þ
|
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Delaware
|
20-0467835
|
|
(State or other jurisdictions of
incorporation or organization)
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(I.R.S. Employer Identification No.)
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|
5320 Legacy Drive
Plano, TX
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75024
|
|
(Address of principal executive offices)
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(Zip Code)
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Large accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
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Smaller reporting company o
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(Do not check if a smaller reporting company)
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Class
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Outstanding at November 1, 2011
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|
Common Stock, $.001 par value
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391,624,449
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Page
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|||||
PART I. FINANCIAL INFORMATION
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|||||
Item 1. Financial Statements
|
|||||
3
|
|||||
4
|
|||||
5
|
|||||
6
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|||||
7
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|||||
18
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|||||
31
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|||||
32
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|||||
PART II. OTHER INFORMATION
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|||||
33
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|||||
33
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|||||
33
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|||||
33
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|||||
34
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|||||
September 30,
|
December 31,
|
|||||||
2011
|
2010
|
|||||||
ASSETS
|
||||||||
Current assets
|
||||||||
Cash and cash equivalents
|
$ | 24,363 | $ | 381,869 | ||||
Accrued production receivable
|
264,999 | 223,584 | ||||||
Trade and other receivables, net of allowance of $274 and $456, respectively
|
176,734 | 114,149 | ||||||
Short-term investments
|
81,851 | 93,020 | ||||||
Derivative assets
|
116,761 | 24,242 | ||||||
Deferred tax assets
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- | 27,454 | ||||||
Total current assets
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664,708 | 864,318 | ||||||
Property and equipment
|
||||||||
Oil and natural gas properties (using full cost accounting)
|
||||||||
Proved
|
6,763,404 | 6,042,442 | ||||||
Unevaluated
|
1,088,733 | 870,130 | ||||||
CO2 and other non-hydrocarbon gases properties
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599,881 | 523,423 | ||||||
Pipelines and plants
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1,598,098 | 1,378,239 | ||||||
Other property and equipment
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142,243 | 120,641 | ||||||
Less accumulated depletion, depreciation, amortization, and impairment
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(2,510,715 | ) | (2,197,517 | ) | ||||
Net property and equipment
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7,681,644 | 6,737,358 | ||||||
Derivative assets
|
56,460 | 12,919 | ||||||
Goodwill
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1,236,094 | 1,232,418 | ||||||
Other assets
|
248,027 | 218,050 | ||||||
Total assets
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$ | 9,886,933 | $ | 9,065,063 | ||||
LIABILITIES AND STOCKHOLDERS' EQUITY
|
||||||||
Current liabilities
|
||||||||
Accounts payable and accrued liabilities
|
$ | 405,243 | $ | 350,068 | ||||
Oil and gas production payable
|
183,521 | 143,145 | ||||||
Derivative liabilities
|
9,253 | 78,184 | ||||||
Current maturities of long-term debt
|
8,177 | 7,948 | ||||||
Deferred taxes
|
37,326 | - | ||||||
Total current liabilities
|
643,520 | 579,345 | ||||||
Long-term liabilities
|
||||||||
Long-term debt, net of current portion
|
2,396,549 | 2,416,208 | ||||||
Asset retirement obligations
|
87,725 | 81,290 | ||||||
Derivative liabilities
|
732 | 29,687 | ||||||
Deferred taxes
|
1,799,793 | 1,547,992 | ||||||
Other liabilities
|
22,842 | 29,834 | ||||||
Total long-term liabilities
|
4,307,641 | 4,105,011 | ||||||
Commitments and contingencies (Note 7)
|
||||||||
Stockholders' equity
|
||||||||
Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding
|
- | - | ||||||
Common stock, $.001 par value, 600,000,000 shares authorized; 402,625,687 and 400,291,033 shares issued, respectively
|
403 | 400 | ||||||
Paid-in capital in excess of par
|
3,085,862 | 3,045,937 | ||||||
Retained earnings
|
1,856,868 | 1,336,142 | ||||||
Accumulated other comprehensive loss
|
(7,361 | ) | (488 | ) | ||||
Treasury stock, at cost, 0 and 78,524 shares, respectively
|
- | (1,284 | ) | |||||
Total stockholders' equity
|
4,935,772 | 4,380,707 | ||||||
Total liabilities and stockholders' equity
|
$ | 9,886,933 | $ | 9,065,063 |
|
|
|
|
|
||||||||||||
|
Three Months Ended
|
Nine Months Ended
|
||||||||||||||
|
September 30,
|
September 30,
|
||||||||||||||
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Revenues and other income
|
|
|
|
|
||||||||||||
Oil, natural gas, and related product sales
|
$ | 565,523 | $ | 460,785 | $ | 1,662,814 | $ | 1,279,699 | ||||||||
CO2 sales and transportation fees
|
6,541 | 4,653 | 16,808 | 13,840 | ||||||||||||
Gain on sale of interests in Genesis
|
- | (3 | ) | - | 101,537 | |||||||||||
Interest income and other income
|
4,441 | 1,268 | 12,445 | 7,658 | ||||||||||||
Total revenues and other income
|
576,505 | 466,703 | 1,692,067 | 1,402,734 | ||||||||||||
|
||||||||||||||||
Expenses
|
||||||||||||||||
Lease operating expenses
|
136,531 | 131,768 | 393,560 | 355,731 | ||||||||||||
Production taxes and marketing expenses
|
36,949 | 35,542 | 109,388 | 92,959 | ||||||||||||
CO2 discovery and operating expenses
|
1,358 | 2,488 | 5,381 | 5,537 | ||||||||||||
General and administrative
|
28,906 | 37,115 | 103,652 | 101,016 | ||||||||||||
Interest, net of amounts capitalized of $17,853, $10,917, $42,004 and $56,079, respectively
|
37,617 | 53,331 | 128,643 | 123,230 | ||||||||||||
Depletion, depreciation, and amortization
|
101,978 | 111,602 | 299,067 | 322,683 | ||||||||||||
Derivatives expense (income)
|
(210,154 | ) | 31,854 | (212,308 | ) | (138,045 | ) | |||||||||
Loss on early extinguishment of debt
|
- | - | 16,131 | - | ||||||||||||
Transaction and other costs related to the Encore Merger
|
- | 11,470 | 4,377 | 79,253 | ||||||||||||
Total expenses
|
133,185 | 415,170 | 847,891 | 942,364 | ||||||||||||
|
||||||||||||||||
Income before income taxes
|
443,320 | 51,533 | 844,176 | 460,370 | ||||||||||||
|
||||||||||||||||
Income tax provision (benefit)
|
||||||||||||||||
Current income taxes
|
(5,331 | ) | 3,704 | 5,849 | 11,314 | |||||||||||
Deferred income taxes
|
172,981 | 16,595 | 317,601 | 167,289 | ||||||||||||
|
||||||||||||||||
Consolidated net income
|
275,670 | 31,234 | 520,726 | 281,767 | ||||||||||||
Less: net income attributable to noncontrolling interest
|
- | (2,130 | ) | - | (20,408 | ) | ||||||||||
Net income attributable to Denbury stockholders
|
$ | 275,670 | $ | 29,104 | $ | 520,726 | $ | 261,359 | ||||||||
|
||||||||||||||||
Net income per common share
|
||||||||||||||||
Basic
|
$ | 0.69 | $ | 0.07 | $ | 1.31 | $ | 0.72 | ||||||||
Diluted
|
$ | 0.68 | $ | 0.07 | $ | 1.29 | $ | 0.71 | ||||||||
|
||||||||||||||||
Weighted average common shares outstanding
|
||||||||||||||||
Basic
|
399,040 | 395,913 | 398,371 | 362,241 | ||||||||||||
Diluted
|
403,311 | 401,093 | 403,575 | 367,434 |
|
Nine Months Ended
|
|||||||
|
September 30,
|
|||||||
|
2011
|
2010
|
||||||
Cash flows from operating activities
|
|
|
||||||
Consolidated net income
|
$ | 520,726 | $ | 281,767 | ||||
Adjustments needed to reconcile to net cash provided by operating activities
|
||||||||
Depletion, depreciation, and amortization
|
299,067 | 322,683 | ||||||
Deferred income taxes
|
317,601 | 167,289 | ||||||
Gain on sale of interests in Genesis
|
- | (101,537 | ) | |||||
Stock-based compensation
|
27,520 | 27,326 | ||||||
Non-cash fair value derivative adjustments
|
(217,092 | ) | (185,009 | ) | ||||
Loss on early extinguishment of debt
|
16,131 | - | ||||||
Other, net
|
9,024 | 14,254 | ||||||
Changes in operating assets and liabilities
|
||||||||
Accrued production receivable
|
(45,017 | ) | 48,453 | |||||
Trade and other receivables
|
(53,012 | ) | 20,548 | |||||
Other assets
|
2,818 | 1,106 | ||||||
Accounts payable and accrued liabilities
|
(65,407 | ) | 8,257 | |||||
Oil and natural gas production payable
|
40,819 | 10,553 | ||||||
Other liabilities
|
(14,086 | ) | (22,915 | ) | ||||
Net cash provided by operating activities
|
839,092 | 592,775 | ||||||
|
||||||||
Cash flows used for investing activities
|
||||||||
Oil and natural gas capital expenditures
|
(741,256 | ) | (500,062 | ) | ||||
Acquisitions of oil and natural gas properties
|
(34,291 | ) | (24,390 | ) | ||||
Cash paid in Encore Merger, net of cash acquired
|
- | (813,894 | ) | |||||
Cash paid in Riley Ridge acquisition
|
(199,233 | ) | - | |||||
CO2 and other non-hydrocarbon gases capital expenditures
|
(65,866 | ) | (67,328 | ) | ||||
Pipelines and plants capital expenditures
|
(142,406 | ) | (169,157 | ) | ||||
Net proceeds from sales of oil and natural gas properties
|
47,598 | 909,986 | ||||||
Net proceeds from sale of interests in Genesis
|
- | 162,619 | ||||||
Other
|
(22,798 | ) | (17,927 | ) | ||||
Net cash used for investing activities
|
(1,158,252 | ) | (520,153 | ) | ||||
|
||||||||
Cash flows from financing activities
|
||||||||
Bank repayments
|
(255,000 | ) | (1,519,000 | ) | ||||
Bank borrowings
|
365,000 | 1,229,000 | ||||||
Repayment of senior subordinated notes
|
(525,000 | ) | (609,424 | ) | ||||
Premium paid on repayment of senior subordinated notes
|
(13,137 | ) | (7,213 | ) | ||||
Net proceeds from issuance of senior subordinated notes
|
400,000 | 1,000,000 | ||||||
Net proceeds from issuance of common stock
|
12,348 | 8,614 | ||||||
Costs of debt financing
|
