e10vq
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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þ |
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Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the quarterly period ended June 30, 2007
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o |
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Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
Commission file number 1-12935
DENBURY RESOURCES INC.
(Exact name of Registrant as specified in its charter)
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Delaware |
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20-0467835 |
(State or other jurisdictions of
incorporation or organization)
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(I.R.S. Employer
Identification No.) |
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5100 Tennyson Parkway
Suite 1200
Plano, TX |
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75024 |
(Address of principal executive offices)
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(Zip code) |
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Registrants telephone number, including area code:
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(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 is a large accelerated filer, an accelerated
filer, or a non-accelerated filer. (See definition of accelerated filer and large accelerated
filer in Rule 12-b2 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 |
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, 2007 |
Common Stock, $.001 par value
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122,038,105 |
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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2007 |
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2006 |
|
Assets |
Current assets |
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|
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Cash and cash equivalents |
|
$ |
32,577 |
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$ |
53,873 |
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Accrued production receivable |
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94,387 |
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72,279 |
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Related party receivable Genesis |
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81 |
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119 |
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Trade and other receivables, net of allowance of $339 and $315 |
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36,150 |
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24,260 |
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Deferred tax asset |
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6,266 |
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|
5,855 |
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Derivative assets |
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|
8,830 |
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|
26,883 |
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|
|
|
|
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Total current assets |
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178,291 |
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|
183,269 |
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Property and equipment |
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Oil and natural gas properties (using full cost accounting) |
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|
|
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Proved |
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2,546,558 |
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|
2,226,942 |
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Unevaluated |
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318,444 |
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293,657 |
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CO2 properties and equipment |
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336,103 |
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|
267,483 |
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Other |
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|
45,656 |
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|
43,133 |
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Less accumulated depletion and depreciation |
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(1,037,012 |
) |
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(951,447 |
) |
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Net property and equipment |
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2,209,749 |
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1,879,768 |
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Investment in Genesis |
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10,106 |
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10,640 |
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Deposits on property under option or contract |
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|
49,056 |
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49,002 |
|
Other assets |
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19,649 |
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17,158 |
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Total assets |
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$ |
2,466,851 |
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$ |
2,139,837 |
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Liabilities and Stockholders Equity |
Current liabilities |
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Accounts payable and accrued liabilities |
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$ |
120,318 |
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$ |
139,111 |
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Oil and gas production payable |
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|
61,454 |
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52,244 |
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Derivative liabilities |
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|
9,624 |
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|
4,302 |
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Deferred revenue Genesis |
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|
4,070 |
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4,070 |
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Short-term capital lease obligations |
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|
702 |
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|
671 |
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Total current liabilities |
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196,168 |
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200,398 |
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Long-term liabilities |
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Capital lease obligations |
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6,035 |
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|
6,387 |
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Long-term debt, net of discount or premium |
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|
694,611 |
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507,786 |
|
Asset retirement obligations |
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|
43,862 |
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|
39,331 |
|
Derivative liabilities |
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|
5,220 |
|
|
|
6,834 |
|
Deferred revenue Genesis |
|
|
26,821 |
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|
|
28,843 |
|
Deferred tax liability |
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|
270,043 |
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|
|
235,780 |
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Other |
|
|
13,099 |
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|
|
8,419 |
|
|
|
|
|
|
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Total long-term liabilities |
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1,059,691 |
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|
833,380 |
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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, $.001 par value, 250,000,000 shares authorized;
121,985,444 and 120,506,815 shares issued at June 30, 2007 and
December 31, 2006, respectively |
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122 |
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121 |
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Paid-in capital in excess of par |
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640,158 |
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616,046 |
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Retained earnings |
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|
577,215 |
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498,032 |
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Accumulated other comprehensive income |
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57 |
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Treasury stock, at cost, 298,218 and 370,327 shares at June 30, 2007 and
December 31, 2006, respectively |
|
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(6,560 |
) |
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(8,140 |
) |
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|
|
|
|
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Total stockholders equity |
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1,210,992 |
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|
1,106,059 |
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Total liabilities and stockholders equity |
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$ |
2,466,851 |
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|
$ |
2,139,837 |
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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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2007 |
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2006 |
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2007 |
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2006 |
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Revenues and other income |
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Oil, natural gas and related product sales: |
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Unrelated parties |
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$ |
217,479 |
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$ |
189,369 |
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$ |
386,602 |
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$ |
363,463 |
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Related party Genesis |
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35 |
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|
11 |
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1,484 |
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CO2 sales and transportation fees |
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|
3,394 |
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2,374 |
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|
6,485 |
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|
4,362 |
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Interest income and other |
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|
1,764 |
|
|
|
1,469 |
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|
|
3,547 |
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|
|
2,844 |
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|
|
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|
|
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Total revenues |
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222,637 |
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|
193,247 |
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|
|
396,645 |
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|
372,153 |
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Expenses |
|
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Lease operating expenses |
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|
57,207 |
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|
41,751 |
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|
107,764 |
|
|
|
77,923 |
|
Production taxes and marketing expenses |
|
|
9,035 |
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|
|
8,441 |
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|
|
17,863 |
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|
|
15,386 |
|
Transportation expense Genesis |
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|
1,351 |
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|
|
995 |
|
|
|
2,727 |
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|
|
2,137 |
|
CO2 operating expenses |
|
|
1,204 |
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|
|
785 |
|
|
|
1,907 |
|
|
|
1,430 |
|
General and administrative |
|
|
11,694 |
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|
|
14,574 |
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|
|
23,128 |
|
|
|
24,441 |
|
Interest, net of amounts capitalized of $4,321, $2,735,
$8,354, and $3,009, respectively |
|
|
8,356 |
|
|
|
5,751 |
|
|
|
14,431 |
|
|
|
14,005 |
|
Depletion, depreciation, and amortization |
|
|
46,235 |
|
|
|
36,152 |
|
|
|
87,262 |
|
|
|
68,895 |
|
Commodity derivative expense (income) |
|
|
(15,049 |
) |
|
|
11,529 |
|
|
|
11,858 |
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|
|
23,159 |
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|
|
|
|
|
|
|
|
|
|
|
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|
Total expenses |
|
|
120,033 |
|
|
|
119,978 |
|
|
|
266,940 |
|
|
|
227,376 |
|
|
|
|
|
|
|
|
|
|
|
|
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|
Equity in net income (loss) of Genesis |
|
|
(127 |
) |
|
|
319 |
|
|
|
20 |
|
|
|
559 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
102,477 |
|
|
|
73,588 |
|
|
|
129,725 |
|
|
|
145,336 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax provision (benefit) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current income taxes |
|
|
7,343 |
|
|
|
(2,349 |
) |
|
|
8,961 |
|
|
|
7,437 |
|
Deferred income taxes |
|
|
32,567 |
|
|
|
31,675 |
|
|
|
41,581 |
|
|
|
49,859 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
62,567 |
|
|
$ |
44,262 |
|
|
$ |
79,183 |
|
|
$ |
88,040 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share basic |
|
$ |
0.52 |
|
|
$ |
0.38 |
|
|
$ |
0.66 |
|
|
$ |
0.77 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share diluted |
|
$ |
0.50 |
|
|
$ |
0.36 |
|
|
$ |
0.63 |
|
|
$ |
0.72 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
119,793 |
|
|
|
116,471 |
|
|
|
119,395 |
|
|
|
114,820 |
|
Diluted |
|
|
124,769 |
|
|
|
122,988 |
|
|
|
124,730 |
|
|
|
121,912 |
|
(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
4
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
Cash flow from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
62,567 |
|
|
$ |
44,262 |
|
|
$ |
79,183 |
|
|
$ |
88,040 |
|
Adjustments needed to reconcile to net cash flow provided by operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization |
|
|
46,235 |
|
|
|
36,152 |
|
|
|
87,262 |
|
|
|
68,895 |
|
Non-cash derivative adjustments |
|
|
(13,437 |
) |
|
|
9,317 |
|
|
|
21,721 |
|
|
|
20,179 |
|
Deferred income taxes |
|
|
32,567 |
|
|
|
31,675 |
|
|
|
41,581 |
|
|
|
49,859 |
|
Deferred revenue Genesis |
|
|
(1,066 |
) |
|
|
(1,065 |
) |
|
|
(2,022 |
) |
|
|
(2,005 |
) |
Stock based compensation |
|
|
2,664 |
|
|
|
8,285 |
|
|
|
5,450 |
|
|
|
11,257 |
|
Amortization of debt issue costs and other |
|
|
963 |
|
|
|
167 |
|
|
|
1,545 |
|
|
|
417 |
|
Changes in assets and liabilities related to operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued production receivable |
|
|
(23,550 |
) |
|
|
(4,317 |
) |
|
|
(22,070 |
) |
|
|
(4,160 |
) |
Trade and other receivables |
|
|
(2,806 |
) |
|
|
(10,198 |
) |
|
|
(11,785 |
) |
|
|
(5,940 |
) |
Other assets |
|
|
(124 |
) |
|
|
7,500 |
|
|
|
(146 |
) |
|
|
(2,632 |
) |
Accounts payable and accrued liabilities |
|
|
(10,515 |
) |
|
|
(19,027 |
) |
|
|
(15,501 |
) |
|
|
(23,768 |
) |
Oil and gas production payable |
|
|
7,782 |
|
|
|
3,440 |
|
|
|
9,211 |
|
|
|
8,306 |
|
Other liabilities |
|
|
972 |
|
|
|
226 |
|
|
|
1,168 |
|
|
|
481 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activites |
|
|
102,252 |
|
|
|
106,417 |
|
|
|
195,597 |
|
|
|
208,929 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow used for investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas expenditures |
|
|
(160,290 |
) |
|
|
(131,502 |
) |
|
|
(299,309 |
) |
|
|
(250,101 |
) |
Acquisitions of oil and gas properties |
|
|
(7,523 |
) |
|
|
(61,925 |
) |
|
|
(46,660 |
) |
|
|
(314,335 |
) |
Change in accrual for capital expenditures |
|
|
(4,514 |
) |
|
|
4,584 |
|
|
|
(8,769 |
) |
|
|
14,612 |
|
Acquisitions of CO2 assets and CO2
capital expenditures |
|
|
(37,011 |
) |
|
|
(17,143 |
) |
|
|
(68,427 |
) |
|
|
(28,167 |
) |
Purchases of other assets |
|
|
(1,870 |
) |
|
|
(1,540 |
) |
|
|
(4,487 |
) |
|
|
(3,682 |
) |
Dispositions of other assets |
|
|
33 |
|
|
|
20 |
|
|
|
1,753 |
|
|
|
222 |
|
Proceeds from sales of oil and gas properties and
equipment |
|
|
5,835 |
|
|
|
2,038 |
|
|
|
5,840 |
|
|
|
2,038 |
|
Deposits on properties under option or contract |
|
|
(21 |
) |
|
|
|
|
|
|
(54 |
) |
|
|
26,299 |
|
Increase in restricted cash |
|
|
(43 |
) |
|
|
(27 |
) |
|
|
(906 |
) |
|
|
(65 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used for investing activities |
|
|
(205,404 |
) |
|
|
(205,495 |
) |
|
|
(421,019 |
) |
|
|
(553,179 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank repayments |
|
|
(140,000 |
) |
|
|
(130,000 |
) |
|
|
(140,000 |
) |
|
|
(130,000 |
) |
Bank borrowings |
|
|
80,000 |
|
|
|
100,000 |
|
|
|
176,000 |
|
|
|
200,000 |
|
Payments on capital lease obligations |
|
|
(166 |
) |
|
|
(142 |
) |
|
|
(327 |
) |
|
|
(280 |
) |
Issuance of subordinated debt |
|
|
150,750 |
|
|
|
|
|
|
|
150,750 |
|
|
|
|
|
Issuance of common stock |
|
|
5,477 |
|
|
|
127,846 |
|
|
|
10,687 |
|
|
|
132,311 |
|
Income tax benefit from equity awards |
|
|
6,280 |
|
|
|
4,317 |
|
|
|
8,840 |
|
|
|
10,152 |
|
Purchase of treasury stock |
|
|
(19 |
) |
|
|
(2,115 |
) |
|
|
(19 |
) |
|
|
(2,122 |
) |
Costs of debt financing |
|
|
(1,600 |
) |
|
|
|
|
|
|
(1,805 |
) |
|
|
(88 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
100,722 |
|
|
|
99,906 |
|
|
|
204,126 |
|
|
|
209,973 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
(2,430 |
) |
|
|
828 |
|
|
|
(21,296 |
) |
|
|
(134,277 |
) |
Cash and cash equivalents at beginning of period |
|
|
35,007 |
|
|
|
29,984 |
|
|
|
53,873 |
|
|
|
165,089 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
32,577 |
|
|
$ |
30,812 |
|
|
$ |
32,577 |
|
|
$ |
30,812 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosure of cash flow information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid during the period for interest |
|
$ |
18,970 |
|
|
$ |
14,772 |
|
|
$ |
21,349 |
|
|
$ |
15,897 |
|
Cash paid during the period for income taxes |
|
|
6,332 |
|
|
|
4,200 |
|
|
|
7,370 |
|
|
|
4,206 |
|
Interest capitalized |
|
|
4,321 |
|
|
|
2,735 |
|
|
|
8,354 |
|
|
|
3,009 |
|
(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, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
Net income |
|
$ |
62,567 |
|
|
$ |
44,262 |
|
|
$ |
79,183 |
|
|
$ |
88,040 |
|
Other comprehensive income, net of income tax: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of derivative contracts
designated as a hedge,
net of tax of $364 and $36 |
|
|
570 |
|
|
|
|
|
|
|
57 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
$ |
63,137 |
|
|
$ |
44,262 |
|
|
$ |
79,240 |
|
|
$ |
88,040 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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, 2006. 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, 2007 and the consolidated results of its operations and cash flows for the three and
six month periods ended June 30, 2007 and 2006. Certain prior period items have been reclassified
to make the classification consistent with the classification in the most recent quarter.
