |
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Deferred income taxes |
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|
(88,406 |
) |
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|
80,429 |
|
Deferred revenue Genesis |
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|
(1,998 |
) |
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|
(2,182 |
) |
Stock-based compensation |
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|
16,566 |
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|
7,385 |
|
Non-cash fair value derivative adjustments |
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|
301,197 |
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|
69,003 |
|
Founders retirement compensation |
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|
6,350 |
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Other |
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(428 |
) |
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|
(396 |
) |
Changes in assets and liabilities related to operations: |
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Accrued production receivable |
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|
|
(33,520 |
) |
|
|
(44,359 |
) |
Trade and other receivables |
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|
|
18,897 |
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|
|
(46,879 |
) |
Other assets |
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|
|
(21 |
) |
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|
269 |
|
Accounts payable and accrued liabilities |
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|
33,026 |
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|
(10,442 |
) |
Oil and gas production payable |
|
|
|
(9,574 |
) |
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|
27,065 |
|
Other liabilities |
|
|
|
617 |
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|
(1,191 |
) |
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Net cash provided by operating activites |
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|
260,789 |
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|
370,329 |
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Cash flow used for investing activities: |
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Oil and natural gas capital expenditures |
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|
|
(215,978 |
) |
|
|
(303,654 |
) |
Acquisitions of oil and natural gas properties |
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|
|
(196,274 |
) |
|
|
(2,357 |
) |
Distributions from Genesis |
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|
5,115 |
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|
|
2,725 |
|
CO2 capital expenditures, including pipelines |
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|
|
(399,406 |
) |
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|
(110,198 |
) |
Net purchases of other assets |
|
|
|
(8,312 |
) |
|
|
(16,931 |
) |
Net proceeds from sales of oil and gas properties and
equipment |
|
|
|
240,087 |
|
|
|
49,029 |
|
Other |
|
|
|
(72 |
) |
|
|
(686 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Net cash used for investing activities |
|
|
|
(574,840 |
) |
|
|
(382,072 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from financing activities: |
|
|
|
|
|
|
|
|
|
Bank repayments |
|
|
|
(505,000 |
) |
|
|
(222,000 |
) |
Bank borrowings |
|
|
|
475,000 |
|
|
|
72,000 |
|
Income tax benefit from equity awards |
|
|
|
938 |
|
|
|
14,143 |
|
Pipeline financing Genesis |
|
|
|
171 |
|
|
|
225,248 |
|
Issuance of subordinated debt |
|
|
|
389,827 |
|
|
|
|
|
Issuance of common stock |
|
|
|
7,257 |
|
|
|
9,710 |
|
Costs of debt financing |
|
|
|
(10,080 |
) |
|
|
|
|
Other |
|
|
|
(1,172 |
) |
|
|
(456 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
|
356,941 |
|
|
|
98,645 |
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
Net increase in cash and cash equivalents |
|
|
|
42,890 |
|
|
|
86,902 |
|
|
|
|
|
|
|
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|
|
Cash and cash equivalents at beginning of period |
|
|
|
17,069 |
|
|
|
60,107 |
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
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|
Cash and cash equivalents at end of period |
|
|
$ |
59,959 |
|
|
$ |
147,009 |
|
|
|
|
|
|
|
|
|
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|
Supplemental disclosure of cash flow information: |
|
|
|
|
|
|
|
|
|
Cash paid for interest, net of amounts capitalized |
|
|
$ |
5,837 |
|
|
$ |
10,186 |
|
Cash paid (refunded) for income taxes |
|
|
|
(14,416 |
) |
|
|
58,629 |
|
Interest capitalized |
|
|
|
27,827 |
|
|
|
12,811 |
|
Decrease in accrual for capital expenditures |
|
|
|
(41,612 |
) |
|
|
(5,999 |
) |
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
5
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF
COMPREHENSIVE OPERATIONS
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Net income (loss) |
|
$ |
(87,240 |
) |
|
$ |
114,053 |
|
|
$ |
(105,537 |
) |
|
$ |
187,055 |
|
Other comprehensive income, net of income tax: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in
fair value of interest rate lock derivative contracts designated as a
hedge, net of tax of $301 and $49, respectively |
|
|
|
|
|
|
492 |
|
|
|
|
|
|
|
12 |
|
Interest rate lock derivative contracts reclassified to
income,
net of taxes of $10, $551, $21 and $562, respectively |
|
|
17 |
|
|
|
900 |
|
|
|
35 |
|
|
|
918 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss) |
|
$ |
(87,223 |
) |
|
$ |
115,445 |
|
|
$ |
(105,502 |
) |
|
$ |
187,985 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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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 June 30, 2009, the consolidated results of its operations for the three and
six month periods ended June 30, 2009 and 2008 and cash flows
for the six months ended June 30, 2009 and 2008. Certain prior period items have been reclassified
to make the classification consistent with the classification in the most recent quarter. We have
evaluated events that occurred subsequent to June 30, 2009
through August 10, 2009, the financial
statement issuance date.
Net Income (Loss) Per Common Share
Basic net income (loss) per common share is computed by dividing net income by the weighted
average number of shares of common stock outstanding during the period. Diluted net income per
common share is calculated in the same manner but also considers the impact on net income and
common shares for the potential dilution from stock options, stock appreciation rights (SARs),
non-vested restricted stock and any other convertible securities outstanding. For the three and
six month periods ended June 30, 2009 and 2008, there were no adjustments to net income (loss) for
purposes of calculating diluted net income (loss) per common share. The following is a
reconciliation of the weighted average common shares used in the basic and diluted net income
(loss) per common share calculations for the three and six month periods ended June 30, 2009 and
2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
In thousands |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Weighted average common shares basic |
|
|
246,084 |
|
|
|
243,623 |
|
|
|
245,830 |
|
|
|
243,189 |
|
Potentially dilutive securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options and SARs |
|
|
|
|
|
|
7,389 |
|
|
|
|
|
|
|
8,043 |
|
Restricted stock |
|
|
|
|
|
|
1,389 |
|
|
|
|
|
|
|
1,371 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares -
diluted |
|
|
246,084 |
|
|
|
252,401 |
|
|
|
245,830 |
|
|
|
252,603 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The weighted average common shares basic amount excludes 2,928,022 shares at June 30, 2009
and 2,668,538 shares at June 30, 2008, of non-vested restricted stock that is subject to future
vesting over time. As these restricted shares vest, they will be included in the shares
outstanding used to calculate basic net income (loss) per common share (although all restricted
stock is issued and outstanding upon grant). For purposes of calculating weighted average common
shares diluted during the three and six months ended June 30, 2008, the non-vested restricted
stock is included in the computation using the treasury stock method, with the proceeds equal to
the average unrecognized compensation during the period, adjusted for any estimated future tax
consequences recognized directly in equity.
7
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
For the three and six months ended June 30, 2008, stock options and SARs to purchase
approximately 49,000 and 691,000 shares of common stock, respectively, were outstanding but
excluded from the diluted net income per common share calculations, as the exercise prices of the
options exceeded the average market price of the Companys common stock during these periods and
would be anti-dilutive to the calculations.
For the three and six months ended June 30, 2009, all outstanding stock options, SARs and
non-vested restricted stock were excluded from the calculation of weighted average
common shares - diluted as their impact would have been antidilutive to the net losses incurred
during those periods. During the three and six months ended June 30, 2009, 11.2 million and 11.1
million, respectively, of stock options and SARs were excluded from the calculation of weighted average common shares - diluted and for both 2009 periods, 2.8 million shares of non-vested restricted stock were excluded.
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 June 30, 2009 and December 31, 2008, we had $761.7 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 June 30, 2009 or
December 31, 2008. Depreciation will commence as each pipeline is placed into service. Each
pipeline is depreciated on a straight-line basis over its estimated useful life as determined for
GAAP purposes, which range between 20 to 30 years.
Goodwill
Goodwill represents the excess of the purchase price over the estimated fair value of the net
assets acquired in the acquisition of a business. Goodwill is not amortized, but rather it is
tested for impairment annually and also when events or changes in circumstances indicate that the
fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment
test requires allocating goodwill and other assets and liabilities to reporting units. In the case
of Denbury, we have only one reporting unit. The fair value of the reporting unit is determined
and compared to the book value of the reporting unit. If the fair value of the reporting unit is
less than the book value, including goodwill, the recorded goodwill is impaired to its implied fair
value with a charge to operating expense.
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, Acquisitions and Divestitures).
Equity Method Accounting. In November 2008, the FASB reached a consensus on Emerging Issues
Task Force (EITF) Issue 08-6, Equity Method Investment Accounting Considerations which was
issued to clarify how the application of equity method accounting will be affected by SFAS No.
141(R) and SFAS No. 160, Non-Controlling Interests in Consolidated Financial Statements an
amendment of ARB No. 51. 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 Opinion No. 18, The Equity Method of Accounting for Investments in
Common Stock. 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, applies prospectively and did not have any impact on our financial
position or results of operations.
Noncontrolling Interests. In December 2007, the FASB issued SFAS No. 160 which establishes
accounting and reporting standards for ownership interests in subsidiaries held by parties other
than the parent, the amount of consolidated net income attributable to the parent and to the
noncontrolling interest, changes in a parents ownership
8
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
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.
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, Accounting for Derivative Instruments and Hedging Activities,
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 Effective Date of FASB Statement No. 157, which delayed the effective date of SFAS
No. 157, Fair Value Measurements, 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.
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. The adoption of these FSPs enhanced our interim
financial statement disclosures but did not have any impact on our financial position or
results of operations.
Subsequent Events. In May 2009, the FASB issued SFAS No. 165, Subsequent Events to
establish accounting standards for events that occur after the balance sheet date but before
financial statements are issued or are available to be issued. SFAS No. 165 does not significantly
change current practice. The new standard does require companies to disclose the date through
which subsequent events were evaluated and whether or not that date was the date the financial
statements were issued or available for issuance. The Company adopted SFAS No. 165 upon issuance.
This standard did not have any impact on the Companys financial position or results of operations.
Recently Issued Accounting Pronouncements
Modernization of Oil and Gas Reporting. On December 31, 2008, the Securities and Exchange
Commission adopted major revisions to its rules governing oil and gas company reporting
requirements. These include provisions that permit the use of new technologies to determine proved
reserves, and 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 twelve-month period. The new oil and gas reporting requirements are effective
for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, with early
adoption not permitted. We are currently evaluating the impact the new rules may have on our
financial condition or results of operations.
9
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
FASB Accounting Standards CodificationTM. In June 2009, the FASB issued
SFAS No. 168, The FASB Accounting Standards CodificationTM and the Hierarchy of
Generally Accepted Accounting Principles, which becomes effective for financial statements issued
for interim and annual periods ending after September 15, 2009. SFAS No. 168 replaces SFAS No.
162, The Hierarchy of Generally Accepted Accounting Principles. The FASB Accounting Standards
Codification TM will become the source of U.S. GAAP recognized by the FASB for
nongovernmental entities. The Company will apply this standard to our financial statements issued
for the nine months ended September 30, 2009. This standard will not have any impact on the
Companys financial position or results of operations.
Transfers of Financial Assets. In June 2009, the FASB issued SFAS No. 166, Accounting for
Transfers of Financial Assets an amendment to FASB Statement No. 140. SFAS No. 166 removes the
concept of a qualifying special-purpose entity (QSPE) from FASB Statement No. 140, Accounting
for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities a replacement of
FASB Statement 125, creates a new unit of account definition that must be met for transfers of
portions of financial assets to be eligible for sale accounting, clarifies the derecognition
criteria for a transfer to be accounted for as a sale, changes the amount of recognized gains or
losses on the transfer of financial assets accounted for as a sale when beneficial interests are
received by the transferor and introduces new disclosure requirements. SFAS No. 166 is effective
for us beginning January 1, 2010. We do not anticipate the adoption of SFAS No. 166 will have a
material impact on our financial condition or results of operations.
Consolidation of Variable Interest Entities. In June 2009, the FASB issued SFAS No. 167,
Amendments to FASB Interpretation
No. 46(R). This standard eliminates the exemption in FASB
Interpretation No. 46(R) for QSPEs, introduces a new approach for determining who should
consolidate a variable interest entity and changes the requirement as to when it is necessary to
reassess who should consolidate a variable-interest entity. This standard is effective for us
beginning January 1, 2010. We are currently evaluating the impact the new rule may have on our
financial condition or results of operations.
Note 2. Acquisitions and Divestitures
Hastings Field Acquisition
During
November 2006, we entered into an agreement with a subsidiary of Venoco, Inc., that gave
us an option to purchase their interest in Hastings Field, a strategically significant potential
tertiary flood candidate located near Houston, Texas. We exercised the purchase option prior to
September 2008, and closed the acquisition during February 2009. As consideration for the option
agreement, during 2006 through 2008, we made cash payments totaling $50 million which we recorded
as a deposit. The purchase price of approximately $196 million, which was paid in cash, was
determined as of January 1, 2009 (the effective date) with closing on February 2, 2009. The 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 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.
10
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
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 or six month periods ended June 30, 2009 or 2008.
Sale of Barnett Shale Assets
In May 2009, we entered into an agreement to sell 60% of our Barnett Shale natural gas assets
to Talon Oil and Gas LLC, a privately held company, for $270 million (before closing adjustments).
In June 2009, we closed on approximately three-quarters of the sale with net proceeds (after
closing adjustments, but including the $10 million deposit) of $197.5 million. The agreement has
an effective date of June 1, 2009, and consequently operating net revenues after June 1, net of
capital expenditures, along with any other purchase price adjustments, were adjustments to the
selling price. We did not record a gain or loss on the sale in accordance with the full cost
method of accounting. The Company closed on the remaining portion of the sale on July 15, 2009
(see Note 9, Subsequent Event). We have not presented pro forma information for the disposal as
the pro forma effect was not material.
11
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 six
months ended June 30, 2009.
|
|
|
|
|
|
|
Six Months Ended |
|
In thousands |
|
June 30, 2009 |
|
Balance, beginning of period |
|
$ |
45,064 |
|
Liabilities incurred and assumed during period |
|
|
2,638 |
|
Revisions in estimated retirement obligations |
|
|
857 |
|
Liabilities settled during period |
|
|
(1,511 |
) |
Accretion expense |
|
|
1,637 |
|
Sales |
|
|
(838 |
) |
|
|
|
|
Balance, end of period |
|
$ |
47,847 |
|
|
|
|
|
At June 30, 2009, $1.6 million 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 six month period ended June 30, 2009 are primarily
related to the Hastings Field acquisition and sales during the period are primarily related to the
Barnett Shale natural gas assets (see Note 2, Acquisitions and Divestitures). We hold cash and
liquid investments in escrow accounts that are legally restricted for certain of our asset
retirement obligations. The balances of these escrow accounts were $7.4 million at both June 30,
2009 and December 31, 2008 and are included in Other assets in our Unaudited Condensed
Consolidated Balance Sheets.