(13,104 | ) | (76,232 | ) | ||||
ENP distributions to noncontrolling interest
|
- | (24,513 | ) | |||||
Other
|
(9,453 | ) | (8,100 | ) | ||||
Net cash used for financing activities
|
(38,346 | ) | (6,868 | ) | ||||
|
||||||||
Net increase (decrease) in cash and cash equivalents
|
(357,506 | ) | 65,754 | |||||
Cash and cash equivalents at beginning of period
|
381,869 | 20,591 | ||||||
Cash and cash equivalents at end of period
|
$ | 24,363 | $ | 86,345 |
|
Three Months Ended
|
Nine Months Ended
|
||||||||||||||
|
September 30,
|
September 30,
|
||||||||||||||
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Consolidated net income
|
$ | 275,670 | $ | 31,234 | $ | 520,726 | $ | 281,767 | ||||||||
Other comprehensive income, net of income tax
|
||||||||||||||||
Net unrealized loss on available-for-sale securities, net of tax benefit of $2,420 and $4,244, respectively
|
(3,949 | ) | - | (6,925 | ) | - | ||||||||||
Interest rate lock derivative contracts reclassified to income, net of tax of $11, $11, $32, and $32, respectively
|
17 | 17 | 52 | 52 | ||||||||||||
Change in deferred hedge loss on interest rate swaps, net of tax benefit of $14 and $32, respectively
|
- | (68 | ) | - | (155 | ) | ||||||||||
Consolidated comprehensive income
|
271,738 | 31,183 | 513,853 | 281,664 | ||||||||||||
Less: comprehensive income attributable to noncontrolling interest
|
- | (2,074 | ) | - | (20,308 | ) | ||||||||||
Comprehensive income attributable to Denbury stockholders
|
$ | 271,738 | $ | 29,109 | $ | 513,853 | $ | 261,356 |
|
Three Months Ended
|
Nine Months Ended
|
||||||||||||||
|
September 30,
|
September 30,
|
||||||||||||||
In thousands
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Basic weighted average common shares
|
399,040 | 395,913 | 398,371 | 362,241 | ||||||||||||
Potentially dilutive securities:
|
||||||||||||||||
Stock options and SARs
|
2,954 | 3,647 | 3,818 | 3,772 | ||||||||||||
Performance equity awards
|
41 | 292 | 22 | 305 | ||||||||||||
Restricted stock
|
1,276 | 1,241 | 1,364 | 1,116 | ||||||||||||
Diluted weighted average common shares
|
403,311 | 401,093 | 403,575 | 367,434 |
|
Three Months Ended
|
Nine Months Ended
|
||||||||||||||
|
September 30,
|
September 30,
|
||||||||||||||
In thousands
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Stock options and SARs
|
4,731 | 4,270 | 3,108 | 4,613 | ||||||||||||
Restricted stock
|
139 | 69 | 56 | 298 |
In thousands
|
|
|||
Consideration:
|
|
|||
Cash payment
|
$ | 199,554 | ||
Deferred payment(1)
|
15,000 | |||
Total consideration
|
214,554 | |||
|
||||
Less: Fair value of assets and liabilities acquired:(2)
|
||||
Oil and natural gas properties
|
||||
Proved
|
48,731 | |||
Unevaluated
|
12,542 | |||
CO2 and other non-hydrocarbon gases properties
|
9,741 | |||
Pipelines and plants
|
91,594 | |||
Other assets(3)
|
48,660 | |||
Asset retirement obligations
|
(389 | ) | ||
|
210,879 | |||
|
||||
Goodwill
|
$ | 3,675 | ||
|
||||
(1) The deferred payment is included in "Accounts payable and accrued liabilities" on the accompanying balance sheet and will be paid at the time the property’s gas plant is operational and meets specific performance conditions as described above. | ||||
(2) Fair value of the assets acquired and liabilities assumed is preliminary, pending final closing adjustments. | ||||
(3) Other assets includes helium extraction rights of $36.7 million. Helium reserves at Riley Ridge are owned primarily by the Federal government. The fair value assigned to helium extraction rights was calculated using the income approach and represents the future net revenues associated with the Company’s right to extract and sell the helium on behalf of the helium resource owners. Upon commencement of helium production, helium extraction rights will be amortized on a units-of-production basis. |
|
Pro Forma Results
|
|||||||
In thousands, except per share amounts
|
Three Months Ended September 30, 2010
|
Nine Months Ended September 30, 2010
|
||||||
Pro forma total revenues
|
$ | 466,703 | $ | 1,579,184 | ||||
Pro forma net income attributable to Denbury stockholders
|
29,104 | 276,527 | ||||||
Pro forma net income per common share:
|
||||||||
Basic
|
$ | 0.07 | $ | 0.70 | ||||
Diluted
|
0.07 | 0.69 |
|
September 30,
|
December 31,
|
||||||
In thousands
|
2011
|
2010
|
||||||
Bank Credit Agreement
|
$ | 110,000 | $ | - | ||||
7½% Senior Subordinated Notes due 2013, including discount of $437
|
- | 224,563 | ||||||
7½% Senior Subordinated Notes due 2015, including premium of $427
|
- | 300,427 | ||||||
9½% Senior Subordinated Notes due 2016, including premium of $12,538 and $14,589, respectively
|
237,458 | 239,509 | ||||||
9¾% Senior Subordinated Notes due 2016, including discount of $18,925 and $22,139, respectively
|
407,425 | 404,211 | ||||||
8¼% Senior Subordinated Notes due 2020
|
996,273 | 996,273 | ||||||
6⅜% Senior Subordinated Notes due 2021
|
400,000 | - | ||||||
Other Subordinated Notes, including premium of $35 and $41, respectively
|
3,841 | 3,848 | ||||||
NEJD Pipeline financing
|
164,626 | 167,331 | ||||||
Free State Pipeline financing
|
80,093 | 81,188 | ||||||
Capital lease obligations
|
5,010 | 6,806 | ||||||
Total
|
2,404,726 | 2,424,156 | ||||||
Less current obligations
|
(8,177 | ) | (7,948 | ) | ||||
Long-term debt and capital lease obligations
|
$ | 2,396,549 | $ | 2,416,208 |
|
Three Months Ended
|
Nine Months Ended
|
||||||||||||||
|
September 30,
|
September 30,
|
||||||||||||||
In thousands
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Oil
|
|
|
|
|
||||||||||||
Payment on settlements of derivative contracts
|
$ | 1,857 | $ | 3,590 | $ | 23,857 | $ | 80,969 | ||||||||
Fair value adjustments to derivative contracts - expense (income)
|
(205,355 | ) | 62,450 | (225,485 | ) | (144,471 | ) | |||||||||
Total derivative expense (income) - oil
|
(203,498 | ) | 66,040 | (201,628 | ) | (63,502 | ) | |||||||||
Natural Gas
|
||||||||||||||||
Receipt on settlements of derivative contracts
|
(6,427 | ) | (13,626 | ) | (19,073 | ) | (34,005 | ) | ||||||||
Fair value adjustments to derivative contracts - expense (income)
|
(229 | ) | (19,933 | ) | 8,393 | (39,041 | ) | |||||||||
Total derivative expense (income) - natural gas
|
(6,656 | ) | (33,559 | ) | (10,680 | ) | (73,046 | ) | ||||||||
Ineffectiveness on interest rate swaps
|
- | (627 | ) | - | (1,497 | ) | ||||||||||
Derivative expense (income)
|
$ | (210,154 | ) | $ | 31,854 | $ | (212,308 | ) | $ | (138,045 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX Contract Prices Per Bbl
|
|||||||
|
|
|
|
|
|
Type of
|
|
|
|
Weighted Average Price
|
|||||||
Year
|
|
Months
|
|
Contract
|
|
Bbls/d
|
|
Swap
|
|
Floor
|
|
Ceiling
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
2011
|
|
Oct - Dec
|
|
Swap
|
|
625
|
|
$
|
79.18
|
|
$
|
-
|
|
$
|
-
|
||
|
|
|
|
|
|
Collar
|
|
45,500
|
|
|
-
|
|
|
70.33
|
|
|
101.74
|
|
|
|
|
|
|
Put
|
|
6,625
|
|
|
-
|
|
|
69.53
|
|
|
-
|
|
|
|
|
Total Oct - Dec 2011
|
|
52,750
|
|
|
|
|
|
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012
|
|
Jan - Mar
|
|
Swap
|
|
625
|
|
|
81.04
|
|
|
-
|
|
|
-
|
||
|
|
|
|
|
|
Collar
|
|
52,000
|
|
|
-
|
|
|
70.00
|
|
|
106.86
|
|
|
|
|
|
|
Put
|
|
625
|
|
|
-
|
|
|
65.00
|
|
|
-
|
|
|
|
|
Total Jan - Mar 2012
|
|
53,250
|
|
|
|
|
|
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Apr-June
|
|
Swap
|
|
625
|
|
|
81.04
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
Collar
|
|
53,000
|
|
|
-
|
|
|
70.00
|
|
|
119.44
|
|
|
|
|
|
|
Put
|
|
625
|
|
|
-
|
|
|
65.00
|
|
|
-
|
|
|
|
|
Total Apr - June 2012
|
|
54,250
|
|
|
|
|
|
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July-Sept
|
|
Swap
|
|
625
|
|
|
81.04
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
Collar
|
|
53,000
|
|
|
-
|
|
|
80.00
|
|
|
128.57
|
|
|
|
|
|
|
Put
|
|
625
|
|
|
-
|
|
|
65.00
|
|
|
-
|
|
|
|
|
Total July - Sept 2012
|
|
54,250
|
|
|
|
|
|
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oct - Dec
|
|
Swap
|
|
625
|
|
|
81.04
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
Collar
|
|
53,000
|
|
|
-
|
|
|
80.00
|
|
|
128.57
|
|
|
|
|
|
|
Put
|
|
625
|
|
|
-
|
|
|
65.00
|
|
|
-
|
|
|
|
|
Total Oct - Dec 2012
|
|
54,250
|
|
|
|
|
|
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013
|
|
Jan - Mar
|
|
Collar
|
|
16,000
|
|
|
-
|
|
|
70.00
|
|
|
112.66
|
||
|
|
|
|
Total Jan - Mar 2013
|
|
16,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Type of
|
|
|
|
Weighted Average Swap
|
|
Year
|
|
Months
|
|
Contract
|
|
MMBtu/d
|
|
Price per MMBtu
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Contracts
|
|
|
|
|
|
||||||
2011
|
|
Oct - Dec
|
|
Swap
|
|
33,500
|
|
$
|
6.27
|
||
|
|
|
|
Total Oct - Dec 2011
|
|
33,500
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
2012
|
|
Jan - Dec
|
|
Swap
|
|
20,000
|
|
|
6.53
|
||
|
|
|
|
Total Jan - Dec 2012
|
|
20,000
|
|
|
|
|
|
Estimated Fair Value
|
|||||||
|
|
Asset (Liability)
|
|||||||
In thousands
|
|
September 30,
|
December 31,
|
||||||
Type of Contract
|
Balance Sheet Location
|
2011
|
2010
|
||||||
Derivatives not designated as hedging instruments:
|
|
|
|
||||||
Derivative asset
|
|
|
|
||||||
Oil contracts
|
Derivative assets - current
|
$ | 96,177 | $ | 3,050 | ||||
Natural gas contracts
|
Derivative assets - current
|
20,584 | 21,192 | ||||||
Oil contracts
|
Derivative assets - long-term
|
52,627 | 1,301 | ||||||
Natural gas contracts
|
Derivative assets - long-term
|
3,833 | 11,618 | ||||||
|
|
||||||||
Derivative liability
|
|
||||||||
Oil contracts
|
Derivative liabilities - current
|
(60 | ) | (55,256 | ) | ||||
Deferred premiums
|
Derivative liabilities - current
|
(9,193 | ) | (22,928 | ) | ||||
Oil contracts
|
Derivative liabilities - long-term
|
(70 | ) | (25,906 | ) | ||||
Deferred premiums
|
Derivative liabilities - long-term
|
(662 | ) | (3,781 | ) | ||||
Total derivatives not designated as hedging instruments
|
|
$ | 163,236 | $ | (70,710 | ) |
|
•
|
Level 1 - Quoted prices in active markets for identical assets or liabilities as of the reporting date.
|
|
•
|
Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded oil and natural gas derivatives that are based on NYMEX pricing.
|
|
•
|
Level 3 - Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. Instruments in this category include non-exchange-traded natural gas derivatives swaps that are based on regional pricing other than NYMEX (e.g., Houston Ship Channel).