Net Income Per Common Share
Basic net income per common share is computed by dividing net income by the weighted average
number of shares of common stock outstanding during the period. Diluted net income per common
share is calculated in the same manner but also considers the impact on net income and common
shares for the potential dilution from stock options, stock appreciation rights (SARs),
non-vested restricted stock and any other convertible securities outstanding. For the three and
six month periods ended June 30, 2007 and 2006, there were no adjustments to net income for
purposes of calculating diluted net income per common share. In April 2006, we issued 3,492,595
shares of common stock in a public offering. The following is a reconciliation of the weighted
average common shares used in the basic and diluted net income per common share calculations for
the three and six month periods ended June 30, 2007 and 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
(Shares in Thousands) |
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares basic |
|
|
119,793 |
|
|
|
116,471 |
|
|
|
119,395 |
|
|
|
114,820 |
|
Potentially dilutive securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options and SARs |
|
|
4,260 |
|
|
|
5,498 |
|
|
|
4,658 |
|
|
|
6,094 |
|
Restricted stock |
|
|
716 |
|
|
|
1,019 |
|
|
|
677 |
|
|
|
998 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares diluted |
|
|
124,769 |
|
|
|
122,988 |
|
|
|
124,730 |
|
|
|
121,912 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The weighted average common shares basic amount excludes 1,531,141 shares at June 30, 2007
and 1,687,539 shares at June 30, 2006, of non-vested restricted stock that is subject to future
vesting over time. As these restricted shares vest, they will be included in the shares
outstanding used to calculate basic net income per common share (although all restricted stock is
issued and outstanding upon grant). For purposes of calculating weighted average common shares
diluted, the non-vested restricted stock is included in the computation using the treasury stock
method, with the proceeds equal to the average unrecognized compensation during the period,
adjusted for any estimated future tax consequences recognized directly in equity. The dilution
impact of these shares on our earnings per share calculation may increase in future periods, depending on the market price of our
common stock during those periods.
7
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
For the three months ended June 30, 2007 and 2006, common stock options to purchase
approximately 80,000 and 60,000 shares of common stock, and for the six months ended June 30, 2007
and 2006, stock options to purchase approximately 157,000 and 66,000 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.
Recently Adopted Accounting Pronouncement
Uncertain Tax Positions
In June 2006, the Financial Accounting Standards Board (FASB) issued Interpretation 48 (FIN
48), Accounting for Uncertainties in Income Taxes an interpretation of FASB Statement No. 109,
Accounting for Income Taxes. This interpretation addresses how tax benefits claimed or expected to
be claimed on a tax return should be recorded in the financial statements. Under FIN 48, the
Company may recognize the tax benefit from an uncertain tax position only if it is more likely than
not that the tax position will be sustained on examination by the taxing authorities, based on the
technical merits of the position. The tax benefits recognized in the financial statements from
such a position should be measured based on the largest benefit that has a greater than fifty
percent likelihood of being realized upon ultimate settlement. FIN 48 also provides guidance on
derecognition, classification, interest and penalties on income taxes, accounting in interim
periods and required increased disclosures.
We adopted the provisions of FIN 48 as of January 1, 2007. As a result of the implementation,
we determined that approximately $4.0 million of tax benefits previously recognized were considered
uncertain tax positions, as the timing of these deductions may not be sustained upon examination by
taxing authorities. As such, upon adoption of FIN 48, we recorded income taxes payable of $4.3
million (including $0.3 million in estimated interest) which was offset by a corresponding
reduction of the deferred tax liability of $4.1 million for the tax position that we believe will
ultimately be sustained. At January 1, 2007 the total amount of unrecognized tax benefits was $4.5
million, exclusive of interest.
There was no cumulative adjustment made to the opening balance of retained earnings at January
1, 2007. Our uncertain tax positions relate primarily to timing differences and we do not believe
any of such uncertain tax positions will materially impact our effective tax rate in future
periods. The amount of unrecognized tax benefits did not materially change as of June 30, 2007.
The amount of unrecognized tax benefits are expected to change over the next 12 months; however,
such change is not expected to have a significant impact on our results of operations or financial
position.
We file consolidated and separate income tax returns in the U.S. federal jurisdiction and in
many state jurisdictions. We are currently under examination by both the Internal Revenue Service
and State authorities. The IRS is examining 2004 while Mississippi is auditing the periods from
1998 through 2003. We expect the 2004 IRS examination to be finalized in the third quarter of 2007
and we currently do not anticipate any material assessments as a result of this audit. Louisiana
is auditing the periods from 2002 through 2004.
We have not paid any significant interest or penalties associated with our income taxes, but
we will classify both interest expense and penalties as part of our income tax expense.
Recently Issued Accounting Pronouncement
Fair Value Option for Financial Assets and Liabilities
In February 2007, the FASB issued FASB Statement No. 159, The Fair Value Option for
Financial Assets and Financial Liabilities (FAS 159). FAS 159 permits entities to choose to
measure many financial instruments and certain other items at fair value, with the objective
of improving financial reporting by giving entities the opportunity to mitigate volatility in
reported earnings caused by measuring related assets and liabilities differently without
having to apply complex hedge accounting provisions. The provisions of FAS 159 are effective
for us beginning January 1, 2008. We have not yet determined what impact, if any, this
pronouncement will have on our financial position or results of operations.
8
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 2. Acquisitions
2007 Acquisition
On March 30, 2007, Denbury completed the acquisition of the Seabreeze Complex, which is
composed of two significant fields and four smaller fields, in the general area of Houston, Texas.
At the time of acquisition these fields were producing approximately 400 BOE/d and had estimated
current conventional proved reserves of approximately 525 MBOE. Two of these fields are future
potential CO2 tertiary flood candidates. Tertiary flooding at these fields is not
expected to begin until 2010 or 2011, following completion of the proposed CO2 pipeline
from Louisiana to Hastings Field, near Houston, Texas.
The preliminary adjusted purchase price is approximately $41.7 million, after adjusting for
interim net cash flow between the effective date and closing date of the acquisition, and minor
purchase price adjustments. The preliminary purchase price is subject to final adjustment of the
estimated interim net cash flow and potentially other minor adjustments as outlined in the purchase
and sales agreement. The preliminary purchase price was allocated between proved and unevaluated
oil and natural gas properties based on a risk adjusted analysis of the total estimated value of
the proved and probable reserves acquired. Based on this analysis, $5.5 million was assigned to
proved properties and $36.1 million was assigned to unevaluated properties. The unevaluated costs
are currently excluded from the amortization base and will be transferred to the amortization base
as we develop and test the tertiary recovery projects planned in these fields.
We have not presented any pro forma information for the acquired properties as the pro forma
effect was not material to our results of operations for the first quarters of 2007 or 2006.
2006 Acquisitions
On January 31, 2006, we completed an acquisition of three producing oil properties that are
future potential CO2 tertiary oil flood candidates: Tinsley Field approximately 40
miles northwest of Jackson, Mississippi; Citronelle Field in Southwest Alabama, and the smaller
South Cypress Creek Field near the Companys Eucutta Field in Eastern Mississippi. The adjusted
purchase price was approximately $250 million (including the $25 million deposited as earnest money
as of December 31, 2005), of which $124 million was assigned to unevaluated properties.
During May 2006, we purchased the Delhi Holt-Bryant Unit (Delhi) in northern Louisiana for
$50 million, plus a 25% reversionary interest to the seller after we have achieved $200 million in
net operating revenue, as defined. Delhi is also a future potential CO2 tertiary oil
flood candidate. Approximately $49 million of the purchase price was assigned to unevaluated
properties.
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 wells 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.
9
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
The following table summarizes the changes in our asset retirement obligations for the six
months ended June 30, 2007.
|
|
|
|
|
|
|
Six Months Ended |
|
Amounts in thousands |
|
June 30, 2007 |
|
|
Balance, beginning of period |
|
$ |
41,107 |
|
Liabilities incurred and assumed during period |
|
|
3,099 |
|
Revisions in estimated retirement obligations |
|
|
805 |
|
Liabilities settled during period |
|
|
(996 |
) |
Accretion expense |
|
|
1,486 |
|
|
|
|
|
Balance, end of period |
|
$ |
45,501 |
|
|
|
|
|
At June 30, 2007, $1.6 million of our asset retirement obligation was classified in Accounts
payable and accrued liabilities under current liabilities in our Condensed Consolidated Balance
Sheets. Liabilities incurred and assumed during the period are primarily for oil properties
acquired during 2007. 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 $8.5 million at June 30, 2007 and $7.6 million at December 31, 2006 and are included in Other
assets in our Condensed Consolidated Balance Sheets.
Note 4. Notes Payable and Long-term Indebtedness
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
Amounts in thousands |
|
2007 |
|
|
2006 |
|
|
|
|
|
|
|
|
|
|
7.5% Senior Subordinated Notes due 2015 |
|
$ |
300,000 |
|
|
$ |
150,000 |
|
Premium on Senior Subordinated Notes due 2015 |
|
|
728 |
|
|
|
|
|
7.5% Senior Subordinated Notes due 2013 |
|
|
225,000 |
|
|
|
225,000 |
|
Discount on Senior Subordinated Notes due 2013 |
|
|
(1,117 |
) |
|
|
(1,214 |
) |
Senior bank loan |
|
|
170,000 |
|
|
|
134,000 |
|
Capital lease obligations Genesis |
|
|
5,561 |
|
|
|
5,869 |
|
Capital lease obligations |
|
|
1,176 |
|
|
|
1,189 |
|
|
|
|
|
|
|
|
Total |
|
|
701,348 |
|
|
|
514,844 |
|
Less current obligations |
|
|
702 |
|
|
|
671 |
|
|
|
|
|
|
|
|
Long-term debt and capital lease obligations |
|
$ |
700,646 |
|
|
$ |
514,173 |
|
|
|
|
|
|
|
|
On March 31, 2007, we amended our Sixth Amended and Restated Credit Agreement, the instrument
governing our senior bank loan. The amendments (i) increased the commitment under the facility to
$350 million, (ii) permit an additional $150 million add-on to the existing 7.5% Senior
Subordinated Notes due 2015, (iii) obtained consent for a sale of our existing CO2
pipelines to Genesis Energy, L.P., and (iv) reaffirmed the borrowing base at $500 million.
On April 3, 2007, we issued $150 million of Senior Subordinated Notes as an additional
issuance under the instrument governing the 7.5% Senior Subordinated Notes due 2015. The notes,
which carry a coupon rate of 7.5%, were sold at 100.5% of par, which equates to an effective yield
to maturity of approximately 7.4%. Net proceeds from the sale were approximately $149.2 million.
The net proceeds were used to repay a portion of the outstanding borrowings under our bank credit
facility.
10
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
5. Related Party Transactions Genesis
Interest in and Transactions with Genesis
Denbury is the general partner and owns an aggregate 9.25% interest in Genesis Energy, L.P.
(Genesis), a publicly traded master limited partnership. Genesis primary business activities
include: gathering, marketing and transportation of crude oil and natural gas, and wholesale
marketing of CO2, primarily in Mississippi, Texas, Alabama and Florida.
We are accounting for our 9.25% ownership in Genesis under the equity method of accounting as
we have significant influence over the limited partnership; however, our control is limited under
the limited partnership agreement and therefore we do not consolidate Genesis. Our equity in
Genesis net income (loss) for the three months ended June 30, 2007 and 2006 was ($0.1) million and $0.3 million, respectively, and for the six months
ended June 30, 2007 and 2006 was $20,000 and $0.6 million, respectively. Denbury received pro-rata
distributions from Genesis of $0.6 million and $0.4 million for the six months ended June 30, 2007
and 2006, respectively. We also received $0.1 million in each of these periods in 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, Inc.
On July 25, 2007, Genesis closed on a previously announced acquisition wherein they acquired
several energy related businesses from the Davison family of Ruston, Louisiana for total
consideration of approximately $563 million, plus payment of approximately $35.1 million for
certain purchase price adjustments and for estimated working capital of the sellers. These
businesses include a trucking operation for petroleum products and other bulk commodities, terminal
storage of refined petroleum products, a refinery service operation which processes sour gas
streams at several refining operations, and a wholesale petroleum products marketing business.
Approximately one-half of the acquisition was funded by debt from Genesis bank credit facility and
approximately one-half through the issuance of Genesis common units to the seller. In conjunction
with that acquisition, we exercised our right to maintain our pro rata (7.4%) ownership of common
units, acquiring 1,074,882 additional common units for approximately $22.4 million, in addition to
our capital contribution of an additional $6.2 million as general partner to maintain our 2%
general partners capital interest.