12
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 4. Notes Payable and Long-Term Indebtedness
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
In thousands |
|
2009 |
|
|
2008 |
|
9.75% Senior Subordinated Notes due 2016 |
|
$ |
426,350 |
|
|
$ |
|
|
Discount on Senior Subordinated Notes due 2016 |
|
|
(28,566 |
) |
|
|
|
|
7.5% Senior Subordinated Notes due 2015 |
|
|
300,000 |
|
|
|
300,000 |
|
Premium on Senior Subordinated Notes due 2015 |
|
|
556 |
|
|
|
599 |
|
7.5% Senior Subordinated Notes due 2013 |
|
|
225,000 |
|
|
|
225,000 |
|
Discount on Senior Subordinated Notes due 2013 |
|
|
(728 |
) |
|
|
(826 |
) |
NEJD financing Genesis |
|
|
172,163 |
|
|
|
173,618 |
|
Free State financing Genesis |
|
|
78,260 |
|
|
|
76,634 |
|
Senior bank loan |
|
|
45,000 |
|
|
|
75,000 |
|
Capital lease obligations Genesis |
|
|
4,171 |
|
|
|
4,544 |
|
Capital lease obligations |
|
|
2,484 |
|
|
|
2,705 |
|
|
|
|
|
|
|
|
Total |
|
|
1,224,690 |
|
|
|
857,274 |
|
Less current obligations |
|
|
4,586 |
|
|
|
4,507 |
|
|
|
|
|
|
|
|
Long-term debt and capital lease obligations |
|
$ |
1,220,104 |
|
|
$ |
852,767 |
|
|
|
|
|
|
|
|
Issuance of 9.75% Senior Subordinated Notes due 2016
On February 13, 2009, we issued $420 million of 9.75% Senior Subordinated Notes due 2016
(2016 Notes). The 2016 Notes, which carry a coupon rate of 9.75%, were sold at a discount
(92.816% of par), which equates to an effective yield to maturity of approximately 11.25%. The net
proceeds of $381.4 million were used to repay most of our then-outstanding borrowings under our
bank credit facility, which increased from the December 31, 2008 balance, primarily associated with
the funding of the Hastings Field acquisition (see Note 2, Acquisitions and Divestitures). In
conjunction with this debt offering we amended our bank credit facility in early February 2009,
which, among other things, allowed us to issue these senior subordinated notes.
In June 2009, we issued an additional $6.35 million of the 2016 Notes to our founder, Gareth
Roberts, as part of a Founders Retirement Agreement. In connection with this issuance, we recorded
compensation expense of $6.35 million in General and administrative expense in our Unaudited
Condensed Consolidated Statement of Operations for the three and six months ended June 30, 2009.
The 2016 Notes mature on March 1, 2016, and interest on the 2016 Notes is payable March 1 and
September 1 of each year beginning on September 1, 2009. We may redeem the 2016 Notes in whole or
in part at our option beginning March 1, 2013, at the following redemption prices: 104.875% after
March 1, 2013, 102.4375% after March 1, 2014, and 100%, after March 1, 2015. In addition, we may at
our option, redeem up to an aggregate of 35% of the 2016 Notes before March 1, 2012 at a price of
109.75%. The indenture contains certain restrictions on our ability to incur additional debt, pay
dividends on our common stock, make investments, create liens on our assets, engage in transactions
with our affiliates, transfer or sell assets, consolidate or merge, or sell substantially all of
our assets. The 2016 Notes are not subject to any sinking fund requirements. All of our
significant subsidiaries fully and unconditionally guarantee this debt.
Senior Bank Loan
To clarify that Denbury entities are allowed to guarantee obligations of other Denbury
entities, in May 2009 we amended our Sixth Amended and Restated Credit Agreement,
the instrument governing our Senior Bank Loan, to explicitly permit these guarantees and waive any
possible previous technical violations of this provision.
13
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
In June 2009 we again amended our Senior Bank Loan agreement in connection with the sale of our Barnett Shale natural gas properties and (i) reduced our
borrowing base from $1.0 billion to $900 million and (ii)
allowed for an additional percentage of our forecasted production to
be hedged through June 30, 2009.
The amendment did not impact
the banks commitment amount, which remains at $750 million.
Note 5. Related Party Transactions Genesis
Interest in and Transactions with Genesis
Denburys subsidiary, Genesis Energy, LLC, is the general partner of, and together with
Denburys other subsidiaries, owns an aggregate 12% interest in Genesis Energy, L.P. (Genesis), a
publicly traded master limited partnership. Genesis business is focused on the mid-stream segment
of the oil and natural gas industry in the Gulf Coast area of the United States, and its activities
include gathering, marketing and transportation of crude oil and natural gas, refinery services,
wholesale marketing of CO2, and supply and logistic services.
We account for our 12% ownership in Genesis under the equity method of accounting as we have
significant influence over the limited partnership; however, our control is limited under the
limited partnership agreement and therefore we do not consolidate Genesis. Our investment in
Genesis is included in Other assets in our Unaudited Condensed Consolidated Balance Sheets.
Denbury received cash distributions from Genesis of $5.1 million and $2.8 million during the six
months ended June 30, 2009 and 2008, respectively. We also received $0.1 million during both the
six months ended June 30, 2009 and 2008 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 June 30, 2009, the balance of our equity investment in Genesis was $78.9 million. Based on
quoted market values of Genesis publicly traded limited partnership units at June 30, 2009, the
estimated market value of our publicly traded common units of Genesis was approximately $51.2
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 June 30,
2009 for impairment. Based upon this review, which considered 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, which agreements make them Class B Members in Genesis Energy, LLC. The compensation
agreements provide Genesis management with the ability to earn up to an approximate aggregate 17%
interest in the incentive distributions that Genesis Energy, LLC receives (commencing in 2009) from
Genesis. The percentage interest in the incentive distribution earned in any given period can vary
based upon the Cash Available Before Reserves (CABR) per unit as generated by Genesis (excluding
any transactions between Genesis and the Company) over each of the three individuals base amount of
CABR per unit as stated in their compensation agreement, subject to vesting and other
requirements. As the amount of CABR per unit increases, the members share of the incentive
distributions increases, up to a maximum aggregate 17% in any given period.
The amount payable under the award in the event of an employee termination is the present
value of the members share of forecasted incentive distributions assuming the then current level
of distributions continue into perpetuity. The award agreement dictates that the members share of
future incentive distributions be discounted back to the payment date using a discount rate equal
to the current distribution yield of market comparable general partners of master limited
partnerships.
The awards vest 25% on each anniversary grant date. The awards are mandatorily redeemable
upon termination of employment or change in control and require the membership interests of the
holders of the awards to be redeemed for cash (or in certain circumstances Genesis limited
partnership units) by Genesis Energy, LLC. Under the provisions of SFAS 123(R), Share-Based
Payment, the estimated fair value of these awards is measured each reporting period and recorded
as a liability to the extent vested. Changes in the liability are recorded as compensation expense
in General and administrative expenses in our Unaudited Condensed Consolidated Statement of
Operations. We use the graded
14
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
attribution method to recognize the share-based compensation expense
associated with these awards. As of June 30, 2009, we had approximately $5.3 million recorded as a
liability for these awards in our Unaudited Condensed Consolidated Balance Sheet. We recorded approximately $2.9 million in the three month period ended June 30, 2009 and $2.6 million
in the three month period ended March 31, 2009 in General and administrative expenses on our Unaudited Condensed Consolidated
Statement of Operations, of which $0.1 million in each three month period relates
to cash
payments made under these awards and $2.8 million and $2.5 million, respectively, are associated
with the fair value of the award.
The fair value of these awards is estimated using a discounted cash flow analysis which
includes assumptions regarding a number of variables, including Genesis managements estimates of future CABR
generated by Genesis, the distribution yield of market comparable publicly-traded general partners
of master limited partnerships and a discount rate which considers the risk of forecasted items
being realized, the time value of money and the risk of nonperformance by Denbury.
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 June 30, 2009, we have
recorded $172.2 million for the NEJD financing and $78.3 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. We expensed $2.0
million and $1.9 million, respectively, for these transportation services during the three months
ended June 30, 2009 and 2008, respectively, and $4.2 million and $3.4 million during the six months
ended June 30, 2009 and 2008, respectively.
Transportation Leases
We have pipeline transportation agreements with Genesis to transport our crude oil from
certain of our fields in Southwest Mississippi, and to transport CO2 from our main
CO2 pipeline to Brookhaven Field for our tertiary operations. We have accounted for
these agreements as capital leases. At June 30, 2009 and December 31, 2008, we had $4.2 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 June 30, 2009 and December 31, 2008, $22.0
million and $24.0 million, respectively, was recorded as deferred revenue, of which $4.1 million
was included in current liabilities at both June 30, 2009 and December 31, 2008. We recognized
deferred revenue of $1.0 million and $1.1 million for the three month periods ended June 30, 2009
and 2008, respectively, and $2.0 million and $2.2 million during the six month periods ended June
30, 2009 and 2008, respectively, for deliveries under these volumetric production payments. We
provide Genesis with certain processing and transportation services in connection with transporting
CO2 to their industrial customers for a fee of approximately $0.20 per Mcf of
CO2. For these services, we recognized revenues of $1.3 million and $1.4 million for
the three months ended June 30, 2009 and 2008, respectively, and $2.5 million and $2.6 million for
the six months ended June 30, 2009 and 2008, respectively.
15
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
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 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. In May 2009, we entered into crude oil collar contracts
covering 25,000 Bbls/d for the third quarter of 2010 with a weighted average floor price of $57.50
per Bbl and a weighted average ceiling price of $80.34 per Bbl. In conjunction with the sale of our
Barnett Shale assets (see Note 2, Acquisitions and Divestitures), we transferred a portion of our
2010 and 2011 natural gas derivative swap contracts to the purchaser, Talon Oil and Gas LLC. At
June 30, 2009, we retained natural gas derivative swap contracts covering 42,000 MMBtu/d for 2010
at an average price of $5.67 per MMBtu and 29,000 MMBtu/d for 2011 at a weighted average price of
$6.23 per MMBtu.
At June 30, 2009, our oil and natural gas derivative contracts were recorded at their fair
value, which was a net liability of $47.0 million. All of the mark-to-market valuations used for
our oil and natural gas derivatives are provided by external sources and are based on prices that
are actively quoted. We manage and control market and counterparty credit risk through established
internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit
risk exposure to counterparties through formal credit policies, monitoring procedures and
diversification. All of our derivative contracts are with parties that are lenders under our
Senior Bank Loan.
The following is a summary of Commodity derivative expense included in our Unaudited
Condensed Consolidated Statements of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
In thousands |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Receipt (payment) on settlements of derivative contracts oil |
|
$ |
42,002 |
|
|
$ |
(12,131 |
) |
|
$ |
127,838 |
|
|
$ |
(19,523 |
) |
Receipt (payment) on settlements of derivative contracts gas |
|
|
|
|
|
|
(16,463 |
) |
|
|
|
|
|
|
(17,119 |
) |
Fair value adjustments to derivative contracts expense |
|
|
(194,791 |
) |
|
|
(30,223 |
) |
|
|
(301,142 |
) |
|
|
(68,956 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative expense |
|
$ |
(152,789 |
) |
|
$ |
(58,817 |
) |
|
$ |
(173,304 |
) |
|
$ |
(105,598 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
16
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
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 |
|
June 30, |
|
December 31, |
Type of Contract and Period |
|
Bbls/d |
|
Swap Price |
|
Floor |
|
Ceiling |
|
2009 |
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
Collar Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 2009 - Dec. 2009 |
|
|
30,000 |
|
|
|
|
|
|
$ |
75.00 |
|
|
$ |
115.00 |
|
|
$ |
39,279 |
|
|
$ |
249,746 |
|
April 2010 - June 2010 |
|
|
5,000 |
|
|
|
|
|
|
|
50.00 |
|
|
|
76.00 |
|
|
|
(3,089 |
) |
|
|
|
|
April 2010 - June 2010 |
|
|
10,000 |
|
|
|
|
|
|
|
50.00 |
|
|
|
73.15 |
|
|
|
(7,416 |
) |
|
|
|
|
April 2010 - June 2010 |
|
|
5,000 |
|
|
|
|
|
|
|
50.00 |
|
|
|
76.40 |
|
|
|
(3,009 |
) |
|
|
|
|
April 2010 - June 2010 |
|
|
5,000 |
|
|
|
|
|
|
|
50.00 |
|
|
|
74.30 |
|
|
|
(3,447 |
) |
|
|
|
|
July 2010 - Sept. 2010 |
|
|
2,500 |
|
|
|
|
|
|
|
55.00 |
|
|
|
80.10 |
|
|
|
(1,145 |
) |
|
|
|
|
July 2010 - Sept. 2010 |
|
|
10,000 |
|
|
|
|
|
|
|
55.00 |
|
|
|
80.00 |
|
|
|
(4,616 |
) |
|
|
|
|
July 2010 - Sept. 2010 |
|
|
7,500 |
|
|
|
|
|
|
|
60.00 |
|
|
|
80.40 |
|
|
|
(2,588 |
) |
|
|
|
|
July 2010 - Sept. 2010 |
|
|
5,000 |
|
|
|
|
|
|
|
60.00 |
|
|
|
81.05 |
|
|
|
(1,613 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jan. 2010 - March 2010 |
|
|
6,667 |
|
|
$ |
52.50 |
|
|
|
|
|
|
|
|
|
|
|
(12,369 |
) |
|
|
|
|
Jan. 2010 - March 2010 |
|
|
3,333 |
|
|
|
52.20 |
|
|
|
|
|
|
|
|
|
|
|
(6,270 |
) |
|
|
|
|
Jan. 2010 - March 2010 |
|
|
5,000 |
|
|
|
52.10 |
|
|
|
|
|
|
|
|
|
|
|
(9,449 |
) |
|
|
|
|
Jan. 2010 - March 2010 |
|
|
5,000 |
|
|
|
50.90 |
|
|
|
|
|
|
|
|
|
|
|
(9,969 |
) |
|
|
|
|
Jan. 2010 - March 2010 |
|
|
5,000 |
|
|
|
51.45 |
|
|
|
|
|
|
|
|
|
|
|
(9,731 |
) |
|
|
|
|
Fair Value of Natural Gas Derivative Contracts Not Classified as Hedging Instruments under SFAS No. 133:
On
July 15, 2009, in conjunction with closing the second portion of
our sale of 60% of our Barnett
Shale natural gas assets (see Note 2, Acquisitions and Divestitures) we transferred 3,000 MMBtu/d
of our 2010 natural gas derivative swap contracts, and 2,000 MMBtu/d of our 2011 natural gas
derivative swap contracts, to the purchaser, Talon Oil and Gas LLC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value |
|
|
NYMEX Contract |
|
Asset (Liability) |
|
|
Prices Per MMBtu |
|
June 30, |
|
December 31, |
Type of Contract and Period |
|
MMBtu/d |
|
Swap Price |
|
2009 |
|
2008 |
|
|
|
|
|
|
|
|
|
|
(In thousands) |
Swap Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jan. 2010 - Dec. 2010 |
|
|
42,000 |
|
|
$ |
5.67 |
|
|
$ |
(5,514 |
) |
|
$ |
|
|
Jan. 2011 - Dec. 2011 |
|
|
10,000 |
|
|
|
6.27 |
|
|
|
(1,980 |
) |
|
|
|
|
Jan. 2011 - Dec. 2011 |
|
|
10,000 |
|
|
|
6.25 |
|
|
|
(2,027 |
) |
|
|
|
|
Jan. 2011 - Dec. 2011 |
|
|
9,000 |
|
|
|
6.16 |
|
|
|
(2,095 |
) |
|
|
|
|
17
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Additional Disclosures about Derivative Instruments:
At June 30, 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) |
|
|
|
|
|
June 30, |
|
|
December 31, |
|
Type of Contract |
|
Balance Sheet Location |
|
2009 |
|
|
2008 |
|
|
|
|
|
(In thousands) |
|
Derivatives not
designated as
hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Asset |
|
|
|
|
|
|
|
|
|
|
Crude Oil contracts |
|
Derivative assets - current |
|
$ |
39,279 |
|
|
$ |
249,746 |
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Liability |
|
|
|
|
|
|
|
|
|
|
Crude Oil contracts |
|
Derivative liability - current |
|
|
(64,750 |
) |
|
|
|
|
Natural Gas contracts |
|
Derivative liability - current |
|
|
(205 |
) |
|
|
|
|
Crude Oil contracts |
|
Derivative liability - long-term |
|
|
(9,962 |
) |
|
|
|
|
Natural Gas contracts |
|
Derivative liability - long-term |
|
|
(11,410 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives not
designated as hedging
instruments |
|
|
|
$ |
(47,048 |
) |
|
$ |
249,746 |
|
|
|
|
|
|
|
|
|
|
For the three and six months ended June 30, 2009 and 2008, the effect on income of derivative
financial instruments under SFAS No. 133 was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Gain / (Loss) |
|
|
Amount of Gain / (Loss) |
|
|
|
|
|
|
|
Recognized in Income For |
|
|
Recognized in Income For |
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
Location of Gain/(Loss) |
|
|
June 30, |
|
|
June 30, |
|
|
June 30, |
|
|
June 30, |
|
Type of Contract |
|
Recognized in Income |
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
(In thousands) |
|
Derivatives not
designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Contracts |
|
Commodity derivative expense |
|
$ |
(147,316 |
) |
|
$ |
(19,688 |
) |
|
$ |
(157,341 |
) |
|
$ |
(24,442 |
) |
Natural Gas Contracts |
|
Commodity derivative expense |
|
|
(5,473 |
) |
|
|
(39,129 |
) |
|
|
(15,963 |
) |
|
|
(81,156 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives not
designated as hedging
instruments |
|
|
|
|
|
$ |
(152,789 |
) |
|
$ |
(58,817 |
) |
|
$ |
(173,304 |
) |
|
$ |
(105,598 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 7. Fair Value Measurements
As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or
paid to transfer a liability in an orderly transaction between market participants at the
measurement date (exit price). We utilize market data or assumptions that market participants would
use in pricing the asset or liability, including assumptions about risk and the risks inherent in
the inputs to the valuation technique. These inputs can be readily observable, market corroborated,
or generally unobservable. We primarily apply the market approach for recurring fair value
measurements and endeavor to utilize the best available information. Accordingly, we utilize
valuation techniques that maximize the use of observable inputs and minimize the use of
unobservable inputs. We are able to classify fair value balances based on the observability of
those inputs. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to
measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active
markets for identical assets or liabilities (level 1 measurement) and the lowest priority to
unobservable inputs (level 3 measurement). The three levels of the fair value hierarchy defined by
SFAS No. 157 are as follows:
18
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Level 1 Quoted prices in active markets for identical assets or liabilities as of the
reporting date. During 2008 we had no level 1 recurring measurements.
