e10vq
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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þ |
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Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the quarterly period ended September 30, 2006
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o |
|
Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
Commission file number 1-12935
DENBURY RESOURCES INC.
(Exact name of Registrant as specified in its charter)
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|
Delaware
(State or other jurisdictions of
incorporation or organization)
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20-0467835
(I.R.S. Employer
Identification No.) |
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5100 Tennyson Parkway
Suite 1200
Plano, TX
(Address of principal executive offices)
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75024
(Zip code) |
Registrants telephone number, including area code: (972) 673-2000
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes þ No o
Indicate by check mark whether the registrant 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):
Large accelerated filer þ Accelerated filer o 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 October 31, 2006 |
Common Stock, $.001 par value
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120,007,754 |
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except shares)
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|
|
|
|
|
|
|
|
September 30, |
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December 31, |
|
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2006 |
|
|
2005 |
|
Assets
|
Current assets |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
28,924 |
|
|
$ |
165,089 |
|
Accrued production receivables |
|
|
67,000 |
|
|
|
65,611 |
|
Related party receivable Genesis |
|
|
386 |
|
|
|
1,312 |
|
Trade and other receivables |
|
|
35,003 |
|
|
|
25,887 |
|
Deferred tax asset |
|
|
10,624 |
|
|
|
41,284 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
141,937 |
|
|
|
299,183 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment |
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|
|
|
|
|
|
Oil and natural gas properties (using full cost accounting) |
|
|
|
|
|
|
|
|
Proved |
|
|
2,171,432 |
|
|
|
1,669,579 |
|
Unevaluated |
|
|
241,736 |
|
|
|
46,597 |
|
CO2 properties and equipment |
|
|
252,680 |
|
|
|
210,046 |
|
Other |
|
|
40,341 |
|
|
|
34,647 |
|
Less accumulated depletion and depreciation |
|
|
(913,007 |
) |
|
|
(804,899 |
) |
|
|
|
|
|
|
|
Net property and equipment |
|
|
1,793,182 |
|
|
|
1,155,970 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in Genesis |
|
|
10,834 |
|
|
|
10,829 |
|
Deposits on property acquisitions |
|
|
|
|
|
|
26,425 |
|
Other assets |
|
|
15,691 |
|
|
|
12,662 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,961,644 |
|
|
$ |
1,505,069 |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Liabilities and Stockholders Equity
|
|
|
|
|
|
|
|
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Current liabilities |
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities |
|
$ |
113,746 |
|
|
$ |
104,840 |
|
Oil and gas production payable |
|
|
51,131 |
|
|
|
41,821 |
|
Derivative liabilities |
|
|
5,575 |
|
|
|
2,759 |
|
Deferred revenue Genesis |
|
|
4,070 |
|
|
|
4,070 |
|
Short-term capital lease obligations Genesis |
|
|
616 |
|
|
|
574 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
175,138 |
|
|
|
154,064 |
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
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Long-term liabilities |
|
|
|
|
|
|
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Capital lease obligations Genesis |
|
|
5,402 |
|
|
|
5,870 |
|
Long-term debt |
|
|
443,942 |
|
|
|
373,591 |
|
Asset retirement obligations |
|
|
35,134 |
|
|
|
25,297 |
|
Derivative liabilities |
|
|
9,405 |
|
|
|
6,624 |
|
Deferred revenue Genesis |
|
|
29,839 |
|
|
|
33,023 |
|
Deferred tax liability |
|
|
215,536 |
|
|
|
170,758 |
|
Other |
|
|
3,268 |
|
|
|
2,180 |
|
|
|
|
|
|
|
|
Total long-term liabilities |
|
|
742,526 |
|
|
|
617,343 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Stockholders equity |
|
|
|
|
|
|
|
|
Preferred stock, $.001 par value, 25,000,000 shares authorized, none
issued and outstanding |
|
|
|
|
|
|
|
|
Common stock, $.001 par value, 250,000,000 shares authorized;
120,237,661 and 115,038,531 shares issued at September 30, 2006 and
December 31, 2005, respectively |
|
|
120 |
|
|
|
115 |
|
Paid-in capital in excess of par |
|
|
609,934 |
|
|
|
443,283 |
|
Retained earnings |
|
|
442,909 |
|
|
|
295,575 |
|
Treasury stock, at cost, 408,669 and 340,337 shares at September
30, 2006 and
December 31, 2005, respectively |
|
|
(8,983 |
) |
|
|
(5,311 |
) |
|
|
|
|
|
|
|
Total stockholders equity |
|
|
1,043,980 |
|
|
|
733,662 |
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
1,961,644 |
|
|
$ |
1,505,069 |
|
|
|
|
|
|
|
|
(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)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Revenues and other income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, natural gas and related product sales |
| | |
|
| | |
|
| | |
|
| | |
|
Unrelated
parties |
|
$ |
187,786 |
|
|
$ |
137,137 |
|
|
$ |
551,249 |
|
|
$ |
371,947 |
|
Related party Genesis |
|
|
12 |
|
|
|
1,411 |
|
|
|
1,496 |
|
|
|
3,389 |
|
CO2 sales and transportation fees |
|
|
2,687 |
|
|
|
2,594 |
|
|
|
7,049 |
|
|
|
5,841 |
|
Interest income and other |
|
|
1,559 |
|
|
|
716 |
|
|
|
4,403 |
|
|
|
2,026 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
192,044 |
|
|
|
141,858 |
|
|
|
564,197 |
|
|
|
383,203 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
42,225 |
|
|
|
25,983 |
|
|
|
120,148 |
|
|
|
75,702 |
|
Production taxes and marketing expenses |
|
|
8,611 |
|
|
|
5,995 |
|
|
|
23,997 |
|
|
|
16,713 |
|
Transportation expense Genesis |
|
|
1,138 |
|
|
|
1,023 |
|
|
|
3,275 |
|
|
|
3,013 |
|
CO2 operating expenses |
|
|
842 |
|
|
|
631 |
|
|
|
2,272 |
|
|
|
1,422 |
|
General and administrative |
|
|
10,599 |
|
|
|
8,952 |
|
|
|
35,040 |
|
|
|
21,439 |
|
Interest, net of amounts capitalized of $3,731, $415, $6,740
and $1,049, respectively |
|
|
5,009 |
|
|
|
4,507 |
|
|
|
19,014 |
|
|
|
13,318 |
|
Depletion, depreciation and amortization |
|
|
41,188 |
|
|
|
24,340 |
|
|
|
110,083 |
|
|
|
70,273 |
|
Commodity derivative expense (income) |
|
|
(12,375 |
) |
|
|
11,818 |
|
|
|
10,784 |
|
|
|
18,614 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses |
|
|
97,237 |
|
|
|
83,249 |
|
|
|
324,613 |
|
|
|
220,494 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in net income (loss) of Genesis |
|
|
157 |
|
|
|
(55 |
) |
|
|
716 |
|
|
|
276 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
94,964 |
|
|
|
58,554 |
|
|
|
240,300 |
|
|
|
162,985 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax provision |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current income taxes |
|
|
5,419 |
|
|
|
7,684 |
|
|
|
12,856 |
|
|
|
17,320 |
|
Deferred income taxes |
|
|
30,251 |
|
|
|
12,324 |
|
|
|
80,110 |
|
|
|
36,380 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
59,294 |
|
|
$ |
38,546 |
|
|
$ |
147,334 |
|
|
$ |
109,285 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share basic |
|
$ |
0.50 |
|
|
$ |
0.34 |
|
|
$ |
1.27 |
|
|
$ |
0.98 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share diluted |
|
$ |
0.48 |
|
|
$ |
0.32 |
|
|
$ |
1.20 |
|
|
$ |
0.92 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
117,917 |
|
|
|
112,159 |
|
|
|
115,864 |
|
|
|
111,466 |
|
Diluted |
|
|
123,966 |
|
|
|
119,487 |
|
|
|
123,055 |
|
|
|
119,098 |
|
(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 |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Cash flow from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
59,294 |
|
|
$ |
38,546 |
|
|
$ |
147,334 |
|
|
$ |
109,285 |
|
Adjustments needed to reconcile to net cash flow provided by operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
41,188 |
|
|
|
24,340 |
|
|
|
110,083 |
|
|
|
70,273 |
|
Non-cash derivative adjustments |
|
|
(14,582 |
) |
|
|
8,054 |
|
|
|
5,597 |
|
|
|
11,975 |
|
Deferred income taxes |
|
|
30,251 |
|
|
|
12,324 |
|
|
|
80,110 |
|
|
|
36,380 |
|
Deferred revenue Genesis |
|
|
(1,178 |
) |
|
|
(682 |
) |
|
|
(3,183 |
) |
|
|
(1,974 |
) |
Stock based compensation |
|
|
3,440 |
|
|
|
1,031 |
|
|
|
14,697 |
|
|
|
3,090 |
|
Income tax benefit from equity awards |
|
|
|
|
|
|
3,242 |
|
|
|
|
|
|
|
8,676 |
|
Amortization of debt issue costs and other |
|
|
570 |
|
|
|
491 |
|
|
|
987 |
|
|
|
1,003 |
|
Changes in assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued production receivables |
|
|
3,697 |
|
|
|
(3,700 |
) |
|
|
(463 |
) |
|
|
(11,094 |
) |
Trade and other receivables |
|
|
(6,805 |
) |
|
|
5,284 |
|
|
|
(12,745 |
) |
|
|
(3,226 |
) |
Other assets |
|
|
1,400 |
|
|
|
|
|
|
|
(1,232 |
) |
|
|
130 |
|
Accounts payable and accrued liabilities |
|
|
17,280 |
|
|
|
(13,546 |
) |
|
|
(6,488 |
) |
|
|
2,272 |
|
Oil and gas production payable |
|
|
1,003 |
|
|
|
955 |
|
|
|
9,309 |
|
|
|
5,253 |
|
Other liabilities |
|
|
(193 |
) |
|
|
(52 |
) |
|
|
288 |
|
|
|
(742 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operations |
|
|
135,365 |
|
|
|
76,287 |
|
|
|
344,294 |
|
|
|
231,301 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow used for investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas expenditures |
|
|
(126,887 |
) |
|
|
(72,020 |
) |
|
|
(376,988 |
) |
|
|
(210,900 |
) |
Acquisitions of oil and gas properties |
|
|
(1,315 |
) |
|
|
(2,700 |
) |
|
|
(315,650 |
) |
|
|
(71,244 |
) |
Change in accrual for capital expenditures |
|
|
(1,617 |
) |
|
|
10,878 |
|
|
|
12,995 |
|
|
|
19,868 |
|
Acquisitions of CO2 assets and capital expenditures |
|
|
(14,450 |
) |
|
|
(14,751 |
) |
|
|
(42,617 |
) |
|
|
(49,869 |
) |
Net purchases of other assets |
|
|
(4,230 |
) |
|
|
(1,057 |
) |
|
|
(7,690 |
) |
|
|
(4,156 |
) |
Proceeds from oil and gas property sales |
|
|
5,893 |
|
|
|
1,888 |
|
|
|
7,931 |
|
|
|
1,865 |
|
Deposits on acquisitions |
|
|
126 |
|
|
|
|
|
|
|
26,425 |
|
|
|
4,507 |
|
Sales of short-term investments |
|
|
|
|
|
|
2,000 |
|
|
|
|
|
|
|
57,133 |
|
Increase in restricted cash |
|
|
(869 |
) |
|
|
(78 |
) |
|
|
(934 |
) |
|
|
(188 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used for investing activities |
|
|
(143,349 |
) |
|
|
(75,840 |
) |
|
|
(696,528 |
) |
|
|
(252,984 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank repayments |
|
|
(10,000 |
) |
|
|
|
|
|
|
(140,000 |
) |
|
|
(19,800 |
) |
Bank borrowings |
|
|
10,000 |
|
|
|
10,000 |
|
|
|
210,000 |
|
|
|
39,800 |
|
Payments on capital lease obligations Genesis |
|
|
(145 |
) |
|
|
(132 |
) |
|
|
(425 |
) |
|
|
(386 |
) |
Income tax benefit from equity awards |
|
|
5,041 |
|
|
|
|
|
|
|
15,193 |
|
|
|
|
|
Issuance of common stock |
|
|
4,952 |
|
|
|
3,314 |
|
|
|
137,263 |
|
|
|
11,139 |
|
Purchase of treasury stock |
|
|
(3,423 |
) |
|
|
(1,955 |
) |
|
|
(5,545 |
) |
|
|
(5,119 |
) |
Costs of debt financing |
|
|
(329 |
) |
|
|
|
|
|
|
(417 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
6,096 |
|
|
|
11,227 |
|
|
|
216,069 |
|
|
|
25,634 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
(1,888 |
) |
|
|
11,674 |
|
|
|
(136,165 |
) |
|
|
3,951 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of period |
|
|
30,812 |
|
|
|
25,316 |
|
|
|
165,089 |
|
|
|
33,039 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
28,924 |
|
|
$ |
36,990 |
|
|
$ |
28,924 |
|
|
$ |
36,990 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosure of cash flow information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid during the period for interest |
|
$ |
1,519 |
|
|
$ |
374 |
|
|
$ |
17,416 |
|
|
$ |
9,280 |
|
Cash paid during the period for income taxes |
|
|
4 |
|
|
|
1,500 |
|
|
|
4,210 |
|
|
|
9,000 |
|
Interest capitalized |
|
|
3,731 |
|
|
|
415 |
|
|
|
6,740 |
|
|
|
1,049 |
|
(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
5
DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF
COMPREHENSIVE OPERATIONS
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Net income |
|
$ |
59,294 |
|
|
$ |
38,546 |
|
|
$ |
147,334 |
|
|
$ |
109,285 |
|
Other comprehensive income, net of income tax: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassification adjustments related to settlements of derivative
contracts, net of tax of $713 and $2,072, respectively |
|
|
|
|
|
|
1,163 |
|
|
|
|
|
|
|
3,380 |
|
Unrealized gain on securities available for sale |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
$ |
59,294 |
|
|
$ |
39,709 |
|
|
$ |
147,334 |
|
|
$ |
112,689 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)
6
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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, 2005. Any
capitalized terms used but not defined in these Notes to Unaudited Condensed Consolidated Financial
Statements have the same meaning given to them in the Form 10-K.