Oil Sales and Transportation Services
We utilize Genesis trucking services and common carrier pipeline in Mississippi to transport
certain of our crude oil production to sales points where it is sold to third party purchasers. In
the first six months of 2007 and 2006, we expensed $2.7 million and $2.1 million, respectively, for
these transportation services.
Transportation Leases
In late 2004 and early 2005, we entered into pipeline transportation agreements with Genesis
to transport our crude oil from certain of our fields in Southwest Mississippi and to transport
CO2 from our main CO2 pipeline to Brookhaven Field for our tertiary
operations. We have accounted for these agreements as capital leases. The pipelines held under
these capital leases are classified as property and equipment and are amortized using the
straight-line method over the lease terms. Lease amortization is included in depreciation expense.
The related obligations are recorded as debt. At June 30, 2007, we had $5.6 million of capital
lease obligations with Genesis recorded as liabilities in our Condensed Consolidated Balance Sheet,
of which $0.7 million was current. At December 31, 2006, we had $5.9 million of capital lease
obligations with Genesis recorded as liabilities in our Condensed Consolidated Balance Sheet, of
which $0.6 million was current.
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, 2007 and December 31, 2006, $30.9
million and $32.9 million, respectively, was recorded as deferred revenue of which $4.1 million was
included in current liabilities at June 30, 2007 and December 31, 2006. We recognized deferred
revenue of $1.1 million during each of the three month periods ended June 30, 2007 and 2006 and
$2.0 million during each of the six month periods ended June 30, 2007 and 2006, for deliveries
under these volumetric production payments. We provide Genesis
11
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
with certain processing and
transportation services in connection with these agreements for a fee of approximately $0.17 per
Mcf of CO2. For these services, we recognized revenues of $1.2 million for
each of the three month periods ended June 30, 2007 and 2006 and $2.3 million and $2.2 million for
the six months ended June 30, 2007 and 2006, respectively.
We had a net receivable from Genesis of $0.1 million at June 30, 2007 and December 31, 2006 in
current assets and a long-term payable to Genesis of $0.5 million at June 30, 2007.
Note 6. Derivative Instruments and Hedging Activities
Oil and Gas Derivative Contracts
We do not apply hedge accounting treatment to our oil and 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 Condensed Consolidated Statements of
Operations.
The following is a summary of Commodity derivative income (expense) included in our
Condensed Consolidated Statements of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Six Months |
|
Amounts
in thousands |
|
Ended June 30, |
|
|
Ended June 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
Receipt (payment)
on settlements of
derivative
contracts Oil |
|
$ |
(1,108 |
) |
|
$ |
(2,212 |
) |
|
$ |
(981 |
) |
|
$ |
(2,980 |
) |
Receipt (payment)
of settlements of
derivative
contracts Gas |
|
|
2,827 |
|
|
|
|
|
|
|
10,951 |
|
|
|
|
|
Fair value
adjustments to
derivative
contracts |
|
|
13,330 |
|
|
|
(9,317 |
) |
|
|
(21,828 |
) |
|
|
(20,179 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
derivative income
(expense) |
|
$ |
15,049 |
|
|
$ |
(11,529 |
) |
|
$ |
(11,858 |
) |
|
$ |
(23,159 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Natural Gas Commodity Derivative Contracts at June 30, 2007:
Crude Oil Contracts at June 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
NYMEX Contract Prices Per Bbl |
|
|
Fair Value at |
|
|
|
|
|
|
|
|
|
|
|
June 30, 2007 |
|
Type of Contract and Period |
|
Bbls/d |
|
|
Swap Price |
|
|
(In Thousands) |
|
Swap Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
July 2007 - Dec. 2007 |
|
|
2,000 |
|
|
$ |
58.93 |
|
|
$ |
(4,454 |
) |
Jan. 2008 - Dec. 2008 |
|
|
2,000 |
|
|
|
57.34 |
|
|
|
(10,390 |
) |
Natural Gas Contracts at June 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
NYMEX Contract Prices Per MMBtu |
|
|
Fair Value at |
|
|
|
|
|
|
|
|
|
|
|
June 30, 2007 |
|
Type of Contract and Period |
|
MMBtu/d |
|
|
Swap Price |
|
|
(In Thousands) |
|
Swap Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
July 2007 - Dec. 2007 |
|
|
20,000 |
|
|
$ |
7.99 |
|
|
$ |
2,424 |
|
July 2007 - Dec. 2007 |
|
|
40,000 |
|
|
|
7.96 |
|
|
|
4,629 |
|
July 2007 - Dec. 2007 |
|
|
15,000 |
|
|
|
7.95 |
|
|
|
1,709 |
|
At June 30, 2007, our oil and natural gas derivative contracts were recorded at their fair
value, which was a net liability of $6.1 million.
12
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Interest Rate Lock Derivative Contracts
In January 2007, we entered into interest rate lock contracts to remove our exposure to
possible interest rate fluctuations related to our commitment to the sale-leaseback financing of
certain equipment for CO2 recycling facilities at our tertiary oil fields. The interest
rate lock contracts cover two groups of equipment currently being constructed that we have
committed to finance with Bank of America Leasing & Capital LLC. This equipment has estimated
completion dates during the fourth quarter of 2007 and in mid-year 2008, with total estimated costs
of approximately $15 million and $24 million, respectively. We are applying hedge accounting to
these contracts as provided under SFAS No. 133. For these instruments designated as interest rate
hedges, changes in fair value, to the extent the hedge is effective, are recognized in other
comprehensive income (loss) until the hedged item is recognized in earnings. Amounts representing
hedge ineffectiveness are recorded in earnings. Hedge effectiveness is assessed quarterly based on
the total change in the contracts fair value.
At June 30, 2007, the interest rate lock contracts have a fair value asset of approximately
$0.2 million that was recorded in our June 30, 2007 Condensed Consolidating Balance Sheet. We
recorded $57,000 (net of taxes of $36,000) in accumulated other
comprehensive income in our June 30,
2007 Condensed Consolidating Balance Sheet and the ineffectiveness totaling $0.1 million was recognized as income in our Condensed Consolidating
Statement of Operations for the six months ended June 30, 2007.
Note 7. 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:
13
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2007 |
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
Denbury |
|
|
|
Denbury |
|
|
Denbury |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Amounts in thousands |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
413,507 |
|
|
$ |
173,743 |
|
|
$ |
7,356 |
|
|
$ |
(416,315 |
) |
|
$ |
178,291 |
|
Property and equipment |
|
|
|
|
|
|
2,209,731 |
|
|
|
18 |
|
|
|
|
|
|
|
2,209,749 |
|
Investment in subsidiaries (equity method) |
|
|
789,046 |
|
|
|
|
|
|
|
789,113 |
|
|
|
(1,568,053 |
) |
|
|
10,106 |
|
Other assets |
|
|
309,167 |
|
|
|
65,476 |
|
|
|
154 |
|
|
|
(306,092 |
) |
|
|
68,705 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,511,720 |
|
|
$ |
2,448,950 |
|
|
$ |
796,641 |
|
|
$ |
(2,290,460 |
) |
|
$ |
2,466,851 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
|
|
|
$ |
605,117 |
|
|
$ |
7,366 |
|
|
$ |
(416,315 |
) |
|
$ |
196,168 |
|
Long-term liabilities |
|
|
300,728 |
|
|
|
1,064,826 |
|
|
|
229 |
|
|
|
(306,092 |
) |
|
|
1,059,691 |
|
Stockholders equity |
|
|
1,210,992 |
|
|
|
779,007 |
|
|
|
789,046 |
|
|
|
(1,568,053 |
) |
|
|
1,210,992 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
1,511,720 |
|
|
$ |
2,448,950 |
|
|
$ |
796,641 |
|
|
$ |
(2,290,460 |
) |
|
$ |
2,466,851 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006 |
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
Denbury |
|
|
|
Denbury |
|
|
Denbury |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Amounts in thousands |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
392,372 |
|
|
$ |
180,476 |
|
|
$ |
3,662 |
|
|
$ |
(393,241 |
) |
|
$ |
183,269 |
|
Property and equipment |
|
|
|
|
|
|
1,879,742 |
|
|
|
26 |
|
|
|
|
|
|
|
1,879,768 |
|
Investment in subsidiaries (equity method) |
|
|
709,611 |
|
|
|
|
|
|
|
709,020 |
|
|
|
(1,407,991 |
) |
|
|
10,640 |
|
Other assets |
|
|
154,076 |
|
|
|
64,391 |
|
|
|
154 |
|
|
|
(152,461 |
) |
|
|
66,160 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,256,059 |
|
|
$ |
2,124,609 |
|
|
$ |
712,862 |
|
|
$ |
(1,953,693 |
) |
|
$ |
2,139,837 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
|
|
|
$ |
590,602 |
|
|
$ |
3,037 |
|
|
$ |
(393,241 |
) |
|
$ |
200,398 |
|
Long-term liabilities |
|
|
150,000 |
|
|
|
835,627 |
|
|
|
214 |
|
|
|
(152,461 |
) |
|
|
833,380 |
|
Stockholders equity |
|
|
1,106,059 |
|
|
|
698,380 |
|
|
|
709,611 |
|
|
|
(1,407,991 |
) |
|
|
1,106,059 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
1,256,059 |
|
|
$ |
2,124,609 |
|
|
$ |
712,862 |
|
|
$ |
(1,953,693 |
) |
|
$ |
2,139,837 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2007 |
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
Denbury |
|
|
|
Denbury |
|
|
Denbury |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Amounts in thousands |
|
Revenues |
|
$ |
5,531 |
|
|
$ |
222,619 |
|
|
$ |
18 |
|
|
$ |
(5,531 |
) |
|
$ |
222,637 |
|
Expenses |
|
|
5,646 |
|
|
|
119,244 |
|
|
|
674 |
|
|
|
(5,531 |
) |
|
|
120,033 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before the following: |
|
|
(115 |
) |
|
|
103,375 |
|
|
|
(656 |
) |
|
|
|
|
|
|
102,604 |
|
Equity in net earnings of subsidiaries |
|
|
62,676 |
|
|
|
|
|
|
|
63,245 |
|
|
|
(126,048 |
) |
|
|
(127 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
62,561 |
|
|
|
103,375 |
|
|
|
62,589 |
|
|
|
(126,048 |
) |
|
|
102,477 |
|
Income tax provision (benefit) |
|
|
(6 |
) |
|
|
40,003 |
|
|
|
(87 |
) |
|
|
|
|
|
|
39,910 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
62,567 |
|
|
$ |
63,372 |
|
|
$ |
62,676 |
|
|
$ |
(126,048 |
) |
|
$ |
62,567 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2006 |
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
Denbury |
|
|
|
Denbury |
|
|
Denbury |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Amounts in thousands |
|
Revenues |
|
$ |
2,781 |
|
|
$ |
190,466 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
193,247 |
|
Expenses |
|
|
2,858 |
|
|
|
116,791 |
|
|
|
329 |
|
|
|
|
|
|
|
119,978 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before the following: |
|
|
(77 |
) |
|
|
73,675 |
|
|
|
(329 |
) |
|
|
|
|
|
|
73,269 |
|
Equity in net earnings of subsidiaries |
|
|
44,342 |
|
|
|
|
|
|
|
44,808 |
|
|
|
(88,831 |
) |
|
|
319 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
44,265 |
|
|
|
73,675 |
|
|
|
44,479 |
|
|
|
(88,831 |
) |
|
|
73,588 |
|
Income tax provision |
|
|
3 |
|
|
|
29,186 |
|
|
|
137 |
|
|
|
|
|
|
|
29,326 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
44,262 |
|
|
$ |
44,489 |
|
|
$ |
44,342 |
|
|
$ |
(88,831 |
) |
|
$ |
44,262 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Statements of Operations (continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2007 |
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
Denbury |
|
|
|
Denbury |
|
|
Denbury |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Amounts in thousands |
|
Revenues |
|
$ |
8,344 |
|
|
$ |
396,611 |
|
|
$ |
34 |
|
|
$ |
(8,344 |
) |
|
$ |
396,645 |
|
Expenses |
|
|
8,550 |
|
|
|
265,446 |
|
|
|
1,288 |
|
|
|
(8,344 |
) |
|
|
266,940 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before the following: |
|
|
(206 |
) |
|
|
131,165 |
|
|
|
(1,254 |
) |
|
|
|
|
|
|
129,705 |
|
Equity in net earnings of subsidiaries |
|
|
79,379 |
|
|
|
|
|
|
|
80,590 |
|
|
|
(159,949 |
) |
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
79,173 |
|
|
|
131,165 |
|
|
|
79,336 |
|
|
|
(159,949 |
) |
|
|
129,725 |
|
Income tax provision (benefit) |
|
|
(10 |
) |
|
|
50,595 |
|
|
|
(43 |
) |
|
|
|
|
|
|
50,542 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
79,183 |
|
|
$ |
80,570 |
|
|
$ |
79,379 |
|
|
$ |
(159,949 |
) |
|
$ |
79,183 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2006 |
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
Denbury |
|
|
|
Denbury |
|
|
Denbury |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Amounts in thousands |
|
Revenues |
|
$ |
5,594 |
|
|
$ |
366,559 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
372,153 |
|
Expenses |
|
|
5,761 |
|
|
|
220,855 |
|
|
|
760 |
|
|
|
|
|
|
|
227,376 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before the following: |
|
|
(167 |
) |
|
|
145,704 |
|
|
|
(760 |
) |
|
|
|
|
|
|
144,777 |
|
Equity in net earnings of subsidiaries |
|
|
88,201 |
|
|
|
|
|
|
|
89,152 |
|
|
|
(176,794 |
) |
|
|
559 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
88,034 |
|
|
|
145,704 |
|
|
|
88,392 |
|
|
|
(176,794 |
) |
|
|
145,336 |
|
Income tax provision (benefit) |
|
|
(6 |
) |
|
|
57,111 |
|
|
|
191 |
|
|
|
|
|
|
|
57,296 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
88,040 |
|
|
$ |
88,593 |
|
|
$ |
88,201 |
|
|
$ |
(176,794 |
) |
|
$ |
88,040 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16
DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2007 |
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
Denbury |
|
|
|
Denbury |
|
|
Denbury |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Amounts in thousands |
|
Cash flow from operations |
|
$ |
33 |
|
|
$ |
195,195 |
|
|
$ |
369 |
|
|
$ |
|
|
|
$ |
195,597 |
|
Cash flow from investing
activities |
|
|
(170,258 |
) |
|
|
(421,019 |
) |
|
|
|
|
|
|
170,258 |
|
|
|
(421,019 |
) |
Cash flow from financing
activities |
|
|
170,258 |
|
|
|
204,126 |
|
|
|
|
|
|
|
(170,258 |
) |
|
|
204,126 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash |
|
|
33 |
|
|
|
(21,698 |
) |
|
|
369 |
|
|
|
|
|
|
|
(21,296 |
) |
Cash, beginning of period |
|
|
1 |
|
|
|
52,225 |
|
|
|
1,647 |
|
|
|
|
|
|
|
53,873 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, end of period |
|
$ |
34 |
|
|
$ |
30,527 |
|
|
$ |
2,016 |
|
|
$ |
|
|
|
$ |
32,577 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2006 |
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
Denbury |
|
|
|
Denbury |
|
|
Denbury |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Amounts in thousands |
|
Cash flow from operations |
|
$ |
(140,340 |
) |
|
$ |
348,822 |
|
|
$ |
447 |
|
|
$ |
|
|
|
$ |
208,929 |
|
Cash flow from investing activities |
|
|
|
|
|
|
(553,179 |
) |
|
|
|
|
|
|
|
|
|
|
(553,179 |
) |
Cash flow from financing activities |
|
|
140,340 |
|
|
|
69,633 |
|
|
|
|
|
|
|
|
|
|
|
209,973 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash |
|
|
|
|
|
|
(134,724 |
) |
|
|
447 |
|
|
|
|
|
|
|
(134,277 |
) |
Cash, beginning of period |
|
|
1 |
|
|
|
164,408 |
|
|
|
680 |
|
|
|
|
|
|
|
165,089 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, end of period |
|
$ |
1 |
|
|
$ |
29,684 |
|
|
$ |
1,127 |
|
|
$ |
|
|
|
$ |
30,812 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17
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
You should read the following in conjunction with our financial statements contained herein
and our Form 10-K for the year ended December 31, 2006, 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.