Level 2 Pricing inputs are other than quoted prices in active markets included in level 1,
which are either directly or indirectly observable as of the reported date. Level 2 includes those
financial instruments that are valued using models or other valuation methodologies. These models
are primarily industry-standard models that consider various assumptions, including quoted forward
prices for commodities, time value, volatility factors, and current market and contractual prices
for the underlying instruments, as well as other relevant economic measures. Substantially all of
these assumptions are observable in the marketplace throughout the full term of the instrument, can
be derived from observable data or are supported by observable levels at which transactions are
executed in the marketplace.
Instruments in this category include non-exchange-traded oil and natural gas derivatives such
as over-the-counter swaps. We have included an estimate of nonperformance risk in the fair value
measurement of our oil and natural gas derivative contracts as required by SFAS No. 157. We have measured
nonperformance risk based upon credit default swaps or credit spreads. At both June 30, 2009 and December 31, 2008, the fair value of our oil and natural
gas derivative contracts was reduced by $3.7 million for estimated nonperformance risk.
Level 3 Pricing inputs include significant inputs that are generally less observable from
objective sources. These inputs may be used with internally developed methodologies that result in
managements best estimate of fair value.
The following table sets forth by level within the fair value hierarchy our financial assets
and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at June 30, 2009 Using: |
|
|
|
|
|
|
|
Significant |
|
|
|
|
|
|
|
|
|
Quoted Prices |
|
|
Other |
|
|
Significant |
|
|
|
|
|
|
in Active |
|
|
Observable |
|
|
Unobservable |
|
|
|
|
|
|
Markets |
|
|
Inputs |
|
|
Inputs |
|
|
|
|
In thousands |
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
|
Total |
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil derivative contracts |
|
$ |
|
|
|
$ |
39,279 |
|
|
$ |
|
|
|
$ |
39,279 |
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas derivative contracts |
|
|
|
|
|
|
(86,327 |
) |
|
|
|
|
|
|
(86,327 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
|
|
|
$ |
(47,048 |
) |
|
$ |
|
|
|
$ |
(47,048 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table sets forth the fair value of financial instruments that are not recorded
at fair value in our Unaudited Condensed Consolidated Financial Statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2009 |
|
December 31, 2008 |
|
|
Carrying |
|
Estimated |
|
Carrying |
|
Estimated |
In thousands |
|
Amount |
|
Fair Value |
|
Amount |
|
Fair Value |
9.75% Senior Subordinated Notes due 2016 |
|
$ |
397,784 |
|
|
$ |
438,075 |
|
|
$ |
|
|
|
$ |
|
|
7.5% Senior Subordinated Notes due 2015 |
|
|
300,556 |
|
|
|
285,000 |
|
|
|
300,599 |
|
|
|
213,000 |
|
7.5% Senior Subordinated Notes due 2013 |
|
|
224,272 |
|
|
|
214,875 |
|
|
|
224,174 |
|
|
|
171,000 |
|
Senior Bank Loan |
|
|
45,000 |
|
|
|
41,128 |
|
|
|
75,000 |
|
|
|
64,000 |
|
The fair values of our senior subordinated notes are based on quoted market prices. The
carrying value of our Senior Bank Loan is approximately fair value based on the fact that it is
subject to short-term floating interest rates that
19
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
approximate the rates available to us for those
periods. We adjusted the estimated fair value measurement of our Senior Bank Loan in accordance
with SFAS No. 157 for estimated nonperformance risk. This estimated nonperformance risk totaled
approximately $3.9 million and $11.0 million at June 30, 2009 and December 31, 2008, respectively,
and was determined utilizing industry credit default swaps. We have other financial instruments
consisting primarily of cash, cash equivalents, short-term receivables and payables that
approximate fair value due to the nature of the instrument and the relatively short maturities.
Note 8. Condensed Consolidating Financial Information
Our subordinated debt is fully and unconditionally guaranteed jointly and severally by all of
Denbury Resources Inc.s subsidiaries other than minor subsidiaries, except that with respect to
our $225 million of 7.5% Senior Subordinated Notes due 2013, Denbury Resources Inc. and Denbury
Onshore, LLC are co-obligors. Except as noted in the foregoing sentence, Denbury Resources Inc. is
the sole issuer and Denbury Onshore, LLC is a subsidiary guarantor. The results of our equity
interest in Genesis are reflected through the equity method by one of our subsidiaries, Denbury
Gathering & Marketing. Each subsidiary guarantor and the subsidiary co-obligor are 100% owned,
directly or indirectly, by Denbury Resources Inc. The following is condensed consolidating
financial information for Denbury Resources Inc., Denbury Onshore, LLC, and subsidiary guarantors:
20
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2009 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
In thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
453,561 |
|
|
$ |
256,901 |
|
|
$ |
17,236 |
|
|
$ |
(466,337 |
) |
|
$ |
261,361 |
|
Property and equipment |
|
|
|
|
|
|
3,215,096 |
|
|
|
111,650 |
|
|
|
|
|
|
|
3,326,746 |
|
Investment in subsidiaries (equity method) |
|
|
1,268,178 |
|
|
|
|
|
|
|
1,212,347 |
|
|
|
(2,480,525 |
) |
|
|
|
|
Other assets |
|
|
747,393 |
|
|
|
204,921 |
|
|
|
56,205 |
|
|
|
(738,028 |
) |
|
|
270,491 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
2,469,132 |
|
|
$ |
3,676,918 |
|
|
$ |
1,397,438 |
|
|
$ |
(3,684,890 |
) |
|
$ |
3,858,598 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
15,857 |
|
|
$ |
698,317 |
|
|
$ |
122,762 |
|
|
$ |
(466,337 |
) |
|
$ |
370,599 |
|
Long-term liabilities |
|
|
698,340 |
|
|
|
1,766,254 |
|
|
|
6,498 |
|
|
|
(738,028 |
) |
|
|
1,733,064 |
|
Stockholders equity |
|
|
1,754,935 |
|
|
|
1,212,347 |
|
|
|
1,268,178 |
|
|
|
(2,480,525 |
) |
|
|
1,754,935 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
2,469,132 |
|
|
$ |
3,676,918 |
|
|
$ |
1,397,438 |
|
|
$ |
(3,684,890 |
) |
|
$ |
3,858,598 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
In thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
458,051 |
|
|
$ |
408,940 |
|
|
$ |
14,992 |
|
|
$ |
(466,784 |
) |
|
$ |
415,199 |
|
Property and equipment |
|
|
|
|
|
|
2,973,947 |
|
|
|
28,250 |
|
|
|
|
|
|
|
3,002,197 |
|
Investment in subsidiaries (equity method) |
|
|
1,371,347 |
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2009 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
In thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Revenues |
|
$ |
15,862 |
|
|
$ |
215,538 |
|
|
$ |
1,854 |
|
|
$ |
(15,862 |
) |
|
$ |
217,392 |
|
Expenses |
|
|
17,380 |
|
|
|
354,224 |
|
|
|
2,318 |
|
|
|
(15,862 |
) |
|
|
358,060 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before the following: |
|
|
(1,518 |
) |
|
|
(138,686 |
) |
|
|
(464 |
) |
|
|
|
|
|
|
(140,668 |
) |
Equity in net earnings of subsidiaries |
|
|
(85,722 |
) |
|
|
|
|
|
|
(85,015 |
) |
|
|
170,737 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
(87,240 |
) |
|
|
(138,686 |
) |
|
|
(85,479 |
) |
|
|
170,737 |
|
|
|
(140,668 |
) |
Income tax provision (benefit) |
|
|
|
|
|
|
(53,671 |
) |
|
|
243 |
|
|
|
|
|
|
|
(53,428 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
(loss) |
|
$ |
(87,240 |
) |
|
$ |
(85,015 |
) |
|
$ |
(85,722 |
) |
|
$ |
170,737 |
|
|
$ |
(87,240 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2008 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
In thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Revenues |
|
$ |
5,625 |
|
|
$ |
417,218 |
|
|
$ |
767 |
|
|
$ |
(5,625 |
) |
|
$ |
417,985 |
|
Expenses |
|
|
5,746 |
|
|
|
233,361 |
|
|
|
828 |
|
|
|
(5,625 |
) |
|
|
234,310 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before the following: |
|
|
(121 |
) |
|
|
183,857 |
|
|
|
(61 |
) |
|
|
|
|
|
|
183,675 |
|
Equity in net earnings of subsidiaries |
|
|
114,171 |
|
|
|
|
|
|
|
114,449 |
|
|
|
(228,620 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
114,050 |
|
|
|
183,857 |
|
|
|
114,388 |
|
|
|
(228,620 |
) |
|
|
183,675 |
|
Income tax provision (benefit) |
|
|
(3 |
) |
|
|
69,408 |
|
|
|
217 |
|
|
|
|
|
|
|
69,622 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
114,053 |
|
|
$ |
114,449 |
|
|
$ |
114,171 |
|
|
$ |
(228,620 |
) |
|
$ |
114,053 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Statements of Operations (continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2009 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
In thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Revenues |
|
$ |
26,720 |
|
|
$ |
387,598 |
|
|
$ |
3,553 |
|
|
$ |
(26,720 |
) |
|
$ |
391,151 |
|
Expenses |
|
|
29,053 |
|
|
|
553,188 |
|
|
|
5,273 |
|
|
|
(26,720 |
) |
|
|
560,794 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before the following: |
|
|
(2,333 |
) |
|
|
(165,590 |
) |
|
|
(1,720 |
) |
|
|
|
|
|
|
(169,643 |
) |
Equity in net earnings of subsidiaries |
|
|
(103,204 |
) |
|
|
|
|
|
|
(101,345 |
) |
|
|
204,549 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
(105,537 |
) |
|
|
(165,590 |
) |
|
|
(103,065 |
) |
|
|
204,549 |
|
|
|
(169,643 |
) |
Income tax provision (benefit) |
|
|
|
|
|
|
(64,245 |
) |
|
|
139 |
|
|
|
|
|
|
|
(64,106 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
(loss) |
|
$ |
(105,537 |
) |
|
$ |
(101,345 |
) |
|
$ |
(103,204 |
) |
|
$ |
204,549 |
|
|
$ |
(105,537 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2008 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
In thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Revenues |
|
$ |
11,250 |
|
|
$ |
734,462 |
|
|
$ |
858 |
|
|
$ |
(11,250 |
) |
|
$ |
735,320 |
|
Expenses |
|
|
11,491 |
|
|
|
433,883 |
|
|
|
1,632 |
|
|
|
(11,250 |
) |
|
|
435,756 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before the following: |
|
|
(241 |
) |
|
|
300,579 |
|
|
|
(774 |
) |
|
|
|
|
|
|
299,564 |
|
Equity in net earnings of subsidiaries |
|
|
187,275 |
|
|
|
|
|
|
|
188,254 |
|
|
|
(375,529 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
187,034 |
|
|
|
300,579 |
|
|
|
187,480 |
|
|
|
(375,529 |
) |
|
|
299,564 |
|
Income tax provision (benefit) |
|
|
(21 |
) |
|
|
112,325 |
|
|
|
205 |
|
|
|
|
|
|
|
112,509 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
187,055 |
|
|
$ |
188,254 |
|
|
$ |
187,275 |
|
|
$ |
(375,529 |
) |
|
$ |
187,055 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Statements of Cash Flows
Denbury Resources Inc. (Parent) has no independent assets or operations. Denbury
Onshore, LLC is our operating subsidiary. Cash flow activity of Denbury Resources Inc. consists of
intercompany loans between Denbury Resources Inc. and Denbury Onshore, LLC to service the parent
company issued debt. This intercompany cash flow activity is eliminated in consolidation. Cash
flow activity of Denbury Onshore, LLC combined with the other guarantor subsidiaries is presented
in our Unaudited Condensed Consolidated Statements of Cash Flows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2009 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
In thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Cash flow from operations |
|
$ |
|
|
|
$ |
260,548 |
|
|
$ |
241 |
|
|
$ |
|
|
|
$ |
260,789 |
|
Cash flow from investing activities |
|
|
(388,391 |
) |
|
|
(574,840 |
) |
|
|
|
|
|
|
388,391 |
|
|
|
(574,840 |
) |
Cash flow from financing activities |
|
|
388,391 |
|
|
|
356,941 |
|
|
|
|
|
|
|
(388,391 |
) |
|
|
356,941 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash |
|
|
|
|
|
|
42,649 |
|
|
|
241 |
|
|
|
|
|
|
|
42,890 |
|
Cash, beginning of period |
|
|
24 |
|
|
|
16,898 |
|
|
|
147 |
|
|
|
|
|
|
|
17,069 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, end of period |
|
$ |
24 |
|
|
$ |
59,547 |
|
|
$ |
388 |
|
|
$ |
|
|
|
$ |
59,959 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2008 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
In thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Cash flow from operations |
|
$ |
(10 |
) |
|
$ |
370,325 |
|
|
$ |
14 |
|
|
$ |
|
|
|
$ |
370,329 |
|
Cash flow from investing activities |
|
|
(23,757 |
) |
|
|
(384,797 |
) |
|
|
2,725 |
|
|
|
23,757 |
|
|
|
(382,072 |
) |
Cash flow from financing activities |
|
|
23,757 |
|
|
|
98,645 |
|
|
|
|
|
|
|
(23,757 |
) |
|
|
98,645 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash |
|
|
(10 |
) |
|
|
84,173 |
|
|
|
2,739 |
|
|
|
|
|
|
|
86,902 |
|
Cash, beginning of period |
|
|
34 |
|
|
|
58,343 |
|
|
|
1,730 |
|
|
|
|
|
|
|
60,107 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, end of period |
|
$ |
24 |
|
|
$ |
142,516 |
|
|
$ |
4,469 |
|
|
$ |
|
|
|
$ |
147,009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 9. Subsequent Event
On July 15, 2009, we closed the remaining balance of the sale of 60% of our Barnett Shale
natural gas assets (see Note 2, Acquisitions and Divestitures). Net proceeds from the second
closing were approximately $62.3 million, bringing total net proceeds of the sale to approximately
$259.8 million (after closing adjustments and net of $8.1 million for natural gas swaps transferred
in the sale). We did not record any gain or loss on the sale in accordance with the full cost
method of accounting.