Accounting measurements at interim dates inherently involve greater reliance on estimates than
at year end and the results of operations for the interim periods shown in this report are not
necessarily indicative of results to be expected for the fiscal year. In managements opinion, the
accompanying unaudited condensed consolidated financial statements include all adjustments (of a
normal recurring nature) necessary to present fairly the consolidated financial position of Denbury
as of September 30, 2006 and the consolidated results of its operations and cash flows for the
three and nine month periods ended September 30, 2006 and 2005. Certain prior period items have
been reclassified to make the classification consistent with the classification in the most recent
quarter.
Stock Split
On October 19, 2005, stockholders of Denbury Resources Inc. approved an amendment to our
Restated Certificate of Incorporation to increase the number of shares of our authorized common
stock from 100,000,000 shares to 250,000,000 shares and to split our common stock on a 2-for-1
basis. Stockholders of record on October 31, 2005, received one additional share of Denbury common
stock for each share of common stock held at that time. Information pertaining to shares and
earnings per share has been retroactively adjusted in the accompanying financial statements and
related notes thereto to reflect the stock split.
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
nine month periods ended September 30, 2006 and 2005, 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 See Note 3, Stockholders Equity. 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 nine month periods ended September 30, 2006 and 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
Share amounts in Thousands |
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Weighted average common shares basic |
|
|
117,917 |
|
|
|
112,159 |
|
|
|
115,864 |
|
|
|
111,466 |
|
|
Potentially dilutive securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options and SARs |
|
|
5,183 |
|
|
|
6,264 |
|
|
|
6,172 |
|
|
|
6,691 |
|
Restricted stock |
|
|
866 |
|
|
|
1,064 |
|
|
|
1,019 |
|
|
|
941 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares diluted |
|
|
123,966 |
|
|
|
119,487 |
|
|
|
123,055 |
|
|
|
119,098 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The weighted average common shares basic amount excludes 1,422,229 shares at
September 30, 2006 and 2,018,000 shares at September 30, 2005, 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.
For the three months ended September 30, 2006 and 2005, stock options and SARs to purchase
approximately 111,000 and 131,000 shares of common stock, and for the nine months ended September
30, 2006 and 2005, stock options and SARs to purchase approximately 117,000 and 304,000 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.
Stock-based Compensation
In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standard (SFAS) No. 123(R), Share Based Payment, which is a revision of
SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No. 123(R) supersedes Accounting
Principles Board Opinion 25 (APB 25), Accounting for Stock Issued to Employees, and amends SFAS
No. 95, Statement of Cash Flows. Generally, the approach in SFAS No. 123(R) is similar to the
approach described in SFAS No. 123. However, SFAS No. 123(R) requires all share-based compensation
to employees, including grants of employee stock options, to be recognized in our consolidated
financial statements based on estimated fair value.
We adopted SFAS No. 123(R) on January 1, 2006, using the modified prospective application
method described in the statement. Under the modified prospective method, effective January 1,
2006, we began to recognize compensation expense for the unvested portion of awards outstanding as
of December 31, 2005 over the remaining service periods, and for new awards granted or modified
after January 1, 2006. See Note 6 for further discussion regarding our stock compensation plans.
Recent Accounting Pronouncements
In July 2006, the FASB issued Interpretation 48, Accounting for Uncertainty in Income
Taxes (FIN 48). FIN 48 clarifies the accounting for uncertainty in income taxes recognized
in an enterprises financial statements in accordance with SFAS No. 109, Accounting for
Income Taxes. This interpretation prescribes a recognition threshold and measurement
attribute for the financial statement recognition and measurement of a tax position taken or
expected to be taken in a tax return. FIN 48 also provides guidance on derecognition,
classification, interest and penalties, accounting in interim periods, disclosure and
transition. We are currently evaluating the impact this interpretation will have on our
consolidated financial statements. This interpretation will be effective for Denbury
beginning January 1, 2007.
2. 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. We have begun
our initial tertiary development work at Tinsley Field, consisting primarily of planning, land and
engineering work, with more extensive development and facility construction planned for 2007. The
timing of tertiary development at Citronelle Field is uncertain, as we will need to build a 60- to
70-mile pipeline extension of our Free State pipeline (pipeline from Jackson to East Mississippi)
before flooding can commence, and South Cypress Creek will probably be flooded following our
initial development of our other East Mississippi properties.
8
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The adjusted purchase price for these properties was approximately $250 million, after
adjusting for interim net cash flow between the effective date and closing date of the acquisition,
and minor purchase price adjustments. The adjusted purchase price of $250 million 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, probable, and possible reserves acquired. Based on this
analysis, approximately $126 million was assigned to proved properties and approximately $124
million 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 currently estimate that this development
will take place over the next two to five years. The acquisition was funded with the proceeds of
$150 million of senior subordinated notes issued in December 2005 and $100 million of bank
financing under the Companys then existing credit facility (repaid in late April 2006 with
proceeds from a $125 million equity offering).
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, one that will require construction of a CO2 pipeline before flooding
can commence, which will likely be an extension of the currently planned CO2 pipeline
from Jackson Dome to Tinsley Field. Our goal is to have this CO2 line installed within
the next two years, with initial oil production from tertiary operations currently anticipated
during 2010. Currently, there is neither significant oil production nor proved oil reserves at
Delhi. The purchase price of approximately $50 million 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, probable, and possible reserves acquired. Based on the analysis,
approximately $1 million was assigned to evaluated properties and approximately $49 million was
assigned to unevaluated properties. The unevaluated costs are currently excluded from the
amortization base and will be transferred to the amortization base over the next three to five
years as we develop and test the tertiary recovery projects planned in this field. The acquisition
was funded with our bank credit facility.
The operating results of the acquired properties were included in our financial statements
beginning in February 2006, except for Delhi, which was included beginning June 2006. 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 three or nine months ended September 30, 2006 and
2005.
3. STOCKHOLDERS EQUITY
On April 25, 2006, we closed on the $125 million sale (net to Denbury) of 3,492,595 shares of
common stock in a public offering. We used the net proceeds from the offering to repay then
current borrowings under our bank credit facility, which were $120 million as of April 25, 2006,
the majority of which was incurred to partially fund our $250 million acquisition of three
properties in January 2006.
4. ASSET RETIREMENT OBLIGATIONS
In general, our future asset retirement obligations relate to future costs associated with
plugging and abandonment of our oil and natural gas wells, removal of equipment and facilities from
leased acreage and land restoration. The fair value of a liability for an asset retirement
obligation 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 nine
months ended September 30, 2006.
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
September 30, 2006 |
|
Amounts in thousands |
|
|
|
Beginning asset retirement obligation, as of 12/31/2005 |
|
$ |
27,088 |
|
Liabilities incurred and assumed during period |
|
|
9,412 |
|
Revisions in estimated cash flows |
|
|
1,519 |
|
Liabilities settled during period |
|
|
(965 |
) |
Accretion expense |
|
|
1,863 |
|
|
|
|
|
Ending asset retirement obligation as of 9/30/2006 |
|
$ |
38,917 |
|
|
|
|
|
At September 30, 2006, $3.8 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 properties
acquired during 2006. We hold cash and liquid investments in escrow accounts that are legally
restricted for certain of our asset retirement obligations. The
balances of these escrow accounts were $7.6 million at September 30, 2006 and $6.7 million at
December 31, 2005
and are included in Other assets in our Condensed Consolidated Balance Sheets.
5. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
Amounts in thousands |
|
2006 |
|
|
2005 |
|
7.5% Senior Subordinated Notes due 2015 |
|
$ |
150,000 |
|
|
$ |
150,000 |
|
7.5% Senior Subordinated Notes due 2013 |
|
|
225,000 |
|
|
|
225,000 |
|
Discount on Senior Subordinated Notes due 2013 |
|
|
(1,263 |
) |
|
|
(1,409 |
) |
Senior bank loan |
|
|
70,000 |
|
|
|
|
|
Capital lease obligations Genesis |
|
|
6,018 |
|
|
|
6,444 |
|
Other |
|
|
205 |
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
449,960 |
|
|
|
380,035 |
|
Less current obligations |
|
|
616 |
|
|
|
574 |
|
|
|
|
|
|
|
|
Long-term debt and capital lease obligations |
|
$ |
449,344 |
|
|
$ |
379,461 |
|
|
|
|
|
|
|
|
On September 14, 2006, we entered into a Sixth Amended and Restated Credit Agreement with our
nine banks which modified our previous bank credit agreement. The new agreement (i) improves the
credit pricing under the agreement, (ii) extends the term of the credit arrangements by two and
one-half years to September 14, 2011, (iii) increases the borrowing base from $300 million to $500
million, (iv) increases the maximum facility size from $300 million to $800 million, and (v) makes
other minor modifications and corrections. Under the new agreement, the commitment amount remained
at $150 million. 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 we make in excess of the commitment amount
($150 million), up to the borrowing base limit, although the banks are not obligated to fund any
amount in excess of the commitment amount. The new credit agreement maintains the structure of
semi-annual reviews of the borrowing base and commitment amount.
10
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
6. STOCK COMPENSATION PLANS
Incentive Programs
Denbury has two stock compensation plans. The first plan has been in existence since 1995
(the 1995 Plan) and expired in August 2005 (although options granted under the 1995 Plan prior to
that time can remain outstanding for up to 10 years). The 1995 plan only provided for the issuance
of stock options and in January 2005, we issued stock options under the 1995 Plan that utilized
substantially all of the remaining shares. The second plan, the 2004 Omnibus Stock and Incentive
Plan (the 2004 Plan), has a 10-year term and was approved by the stockholders in May 2004.
Awards covering a total of 5.0 million shares of common stock are authorized for issuance pursuant
to the 2004 Plan, of which awards covering no more than 2,750,000 shares may be issued in the form
of restricted stock or performance vesting awards. At September 30, 2006, a total of 1,042,513
shares were available for future issuance of awards, of which only 326,281 shares may be in the
form of restricted stock or performance vesting awards. The 2004 Plan provides for the issuance of
incentive and non-qualified stock options, restricted stock awards and stock appreciation rights
(SARs) settled in stock that may be issued to officers, employees, directors and consultants.
Denbury has historically granted incentive and non-qualified stock options to its employees.
Effective January 1, 2006, we completely replaced the use of stock options for employees with SARs
settled in stock, as SARs are less dilutive to our stockholders while providing an employee with
essentially the same economic benefits as stock options. The stock options and SARs generally become exercisable over a four-year vesting period with the specific terms of
vesting determined at the time of grant based on guidelines established by the Board of Directors.
The stock options and SARs expire over terms not to exceed 10 years from the date of grant, 90 days after
termination of employment or permanent disability or one year after the death of the optionee. The
stock options and SARs are granted at the fair market value at the time of grant, which is defined in the 2004
Plan as the closing price on the NYSE on the date of grant. The plan is administered by the
Compensation Committee of Denburys Board of Directors.
During August 2004 through January 2005, the Board of Directors, based on a recommendation by
the Boards Compensation Committee, awarded the officers of Denbury a total of 2,200,000 shares of
restricted stock and the independent directors of Denbury a total of 120,000 shares of restricted
stock, all granted under the 2004 Plan. The holders of these shares have all of the rights and
privileges of owning the shares (including voting rights) except that the holders are not entitled
to delivery of the certificates until certain requirements are met. With respect to the 2,200,000
shares of restricted stock granted to officers of Denbury, the vesting restrictions on those shares
are as follows: i) 65% of the awards vest 20% per year over five years and, ii) 35% of the awards
vest upon retirement, as defined in the 2004 Plan. With respect to the 65% of the awards that vest
over five years, on each annual vesting date, 66-2/3% of the vested shares may be delivered to the
holder with the remaining 33-1/3% retained and held in escrow until the holders separation from
the Company. With respect to the 120,000 restricted shares issued to Denburys independent board
members, the shares vest 20% per year over five years. For these directors shares, on each annual
vesting date, 40% of such vested shares may be delivered to the holder with the remaining 60%
retained and held in escrow until the holders separation from the Company. In January 2006, a
total of 38,276 shares of restricted stock were granted to officers and certain members of our
management group. These shares cliff vest four years from the date of grant.
Mr. Worthey, Senior Vice President of Operations, left Denbury effective June 5, 2006. Mr.
Worthey had served as an officer of the Company since September 1, 1992. The Board of Directors
modified certain of his outstanding long-term equity incentives awarded to him during 2003 and
2004. As a result of the modification, Mr. Worthey retained stock options covering 63,090 shares
of Denbury common stock which pursuant to their original terms vest in either January 2007 or
January 2008, and received accelerated vesting of 136,500 shares of restricted stock which
originally were set to vest between mid-August 2006 and mid-August 2008. The options have an
average weighted exercise price of $6.26 per share and were granted in early 2003 and early 2004;
the restricted
stock was awarded in August 2004. The compensation cost resulting from the modifications was
approximately $5.3 million and was included in General and administrative expenses in the
Condensed Consolidated Statement of Operations for the Nine Months Ended September 30, 2006. No
significant cash compensation was paid to Mr. Worthey upon separation. As part of Mr. Wortheys
separation, he also entered into non-competition and consulting agreements covering a period of
twenty-seven months.
11
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
During the third quarter of 2006, our Vice President of Marketing announced his retirement and
departed the Company on August 31, 2006, in connection with
which we expensed approximately $750,000 related to options and
restricted stock that he held.
Total compensation expense charged against income for stock-based compensation was $3.4
million and $14.7 million (including the $5.3 million resulting from modification of Mr. Wortheys
equity awards discussed above) for the three and nine months ended September 30, 2006,
respectively. Part of this expense, $0.3 million and $1.1 million for the three and nine months
ended September 30, 2006, respectively, was included in Lease operating expenses for stock
compensation expense associated with our field employees, and the remaining $3.1 million and $13.6
million for the three and nine months ended September 30, 2006, respectively, was recognized in
General and administrative expenses in the Condensed Consolidated Statements of Operations. The
total income tax benefit recognized in the Condensed Consolidated Statements of Operations for
share-based compensation arrangements was $0.9 million and $3.9 million for the three and nine
months ended September 30, 2006, respectively. Share-based compensation capitalized as part of
Oil and Natural Gas Properties was $0.4 million and $1.3 million for the three and nine months
ended September 30, 2006, respectively.