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, and hold significant operating acreage in the
Barnett Shale play near Fort Worth, Texas, onshore Louisiana, Alabama, and properties in Southeast
Texas. Our goal is to increase the value of acquired properties through a combination of
exploitation, drilling, and proven engineering extraction processes, including secondary and
tertiary recovery operations. Our corporate headquarters are in Plano, Texas (a suburb of Dallas),
and we have five primary field offices located in Laurel, Mississippi; McComb, Mississippi;
Brandon, Mississippi; Cleburne, Texas; and Houma, Louisiana.
Overview
Operating results. Our average production levels were 12% higher in the second quarter of
2007 than during the second quarter of 2006 and 10% higher in the first half of 2007 than during
the first half of 2006, with significant increases in our tertiary oil and Barnett Shale
production, partially offset by significant production declines in our Louisiana onshore
properties. Our second quarter average production rate of 41,916 BOE/d was a Company quarterly
record, and 9% higher than our first quarter 2007 average production rate. Higher natural gas
prices further improved 2007 second quarter results as our average realized per BOE commodity price
during that period was 3% higher than during the second quarter of 2006, resulting in 15% higher
revenues in the 2007 second quarter period. Conversely, commodity prices on a per BOE basis were
4% lower in the first half of 2007, partially offsetting our higher first half production,
resulting in a net 6% overall increase in revenues for the first six months of 2007.
Excluding any impact of our commodity derivative income and expenses discussed below, our
aggregate expenses increased 25% during the second quarter of 2007 as compared to the second
quarter of 2006 due to (i) higher overall industry costs, (ii) a higher percentage of operations
related to tertiary operations (which have higher operating costs per BOE), (iii) the timing impact
of the continued expansion of our tertiary operations in which we expense the cost of our
CO2 injections and other operating costs even though production response to the
injections will lag behind (see Results of Operations CO2 Operations for a more
thorough discussion), (iv) significantly higher average debt levels to finance our $42 million
acquisition on March 31, 2007 (see Recent Acquisition below) and due to continued spending in
excess of cash flow from operations (see Capital Resources and Liquidity), and (v) higher
compensation expense resulting from additional employees and increased salaries which we consider
necessary in order to remain competitive in the industry. General and administrative expenses
decreased in the 2007 period because the general increase in compensation costs during 2007 was
more than offset by a $5.3 million charge to earnings in the second quarter of 2006 related to the
departure of our former Senior Vice President of Operations.
During the first half of 2007, aggregate expenses (excluding any commodity and derivative
income and expenses) also increased 25% overall with similar variances in all categories except for
interest expense. Our interest expense increased significantly less on a six month basis as
compared to the second quarter variance because debt levels were lower in the first quarter of 2007
than during the second quarter, reducing the percentage increase in debt levels on a six month
basis as compared to the second quarter percentage increase.
In addition to affecting our revenue, fluctuations in natural gas prices also affected the
market value of our derivative contracts. Quarter-end closing prices of the near-month derivative
natural gas price futures for the last three quarters help illustrate this. At December 31, 2006,
the near-month natural gas price futures closed at $6.30, at March 31, 2007, it closed at $7.73,
and on June 30, 2007, it closed at $6.77. Since we entered into derivative contracts covering 80%
to 90% of our anticipated 2007 natural gas production in late 2006 at an average price of
approximately $7.96 per Mcf, these fluctuating quarter-end natural gas price futures caused
significant non-cash mark-to-market value adjustments. We recorded a $35.2 million non-cash
pre-tax mark-to-market charge to earnings in the first quarter of 2007, which partially reversed
itself in the second quarter of 2007 with a $13.3 million non-cash mark-to-market pre-tax gain, or
a net charge of $21.8 million for the six month period, all primarily related to our 2007 natural
gas swaps and the changes in quarter-end
18
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
natural gas price futures. During the 2006 periods, we
recorded a non-cash mark-to-market charge to earnings of $10.9 million in the first quarter and a
$9.3 million charge in the second, or a total charge of $20.2 million during the first half of
2006, all related to our oil derivative contracts in place at that time. The difference in these
mark-to-market value adjustments was most pronounced in the second quarter comparison as the 2007 period included a
$13.3 million gain and the 2006 period included a $9.3 million expense, a net difference of $22.6
million on a pre-tax basis.
The net result was net income of $62.6 million during the second quarter of 2007 as compared
to $44.3 million during the second quarter of 2006 as the higher production levels, higher
commodity prices and non-cash mark-to-market value adjustments to income more than offset the other
higher expenses. On a six month basis, net income was $79.2 million during the first half of 2007
as compared to $88.0 million during the first half of 2006 as the higher production in 2007 was
more than offset by lower commodity prices and higher expenses than in the first half of 2006.
While overall costs were higher in the 2007 periods than in the comparable 2006 periods,
during 2007 the rate of inflation in our industry appears to have moderated, and in some cases, we
are beginning to see modest cost reductions. Likewise, although goods and services are still in
tight supply, there have been signs of improvement in overall
availability; but some supply issues persist,
including long lead times for certain items, such as compressors used in our tertiary recycle
facilities and construction services for pipelines. It is difficult to forecast price trends and
supply and service availability, which if adverse, can significantly impact both operating costs
and capital expenditures, as well as cause delays in achieving our anticipated production targets.
Overview of tertiary operations. Since we acquired our first carbon dioxide tertiary flood in
Mississippi in 1999, we have gradually increased our emphasis on these types of operations. We
particularly like this play because of its risk profile, rate of return and lack of competition in
our operating area. Generally, from East Texas to Florida, there are no known significant natural
sources of carbon dioxide except our own, and these large volumes of CO2 that we own
drive the play. Please refer to the section entitled CO2 Operations below and
contained in Managements Discussion and Analysis of Financial Condition and Results of Operations
in our 2006 Form 10-K for further information regarding these operations, their potential, and the
ramifications of this focus.
Oil production from our tertiary operations increased to an average of 13,683 BOE/d in the
second quarter of 2007, a 32% increase over the second quarter 2006 tertiary production level of
10,375 BOE/d and a 16% increase over the first quarter 2007 tertiary production level. Production from our
Phase II operations in eastern Mississippi (Soso, Eucutta and Martinville Fields) contributed 2,229
BOE/d (approximately two-thirds) to the increase over the prior years second quarter production,
with the balance of the increase coming from our Phase I fields, except Little Creek Field which is
on a gradual decline.
Proposed sale of Louisiana assets. In late May 2007, we announced that we were evaluating
strategic alternatives for our Louisiana assets, other than our Louisiana oil properties that have
potential for tertiary recovery operations. We have engaged an advisor and in early August we plan
to open a data room for a potential sale. Assuming that we achieve bids for these properties that
are acceptable to us, closing would likely occur early in the fourth quarter. Production from the
properties that are currently being considered for sale averaged approximately 28.8 MMcfe/d (85%
natural gas) during the second quarter of 2007.
Recent Acquisition by Genesis Energy. On July 25, 2007, Genesis Energy, L.P. (Genesis), a
master limited partnership of which Denbury is the general partner, closed on a previously
announced acquisition in which they acquired several energy related businesses from the Davison
family of Ruston, Louisiana for total consideration of approximately $563 million, plus payment of
approximately $35.1 million for certain purchase price adjustments and for estimated working
capital of the sellers. These businesses include a trucking operation for petroleum products and
other bulk commodities, terminal storage of refined petroleum products, a refinery service
operation which processes sour gas streams at several refining operations, and a wholesale
petroleum products marketing business. Approximately one-half of the acquisition was funded by
debt from Genesis bank credit facility and approximately one-half through the issuance of Genesis
common units to the seller. In conjunction with that acquisition, we exercised our right to
maintain our pro rata (7.4%) ownership of common units, acquiring 1,074,882 additional common units
for approximately $22.4 million, in addition to our capital contribution of an additional $6.2
million as general partner to maintain our 2% general partners capital interest.
19
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
We have previously discussed with Genesis that upon Genesis achieving certain goals, primarily
the acquisition of other economic projects that are not related to Denbury, that we would undertake
to drop-down certain Denbury assets to Genesis based upon acquisition by Genesis of $1.50 of
non-Denbury-related acquisitions for every $1.00 of sales from Denbury. These drop-down
transactions are currently thought most likely to consist of property sales combined with
associated transportation or service arrangements or direct financing leases, or a combination of
both. As a result of the recent Genesis acquisition, we anticipate that during 2007, we will enter
into drop-down transactions with Genesis involving our existing CO2 pipelines, with a
total currently estimated value of between $200 million and $250 million. These drop-down
transactions would be subject to, among other things, negotiation of specific terms, the approval
of the board of directors of both entities, and the receipt of fairness opinions by both companies,
and is expected to occur early in the fourth quarter of 2007. We would anticipate similar
transactions with Genesis for the new CO2 pipeline we are constructing from Jackson Dome
to Tinsley and Delhi Fields once that pipeline is completed, forecasted at this time to be during
2008. If in future periods Genesis is able to complete additional acquisitions of sufficient size
with acceptable economic returns, and subject to the same types of conditions, we would anticipate
similar transactions with Genesis with our proposed 280 to 300 mile CO2 pipeline from
Southern Louisiana to Hastings Field, located near Houston, Texas, probably during 2010.
Recent Acquisition. On March 30, 2007, we completed an acquisition of six producing oil and
natural gas fields, two of which are future potential CO2 tertiary oil flood candidates,
collectively called the Seabreeze Complex, located near Houston, Texas, at a cost of approximately
$41.7 million. Tertiary operations are not expected to commence at these fields until 2010 or
2011, following anticipated completion of the 280 to 300 mile CO2 pipeline from
Louisiana to Hastings Field (also near Houston). The acquisition was funded with bank financing
under our existing credit facility. At the time of acquisition, these fields were producing
approximately 400 BOE/d net to the acquired interests, and had estimated proved conventional
reserves of approximately 525 MBOE. We operate all of these fields and own the majority of the
working interests.