|
|
Fair Value Measurements Using:
|
|||||||||||||||
|
|
Significant
|
|
|
||||||||||||
|
Quoted Prices
|
Other
|
Significant
|
|
||||||||||||
|
in Active
|
Observable
|
Unobservable
|
|
||||||||||||
|
Markets
|
Inputs
|
Inputs
|
|
||||||||||||
In thousands
|
(Level 1)
|
(Level 2)
|
(Level 3)
|
Total
|
||||||||||||
September 30, 2011
|
|
|||||||||||||||
Assets
|
|
|
|
|
||||||||||||
Short-term investments
|
$ | 81,851 | $ | - | $ | - | $ | 81,851 | ||||||||
Oil and natural gas derivative contracts
|
- | 166,244 | 6,977 | 173,221 | ||||||||||||
Liabilities
|
||||||||||||||||
Oil and natural gas derivative contracts
|
- | (130 | ) | - | (130 | ) | ||||||||||
Total
|
$ | 81,851 | $ | 166,114 | $ | 6,977 | $ | 254,942 | ||||||||
|
||||||||||||||||
December 31, 2010
|
||||||||||||||||
Assets
|
||||||||||||||||
Short-term investments
|
$ | 93,020 | $ | - | $ | - | $ | 93,020 | ||||||||
Oil and natural gas derivative contracts
|
- | 20,683 | 16,478 | 37,161 | ||||||||||||
Liabilities
|
||||||||||||||||
Oil and natural gas derivative contracts
|
- | (81,162 | ) | - | (81,162 | ) | ||||||||||
Total
|
$ | 93,020 | $ | (60,479 | ) | $ | 16,478 | $ | 49,019 |
|
Three Months Ended
|
Nine Months Ended
|
||||||||||||||
|
September 30,
|
September 30,
|
||||||||||||||
In thousands
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Balance, beginning of period
|
$ | 6,638 | $ | 40,283 | $ | 16,478 | $ | - | ||||||||
Unrealized gains (losses) on commodity derivative contracts included in earnings
|
1,717 | 20,103 | (5,359 | ) | 35,002 | |||||||||||
Commodity derivative contracts acquired from Encore
|
- | - | - | 38,093 | ||||||||||||
Receipts on settlement of commodity derivative contracts
|
(1,378 | ) | (9,035 | ) | (4,142 | ) | (21,744 | ) | ||||||||
Balance, end of period
|
$ | 6,977 | $ | 51,351 | $ | 6,977 | $ | 51,351 |
|
September 30, 2011
|
December 31, 2010
|
||||||||||||||
|
Carrying
|
Estimated
|
Carrying
|
Estimated
|
||||||||||||
In thousands
|
Amount
|
Fair Value
|
Amount
|
Fair Value
|
||||||||||||
7½% Senior Subordinated Notes due 2013
|
$ | - | $ | - | $ | 224,563 | $ | 228,375 | ||||||||
7½% Senior Subordinated Notes due 2015
|
- | - | 300,427 | 310,500 | ||||||||||||
9½% Senior Subordinated Notes due 2016
|
237,458 | 242,914 | 239,509 | 249,661 | ||||||||||||
9¾% Senior Subordinated Notes due 2016
|
407,425 | 460,458 | 404,211 | 475,380 | ||||||||||||
8¼% Senior Subordinated Notes due 2020
|
996,273 | 1,046,087 | 996,273 | 1,080,956 | ||||||||||||
6⅜% Senior Subordinated Notes due 2021
|
400,000 | 388,000 | - | - |
|
September 30,
|
December 31,
|
||||||
In thousands
|
2011
|
2010
|
||||||
Accounts payable
|
$ | 107,391 | $ | 47,660 | ||||
Accrued exploration and development costs
|
143,647 | 101,758 | ||||||
Accrued compensation
|
27,476 | 39,757 | ||||||
Accrued lease operating expense
|
30,005 | 23,557 | ||||||
Accrued interest
|
28,957 | 57,077 | ||||||
Taxes payable
|
19,214 | 34,371 | ||||||
Deferred Riley Ridge acquisition consideration
|
15,000 | - | ||||||
Other
|
33,553 | 45,888 | ||||||
Total
|
$ | 405,243 | $ | 350,068 |
|
Nine Months Ended
|
|||||||
|
September 30,
|
|||||||
In thousands
|
2011
|
2010
|
||||||
Cash paid for interest, expensed
|
$ | 137,289 | $ | 114,012 | ||||
Cash paid for interest, capitalized
|
42,004 | 56,079 | ||||||
Cash paid for income taxes
|
36,688 | 13,691 | ||||||
Cash received for income tax refunds
|
21,990 | 13,525 | ||||||
Increase in liabilities for capital expenditures
|
86,769 | 13,880 | ||||||
Issuance of Denbury common stock in connection with the Encore Merger
|
- | 2,085,681 |
·
|
incremental income of $248.1 million ($153.8 million after tax) attributable to the non-cash increase in the fair value of the Company’s commodity derivative contracts, principally due to the change in NYMEX oil futures prices; and
|
·
|
an increase in revenue of $104.7 million ($64.9 million after tax), or 23%, as a result of higher commodity prices, partially offset by lower production as a result of asset sales in late 2010.
|
·
|
$475 million allocated for tertiary oil field expenditures;
|
·
|
$400 million in the Bakken area of North Dakota;
|
·
|
$200 million to be spent on our CO2 pipelines;
|
·
|
$200 million to be spent on CO2 sources in the Jackson Dome and Riley Ridge areas; and
|
·
|
$75 million on drilling, completion and other development activities in our other areas.
|
Nine Months Ended
|
||||||||
September 30,
|
||||||||
In thousands
|
2011
|
2010
|
||||||
Oil and natural gas exploration and development:
|
|
|
||||||
Drilling
|
$ | 399,812 | $ | 242,302 | ||||
Geological, geophysical, and acreage
|
26,609 | 23,381 | ||||||
Facilities
|
195,928 | 99,797 | ||||||
Recompletions
|
177,569 | 136,357 | ||||||
Capitalized interest
|
31,116 | 23,672 | ||||||
Total oil and natural gas exploration and development expenditures
|
831,034 | 525,509 | ||||||
CO2 and other non-hydrocarbon gases capital expenditures:
|
||||||||
Drilling
|
47,750 | 29,222 | ||||||
Geological, geophysical, and acreage
|
9,314 | 17,341 | ||||||
Facilities
|
24,926 | 20,291 | ||||||
Total CO2 and other non-hydrocarbon gases capital expenditures
|
81,990 | 66,854 | ||||||
Pipelines and plants capital expenditures:
|
||||||||
Pipelines and plants
|
114,024 | 138,511 | ||||||
Capitalized interest
|
10,888 | 32,407 | ||||||
Total pipelines and plants capital expenditures
|
124,912 | 170,918 | ||||||
Total capital expenditures excluding acquisitions
|
1,037,936 | 763,281 | ||||||
Oil and natural gas property acquisitions
|
34,291 | 24,390 | ||||||
Consideration for the Encore Merger(1)
|
- | 2,952,515 | ||||||
Consideration for August 2011 Riley Ridge acquisition
|
214,554 | - | ||||||
Total
|
$ | 1,286,781 | $ | 3,740,186 |
|
Average Daily Production (Bbls/d)
|
|||||||||||||||||||||||||||
|
First
|
Second
|
Third
|
Fourth
|
First
|
Second
|
Third
|
|||||||||||||||||||||
|
Quarter
|
Quarter
|
Quarter
|
Quarter
|
Quarter
|
Quarter
|
Quarter
|
|||||||||||||||||||||
Tertiary Oil Field
|
2010
|
2010
|
2010
|
2010
|
2011
|
2011
|
2011
|
|||||||||||||||||||||
Phase 1:
|
|
|
|
|
|
|
|
|||||||||||||||||||||
Brookhaven
|
3,416 | 3,277 | 3,323 | 3,699 | 3,664 | 3,213 | 3,030 | |||||||||||||||||||||
McComb area
|
2,289 | 2,160 | 2,484 | 2,433 | 2,161 | 1,983 | 2,005 | |||||||||||||||||||||
Mallalieu area
|
3,443 | 3,628 | 3,279 | 3,164 | 2,925 | 2,646 | 2,620 | |||||||||||||||||||||
Other
|
2,817 | 3,282 | 3,343 | 3,361 | 3,290 | 3,196 | 2,879 | |||||||||||||||||||||
Phase 2:
|
||||||||||||||||||||||||||||
Heidelberg
|
1,708 | 1,857 | 2,806 | 3,422 | 3,374 | 3,548 | 3,141 | |||||||||||||||||||||
Eucutta
|
3,792 | 3,625 | 3,284 | 3,286 | 3,247 | 3,114 | 2,985 | |||||||||||||||||||||
Soso
|
3,213 | 3,207 | 3,016 | 2,828 | 2,582 | 2,317 | 2,331 | |||||||||||||||||||||
Martinville
|
927 | 764 | 606 | 586 | 500 | 416 | 453 | |||||||||||||||||||||
Phase 3:
|
||||||||||||||||||||||||||||
Tinsley
|
4,419 | 5,248 | 6,024 | 6,614 | 6,567 | 6,990 | 7,075 | |||||||||||||||||||||
Phase 4:
|
||||||||||||||||||||||||||||
Cranfield
|
936 | 811 | 855 | 1,043 | 991 | 1,085 | 1,214 | |||||||||||||||||||||
Phase 5:
|
||||||||||||||||||||||||||||
Delhi
|
63 | 648 | 511 | 703 | 1,524 | 2,263 | 3,358 | |||||||||||||||||||||
Total tertiary oil production
|
27,023 | 28,507 | 29,531 | 31,139 | 30,825 | 30,771 | 31,091 | |||||||||||||||||||||
|
||||||||||||||||||||||||||||
Tertiary operating expense per Bbl
|
$ | 22.67 | $ | 21.37 | $ | 22.54 | $ | 22.26 | $ | 25.40 | $ | 23.35 | $ | 25.34 |
|
Three Months Ended
|
Nine Months Ended
|
||||||||||||||
|
September 30,
|
September 30,
|
||||||||||||||
In thousands, except per share and unit data
|
2011
|
2010(1)
|
2011
|
2010(1)
|
||||||||||||
Operating results:
|
|
|
||||||||||||||
Net income attributable to Denbury stockholders
|
$ | 275,670 | $ | 29,104 | $ | 520,726 | $ | 261,359 | ||||||||
Net income per common share - basic
|
0.69 | 0.07 | 1.31 | 0.72 | ||||||||||||
Net income per common share - diluted
|
0.68 | 0.07 | 1.29 | 0.71 | ||||||||||||
Cash flow from operations
|
315,739 | 208,484 | 839,092 | 592,775 | ||||||||||||
Average daily production volumes:
|
||||||||||||||||
Bbls/d
|
61,984 | 64,233 | 60,007 | 58,234 | ||||||||||||
Mcf/d
|
29,079 | 80,983 | 30,736 | 81,065 | ||||||||||||
BOE/d
|
66,830 | 77,730 | 65,129 | 71,745 | ||||||||||||
Operating revenues:
|
||||||||||||||||
Oil sales
|
$ | 552,281 | $ | 426,896 | $ | 1,621,047 | $ | 1,176,085 | ||||||||
Natural gas sales
|
13,242 | 33,889 | 41,767 | 103,614 | ||||||||||||
Total oil and natural gas sales
|
$ | 565,523 | $ | 460,785 | $ | 1,662,814 | $ | 1,279,699 | ||||||||
Commodity derivative contracts: (2)
|
||||||||||||||||