Prior to 2006, we accounted for stock-based compensation utilizing the recognition and
measurement principles of Accounting Principles Board Opinion 25 (APB 25), Accounting for Stock
Issued to Employees, and its related interpretations. Under these principles, no compensation
expense for stock options was reflected in net income as long as the stock options had an exercise
price equal to the quoted market price of the underlying common stock on the date of grant. For
restricted stock grants, we recognize compensation expense equal to the intrinsic value of the
stock on the date of grant over the applicable vesting periods. The following table illustrates
the effect on net income and net income per common share if we had applied the fair value
recognition and measurement provisions of SFAS No. 123, as amended by SFAS No. 148, in accounting
for our stock-based compensation.
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Nine Months |
|
|
|
Ended |
|
|
Ended |
|
|
|
September 30, |
|
|
September 30, |
|
Amounts in thousands, except per share amounts |
|
2005 |
|
|
2005 |
|
Net income, as reported |
|
$ |
38,546 |
|
|
$ |
109,285 |
|
Add: stock-based compensation included in
reported net income, net of related tax
effects |
|
|
679 |
|
|
|
2,073 |
|
Less: stock-based compensation expense
applying fair value based method, net of
related tax effects |
|
|
2,152 |
|
|
|
5,627 |
|
|
|
|
|
|
|
|
Pro-forma net income |
|
$ |
37,073 |
|
|
$ |
$105,731 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share |
|
|
|
|
|
|
|
|
As reported: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.34 |
|
|
$ |
0.98 |
|
Diluted |
|
|
0.32 |
|
|
|
0.92 |
|
Pro forma: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.33 |
|
|
$ |
0.95 |
|
Diluted |
|
|
0.31 |
|
|
|
0.90 |
|
Prior to the adoption of SFAS No. 123(R) on January 1, 2006, we did not assume the
capitalization of any stock-based compensation in our SFAS No. 123 pro forma net income. As a
result, no stock-based compensation
expense is reflected as being capitalized in the table above. Beginning in 2006, an appropriate
portion of stock-based compensation associated with our employees involved in our exploration and
drilling activities has been capitalized as part of our Oil and Natural Gas Properties in the
Condensed Consolidated Balance Sheet. The effect of applying SFAS No. 123(R) during the three and
nine months ended September 30, 2006 was to decrease
12
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
net income by approximately $1.5 million and
$5.0 million, respectively, for stock compensation expense that would only have been presented in
footnote disclosures under the old requirements of SFAS No. 123. The effect on earnings per share
for the three months ended September 30, 2006 was a decrease of $0.01 per both basic and diluted
share, and for the nine months ended September 30, 2006 was a decrease of $0.04 per both basic and
diluted share. Additionally, cash flow from operations was lower and cash flow from financing
activities was higher by approximately $5.0 million and $15.2 million for the three and nine months
ended September 30, 2006, respectively, associated with the tax benefits for tax deductions in
excess of recognized compensation expenses that is now required to be reported as a financing cash
flow.
Stock Options and SARs
The
fair value of each stock option or SAR award is estimated on the date of grant using the Black-Scholes
option pricing model using the assumptions noted in the following table. The risk-free rate for
periods within the contractual life of the option is based on the U.S. Treasury yield curve in
effect at the time of grant. The expected life of stock options and
SARs granted was derived from examination of
our historical option grants and subsequent exercises. The contractual terms (4-year cliff vesting
and 4-year graded vesting) are evaluated separately for the expected life, as the exercise behavior
for each is different. Expected volatilities are based on the historical volatility of our stock.
Implied volatility was not used in this analysis as our tradable call option terms are short and
the trading volume is low. Our dividend yield is zero, as Denbury does not pay a dividend.
|
|
|
|
|
|
|
|
|
|
|
Nine months ended |
|
Year ended |
|
|
September 30, 2006 |
|
December 31, 2005 |
Weighted average fair value
of options granted |
|
|
$12.69 |
|
|
$ |
6.94 |
|
Risk free interest rate |
|
|
4.52 |
% |
|
|
3.80 |
% |
Expected life |
|
|
4.9 to 6.9 years |
|
|
5 years | |
Expected volatility |
|
|
41.3 |
% |
|
|
42.6 |
% |
Dividend yield |
|
|
|
|
|
|
|
|
The following is a summary of our stock option and SARs activity for the nine months ended
September 30, 2006 and the year ended December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
Year Ended |
|
|
|
September 30, 2006 |
|
|
December 31, 2005 |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
Number |
|
|
Average |
|
|
Number |
|
|
Average |
|
|
|
of Options |
|
|
Price |
|
|
of Options |
|
|
Price |
|
Outstanding at beginning of period |
|
|
9,406,072 |
|
|
$ |
8.07 |
|
|
|
8,880,314 |
|
|
$ |
5.25 |
|
Granted |
|
|
498,306 |
|
|
|
27.10 |
|
|
|
2,483,254 |
|
|
|
16.29 |
|
Exercised |
|
|
(1,773,795 |
) |
|
|
5.45 |
|
|
|
(1,797,146 |
) |
|
|
5.37 |
|
Forfeited |
|
|
(424,009 |
) |
|
|
10.45 |
|
|
|
(160,350 |
) |
|
|
8.86 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period |
|
|
7,706,574 |
|
|
|
9.78 |
|
|
|
9,406,072 |
|
|
|
8.07 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of period |
|
|
2,528,672 |
|
|
$ |
4.90 |
|
|
|
2,509,635 |
|
|
$ |
4.50 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
total intrinsic value of stock options and SARs exercised during the nine months ended September 30, 2006
and the year ended December 31, 2005 was approximately $43.8 million and $24.8 million,
respectively. The aggregate intrinsic value of stock options and SARs outstanding at September 30,
2006 was approximately $147.4 million and these options and SARs have a weighted-average remaining
contractual life of 6.4 years. The aggregate intrinsic value of options exercisable at September
30, 2006 was approximately $60.7 million and these stock options and SARs have a weighted-average remaining
contractual life of 3.9 years.
13
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
A
summary of the status of our non-vested stock options and SARs as of September 30, 2006, and the changes
during the nine months ended September 30, 2006, is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-Average |
|
|
|
|
|
|
|
Grant-Date |
|
Non-vested Options |
|
Shares |
|
|
Fair Value |
|
Non-vested at January 1, 2006 |
|
|
6,896,437 |
|
|
$ |
4.25 |
|
Granted |
|
|
498,306 |
|
|
|
12.69 |
|
Vested |
|
|
(1,792,832 |
) |
|
|
2.97 |
|
Forfeited |
|
|
(424,009 |
) |
|
|
4.81 |
|
|
|
|
|
|
|
|
|
Non-vested at September 30, 2006 |
|
|
5,177,902 |
|
|
|
5.46 |
|
|
|
|
|
|
|
|
|
As of September 30, 2006, there was $13.3 million of total compensation cost to be recognized
in future periods related to non-vested option share-based compensation arrangements. The cost is
expected to be recognized over a weighted-average period of 1.3 years. Cash received from stock
option exercises under share-based payment arrangements for the nine months ended September 30,
2006 and year ended December 31, 2005 was $9.7 million in each period. The tax benefit realized
from stock option and SAR exercises of share-based payment arrangements totaled $13.6 million for the nine months
ended September 30, 2006 and $8.6 million for the year ended December 31, 2005.
Restricted Stock
As of September 30, 2006 we had issued 2,423,719 shares of restricted stock pursuant to the
2004 Plan and have recorded deferred compensation expense of $26.7 million, the fair market value
of the shares on the grant dates. This expense is amortized over the applicable five-year,
four-year, or retirement date vesting periods. As of September 30, 2006, there was $14.3 million
of unrecognized compensation expense related to non-vested restricted stock grants. The
unrecognized compensation cost is expected to be recognized over a weighted-average period of 3
years.
A summary of the status of our non-vested restricted stock grants as of September 30, 2006,
and the changes during the nine months ended September 30, 2006, is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-Average |
|
|
|
|
|
|
|
Grant-Date |
|
Non-vested Restricted Stock Grants |
|
Shares |
|
|
Fair Value |
|
Non-vested at January 1, 2006 |
|
|
2,014,000 |
|
|
$ |
10.15 |
|
Granted |
|
|
103,719 |
|
|
|
29.39 |
|
Vested |
|
|
(524,815 |
) |
|
|
10.17 |
|
Forfeited |
|
|
(170,675 |
) |
|
|
10.26 |
|
|
|
|
|
|
|
|
|
Non-vested at September 30, 2006 |
|
|
1,422,229 |
|
|
|
11.53 |
|
|
|
|
|
|
|
|
|
7. 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 account 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 September
30, 2006 and 2005 was $157,000 and ($55,000), respectively, and for the nine months ended September
30, 2006 and
14
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
2005 was $716,000 and $276,000, respectively. Genesis Energy, Inc., the general
partner of which we own 100%, has guaranteed the bank debt of Genesis, which as of September 30,
2006 was $6.0 million, plus $9.2 million in outstanding letters of credit. There are no guarantees
by Denbury or any of its other subsidiaries of the debt of Genesis or of Genesis Energy, Inc.
During the second and third quarters of 2006, we invested a total of $2.1 million in a
Louisiana petroleum coke-to-ammonia project that is in the development stage and we have committed
to invest an additional $0.9 million. All of our investment may later be redeemed, with a return,
or converted to equity after construction financing for the project has been obtained. If built,
we plan to take 100% of the CO2 produced from this plant. Genesis has also
invested in this project, with its total commitment not to exceed $1.0 million.
Oil Sales and Transportation Services
Prior to September 2004, including the period prior to our investment in Genesis, we sold
certain of our oil production to Genesis. Beginning in September 2004, we discontinued most of our
direct sales to Genesis and began to transport our crude oil using Genesis common carrier pipeline
to a sales point where it is sold to third party purchasers. For these transportation services, we
pay Genesis a fee for the use of their pipeline and trucking services. In the first nine months of
2006 and 2005, we expensed $3.3 million and $3.0 million, respectively, for these transportation
services. Denbury received other miscellaneous payments from Genesis for the nine months ended
September 30, 2006 and 2005, including $90,000 in each period of director fees for certain
executive officers of Denbury that are board members of Genesis, and $670,000 and $387,000,
respectively, in pro rata dividend distributions from Genesis.
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 September 30, 2006, we had $6.0 million of
capital lease obligations with Genesis recorded as liabilities in our Condensed Consolidated
Balance Sheet, of which $616,000 was current. At December 31, 2005, we had $6.4 million of capital
lease obligations with Genesis recorded as liabilities in our Condensed Consolidated Balance Sheet,
of which $574,000 was current.
CO2 Volumetric Production Payments
During 2003 through 2005, we sold 280.5 Bcf of CO2 to Genesis under volumetric
production payment agreements. We have recorded the net proceeds of these volumetric production
payment sales as deferred revenue and will recognize such revenue as CO2 is delivered
during the term of the three volumetric production payments. At September 30, 2006 and December
31, 2005, $33.9 million and $37.1 million, respectively, was recorded as deferred revenue of which
$4.1 million was included in current liabilities at September 30, 2006 and December 31, 2005. We
recognized deferred revenue of $1.2 million and $0.7 million during the three months ended
September 30, 2006 and 2005 and $3.2 million and $2.0 million for the nine months ended September
30, 2006 and 2005, respectively, for deliveries under these volumetric production payments. We
provide Genesis with certain processing and transportation services in connection with transporting
CO2 to their industrial customers for a fee of approximately $0.17 per Mcf of
CO2, which resulted in our receiving $1.3 million and $0.8 million in revenue for the
three months ended September 30, 2006 and 2005 and $3.5 million and $2.3 million for the nine
months ended September 30, 2006 and 2005, respectively.
15
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Summarized financial information of Genesis Energy, L.P. (amounts in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Revenues |
|
$ |
229,551 |
|
|
$ |
300,577 |
|
|
$ |
726,496 |
|
|
$ |
814,321 |
|
Cost of sales |
|
|
221,206 |
|
|
|
295,959 |
|
|
|
702,671 |
|
|
|
799,832 |
|
Other expenses |
|
|
6,650 |
|
|
|
5,259 |
|
|
|
16,095 |
|
|
|
11,890 |
|
Income from discontinued operations |
|
|
|
|
|
|
45 |
|
|
|
|
|
|
|
318 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
1,695 |
|
|
$ |
(596 |
) |
|
$ |
7,730 |
|
|
$ |
2,917 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
Current assets |
|
$ |
102,293 |
|
|
$ |
90,449 |
|
Non-current assets |
|
|
90,689 |
|
|
|
91,328 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
192,982 |
|
|
$ |
181,777 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
97,627 |
|
|
$ |
92,611 |
|
Non-current liabilities |
|
|
7,009 |
|
|
|
955 |
|
Partners capital |
|
|
88,346 |
|
|
|
88,211 |
|
|
|
|
|
|
|
|
Total liabilities and partners capital |
|
$ |
192,982 |
|
|
$ |
181,777 |
|
|
|
|
|
|
|
|
8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Effective January 1, 2005, we elected to discontinue hedge accounting treatment for financial
statement purposes for our oil and natural gas derivative contracts and accordingly de-designated
our derivative instruments from hedge accounting treatment in accordance with SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities. As a result of this change, we
began accounting for our oil and natural gas derivative contracts as speculative contracts in the
first quarter of 2005. As speculative contracts, the changes in the fair value of these
instruments are recognized in income in the period of change.
We enter into various financial contracts to economically hedge 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 historically
consisted of price floors, collars and fixed price swaps. Prior to 2005, we generally attempted to
hedge between 50% and 75% of our anticipated production each year to provide us with a reasonably
certain amount of cash flow to cover a majority of our budgeted exploration and development
expenditures without incurring significant debt, although our hedging percentage may vary relative
to our debt levels. Since 2005, 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. When we make a significant acquisition, we generally attempt to hedge a large
percentage, up to 100%, of the forecasted 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 September 30, 2006, the only derivative contracts we have in place relate to the $250 million
acquisition that closed January 31, 2006, on which we entered into contracts to cover 100% of the
estimated proved production for three years at the time we signed the purchase and sale agreement
in November 2005. All of the mark-to-market valuations used for our financial derivatives are
provided by external sources and are based on prices that are actively quoted. We manage and
control market and counterparty credit risk through established internal control procedures, which
are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties
through formal credit policies, monitoring procedures, and diversification.