April 2007 Debt Issuance. On April 3, 2007, we issued $150 million of 7.5% Senior
Subordinated Notes due 2015 as an additional issuance under our existing indenture governing our
December 2005 sale of $150 million of 7.5% Senior Subordinated Notes due 2015. The notes were
issued at 100.5% of par, which equates to an effective yield to maturity of 7.4%. The net proceeds
from the sale were approximately $149.2 million, which we used to repay a portion of the
outstanding borrowings under our bank credit facility.
Capital Resources and Liquidity
Our current 2007 capital exploration and development budget is $690 million, excluding any
acquisitions. We expect to spend approximately 60% of our 2007 budget on tertiary related
operations, approximately 20% in the Barnett Shale area, and less than 10% on exploration projects,
with the balance spent on our conventional properties in Mississippi and Louisiana. This capital
program includes an estimated $110 million (of an anticipated $150 million) for a CO2
pipeline from our CO2 source at Jackson Dome to Tinsley and Delhi Fields, two oil fields
acquired during 2006. Based on oil and natural gas commodity futures prices as of the end of July
2007, our capital budget is $175 million to $225 million greater than our anticipated cash flow
from operations, a much greater shortfall than we have had in recent years. We plan to fund most,
if not all, of this entire shortfall through transactions with Genesis whereby we would drop-down
our two existing significant CO2 pipelines to them (see Overview Recent Acquisition
by Genesis Energy). Alternatively, if a sale of our Louisiana assets is consummated (see
Overview Proposed sale of Louisiana assets), depending on the net proceeds therefrom, which is
difficult to forecast, those proceeds could also fund our anticipated cash shortfall. If neither
transaction is completed, we would plan to fund the cash shortfall with bank debt and could
potentially reduce our capital budget later in the year.
As of July 31, 2007, we had $200 million of bank debt outstanding on a $500 million borrowing
base, leaving us significant incremental borrowing capacity, more than we currently plan or desire
to use, particularly considering the potential for significant cash proceeds later this year from
the above contemplated transactions.
We monitor our capital expenditures on a regular basis, adjusting them up or down depending on
commodity prices and the resultant cash flow. Therefore, during the last few years as commodity
prices have increased, we have increased our capital budget throughout the year. As a result of
the recent cost inflation in our industry, many of our recent budget increases have related to
escalating costs rather than additional projects. Even though there are signs that the rate of
this
20
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
inflationary trend is subsiding, if costs do rise or we spend more than our estimated or
forecasted amounts, we will either have to increase our capital budget or consider the elimination
of a portion of our planned projects.
We continue to pursue additional acquisitions of mature oil fields that we believe have
potential as future tertiary flood candidates. These possible acquisitions are difficult to
forecast and the purchase price can vary widely depending on the levels of existing production and
conventional proved reserves and commodity prices. Any additional acquisitions would be funded, at
least temporarily, with bank or other debt, although if significant, the acquisition would likely
be ultimately funded with more permanent capital such as subordinated debt and/or additional
equity.
Amendment to our bank credit facility. On March 31, 2007, we amended our Sixth Amended and
Restated Credit Agreement with our nine banks, led by JPMorgan Chase Bank, N.A., as administrative
agent. The amendment (i) increased the commitment amount that the banks are committed to fund from
$250 million to $350 million, (ii) reconfirmed the borrowing base of $500 million, (iii) authorized
the $150 million subordinated debt offering (see Overview April 2007 Debt Issuance), and (iv) authorized us to enter into a sale-leaseback type
transaction for our CO2 pipelines, not to exceed $300 million, with Genesis, in the type
of transaction contemplated and discussed above (see Overview Recent Acquisition by Genesis).
With regard to our bank credit facility, the borrowing base represents the amount that can be
borrowed from a credit standpoint based on our assets, as confirmed by the banks, while the
commitment amount is the amount the banks have committed to fund pursuant to the terms of the
credit agreement. The banks have the option to participate in any borrowing request by us in
excess of the commitment amount ($350 million), up to the borrowing base limit ($500 million),
although the banks are not obligated to fund any amount in excess of the commitment amount. At
July 31, 2007, we had outstanding $525 million (principal amount) of 7.5% subordinated notes and
$200 million of bank debt.
Sources and Uses of Capital Resources
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
|
June 30, |
|
Amounts in thousands |
|
2007 |
|
|
2006 |
|
Capital expenditures |
|
|
|
|
|
|
|
|
Oil and gas exploration and development |
|
|
|
|
|
|
|
|
Drilling |
|
$ |
159,448 |
|
|
$ |
102,058 |
|
Geological, geophysical and acreage |
|
|
10,558 |
|
|
|
17,008 |
|
Pipelines and facilities |
|
|
56,259 |
|
|
|
64,296 |
|
Recompletions |
|
|
64,988 |
|
|
|
64,004 |
|
Capitalized
interest |
|
|
8,056 |
|
|
|
2,735 |
|
|
|
|
|
|
|
|
Total oil and gas exploration and development expenditures |
|
|
299,309 |
|
|
|
250,101 |
|
Oil and gas property acquisitions |
|
|
46,660 |
|
|
|
314,335 |
|
|
|
|
|
|
|
|
Total oil and natural gas capital expenditures |
|
|
345,969 |
|
|
|
564,436 |
|
CO2 capital expenditures, including capitalized interest |
|
|
68,427 |
|
|
|
28,167 |
|
|
|
|
|
|
|
|
Total |
|
$ |
414,396 |
|
|
$ |
592,603 |
|
|
|
|
|
|
|
|
Our 2007 capital expenditures have been funded with $195.6 million of cash flow from
operations, $150.0 million from our issuance of subordinated debt in April, $36.0 million of net
bank borrowings, and the balance funded with working capital. Adjusted cash flow from operations
(a non-GAAP measure defined as cash flow from operations before changes in assets and liabilities
as discussed below under Results of Operations Operating Results) was $234.7 million for the
first six months of 2007, while cash flow from operations for the same period, the GAAP measure,
was $195.6 million.
Our 2006 expenditures were funded with $208.9 million of cash flow from operations, $132.3
million of equity issued and $70 million of net bank borrowings, with the balance funded from cash
and other sources, including funds remaining from our December 2005 issuance of $150 million of
subordinated debt.
21
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Off-Balance Sheet Arrangements
Commitments and Obligations
Our obligations that are not currently recorded on our balance sheet consist of our operating
leases and various obligations for development and exploratory expenditures arising from purchase
agreements, our capital expenditure program, or other transactions common to our industry. In
addition, in order to recover our proved undeveloped reserves, we must also fund the associated
future development costs as forecasted in the proved reserve reports. Our derivative contracts are
discussed in Note 6 to the Unaudited Condensed Consolidated Financial Statements. Neither the
amounts nor the terms of these commitments or contingent obligations have changed significantly
from the year-end 2006 amounts reflected in our Form 10-K filed on March 1, 2007, except for (i) a
commitment to a new building lease expected to commence in mid-2008 representing future payments of
approximately $20 million over 136 months and (ii) additional commitments discussed below to
purchase anthropogenic (manufactured) CO2 from proposed gasification plants, if they are
built.
We currently have long-term commitments to purchase manufactured CO2 from three
proposed gasification plants, if these plants are built, two proposed by the developers of the
Faustina Hydrogen Products LLC and another by Rentech Inc. If all three plants are built, these
synthetic sources are currently anticipated to provide us with an aggregate of 750 MMcf/d to 850
MMcf/d of CO2 by 2012. The base price of CO2 per Mcf from these synthetic
sources is currently expected to be 1.5 to 2.0 times higher than our most recent all-in cost of
CO2 from natural sources (Jackson Dome) using current oil prices and assuming comparable
compression levels. These predicted synthetic CO2 prices are expected to be competitive
with the cost of our natural CO2 after adjusting for our share of potential carbon
emissions credits using estimated current prices of CO2 carbon credit futures. If all
three plants are built, the aggregate purchase obligation for this CO2 would be around
$150 million per year at current oil prices and assuming comparable compression levels, before any
potential savings from our share of carbon emissions 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, although the initial Faustina plant is currently scheduled to begin
construction in late 2007 or early 2008, with completion scheduled in late 2010.
Please refer to Managements Discussion and Analysis of Financial Condition and Results of
Operations Off-Balance Sheet Arrangements Commitments and Obligations contained in our 2006
Form 10-K for further information regarding our commitments and obligations.
Results of Operations
CO2 Operations
Our focus on CO2 operations is becoming an ever-increasing part of our business and
operations. We believe that there are significant additional oil reserves and production that can
be obtained through the use of CO2, and we have outlined certain of this potential in
our annual report and other public disclosures. In addition to its long-term effect, our focus on
these types of operations impacts certain trends in our current and near-term operating results.
Please refer to Managements Discussion and Analysis of Financial Condition and Results of
Operations and the section entitled CO2 Operations contained in our 2006 Form 10-K
for further information regarding these matters.
During the remainder of 2007 we plan to drill additional CO2 source wells to
further increase our production capacity and reserves. We estimate that we are currently capable
of producing between 650 MMcf/d and 700 MMcf/d of CO2. During the second quarter of
2007, our CO2 production averaged 477 MMcf/d, as compared to an average of approximately
448 MMcf/d during the first quarter of 2007, and average production of 290 MMcf/d during the first
half of 2006. We used 81% of this production, or 387 MMcf/d, in our tertiary operations during the
second quarter of 2007, and sold the balance to our industrial customers or to Genesis pursuant to
our volumetric production payments.
Our oil production from tertiary operations increased to an average of 13,683 BOE/d in the
second quarter of 2007, a 32% increase over the second quarter of 2006 tertiary production level of
10,375 BOE/d, and a 16% increase over the first quarter of 2007 tertiary production levels. The
table below shows our tertiary oil production by field for the first and second quarters of 2007
and all four quarters of 2006. We saw continued improved response from our newer floods at
Smithdale, Martinville, Eucutta and Soso Fields, most of which were initiated during 2006. In
addition, we continue to
22
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
see improved response at most of our other floods, except for Little Creek
Field, which is a mature flood and is expected to continue to decline over the next several years.
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (BOE/d) |
|
|
|
First |
|
|
Second |
|
|
Third |
|
|
Fourth |
|
|
|
First |
|
|
Second |
|
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
|
Quarter |
|
|
Quarter |
|
Tertiary Oil Field |
|
2006 |
|
|
2006 |
|
|
2006 |
|
|
2006 |
|
|
|
2007 |
|
|
2007 |
|
|
|
|
|
Phase I: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brookhaven |
|
|
547 |
|
|
|
798 |
|
|
|
965 |
|
|
|
1,014 |
|
|
|
|
1,422 |
|
|
|
1,794 |
|
Little Creek & Lazy Creek |
|
|
3,006 |
|
|
|
3,056 |
|
|
|
2,623 |
|
|
|
2,279 |
|
|
|
|
2,117 |
|
|
|
1,974 |
|
Mallalieu (East and West) |
|
|
5,219 |
|
|
|
5,385 |
|
|
|
5,243 |
|
|
|
4,994 |
|
|
|
|
5,470 |
|
|
|
5,802 |
|
McComb & Olive |
|
|
932 |
|
|
|
1,062 |
|
|
|
1,242 |
|
|
|
1,467 |
|
|
|
|
1,497 |
|
|
|
1,257 |
|
Smithdale |
|
|
54 |
|
|
|
74 |
|
|
|
41 |
|
|
|
63 |
|
|
|
|
314 |
|
|
|
627 |
|
Phase II: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Martinville |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24 |
|
|
|
|
320 |
|
|
|
521 |
|
Eucutta |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
187 |
|
|
|
|
614 |
|
|
|
1,338 |
|
Soso |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25 |
|
|
|
370 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total tertiary oil production |
|
|
9,758 |
|
|
|
10,375 |
|
|
|
10,114 |
|
|
|
10,028 |
|
|
|
|
11,779 |
|
|
|
13,683 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We spent approximately $0.19 per Mcf to produce our CO2 during the first half of
2007, about the same as the 2006 first six months average of $0.20 per Mcf. Our estimated total
cost per thousand cubic feet of CO2 during the first half of 2007 was approximately
$0.27, after inclusion of depreciation and amortization expense, down slightly from the 2006
average of $0.29 per Mcf. On a quarterly basis, we spent approximately $0.21 per Mcf to produce
our CO2 during the second quarter of 2007, the same rate as the 2006 second quarter
average, and in the same range as the six month amounts. Our estimated total cost per thousand
cubic feet of CO2 during the second quarter of 2007 was approximately $0.29, after
inclusion of depreciation and amortization expense.
For the first half of 2007, our operating costs for our tertiary properties averaged $20.38
per BOE, higher than the prior years first half average of $16.26 per BOE, but slightly lower than
our fourth quarter 2006 average of $20.58 per BOE. The higher costs are primarily due to general
cost inflation in the industry and the new floods initiated last year, which resulted in higher
CO2 costs, higher fuel and energy costs and higher rental payments on leased equipment.