Net cash receipts (payments) on settlement of commodity derivative contracts
|
$ | 4,570 | $ | 10,036 | $ | (4,784 | ) | $ | (46,964 | ) | ||||||
Non-cash fair value derivative gains (losses)
|
205,584 | (42,517 | ) | 217,092 | 183,512 | |||||||||||
Total income (expense) from commodity derivative contracts
|
$ | 210,154 | $ | (32,481 | ) | $ | 212,308 | $ | 136,548 | |||||||
Operating expenses:
|
||||||||||||||||
Lease operating
|
$ | 136,531 | $ | 131,768 | $ | 393,560 | $ | 355,731 | ||||||||
Production taxes and marketing
|
36,949 | 35,542 | 109,388 | 92,959 | ||||||||||||
Total production expenses
|
$ | 173,480 | $ | 167,310 | $ | 502,948 | $ | 448,690 | ||||||||
Unit prices - including impact of derivative settlements: (2)
|
||||||||||||||||
Oil price per Bbl
|
$ | 96.52 | $ | 71.63 | $ | 97.50 | $ | 68.88 | ||||||||
Natural gas price per Mcf
|
7.35 | 6.38 | 7.25 | 6.22 | ||||||||||||
Unit prices - excluding impact of derivative settlements: (2)
|
||||||||||||||||
Oil price per Bbl
|
$ | 96.85 | $ | 72.24 | $ | 98.95 | $ | 73.98 | ||||||||
Natural gas price per Mcf
|
4.95 | 4.55 | 4.98 | 4.68 | ||||||||||||
|
||||||||||||||||
Oil and natural gas operating revenues and expenses per BOE:
|
||||||||||||||||
Oil and natural gas revenues
|
$ | 91.98 | $ | 64.44 | $ | 93.52 | $ | 65.34 | ||||||||
|
||||||||||||||||
Oil and natural gas lease operating expenses
|
$ | 22.21 | $ | 18.43 | $ | 22.13 | $ | 18.16 | ||||||||
Oil and natural gas production taxes and marketing expense
|
6.01 | 4.97 | 6.15 | 4.75 | ||||||||||||
Total oil and natural gas production expenses
|
$ | 28.22 | $ | 23.40 | $ | 28.28 | $ | 22.91 | ||||||||
(1) Includes the results of operations of Encore properties and ENP from March 9, 2010 through September 30, 2010. | ||||||||||||||||
(2) See Item 3, Qualitative and Quantitative Disclosures about Market Risk, for additional information concerning our commodity derivative contracts. |
|
Average Daily Production (BOE/d)
|
|||||||||||||||||||||||||||||||
|
First Quarter
|
Pro Forma
|
Second Quarter
|
Third Quarter
|
Fourth Quarter
|
First Quarter
|
Second Quarter
|
Third Quarter
|
||||||||||||||||||||||||
|
First Quarter
|
|||||||||||||||||||||||||||||||
Operating Area
|
2010(1)
|
2010(2)
|
2010
|
2010
|
2010
|
2011
|
2011
|
2011
|
||||||||||||||||||||||||
Gulf Coast Region:
|
|
|
|
|
|
|
||||||||||||||||||||||||||
Tertiary oil fields
|
27,023 | 27,023 | 28,507 | 29,531 | 31,139 | 30,825 | 30,771 | 31,091 | ||||||||||||||||||||||||
Non-tertiary fields:
|
||||||||||||||||||||||||||||||||
Mississippi
|
7,829 | 7,829 | 8,967 | 7,965 | 7,293 | 7,586 | 7,333 | 7,193 | ||||||||||||||||||||||||
Texas
|
5,235 | 5,235 | 5,148 | 4,824 | 4,564 | 4,371 | 4,202 | 4,096 | ||||||||||||||||||||||||
Louisiana
|
662 | 662 | 775 | 714 | 687 | 767 | 659 | 214 | ||||||||||||||||||||||||
Alabama and other
|
997 | 997 | 1,078 | 1,091 | 1,026 | 1,026 | 1,084 | 1,072 | ||||||||||||||||||||||||
Total Gulf Coast Region
|
41,746 | 41,746 | 44,475 | 44,125 | 44,709 | 44,575 | 44,049 | 43,666 | ||||||||||||||||||||||||
|
||||||||||||||||||||||||||||||||
Rocky Mountain Region:
|
||||||||||||||||||||||||||||||||
Cedar Creek Anticline
|
2,537 | 9,830 | 9,967 | 9,791 | 9,328 | 9,163 | 8,925 | 8,930 | ||||||||||||||||||||||||
Bakken
|
890 | 3,549 | 4,500 | 4,657 | 5,193 | 5,728 | 7,626 | 9,976 | ||||||||||||||||||||||||
Bell Creek
|
252 | 966 | 997 | 994 | 957 | 890 | 936 | 889 | ||||||||||||||||||||||||
Paradox
|
173 | 675 | 702 | 738 | 716 | 635 | 690 | 680 | ||||||||||||||||||||||||
Other
|
777 | 2,925 | 2,944 | 2,889 | 2,809 | 2,613 | 2,693 | 2,689 | ||||||||||||||||||||||||
Total Rocky Mountain Region
|
4,629 | 17,945 | 19,110 | 19,069 | 19,003 | 19,029 | 20,870 | 23,164 | ||||||||||||||||||||||||
|
||||||||||||||||||||||||||||||||
Total Continuing Production
|
46,375 | 59,691 | 63,585 | 63,194 | 63,712 | 63,604 | 64,919 | 66,830 | ||||||||||||||||||||||||
|
||||||||||||||||||||||||||||||||
Disposed Properties:
|
||||||||||||||||||||||||||||||||
Legacy Encore properties
|
4,479 | 17,853 | 11,684 | 5,906 | 4,156 | - | - | - | ||||||||||||||||||||||||
ENP
|
2,271 | 9,034 | 8,842 | 8,630 | 8,567 | - | - | - | ||||||||||||||||||||||||
Total Production
|
53,125 | 86,578 | 84,111 | 77,730 | 76,435 | 63,604 | 64,919 | 66,830 | ||||||||||||||||||||||||
|
||||||||||||||||||||||||||||||||
(1) Includes production of Encore and ENP from March 9, 2010 through March 31, 2010. | ||||||||||||||||||||||||||||||||
(2) Represents pro forma production assuming we had reported the production from the Encore Merger beginning January 1, 2010. |
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
||||||
|
|
2011 vs. 2010
|
|
2011 vs. 2010
|
||||||
In thousands
|
|
Increase (Decrease) in Revenues
|
|
Percentage Increase (Decrease) in Revenues
|
|
Increase (Decrease) in Revenues
|
|
Percentage Increase (Decrease) in Revenues
|
||
Change in oil and natural gas revenues due to:
|
|
|
|
|
|
|
|
|
|
|
Increase in commodity prices
|
|
$
|
169,368
|
|
37%
|
|
$
|
501,114
|
|
39%
|
Decrease in production
|
|
|
(64,630)
|
|
(14%)
|
|
|
(117,999)
|
|
(9%)
|
Total increase in oil and natural gas revenues
|
|
$
|
104,738
|
|
23%
|
|
$
|
383,115
|
|
30%
|
|
Three Months Ended
|
Three Months Ended
|
Three Months Ended
|
Nine Months Ended
|
||||||||||||||||||||||||||||
|
March 31,
|
June 30,
|
September 30,
|
September 30,
|
||||||||||||||||||||||||||||
|
2011
|
2010
|
2011
|
2010
|
2011
|
2010
|
2011
|
2010
|
||||||||||||||||||||||||
Net Realized Prices:
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||
Oil price per Bbl
|
$ | 93.67 | $ | 76.53 | $ | 106.30 | $ | 73.99 | $ | 96.85 | $ | 72.24 | $ | 98.95 | $ | 73.98 | ||||||||||||||||
Natural gas price per Mcf
|
4.81 | 5.40 | 5.16 | 4.44 | 4.95 | 4.55 | 4.98 | 4.68 | ||||||||||||||||||||||||
Price per BOE
|
88.42 | 69.21 | 100.06 | 63.76 | 91.98 | 64.44 | 93.52 | 65.34 | ||||||||||||||||||||||||
|
||||||||||||||||||||||||||||||||
NYMEX Differentials:
|
||||||||||||||||||||||||||||||||
Oil per Bbl
|
$ | (0.59 | ) | $ | (2.08 | ) | $ | 3.72 | $ | (4.13 | ) | $ | 7.25 | $ | (3.85 | ) | $ | 3.49 | $ | (3.62 | ) | |||||||||||
Natural gas per Mcf
|
0.61 | 0.37 | 0.78 | 0.09 | 0.89 | 0.31 | 0.77 | 0.14 |
|
Three Months Ended September 30,
|
|||||||||||||||||||||||
|
2011
|
2010
|
2011
|
2010
|
2011
|
2010
|
||||||||||||||||||
In thousands
|
Oil
Derivative Contracts
|
Natural Gas
Derivative Contracts
|
Total Commodity Derivative Contracts
|
|||||||||||||||||||||
Non-cash fair value gain (loss)
|
$ | 205,355 | $ | (62,450 | ) | $ | 229 | $ | 19,933 | $ | 205,584 | $ | (42,517 | ) | ||||||||||
Cash settlement receipts (payments)
|
(1,857 | ) | (3,590 | ) | 6,427 | 13,626 | 4,570 | 10,036 | ||||||||||||||||
Total
|
$ | 203,498 | $ | (66,040 | ) | $ | 6,656 | $ | 33,559 | $ | 210,154 | $ | (32,481 | ) |
|
Nine Months Ended September 30,
|
|||||||||||||||||||||||
|
2011
|
2010
|
2011
|
2010
|
2011
|
2010
|
||||||||||||||||||
In thousands
|
Oil Derivative Contracts
|
Natural Gas Derivative Contracts
|
Total Commodity Derivative Contracts
|
|||||||||||||||||||||
Non-cash fair value gain (loss)
|
$ | 225,485 | 144,471 | (8,393 | ) | 39,041 | $ | 217,092 | $ | 183,512 | ||||||||||||||
Cash settlement receipts (payments)
|
(23,857 | ) | (80,969 | ) | 19,073 | 34,005 | (4,784 | ) | (46,964 | ) | ||||||||||||||
Total
|
$ | 201,628 | $ | 63,502 | $ | 10,680 | $ | 73,046 | $ | 212,308 | $ | 136,548 |
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||
September 30,
|
September 30,
|
|||||||||||||||
In thousands, except per BOE data and employees
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Gross G&A expenses (excluding stock compensation)
|
$ | 57,061 | $ | 61,532 | $ | 184,895 | $ | 167,715 | ||||||||
Gross stock-based compensation
|
11,154 | 9,832 | 32,178 | 27,134 | ||||||||||||
State franchise taxes
|
1,894 | 952 | 4,721 | 2,987 | ||||||||||||
Operator labor and overhead recovery charges
|
(31,720 | ) | (30,633 | ) | (92,859 | ) | (81,764 | ) | ||||||||
Capitalized exploration and development costs
|
(9,483 | ) | (4,568 | ) | (25,283 | ) | (15,056 | ) | ||||||||
Net G&A expense
|
$ | 28,906 | $ | 37,115 | $ | 103,652 | $ | 101,016 | ||||||||
G&A per BOE:
|
||||||||||||||||
Net G&A expense(1)
|
$ | 2.94 | $ | 3.88 | $ | 4.14 | $ | 3.83 | ||||||||
Net stock-based compensation(1)
|
1.45 | 1.18 | 1.42 | 1.18 | ||||||||||||
State franchise taxes
|
0.31 | 0.13 | 0.27 | 0.15 | ||||||||||||
Net G&A expense
|
$ | 4.70 | $ | 5.19 | $ | 5.83 | $ | 5.16 | ||||||||
Employees as of September 30
|
1,274 | 1,225 | 1,274 | 1,225 | ||||||||||||
(1) Net of operator labor and overhead recovery charges, and capitalized exploration and development costs.