24
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
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 gas company engaged in acquisition, development and
exploration activities in the U.S. Gulf Coast region. We are the largest oil and natural gas
producer in Mississippi, own the largest carbon dioxide (CO2) reserves east of the
Mississippi River used for tertiary oil recovery, hold interests in the Barnett Shale play near
Fort Worth, Texas, and properties onshore in Louisiana, Alabama and Southeast Texas. Our goal is
to increase the value of acquired properties through a combination of exploitation, drilling, and
proven engineering extraction processes, with our most significant emphasis relating to tertiary
recovery. Our corporate headquarters are in Plano, Texas (a suburb of Dallas), and we have three
primary field offices located in Laurel, Mississippi; McComb, Mississippi; and Jackson,
Mississippi.
Second Quarter Operating Highlights. During the second quarter of 2009 we recorded a net loss
of $87.2 million, as compared to net income of $114.1 million in the second quarter of 2008.
Included in the 2009 second quarter loss was $194.8 million ($120.8 million after tax) expensed for
non-cash fair value adjustments related to our oil and natural gas derivative contracts and $10.0
million ($6.2 million after tax) expensed in conjunction with Gareth Roberts retirement as CEO of
the Company under a Founders Retirement Agreement. See further discussion regarding this
Founders Retirement Agreement under Recent Management Changes below.
For the second quarter of 2009 our oil and natural gas production averaged 52,269 BOE/d, a 13%
increase over second quarter 2008 production, and a 2% decrease from production levels in the first
quarter of 2009. The increase over the prior year second quarter period was primarily due to a 29%
increase in our tertiary oil production, which increased to 24,092 Bbls/d in the second quarter of
2009, and production from Hastings Field which we acquired in February 2009. During the second
quarter of 2009 we had our first production response from our CO2 flood at Heidelberg
Field, a little earlier than originally predicted, which averaged 250 Bbls/d for the quarter.
Although our average tertiary oil production increased 1,509 Bbls/d (7%) between the first and
second quarters of 2009, that increase was not enough to offset production decreases in our Barnett
Shale production and non-tertiary Mississippi production. Most of the decrease in our Barnett
Shale production between the first and second quarters of 2009 was associated with 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 decrease
in our nontertiary Mississippi production was primarily due to anticipated declines in our
Heidelberg and Sharon Field production. See Results of Operations CO2 Operations
and 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 over second quarter 2008
levels, our oil and natural gas revenues were 49% lower in the second quarter of 2009 than in the
prior year second quarter, as the average price we received for our production on a per BOE basis
was 55% lower in the current year period. Since over 70% of our production is oil, oil prices have
a much larger impact on our revenues than natural gas prices. NYMEX oil prices moved from $44.60
per barrel at December 31, 2008 to as low as $34.00 per barrel in mid-February 2009, up to $49.66
per barrel at March 31, 2009 and $69.89 per barrel at June 30, 2009. NYMEX natural gas prices have decreased
from year-end 2008, falling from $5.62 per Mcf at December 31, 2008 to $3.78 per Mcf at March 31,
2009 and $3.835 per Mcf at June 30, 2009.
Cash settlements received on our oil commodity derivative contracts, which are not included in
our oil and natural gas revenues, were $42.0 million in the second quarter of 2009, as compared to
cash payments made of $12.1 million on oil derivative contracts and $16.5 million in cash payments
on our natural gas commodity derivative contracts in the
25
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
second quarter of 2008. The non-cash fair
value adjustments associated with our derivative contracts resulted in a $194.8 million charge in
the second quarter of 2009 as compared to a $30.2 million charge in the prior year period, due
primarily to the increase in oil prices and expiration of contracts during the quarter.
Our second quarter lease operating expenses on a gross basis were approximately 9% higher than
in the second quarter of 2008 and approximately 12% higher than in the first quarter of 2009. On a
per BOE basis, our lease operating expenses were approximately 4% lower than in the second quarter
of 2008, as higher production levels offset the increase in lease operating expenses, but were
approximately 13% higher than in the first quarter of 2009 as we began expensing production costs
associated with two new tertiary floods in the second quarter of 2009 (Cranfield and Heidelberg
Fields). Although we have focused a great deal of effort on reducing lease operating expenses in
the first part of this year, the new tertiary floods, the acquisition of Hastings Field in early
February 2009 (which has a significantly higher operating cost per BOE than most of the Companys
other fields) and the recent increase in oil prices which results in higher CO2 costs,
negatively impacted our per BOE lease operating expenses during the quarter (see further discussion
below under Results of Operations Operating Results
Production Expenses).
Our general and administrative expenses were approximately $18.3 million higher than in the
second quarter of 2008, due primarily to higher employee costs, the expensing of $2.9 million
associated with our compensation arrangement for certain management of Genesis, and $10.0 million
expensed in connection with Mr. Gareth Roberts retirement as CEO and President of the Company
under a Founders Retirement Agreement (see further discussion below under Recent Management
Changes and Results of Operations General and
Administrative Expenses).
Interest expense also increased in the second quarter of 2009, primarily due to higher average
debt levels related to the Hastings Field acquisition in February 2009, and a higher average cost
of money (i.e. higher interest rates), partially offset by higher levels of capitalized interest
during the second quarter of 2009 as compared to the second quarter of 2008.
Sale of Barnett Shale Natural Gas Assets. In May 2009, we entered into an agreement to sell
60% of our Barnett Shale assets to Talon Oil and Gas LLC, a privately held company, for $270
million (before closing adjustments). On June 30, 2009, we closed on approximately three-quarters
of the sale with net proceeds (after closing adjustments) of $197.5 million. The agreement has an
effective date of June 1, 2009, and consequently operating net revenues after June 1, net of
capital expenditures, along with any other purchase price adjustments, were adjustments to the
selling price. We did not record a gain or loss on the sale in accordance with the full cost
method of accounting. We closed on the remaining portion of the sale on July 15, 2009. Our net
proceeds from this sale, after estimated taxes, are expected to be $235 million. We plan to use
the net proceeds from the sale to currently repay bank debt, but we plan to ultimately use the net
proceeds from this sale to increase our capital spending on our tertiary operations during 2010
above those levels that we would otherwise choose to spend.
Recent Management Changes. On June 30, 2009, under a management succession plan adopted by
our Board of Directors and announced on February 5, 2009, Gareth Roberts, the Companys founder,
relinquished his position as President and CEO and became Co-Chairman of the Board of Directors and
assumed a non-officer role as the Companys Chief Strategist. Phil Rykhoek, previously Senior Vice
President and Chief Financial Officer, became CEO; Tracy Evans, previously Senior Vice President
Reservoir Engineering, became President and Chief Operating Officer; and Mark Allen, previously
Vice President and Chief Accounting Officer, became Senior Vice President and Chief Financial
Officer.
In connection with Mr. Roberts retirement as CEO and President of the Company, Mr. Roberts
and the Company entered into a Founders Retirement Agreement (the Agreement). Under this
Agreement, Mr. Roberts received compensation of (i) $3.65 million in cash, plus (ii) the Company
issued him $6.35 million of the Companys 9.75% Senior Subordinated Notes due 2016. As part of the
Agreement, there are restrictions that prohibit Mr. Roberts from trading the Notes for two years,
and he has entered into a non-compete arrangement with the Company through 2013. Mr. Roberts will
continue to provide services to the Company as Co-Chairman of the
Board of Directors and in a
non-officer role as Chief Strategist.
Purchase of Hastings Field. On February 2, 2009, we closed the acquisition of Hastings Field
located near Houston, Texas for approximately $201 million in cash. Hastings Field is a
significant potential tertiary oil flood that we plan to flood with CO2 delivered from
Jackson Dome using our Green Pipeline, which is currently under construction. We originally
entered into an agreement in November 2006 with a subsidiary of Venoco, Inc., that gave us the
option to
26
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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, and 2,189 BOE/d during the
second quarter of 2009, all non-CO2 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.
Subordinated Debt Issuance. On February 13, 2009, we issued $420 million of 9.75% Senior
Subordinated Notes due 2016 (the Notes). The Notes were sold to the public at 92.816% of par,
plus accrued interest from February 13, 2009, which equates to an effective yield to maturity of
approximately 11.25% (before offering expenses). Interest on the Notes will be paid on March 1 and
September 1 of each year, beginning September 1, 2009. The Notes will mature on March 1, 2016. We
used the net proceeds from the offering of approximately $381.4 million to repay most of the then
outstanding debt on our bank credit facility. We issued an additional $6.35 million of Notes to
Mr. Roberts on June 30, 2009 (see Recent Management Changes above).
Capital Resources and Liquidity
In a continuing effort to mitigate the effects of the deterioration in the capital markets and
the steep decline in commodity prices which began during mid-2008, we have taken additional
measures during the first half of 2009 to improve our liquidity. In February 2009, we issued $420
million of 9.75% Senior Subordination Notes and in June and July 2009, we completed the sale of 60%
of our Barnett Shale assets. During the second quarter we also entered into additional commodity
derivative contracts for 2010 to protect our cash flow. We used the $381.4 million proceeds from
the February Notes issuance to repay the majority of our then-outstanding bank debt, and we plan to
do the same with the proceeds from our recent Barnett Shale sale, at least temporarily, freeing up
our credit line for future capital needs. Our new commodity derivative contracts include crude oil
collars covering 25,000 Bbls/d during the third quarter of 2010 with
a weighted average floor price of $57.50 per
barrel and a weighted average ceiling price of $80.34 per barrel.
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 $500 million to be spent on our CO2 pipelines, the majority of
which will be spent on the Green Pipeline. The budget also assumes that we fund approximately $100
million of budgeted equipment purchases with operating leases, which is dependent upon securing
acceptable financing. Through June 30, 2009, we have completed approximately $44 million of these
leases. If we do not enter into a total of $100 million of operating leases during 2009, our net
capital expenditures would increase accordingly, and we would anticipate funding those additional
capital expenditures under our bank credit line.
Our 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 futures prices as of the end
of July 2009, and including the expected cash settlements on our 2009 oil derivative contracts, we
anticipate that 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 expect this shortfall to be funded by the
$381.4 million of net proceeds from our February 2009 subordinated debt issuance and the estimated
$235 million of net proceeds from the sale of 60% of our Barnett Shale properties; however, we
ultimately expect to utilize the net proceeds from the Barnett Shale assets to increase our capital
expenditures in our tertiary operations during 2010.
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
27
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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. In
conjunction with the sale of our Barnett Shale properties the banks re-determined our bank
borrowing base and reduced it from $1.0 billion to $900 million, but the commitment amount was left
unchanged at $750 million. We anticipate this credit line will be sufficient for our 2009 plans,
and do not expect our bank credit line to be reduced by our banks unless commodity prices were to
decrease significantly from current levels. Based on current projections, we expect to have little
or no bank debt drawn at the end of 2009, leaving up to $750 million available on our bank line.
We currently do not anticipate raising any additional capital during 2009 unless needed for an
acquisition or to supplement previously budgeted equipment leasing if we are unable to find
suitable financing. 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 Operations Off-Balance Sheet Arrangements
Commitments and Obligations in our 2008 Form 10-K for further information regarding these
commitments).
Sources and Uses of Capital Resources
Capital Expenditure Summary
The
following table of capital expenditures includes accrued capital for
each period. Our cash expenditures were $41.6 million higher in the
2009 period and $6.0 million higher in the 2008 period than the
amounts listed below due to the decrease in our capital accruals in
those periods.
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
|
June 30, |
|
In thousands |
|
2009 |
|
|
2008 |
|
Oil and natural gas exploration and development: |
|
|
|
|
|
|
|
|
Drilling |
|
$ |
28,960 |
|
|
$ |
129,187 |
|
Geological, geophysical and acreage |
|
|
7,198 |
|
|
|
9,475 |
|
Facilities |
|
|
111,599 |
|
|
|
79,085 |
|
Recompletions |
|
|
35,591 |
|
|
|
71,539 |
|
Capitalized interest |
|
|
6,836 |
|
|
|
9,717 |
|
|
|
|
|
|
|
|
Total oil and natural gas exploration and development expenditures |
|
|
190,184 |
|
|
|
299,003 |
|
Oil and gas property acquisitions |
|
|
196,274 |
|
|
|
2,357 |
|
|
|
|
|
|
|
|
Total oil and natural gas capital expenditures |
|
|
386,458 |
|
|
|
301,360 |
|
CO2 capital
expenditures |
|
|
|
|
|
|
|
|
CO2 pipelines |
|
|
340,143 |
|
|
|
47,242 |
|
CO2 producing fields |
|
|
22,453 |
|
|
|
58,514 |
|
Capitalized interest |
|
|
20,991 |
|
|
|
3,094 |
|
|
|
|
|
|
|
|
Total CO2 capital expenditures |
|
|
383,587 |
|
|
|
108,850 |
|
|
|
|
|
|
|
|
Total |
|
$ |
770,045 |
|
|
$ |
410,210 |
|
|
|
|
|
|
|
|
Our first half 2009 capital expenditures were funded with $260.8 million of cash flow
from operations, $197.5 million of net proceeds from the sale of a portion of our Barnett Shale
natural gas assets and $381.4 million of proceeds from the February 2009 issuance of 9.75% Senior
Subordinated Notes. Our first half 2008 capital expenditures were
28
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
funded with $370.3 million of
cash flow from operations, $225 million from the drop-down of CO2 pipelines to Genesis
and $48.9 million from the proceeds from the second closing on our Louisiana property sale.