Because we expense all lease operating costs, including injection costs, associated with starting a
new flood, we expect the lease operating expense per BOE for tertiary operations to initially be
high, until production increases significantly. For example, for the first half of 2007, operating
costs per BOE for our Phase I properties, which are generally more developed than our Phase II
properties, were $17.29 per BOE, as compared to tertiary operating costs of $40.54 per BOE for
Phase II, an area which first responded in late 2006. In comparison, our operating costs for
Mallalieu Field, currently our highest volume tertiary producer, was $10.79 per BOE during the same
period. We expect our operating costs to average between $13 and $15 per BOE over the life of a
tertiary flood, even though our recent average tertiary operating costs have been higher, as we
continue to implement additional floods.
Operating Results
As summarized in the Overview section above and discussed in more detail below, for the
second quarter of 2007, higher production, higher commodity prices, and favorable non-cash
mark-to-market value adjustments to income more than offset higher expenses, resulting in
near-record quarterly earnings and cash flow from operations. On a six month basis, higher
production was more than offset by lower commodity prices and higher expenses than in the first
half of 2006, resulting in a slight decrease in net income during the 2007 six month period.
23
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
Amounts in thousands, except per share amounts |
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
Net income |
|
$ |
62,567 |
|
|
$ |
44,262 |
|
|
$ |
79,183 |
|
|
$ |
88,040 |
|
Net income per common share basic |
|
|
0.52 |
|
|
|
0.38 |
|
|
|
0.66 |
|
|
|
0.77 |
|
Net income per common share diluted |
|
|
0.50 |
|
|
|
0.36 |
|
|
|
0.63 |
|
|
|
0.72 |
|
Adjusted cash flow from operations (see below) |
|
$ |
130,493 |
|
|
$ |
128,793 |
|
|
$ |
234,720 |
|
|
$ |
236,642 |
|
Net change in assets and liabilities relating to
operations |
|
|
(28,241 |
) |
|
|
(22,376 |
) |
|
|
(39,123 |
) |
|
|
(27,713 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from operations (1) |
|
$ |
102,252 |
|
|
$ |
106,417 |
|
|
$ |
195,597 |
|
|
$ |
208,929 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Net cash flow provided by operations as per the Unaudited Condensed Consolidated Statements
of Cash Flows. |
Adjusted cash flow from operations is a non-GAAP measure that represents cash flow provided by
operations before changes in assets and liabilities, as calculated from our Unaudited Condensed
Consolidated Statements of Cash Flows. Cash flow from operations is the GAAP measure as presented
in our Unaudited Condensed Consolidated Statements of Cash Flows. In our discussion herein, we
have elected to discuss these two components of cash flow provided by operations separately.
Adjusted cash flow from operations, a non-GAAP measure, is the cash flow earned or incurred
from operating activities without regard to the collection or payment of associated receivables or
payables. We believe it is important to consider adjusted cash flow from operations separately, as
we believe it can often be a better way to discuss changes in operating trends in our business
caused by changes in production, prices, operating costs, and related operational factors, without
regard to whether the earned or incurred item was collected or paid during that year. We also use
this measure because the collection of our receivables or payment of our obligations has not been a
significant issue for our business, but merely a timing issue from one period to the next, with
fluctuations generally caused by significant changes in commodity prices or significant changes in
drilling activity. Adjusted cash flow from operations is not a measure of financial performance
under GAAP and should not be considered as an alternative to cash flows from operations, investing,
or financing activities, nor as a liquidity measure or indicator of cash flows.
The net change in assets and liabilities relating to operations is also important as it does
require or provide additional cash for use in our business; however, we prefer to discuss its
effect separately. For instance, as noted above, during all the periods, we used cash to fund a
net increase in our other working capital items. During 2007, this was primarily caused by an
increase in trade and production receivables as a result of our increased production volumes and
higher level of activity, coupled with a decrease in our payables. During the first half of 2006,
this was primarily caused by a decrease in our payables, partially offset by an increase in our
receivables.
Certain of our operating results and statistics for the comparative second quarters and first
six months of 2007 and 2006 are included in the following table.
24
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
Average daily production volumes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bbls/d |
|
|
26,172 |
|
|
|
23,362 |
|
|
|
25,119 |
|
|
|
22,790 |
|
Mcf/d |
|
|
94,459 |
|
|
|
84,671 |
|
|
|
90,007 |
|
|
|
82,076 |
|
BOE/d (1) |
|
|
41,916 |
|
|
|
37,474 |
|
|
|
40,120 |
|
|
|
36,469 |
|
Operating revenues (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
151,178 |
|
|
$ |
136,118 |
|
|
$ |
269,310 |
|
|
$ |
249,559 |
|
Natural gas sales |
|
|
66,301 |
|
|
|
53,286 |
|
|
|
117,303 |
|
|
|
115,388 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas sales |
|
$ |
217,479 |
|
|
$ |
189,404 |
|
|
$ |
386,613 |
|
|
$ |
364,947 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas derivative contracts (2) (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash receipt (payment) on settlement of derivative
contracts |
|
$ |
1,719 |
|
|
$ |
(2,212 |
) |
|
$ |
9,970 |
|
|
$ |
(2,980 |
) |
Non-cash fair value adjustment income (expense) |
|
|
13,330 |
|
|
|
(9,317 |
) |
|
|
(21,828 |
) |
|
|
(20,179 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income (expense) from oil and gas derivative contracts |
|
$ |
15,049 |
|
|
$ |
(11,529 |
) |
|
$ |
(11,858 |
) |
|
$ |
(23,159 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
57,207 |
|
|
$ |
41,751 |
|
|
$ |
107,764 |
|
|
$ |
77,923 |
|
Production taxes and marketing expenses |
|
|
10,386 |
|
|
|
9,436 |
|
|
|
20,590 |
|
|
|
17,523 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production expenses (3) |
|
$ |
67,593 |
|
|
$ |
51,187 |
|
|
$ |
128,354 |
|
|
$ |
95,446 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-tertiary CO2 operating margin (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2 sales and transportation fees (4) |
|
$ |
3,394 |
|
|
$ |
2,374 |
|
|
$ |
6,485 |
|
|
$ |
4,362 |
|
CO2 operating expenses |
|
|
1,204 |
|
|
|
785 |
|
|
|
1,907 |
|
|
|
1,430 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2 operating margin |
|
$ |
2,190 |
|
|
$ |
1,589 |
|
|
$ |
4,578 |
|
|
$ |
2,932 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit prices including impact of derivative settlements (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
63.01 |
|
|
$ |
62.99 |
|
|
$ |
59.02 |
|
|
$ |
59.78 |
|
Gas price per Mcf |
|
|
8.04 |
|
|
|
6.92 |
|
|
|
7.87 |
|
|
|
7.77 |
|
Unit prices excluding impact of derivative settlements (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
63.48 |
|
|
$ |
64.03 |
|
|
$ |
59.23 |
|
|
$ |
60.50 |
|
Gas price per Mcf |
|
|
7.71 |
|
|
|
6.92 |
|
|
|
7.20 |
|
|
|
7.77 |
|
Oil and gas operating revenues and expenses per BOE (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenues |
|
$ |
57.02 |
|
|
$ |
55.54 |
|
|
$ |
53.24 |
|
|
$ |
55.29 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas lease operating expenses |
|
$ |
15.00 |
|
|
$ |
12.24 |
|
|
$ |
14.84 |
|
|
$ |
11.80 |
|
Oil and gas production taxes and marketing expense |
|
|
2.72 |
|
|
|
2.77 |
|
|
|
2.84 |
|
|
|
2.65 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas production expenses |
|
$ |
17.72 |
|
|
$ |
15.01 |
|
|
$ |
17.68 |
|
|
$ |
14.45 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 $1.1 million for the three month periods ended June 30,
2007 and 2006, and $2.0 million for each of the six month periods ended June 30, 2007 and 2006, associated with volumetric production
payments with Genesis. Also includes transportation income from Genesis of $1.2 million for each of
the three month periods ended June 30, 2007 and 2006, and $2.3 million and $2.2 million for the six
months ended June 30, 2007 and 2006, respectively. |
25
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Production: Production by area for each of the quarters of 2006 and the first and second
quarters of 2007 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 |
|
2006 |
|
|
2006 |
|
|
2006 |
|
|
2006 |
|
|
|
2007 |
|
|
2007 |
|
|
|
|
|
|
|
Mississippi non-CO2 floods |
|
|
12,455 |
|
|
|
12,633 |
|
|
|
13,069 |
|
|
|
12,808 |
|
|
|
|
12,738 |
|
|
|
12,525 |
|
Mississippi CO2 floods |
|
|
9,758 |
|
|
|
10,375 |
|
|
|
10,114 |
|
|
|
10,028 |
|
|
|
|
11,779 |
|
|
|
13,683 |
|
Onshore Louisiana |
|
|
8,349 |
|
|
|
8,623 |
|
|
|
8,221 |
|
|
|
6,572 |
|
|
|
|
5,591 |
|
|
|
5,391 |
|
Texas |
|
|
3,953 |
|
|
|
4,621 |
|
|
|
4,952 |
|
|
|
5,925 |
|
|
|
|
6,989 |
|
|
|
9,048 |
|
Alabama and other |
|
|
939 |
|
|
|
1,222 |
|
|
|
1,205 |
|
|
|
1,286 |
|
|
|
|
1,208 |
|
|
|
1,269 |
|
|
|
|
|
|
|
Total Company |
|
|
35,454 |
|
|
|
37,474 |
|
|
|
37,561 |
|
|
|
36,619 |
|
|
|
|
38,305 |
|
|
|
41,916 |
|
|
|
|
|
|
|
As outlined in the above table, production in the second quarter of 2007 increased 12% (4,442
BOE/d) over second quarter of 2006 levels, 9% over the first quarter 2007 levels, and 10% in the
first six months of 2007 compared to production in the first six months of 2006. These increases
from the 2006 periods are primarily due to increased production from our tertiary operations and
the Barnett Shale, offset in part by decreases in our onshore Louisiana wells. The increase in our
tertiary operations is discussed above under Results of Operations CO2 Operations.
Production in the Mississippi non-CO2 floods area was approximately the same as
the prior years second quarter and down only slightly from the first quarter of 2007 level, as our
continued drilling activity developing the Selma Chalk natural gas reservoir in the Heidelberg area
has helped offset the gradual declines in oil production.
Our second quarter 2007 Barnett Shale production increased approximately 81%, to 8,368 BOE/d,
from the prior year quarters level due to our successful drilling activity over the last year.
During 2006, we drilled 46 horizontal wells and we drilled and completed 19 wells in the first half
of 2007. We had four rigs working in the area during most of the first quarter of 2007, but have
recently reduced our rig count in this area to three, which we plan to retain for the remainder of
2007. We do not anticipate any significant production increases from the Barnett Shale during the
remainder of 2007, although production should not decline significantly with the ongoing activity
of three drilling rigs.
The decrease in onshore Louisiana production in 2007 is due primarily to the expected
relatively rapid depletion of wells in this area. Since 2005 we have focused less of our spending
in this area and therefore drilled fewer wells than we have historically. We are pursuing the
potential divesture of these assets, excluding any oil fields that could have tertiary oil
potential (See Overview Potential sale of Louisiana assets).
The Texas property acquisition we made late in the first quarter of 2007 (see Overview
Recent Acquisition) contributed approximately 680 BOE/d to the second quarter 2007 production,
shown in the above table.
Our production for the second quarter of 2007 was weighted toward oil (62%), about the same as
our proportion of oil production during the second quarter of 2006, as the recent increases in
natural gas production in the Barnett Shale area, offset by declines in natural gas production in
Louisiana, generally have been matched by increases in our tertiary oil production.
Oil and Natural Gas Revenues: Oil and natural gas revenues for the second quarter of 2007
increased $28.1 million, or 15%, from revenues in the comparable quarter of 2006, as both commodity
prices and production were higher. The increase in overall commodity prices in the second quarter
of 2007 increased revenues by $5.6 million, or 3%, while the increase in production in the second
quarter of 2007 increased oil and natural gas revenues by $22.5 million, or 12%, over the prior
years second quarter levels. When comparing the respective six month periods, revenues increased
$21.7 million, or 6%, as higher production was partially offset by lower commodity prices. The
increase in production during the first half of 2007 increased revenues by $36.5 million, or 10%,
while the decrease in overall commodity prices during the first half of 2007 decreased oil and
natural gas revenues by $14.8 million, or 4% over the prior years first half.