|
Interest and Financing Expenses
|
|
|
|
|
|||||||||||||
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||||||
|
September 30,
|
September 30,
|
|||||||||||||||
In thousands, except per BOE data and interest rates
|
2011
|
2010
|
2011
|
2010
|
|||||||||||||
Cash interest
|
$ | 51,540 | $ | 58,234 | $ | 156,255 | $ | 164,173 | |||||||||
Non-cash interest
|
3,930 | 6,014 | 14,392 | 15,136 | |||||||||||||
Less: capitalized interest
|
(17,853 | ) | (10,917 | ) | (42,004 | ) | (56,079 | ) | |||||||||
|
Interest expense, net
|
$ | 37,617 | $ | 53,331 | $ | 128,643 | $ | 123,230 | ||||||||
Interest income and other
|
$ | 4,441 | $ | 1,268 | $ | 12,445 | $ | 7,658 | |||||||||
Net cash interest expense and other income per BOE (1)
|
$ | 4.80 | $ | 6.57 | $ | 5.79 | $ | 5.27 | |||||||||
Average debt outstanding
|
$ | 2,426,820 | $ | 2,751,258 | $ | 2,415,193 | $ | 2,710,573 | |||||||||
Average interest rate (2)
|
8.5 | % | 8.5 | % | 8.6 | % | 8.1 | % | |||||||||
|
|||||||||||||||||
(1) Cash interest expense less capitalized interest less interest income and other income on a per BOE basis. | |||||||||||||||||
(2) Includes commitment fees but excludes debt issue costs and amortization of discount and premium. |
Depletion, Depreciation, and Amortization ("DD&A")
|
|
|
|
|
||||||||||||
|
Three Months Ended
|
Nine Months Ended
|
||||||||||||||
|
September 30,
|
September 30,
|
||||||||||||||
In thousands, except per BOE data
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
DD&A of oil and natural gas properties
|
$ | 90,241 | $ | 108,692 | $ | 264,288 | $ | 295,923 | ||||||||
Depletion and depreciation of CO2 assets
|
4,625 | 4,984 | 13,803 | 15,964 | ||||||||||||
Asset retirement obligations
|
1,456 | 1,877 | 4,715 | 4,676 | ||||||||||||
Depreciation of other fixed assets
|
5,656 | 5,668 | 16,261 | 15,739 | ||||||||||||
Cumulative change due to revision in policy for CO2 properties
|
- | (9,619 | ) | - | (9,619 | ) | ||||||||||
Total DD&A
|
$ | 101,978 | $ | 111,602 | $ | 299,067 | $ | 322,683 | ||||||||
|
||||||||||||||||
DD&A per BOE:
|
||||||||||||||||
Oil and natural gas properties
|
$ | 14.91 | $ | 15.46 | $ | 15.13 | $ | 15.35 | ||||||||
CO2 assets and other fixed assets
|
1.68 | 1.49 | 1.69 | 1.62 | ||||||||||||
Cumulative change due to revision in policy for CO2 properties
|
- | (1.34 | ) | - | (0.49 | ) | ||||||||||
Total DD&A cost per BOE
|
$ | 16.59 | $ | 15.61 | $ | 16.82 | $ | 16.48 |
Income Taxes
|
|
|
|
|
||||||||||||
|
Three Months Ended
|
Nine Months Ended
|
||||||||||||||
|
September 30,
|
September 30,
|
||||||||||||||
In thousands, except per BOE amounts and tax rates
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Current income tax provision (benefit)
|
$ | (5,331 | ) | $ | 3,704 | $ | 5,849 | $ | 11,314 | |||||||
Deferred income tax provision
|
172,981 | 16,595 | 317,601 | 167,289 | ||||||||||||
Total income tax provision
|
$ | 167,650 | $ | 20,299 | $ | 323,450 | $ | 178,603 | ||||||||
Average income tax provision per BOE
|
$ | 27.27 | $ | 2.84 | $ | 18.19 | $ | 9.12 | ||||||||
Effective tax rate
|
37.8 | % | 39.4 | % | 38.3 | % | 38.8 | % |
|
Three Months Ended
|
Nine Months Ended
|
||||||||||||||
|
September 30,
|
September 30,
|
||||||||||||||
Per BOE data
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Oil and natural gas revenues
|
$ | 91.98 | $ | 64.44 | $ | 93.52 | $ | 65.34 | ||||||||
Gain (loss) on settlements of derivative contracts
|
0.74 | 1.40 | (0.27 | ) | (2.40 | ) | ||||||||||
Lease operating expenses
|
(22.21 | ) | (18.43 | ) | (22.13 | ) | (18.16 | ) | ||||||||
Production taxes and marketing expenses
|
(6.01 | ) | (4.97 | ) | (6.15 | ) | (4.75 | ) | ||||||||
Production netback
|
64.50 | 42.44 | 64.97 | 40.03 | ||||||||||||
Non-tertiary CO2 operating margin
|
0.84 | 0.30 | 0.65 | 0.42 | ||||||||||||
General and administrative expenses
|
(4.70 | ) | (5.19 | ) | (5.83 | ) | (5.16 | ) | ||||||||
Transactions and other costs related to the Encore Merger
|
- | (1.60 | ) | (0.25 | ) | (4.05 | ) | |||||||||
Net cash interest expense and other income
|
(4.80 | ) | (6.57 | ) | (5.79 | ) | (5.27 | ) | ||||||||
Current income taxes and other
|
2.34 | 1.37 | 0.96 | 0.92 | ||||||||||||
Changes in assets and liabilities relating to operations
|
(6.83 | ) | (1.60 | ) | (7.52 | ) | 3.37 | |||||||||
Cash flow from operations
|
51.35 | 29.15 | 47.19 | 30.26 | ||||||||||||
DD&A
|
(16.59 | ) | (15.61 | ) | (16.82 | ) | (16.48 | ) | ||||||||
Deferred income taxes
|
(28.13 | ) | (2.32 | ) | (17.86 | ) | (8.54 | ) | ||||||||
Gain on sale of interests in Genesis
|
- | - | - | 5.18 | ||||||||||||
Loss on early extinguishment of debt
|
- | - | (0.91 | ) | - | |||||||||||
Non-cash fair value derivative adjustments
|
33.44 | (5.86 | ) | 12.21 | 9.45 | |||||||||||
Net income attributable to noncontrolling interest
|
- | (0.30 | ) | - | (1.04 | ) | ||||||||||
Changes in assets and liabilities and other non-cash items
|
4.77 | (0.99 | ) | 5.48 | (5.49 | ) | ||||||||||
Net income attributable to Denbury stockholders
|
$ | 44.84 | $ | 4.07 | $ | 29.29 | $ | 13.34 |
|
|
|||||||||||||||||||||||
In thousands, except percentages
|
2014
|
2015
|
2016
|
2017
|
2020
|
2021
|
||||||||||||||||||
Variable rate debt:
|
|
|
|
|
|
|
||||||||||||||||||
Bank Credit Agreement (weighted average interest rate of 1.73% at September 30, 2011)
|
$ | 110,000 | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||||
Fixed rate debt:
|
||||||||||||||||||||||||
9.5% Senior Subordinated Notes due 2016
|
- | - | 224,920 | - | - | - | ||||||||||||||||||
9.75% Senior Subordinated Notes due 2016
|
- | - | 426,350 | - | - | - | ||||||||||||||||||
8.25% Senior Subordinated Notes due 2020
|
- | - | - | - | 996,273 | - | ||||||||||||||||||
6.375% Senior Subordinated Notes due 2021
|
- | - | - | - | - | 400,000 | ||||||||||||||||||
Other Subordinated Notes
|
1,072 | 485 | - | 2,250 | - | - |
|
Crude Oil
|
Natural Gas
|
||||||
|
Derivative
|
Derivative
|
||||||
|
Contracts
|
Contracts
|
||||||
In thousands
|
Receipt / (Payment)
|
Receipt
|
||||||
Based on:
|
|
|
||||||
NYMEX futures prices as of September 30, 2011
|
$ | 189 | $ | 25,083 | ||||
10% increase in prices
|
(2,305 | ) | 20,877 | |||||
10% decrease in prices
|
67,018 | 29,288 |
|
|
|
|
|
|
Total Number of
|
|
Approximate Dollar
|
|
Total
|
|
|
|
|
Shares Purchased
|
|
Value of Shares
|
|
Number of
|
|
Average
|
|
as Part of Publicly
|
|
that May Yet Be
|
|
|
Shares
|
|
Price Paid
|
|
Announced Plans or
|
|
Purchased Under the
|
|
Month
|
Purchased
|
|
per Share
|
|
Programs
|
|
Plans or Programs
|
|
July 2011
|
4,042
|
|
$
|
19.49
|
|
-
|
$
|
-
|
August 2011
|
16,298
|
|
|
18.15
|
|
-
|
|
-
|
September 2011
|
3,581
|
|
|
14.63
|
|
-
|
|
-
|
Total
|
23,921
|
|
|
17.85
|
|
-
|
$
|
-
|
Exhibit
|
Description
|
|
4.1
|
Sixth Amendment to Credit Agreement dated as of March 9, 2010, dated as of September 1, 2011, among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto (incorporated by reference as Exhibit 10.1 of our Form 8-K filed on September 8, 2011).
|
|
10.1*
|
Officer Resignation Agreement dated as of September 29, 2011.
|
|
31.1*
|
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
31.2*
|
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
32*
|
Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
101*
|
Interactive Data Files
|
DENBURY RESOURCES INC.
|
||||||
By:
|
/s/ Mark C. Allen
|
|||||
Mark C. Allen
|
||||||
Senior Vice President, Chief Financial Officer,
Treasurer, and Assistant Secretary
|
||||||
By:
|
/s/ Alan Rhoades
|
|||||
Alan Rhoades
|
||||||
Vice President and Chief Accounting Officer
|
DENBURY RESOURCES, INC.
|
||
By:
|
/s/ Wieland Wettstein
|
|
Name:
|
Wieland Wettstein
|
|
Title:
|
Chairman of the Board of Directors
|
RONALD T. EVANS
|
||
/s/ Ronald T. Evans
|
|
1.
|
I have reviewed this quarterly report on Form 10-Q of Denbury Resources Inc. (the “registrant”);
|
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
|
4.
|
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
|
5.
|
The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions)
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
November 8, 2011
|
/s/ Phil Rykhoek
|
||||||
Phil Rykhoek
|
|||||||
Chief Executive Officer
|
|
1.
|
I have reviewed this quarterly report on Form 10-Q of Denbury Resources Inc. (the “registrant”);
|
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
|
4.
|
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
|
5.
|
The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
November 8, 2011
|
/s/ Mark C. Allen
|
||||||
Mark C. Allen
|
|||||||
Senior Vice President, Chief Financial Officer, Treasurer, and Assistant Secretary
|
|
1.
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended;
|
|
and
|
|
2.
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Denbury.