16
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following is a summary of Commodity Derivative Expense (Income) included in our
Condensed Consolidated Statements of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Nine Months |
|
|
|
Ended September 30, |
|
|
Ended September 30, |
|
Amounts in thousands |
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Settlements of derivative contracts Oil |
|
$ |
2,207 |
|
|
$ |
|
|
|
$ |
5,187 |
|
|
$ |
|
|
Settlements of derivative contracts Gas |
|
|
|
|
|
|
3,765 |
|
|
|
|
|
|
|
6,640 |
|
Reclassification of accumulated other comprehensive income balance |
|
|
|
|
|
|
1,875 |
|
|
|
|
|
|
|
5,451 |
|
Fair value adjustments to derivative contracts |
|
|
(14,582 |
) |
|
|
6,178 |
|
|
|
5,597 |
|
|
|
6,523 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative expense (income) |
|
$ |
(12,375 |
) |
|
$ |
11,818 |
|
|
$ |
10,784 |
|
|
$ |
18,614 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Oil Contracts at September 30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value at |
|
|
NYMEX Contract Prices Per Bbl |
|
September 30, 2006 |
Type of Contract and Period |
|
Bbls/d |
|
Swap Price |
|
(In Thousands) |
Swap Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
Oct. 2006 - Dec. 2006 |
|
|
2,200 |
|
|
$ |
59.65 |
|
|
$ |
(944 |
) |
Jan. 2007 - Dec. 2007 |
|
|
2,000 |
|
|
|
58.93 |
|
|
|
(6,376 |
) |
Jan. 2008 - Dec. 2008 |
|
|
2,000 |
|
|
|
57.34 |
|
|
|
(7,660 |
) |
At September 30, 2006, our derivative contracts were recorded at their fair value, which was a
liability of $15.0 million.
9. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
Denbury Resources Inc. and Denbury Onshore, LLC are co-obligors of our subordinated debt. Our
subordinated debt is fully and unconditionally guaranteed by Denbury Resources Inc.s significant
subsidiaries other than minor subsidiaries. The results of our equity interest in Genesis is
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 significant subsidiaries:
17
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidating Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2006 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
Amounts in thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
380,712 |
|
|
$ |
135,417 |
|
|
$ |
3,834 |
|
|
$ |
(378,026 |
) |
|
$ |
141,937 |
|
Property and equipment |
|
|
|
|
|
|
1,793,150 |
|
|
|
32 |
|
|
|
|
|
|
|
1,793,182 |
|
Investment in subsidiaries (equity method) |
|
|
654,456 |
|
|
|
|
|
|
|
653,985 |
|
|
|
(1,297,607 |
) |
|
|
10,834 |
|
Other assets |
|
|
158,812 |
|
|
|
13,873 |
|
|
|
154 |
|
|
|
(157,148 |
) |
|
|
15,691 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,193,980 |
|
|
$ |
1,942,440 |
|
|
$ |
658,005 |
|
|
$ |
(1,832,781 |
) |
|
$ |
1,961,644 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
|
|
|
$ |
549,979 |
|
|
$ |
3,185 |
|
|
$ |
(378,026 |
) |
|
$ |
175,138 |
|
Long-term liabilities |
|
|
150,000 |
|
|
|
749,310 |
|
|
|
364 |
|
|
|
(157,148 |
) |
|
|
742,526 |
|
Stockholders equity |
|
|
1,043,980 |
|
|
|
643,151 |
|
|
|
654,456 |
|
|
|
(1,297,607 |
) |
|
|
1,043,980 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
1,193,980 |
|
|
$ |
1,942,440 |
|
|
$ |
658,005 |
|
|
$ |
(1,832,781 |
) |
|
$ |
1,961,644 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2005 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
Amounts in thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
222,858 |
|
|
$ |
297,575 |
|
|
$ |
2,577 |
|
|
$ |
(223,827 |
) |
|
$ |
299,183 |
|
Property and equipment |
|
|
|
|
|
|
1,155,923 |
|
|
|
47 |
|
|
|
|
|
|
|
1,155,970 |
|
Investment in subsidiaries (equity method) |
|
|
506,862 |
|
|
|
|
|
|
|
505,540 |
|
|
|
(1,001,573 |
) |
|
|
10,829 |
|
Other assets |
|
|
154,288 |
|
|
|
37,120 |
|
|
|
169 |
|
|
|
(152,490 |
) |
|
|
39,087 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
884,008 |
|
|
$ |
1,490,618 |
|
|
$ |
508,333 |
|
|
$ |
(1,377,890 |
) |
|
$ |
1,505,069 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
346 |
|
|
$ |
376,194 |
|
|
$ |
1,351 |
|
|
$ |
(223,827 |
) |
|
$ |
154,064 |
|
Long-term liabilities |
|
|
150,000 |
|
|
|
619,713 |
|
|
|
120 |
|
|
|
(152,490 |
) |
|
|
617,343 |
|
Stockholders equity |
|
|
733,662 |
|
|
|
494,711 |
|
|
|
506,862 |
|
|
|
(1,001,573 |
) |
|
|
733,662 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
884,008 |
|
|
$ |
1,490,618 |
|
|
$ |
508,333 |
|
|
$ |
(1,377,890 |
) |
|
$ |
1,505,069 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidating Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2006 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
Amounts in thousands |
|
Obligor) |
|
|
Co-Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Revenues |
|
$ |
2,812 |
|
|
$ |
189,226 |
|
|
$ |
6 |
|
|
$ |
|
|
|
$ |
192,044 |
|
Expenses |
|
|
2,917 |
|
|
|
93,751 |
|
|
|
569 |
|
|
|
|
|
|
|
97,237 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before the following: |
|
|
(105 |
) |
|
|
95,475 |
|
|
|
(563 |
) |
|
|
|
|
|
|
94,807 |
|
Equity in net earnings of subsidiaries |
|
|
59,393 |
|
|
|
|
|
|
|
60,004 |
|
|
|
(119,240 |
) |
|
|
157 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
59,288 |
|
|
|
95,475 |
|
|
|
59,441 |
|
|
|
(119,240 |
) |
|
|
94,964 |
|
Income tax provision (benefit) |
|
|
(6 |
) |
|
|
35,628 |
|
|
|
48 |
|
|
|
|
|
|
|
35,670 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
59,294 |
|
|
$ |
59,847 |
|
|
$ |
59,393 |
|
|
$ |
(119,240 |
) |
|
$ |
59,294 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2005 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
Amounts in thousands |
|
Obligor) |
|
|
Co-Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Revenues |
|
$ |
|
|
|
$ |
141,858 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
141,858 |
|
Expenses |
|
|
41 |
|
|
|
82,825 |
|
|
|
383 |
|
|
|
|
|
|
|
83,249 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before the following: |
|
|
(41 |
) |
|
|
59,033 |
|
|
|
(383 |
) |
|
|
|
|
|
|
58,609 |
|
Equity in net earnings of subsidiaries |
|
|
38,571 |
|
|
|
|
|
|
|
38,724 |
|
|
|
(77,350 |
) |
|
|
(55 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
38,530 |
|
|
|
59,033 |
|
|
|
38,341 |
|
|
|
(77,350 |
) |
|
|
58,554 |
|
Income tax provision (benefit) |
|
|
(16 |
) |
|
|
20,254 |
|
|
|
(230 |
) |
|
|
|
|
|
|
20,008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
38,546 |
|
|
$ |
38,779 |
|
|
$ |
38,571 |
|
|
$ |
(77,350 |
) |
|
$ |
38,546 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidating Statements of Operations (continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2006 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
Amounts in thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Revenues |
|
$ |
8,406 |
|
|
$ |
555,785 |
|
|
$ |
6 |
|
|
$ |
|
|
|
$ |
564,197 |
|
Expenses |
|
|
8,678 |
|
|
|
314,606 |
|
|
|
1,329 |
|
|
|
|
|
|
|
324,613 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before the following: |
|
|
(272 |
) |
|
|
241,179 |
|
|
|
(1,323 |
) |
|
|
|
|
|
|
239,584 |
|
Equity in net earnings of subsidiaries |
|
|
147,594 |
|
|
|
|
|
|
|
149,156 |
|
|
|
(296,034 |
) |
|
|
716 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
147,322 |
|
|
|
241,179 |
|
|
|
147,833 |
|
|
|
(296,034 |
) |
|
|
240,300 |
|
Income tax provision (benefit) |
|
|
(12 |
) |
|
|
92,739 |
|
|
|
239 |
|
|
|
|
|
|
|
92,966 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
147,334 |
|
|
$ |
148,440 |
|
|
$ |
147,594 |
|
|
$ |
(296,034 |
) |
|
$ |
147,334 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2005 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
Amounts in thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Revenues |
|
$ |
|
|
|
$ |
383,203 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
383,203 |
|
Expenses |
|
|
123 |
|
|
|
219,509 |
|
|
|
862 |
|
|
|
|
|
|
|
220,494 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before the following: |
|
|
(123 |
) |
|
|
163,694 |
|
|
|
(862 |
) |
|
|
|
|
|
|
162,709 |
|
Equity in net earnings of subsidiaries |
|
|
109,360 |
|
|
|
|
|
|
|
109,934 |
|
|
|
(219,018 |
) |
|
|
276 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
109,237 |
|
|
|
163,694 |
|
|
|
109,072 |
|
|
|
(219,018 |
) |
|
|
162,985 |
|
Income tax provision (benefit) |
|
|
(48 |
) |
|
|
54,036 |
|
|
|
(288 |
) |
|
|
|
|
|
|
53,700 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
109,285 |
|
|
$ |
109,658 |
|
|
$ |
109,360 |
|
|
$ |
(219,018 |
) |
|
$ |
109,285 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20
DENBURY RESOURCES INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidating Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2006 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
Amounts in thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Cash flow from operations |
|
$ |
(146,911 |
) |
|
$ |
490,504 |
|
|
$ |
701 |
|
|
$ |
|
|
|
$ |
344,294 |
|
Cash flow from investing activities |
|
|
|
|
|
|
(696,528 |
) |
|
|
|
|
|
|
|
|
|
|
(696,528 |
) |
Cash flow from financing activities |
|
|
146,911 |
|
|
|
69,158 |
|
|
|
|
|
|
|
|
|
|
|
216,069 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash |
|
|
|
|
|
|
(136,866 |
) |
|
|
701 |
|
|
|
|
|
|
|
(136,165 |
) |
Cash, beginning of period |
|
|
1 |
|
|
|
164,408 |
|
|
|
680 |
|
|
|
|
|
|
|
165,089 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, end of period |
|
$ |
1 |
|
|
$ |
27,542 |
|
|
$ |
1,381 |
|
|
$ |
|
|
|
$ |
28,924 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2005 |
|
|
|
Denbury |
|
|
Denbury |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources Inc. |
|
|
Onshore, LLC |
|
|
|
|
|
|
|
|
|
|
Denbury |
|
|
|
(Parent and Co- |
|
|
(Issuer and Co- |
|
|
Guarantor |
|
|
|
|
|
|
Resources Inc. |
|
Amounts in thousands |
|
Obligor) |
|
|
Obligor) |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Cash flow from operations |
|
$ |
(6,020 |
) |
|
$ |
236,921 |
|
|
$ |
400 |
|
|
$ |
|
|
|
$ |
231,301 |
|
Cash flow from investing activities |
|
|
|
|
|
|
(252,963 |
) |
|
|
(21 |
) |
|
|
|
|
|
|
(252,984 |
) |
Cash flow from financing activities |
|
|
6,020 |
|
|
|
19,614 |
|
|
|
|
|
|
|
|
|
|
|
25,634 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash |
|
|
|
|
|
|
3,572 |
|
|
|
379 |
|
|
|
|
|
|
|
3,951 |
|
Cash, beginning of period |
|
|
1 |
|
|
|
32,881 |
|
|
|
157 |
|
|
|
|
|
|
|
33,039 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, end of period |
|
$ |
1 |
|
|
$ |
36,453 |
|
|
$ |
536 |
|
|
$ |
|
|
|
$ |
36,990 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21
DENBURY RESOURCES INC.
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, 2005, 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 onshore
Louisiana, Alabama, and in the Barnett Shale play near Fort Worth, 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 Houma, Louisiana; Laurel, Mississippi; McComb, Mississippi; Brandon,
Mississippi; and Cleburne, Texas.
Overview
Operating results. The combination of high commodity prices and record quarterly production
resulted in another quarter of near record earnings and cash flow from operations. Production for
the third quarter of 2006 was 37,561 BOE/d, 37% higher than production in the third quarter of
2005, with production increases in every operating area. Last years third quarter production was
negatively affected by Hurricanes Katrina and Rita, with approximately 3,800 BOE/d of production
estimated as having been deferred during that period. If last years third quarter production is
adjusted to include the estimated deferred portion, the production increase between the comparative
quarters would be reduced to approximately 21%. Commodity prices remained strong during the third
quarter of 2006, although on a comparative BOE basis, prices for the two third quarters were
approximately the same, oil being a little higher in the 2006 period and natural gas prices a
little lower.
Other significant factors impacted the respective two quarters. During the third quarter of
2006, we recognized $14.6 million of income associated with non-cash mark-to-market fair value
changes on our oil swaps as a result of the decline in oil prices late in the period. Conversely,
during the third quarter of 2005, we recognized mark-to-market fair value and other non-cash
expenses of $8.1 million associated with derivative contracts in place at that time as commodity
prices increased during that period. We also capitalized approximately $3.7 million of interest
expense in the third quarter of 2006, primarily related to the unevaluated properties included in
our 2006 acquisitions, reducing our overall increase in interest expense to 11%, even though
average debt levels were 81% higher in the third quarter of 2006 than in the comparable period of
2005. Overall industry costs continue to increase, the primary reason for record, or near record,
operating costs and depreciation and depletion rates per BOE in the third quarter of 2006.