Off-Balance Sheet Arrangements
Commitments and Obligations
Our obligations that are not currently recorded on our balance sheet consist of our operating
leases and various obligations for development and exploratory expenditures arising from purchase
agreements, our capital expenditure program, or other transactions common to our industry. In
addition, in order to recover our proved undeveloped reserves, we must also fund the associated
future development costs as forecasted in the proved reserve reports. Our derivative contracts are
discussed in Note 6 to the Unaudited Condensed Consolidated Financial Statements.
On February 2, 2009, we closed our $201 million purchase of Hastings Field. Under the
agreement, we are required to make aggregate net cumulative capital expenditures in this field of
approximately $179 million over the next six years cumulating as follows: $26.8 million by December
31, 2010, $71.5 million by December 31, 2011, $107.2 million by December 31, 2012, $142.9 million
by December 31, 2013, and $178.7 million by December 31, 2014. If we fail to spend the required
amounts by the due dates, we are required to make a cash payment equal to 10% of the cumulative
shortfall at each applicable date. Further, we are committed to injecting at least an average of
50 MMcf/d of CO2 (total of purchased and recycled) in the West Hastings Unit for the 90
day period prior to January 1, 2013. If such injections do not occur, we must either (1)
relinquish our rights to initiate (or continue) tertiary operations and reassign to Venoco all
assets previously purchased for the value of such assets at that time based upon the discounted
value of the fields proved reserves using a 20% discount rate, or (2) make an additional payment
of $20 million in January 2013, less any payments made for failure to meet the capital spending
requirements as of December 31, 2012, and a $30 million payment for each subsequent year (less
amounts paid for capital expenditure shortfalls) until the CO2 injection rate in the
Hastings Field equals or exceeds the minimum required injection rate.
We
currently have long-term commitments to purchase
CO2
from eight proposed
gasification plants, four of which are in the Gulf Coast region and four in the Midwest region
(Illinois, Indiana and Kentucky). The Midwest plants are not only conditioned on the specific
plants being constructed, but also upon Denbury contracting additional volumes of CO2
for purchase in the general area of the proposed plants that would provide an acceptable economic
return on the CO2 pipeline that we would need to construct to transport these volumes to
our existing CO2 pipeline system. If all of these plants were to be built, these
CO2 sources are currently anticipated to provide us with aggregate CO2
volumes of 1.2 Bcf/d to 1.9 Bcf/d. Due to the current economic conditions, the earliest we would
expect any plant to be completed and providing CO2 would be 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 source (Jackson Dome) using current oil
prices. Prices for CO2 delivered from these projects are expected to be competitive
with the cost of our natural CO2 after adjusting for our share of potential carbon
emissions reduction credits using estimated futures prices of carbon emissions reduction credits.
If all eight plants are built, the aggregate purchase obligation for this CO2 would be
around $280 million per year, assuming a $70 per barrel oil price, before any potential savings
from our share of carbon emissions reduction credits. All of the contracts have price adjustments
that fluctuate based on the price of oil. Construction has not yet commenced on any of these
plants, and their construction is contingent on the satisfactory resolution of various issues,
including financing. While it is likely that not every plant currently under contract will be
constructed, there are several other plants under consideration that could provide CO2
to us that would either supplement or replace some of the
CO2
volumes from the eight
proposed plants for which we currently have
CO2
output purchase contracts. We are having ongoing discussions with
several of these other potential sources.
Neither the amounts nor the terms of any other commitments or contingent obligations have
changed significantly, from the year-end amounts reflected in our 2008 Form 10-K filed in March
2009 other than as discussed above, and other than our February 2009 subordinated debt issuance
discussed in Overview Subordinated Debt Issuance. Please refer to Managements Discussion and
Analysis of Financial Condition and Results of Operations Off-Balance Sheet Arrangements
Commitments and Obligations contained in our 2008 Form 10-K for further information regarding our
commitments and obligations.
29
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Results of Operations
CO2 Operations
Our focus on CO2 operations is becoming an ever-increasing part of our business and
operations. We believe that there are significant additional oil reserves and production that can
be obtained through the use of CO2, and we have outlined certain of this potential in
our 2008 annual report and other public disclosures. In addition to its long-term effect, our
focus on these types of operations impacts certain trends in our current and near-term operating
results. Please refer to Managements Discussion and Analysis of Financial Condition and Results
of Operations and the section entitled CO2 Operations contained in our 2008 Form 10-K
for further information regarding these matters.
During 2009 we have drilled one additional CO2 source well to further increase our
production capacity and reserves at Jackson Dome. While the preliminary results are encouraging,
we are not yet certain as to the magnitude of incremental reserves, if any. We estimate that we
are currently capable of producing between 900 MMcf/d and 1 Bcf/d of CO2. During the
second quarter of 2009 our CO2 production averaged 581 MMcf/d, as compared to an average
of approximately 596 MMcf/d during the second quarter of 2008, and 732 MMcf/d in the first quarter
of 2009. We used 87% of this production, or 499 MMcf/d, in our tertiary operations during the
second quarter of 2009, and sold the balance to our industrial customers or to Genesis pursuant to
our volumetric production payments.
We spent approximately $0.16 per Mcf to produce our CO2 during the first six months
of 2009, comprised of $0.14 per Mcf during the first quarter of 2009 and $0.18 per Mcf during the
second quarter of 2009. This rate is down significantly from $0.25 per Mcf during the first six
months of 2008, due primarily to decreased CO2 royalty expense as a result of lower oil
prices (upon which royalties are based) in the first half of 2009. Our estimated total cost per
thousand cubic feet of CO2 during the first half of 2009 was approximately $0.24, after
inclusion of depreciation and amortization expense, down from the 2008 first six months average of
$0.33 per Mcf. Our estimated total cost per thousand cubic feet of CO2 during the
second quarter of 2009 was approximately $0.26, after inclusion of depreciation and amortization
expense.
We recently announced that we have initiated a comprehensive feasibility study of a possible
long-term CO2 pipeline project which would connect proposed gasification plants in the
Midwest to the Companys existing CO2 pipeline infrastructure in Mississippi or
Louisiana. Two of the proposed plants are in the term sheet negotiation phase of a U.S. Department
of Energy Loan Guarantee Program (see Off-Balance Sheet Obligations Commitment and
Obligations) which would still require successful finalization of negotiations with the Department of Energy (DOE) to receive such guarantees. The Illinois Department of Commerce and Economic Opportunity has provided financial
assistance for the feasibility study for the Illinois portion of the pipeline. The feasibility
study is expected to determine the most likely pipeline route, the estimated costs of constructing
such a pipeline, and review regulatory, legal and permitting requirements. Our current preliminary
estimates suggest this would be a 500 to 700 mile pipeline system with a preliminary cost estimate
of approximately $1.0 billion, based on the cost of other pipelines recently built or under
construction by the Company. It is estimated that the study will be completed in the fourth
quarter of 2009, following which, we will evaluate external market conditions, the potential
financing opportunities and construction of the proposed gasification projects, and make a decision
as to whether or not we will take initial steps to build such a pipeline.
A third proposed gasification plant for
which Denbury has a CO2 output purchase contract,
was also selected by the loan guarantee program. The Company plans to commence a pipeline study
for this plant proposed to be built along the Gulf Coast of Mississippi, which would likely be a
110 mile pipeline that connects to the existing Free State Pipeline.
In addition to our natural source of CO2 and the proposed gasification plants
discussed above (see Off-Balance Sheet Arrangements Commitments and Obligations), we continue
to have ongoing discussions with owners of existing plants of various types that emit CO2
which we may be able to purchase. In order to capture such volumes, we (or the plant owner)
would need to install additional equipment, which includes at a minimum, compression and
dehydration facilities. Most of these existing plants emit relatively small volumes of
CO2, generally less than the proposed gasification plants, but such volumes
may still be attractive if the source is located near our Green Pipeline. The capture of CO2
could also be influenced by 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.
30
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
The following table summarizes our tertiary oil production and tertiary lease operating
expense per barrel for each quarter in 2008 and the first and second quarters of 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (BOE/d) |
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
First |
|
Second |
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
|
Quarter |
|
Quarter |
Tertiary Oil Field |
|
2008 |
|
2008 |
|
2008 |
|
2008 |
|
|
2009 |
|
2009 |
|
|
|
|
Phase I: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brookhaven |
|
|
2,638 |
|
|
|
2,714 |
|
|
|
2,772 |
|
|
|
3,178 |
|
|
|
|
3,451 |
|
|
|
3,466 |
|
Little Creek area |
|
|
1,807 |
|
|
|
1,661 |
|
|
|
1,556 |
|
|
|
1,706 |
|
|
|
|
1,619 |
|
|
|
1,560 |
|
Mallalieu area |
|
|
6,099 |
|
|
|
6,260 |
|
|
|
5,339 |
|
|
|
5,056 |
|
|
|
|
4,490 |
|
|
|
4,264 |
|
McComb area |
|
|
1,632 |
|
|
|
1,818 |
|
|
|
2,061 |
|
|
|
2,092 |
|
|
|
|
2,246 |
|
|
|
2,429 |
|
Lockhart Crossing |
|
|
|
|
|
|
|
|
|
|
182 |
|
|
|
555 |
|
|
|
|
607 |
|
|
|
698 |
|
Phase II: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eucutta |
|
|
2,699 |
|
|
|
2,933 |
|
|
|
3,262 |
|
|
|
3,538 |
|
|
|
|
3,813 |
|
|
|
4,145 |
|
Heidelberg |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
250 |
|
Martinville |
|
|
793 |
|
|
|
715 |
|
|
|
736 |
|
|
|
1,213 |
|
|
|
|
1,118 |
|
|
|
951 |
|
Soso |
|
|
1,488 |
|
|
|
1,885 |
|
|
|
2,358 |
|
|
|
2,704 |
|
|
|
|
2,705 |
|
|
|
2,589 |
|
Phase III: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tinsley |
|
|
|
|
|
|
675 |
|
|
|
1,518 |
|
|
|
1,832 |
|
|
|
|
2,390 |
|
|
|
3,402 |
|
Phase IV: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cranfield |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
144 |
|
|
|
338 |
|
|
|
|
|
Total tertiary oil production |
|
|
17,156 |
|
|
|
18,661 |
|
|
|
19,784 |
|
|
|
21,874 |
|
|
|
|
22,583 |
|
|
|
24,092 |
|
|
|
|
|
Tertiary operating expense per Bbl |
|
$ |
20.81 |
|
|
$ |
24.67 |
|
|
$ |
26.81 |
|
|
$ |
21.86 |
|
|
|
$ |
20.48 |
|
|
$ |
20.86 |
|
Oil production from our tertiary operations increased to an average of 24,092 Bbls/d in the
second quarter of 2009, a 29% increase over our second quarter 2008 tertiary production level of
18,661 Bbls/d and a 7% increase over our first quarter 2009 tertiary production level. These
increases are the result of the production growth in our more recent floods such as Tinsley,
Eucutta and Soso Fields, whose production has increased since the second quarter of 2008 as the
CO2 floods have been expanded and production response occurs across the fields. In
addition, we had our first production response from Cranfield Field during the first quarter of
2009 and our first response from Heidelberg Field in the second quarter of 2009, a little earlier
than anticipated. The recent decline at Mallalieu Field is partially due to CO2 recycle
volumes exceeding the plant capacity there. We are currenty expanding the capacity of the facility
and expect it to be operational late in the third quarter of 2009. Once the recycle capacity is
expanded we would expect production at Mallalieu Field to plateau.
Additionally, the recent decline at
Soso Field is largely due to water handling limitations that have recently been addressed and we
expect production at Soso Field to increase during the fourth quarter of 2009. We now anticipate
initiating CO2 injections at Delhi Field (Phase V) during the fourth quarter of 2009.
Although the Delhi pipeline is essentially complete, we are awaiting regulatory approvals before we
can commission the line. We currently anticipate initial tertiary production response at Delhi
Field around mid-year 2010.
During the second quarter of 2009, our operating costs for our tertiary properties averaged
$20.86 per Bbl, lower than the prior years second quarter average of $24.67 per Bbl, but slightly
higher than our first quarter 2009 average of $20.48 per Bbl. For the first six months of 2009,
our tertiary properties averaged $20.68 per Bbl as compared to $22.82 per Bbl in the prior year
period. While our costs have increased on a gross basis due to our new tertiary floods and ongoing
expansion of existing floods, they have decreased on a per Bbl basis from the second quarter and
first six months of 2008, primarily due to our increased production and to the reduced cost of
CO2 in the current year periods. On a per Bbl basis, our cost of CO2
decreased by $3.22 per BOE, from $6.90 per Bbl in the second quarter of 2008 to $3.68 in the second
quarter of 2009, primarily due to the reduction in oil prices to which our CO2 costs are
partially tied. In addition, our workover costs were lower in the second quarter of 2009 on a per
BOE basis than in the prior year period. The slight increase from the first quarter of 2009 on a
per BOE basis is primarily due to our new floods in Cranfield and Heidelberg, where we began
expensing production costs during the second quarter of 2009, and
higher equipment rental
costs due to new equipment leases. In addition, the cost of our
CO2 increased in the current quarter as a result
31
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
of higher oil prices as discussed above. For any specific field, we expect our tertiary lease
operating expense per BOE to be high initially, then decrease as production
increases, ultimately levelling off until production
begins to decline toward the latter life of the field, when lease
operating expense per BOE will again increase.
Operating Results
As summarized in the Overview section above and discussed in more detail below, our
operating results for the second quarter and first six months of 2009 were significantly lower as
compared to the same periods in the prior year, despite our significant production growth from the
prior year. The primary factors impacting our operating results were lower oil and natural gas
commodity prices in the current year periods, significant non-cash losses associated with fair
value changes in our oil and natural gas derivative contracts and generally higher costs, which are
explained in more detail below.
Certain of our operating results and statistics for the comparative second quarters and first
six months of 2009 and 2008 are included in the following table.