|
Dated: November 8, 2011
|
/s/ Phil Rykhoek
|
||||||
Phil Rykhoek
|
|||||||
Chief Executive Officer
|
|||||||
Dated: November 8, 2011
|
/s/ Mark C. Allen
|
||||||
Mark C. Allen
|
|||||||
Senior Vice President, Chief Financial Officer, Treasurer, and Assistant Secretary
|
Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $) | Sep. 30, 2011 | Dec. 31, 2010 |
---|---|---|
Current assets | ||
Allowance for trade and other receivables | $ 274,000 | $ 456,000 |
Stockholders' equity | ||
Preferred stock, par value | $ 0.001 | $ 0.001 |
Preferred stock, shares authorized | 25,000,000 | 25,000,000 |
Preferred stock, shares issued | 0 | 0 |
Common stock, par value | $ 0.001 | $ 0.001 |
Common stock, shares authorized | 600,000,000 | 600,000,000 |
Common stock, shares issued | 402,625,687 | 400,291,033 |
Treasury stock, shares | 0 | 78,524 |
Condensed Consolidated Statements of Operations (Unaudited) (USD $) | 3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2011 | Sep. 30, 2010 | Sep. 30, 2011 | Sep. 30, 2010 | |
Revenues and other income | ||||
Oil, natural gas, and related product sales | $ 565,523,000 | $ 460,785,000 | $ 1,662,814,000 | $ 1,279,699,000 |
CO2 sales and transportation fees | 6,541,000 | 4,653,000 | 16,808,000 | 13,840,000 |
Gain on sale of interests in Genesis | 0 | (3,000) | 0 | 101,537,000 |
Interest income and other income | 4,441,000 | 1,268,000 | 12,445,000 | 7,658,000 |
Total revenues and other income | 576,505,000 | 466,703,000 | 1,692,067,000 | 1,402,734,000 |
Expenses | ||||
Lease operating expenses | 136,531,000 | 131,768,000 | 393,560,000 | 355,731,000 |
Production taxes and marketing expenses | 36,949,000 | 35,542,000 | 109,388,000 | 92,959,000 |
CO2 discovery and operating expenses | 1,358,000 | 2,488,000 | 5,381,000 | 5,537,000 |
General and administrative | 28,906,000 | 37,115,000 | 103,652,000 | 101,016,000 |
Interest, net of amounts capitalized | 37,617,000 | 53,331,000 | 128,643,000 | 123,230,000 |
Depletion, depreciation, and amortization | 101,978,000 | 111,602,000 | 299,067,000 | 322,683,000 |
Derivatives expense (income) | (210,154,000) | 31,854,000 | (212,308,000) | (138,045,000) |
Loss on early extinguishment of debt | 0 | 0 | 16,131,000 | 0 |
Transaction and other costs | 0 | 11,470,000 | 4,377,000 | 79,253,000 |
Total expenses | 133,185,000 | 415,170,000 | 847,891,000 | 942,364,000 |
Income (loss) before income taxes | 443,320,000 | 51,533,000 | 844,176,000 | 460,370,000 |
Income tax provision (benefit) | ||||
Current income taxes | (5,331,000) | 3,704,000 | 5,849,000 | 11,314,000 |
Deferred income taxes | 172,981,000 | 16,595,000 | 317,601,000 | 167,289,000 |
Consolidated net income (loss) | 275,670,000 | 31,234,000 | 520,726,000 | 281,767,000 |
Less: net income attributable to noncontrolling interest | 0 | (2,130,000) | 0 | (20,408,000) |
Net income (loss) attributable to Denbury stockholders | $ 275,670,000 | $ 29,104,000 | $ 520,726,000 | $ 261,359,000 |
Net income (loss) per common share | ||||
Basic | $ 0.69 | $ 0.07 | $ 1.31 | $ 0.72 |
Diluted | $ 0.68 | $ 0.07 | $ 1.29 | $ 0.71 |
Weighted average common shares outstanding | ||||
Basic | 399,040,000 | 395,913,000 | 398,371,000 | 362,241,000 |
Diluted | 403,311,000 | 401,093,000 | 403,575,000 | 367,434,000 |
Supplemental Information (Tables) | 9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Supplemental Information (Tables) [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accounts Payable and Accrued Liabilities |
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Supplemental Cash Flow Information |
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Document and Entity Information | 9 Months Ended |
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Sep. 30, 2011 | |
Document And Company Information [Abstract] | |
Entity Registrant Name | Denbury Resources Inc. |
Entity Central Index Key | 0000945764 |
Document Type | 10-Q |
Document Period End Date | Sep. 30, 2011 |
Amendment Flag | false |
Document Fiscal Year Focus | 2011 |
Document Fiscal Period Focus | Q3 |
Current Fiscal Year End Date | --12-31 |
Entity Well-known Seasoned Issuer | Yes |
Entity Voluntary Filers | No |
Entity Current Reporting Status | Yes |
Entity Filer Category | Large Accelerated Filer |
Entity Common Stock, Shares Outstanding | 391,624,449 |
Basis of Presentation (Details Textuals) (USD $) Share data in Millions, unless otherwise specified | 3 Months Ended | 9 Months Ended | |||||
---|---|---|---|---|---|---|---|
Sep. 30, 2011 | Sep. 30, 2010 | Sep. 30, 2011 | Sep. 30, 2010 | Dec. 31, 2010 | Dec. 30, 2010
ENP LP Investment [Member] | Dec. 30, 2010
GP LLC [Member] | |
Business Acquisition [Line Items] | |||||||
Ownership percentage in subsidiaries | 46.00% | 100.00% | |||||
Cost basis of investment in VNR | $ 93,000,000 | ||||||
Interest in guarantor subsidiaries | 100.00% | 100.00% | |||||
Basis of Presentation (Textuals) [Abstract] | |||||||
Net income attributable to noncontrolling interest | 0 | 2,130,000 | 0 | 20,408,000 | |||
Weighted average common shares - basic restricted stock | 3.40 | 3.40 | 3.50 | 3.30 | |||
Net unrealized losses on available-for-sale securities, net of tax | 3,949,000 | 0 | 6,925,000 | 0 | |||
Unrealized loss on short term investment, tax | 2,420,000 | 0 | 4,244,000 | 0 | |||
Distribution on Vanguard common units | $ 1,800,000 | $ 5,300,000 |
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Derivative Instruments and Hedging Activities | 9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Derivative Instruments and Hedging Activities [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivative Instruments and Hedging Activities | Note 4. Derivative Instruments
We do not apply hedge accounting treatment to our oil and natural gas derivative contracts, and therefore the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the cash settlements of expired contracts are shown under “Derivatives expense (income)” in our Unaudited Condensed Consolidated Statements of Operations. From time to time, we enter into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production. We do not hold or issue derivative financial instruments for trading purposes. These contracts have consisted of price floors, collars and fixed price swaps. The production that we hedge has varied from year to year depending on our levels of debt and financial strength and expectation of future commodity prices. We currently employ a strategy to hedge a portion of our forecasted production for a period generally ranging from approximately 12 to 18 months in advance, as we believe it is important to protect our future cash flow to provide a level of assurance for our capital spending in those future periods in light of current worldwide economic uncertainties and commodity price volatility.
We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures, and diversification. All of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement.
The following is a summary of “Derivatives expense (income)” included in the accompanying Unaudited Condensed Consolidated Statements of Operations for the periods indicated:
Commodity Derivative Contracts Not Classified as Hedging Instruments
The following tables present outstanding commodity derivative contracts with respect to future production as of September 30, 2011
Additional Disclosures about Derivative Instruments
At September 30, 2011 and December 31, 2010, we had derivative financial instruments recorded in our Unaudited Condensed Consolidated Balance Sheets as follows:
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Acquisitions and Divestitures (Details) (USD $) | Sep. 30, 2011 | Dec. 31, 2010 | Aug. 01, 2011
Riley Ridge Phase 2 [Member] |
---|---|---|---|
Riley Ridge Purchase Price Allocation | |||
Cash payment | $ 199,554,000 | ||
Deferred payment | 15,000,000 | 0 | 15,000,000 |
Total consideration | 214,554,000 | ||
Oil and natural gas properties - proved | 48,731,000 | ||
Oil and natural gas properties - unproved | 12,542,000 | ||
CO2 and other non-hydrocarbon gases properties | 9,741,000 | ||
Pipelines and plants | 91,594,000 | ||
Other assets | 48,660,000 | ||
Asset retirement obligations | (389,000) | ||
Business Acquisition Purchase Price Allocation Assets Acquired Liabilities Assumed Excluding Contingent Consideration | 210,879,000 | ||
Goodwill | 3,675,000 | ||
Helium extraction rights | $ 36,700,000 |
Supplemental Information (Details) (USD $) | Sep. 30, 2011 | Dec. 31, 2010 |
---|---|---|
Accounts Payable and Accrued Liabilities | ||
Accounts payable | $ 107,391,000 | $ 47,660,000 |
Accrued exploration and development costs | 143,647,000 | 101,758,000 |
Accrued compensation | 27,476,000 | 39,757,000 |
Accrued lease operating expense | 30,005,000 | 23,557,000 |
Accrued interest | 28,957,000 | 57,077,000 |
Taxes payable | 19,214,000 | 34,371,000 |
Deferred Riley Ridge acquisition consideration | 15,000,000 | 0 |
Other Accrued Liabilities Current | 33,553,000 | 45,888,000 |
Total | $ 405,243,000 | $ 350,068,000 |
Basis of Presentation (Details 1) | 3 Months Ended | 9 Months Ended | ||
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Sep. 30, 2011 | Sep. 30, 2010 | Sep. 30, 2011 | Sep. 30, 2010 | |
Stock Options and SARs [Member] | ||||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Total | 4,731,000 | 4,270,000 | 3,108,000 | 4,613,000 |
Restricted Stock [Member] | ||||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Total | 139,000 | 69,000 | 56,000 | 298,000 |
Significant Accounting Policies (Policies) | 9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||
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Sep. 30, 2011 | |||||||||||||||||||||||||||||||||||||||||||||||||||
Policy Text Block [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||
Interim Financial Statements - Basis of Accounting | The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by Accounting Principles Generally Accepted in the United States (“U.S. GAAP”) for complete financial statements. 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, 2010. Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.
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Interim Financial Statements - Use of Estimates | 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 year. In management's opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of September 30, 2011, our consolidated results of operations for the three and nine months ended September 30, 2011 and 2010, and our consolidated cash flows for the nine months ended September 30, 2011 and 2010. Certain prior period items have been reclassified to make the classification consistent with the classification in the most recent quarter. | ||||||||||||||||||||||||||||||||||||||||||||||||||
Noncontrolling Interest | Noncontrolling Interest
From March 9, 2010 to December 31, 2010, we owned approximately 46% of Encore Energy Partners LP (“ENP”) outstanding common units and 100% of Encore Energy Partners GP LLC (“GP LLC”), which was ENP's general partner. Considering the presumption of control of GP LLC in accordance with the Consolidation topic of the Financial Accounting Standards Board Codification (“FASC”), the results of operations and cash flows of ENP were consolidated with those of Denbury for this period. On December 31, 2010, we sold all of our ownership interests in ENP and, therefore, we did not consolidate ENP in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2010. As presented in the Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2010, “Net income attributable to noncontrolling interest” of $2.1 million and $20.4 million, respectively, represents ENP's results of operations attributable to third-party ENP limited partner interest owners, other than Denbury, for the portion of that period for which we consolidated ENP. | ||||||||||||||||||||||||||||||||||||||||||||||||||
Net Income Per Common Share | Net Income Per Common Share
Basic net income per common share is computed by dividing net income attributable to our stockholders 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 of the potential dilution from stock options, stock appreciation rights (“SARs”), unvested restricted stock, and unvested performance equity awards. For the three and nine months ended September 30, 2011 and 2010, there were no adjustments to net income attributable to our stockholders for purposes of calculating diluted net income per common share. Basic weighted average common shares excludes 3.4 million and 3.5 million shares for the three and nine months ended September 30, 2011, respectively, and 3.4 million and 3.3 million shares for the three and nine months ended September 30, 2010, respectively, of unvested restricted stock. As these restricted shares vest or become retirement eligible, 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 diluted weighted average common shares, unvested restricted stock is included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, adjusted for any estimated future tax consequences recognized directly in equity.
The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income per share as their effect would have been anti-dilutive:
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Short-term Investments | Short-term Investments
Short-term investments are available-for-sale securities recorded at fair value with any unrealized gains or losses included in accumulated other comprehensive income. At September 30, 2011 and December 31, 2010, short-term investments consisted entirely of our investment in Vanguard Natural Resources LLC (“Vanguard”) common units obtained as partial consideration for the sale of our interests in ENP to a subsidiary of Vanguard on December 31, 2010. The cost basis of this investment is $93.0 million. We received distributions of $1.8 million and $5.3 million on the Vanguard common units we own for the three and nine months ended September 30, 2011, respectively, which distributions are included in “Interest income and other income” on our Unaudited Condensed Consolidated Statements of Operations. The unrealized loss on our short-term investment of $3.9 million (net of a tax benefit of $2.4 million) and $6.9 million (net of a tax benefit of $4.2 million) for the three and nine months ended September 30, 2011, respectively, is included in our Unaudited Condensed Consolidated Statements of Comprehensive Operations. | ||||||||||||||||||||||||||||||||||||||||||||||||||
Derivatives, Policy [Policy Text Block] | We do not apply hedge accounting treatment to our oil and natural gas derivative contracts, and therefore the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the cash settlements of expired contracts are shown under “Derivatives expense (income)” in our Unaudited Condensed Consolidated Statements of Operations. From time to time, we enter into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production. We do not hold or issue derivative financial instruments for trading purposes. These contracts have consisted of price floors, collars and fixed price swaps. The production that we hedge has varied from year to year depending on our levels of debt and financial strength and expectation of future commodity prices. We currently employ a strategy to hedge a portion of our forecasted production for a period generally ranging from approximately 12 to 18 months in advance, as we believe it is important to protect our future cash flow to provide a level of assurance for our capital spending in those future periods in light of current worldwide economic uncertainties and commodity price volatility.