26
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Excluding any impact of our derivative contracts, our net realized commodity prices and NYMEX
differentials were as follows during the first and second quarters and first six months periods of
2006 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
March 31, |
|
|
June 30, |
|
|
June 30, |
|
|
|
2007 |
|
|
2006 |
|
|
% Change |
|
|
2007 |
|
|
2006 |
|
|
% Change |
|
|
2007 |
|
|
2006 |
|
|
% Change |
|
Net Realized Prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
54.57 |
|
|
$ |
56.75 |
|
|
|
-4 |
% |
|
$ |
63.48 |
|
|
$ |
64.03 |
|
|
|
-1 |
% |
|
$ |
59.23 |
|
|
$ |
60.50 |
|
|
|
-2 |
% |
Gas price per Mcf |
|
|
6.63 |
|
|
|
8.68 |
|
|
|
-24 |
% |
|
|
7.71 |
|
|
|
6.92 |
|
|
|
11 |
% |
|
|
7.20 |
|
|
|
7.77 |
|
|
|
-7 |
% |
Price per BOE |
|
|
49.06 |
|
|
|
55.01 |
|
|
|
-11 |
% |
|
|
57.02 |
|
|
|
55.54 |
|
|
|
3 |
% |
|
|
53.24 |
|
|
|
55.29 |
|
|
|
-4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX differentials: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil per Bbl |
|
$ |
(3.73 |
) |
|
$ |
(6.71 |
) |
|
|
-44 |
% |
|
$ |
(1.61 |
) |
|
$ |
(6.64 |
) |
|
|
-76 |
% |
|
$ |
(2.47 |
) |
|
$ |
(6.58 |
) |
|
|
-62 |
% |
Natural Gas per Mcf |
|
|
(0.51 |
) |
|
|
0.78 |
|
|
|
-165 |
% |
|
|
0.07 |
|
|
|
0.25 |
|
|
|
-72 |
% |
|
|
(0.19 |
) |
|
|
0.49 |
|
|
|
-139 |
% |
Our oil NYMEX differential during the second quarter of 2007 was the lowest in our
corporate history. The improved NYMEX differential during 2007 was related to higher prices
received for both our light sweet barrels and our sour barrels primarily as a result of NYMEX (WTI)
prices being depressed due to lack of available storage capacity in the mid-continent area, an
oversupply of crude from Canada, capacity/transportation issues in moving crude oil out of the
Cushing, Oklahoma area and unanticipated refinery outages. There are preliminary indications that
this trend is reversing itself in the third quarter and that our differentials have begun to return
to historic levels, based on prices to date during July 2007.
Our natural gas NYMEX differentials are generally caused by movement in the NYMEX natural gas
prices during a month as most of our natural gas is sold on an index price that is set near the
first of the month. While the percentage change in the above table is quite large, these
differentials are very seldom more than a dollar above or below the NYMEX amount.
Oil and Natural Gas Derivative Contracts: During the first half of 2007, although we had
significant fluctuations related to our non-cash mark-to-market value adjustments in our oil and
natural gas derivative contracts (a $35.2 million expense in the first quarter and income of $13.3
million in the second quarter) (see also Overview Results of Operations and Market Risk
Management), we had net positive cash receipts during each quarter in 2007 from these derivative
contracts. We received approximately $8.3 million in net settlements during the first quarter of
2007 and approximately $1.7 million during the second quarter, primarily related to our 2007
natural gas swaps. In comparison, we paid out approximately $0.8 million during the first quarter
of 2006 and $2.2 million during the second quarter of 2006 related to our oil swaps in existence at
that time.
Production Expenses: Our lease operating expenses increased between the comparable
first six months and second quarters on both a per BOE basis and in absolute dollars, primarily as
a result of (i) our increasing emphasis on tertiary operations (see discussion of those expenses
under CO2 Operations above), (ii) higher overall industry costs, (iii) increased
personnel and related costs, (iv) higher fuel and energy costs to operate our tertiary properties,
(v) increasing lease payments for certain of our tertiary operating facilities, and (vi) higher
workover costs.
During the second quarter of 2007, operating costs averaged $15.00 per BOE, up from $12.24 per
BOE in the second quarter of 2006, and up from the $14.66 per BOE in the first quarter of 2007.
Operating expenses on our tertiary operations increased from $17.41 per BOE in the second quarter
of 2006 to $20.47 per BOE during the second quarter of 2007, as a result of the increased number of
tertiary floods in their initial stages. Tertiary operating expenses were particularly impacted by
higher power and energy costs, expenses on new floods in the initial stages of their production
response, and payments on leased facilities and equipment (see CO2 Operations above).
Our emphasis on tertiary operations is expected to continue, which may further increase our cost
per BOE as tertiary production becomes a more significant portion of our total production and
operations. The trends were similar when comparing the respective first half periods.
27
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Production taxes and marketing expenses generally change in proportion to commodity prices and
production volumes and therefore were higher in the second quarter of 2007 than in the comparable
quarter of 2006. Transportation and plant processing fees were approximately $1.7 million higher
in the second quarter of 2007 than in the second quarter of 2006 and approximately $3.2 million
higher for the first half of 2007 than in the first half of 2006.
General and Administrative Expenses
Net general and administrative (G&A) expenses decreased 20% between the respective second
quarters and 5% between the respective first six months, as set forth below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
Net G&A expense (thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross G&A expenses |
|
$ |
28,372 |
|
|
$ |
27,255 |
|
|
$ |
55,142 |
|
|
$ |
48,595 |
|
State franchise taxes |
|
|
740 |
|
|
|
282 |
|
|
|
1,458 |
|
|
|
694 |
|
Operator labor and
overhead recovery charges |
|
|
(14,894 |
) |
|
|
(11,176 |
) |
|
|
(28,700 |
) |
|
|
(21,085 |
) |
Capitalized exploration
and development costs |
|
|
(2,524 |
) |
|
|
(1,787 |
) |
|
|
(4,772 |
) |
|
|
(3,763 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net G&A expense |
|
$ |
11,694 |
|
|
$ |
14,574 |
|
|
$ |
23,128 |
|
|
$ |
24,441 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average G&A cost per BOE |
|
$ |
3.07 |
|
|
$ |
4.27 |
|
|
$ |
3.18 |
|
|
$ |
3.70 |
|
Employees as of June 30 |
|
|
672 |
|
|
|
550 |
|
|
|
672 |
|
|
|
550 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
G&A expenses increased $1.1 million, or 4%, between the respective second quarters and
$6.5 million and 13% between the respective first six months. These increases are primarily due to
higher compensation and personnel related costs caused by an increase in the number of employees,
higher wages resulting from the 5% mid-year pay increase for all employees in mid-2006, and 2006
year end pay increases which averaged 4.4%. During 2006, we increased our employee count by 30%
and we further increased our employee count 13% in the first half of 2007. Partially offsetting
these overall compensation increases was a $5.3 million charge to earnings in the second quarter of
2006 related to the modification of the vesting terms of certain restricted stock and stock options
previously granted to our former Senior Vice President of Operations, associated with his departure
from the Company. Stock compensation expense reflected in gross G&A expenses was approximately
$3.0 million in the second quarter of 2007 and $6.1 million for the six months ended June 30, 2007.
Stock compensation expense, excluding the $5.3 million charge
discussed above, was $3.4 million for the second quarter of 2006 and $6.8 million for the six months
ended June 30, 2006. Due to increased competitive pressures in the industry, our wages are
increasing at a rate higher than general inflation and we expect this trend to continue. As such,
we granted a 2% pay raise to all employees effective July 1, 2007.
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 2007. 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 33% between the second quarters of 2006
and 2007 and increased by 36%
between the first six months of 2006 and 2007. Capitalized exploration costs also increased by 41%
between the second quarters of 2006 and 2007 and increased by 27% between the first six months of
2006 and 2007, primarily as a result of increases in personnel and compensation costs.
The net effect was a 20% decrease in net G&A expense between the respective second quarters
and a 5% decrease between the first six months of 2007 and 2006. On a per BOE basis, G&A costs
decreased 28% in the second quarter of 2007 as compared to levels in the second quarter of 2006,
and decreased 14% between the comparative first six months of 2007 and 2006.
28
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, |
|
Amounts
in thousands, except per BOE amounts and interest rates |
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
Cash interest expense |
|
$ |
12,372 |
|
|
$ |
8,225 |
|
|
$ |
22,211 |
|
|
$ |
16,493 |
|
Non-cash interest expense |
|
|
305 |
|
|
|
261 |
|
|
|
574 |
|
|
|
521 |
|
Less: Capitalized interest |
|
|
(4,321 |
) |
|
|
(2,735 |
) |
|
|
(8,354 |
) |
|
|
(3,009 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
$ |
8,356 |
|
|
$ |
5,751 |
|
|
$ |
14,431 |
|
|
$ |
14,005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest and other income |
|
$ |
1,764 |
|
|
$ |
1,469 |
|
|
$ |
3,547 |
|
|
$ |
2,844 |
|
Average net cash interest expense per BOE (1) |
|
$ |
1.65 |
|
|
$ |
1.18 |
|
|
$ |
1.43 |
|
|
$ |
1.61 |
|
Average interest rate (2) |
|
|
7.6 |
% |
|
|
7.4 |
% |
|
|
7.5 |
% |
|
|
7.4 |
% |
Average debt outstanding |
|
$ |
653,303 |
|
|
$ |
443,786 |
|
|
$ |
592,284 |
|
|
$ |
445,361 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Cash interest expense less capitalized interest less interest and other income on
BOE basis. |
(2) |
|
Includes commitment fees but excludes amortization of discount and debt issue
costs. |
Interest expense increased $2.6 million, or 45%, when comparing the second quarters of
2007 and 2006, and was just slightly higher for the six months ended June 30, 2007 as compared to
the prior year six month period. Our average debt levels were significantly higher in the 2007
periods as our debt increased to fund acquisitions of properties in 2006 and 2007 and to fund our
budgeted capital spending, which in 2007 is significantly in excess of our cash flow from
operations (see also Capital Resources and Liquidity). The increase in cash interest expense was
partially offset by higher capitalized interest in the 2007 periods as indicated in the above
table, due primarily to interest capitalized on our significant unevaluated properties acquired
during 2006 and 2007.
Depletion, Depreciation and Amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
Amounts in thousands, except per BOE amounts |
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
Depletion and depreciation of oil and natural
gas properties |
|
$ |
40,977 |
|
|
$ |
32,199 |
|
|
$ |
76,943 |
|
|
$ |
61,516 |
|
Depletion and depreciation of CO2 assets |
|
|
2,762 |
|
|
|
1,891 |
|
|
|
5,442 |
|
|
|
3,680 |
|
Asset retirement obligations |
|
|
756 |
|
|
|
615 |
|
|
|
1,486 |
|
|
|
1,186 |
|
Depreciation of other fixed assets |
|
|
1,740 |
|
|
|
1,447 |
|
|
|
3,391 |
|
|
|
2,513 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total DD&A |
|
$ |
46,235 |
|
|
$ |
36,152 |
|
|
$ |
87,262 |
|
|
$ |
68,895 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A per BOE: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties |
|
$ |
10.94 |
|
|
$ |
9.62 |
|
|
$ |
10.80 |
|
|
$ |
9.50 |
|
CO2 assets and other fixed assets |
|
|
1.18 |
|
|
|
0.98 |
|
|
|
1.22 |
|
|
|
0.94 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total DD&A cost per BOE |
|
$ |
12.12 |
|
|
$ |
10.60 |
|
|
$ |
12.02 |
|
|
$ |
10.44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our depletion, depreciation and amortization (DD&A) rate for oil and natural gas properties
on a per BOE basis increased 14% between the respective second quarters and increased 14% between
the respective first six months, primarily due to capital spending and increased costs. In the
second quarter of 2007, we booked approximately 7.2 million barrels of incremental oil reserves
related to our tertiary operations in Soso and Martinville Fields and 10.7 million BOEs of
incremental reserves in our Barnett Shale area; however, the future capital costs associated with
these additions along with other capital spending and reclassification of costs into our full cost
pool resulted in a DD&A rate for our oil and natural gas properties of $10.94 per BOE in the second
quarter of 2007 as compared to $10.64 per BOE in the
29
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
first quarter of 2007 and $10.45 per BOE, in
the fourth quarter of 2006. We allocated approximately $36.1 million of the $41.7 million
preliminary adjusted purchase price of our March 31, 2007 Seabreeze acquisition to unevaluated
properties to reflect the significant probable reserves from future tertiary flooding that we
considered to be part of the acquisition. As a result, that acquisition did not materially affect
our overall DD&A rate, as the amount included in our full cost pool was at a cost per BOE
relatively consistent with our overall DD&A rate. 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.
Our DD&A rate for our CO2 and other general corporate fixed assets increased in the
first half of 2007 as compared to the rate for the first six months in 2006 as a result of costs
incurred drilling CO2 wells during the past year, putting the Free State CO2 pipeline into service late in the first quarter of 2006, and higher future development costs,
partially offset by an increase in CO2 reserves from 4.6 Tcf as of December 31, 2005, to
5.5 Tcf as of December 31, 2006 (100% working interest basis before amounts attributable to
Genesis volumetric production payments).
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
Amounts in thousands, except per BOE amounts and tax rates |
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
Current income tax expense (benefit) |
|
$ |
7,343 |
|
|
$ |
(2,349 |
) |
|
$ |
8,961 |
|
|
$ |
7,437 |
|
Deferred income tax expense |
|
|
32,567 |
|
|
|
31,675 |
|
|
|
41,581 |
|
|
|
49,859 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
$ |
39,910 |
|
|
$ |
29,326 |
|
|
$ |
50,542 |
|
|
$ |
57,296 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average income tax expense per BOE |
|
$ |
10.46 |
|
|
$ |
8.60 |
|
|
$ |
6.96 |
|
|
$ |
8.68 |
|
Effective tax rate |
|
|
38.9 |
% |
|
|
39.9 |
% |
|
|
39.0 |
% |
|
|
39.4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Our income tax provision for the second quarter and first half of 2007 and 2006 was based on
an estimated statutory tax rate of approximately 39%, adjusted for the impacts of certain items
such as compensation arising from incentive stock options that cannot be deducted for tax purposes
in the same manner as the book expense. In both periods, the current income tax expense represents
our anticipated alternative minimum cash taxes that we cannot offset with enhanced oil recovery
credits. As of December 31, 2006, we had an estimated $41.9 million of enhanced oil recovery
credits to carry forward that we can utilize to reduce our current income taxes during 2007. We
have not earned any additional credits since 2005 due to the high oil prices, which completely
phased out our ability to earn any additional credits.