32
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
In thousands except per share and unit data |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Operating results |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(87,240 |
) |
|
$ |
114,053 |
|
|
$ |
(105,537 |
) |
|
$ |
187,055 |
|
Net income (loss) per common share basic |
|
|
(0.35 |
) |
|
|
0.47 |
|
|
|
(0.43 |
) |
|
|
0.77 |
|
Net income (loss) per common share diluted |
|
|
(0.35 |
) |
|
|
0.45 |
|
|
|
(0.43 |
) |
|
|
0.74 |
|
Cash flow from operations |
|
|
148,170 |
|
|
|
164,072 |
|
|
|
260,789 |
|
|
|
370,329 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production volumes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bbls/d |
|
|
37,921 |
|
|
|
31,332 |
|
|
|
37,781 |
|
|
|
30,748 |
|
Mcf/d |
|
|
86,088 |
|
|
|
89,835 |
|
|
|
90,327 |
|
|
|
89,127 |
|
BOE/d (1) |
|
|
52,269 |
|
|
|
46,305 |
|
|
|
52,836 |
|
|
|
45,602 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
188,170 |
|
|
$ |
326,962 |
|
|
$ |
321,435 |
|
|
$ |
577,403 |
|
Natural gas sales |
|
|
23,382 |
|
|
|
86,281 |
|
|
|
58,186 |
|
|
|
149,037 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas sales |
|
$ |
211,552 |
|
|
$ |
413,243 |
|
|
$ |
379,621 |
|
|
$ |
726,440 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas derivative contracts (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash receipt (payment) on settlement of derivative contracts |
|
$ |
42,002 |
|
|
$ |
(28,594 |
) |
|
$ |
127,838 |
|
|
$ |
(36,642 |
) |
Non-cash fair value adjustment expense |
|
|
(194,791 |
) |
|
|
(30,223 |
) |
|
|
(301,142 |
) |
|
|
(68,956 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expense from oil and natural gas derivative contracts |
|
$ |
(152,789 |
) |
|
$ |
(58,817 |
) |
|
$ |
(173,304 |
) |
|
$ |
(105,598 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
83,658 |
|
|
$ |
76,825 |
|
|
$ |
158,608 |
|
|
$ |
142,826 |
|
Production taxes and marketing expenses (3) |
|
|
10,784 |
|
|
|
20,530 |
|
|
|
19,976 |
|
|
|
37,266 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production expenses |
|
$ |
94,442 |
|
|
$ |
97,355 |
|
|
$ |
178,584 |
|
|
$ |
180,092 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-tertiary CO2 operating margin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2 sales and transportation fees (4) |
|
$ |
2,884 |
|
|
$ |
3,383 |
|
|
$ |
6,049 |
|
|
$ |
6,234 |
|
CO2 operating expenses |
|
|
(1,095 |
) |
|
|
(453 |
) |
|
|
(2,395 |
) |
|
|
(1,596 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-tertiary CO2 operating margin |
|
$ |
1,789 |
|
|
$ |
2,930 |
|
|
$ |
3,654 |
|
|
$ |
4,638 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit prices including impact of derivative settlements
(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
66.70 |
|
|
$ |
110.42 |
|
|
$ |
65.70 |
|
|
$ |
99.69 |
|
Gas price per Mcf |
|
|
2.98 |
|
|
|
8.54 |
|
|
|
3.56 |
|
|
|
8.13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit prices excluding impact of derivative settlements
(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
54.53 |
|
|
$ |
114.67 |
|
|
$ |
47.00 |
|
|
$ |
103.18 |
|
Gas price per Mcf |
|
|
2.98 |
|
|
|
10.55 |
|
|
|
3.56 |
|
|
|
9.19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas operating revenues and expenses per BOE (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenues |
|
$ |
44.48 |
|
|
$ |
98.07 |
|
|
$ |
39.70 |
|
|
$ |
87.53 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas lease operating expenses |
|
$ |
17.59 |
|
|
$ |
18.23 |
|
|
$ |
16.59 |
|
|
$ |
17.21 |
|
Oil and natural gas production taxes and marketing expense |
|
|
2.27 |
|
|
|
4.87 |
|
|
|
2.09 |
|
|
|
4.49 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas production expenses |
|
$ |
19.86 |
|
|
$ |
23.10 |
|
|
$ |
18.68 |
|
|
$ |
21.70 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 and $1.1 million, respectively, for the three
month periods ended June
30, 2009 and 2008, and $2.0 million and $2.2 million for the six month periods ended June 30,
2009 and 2008, respectively, associated with volumetric production payments with Genesis. Also
includes transportation income from Genesis of $1.3 million and $1.4 million for the three month
periods ended June 30, 2009 and 2008, respectively, and $2.5 million and $2.6 million for the six
months ended June 30, 2009 and 2008, respectively. |
33
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Production: Production by area for each of the quarters of 2008 and the first and second
quarters of 2009 is listed in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (BOE/d) |
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
First |
|
Second |
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
|
Quarter |
|
Quarter |
Operating Area |
|
2008 |
|
2008 |
|
2008 |
|
2008 |
|
|
2009 |
|
2009 |
Tertiary oil fields |
|
|
17,156 |
|
|
|
18,661 |
|
|
|
19,784 |
|
|
|
21,874 |
|
|
|
|
22,583 |
|
|
|
24,092 |
|
Mississippi
non-CO2 floods |
|
|
12,128 |
|
|
|
11,617 |
|
|
|
11,694 |
|
|
|
12,150 |
|
|
|
|
11,904 |
|
|
|
10,043 |
|
Texas |
|
|
13,522 |
|
|
|
14,068 |
|
|
|
12,701 |
|
|
|
12,576 |
|
|
|
|
17,063 |
|
|
|
16,088 |
|
Onshore Louisiana |
|
|
905 |
|
|
|
663 |
|
|
|
512 |
|
|
|
418 |
|
|
|
|
708 |
|
|
|
885 |
|
Alabama and other |
|
|
1,189 |
|
|
|
1,296 |
|
|
|
1,222 |
|
|
|
1,219 |
|
|
|
|
1,150 |
|
|
|
1,161 |
|
|
|
|
|
|
|
Total Company |
|
|
44,900 |
|
|
|
46,305 |
|
|
|
45,913 |
|
|
|
48,237 |
|
|
|
|
53,408 |
|
|
|
52,269 |
|
|
|
|
|
|
|
As
outlined in the above table, production in the second quarter of 2009 increased 13% over
second quarter 2008 production levels and 16% over production levels in the first six months of
2008. These increases were primarily due to production increases in our tertiary oil fields, our
Barnett Shale production and to the acquisition of Hastings Field in February 2009. In comparing
the sequential first and second quarters of 2009, our average tertiary oil production increased
1,509 Bbls/d (7%), but that increase was more than offset by production decreases in our Barnett
Shale production and non-tertiary Mississippi production. The increase in our tertiary operations
is discussed above under Results of Operations CO2 Operations.
Our Texas Barnett Shale production was 13,390 BOE/d during the second quarter of 2009. This
was essentially flat with second quarter 2008 production levels there, but 1,542 BOE/d less than
first quarter 2009 production levels. Most of the decrease in our Barnett Shale production between
the first and second quarters of 2009 was associated with 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. As a result of our curtailed
drilling program in the Barnett Shale during 2009, we anticipate that our Barnett Shale production
will continue to decrease throughout the year. As discussed previously, we have recently sold 60%
of our interests in the Barnett Shale so our production for the
remainder of 2009 will be reduced correspondingly. The acquisition of Hasting Field in February
2009 added 1,562 BOE/d during the first quarter of 2009 and 2,189 BOE/d during the second quarter
of 2009 to our Texas area production.
Production in the Mississippi-non-CO2 floods area has decreased from levels in the
second quarter and first six months of 2008, as well as from first quarter 2009 levels. Most of
this decrease is due to the expected gradual decline in Heidelberg Field due to depletion, and less
drilling activity developing natural gas in the Selma Chalk. Our drilling activity in Sharon Field
(natural gas) in the latter part of 2008 helped offset the declines in the first quarter of 2009,
but production there declined in the second quarter of 2009 as we have not drilled any additional
wells in this field this year.
Oil and Natural Gas Revenues: Due to the significant decrease in oil and natural gas prices
between the first half of 2008 and 2009, our oil and natural gas revenues dropped sharply in the
second quarter and first six months of 2009 as compared to these revenues in the same periods of
2008, offset in part by increases in production. These changes in revenues, excluding any impact
of our derivative contracts, are seen in the following table:
34
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
In thousands |
|
2009 vs. 2008 |
|
2009 vs. 2008 |
|
|
|
|
|
|
Percentage |
|
|
|
|
|
Percentage |
|
|
Increase |
|
Increase |
|
Increase |
|
Increase |
|
|
(Decrease) In |
|
(Decrease) In |
|
(Decrease) In |
|
(Decrease) In |
|
|
Revenues |
|
Revenues |
|
Revenues |
|
Revenues |
Change in revenues due to: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in production |
|
$ |
53,226 |
|
|
|
13 |
% |
|
$ |
110,596 |
|
|
|
15 |
% |
Decrease in commodity prices |
|
|
(254,917 |
) |
|
|
(62 |
%) |
|
|
(457,415 |
) |
|
|
(63 |
%) |
|
|
|
|
|
Total decrease in revenues |
|
$ |
(201,691 |
) |
|
|
(49 |
%) |
|
$ |
(346,819 |
) |
|
|
(48 |
%) |
|
|
|
|
|
Excluding any impact of our derivative contracts, our net realized commodity prices and
NYMEX differentials were as follows during the first and second quarters and first six month
periods of 2008 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Three Months Ended |
|
Six Months Ended |
|
|
March 31, |
|
June 30, |
|
June 30, |
|
|
2009 |
|
2008 |
|
% Change |
|
2009 |
|
2008 |
|
% Change |
|
2009 |
|
2008 |
|
% Change |
Net Realized Prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
39.34 |
|
|
$ |
91.24 |
|
|
|
(57 |
%) |
|
$ |
54.53 |
|
|
$ |
114.67 |
|
|
|
(52 |
%) |
|
$ |
47.00 |
|
|
$ |
103.18 |
|
|
|
(54 |
%) |
Gas price per Mcf |
|
|
4.09 |
|
|
|
7.80 |
|
|
|
(48 |
%) |
|
|
2.98 |
|
|
|
10.55 |
|
|
|
(72 |
%) |
|
|
3.56 |
|
|
|
9.19 |
|
|
|
(61 |
%) |
Price per BOE |
|
|
34.97 |
|
|
|
76.65 |
|
|
|
(54 |
%) |
|
|
44.48 |
|
|
|
98.07 |
|
|
|
(55 |
%) |
|
|
39.70 |
|
|
|
87.53 |
|
|
|
(55 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX Differentials: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil per Bbl |
|
$ |
(3.99 |
) |
|
$ |
(6.50 |
) |
|
|
(39 |
%) |
|
$ |
(5.30 |
) |
|
$ |
(9.64 |
) |
|
|
(45 |
%) |
|
$ |
(4.62 |
) |
|
$ |
(7.85 |
) |
|
|
(41 |
%) |
Natural Gas per Mcf |
|
|
(0.41 |
) |
|
|
(0.92 |
) |
|
|
(55 |
%) |
|
|
(0.82 |
) |
|
|
(0.92 |
) |
|
|
(11 |
%) |
|
|
(0.59 |
) |
|
|
(0.91 |
) |
|
|
(35 |
%) |
Our Company-wide oil price NYMEX differential improved in the second quarter and first
six months of 2009 over our differential in the comparable prior year periods, due primarily to the
decrease in oil prices. Our oil price NYMEX differential was slightly worse in the second quarter
of 2009, as compared to the previous quarter, due primarily to oil price increases.
Our natural gas NYMEX differentials are generally caused by movement in the NYMEX natural gas
prices during the month, as most of our natural gas is sold on an index price that is set near the
first of each month. While the percentage change in NYMEX natural gas differentials can be quite
large, these differentials are very seldom more than a dollar above or below NYMEX prices.
Oil and Natural Gas Derivative Contracts: The following tables summarize the impact that our
oil and natural gas derivative contracts had on our operating results for the three and six months
ended June 30, 2009 and 2008.
35
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Three Months Ended |
|
Six Months Ended |
|
|
March 31, |
|
June 30, |
|
June 30, |
|
|
2009 |
|
2009 |
|
2009 |
|
|
Non-Cash |
|
|
|
|
|
Non-Cash |
|
|
|
|
|
Non-Cash |
|
|
|
|
Fair Value |
|
Cash |
|
Fair Value |
|
Cash |
|
Fair Value |
|
Cash |
|
|
Adjustment |
|
Settlements |
|
Adjustment |
|
Settlements |
|
Adjustment |
|
Settlements |
|
|
Income/ |
|
Receipt/ |
|
Income/ |
|
Receipt/ |
|
Income/ |
|
Receipt/ |
In thousands |
|
(expense) |
|
(payment) |
|
(expense) |
|
(payment) |
|
(expense) |
|
(payment) |
|
|
|
|
|
|
|
Crude oil derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 contracts |
|
$ |
(77,014 |
) |
|
$ |
85,836 |
|
|
$ |
(133,453 |
) |
|
$ |
42,002 |
|
|
$ |
(210,467 |
) |
|
$ |
127,838 |
|
2010 contracts |
|
|
(18,847 |
) |
|
|
|
|
|
|
(55,865 |
) |
|
|
|
|
|
|
(74,712 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total crude oil derivative contracts |
|
$ |
(95,861 |
) |
|
$ |
85,836 |
|
|
$ |
(189,318 |
) |
|
$ |
42,002 |
|
|
$ |
(285,179 |
) |
|
$ |
127,838 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 contracts |
|
$ |
(4,750 |
) |
|
$ |
|
|
|
$ |
(2,551 |
) |
|
$ |
|
|
|
$ |
(7,301 |
) |
|
$ |
|
|
2011 contracts |
|
|
(5,740 |
) |
|
|
|
|
|
|
(2,922 |
) |
|
|
|
|
|
|
(8,662 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total natural gas derivative contracts |
|
$ |
(10,490 |
) |
|
$ |
|
|
|
$ |
(5,473 |
) |
|
$ |
|
|
|
$ |
(15,963 |
) |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative contracts |
|
$ |
(106,351 |
) |
|
$ |
85,836 |
|
|
$ |
(194,791 |
) |
|
$ |
42,002 |
|
|
$ |
(301,142 |
) |
|
$ |
127,838 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Three Months Ended |
|
Six Months Ended |
|
|
March 31, |
|
June 30, |
|
June 30, |
|
|
2008 |
|
2008 |
|
2008 |
|
|
Non-Cash |
|
|
|
|
|
Non-Cash |
|
|
|
|
|
Non-Cash |
|
|
|
|
Fair Value |
|
Cash |
|
Fair Value |
|
Cash |
|
Fair Value |
|
Cash |
|
|
Adjustment |
|
Settlements |
|
Adjustment |
|
Settlements |
|
Adjustment |
|
Settlements |
|
|
Income/ |
|
Receipt/ |
|
Income/ |
|
Receipt/ |
|
Income/ |
|
Receipt/ |
In thousands |
|
(expense) |
|
(payment) |
|
(expense) |
|
(payment) |
|
(expense) |
|
(payment) |
|
|
|
|
|
|
|
Crude oil derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 contracts |
|
$ |
2,638 |
|
|
$ |
(7,392 |
) |
|
$ |
(7,557 |
) |
|
$ |
(12,131 |
) |
|
$ |
(4,919 |
) |
|
$ |
(19,523 |
) |
|
|
|
|
|
|
|
Total crude oil derivative contracts |
|
$ |
2,638 |
|
|
$ |
(7,392 |
) |
|
$ |
(7,557 |
) |
|
$ |
(12,131 |
) |
|
$ |
(4,919 |
) |
|
$ |
(19,523 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 contracts |
|
$ |
(41,371 |
) |
|
$ |
(656 |
) |
|
$ |
(22,666 |
) |
|
$ |
(16,463 |
) |
|
$ |
(64,037 |
) |
|
$ |
(17,119 |
) |
|
|
|
|
|
|
|
Total natural gas derivative contracts |
|
$ |
(41,371 |
) |
|
$ |
(656 |
) |
|
$ |
(22,666 |
) |
|
$ |
(16,463 |
) |
|
$ |
(64,037 |
) |
|
$ |
(17,119 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative contracts |
|
$ |
(38,733 |
) |
|
$ |
(8,048 |
) |
|
$ |
(30,223 |
) |
|
$ |
(28,594 |
) |
|
$ |
(68,956 |
) |
|
$ |
(36,642 |
) |
|
|
|
|
|
|
|
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 second quarter of 2009, we
recognized total non-cash fair value expense of $194.8 million and for the first half of 2009, we
recognized total non-cash fair value expense of $301.1 million. Of these amounts, $133.5 million
in the second quarter and $210.5 million in the first six months of 2009 related to our 2009 oil
collars, partially reversing the $242.2 million gain we recognized on these collars during the
fourth quarter of 2008. The remaining non-cash fair value expense recognized during the second
quarter and first half of 2009 was made up of charges on the oil derivative contracts we entered
into during 2009 and on our 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 second
quarter and first half of 2008, we recognized non-cash fair value expense of $30.3 million and
$69.0 million, respectively, on our oil and natural gas derivative contracts.