We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures, and diversification. All of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement.
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Fair Value of Financial Instruments, Policy [Policy Text Block] | Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:
• Level 1 - Quoted prices in active markets for identical assets or liabilities as of the reporting date.
• Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded oil and natural gas derivatives that are based on NYMEX pricing.
• Level 3 - Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. Instruments in this category include non-exchange-traded natural gas derivatives swaps that are based on regional pricing other than NYMEX (e.g., Houston Ship Channel).
We adjust the valuations for nonperformance risk, using our estimate of the counterparty's credit quality for asset positions and Denbury's credit quality for liability positions. We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.
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Condensed Consolidated Statements of Comprehensive Operations (Unaudited) (Parenthetical) (USD $) | 3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2011 | Sep. 30, 2010 | Sep. 30, 2011 | Sep. 30, 2010 | |
Other comprehensive income (loss), net of income tax: | ||||
Tax effect of changes in value on available-for-sale securities | $ (2,420,000) | $ 0 | $ (4,244,000) | $ 0 |
Tax for interest rate lock derivative contracts reclassified to income | 11,000 | 11,000 | 32,000 | 32,000 |
Tax for change in fair value of interest rate lock derivative contracts designated as a hedge | $ 0 | $ 14,000 | $ 0 | $ 32,000 |
Supplemental Information | 9 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Supplemental Information [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Supplemental Information | Note 6. Supplemental Information
Accounts Payable and Accrued Liabilities
The following table summarizes our accounts payable and accrued liabilities as of the periods indicated:
Supplemental Cash Flow Information
The following table sets forth supplemental cash flow information for the periods indicated:
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Riley Ridge Purchase Price Allocation |
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Proforma revenue and net income (loss) |
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Commitments and Contingencies | 9 Months Ended |
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Sep. 30, 2011 | |
Commitments and Contingencies [Abstract] | |
Commitments and Contingencies | Note 7. Commitments and Contingencies
In March 2011, we entered into three long-term supply contracts to purchase CO2 from future anthropogenic sources in the Gulf Coast and Rocky Mountain regions. The three contracts are in addition to the previously disclosed long-term supply contracts Denbury currently has in place in the Gulf Coast, Rocky Mountain and Midwest regions. Under the three new contracts, Denbury will purchase 100% of the CO2 captured from the DKRW Advanced Fuels LLC's Medicine Bow Fuel and Power LLC ("MBFP") project near Medicine Bow, Wyoming, purchase 70% of the CO2 captured from Mississippi Power Company's Kemper County Integrated Gasification Combined Cycle ("Mississippi Power") project in Mississippi, and purchase 100% of the CO2 captured by Air Products LLC (“Air Products”) at a third-party refinery in Port Arthur, Texas. These new contracts each have an initial term of 15 to 16 years and include options to extend the term. We estimate that these new sources will supply approximately 365 MMcf/d of CO2 for our enhanced oil recovery operations, although under certain circumstances, we may be obligated to purchase up to 460 MMcf/d, a portion of which would be at a reduced price per Mcf. We expect to begin taking delivery of approximately 100 MMCF/d of CO2 from the MBFP project in 2015, 115 MMcf/d of CO2 from the Mississippi Power project by 2014, and 50 MMcf/d of CO2 from Air Products in late 2012. Our aggregate maximum purchase obligation for CO2 purchased under these three contracts would be approximately $110 million per year (assuming purchases of 460 MMcf/d), plus transportation, assuming a $100 per barrel NYMEX oil price. The purchase price of CO2 will fluctuate based on the changes in the price of oil.
As is the case with all of our long-term supply contracts to purchase CO2, the three agreements entered into in March are subject to various contingencies. The Mississippi Power and Air Products plants are currently being constructed, and the MBFP project is contingent upon securing debt financing, equity commitments and receipt of all necessary consents and approvals. In conjunction with the August 1, 2011 Riley Ridge acquisition, we assumed the 20-year helium supply contract under which the original participants in Riley Ridge agreed to supply helium to a third party purchaser. Subsequently, we amended this contract to provide for annual delivery (to the 8/8ths working interest) of 127 MMcf of helium (previously 200 MMcf) during the first two years of the contract and thereafter provides for delivery of 400 MMcf of helium per year. If the contracted quantity of helium is not supplied, we are obligated to compensate the third party helium purchaser for the amount of the shortfall in an amount not to exceed $8.0 million per year. In the third quarter of 2008, we obtained approval from the National Office of the Internal Revenue Service (“IRS”) to change our method of tax accounting for certain assets used in our tertiary oilfield recovery operations. As a result of the approved change in method of tax accounting, beginning with the 2007 tax year we began to deduct, rather than capitalize, such costs for tax purposes, and applied for tax refunds associated with such change for our 2004 and 2006 tax years. Notwithstanding its consent to our change in tax accounting in 2008, the IRS subsequently exercised its prerogative to challenge the tax accounting method we used. In late January 2011, we received a Technical Advice Memorandum (“TAM”) issued by the IRS National Office disapproving our method of accounting and revoking its consent to our change, on a prospective basis only, commencing January 1, 2011. As a result of the prospective nature of the IRS's determination, there should be no change in our position with respect to the deductibility of these costs for 2007, 2008, 2009 and 2010. However, refund claims of $10.6 million for tax years through 2006 are pending and are subject to review by the Joint Committee on Taxation of the U.S. Congress. We are unable to assess the outcome of any such review, nor how that outcome may affect the other years covered by the TAM.
We are subject to audits for sales and use taxes and severance taxes in the various states in which we operate, and from time to time receive assessments for potential taxes that we may owe. Currently, we have no material assessments for potential taxes.
We are involved in various lawsuits, claims and other regulatory proceedings incidental to our businesses. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows, litigation is subject to inherent uncertainties. If an unfavorable ruling were to occur, there exists the possibility of a material adverse impact on our net income in the period in which the ruling occurs. We provide accruals for litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated. |
Fair Value Measurements | 9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Fair Value, Assets and Liabilities Measured on Recurring Basis [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Measurements | Note 5. Fair Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:
• Level 1 - Quoted prices in active markets for identical assets or liabilities as of the reporting date.
• Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded oil and natural gas derivatives that are based on NYMEX pricing.
• Level 3 - Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. Instruments in this category include non-exchange-traded natural gas derivatives swaps that are based on regional pricing other than NYMEX (e.g., Houston Ship Channel).
We adjust the valuations for nonperformance risk, using our estimate of the counterparty's credit quality for asset positions and Denbury's credit quality for liability positions. We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.
The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of the periods indicated:
Note 5. Fair Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:
• Level 1 - Quoted prices in active markets for identical assets or liabilities as of the reporting date.
• Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded oil and natural gas derivatives that are based on NYMEX pricing.
• Level 3 - Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. Instruments in this category include non-exchange-traded natural gas derivatives swaps that are based on regional pricing other than NYMEX (e.g., Houston Ship Channel).
We adjust the valuations for nonperformance risk, using our estimate of the counterparty's credit quality for asset positions and Denbury's credit quality for liability positions. We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.
The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of the periods indicated:
The following table summarizes the changes in the fair value of our Level 3 assets for the three and nine months ended September 30, 2011 and 2010
Since we do not use hedge accounting for our commodity derivative contracts, any gains and losses on our assets and liabilities are included in “Derivatives expense (income)” in the accompanying Unaudited Condensed Consolidated Statements of Operations. The following table sets forth the fair value of financial instruments that are not recorded at fair value in our Unaudited Condensed Consolidated Financial Statements. See Note 3, Long-Term Debt and Item 3, Quantitative and Qualitative Disclosures about Market Risk for further information about these financial instruments.
The fair values of our senior subordinated notes are based on quoted market prices. We have other financial instruments consisting primarily of cash, cash equivalents, our Bank Credit Agreement, and short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities. |
Basis of Presentation | 9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Significant Accounting Policies [Text Block] | Note 1. Basis of Presentation
Organization and Nature of Operations
We are a growing independent oil and natural gas company. We are the largest oil and natural gas producer in both Mississippi and Montana, own the largest reserves of CO2 used for tertiary oil recovery east of the Mississippi River, and hold significant operating acreage in the Rocky Mountain and Gulf Coast regions. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with our most significant emphasis on our CO2 tertiary recovery operations.
Interim Financial Statements
The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by Accounting Principles Generally Accepted in the United States (“U.S. GAAP”) for complete financial statements. 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, 2010. Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.
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 year. In management's opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of September 30, 2011, our consolidated results of operations for the three and nine months ended September 30, 2011 and 2010, and our consolidated cash flows for the nine months ended September 30, 2011 and 2010. Certain prior period items have been reclassified to make the classification consistent with the classification in the most recent quarter. Noncontrolling Interest
From March 9, 2010 to December 31, 2010, we owned approximately 46% of Encore Energy Partners LP (“ENP”) outstanding common units and 100% of Encore Energy Partners GP LLC (“GP LLC”), which was ENP's general partner. Considering the presumption of control of GP LLC in accordance with the Consolidation topic of the Financial Accounting Standards Board Codification (“FASC”), the results of operations and cash flows of ENP were consolidated with those of Denbury for this period. On December 31, 2010, we sold all of our ownership interests in ENP and, therefore, we did not consolidate ENP in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2010. As presented in the Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2010, “Net income attributable to noncontrolling interest” of $2.1 million and $20.4 million, respectively, represents ENP's results of operations attributable to third-party ENP limited partner interest owners, other than Denbury, for the portion of that period for which we consolidated ENP. Net Income Per Common Share
Basic net income per common share is computed by dividing net income attributable to our stockholders 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 of the potential dilution from stock options, stock appreciation rights (“SARs”), unvested restricted stock, and unvested performance equity awards. For the three and nine months ended September 30, 2011 and 2010, there were no adjustments to net income attributable to our stockholders for purposes of calculating diluted net income per common share. 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 periods indicated:
Basic weighted average common shares excludes 3.4 million and 3.5 million shares for the three and nine months ended September 30, 2011, respectively, and 3.4 million and 3.3 million shares for the three and nine months ended September 30, 2010, respectively, of unvested restricted stock. As these restricted shares vest or become retirement eligible, 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 diluted weighted average common shares, unvested restricted stock is included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, adjusted for any estimated future tax consequences recognized directly in equity.