Operating expenses were also impacted by higher energy costs (electrical and fuel charges) and our
continuing emphasis on tertiary operations. General and administrative expenses increased 18%
between the comparative third quarters as a result of the continued growth in personnel and
inflation in the industry, including a 5% pay raise to all employees effective July 1, 2006 in
order to remain competitive with industry compensation levels. Lastly, our income tax expense
increased primarily due to higher pre-tax income and the effective rate increased due to the loss
of our ability to generate enhanced oil recovery credits during 2006 as a result of the high oil
prices.
Net income for the first nine months of 2006 was $147.3 million as compared to $109.3 million
of net income during the first nine months of 2005. The incremental net income during the first
nine months of 2006 was attributable to most of the factors noted above, principally higher
production, partially offset by higher costs. Higher commodity prices in 2006 also played a
significant role in the nine month results, increasing oil and natural gas revenue.
In addition to inflationary costs in our industry, we are experiencing more and more delays in
obtaining goods and services. This industry trend has caused us to experience higher costs than
originally forecasted and to periodically fall behind schedule with regard to timing of planned
activities. While it appears that the recent decline in commodity prices may be showing
preliminary signs of slowing these trends, unless prices continue to decrease, we believe that we
are likely to see continued rising costs, both for operating expenses and capital expenditures, as
well as delays in completing our planned projects, which will likely also cause delays in achieving
our anticipated production targets. See Results of Operations for a more thorough discussion of
our operating results.
22
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview of tertiary operations. Since we acquired our first carbon dioxide tertiary flood in
Mississippi over seven years ago, we have gradually increased our emphasis on these operations, so
that approximately 50% of our 2006 capital budget is related to these types of operations. We
particularly like this play because of its risk profile, rate of return and lack of competition in
our operating areas. 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. We continue to acquire tertiary flood candidates to further expand our operations
(see 2006 acquisitions below). Please also refer to Managements Discussion and Analysis of
Financial Condition and Results of Operations and the sections entitled Overview and
CO2 Operations contained in our 2005 Form 10-K for further information regarding these
operations, their potential, and the ramifications of our focus on these types of operations.
Oil production from our tertiary operations averaged of 10,114 BOE/d in the third quarter of
2006, a 14% increase over the third quarter of 2005 tertiary production level of 8,850 BOE/d, but
approximately the same as our second quarter 2006 production level. Our CO2 injections
have been less than we originally forecasted due to a series of delays in obtaining equipment or
completing facilities, resulting in a corresponding shortfall between our forecasted and actual
tertiary oil production. We believe this temporary fluctuation in oil production does not indicate
any issue with the proved and potential oil reserves recoverable with CO2 because the
historical correlation between oil production and CO2 injections remains high.
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.
We have begun our initial tertiary development work at Tinsley Field, consisting primarily of
planning, land and engineering work, with more extensive development and facility construction
planned for 2007. The timing of tertiary development at Citronelle Field is uncertain as we will
need to build a 60-to-70 mile extension of our Free State pipeline (CO2 pipeline from
Jackson to East Mississippi) before flooding can commence, and South Cypress Creek will probably be
flooded following our initial development of our other East Mississippi properties. The adjusted
purchase price for these three properties was approximately $250 million, after adjusting for
interim net cash flow and minor purchase price adjustments. The acquisition was funded with
proceeds of the $150 million of senior subordinated notes issued in December 2005 and $100 million
of bank financing under the Companys existing credit facility (repaid in April 2006 with proceeds
from our equity offering at that time). During the third quarter of 2006, these fields produced an
average of 2,339 BOE/d, up slightly from the 2,200 BOE/d at the time of acquisition. As of
December 31, 2005, these fields had proved reserves of approximately 14.4 million BOEs. We operate
all three fields and own the majority of the working interests.
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 that will require construction of a CO2 pipeline before flooding can
commence, with current plans to make such a line an extension of the larger, new CO2
pipeline currently planned from Jackson Dome to Tinsley Field. Our goal is to have this
CO2 line installed within the next two years, with initial oil production from tertiary
operations currently anticipated during 2010. Currently, there are neither significant oil
production nor proved oil reserves at Delhi.
April 2006 Equity Offering. On April 25, 2006, we closed the $125 million sale (net to
Denbury) of 3,492,595 shares of common stock in a public offering. We used the net proceeds from
the offering to repay then current borrowings under our bank credit facility, which were $120
million as of that date, the majority of which was incurred to partially fund our $250 million
acquisition of three properties in January 2006.
Capital Resources and Liquidity
Our current capital budget for 2006, excluding acquisitions, is approximately $550 million,
which at commodity futures prices as of the end of October 2006, is estimated to be at least $100
million more than our anticipated cash flow from operations, a shortfall which primarily results
from the drop in commodity prices during the last few months. As of November 1, 2006, we had $84
million of bank debt outstanding, an amount that we estimate will increase another
23
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
$10 million to $20 million during the fourth quarter to fund our capital program. We expect to
end the year with around $100 million of bank debt. Further, we continue to pursue additional
acquisitions of mature oil fields that have potential as future tertiary flood candidates. These
possible acquisitions are difficult to forecast and the purchase price can vary widely depending on
the level of existing production and conventional proved reserves and commodity prices. Any
additional acquisitions would be funded, at least temporarily, with bank or other debt. With the
recent increase in our borrowing base (see Revised bank credit agreement below), we have more
borrowing capacity than we currently plan or desire to use as our goal is to maintain our strong
financial position.
We have not finalized our 2007 capital budget, but preliminarily expect it to be between
$550 million and $650 million, excluding any potential acquisitions. This preliminary 2007 program
includes an estimated $80 million to $90 million for a CO2 pipeline from our
CO2 source at Jackson Dome to Tinsley and Delhi Fields, two oil fields acquired during
2006. It is our intent to refinance this pipeline, and one (or both) of our existing
CO2 pipelines, with Genesis Energy, L.P. by entering into some type of long-term
financing or sale transaction, effectively paying for the cost of the pipeline over time and
recouping cash previously spent. We have discussed with Genesis any
such financing being conditioned upon Genesis achieving certain
goals, primarily the acquisition of other economic projects that are not related to Denbury, based
upon acquisition by Genesis of $1.50 of non-Denbury-related acquisitions for every $1.00 of
financings or sales with Denbury. If Genesis is successful in
acquiring properties from third parties and we reach mutually
agreeable terms with Genesis to
sell them certain Denbury properties, and if commodity prices do not decrease any further, we will
likely spend at or near the upper end of our preliminary 2007 capital budget range. Otherwise,
we will likely reduce our capital program to some degree to remain closer to our anticipated cash
flow from operations.
Preliminarily, approximately 50% of our 2007 budget is expected to be spent on tertiary
related operations, approximately 25% in the Barnett Shale area, and approximately 10% on
exploration projects, with the balance spent on our properties in Mississippi or Louisiana. The
2007 budget will be set and approved by our Board of Directors at our next regularly scheduled
board meeting in December 2006.
Revised bank credit agreement. On September 14, 2006, we entered into a Sixth Amended and
Restated Credit Agreement with our nine banks, led by JPMorgan Chase Bank, N.A., as administrative
agent. The new agreement (i) improves the credit pricing under the agreement, (ii) extends the
term of the credit arrangements by two and one-half years to September 14, 2011, (iii) increases
the borrowing base from $300 million to $500 million, (iv) increases the maximum facility size from
$300 million to $800 million, and (v) makes other minor modifications. Under the new agreement,
the commitment amount remained at $150 million. 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 ($150 million), up to the borrowing base limit, although the banks
are not obligated to fund any amount in excess of the commitment amount. At September 30, 2006, we
had outstanding $375.0 million (principal amount) of 7.5% subordinated notes, approximately $6.0
million of capital lease commitments, $70.0 million of bank debt, and a working capital deficit of
approximately $33.2 million.
Sources and Uses of Capital Resources
During the first nine months of 2006, we spent $377.0 million on oil and natural gas
exploration and development, $42.6 million on CO2 exploration and development, and
approximately $315.7 million on property acquisitions, for total capital expenditures of
approximately $735.3 million. Our exploration and development expenditures included approximately
$164.6 million spent on drilling, $22.7 million spent on geological, geophysical and acreage
expenditures and $189.7 million incurred on facilities and recompletion costs. We funded these
expenditures with $344.3 million of cash flow from operations, $125 million of equity, $70 million
of bank borrowings, and a $13 million increase in our accrued capital expenditures, with the
balance funded with working capital, predominately cash from the December 2005 issuance of $150
million of subordinated debt. 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 $355.6 million for the first nine months of 2006,
while cash flow from operations for the same period, the GAAP measure, was $344.3 million.
24
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Last year, during the first nine months of 2005 we spent $210.9 million on oil and natural gas
exploration and development, $49.9 million on CO2 exploration and development (including
$27.9 million on our CO2 pipeline being constructed to East Mississippi), and
approximately $71.2 million on property acquisitions, for total capital expenditures of
approximately $332.0 million. Our exploration and development expenditures included approximately
$94.9 million spent for drilling, $20.1 million for geological, geophysical and acreage
expenditures and $95.8 million for facilities and recompletion costs. Our 2005 first nine-month
acquisition expenditures included the purchase of additional interest and acreage in the Barnett
Shale area and purchase of two oil fields that may be potential tertiary flood candidates in the
future, Cranfield and Lake St. John fields. We funded these expenditures with $231.3 million of
cash flow from operations, $20.0 million of net bank borrowings, and a $19.9 million increase in
our accrued capital expenditures, with the balance funded with cash remaining from our 2004
offshore property sale. Adjusted cash flow from operations (a non-GAAP measure defined as cash
flow from operations before changes in assets and liabilities as discussed under Results of
Operations Operating Results below) was $238.7 million for the first nine months of 2005, while
cash flow from operations for the same period, the GAAP measure, was $231.3 million.
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. Further, one of our
subsidiaries, the general partner of Genesis Energy, L.P., has guaranteed the bank debt of Genesis
(which as of September 30, 2006, consisted of $6.0 million of debt and $9.2 million in letters of
credit) and we have delivery obligations to deliver CO2 to industrial customers. In
June 2006, we extended our Plano, Texas office lease term by 10 years, to 2019. The total minimum
lease payments under the lease are approximately $32 million during the 13 year period. Lease
payments are payable monthly and are approximately $2 million per year initially and increase to
approximately $2.7 million per year by the end of the term.
During the third quarter of 2006, we committed to purchase a manufactured (anthropogenic)
source of CO2, the by-product of a planned petroleum coke gasification plant in
Louisiana scheduled to commence operations in 2010. This plant, if completed, is expected to
produce between 190 MMcf/d and 225 MMcf/d of CO2 and our purchase price will vary
depending on the oil price at that time and the level of compression provided by the seller. We
currently estimate that our annual minimum purchase commitment will be $2.0 million over a 15 year
period, but the actual purchase price could be several times that minimum amount. Our commitment
is only binding if the plant is constructed, which is still uncertain as the plant is in a
pre-construction phase.
Our derivative contracts are discussed in Note 8 to the Unaudited Condensed Consolidated
Financial Statements. Neither the amounts nor the terms of these non-balance sheet commitments or
contingent obligations have changed significantly, other than as disclosed above, from the year-end
2005 amounts reflected in our Form 10-K filed in March 2006. Please refer to Managements
Discussion and Analysis of Financial Condition and Results of Operations Off-Balance Sheet
Arrangements Commitments and Obligations contained in our 2005 Form 10-K for further
information regarding our commitments and obligations.
Results of Operations
CO2 Operations
As described in the Overview section above, our CO2 operations are 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, this tertiary operating focus impacts certain trends in our
current and near-term operating
25
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
results. Please refer to Managements Discussion and Analysis of Financial Condition and Results
of Operations and the section entitled CO2 Operations contained in our 2005 Form 10-K
for further information regarding these issues.
We originally planned to drill three new CO2 source wells during 2006. The first
well drilled in early 2006 is currently awaiting connection to facilities, the construction of
which has been delayed from the originally estimated completion date. Preliminary indications are
that while this well added only minor incremental reserves, it should, upon completion, further
increase our maximum potential CO2 production rate by 10 MMcf/d to 20 MMcf/d, to a total
level between 450 MMcf/d to 500 MMcf/d. We have had various drilling problems with our second
well and have sidetracked it twice, and as a result, the well is almost three months behind
schedule and still drilling. This development well is not expected to add any significant
incremental CO2 reserves, but should further increase our total productive capacity. As
a result of the delays in the second well, which is nearing total depth, we recently contracted a
second rig to spud the third well, which has commenced drilling but is not expected to reach total
depth until the first quarter of 2007. Drilling is expected to continue for the foreseeable future
as our CO2 production capacity must continue to increase in order to meet our long-term
oil production goals, and we are attempting to increase our proven CO2 reserves in order
to further expand our tertiary operations. During the third quarter of 2006, our CO2
production averaged 352 MMcf/d, as compared to 253 MMcf/d during the third quarter of 2005. We
used 74% of the 2006 volumes, or 260 MMcf/d, in our tertiary operations, and sold the balance to
our industrial customers or to Genesis pursuant to our volumetric production payments.