36
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
During the second quarter and first half of 2009, we received cash settlements of $42.0
million and $127.8 million on our derivative contracts. During the second quarter and first half
of 2008, we made cash payments of $28.6 million and $36.6 million on our derivative contracts,
giving us a total change between the two six-month periods of $164.4 million.
Production Expenses: Our lease operating expenses increased between the comparable second
quarters and first six months of 2009 versus 2008 on a gross basis as a result of (i) our
increasing emphasis on tertiary operations and additional tertiary fields moving into the
productive phase (see discussion of those expenses under CO2 Operations above), (ii)
the acquisition of Hastings Field in February 2009, (iii) increased personnel and related costs,
(iv) higher electrical costs to operate our properties and (v) increasing lease payments for
certain equipment in our tertiary operating facilities, offset in part by lower CO2
costs due primarily to lower oil prices in the 2009 periods. Our lease operating expenses
decreased on a per BOE basis between the comparable second quarters and first six months of 2009
versus 2008 due in part to the 13% and 16% increases in production, respectively, 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, but with the recent drop in oil prices, we expect
that lower demand for certain goods and services will gradually cause prices for those items to
decrease or stabilize over time. During the second quarter of 2009, Company-wide lease operating
costs averaged $17.59 per BOE, up from $15.59 per BOE during the first quarter of 2009, primarily
due to the fact that our incremental growth in production quarter-over-quarter was primarily from
higher cost producing properties such as our tertiary operations and a full quarter of Hastings
Field production. On a proforma basis, after adjusting our second
quarter 2009 operating results to remove 60% of our Barnett Shale
production and lease operating expense, Company-wide lease operating
expense for the second quarter of 2009 would have been approximately
$19.90 per BOE.
Production taxes and marketing expenses generally change in proportion to commodity prices and
production volumes, and therefore were lower in the 2009 periods
compared to the 2008 periods, because the severe decrease in
commodity prices more than
offset our increase in
production. Transportation and plant processing fees were approximately $0.9 million lower in the
second quarter of 2009 than in the second quarter of 2008 and approximately the same in the
respective first halves of 2009 and 2008.
General and Administrative Expenses
General and administrative (G&A) expenses increased 124% between the respective second
quarters and 81% between the respective first six months of 2009 and 2008 as set forth below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
In thousands |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Gross cash G&A expense |
|
$ |
36,107 |
|
|
$ |
29,909 |
|
|
$ |
71,474 |
|
|
$ |
59,577 |
|
Employee stock-based compensation |
|
|
6,359 |
|
|
|
3,962 |
|
|
|
12,499 |
|
|
|
8,459 |
|
Founders compensation award |
|
|
10,000 |
|
|
|
|
|
|
|
10,000 |
|
|
|
|
|
Incentive compensation for Genesis management |
|
|
2,945 |
|
|
|
|
|
|
|
5,538 |
|
|
|
|
|
State franchise taxes |
|
|
1,124 |
|
|
|
857 |
|
|
|
2,239 |
|
|
|
1,685 |
|
Operator labor and overhead recovery charges |
|
|
(19,791 |
) |
|
|
(16,808 |
) |
|
|
(38,777 |
) |
|
|
(32,761 |
) |
Capitalized exploration and development costs |
|
|
(3,609 |
) |
|
|
(3,109 |
) |
|
|
(7,183 |
) |
|
|
(6,144 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net G&A expense |
|
$ |
33,135 |
|
|
$ |
14,811 |
|
|
$ |
55,790 |
|
|
$ |
30,816 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
G&A per BOE: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash G&A expense |
|
$ |
2.88 |
|
|
$ |
2.55 |
|
|
$ |
2.87 |
|
|
$ |
2.70 |
|
Net stock-based compensation |
|
|
1.13 |
|
|
|
0.76 |
|
|
|
1.10 |
|
|
|
0.81 |
|
Founders compensation award |
|
|
2.10 |
|
|
|
|
|
|
|
1.05 |
|
|
|
|
|
Incentive compensation for Genesis management |
|
|
0.62 |
|
|
|
|
|
|
|
0.58 |
|
|
|
|
|
State franchise tax |
|
|
0.24 |
|
|
|
0.20 |
|
|
|
0.23 |
|
|
|
0.20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net G&A expense |
|
$ |
6.97 |
|
|
$ |
3.51 |
|
|
$ |
5.83 |
|
|
$ |
3.71 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employees as of June 30 |
|
|
859 |
|
|
|
761 |
|
|
|
859 |
|
|
|
761 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross G&A expenses increased $6.2 million, or 21%, between the respective second quarters and
$11.9 million, or 20%, between the respective first six months. Approximately $5.1 million of the
increase in gross G&A expenses
37
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
between the respective quarters, and $9.7 million between the first
six month periods, related to increases in compensation and personnel related costs, due primarily
to the increase in employees and salary increases, which we consider necessary in order to remain
competitive in our industry. During 2008, we increased our employee count by 16% and we further
increased our employee count by approximately 8% during the first half of 2009. Stock compensation
expense increased to $6.4 million during the second quarter of 2009 from $4.0 million for the
second quarter of 2008, due primarily to the increase in employees and changes in the mix of
compensation awarded to employees. On a six month basis, stock compensation was approximately
$12.5 million for the first half of 2009 and $8.5 million for the first half of 2008. As discussed
above in Overview Recent Management Changes, we also expensed $10 million in the second quarter
of 2009 related to a Founders Retirement Agreement for Gareth Roberts as he retired as CEO and
President of the Company on June 30, 2009.
Also adding to the increase in net G&A expense for the 2009 periods was a charge relating to
incentive compensation awards for the management of Genesis of $2.9 million in the second quarter
of 2009 and $2.6 million in the first quarter of 2009. As incentive compensation for Genesis
management, our subsidiary which is the general partner of Genesis Energy, LP, awarded management
the right to earn an interest in the incentive distributions we receive. These awards are subject
to vesting over four years and achieving future levels of cash available before reserves on a per
unit basis, among other conditions. Based on current estimates of fair value under the provisions
of SFAS 123(R), we would anticipate accruing up to $10.7 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 Transactions -
Genesis to the Unaudited Condensed Consolidated Financial Statements for further information
regarding these incentive compensation awards.
The increase in gross G&A was offset in part by an increase in operator overhead recovery
charges in the second quarter and first six months of 2009. Our well operating agreements allow
us, when we are the operator, to charge a well with a specified overhead rate during the drilling
phase and also to charge a monthly fixed overhead rate for each producing well. As a result of
additional operated wells from acquisitions, additional tertiary operations, drilling activity
during the past year and increased compensation expense, the amount we recovered as operator
overhead charges increased by 18% between the second quarters of 2008 and 2009 and increased by 18%
between the first six months of 2008 and 2009. Capitalized exploration and development costs also
increased by 16% between the second quarters of 2008 and 2009 and increased by 17% between the
first six months of 2008 and 2009, primarily as a result of increases in personnel and compensation
costs.
The net effect was a 124% increase in net G&A expense between the respective second quarters
and an 81% increase between the first six months of 2009 and 2008. On a per BOE basis, G&A costs
also increased, although at a lower percentage rate as a result of higher production, increasing 99% in
the second quarter of 2009 as compared to levels in the second quarter of 2008, and 57% when comparing the
first six months of 2009 to the prior year period.
38
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Interest and Financing Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
In thousands, except per BOE data and interest rates |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Cash interest expense |
|
$ |
28,318 |
|
|
$ |
13,278 |
|
|
$ |
51,602 |
|
|
$ |
25,078 |
|
Non-cash interest expense |
|
|
2,040 |
|
|
|
408 |
|
|
|
3,326 |
|
|
|
815 |
|
Less: Capitalized interest |
|
|
(15,454 |
) |
|
|
(5,545 |
) |
|
|
(27,827 |
) |
|
|
(12,811 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
$ |
14,904 |
|
|
$ |
8,141 |
|
|
$ |
27,101 |
|
|
$ |
13,082 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest and other income |
|
$ |
2,956 |
|
|
$ |
1,359 |
|
|
$ |
5,481 |
|
|
$ |
2,646 |
|
Net cash interest expense and other income per BOE (1) |
|
$ |
2.52 |
|
|
$ |
1.79 |
|
|
$ |
2.33 |
|
|
$ |
1.34 |
|
Average debt outstanding |
|
$ |
1,363,007 |
|
|
$ |
698,475 |
|
|
$ |
1,249,030 |
|
|
$ |
680,142 |
|
Average interest rate (2) |
|
|
8.3 |
% |
|
|
7.6 |
% |
|
|
8.3 |
% |
|
|
7.4 |
% |
|
|
|
(1) |
|
Cash interest expense less capitalized interest less interest and other income
on BOE basis. |
|
(2) |
|
Includes commitment fees but excludes debt issue costs and amortization of
discount and premium. |
Interest expense increased $6.8 million, or 83%, comparing the second quarters of 2008
and 2009, and $14.0 million, or 107%, comparing levels in the first six months of 2008 and 2009,
primarily as a result of higher average debt levels resulting from the Hastings Field acquisition
in early February 2009 and incremental borrowings to fund our development program. In addition,
our average interest rate is higher in the current year periods than in the prior year periods as a
result of the two pipeline dropdown transactions with Genesis mid-2008, which were recorded as
financing leases and carry a higher imputed rate of interest, and the February 2009 issuance of
$420 million of 9.75% Senior Subordinated Notes. The increase in our interest expense attributable
to higher debt and interest costs was offset in part by an increase in capitalized interest in the
2009 periods, primarily due to capital expenditures on our CO2 pipeline projects
currently in progress and higher average interest rates
during the periods.
Depletion, Depreciation and Amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
In thousands, except per BOE data |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Depletion and depreciation of oil and natural
gas properties |
|
$ |
53,504 |
|
|
$ |
47,820 |
|
|
$ |
106,955 |
|
|
$ |
92,010 |
|
Depletion and depreciation of CO2 assets |
|
|
4,019 |
|
|
|
3,604 |
|
|
|
8,561 |
|
|
|
6,626 |
|
Asset retirement obligations |
|
|
810 |
|
|
|
762 |
|
|
|
1,637 |
|
|
|
1,524 |
|
Depreciation of other fixed assets |
|
|
3,362 |
|
|
|
2,547 |
|
|
|
6,467 |
|
|
|
4,412 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total DD&A |
|
$ |
61,695 |
|
|
$ |
54,733 |
|
|
$ |
123,620 |
|
|
$ |
104,572 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A per BOE: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties |
|
$ |
11.42 |
|
|
$ |
11.53 |
|
|
$ |
11.36 |
|
|
$ |
11.27 |
|
CO2 assets and other fixed assets |
|
|
1.55 |
|
|
|
1.46 |
|
|
|
1.57 |
|
|
|
1.33 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total DD&A cost per BOE |
|
$ |
12.97 |
|
|
$ |
12.99 |
|
|
$ |
12.93 |
|
|
$ |
12.60 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our depletion, depreciation and amortization (DD&A) rate for oil and natural gas properties
on a per BOE basis remained relatively constant between the respective periods. In the second
quarter of 2009, we booked approximately 10.9 million barrels of incremental oil reserves related
to our tertiary operations at Cranfield Field, as a result of the oil production response to the
CO2 injections in that field. Correspondingly, we moved approximately $82.4 million
from
unevaluated properties to the full cost pool relating to Cranfield, representing the acquisition
costs and development expenditures incurred on the field prior to recognizing proved reserves.
39
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
We continually evaluate the performance of our other tertiary projects, and if performance
indicates that we are reasonably certain of recovering additional reserves from these floods, we
recognize those incremental reserves in that quarter. Since we adjust our DD&A rate each quarter
based on any changes in our estimates of oil and natural gas reserves and costs, our DD&A rate
could change significantly in the future. We currently do not anticipate that any significant
incremental reserves will be recognized in the balance of 2009 as we do not expect any production
from any other new floods before year-end.
Our
DD&A rate for our
CO2
and other fixed assets increased in the second 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 June 30, 2009,
we had $761.7 million of costs related to CO2 pipelines under construction. These costs
were not being depreciated at June 30, 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. We did not have a ceiling test write-down at March 31, 2009 or June 30, 2009, as oil
prices have recovered from levels at the end of 2008. However, if oil prices were to decrease
significantly in subsequent periods, we may be required to record additional write-downs under the
full cost pool ceiling test in the future. The possibility and amount of any future write-down is
difficult to predict, and will depend upon oil and natural gas prices at the end of each period,
the incremental proved reserves that may be added each period, revisions to previous reserve
estimates and future capital expenditures, and additional capital spent.
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
In thousands, except per BOE amounts and tax rates |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Current income tax expense |
|
$ |
24,127 |
|
|
$ |
10,844 |
|
|
$ |
24,300 |
|
|
$ |
32,080 |
|
Deferred income tax expense (benefit) |
|
|
(77,555 |
) |
|
|
58,778 |
|
|
|
(88,406 |
) |
|
|
80,429 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense (benefit) |
|
$ |
(53,428 |
) |
|
$ |
69,622 |
|
|
$ |
(64,106 |
) |
|
$ |
112,509 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average income tax expense (benefit) per BOE |
|
$ |
(11.23 |
) |
|
$ |
16.52 |
|
|
$ |
(6.70 |
) |
|
$ |
13.56 |
|
Effective tax rate |
|
|
38.0 |
% |
|
|
37.9 |
% |
|
|
37.8 |
% |
|
|
37.6 |
% |
Our income tax provision was based on an estimated statutory rate of approximately 38%. Our
effective tax rate has generally been slightly lower than our estimated statutory rate due to the
impact of certain items such as our domestic production activities deduction, offset in part by
compensation arising from certain equity compensation that cannot be deducted for tax purposes in
the same manner as book expense. In the second quarters and first six months of both years, the
current income tax expense represents our anticipated alternative minimum cash taxes that we cannot
offset with enhanced oil recovery credits. In addition, included in the second quarter of 2009 is
approximately $16 million in current taxes associated with our sale of a portion of our Barnett
Shale assets on June 30, 2009. In total, we expect to pay approximately $25 million in cash taxes
related to this sale, with the remaining $9 million to be recorded in the third quarter upon
completion of the sale. 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.