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.
30
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
Per BOE data |
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
Oil and natural gas revenues |
|
$ |
57.02 |
|
|
$ |
55.54 |
|
|
$ |
53.24 |
|
|
$ |
55.29 |
|
Gain (loss) on settlements of derivative contracts |
|
|
0.45 |
|
|
|
(0.65 |
) |
|
|
1.37 |
|
|
|
(0.45 |
) |
Lease operating expenses |
|
|
(15.00 |
) |
|
|
(12.24 |
) |
|
|
(14.84 |
) |
|
|
(11.80 |
) |
Production taxes and marketing expenses |
|
|
(2.72 |
) |
|
|
(2.77 |
) |
|
|
(2.84 |
) |
|
|
(2.65 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Production netback |
|
|
39.75 |
|
|
|
39.88 |
|
|
|
36.93 |
|
|
|
40.39 |
|
Non-tertiary CO2 operating margin |
|
|
0.57 |
|
|
|
0.47 |
|
|
|
0.63 |
|
|
|
0.44 |
|
General and administrative expenses |
|
|
(3.07 |
) |
|
|
(4.27 |
) |
|
|
(3.18 |
) |
|
|
(3.70 |
) |
Net cash interest expense |
|
|
(1.65 |
) |
|
|
(1.18 |
) |
|
|
(1.43 |
) |
|
|
(1.61 |
) |
Current income taxes and other |
|
|
(1.39 |
) |
|
|
2.87 |
|
|
|
(0.62 |
) |
|
|
0.33 |
|
Changes in assets and liabilities relating to
operations |
|
|
(7.40 |
) |
|
|
(6.56 |
) |
|
|
(5.39 |
) |
|
|
(4.20 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from operations |
|
|
26.81 |
|
|
|
31.21 |
|
|
|
26.94 |
|
|
|
31.65 |
|
DD&A |
|
|
(12.12 |
) |
|
|
(10.60 |
) |
|
|
(12.02 |
) |
|
|
(10.44 |
) |
Deferred income taxes |
|
|
(8.54 |
) |
|
|
(9.29 |
) |
|
|
(5.73 |
) |
|
|
(7.55 |
) |
Non-cash commodity derivative adjustments |
|
|
3.49 |
|
|
|
(2.73 |
) |
|
|
(3.01 |
) |
|
|
(3.06 |
) |
Changes in assets and liabilities and other
non-cash items |
|
|
6.76 |
|
|
|
4.39 |
|
|
|
4.72 |
|
|
|
2.74 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
16.40 |
|
|
$ |
12.98 |
|
|
$ |
10.90 |
|
|
$ |
13.34 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Market Risk Management
We finance some of our acquisitions and other expenditures with fixed and variable rate debt.
These debt agreements expose us to market risk related to changes in interest rates. The following
table presents the carrying and fair values of our debt, along with average interest rates. We had
$170 million of bank debt outstanding as of June 30, 2007 and $134 million at December 31, 2006.
The fair value of the subordinated debt is based on quoted market prices. None of our debt has any
triggers or covenants regarding our debt ratings with rating agencies.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Maturity Dates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Carrying |
|
|
Fair |
|
Amounts in thousands |
|
2009 |
|
|
2013 |
|
|
2015 |
|
|
Value |
|
|
Value |
|
Variable rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank debt |
|
$ |
170,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
170,000 |
|
|
$ |
170,000 |
|
(The weighted-average interest rate on the bank debt at June 30, 2007 is 6.3%.) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.5% subordinated debt due 2013,
net of discount |
|
|
|
|
|
|
225,000 |
|
|
|
|
|
|
|
223,883 |
|
|
|
225,563 |
|
(The interest rate on the subordinated debt is a fixed rate of 7.5%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.5% subordinated debt due 2015,
including premium |
|
|
|
|
|
|
|
|
|
|
300,000 |
|
|
|
300,728 |
|
|
|
300,750 |
|
(The interest rate on the subordinated debt is a fixed rate of 7.5%) |
Oil and Gas Derivative Contracts
From time to time, we enter into various oil and 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.
Historically, we hedged up to 75% of our anticipated production each year to provide us with a
reasonably certain amount of cash flow to cover most of our budgeted exploration and development
expenditures without incurring significant debt. Since 2005 and beyond, we have entered into fewer
derivative contracts, primarily because of our strong financial position resulting from our lower
levels of debt relative to our cash flow from operations. We did
31
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
make an exception in late 2006
when we swapped 80% to 90% of our forecasted 2007 natural gas production at a weighted average
price of $7.96 per Mcf. We did this to protect our 2007 projected cash flow, primarily because we
currently plan to spend $175 million to $225 million more than we expect to generate in cash flow
from operations (see Capital Resources and Liquidity) and we did not want to be exposed to the
risk of lower natural gas prices.
When we make a significant acquisition, we generally attempt to hedge a large percentage, up
to 100%, of the forecasted proved production for the subsequent one to three years following the
acquisition in order to help provide us with a minimum return on our investment. As of June 30,
2007, we had derivative contracts in place related to our $250 million acquisition that closed on
January 31, 2006, on which we entered into contracts to cover 100% of the first three years
estimated proved producing production at the time we signed the purchase and sale agreement. While
these derivative contracts related to the acquisition represent approximately 7% of our estimated
2007 production, they are intended to help protect our acquisition economics related to the first
three years of production of the proved producing reserves that we acquired. These swaps cover
2,000 Bbls/d for 2007 at a price of $58.93 per Bbl; and 2,000 Bbls/d for 2008 at a price of $57.34
per Bbl.
At June 30, 2007, our derivative contracts were recorded at their fair value, which was a net
liability of approximately $6.1 million, a decrease in value of approximately $21.8 million from
the $15.7 million fair value asset recorded as of December 31, 2006. This change is the result of
both the expiration of contracts during the first six months of 2007 and the increases in both oil
and natural gas commodity futures prices between December 31, 2006 and June 30, 2007.
Based on NYMEX crude oil futures prices at June 30, 2007, oil prices were considerably
higher than the swap prices of our outstanding derivative contracts so we would expect to make
future cash payments of $15.5 million on our oil commodity hedges. If oil futures prices were to
decline by 10%, the amount we would expect to pay under our oil commodity hedges would decrease
to $7.6 million, and if futures prices were to increase by 10% we would expect to pay $23.4
million. Based on NYMEX natural gas futures prices at June 30, 2007, we would expect to receive
cash payments of $8.8 million on our natural gas commodity hedges. If natural gas prices futures
prices were to decline by 10%, we would expect to receive future cash payments of $18.9 million,
and if futures prices were to increase by 10% we would expect to pay $1.3 million.
Interest Rate Lock Contracts
In January 2007, we entered into interest rate lock contracts to remove our exposure to
possible interest rate fluctuations related to our commitment to the sale-leaseback financing of
certain equipment for CO2 recycling facilities at our tertiary oil fields. The interest
rate lock contracts cover equipment currently being constructed that we have committed to finance
with Bank of America Leasing & Capital LLC. This equipment has two estimated completion dates, one
during the fourth quarter of 2007 and one during mid-year 2008, with a total estimated cost of
approximately $15 million and $24 million, respectively. We are applying hedge accounting to these
contracts as provided under SFAS No. 133.
At June 30, 2007, the interest rate locks were recorded at their fair value, which was a net
asset of approximately $0.2 million. If the 5-year Semi-Annual Swap Rate were to increase or
decrease 50-basis points, we would expect the fair value liability to change by approximately $0.9
million, with the increase in rates being a benefit to us and a decrease in rates being a liability
to us.
32
DENBURY RESOURCES INC.
Managements Discussion and Analysis of Financial Condition and Results of Operations
Critical Accounting Policies
For a discussion of our critical accounting policies, which are related to property, plant and
equipment, depletion and depreciation, oil and natural gas reserves, asset retirement obligations,
income taxes and hedging activities, and which remain unchanged, see 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, 2006.
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.
33
DENBURY RESOURCES INC.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
The information required by Item 3 is set forth under Market Risk Management in Managements
Discussion and Analysis of Financial Condition and Results of Operations.
Item 4. Controls and Procedures
We maintain disclosure controls and procedures and internal controls designed to
ensure that information required to be disclosed in our filings under the Securities Exchange Act
of 1934 is recorded, processed, summarized and reported within the time periods specified in the
Securities and Exchange Commissions rules and forms. Our chief executive officer and chief
financial officer have evaluated our disclosure controls and procedures as of the end of the period
covered by this quarterly report on Form 10-Q and have determined that such disclosure controls and
procedures are effective in ensuring that material information required to be disclosed in this
quarterly report is accumulated and communicated to them and our management to allow timely
decisions regarding required disclosure.
There have been no significant changes in internal controls over financial reporting during
the period covered by this Quarterly Report on Form 10-Q that have materially affected, or are
reasonably likely to materially affect, Denburys internal controls over financial reporting.
Part II. Other Information
Item 1. Legal Proceedings
Information with respect to this item has been incorporated by reference from our
Form 10-K for the year ended December 31, 2006. 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, 2006. There have been no material changes to the
risk factors since the filing of such Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
ISSUER PURCHASES OF EQUITY SECURITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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, 2007 |
|
|
322 |
|
|
$ |
30.61 |
|
|
|
|
|
|
|
|
|
May 1 through 31, 2007 |
|
|
128 |
|
|
|
33.43 |
|
|
|
|
|
|
|
|
|
June 1 through 30, 2007 |
|
|
122 |
|
|
|
37.15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
572 |
|
|
|
32.64 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
These shares were purchased from employees of Denbury who delivered shares to the company to
satisfy their minimum tax withholding requirements related to the Denburys stock compensation
plans.
Item 3. Defaults Upon Senior Securities
None.
34
Item 4. Submission of Matters to a Vote of Security Holders
Denburys Annual Meeting of Stockholders was held on May 15, 2007 for the purposes of (1)
electing seven directors, each to serve until their successor is elected and qualified, (2) to
increase the number of shares that may be used under our 2004 omnibus stock and incentive plan, (3)
to increase the number of shares that may be used under our employee stock purchase plan, and (4)
to ratify the appointment by the audit committee of PricewaterhouseCoopers LLP as the Companys
independent auditor for 2007. At the record date, March 30, 2007, 120,737,528 shares of common
stock were outstanding and entitled to one vote per share upon all matters submitted at the
meeting. Holders of 112,946,582 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 seven nominees were re-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 |
|
|
108,221,676 |
|
|
|
4,724,904 |
|
David I. Heather |
|
|
112,408,241 |
|
|
|
538,334 |
|
Greg McMichael |
|
|
108,421,464 |
|
|
|
4,525,111 |
|
Gareth Roberts |
|
|
112,581,241 |
|
|
|
365,334 |
|
Randy Stein |
|
|
112,338,864 |
|
|
|
607,711 |
|
Wieland F. Wettstein |
|
|
111,850,825 |
|
|
|
1,095,755 |
|
Donald D. Wolf |
|
|
107,831,953 |
|
|
|
5,114,622 |
|
The proposal regarding an increase to 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 |
|
|
|
|
|
|
|
75,055,520
|
|
29,538,606
|
|
72,668
|
|
8,279,788 |
The proposal regarding an increase to the number of shares that may used under our
employee stock purchase plan was approved. The votes were cast as follows:
|
|
|
|
|
|
|
For
|
|
Against
|
|
Abstentions
|
|
Broker Non-Votes |
|
|
|
|
|
|
|
93,914,290
|
|
10,679,901
|
|
72,604
|
|
8,279,787 |
The appointment by the audit committee of PricewaterhouseCoopers LLP as the Companys
independent auditor for 2007 was approved. The votes were cast as follows:
|
|
|
|
|
|
|
For
|
|
Against
|
|
Abstentions
|
|
Broker Non-Votes |
|
|
|
|
|
|
|
112,051,508
|
|
435,371
|
|
459,703
|
|
-0- |
Item 5. Other Information
None.
Item 6. Exhibits
Exhibits:
|
|
|
31(a)*
|
|
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
31(b)*
|
|
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
32*
|
|
Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002. |
* Filed herewith.
35
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
|
|
|
|
|
DENBURY RESOURCES INC. (Registrant)
|
|
|
By: |
/s/ Phil Rykhoek
|
|
|
|
Phil Rykhoek |
|
|
|
Sr. Vice President and Chief Financial Officer |
|
|
|
|
|
|
|
|
|
|
|
By: |
/s/ Mark C. Allen
|
|
|
|
Mark C. Allen |
|
|
|
Vice President and Chief Accounting Officer |
|
|
Date: August 6, 2007
36