Oil production from our tertiary operations averaged 10,114 BOE/d in the third quarter of
2006, a 14% increase over our third quarter of 2005 tertiary production level of 8,850 BOE/d, but
approximately the same as tertiary oil production in the second quarter of 2006. Our
CO2 injections have been less than we forecasted due to a series of different types of
delays in obtaining equipment or completing facilities, resulting in a corresponding shortfall
between our forecasted and actual tertiary oil production. This temporary fluctuation in oil
production does not indicate any issue with the proved and potential oil reserves recoverable with
CO2 because the historical correlation between oil production and CO2
injections remains high.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (BOE/d) |
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
First |
|
Second |
|
Third |
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
|
Quarter |
|
Quarter |
|
Quarter |
Tertiary Oil Field |
|
2005 |
|
2005 |
|
2005 |
|
2005 |
|
|
2006 |
|
2006 |
|
2006 |
|
|
|
|
|
|
Brookhaven |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
125 |
|
|
|
|
547 |
|
|
|
798 |
|
|
|
965 |
|
Little Creek & Lazy Creek |
|
|
3,709 |
|
|
|
3,847 |
|
|
|
3,357 |
|
|
|
3,210 |
|
|
|
|
3,006 |
|
|
|
3,056 |
|
|
|
2,623 |
|
Mallalieu (East and West) |
|
|
4,235 |
|
|
|
4,582 |
|
|
|
4,565 |
|
|
|
5,562 |
|
|
|
|
5,219 |
|
|
|
5,385 |
|
|
|
5,243 |
|
McComb & Olive |
|
|
700 |
|
|
|
988 |
|
|
|
928 |
|
|
|
1,011 |
|
|
|
|
932 |
|
|
|
1,062 |
|
|
|
1,242 |
|
Smithdale |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31 |
|
|
|
|
54 |
|
|
|
74 |
|
|
|
41 |
|
|
|
|
|
|
|
Total tertiary oil production |
|
|
8,644 |
|
|
|
9,417 |
|
|
|
8,850 |
|
|
|
9,939 |
|
|
|
|
9,758 |
|
|
|
10,375 |
|
|
|
10,114 |
|
|
|
|
|
|
|
We spent approximately $0.20 per Mcf to produce our CO2 during the third quarter of
2006, up from the 2005 third quarter average of $0.17 per Mcf, principally as a result of higher
oil commodity prices, which results in higher royalty payments, and higher labor, utilities and
equipment rental expense. Our estimated total cost per thousand cubic feet of CO2
during the third quarter of 2006 was approximately $0.30, after inclusion of depreciation and
amortization expense, up from the 2005 average of $0.25 per Mcf for these same reasons. On a nine
month basis, we spent approximately $0.20 per Mcf to produce our CO2 during the first
nine months of 2006, higher than our 2005 nine month average of $0.15 per Mcf, an increase
consistent with the comparable quarterly trends. Our estimated total cost per thousand cubic feet
of CO2 during the first nine months of 2006 was approximately $0.29, after inclusion of
depreciation and amortization expense.
For the third quarter of 2006, our operating costs for our tertiary properties averaged $17.61
per BOE, up significantly from the $11.95 per BOE average in the third quarter of 2005 and from our
2005 annual average of $12.00 per BOE, but approximately the same as our second quarter of 2006
average of $17.42 per BOE. The higher costs were a result of higher CO2 costs which
represent approximately 30% of our total tertiary operating costs (see prior paragraph), higher
fuel and energy costs (which represent almost 35% of our total tertiary operating costs), higher
rental payments on leased equipment, and general cost inflation in the industry, partially offset
by higher production levels. In addition, we
26
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
incurred approximately $2.4 million, or approximately $2.59 per BOE during the third quarter
of 2006, for operating expenses at three new tertiary floods where we commenced operations but have
not yet seen any production response (initial response is expected late in 2006 or in early 2007).
Operating Results
As summarized in the Overview section above and discussed in more detail below, higher
production levels, mark-to-market derivative income, partially offset by higher operating expenses,
resulted in near-record quarterly earnings and cash flow from operations. Included in the first
nine months of 2006 net income is the effect of approximately $5.8 million of non-cash charges
related to the adoption of SFAS No. 123(R) as of January 1, 2006, relating to certain stock-based
compensation that was previously only reflected as a footnote disclosure and not recorded in the
financial statements (See Note 6 to the Unaudited Condensed Consolidated Financial Statements) and
approximately $6.0 million of other non-cash stock charges associated with the departure of a
senior vice president and retirement of another vice president, both during 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
Amounts in thousands, except per share amounts |
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Net income |
|
$ |
59,294 |
|
|
$ |
38,546 |
|
|
$ |
147,334 |
|
|
$ |
109,285 |
|
Net income per common share basic |
|
|
0.50 |
|
|
|
0.34 |
|
|
|
1.27 |
|
|
|
0.98 |
|
Net income per common share diluted |
|
|
0.48 |
|
|
|
0.32 |
|
|
|
1.20 |
|
|
|
0.92 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted cash flow from operations (see below) |
|
$ |
118,983 |
|
|
$ |
87,346 |
|
|
$ |
355,625 |
|
|
$ |
238,708 |
|
Net change in assets and liabilities relating to operations |
|
|
16,382 |
|
|
|
(11,059 |
) |
|
|
(11,331 |
) |
|
|
(7,407 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from operations (1) |
|
$ |
135,365 |
|
|
$ |
76,287 |
|
|
$ |
344,294 |
|
|
$ |
231,301 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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, the non-GAAP measure, measures 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
period. 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.
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 the first nine months of 2006, we used
cash because of increases in trade and other receivables of approximately $12.7 million, while the
other working capital changes generally offset each other. Conversely, during the first nine
months of 2005, our accrued production receivables and trade accounts receivable increased as a
result of higher revenue and increased spending, resulting in a $14.3 million use of cash; however,
this was partially offset by increases in our accounts payable, accrued liabilities and production
payable which resulted in additional cash resources of $7.5 million.
Certain of our operating results and statistics for the comparative third quarters and first
nine months of 2006 and 2005 are included in the following table.
27
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Average daily production volumes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bbls/d |
|
|
23,468 |
|
|
|
18,369 |
|
|
|
23,018 |
|
|
|
19,745 |
|
Mcf/d |
|
|
84,557 |
|
|
|
53,854 |
|
|
|
82,912 |
|
|
|
56,556 |
|
BOE/d (1) |
|
|
37,561 |
|
|
|
27,345 |
|
|
|
36,837 |
|
|
|
29,171 |
|
Operating revenues (Thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
138,172 |
|
|
$ |
95,987 |
|
|
$ |
387,731 |
|
|
$ |
264,337 |
|
Natural gas sales |
|
|
49,626 |
|
|
|
42,561 |
|
|
|
165,014 |
|
|
|
110,999 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas sales |
|
$ |
187,798 |
|
|
$ |
138,548 |
|
|
$ |
552,745 |
|
|
$ |
375,336 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas derivative contracts (2) (Thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash expense on settlements of derivative contracts |
|
$ |
(2,207 |
) |
|
$ |
(3,765 |
) |
|
$ |
(5,187 |
) |
|
$ |
(6,640 |
) |
Non-cash derivative (expense) income |
|
|
14,582 |
|
|
|
(8,053 |
) |
|
|
(5,597 |
) |
|
|
(11,974 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income (expense) from oil and gas derivative contracts |
|
$ |
12,375 |
|
|
$ |
(11,818 |
) |
|
$ |
(10,784 |
) |
|
$ |
(18,614 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses (Thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
42,225 |
|
|
$ |
25,983 |
|
|
$ |
120,148 |
|
|
$ |
75,702 |
|
Production taxes and marketing expenses |
|
|
9,749 |
|
|
|
7,018 |
|
|
|
27,272 |
|
|
|
19,726 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production expenses (3) |
|
$ |
51,974 |
|
|
$ |
33,001 |
|
|
$ |
147,420 |
|
|
$ |
95,428 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2 sales and transportation fees (4) |
|
$ |
2,687 |
|
|
$ |
2,594 |
|
|
$ |
7,049 |
|
|
$ |
5,841 |
|
CO2 operating expenses |
|
|
842 |
|
|
|
631 |
|
|
|
2,272 |
|
|
|
1,422 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO2 operating margin |
|
$ |
1,845 |
|
|
$ |
1,963 |
|
|
$ |
4,777 |
|
|
$ |
4,419 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit prices including impact of derivative settlements |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
62.97 |
|
|
$ |
56.80 |
|
|
$ |
60.88 |
|
|
$ |
49.04 |
|
Gas price per Mcf |
|
|
6.38 |
|
|
|
7.83 |
|
|
|
7.29 |
|
|
|
6.76 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit prices excluding impact of derivative settlements |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price per Bbl |
|
$ |
64.00 |
|
|
$ |
56.80 |
|
|
$ |
61.70 |
|
|
$ |
49.04 |
|
Gas price per Mcf |
|
|
6.38 |
|
|
|
8.59 |
|
|
|
7.29 |
|
|
|
7.19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas operating revenues and expenses per BOE (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenues |
|
$ |
54.35 |
|
|
$ |
55.07 |
|
|
$ |
54.96 |
|
|
$ |
47.13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas lease operating expenses |
|
$ |
12.22 |
|
|
$ |
10.33 |
|
|
$ |
11.95 |
|
|
$ |
9.51 |
|
Oil and gas production taxes and marketing expense |
|
|
2.82 |
|
|
|
2.79 |
|
|
|
2.71 |
|
|
|
2.48 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas production expenses |
|
$ |
15.04 |
|
|
$ |
13.12 |
|
|
$ |
14.66 |
|
|
$ |
11.99 |
|
|
|
|
| |
|
| |
|
|
|
|
|
|
|
|
(1) |
|
Barrel of oil equivalent using the ratio of one barrel of oil to 6 Mcf of natural gas (BOE). |
|
(2) |
|
See also Market Risk Management below for information concerning the Companys hedging
transactions. |
|
(3) |
|
Includes Transportation expense Genesis. |
|
(4) |
|
Includes deferred revenue of $1.2 million and $0.7 million for the three months ended September
30, 2006 and 2005, respectively, and $3.2 million and $2.0 million for the nine months ended
September 30, 2006 and 2005, respectively, associated with a volumetric production payment with
Genesis. Includes transportation income from Genesis of $1.3 million and $0.8 million for the three
months ended September 30, 2006 and 2005, respectively, and $3.5 million and $2.3 million for the
nine months ended September 30, 2006 and 2005, respectively. |
28
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Production: Production by area for each of the quarters of 2005 and the first, second, and third
quarters of 2006 is listed in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (BOE/d) |
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
First |
|
Second |
|
Third |
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
|
Quarter |
|
Quarter |
|
Quarter |
Operating Area |
|
2005 |
|
2005 |
|
2005 |
|
2005 |
|
|
2006 |
|
2006 |
|
2006 |
|
|
|
|
|
|
Mississippi non-CO2 floods |
|
|
13,057 |
|
|
|
12,788 |
|
|
|
10,998 |
|
|
|
11,475 |
|
|
|
|
12,455 |
|
|
|
12,633 |
|
|
|
13,069 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi CO2 floods |
|
|
8,644 |
|
|
|
9,417 |
|
|
|
8,850 |
|
|
|
9,939 |
|
|
|
|
9,758 |
|
|
|
10,375 |
|
|
|
10,114 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Onshore Louisiana |
|
|
6,710 |
|
|
|
5,791 |
|
|
|
5,169 |
|
|
|
6,992 |
|
|
|
|
8,349 |
|
|
|
8,623 |
|
|
|
8,221 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
|
|
1,313 |
|
|
|
2,052 |
|
|
|
2,150 |
|
|
|
3,048 |
|
|
|
|
3,953 |
|
|
|
4,621 |
|
|
|
4,952 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Alabama |
|
|
|
|
|
|
37 |
|
|
|
126 |
|
|
|
141 |
|
|
|
|
917 |
|
|
|
1,213 |
|
|
|
1,215 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other (1) |
|
|
|
|
|
|
384 |
|
|
|
52 |
|
|
|
54 |
|
|
|
|
22 |
|
|
|
9 |
|
|
|
(10 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Company |
|
|
29,724 |
|
|
|
30,469 |
|
|
|
27,345 |
|
|
|
31,649 |
|
|
|
|
35,454 |
|
|
|
37,474 |
|
|
|
37,561 |
|
|
|
|
|
|
|
|
|
|
(1) |
|
Primarily represents production from an offshore property retained from July 2004 offshore
sale. |
As outlined in the above table, production in the third quarter of 2006 increased 37% (10,216
BOE/d) over third quarter of 2005 levels, up slightly from second quarter 2006 levels, and up 26%
during the comparable first nine month periods. The third quarter of 2005 was negatively affected
by Hurricanes Katrina and Rita, as approximately 3,800 BOE/d of production is estimated as having
been deferred during that period. If last years production is adjusted to include deferred
production, the production increase between the comparative quarters would be reduced to
approximately 21%, or approximately 6,400 BOE/d. Of this adjusted quarterly increase, the January
2006 acquisition contributed approximately 2,339 BOE/d of the increase (37%) in the 2006 third
quarter average production (1,255 BOE/d to the Mississippi non-CO2 floods and 1,084
BOE/d to Alabama in the above table). These newly acquired properties contributed approximately
2,199 BOE/d to our average production in the second quarter of 2006, and approximately 2/3rds of
that amount (two months production) during the first quarter of 2006. Our onshore Louisiana
production for the first nine months of 2006 increased 2,512 BOE/d (43% increase) over the prior
years first nine months level, due primarily to production increases at Thornwell and South
Chauvin Fields as a result of 2005 and 2006 drilling activity in that area. The quarter-to-quarter
fluctuations in Louisiana are a result of various wells coming on
production, offset by depletion of
others. Our Louisiana properties are generally shorter-lived properties than our properties in
most other areas and therefore decline rather rapidly, requiring a consistent increase in new
production in order to maintain production levels there.
Our production in the Barnett Shale area during the first nine months of 2006 increased 2,671
BOE/d (145% increase) over our first nine months of 2005 level, also as a result of increased
drilling activity, with 40 to 50 wells planned in 2006. Production from this area has increased
every quarter during the last two years, although this upward trend may not continue much longer as
our activity level there is not expected to increase further.
Production in the Mississippi non-CO2 floods area changed only modestly during
the last three quarters (before giving effect to the January 2006 acquisition related increase
noted above), following modest declines early in 2005. Recent drilling activity in the Heidelberg
Selma Chalk (natural gas) has increased production there slightly in recent quarters. See
CO2 Operations above for a discussion of the tertiary related production.
Our production for the third quarter of 2006 was weighted toward oil (62%), slightly less than
the percentage of oil production (67%) during the third quarter of 2005, as a result of the recent
increases in natural gas production in the Barnett Shale area and Louisiana.
29
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Oil and Natural Gas Revenues: Oil and natural gas revenues for the third quarter of 2006
increased $49.2 million, or 36%, from revenues in the comparable quarter of 2005, primarily as a
result of higher production. When comparing the respective nine month periods, revenues increased
$177.4 million, or 47%, as production also increased, assisted by higher commodity prices. Cash
payments associated with our commodity derivative contracts of $2.2 million and $3.8 million for
the third quarters of 2006 and 2005, respectively, were not significant to either period. See
Market Risk Management for additional information regarding our hedging activities.