In the second quarter of 2008 we obtained approval from the IRS to change our method of tax
accounting for certain assets used in our tertiary oilfield recovery operations. Although the
overall effects of this accounting change are still under audit, we expect to receive tax refunds
of approximately $10.6 million for tax years through 2007, along with other deferred tax benefits,
and in the second quarter of 2008 we reduced our current income tax expense by approximately $19
million to adjust for the impact of this change through the first six months of 2008. The
reduction in current income tax
expense has been offset by a corresponding increase in deferred income tax expense of approximately
the same amount. Although this change is not expected to have a significant impact on the
Companys overall tax rate, it is anticipated that it could defer the amount of cash taxes the
Company might otherwise pay over the next several years.
40
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Per BOE Data
The following table summarizes our cash flow, DD&A and results of operations on a per BOE
basis for the comparative periods. Each of the individual components is discussed above.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
Per BOE data |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Oil and natural gas revenues |
|
$ |
44.48 |
|
|
$ |
98.07 |
|
|
$ |
39.70 |
|
|
$ |
87.53 |
|
Gain (loss) on settlements of derivative contracts |
|
|
8.83 |
|
|
|
(6.79 |
) |
|
|
13.36 |
|
|
|
(4.42 |
) |
Lease operating expenses |
|
|
(17.59 |
) |
|
|
(18.23 |
) |
|
|
(16.59 |
) |
|
|
(17.21 |
) |
Production taxes and marketing expenses |
|
|
(2.27 |
) |
|
|
(4.87 |
) |
|
|
(2.09 |
) |
|
|
(4.49 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Production netback |
|
|
33.45 |
|
|
|
68.18 |
|
|
|
34.38 |
|
|
|
61.41 |
|
Non-tertiary CO2 operating margin |
|
|
0.38 |
|
|
|
0.70 |
|
|
|
0.38 |
|
|
|
0.56 |
|
General and administrative expenses |
|
|
(6.97 |
) |
|
|
(3.51 |
) |
|
|
(5.83 |
) |
|
|
(3.71 |
) |
Net cash interest expense and other income |
|
|
(2.52 |
) |
|
|
(1.79 |
) |
|
|
(2.33 |
) |
|
|
(1.34 |
) |
Current income taxes and other |
|
|
(1.59 |
) |
|
|
(2.08 |
) |
|
|
(0.32 |
) |
|
|
(3.20 |
) |
Changes in assets and liabilities relating to operations |
|
|
8.40 |
|
|
|
(22.56 |
) |
|
|
0.99 |
|
|
|
(9.10 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from operations |
|
|
31.15 |
|
|
|
38.94 |
|
|
|
27.27 |
|
|
|
44.62 |
|
DD&A |
|
|
(12.97 |
) |
|
|
(12.99 |
) |
|
|
(12.93 |
) |
|
|
(12.60 |
) |
Deferred income taxes |
|
|
16.31 |
|
|
|
(13.95 |
) |
|
|
9.24 |
|
|
|
(9.69 |
) |
Non-cash commodity derivative adjustments |
|
|
(40.95 |
) |
|
|
(7.17 |
) |
|
|
(31.49 |
) |
|
|
(8.31 |
) |
Changes in assets and liabilities and other non-cash items |
|
|
(11.88 |
) |
|
|
22.24 |
|
|
|
(3.13 |
) |
|
|
8.52 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(18.34 |
) |
|
$ |
27.07 |
|
|
$ |
(11.04 |
) |
|
$ |
22.54 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 $45
million of bank debt outstanding as of June 30, 2009. The carrying value of our bank debt is
approximately fair value based on the fact that it is subject to short-term floating interest rates
that approximate the rates available to us for those periods. We adjusted the estimated fair value
measurements of our bank debt at June 30, 2009, for estimated nonperformance risk in accordance
with SFAS No. 157. This estimated nonperformance risk totaled approximately $3.9 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 June 30, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Maturity Dates |
|
Carrying |
|
Fair |
In thousands |
|
2011 |
|
2013 |
|
2015 |
|
2016 |
|
Value |
|
Value |
Variable rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank debt (weighted average interest rate of 0.3% at |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2009) |
|
$ |
45,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
45,000 |
|
|
$ |
41,128 |
|
Fixed rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.5% subordinated debt due 2013 (fixed rate of 7.5%) |
|
|
|
|
|
|
225,000 |
|
|
|
|
|
|
|
|
|
|
|
224,271 |
|
|
|
214,875 |
|
7.5% subordinated debt due 2015 (fixed rate of 7.5%) |
|
|
|
|
|
|
|
|
|
|
300,000 |
|
|
|
|
|
|
|
300,556 |
|
|
|
285,000 |
|
9.75% subordinated debt due 2016 (fixed rate of 9.75%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
426,350 |
|
|
|
397,784 |
|
|
|
438,075 |
|
41
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Oil and Gas Derivative Contracts
From time to time, we enter into various oil and natural gas derivative contracts to provide
an economic hedge of our exposure to commodity price risk associated with anticipated future oil
and natural gas production. We do not hold or issue derivative financial instruments for trading
purposes. These contracts have consisted of price floors, collars and fixed price swaps. The
production that we hedge has varied from year to year depending on our levels of debt and financial
strength and expectation of future commodity prices. Recently, we have employed a strategy to
hedge a portion of our production looking out 12 to 15 months from each quarter, as we believe it is
important to protect our future cash flow to provide a level of assurance for our capital spending
in those future periods in light of current world-wide economic
uncertainties. See Note 6 to the Unaudited Condensed Consolidated
Financial Statements for details regarding our derivative contracts.
All of the mark-to-market valuations used for our oil and natural gas derivatives are provided
by external sources and are based on prices that are actively quoted. We manage and control market
and counterparty credit risk through established internal control procedures that are reviewed on
an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal
credit policies, monitoring procedures and diversification. All of
our derivative contracts are with parties that are lenders under our Senior Bank Loan. We have included an estimate of
nonperformance risk in the fair value measurement of our oil and natural gas derivative contracts as required by
SFAS No. 157. We have measured nonperformance risk based upon credit default swaps or credit spreads. At both June 30, 2009 and December 31, 2008, the fair value of
our oil and natural gas derivative contracts was reduced by $3.7 million for estimated
nonperformance risk.
For accounting purposes, we do not apply hedge accounting to our oil and natural gas
derivative contracts. This means that any changes in the fair value of these derivative contracts
will be charged to earnings on a quarterly basis instead of charging the effective portion to other
comprehensive income and the ineffective portion to earnings. Information regarding our current
derivative contract positions and results of our historical derivative activity is included in Note
6 to the Unaudited Condensed Consolidated Financial Statements.
At June 30, 2009, our derivative contracts were recorded at their fair value, which was a net
liability of approximately $47.0 million, a significant change from the $249.7 million fair value
asset recorded at December 31, 2008. This change is primarily related to the expiration of oil
derivative contracts during the first half of 2009, and to the oil and natural gas futures prices
as of June 30, 2009 in relation to the new commodity derivative contracts for 2010 and 2011 that we
entered into during the first and second quarters of 2009.
Commodity Derivative Sensitivity Analysis
Based on NYMEX crude oil and natural gas futures prices as of June 30, 2009, and assuming both
a 10% increase and decrease thereon, we would expect to make or receive payments on our crude oil
and natural gas derivative contracts as seen in the following table:
42
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
|
Crude Oil |
|
Natural Gas |
|
|
Derivative |
|
Derivative |
|
|
Contracts |
|
Contracts |
|
|
Receipt/ |
|
Receipt/ |
In thousands |
|
(Payment) |
|
(Payment) |
|
Based on: |
|
|
|
|
|
|
|
|
NYMEX futures prices as of June 30, 2009 |
|
$ |
(33,063 |
) |
|
$ |
(13,012 |
) |
10% increase in prices |
|
|
(85,692 |
) |
|
|
(29,588 |
) |
10% decrease in prices |
|
|
24,865 |
|
|
|
3,566 |
|
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 7 to the Unaudited Condensed Consolidated Financial
Statements for disclosures regarding our recurring fair value measurements.
Significant uses of fair value measurements include:
|
|
|
allocation of the purchase price paid to acquire businesses to the assets
acquired and liabilities assumed in those acquisitions, |
|
|
|
assessment of impairment of long-lived assets, |
|
|
|
assessment of impairment of goodwill, and |
|
|
|
recorded value of derivative instruments. |
Acquisitions
Under the acquisition method of accounting for business combinations 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
43
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
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, hydrocarbon reserves, hydrocarbon or expected reserve quantities and values,
potential reserves from tertiary operations, hydrocarbon prices, pricing assumptions based upon
current and projected oil and gas prices, liquidity, regulatory matters, mark-to-market values,
competition, long-term forecasts of production, finding costs, rates of return, estimated costs, or
changes in costs, future 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 annual report, including, without
limitation, the portions referenced above, and the uncertainties set forth from time to time in the
Companys other public reports, filings and public statements.
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.
44
DENBURY RESOURCES INC.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures, as defined in Rules
13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934,
consisting of internal controls designed to ensure that information
required to be disclosed in our filings under the Securities Exchange
Act of 1934 is recorded, processed, summarized and reported within
the time periods specified in the Securities and Exchange
Commissions rules and forms and that such information is accumulated
and communicated to management, including our Chief Executive Officer
and our Chief Financial Officer. Our Chief Executive Officer and Chief Financial Officer have
evaluated our disclosure controls and procedures as of the end of the
period covered by this quarterly report on Form 10-Q and have
determined that such disclosure controls and procedures are effective
in ensuring that material information required to be disclosed in
this quarterly report is accumulated and communicated to them and our
management to allow timely decisions regarding required disclosure.
Changes in Internal Control Over Financial Reporting There have been no changes in the
Companys internal control over financial reporting during the most recently completed fiscal
quarter that have materially affected, or are reasonably likely to materially affect, the Companys
internal control over financial reporting.
Part II. Other Information
Item 1. Legal Proceedings
Information with respect to this item has been incorporated by reference from our Form 10-K
for the year ended December 31, 2008. There have been no material developments in such legal
proceedings since the filing of such Form 10-K.
Item 1.A. Risk Factors
Information with respect to the 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, other than as described below.
A
three judge panel has been named in an American Arbitration Association proceeding in Dallas, Texas, initiated by Denbury in late 2008 against Crosstex CCNG Processing Ltd.
(Crosstex Processing) seeking damages (currently plead at the level of $11.4 million) related to a contract which provided for Crosstex Processing to process natural gas produced from Denburys Barnett Shale field, and a counterclaim by Crosstex North
Texas Gathering, L.P. (Crosstex Gathering) for $40.0
million of damages for the value of natural gas liquids to which
Crosstex Gathering alleges it is entitled under a gas gathering
agreement with Denbury in the same field. The parties are currently
engaged in discovery in this proceeding, which is currently set for hearing in late 2009.
Denbury believes that Crosstex Gatherings counterclaim is without merit, and does not believe that the ultimate resolution of these claims and counterclaims will have any material adverse effect upon it or its financial condition.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
ISSUER PURCHASES OF EQUITY SECURITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(c) Total Number of |
|
(d) Maximum Number |
|
|
(a) Total |
|
|
|
|
|
Shares Purchased |
|
of Shares that May |
|
|
Number of |
|
(b) Average |
|
as Part of Publicly |
|
Yet Be Purchased |
|
|
Shares |
|
Price Paid |
|
Announced Plans or |
|
Under the Plan Or |
Period |
|
Purchased |
|
per Share |
|
Programs |
|
Programs |
April 1 through 30, 2009 |
|
|
215 |
|
|
$ |
16.48 |
|
|
|
|
|
|
|
|
|
May 1 through 31, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 1 through 30, 2009 |
|
|
396 |
|
|
$ |
17.63 |
|
|
|
|
|
|
|
|
|
Total |
|
|
611 |
|
|
$ |
17.23 |
|
|
|
|
|
|
|
|
|
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
Denburys Annual Meeting of Stockholders was held on May 13, 2009 for the purposes of (1)
electing eight directors, each to serve until their successor is elected and qualified; (2) to
increase the number the number of shares that may be issued under our 2004 Omnibus Stock and
Incentive Plan by 7,500,000 shares; (3) to increase the number of
45
DENBURY RESOURCES INC.
shares that may be issued under
our Employee Stock Purchase Plan by 1,500,000 shares and to extend the term of the Plan to August
2014; and (4) to ratify the appointment by the audit committee of PricewaterhouseCoopers LLP as the
Companys independent registered accountants for 2009. Holders of 228,702,424 shares of common
stock, representing approximately 92% of the total issued and outstanding shares of common stock
were present in person or by proxy at the meeting to cast their
vote.
With respect to the election of directors, all eight nominees were elected. All of the
directors are elected on an annual basis. The votes were cast as follows:
|
|
|
|
|
|
|
|
|
Nominees for Directors |
|
For |
|
Withheld |
Ronald G. Greene
|
|
|
226,426,062 |
|
|
|
2,276,362 |
|
Michael L. Beatty
|
|
|
227,329,645 |
|
|
|
1,372,779 |
|
Michael B. Decker
|
|
|
218,369,864 |
|
|
|
10,332,560 |
|
David I. Heather
|
|
|
227,697,430 |
|
|
|
1,004,994 |
|
Greg McMichael
|
|
|
216,716,641 |
|
|
|
11,985,783 |
|
Gareth Roberts
|
|
|
227,100,722 |
|
|
|
1,601,702 |
|
Randy Stein
|
|
|
227,589,429 |
|
|
|
1,112,995 |
|
Wieland F. Wettstein
|
|
|
215,442,237 |
|
|
|
13,260,187 |
|
The proposal to increase the number of shares that may be used under our 2004 Omnibus Stock
and Incentive Plan was approved. The votes were cast as follows:
|
|
|
|
|
|
|
For |
|
Against |
|
Abstentions |
|
Broker Non-Votes |
142,567,500
|
|
72,825,615
|
|
62,313
|
|
-0- |
The proposal to increase the number of shares that may be used under our Employee Stock
Purchase Plan and extend the term of the plan was approved. The votes were cast as follows:
|
|
|
|
|
|
|
For |
|
Against |
|
Abstentions |
|
Broker Non-Votes |
164,372,075
|
|
51,020,838
|
|
62,515
|
|
-0- |
The appointment by the audit committee of PricewaterhouseCoopers LLP as the Companys
independent auditor for 2009 was approved. The votes were cast as follows:
|
|
|
|
|
|
|
For |
|
Against |
|
Abstentions |
|
Broker Non-Votes |
227,529,718
|
|
188,880
|
|
983,821
|
|
-0- |
Item 5. Other Information
None.
Item 6. Exhibits
|
|
|
Exhibits: |
|
|
10(a)*
|
|
Amendment to Sixth Amended and Restated Credit Agreement dated as of June 8, 2009. |
31(a)*
|
|
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
31(b)*
|
|
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
32*
|
|
Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002. |
101*
|
|
The following financial statements from the Companys Quarterly Report on Form 10-Q for
the quarter ended June 30, 2009, formatted in XBRL: (i) Consolidated Balance Sheets, (ii)
Consolidated Statements of Operations, (iii) Consolidated Statements of Cash Flows, (iv)
Consolidated Statements of Comprehensive Operations. |
46
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.
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DENBURY RESOURCES INC.
(Registrant) |
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By:
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/s/ Mark C. Allen |
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Mark C. Allen
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Sr. Vice President and Chief Financial Officer |
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By:
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/s/ Alan Rhoades |
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Alan Rhoades |
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Vice President, Accounting |
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Date:
August 10, 2009
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