The 37% increase in production in the third quarter of 2006, as compared to production in the
third quarter of 2005, increased oil and natural gas revenues by $51.8 million (105% of the total
revenue increase), while slightly lower overall commodity prices in the 2006 quarterly period
reduced revenue by $2.5 million, or 5% of the total revenue increase. On a nine month basis, the
26% increase in production in the first nine months of 2006, as compared to production in the first
nine months of 2005, increased oil and natural gas revenues by $98.6 million (56% of the total
revenue increase), and the increase in overall commodity prices in the 2006 nine month period
increased revenue by $78.8 million, or 44% of the total revenue increase. Crude oil prices were
higher in both 2006 periods than in the comparative 2005 periods, while natural gas prices were
higher in 2006 for the comparative nine month periods, but lower during the third quarter of 2006
as compared to the third quarter of 2005. Our realized oil prices (excluding hedges) increased by
13% between the third quarters of 2005 and 2006 and by 26% between the comparable nine month
periods, while our realized natural gas prices (excluding hedges) decreased by 26% between the
third quarters of 2005 and 2006, but increased slightly by 1% between the comparable nine month
periods. On a combined BOE basis, commodity prices were 1% lower in 2006 for the comparative third
quarters and 17% higher for 2006 for the comparative first nine month periods.
The differentials between our net realized oil prices (excluding commodity derivative
contracts) and NYMEX prices were slightly higher for the first nine months of 2006 as compared to
the first nine months of 2005 and the comparative third quarter periods. Our average oil
differential for the first nine months of 2006 was approximately $6.60 per Bbl as compared to $6.45
per Bbl during the first nine months of 2005 and an average of $6.17 per Bbl during the fourth
quarter of 2005. On a quarterly basis, the average oil differential was $6.69 in the third quarter
of 2006 as compared to $6.34 in the third quarter of 2005. The higher overall differential in 2006
was primarily related to higher sour crude differentials prices relative to NYMEX during the
period. These trends are difficult to accurately forecast.
Our natural gas differentials relative to NYMEX improved in 2006 as compared to 2005,
primarily due to decreasing natural gas prices throughout most of the year. Since most of our
natural gas is sold on an index price that is set near the first of each month, the variance will
decrease if NYMEX natural gas prices consistently decrease during the quarter. Our average natural
gas differential for the first nine months of 2006 was a positive variance of approximately $0.40
per Mcf, as compared to a negative variance of $0.48 per Mcf during the first nine months of 2005
and a negative variance of $1.03 per Mcf during the fourth quarter of 2005. On a quarterly basis,
our average natural gas differential for the third quarter of 2006 was a positive variance of
approximately $0.24 per Mcf, as compared to a negative variance of $0.97 per Mcf during the third
quarter of 2005.
The changing commodity prices caused fluctuations in the mark-to-market value adjustments of
our derivative contracts. We recognized a gain of $14.6 million in the third quarter of 2006 as a
result of the decreasing prices, as compared to an expense of $8.1 million during the comparable
period in 2005. For the nine month periods, we recognized an expense in both periods, $5.6 million
during the 2006 nine month period as compared to $12.0 million in the 2005 nine month period.
Production Expenses: Our lease operating expenses increased between the comparable first nine
months and third 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) general cost inflation in our industry, (iii) increased
personnel and related costs, (iv) higher fuel and energy costs to operate our properties, (v)
increasing lease payments for certain of our tertiary operating facilities, and (vi) higher
workover costs. The adoption of SFAS No. 123(R) effective January 1, 2006 (see Overview
Operating results) also added approximately $369,000 of non-cash charges to third quarter 2006
results with similar amounts in the first and second quarters of 2006, representing the stock
compensation expense pertaining to operating personnel.
30
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
During the third quarter of 2006, operating costs averaged $12.22 per BOE, up from $10.33 per
BOE in the third quarter of 2005, and at approximately the same level as the $12.24 per BOE of
operating costs incurred in the second quarter of 2006. Operating expenses incurred in connection
with our tertiary operations increased from $9.7 million in the third quarter of 2005 to $16.4
million during the third quarter of 2006, as a result of the increased tertiary activity. Tertiary
operating expenses were particularly impacted by the higher power and energy costs, higher costs
for CO2 and payments on leased facilities and equipment (see CO2 Operations
above). We expect these increases in tertiary operating costs to continue and to further increase
our cost per BOE as tertiary production becomes a more significant portion of our total production
and operations. Lease operating expenses related to the properties acquired in the January
acquisition were $5.7 million during the third quarter of 2006, and had a higher per BOE cost than
our other properties due to repairs and clean-up performed on the properties. The trends were
similar when comparing the respective first nine month periods.
Production taxes and marketing expenses generally change in proportion to commodity prices and
production volumes and therefore were higher in the third quarter of 2006 than in the comparable
quarter of 2005.
General and Administrative Expenses
General and administrative (G&A) expenses increased 18% between the respective third
quarters and 63% between the respective first nine months, as set forth below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Net G&A expense (thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross G&A expenses |
|
$ |
23,322 |
|
|
$ |
17,737 |
|
|
$ |
70,794 |
|
|
$ |
46,862 |
|
State franchise taxes |
|
|
662 |
|
|
|
447 |
|
|
|
1,355 |
|
|
|
1,065 |
|
Operator overhead charges |
|
|
(11,510 |
) |
|
|
(7,994 |
) |
|
|
(31,471 |
) |
|
|
(22,848 |
) |
Capitalized exploration costs |
|
|
(1,875 |
) |
|
|
(1,238 |
) |
|
|
(5,638 |
) |
|
|
(3,640 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net G&A expense |
|
$ |
10,599 |
|
|
$ |
8,952 |
|
|
$ |
35,040 |
|
|
$ |
21,439 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average G&A cost per BOE |
|
$ |
3.07 |
|
|
$ |
3.56 |
|
|
$ |
3.48 |
|
|
$ |
2.69 |
|
Employees as of September 30 |
|
|
558 |
|
|
|
433 |
|
|
|
558 |
|
|
|
433 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross G&A expenses increased $5.6 million, or 31%, between the respective third quarters and
$23.9 million, or 51%, between the respective first nine months. The single biggest increase was due
to the adoption of SFAS No. 123(R) in January 2006 which increased net G&A expense by approximately
$6.6 million during the first nine months of 2006 ($1.7 million during the third quarter of 2006),
representing the non-cash charge for stock compensation (mainly stock options and stock
appreciation rights) pertaining to personnel charged to G&A. In addition, the third quarter of
2006 includes approximately $730,000 of non-cash compensation expense associated with the
amortization of deferred compensation resulting from the issuance of restricted stock to officers
and directors during 2004 which was already being expensed prior to the adoption of SFAS No.
123(R). This quarterly non-cash compensation charge related to the 2004 grants is lower than the
$1.0 million charged during the third quarter of 2005 as a result of the departure of two
executives during 2006. In the second quarter of 2006, we incurred a $5.3 million charge to
earnings related to the modification of the vesting terms of certain restricted stock and stock
options previously granted to Mr. Worthey, former Senior Vice-President of Operations, associated
with his departure. We also expensed approximately $750,000 in the third quarter of 2006 related
to the retirement of our Vice President of Marketing.
G&A also increased along with higher compensation costs due to additional employees,
associated expenses and wage increases. From September 30, 2005 to September 30, 2006, we had a
net increase of 29% in our employee count related to our acquisitions and increased activity level.
In addition, 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 5%
pay raise to all employees effective July 1, 2006 in order to remain competitive with industry
compensation levels. During the third quarter of 2005, we had one significant non-recurring item
wherein we expensed $1.3 million for food,
31
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
water, gasoline, power generators, and other essential supplies provided as part of relief efforts
in Mississippi and Louisiana following the hurricanes that quarter.
The increase in gross G&A was offset in part by an increase in operator overhead recovery
charges in the third quarter and first nine months of 2006. 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 our
acquisitions and incremental drilling and development activity during the third quarter and first
nine months of 2006, the amount we recovered as operator overhead charges increased by 44% between
the third quarters of 2005 and 2006 and increased by 38% between the first nine months of 2005 and
2006. The operator overhead recovery charges also increased as a result of the allocation to
operations of stock compensation cost related to the adoption of SFAS No. 123(R). Capitalized
exploration costs also increased by 51% between the third quarters of 2005 and 2006 and increased
by 55% between the first nine months of 2005 and 2006 as a result of increased compensation costs,
most of which relates to stock based compensation related to the adopted of SFAS No. 123(R).
The net effect was an 18% increase in net G&A expense between the respective third quarters
and a 63% increase between the first nine months of 2006 and 2005. On a per BOE basis, G&A costs
decreased 14% in the third quarter of 2006 as compared to the level of such costs in the third
quarter of 2005, and increased 29% for the comparative first nine months of 2006 and 2005, both
better results than the increase in gross costs as a result of the higher production levels.
Interest and Financing Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
Amounts in thousands, except per BOE amounts |
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Cash interest expense |
|
$ |
8,456 |
|
|
$ |
4,658 |
|
|
$ |
24,902 |
|
|
$ |
13,694 |
|
Non-cash interest expense |
|
|
284 |
|
|
|
264 |
|
|
|
852 |
|
|
|
673 |
|
Less: Capitalized interest |
|
|
(3,731 |
) |
|
|
(415 |
) |
|
|
(6,740 |
) |
|
|
(1,049 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
$ |
5,009 |
|
|
$ |
4,507 |
|
|
$ |
19,014 |
|
|
$ |
13,318 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest and other income |
|
$ |
1,559 |
|
|
$ |
716 |
|
|
$ |
4,403 |
|
|
$ |
2,026 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average net cash interest expense per BOE (1) |
|
$ |
0.92 |
|
|
$ |
1.43 |
|
|
$ |
1.38 |
|
|
$ |
1.34 |
|
Average interest rate (2) |
|
|
7.5 |
% |
|
|
7.5 |
% |
|
|
7.4 |
% |
|
|
7.5 |
% |
Average debt outstanding |
|
$ |
452,638 |
|
|
$ |
249,711 |
|
|
$ |
447,813 |
|
|
$ |
242,711 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 when comparing the third quarters and first
nine months of
2005 and 2006, primarily due to substantially higher average debt
levels offset in part by higher interest capitalized on our
significant unevaluated properties, primarily related to the two
recent acquisitions. Debt levels were unusually low in the
first half of 2005 following the sale of our offshore properties in mid-2004. Conversely, debt
levels increased in the first quarter of 2006 following the $250 million acquisition which closed
at the end of January, funded by $150 million of subordinated debt issued in December 2005 and $100
million of bank debt borrowed at closing. The bank debt was repaid in April 2006 with the proceeds
from the recent equity offering (see Overview April 2006 Equity Offering), but an additional
$50 million was subsequently borrowed to fund the Delhi acquisition (see Overview Recent
Acquisitions) and an additional $20 million for general working capital, leaving us with total
bank debt of $70 million as of September 30, 2006.
32
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Depletion, Depreciation and Amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
Amounts in thousands, except per BOE amounts |
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Depletion and depreciation of oil and natural gas properties |
|
$ |
36,681 |
|
|
$ |
21,878 |
|
|
$ |
98,197 |
|
|
$ |
63,414 |
|
Depletion
and depreciation of
CO2 assets |
|
|
2,371 |
|
|
|
1,311 |
|
|
|
6,051 |
|
|
|
3,685 |
|
Asset retirement obligations |
|
|
677 |
|
|
|
435 |
|
|
|
1,863 |
|
|
|
1,278 |
|
Depreciation of other fixed assets |
|
|
1,459 |
|
|
|
716 |
|
|
|
3,972 |
|
|
|
1,896 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total DD&A |
|
$ |
41,188 |
|
|
$ |
24,340 |
|
|
$ |
110,083 |
|
|
$ |
70,273 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A per BOE: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties |
|
$ |
10.81 |
|
|
$ |
8.87 |
|
|
$ |
9.95 |
|
|
$ |
8.12 |
|
CO2 assets and other fixed assets |
|
|
1.11 |
|
|
|
0.81 |
|
|
|
1.00 |
|
|
|
0.70 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total DD&A cost per BOE |
|
$ |
11.92 |
|
|
$ |
9.68 |
|
|
$ |
10.95 |
|
|
$ |
8.82 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our depletion, depreciation and amortization (DD&A) rate on a per BOE basis increased 23%
between the respective third quarters and increased 24% between the respective first nine months,
primarily due to rising costs, although a minor reserve revision and lower commodity prices also
contributed to the increase. As a result of cost inflation in the industry, we have adjusted the
estimated future development costs on our undeveloped properties upward almost every quarter, the
primary factor in rising DD&A rates per BOE. Our third quarter 2006 DD&A rate was also negatively
impacted by a writedown of reserves on our Westervelt well, on the Gumbo prospect in Terrebonne
Parish, as the production results during the first month of production indicate substantially lower
reserves than the originally estimated two MMBOE. We are still optimistic about the potential of
the prospect area and recently spudded a second well in this prospect area. Further, the decline
in commodity prices during the third quarter resulted in our losing approximately 1.0 MMBOE of
proved reserves at September 30, 2006 as compared to reserve quantities at June 30, 2006.
representing the reduction of reserves due to a shorter economic life when commodity prices
decrease.
We allocated approximately $124 million of our $250 million January 2006 acquisition and
virtually all of the second quarter 2006 $50 million Delhi acquisition to unevaluated properties to
reflect the significant potential reserves that we considered to be part of these acquisitions. As
a result, these acquisitions did not materially affect our overall DD&A rate, as the amount
included in our full cost pool was a cost per BOE relatively consistent with our overall DD&A rate.
We booked approximately 3.2 MMBbls of incremental oil reserves related to our tertiary operations
during the first half of 2006, which historically have had a lower finding and development cost
than our overall company average. Although we initiated CO2 injections at three East
Mississippi fields in the first nine months of 2006, the magnitude and ability to book any
potential incremental proved reserves at these fields before year-end 2006 will largely depend on
the timing of the production response at two of these fields, Soso and Martinville. 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 nine months of 2006 as compared to the DD&A rate during the comparative first nine months in
2005 as a result of the Free State CO2 pipeline which went into service late in the
first quarter, the additional costs incurred drilling CO2 wells during each year and
higher associated future development costs, partially offset by an increase in CO2
reserves from 2.7 Tcf as of December 31, 2004, to 4.6 Tcf as of December 31, 2005 (100%
working interest basis before amounts attributable to Genesis volumetric production payments).
33
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
Amounts in thousands, except per BOE amounts and tax rates |
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Current income tax expense |
|
$ |
5,419 |
|
|
$ |
7,684 |
|
|
$ |
12,856 |
|
|
$ |
17,320 |
|
Deferred income tax expense |
|
|
30,251 |
|
|
|
12,324 |
|
|
|
80,110 |
|
|
|
36,380 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
$ |
35,670 |
|
|
$ |
20,008 |
|
|
$ |
92,966 |
|
|
$ |
53,700 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average income tax expense per BOE |
|
$ |
10.32 |
|
|
$ |
7.95 |
|
|
$ |
9.24 |
|
|
$ |
6.74 |
|
Effective tax rate |
|
|
37.6 |
% |
|
|
34.2 |
% |
|
|
38.7 |
% |
|
|
32.9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Our income tax provision for the 2006 and 2005 periods was based on an estimated statutory tax
rate of approximately 39%. For the first nine months of 2005, our net effective tax rate was
32.9%, lower than the statutory rate primarily due to the recognition of enhanced oil recovery
credits (EOR) which lowered our overall tax expense. For 2006 we will not earn any additional
EOR credits because of the high oil prices during 2005, which
completely phased out our ability to earn any additional credits for
2006. As a result, our effective tax rate will more closely approximate our statutory tax rate in
2006. Under the recently adopted accounting rules of SFAS No. 123(R), a tax benefit, if any, for
compensation expenses arising from the issuance of incentive stock options (the majority of our
options issued prior to 2006) is not recognizable during the vesting period, the period during
which they are expensed for book purposes, which also caused a slight increase in our effective tax
rate in 2006. Our effective tax rates for the third quarter and nine months ended September 30,
2006 are slightly less than our estimated statutory rate due primarily to a revision to our
previous estimate of EOR credits.
In both periods, the current income tax expense represents our anticipated alternative minimum
cash taxes that we cannot offset with EOR credits. As of December 31, 2005, we had an estimated
$44.7 million of EOR credit carryforwards that we can utilize to
reduce a portion of our cash taxes.
These EOR credits do not begin to expire until 2023.
34
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Per BOE Data
The following table summarizes our cash flow, DD&A and results of operations on a per BOE
basis for the comparative periods. Each of the individual components is discussed above.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
Per BOE data |
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Oil and natural gas revenues |
|
$ |
54.35 |
|
|
$ |
55.07 |
|
|
$ |
54.96 |
|
|
$ |
47.13 |
|
Loss on settlements of derivative contracts |
|
|
(0.64 |
) |
|
|
(1.50 |
) |
|
|
(0.52 |
) |
|
|
(0.83 |
) |
Lease operating expenses |
|
|
(12.22 |
) |
|
|
(10.33 |
) |
|
|
(11.95 |
) |
|
|
(9.51 |
) |
Production taxes and marketing expenses |
|
|
(2.82 |
) |
|
|
(2.79 |
) |
|
|
(2.71 |
) |
|
|
(2.48 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Production netback |
|
|
38.67 |
|
|
|
40.45 |
|
|
|
39.78 |
|
|
|
34.31 |
|
Non-tertiary CO2 operating margin |
|
|
0.53 |
|
|
|
0.78 |
|
|
|
0.48 |
|
|
|
0.55 |
|
General and administrative expenses |
|
|
(3.07 |
) |
|
|
(3.56 |
) |
|
|
(3.48 |
) |
|
|
(2.69 |
) |
Net cash interest expense |
|
|
(0.92 |
) |
|
|
(1.43 |
) |
|
|
(1.38 |
) |
|
|
(1.34 |
) |
Current income taxes and other |
|
|
(0.78 |
) |
|
|
(1.52 |
) |
|
|
(0.04 |
) |
|
|
(0.86 |
) |
Changes in assets and liabilities relating to operations |
|
|
4.74 |
|
|
|
(4.40 |
) |
|
|
(1.12 |
) |
|
|
(0.93 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from operations |
|
|
39.17 |
|
|
|
30.32 |
|
|
|
34.24 |
|
|
|
29.04 |
|
DD&A |
|
|
(11.92 |
) |
|
|
(9.68 |
) |
|
|
(10.95 |
) |
|
|
(8.82 |
) |
Deferred income taxes |
|
|
(8.75 |
) |
|
|
(4.90 |
) |
|
|
(7.97 |
) |
|
|
(4.57 |
) |
Non-cash hedging adjustments |
|
|
4.22 |
|
|
|
(3.20 |
) |
|
|
(0.56 |
) |
|
|
(1.50 |
) |
Changes in assets and liabilities and other non-cash items |
|
|
(5.56 |
) |
|
|
2.78 |
|
|
|
(0.11 |
) |
|
|
(0.43 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
17.16 |
|
|
$ |
15.32 |
|
|
$ |
14.65 |
|
|
$ |
13.72 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35
DENBURY RESOURCES INC.
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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
$70.0 million of bank debt outstanding as of September 30, 2006 and none at December 31, 2005. 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 |
|
2011 |
|
2013 |
|
2015 |
|
Value |
|
Value |
Variable rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank debt |
|
$ |
70,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
70,000 |
|
|
$ |
70,000 |
|
(The weighted-average interest rate on the bank debt at September 30, 2006 is 6.3%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.5% subordinated debt,
net of discount, due 2013 |
|
$ |
|
|
|
$ |
225,000 |
|
|
$ |
|
|
|
$ |
223,737 |
|
|
$ |
233,438 |
|
(The interest rate on the subordinated debt is a fixed rate of 7.5%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.5% subordinated debt, due 2015 |
|
$ |
|
|
|
$ |
|
|
|
$ |
150,000 |
|
|
$ |
150,000 |
|
|
$ |
155,625 |
|
(The interest on the subordinated debt is a fixed rate of 7.5%) |
|
|
|
|
|
|
|
|
|
|
|
|
From time to time, we enter into various derivative contracts to economically hedge 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. For
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. (Please refer to Managements Discussion and Analysis of Financial Condition and
Results of Operations and the sections entitled Market Risk Management contained in our 2005
Form 10-K for further information regarding our hedging activities). 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 September 30, 2006, the only
derivative contracts we have in place relate to the $250 million acquisition that closed on
January 31, 2006, on which we entered into swap contracts to cover 100% of the estimated proved
production for three years at the time we signed the purchase and sale agreement in November
2005. While these derivative contracts related to the acquisition represent less than 6% of our
estimated 2006 production, they are intended to help protect our acquisition economics related to
the first three years of production from the proved producing reserves that we acquired. These
swaps cover 2,200 Bbls/d for 2006 at a price of $59.65 per Bbl; 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 September 30, 2006, our derivative contracts were recorded at their fair value, which was a
net liability of approximately $15.0 million, an increase of approximately $5.6 million from the
$9.4 million fair value liability recorded as of December 31, 2005. This change is the result of a
decrease in the fair market value of our hedges due to an increase in oil prices between December
31, 2005 and September 30, 2006.
Based on NYMEX crude oil futures prices at September 30, 2006, oil prices were higher than
the swap prices of our outstanding derivative contracts so we would not expect to receive any
funds even if oil prices were to drop 10%. Based on NYMEX futures prices at September 30, 2006,
we would expect to make future cash payments of $15.9 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 $4.6 million, and if futures prices were to increase by 10% we
would expect to pay $27.2 million.
36
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, 2005.
Recent Accounting Pronouncements
In July 2006, the FASB issued Interpretation 48, Accounting for Uncertainty in Income
Taxes (FIN 48). FIN 48 clarifies the accounting for uncertainty in income taxes recognized
in an enterprises financial statements in accordance with SFAS No. 109, Accounting for
Income Taxes. This interpretation prescribes a recognition threshold and measurement
attribute for the financial statement recognition and measurement of a tax position taken or
expected to be taken in a tax return. FIN 48 also provides guidance on derecognition,
classification, interest and penalties, accounting in interim periods, disclosure and
transition. We are currently evaluating the impact this interpretation will have on our
consolidated financial statements. This interpretation will be effective for Denbury
beginning January 1, 2007.
Forward-Looking Information
The statements contained in this Quarterly Report on Form 10-Q that are not historical facts,
including, but not limited to, statements found in this Managements Discussion and Analysis of
Financial Condition and Results of Operations, are forward-looking statements, as that term is
defined in Section 21E of the Securities and Exchange Act of 1934, as amended, that involve a
number of risks and uncertainties. Such forward-looking statements may be or may concern, among
other things, forecasted capital expenditures, drilling activity or methods, acquisition plans and
proposals and dispositions, development activities, cost savings, production rates and volumes or
forecasts thereof, hydrocarbon reserves, hydrocarbon or expected reserve quantities and values,
potential reserves from tertiary operations, hydrocarbon prices, pricing assumptions based upon
current and projected oil and gas prices, liquidity, regulatory matters, mark-to-market values,
competition, long-term forecasts of production, finding costs, rates of return, estimated costs, or
changes in costs, future capital expenditures and overall economics and other variables surrounding
our tertiary operations and future plans. Such forward-looking statements generally are
accompanied by words such as plan, estimate, expect, predict, anticipate, projected,
should, assume, believe, target or other words that convey the uncertainty of future events
or outcomes. Such forward-looking information is based upon managements current plans,
expectations, estimates and assumptions and is subject to a number of risks and uncertainties that
could significantly affect current plans, anticipated actions, the timing of such actions and the
Companys financial condition and results of operations. As a consequence, actual results may
differ materially from expectations, estimates or assumptions expressed in or implied by any
forward-looking statements made by or on behalf of the Company. Among the factors that could cause
actual results to differ materially are: fluctuations of the prices received or demand for the
Companys oil and natural gas, inaccurate cost estimates, fluctuations in the prices of goods and
services, the uncertainty of drilling results and reserve estimates, operating hazards, acquisition
risks, requirements for capital or its availability, general economic conditions, competition and
government regulations, unexpected delays, as well as the risks and uncertainties inherent in oil
and gas drilling and production activities or which are otherwise discussed in this annual report,
including, without limitation, the portions referenced above, and the uncertainties set forth from
time to time in the Companys other public reports, filings and public statements.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
The information required by Item 3 is set forth under Market Risk Management in Managements
Discussion and Analysis of Financial Condition and Results of Operations.
37
DENBURY RESOURCES INC.
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.
During 2005 and 2006, information was reported on our whistleblower hotline regarding
misconduct by oilfield vendors and certain employees, including alleged improper billings and
payments by certain vendors to, or on behalf of employees, misuse of Company property, services and
operational information by employees, and the failure by certain employees to properly report
transactions with the Company. During 2005 and continuing into 2006, at the direction of the Audit
Committee of our Board of Directors, and in conjunction with outside counsel retained by the Audit
Committee, investigations have been undertaken regarding these matters. These investigations are
substantially complete. As a result of our investigations, we have dismissed eight employees,
taken disciplinary action against another employee, and terminated all future business with certain
vendors. The estimated amount of improper vendor billings and payments and misuse of Company
property and services is inconsequential to our previously issued financial statements and to the
financial statements contained in this report on Form 10-Q. We further believe that these matters
have not, and will not, materially adversely affect our financial condition, results of operations
or business. We believe that our whistleblower hotline was effective in alerting us to improper
vendor and employee conduct and allowing us to remedy the matter.
Controls and policies in place to prevent these occurrences were overridden by employee
misconduct in the vendor approval and payment process and in adherence to the Companys Code of
Business Conduct and Ethics. As a result of our investigation, we have, and are continuing, to
implement certain improvements to strengthen our internal controls (see also Item 9A. Controls and
Procedures Disclosure Controls and Procedures contained in our 2005 Form 10-K for further
information) and to improve our management practices and policies. We anticipate that various
management changes that have been made, or are in the process of being made, will be combined with
emphasis upon strengthening our internal controls through improved management oversight and
enforcement of Company policies and procedures at the field level.
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, 2005. During the second quarter of 2006 we settled litigation that
was disclosed in our 2005 Form 10-K, styled Harry Bourg Corporation vs. Exxon Mobil Corporations,
et al. During the third quarter of 2006, we settled litigation that was disclosed in our 2005 Form
10-K styled J. Paulin Duhe, Inc. vs. Texaco, Inc. et al. These settlements did not have any
material impact on our results of operations or cash flows for any of the periods presented. There
have been no other 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, 2005. There have been no material changes to the
risk factors since the filing of such Form 10-K.
38
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(c) Total Number of |
|
(d) Maximum Number |
|
|
(a) Total |
|
|
|
|
|
Shares Purchased |
|
of Shares that May |
|
|
Number of |
|
(b) Average |
|
as Part of Publicly |
|
Yet Be Purchased |
|
|
Shares |
|
Price Paid |
|
Announced Plans or |
|
Under the Plan Or |
Period |
|
Purchased |
|
per Share |
|
Programs |
|
Programs |
July 1 through 31, 2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
August 1 through 31, 2006 |
|
|
100,565 |
|
|
$ |
34.03 |
|
|
|
|
|
|
|
|
|
September 1 through 30, 2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
100,565 |
|
|
$ |
34.03 |
|
|
|
|
|
|
|
|
|
These shares were purchased from employees of Denbury who delivered shares to the company to
satisfy their minimum tax withholding requirements related to the vesting of restricted shares.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Submission of Matters to a Vote of Security Holders
None.
Item 5. Other Information
None.
Item 6. Exhibits
|
|
|
Exhibits: |
|
|
|
31(a)*
|
|
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
31(b)*
|
|
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
32*
|
|
Certification of Chief Executive Officer and Chief Financial Officer Pursuant to
Section 906 of the
Sarbanes-Oxley Act of 2002. |
39
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 |
|
|
Dated: November 3, 2006
40