The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income per share as their effect would have been anti-dilutive:
Short-term Investments
Short-term investments are available-for-sale securities recorded at fair value with any unrealized gains or losses included in accumulated other comprehensive income. At September 30, 2011 and December 31, 2010, short-term investments consisted entirely of our investment in Vanguard Natural Resources LLC (“Vanguard”) common units obtained as partial consideration for the sale of our interests in ENP to a subsidiary of Vanguard on December 31, 2010. The cost basis of this investment is $93.0 million. We received distributions of $1.8 million and $5.3 million on the Vanguard common units we own for the three and nine months ended September 30, 2011, respectively, which distributions are included in “Interest income and other income” on our Unaudited Condensed Consolidated Statements of Operations. The unrealized loss on our short-term investment of $3.9 million (net of a tax benefit of $2.4 million) and $6.9 million (net of a tax benefit of $4.2 million) for the three and nine months ended September 30, 2011, respectively, is included in our Unaudited Condensed Consolidated Statements of Comprehensive Operations. Short-term Investments
Short-term investments are available-for-sale securities recorded at fair value with any unrealized gains or losses included in accumulated other comprehensive income. At September 30, 2011 and December 31, 2010, short-term investments consisted entirely of our investment in Vanguard Natural Resources LLC (“Vanguard”) common units obtained as partial consideration for the sale of our interests in ENP to a subsidiary of Vanguard on December 31, 2010. The cost basis of this investment is $93.0 million. We received distributions of $1.8 million and $5.3 million on the Vanguard common units we own for the three and nine months ended September 30, 2011, respectively, which distributions are included in “Interest income and other income” on our Unaudited Condensed Consolidated Statements of Operations. The unrealized loss on our short-term investment of $3.9 million (net of a tax benefit of $2.4 million) and $6.9 million (net of a tax benefit of $4.2 million) for the three and nine months ended September 30, 2011, respectively, is included in our Unaudited Condensed Consolidated Statements of Comprehensive Operations. Recently Issued Accounting Pronouncements
In September 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-08, Testing Goodwill for Impairment, (“ASU 2011-08”). ASU 2011-08 amends the FASC Intangibles – Goodwill and Other topic by permitting entities to assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in the FASC Intangibles – Goodwill and Other topic. We adopted ASU 2011-08 and will apply the guidance prospectively to interim and annual goodwill impairment tests. In June 2011, the FASB issued ASU 2011-05, Presentation of Comprehensive Income, (“ASU 2011-05”). ASU 2011-05 requires the presentation of comprehensive income in either 1) a continuous statement of comprehensive income or 2) two separate but consecutive statements. ASU 2011-05 will be effective for our fiscal year beginning January 1, 2012. Since ASU 2011-05 will only amend presentation requirements, it will not have a material effect on our consolidated financial statements. In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs, (“ASU 2011-04”). ASU 2011-04 amends the FASC Fair Value Measurements topic by providing a consistent definition and measurement of fair value, as well as similar disclosure requirements between U.S. GAAP and International Financial Reporting Standards. ASU 2011-04 changes certain fair value measurement principles, clarifies the application of existing fair value measurements and expands the fair value disclosure requirements, particularly for Level 3 fair value measurements. ASU 2011-04 will be effective for our fiscal year beginning January 1, 2012. The adoption of ASU 2011-04 is not expected to have a material effect on our consolidated financial statements, but may require additional disclosures. |
Long Term Debt (Details Textuals) (USD $) | 3 Months Ended | 9 Months Ended | 1 Months Ended | 1 Months Ended | 9 Months Ended | ||||||||||||||||||
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Sep. 30, 2011 | Sep. 30, 2010 | Sep. 30, 2011 | Sep. 30, 2010 | Mar. 31, 2010 | Sep. 30, 2011
7.5% Senior Subordinated Notes due 2013 [Member] | Feb. 28, 2011
7.5% Senior Subordinated Notes due 2013 [Member] | Dec. 31, 2010
7.5% Senior Subordinated Notes due 2013 [Member] | Mar. 31, 2011
7.5% Senior Subordinated Notes due 2013 [Member]
Extinguishment One [Member] | Apr. 30, 2011
7.5% Senior Subordinated Notes due 2013 [Member]
Extinguishment Two [Member] | Sep. 30, 2011
7.5% Senior Subordinated Notes due 2015 [Member] | Feb. 28, 2011
7.5% Senior Subordinated Notes due 2015 [Member] | Dec. 31, 2010
7.5% Senior Subordinated Notes due 2015 [Member] | Mar. 31, 2011
7.5% Senior Subordinated Notes due 2015 [Member]
Extinguishment One [Member] | Mar. 31, 2011
7.5% Senior Subordinated Notes due 2015 [Member]
Extinguishment Two [Member] | Sep. 30, 2011
9.5% Senior Subordinated Notes due 2016 [Member] | Dec. 31, 2010
9.5% Senior Subordinated Notes due 2016 [Member] | Sep. 30, 2011
9.75% Senior Subordinated Notes due 2016 [Member] | Dec. 31, 2010
9.75% Senior Subordinated Notes due 2016 [Member] | Sep. 30, 2011
6 3/8% Senior Subordinated Notes Due 2021 [Member] | Feb. 28, 2011
6 3/8% Senior Subordinated Notes Due 2021 [Member] | Sep. 30, 2011
Other Subordinated Notes [Member] | Dec. 31, 2010
Other Subordinated Notes [Member] | |
Long Term Debt (Textuals) [Abstract] | |||||||||||||||||||||||
Interest in guarantor subsidiaries | 100.00% | 100.00% | |||||||||||||||||||||
Debt Instrument, Interest Rate Terms | the margin on outstanding Eurodollar loans bears interest at the Eurodollar rate (as defined in the Bank Credit Agreement) plus the applicable margin of 1.5% to 2.5% (previously 2.0% to 3.0%) based on the ratio of outstanding borrowings to the borrowing base, and the base rate loans bear interest at the base rate (as defined in the Bank Credit Agreement) plus the applicable margin of 0.5% to 1.5% (previously 1.0% to 1.5%) based on the ratio of outstanding borrowings to the borrowing base If the borrowing base were to be less than outstanding borrowings under the Bank Credit Agreement, we would be required to repay the deficit over a period of four months | ||||||||||||||||||||||
Commitment fee incurred | ranging between 0.375% and 0.5% on the unused portion of the credit facility or if less, the borrowing base | ||||||||||||||||||||||
Line of Credit Facility, Covenant Terms | adjusts the maximum permitted ratio of debt to adjusted EBITDA of Denbury and its subsidiaries from 4.0x to 4.25x | ||||||||||||||||||||||
Maturity date of Denbury Credit Agreement | May 2016 | ||||||||||||||||||||||
Debt Instrument Redemption Price In Year Five | 103.188% | ||||||||||||||||||||||
Debt Instrument Redemption Price Prior to Year Five | equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest | ||||||||||||||||||||||
Debt Instrument Carrying Amount | $ 400,000,000 | ||||||||||||||||||||||
Interest Rate on Senior Subordinated Notes | 6.375% | ||||||||||||||||||||||
Debt Instrument, Unamortized Discount | 0 | 437,000 | 18,925,000 | 22,139,000 | |||||||||||||||||||
Principal amount of notes for which cash tender offers commenced | 225,000,000 | 300,000,000 | |||||||||||||||||||||
Borrowing Base of Denbury credit agreement | 1,600,000,000 | ||||||||||||||||||||||
Debt Instrument, Unamortized Premium | 0 | 427,000 | 12,538,000 | 14,589,000 | 35,000 | 41,000 | |||||||||||||||||
Net proceeds used for repurchase of notes | 393,000,000 | ||||||||||||||||||||||
Debt Instrument Redemption Price In Year Six | 102.125% | ||||||||||||||||||||||
Debt Instrument Redemption Price In Year Seven | 101.062% | ||||||||||||||||||||||
Debt Instrument Redemption Price In Year Eight | 100.00% | ||||||||||||||||||||||
Debt Instrument Redemption Percentage Of Principal Prior To Year Three | 35.00% | ||||||||||||||||||||||
Debt Instrument Redemption Price Before Year Three With Equity Offering Proceeds | 106.375% | ||||||||||||||||||||||
Debt Instrument Redemption Percentage Of Principal Prior To Year Five With Make-Whole Premium | 100.00% | ||||||||||||||||||||||
Extinguishment of Debt [Line Items] | |||||||||||||||||||||||
Extinguishment of Senior Notes | 169,600,000 | 55,400,000 | 220,900,000 | 79,100,000 | |||||||||||||||||||
Redemption percentage of debt | 100.625% | 100.00% | 104.125% | 103.75% | |||||||||||||||||||
Loss on early extinguishment of debt | $ 0 | $ 0 | $ 16,131,000 | $ 0 |
Acquisitions and Divestitures | 9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Business Combinations [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Acquisitions and Divestitures | Note 2. Acquisitions and Divestitures
Acquisitions
October 2010 and August 2011 Acquisitions of Reserves in Rocky Mountain Region at Riley Ridge
In October 2010, we acquired a 42.5% non-operated working interest in the Riley Ridge Federal Unit (“Riley Ridge”), located in the LaBarge Field of southwestern Wyoming, for $132.3 million after closing adjustments. Riley Ridge contains natural gas resources, as well as helium and CO2 resources. The purchase included a 42.5% interest in a gas plant, currently under construction, which will separate the helium and natural gas from the commingled gas stream. The acquisition also included approximately 33% of the CO2 mineral rights in an additional 28,000 acres adjoining the Riley Ridge Unit. The fair values assigned to assets acquired and liabilities assumed in the October 2010 acquisition have been finalized and no adjustments have been made to amounts previously disclosed in our Form 10-K for the period ended December 31, 2010.
On August 1, 2011, we acquired the remaining 57.5% working interest in Riley Ridge not already owned, the remaining 57.5% interest in the gas plant and a working interest of approximately 33% in the 28,000 acres adjacent to Riley Ridge. As a result of the transaction, we became the operator of both projects. The purchase price was approximately $214.6 million after preliminary closing adjustments, including a $15 million deferred payment to be made at the time the property's gas plant is operational and meets specific performance conditions. We expect the gas plant to be operational during the latter part of the first quarter of 2012.
Because the Riley Ridge plant is currently under construction, current production at the field is negligible. As a result, pro forma information has not been disclosed due to the immateriality of revenues and expenses during 2011 and 2010.
The August 1, 2011 acquisition of Riley Ridge meets the definition of a business under the FASC Business Combinations topic. The following table presents a summary of the fair value of the Riley Ridge assets acquired and liabilities assumed on August 1, 2011:
2010 Merger with Encore Acquisition Company
On March 9, 2010, we acquired Encore Acquisition Company (“Encore”) pursuant to the Encore Merger Agreement entered into with Encore on October 31, 2009. The Encore Merger Agreement provided for a stock and cash transaction valued at approximately $4.8 billion at the acquisition date, including the assumption of debt and the value of the noncontrolling interest in ENP (the “Encore Merger”). Under the Encore Merger Agreement, Encore was merged with and into Denbury, with Denbury surviving the Encore Merger.
For the three months ended September 30, 2010 and for the period from March 9, 2010 to September 30, 2010, we recognized $174.3 million and $435.2 million, respectively, of oil, natural gas sales and related product sales from properties acquired as part of the Encore Merger. For the three months ended September 30, 2010 and for the period from March 9, 2010 to September 30, 2010, we recognized $114.1 million and $294.8 million, respectively, of net field operating income (oil, natural gas and related product sales less lease operating expenses, production taxes and marketing expenses) from properties acquired as part of the Encore Merger. We recognized a total of $11.5 million of transaction and other costs related to the Encore Merger (primarily advisory, legal, accounting, due diligence, integration and severance costs) for the three months ended September 30, 2010, and $4.4 million and $79.3 million of such costs for the nine months ended September 30, 2011 and 2010, respectively.
Pro Forma Information
Had the Encore Merger occurred on January 1, 2010, our combined pro forma revenues and net income for the three and nine months ended September 30, 2010, would have been as follows:
2010 Merger with Encore Acquisition Company
On March 9, 2010, we acquired Encore Acquisition Company (“Encore”) pursuant to the Encore Merger Agreement entered into with Encore on October 31, 2009. The Encore Merger Agreement provided for a stock and cash transaction valued at approximately $4.8 billion at the acquisition date, including the assumption of debt and the value of the noncontrolling interest in ENP (the “Encore Merger”). Under the Encore Merger Agreement, Encore was merged with and into Denbury, with Denbury surviving the Encore Merger.
For the three months ended September 30, 2010 and for the period from March 9, 2010 to September 30, 2010, we recognized $174.3 million and $435.2 million, respectively, of oil, natural gas sales and related product sales from properties acquired as part of the Encore Merger. For the three months ended September 30, 2010 and for the period from March 9, 2010 to September 30, 2010, we recognized $114.1 million and $294.8 million, respectively, of net field operating income (oil, natural gas and related product sales less lease operating expenses, production taxes and marketing expenses) from properties acquired as part of the Encore Merger. We recognized a total of $11.5 million of transaction and other costs related to the Encore Merger (primarily advisory, legal, accounting, due diligence, integration and severance costs) for the three months ended September 30, 2010, and $4.4 million and $79.3 million of such costs for the nine months ended September 30, 2011 and 2010, respectively.
Pro Forma Information
Had the Encore Merger occurred on January 1, 2010, our combined pro forma revenues and net income for the three and nine months ended September 30, 2010, would have been as follows:
Divestitures
2010 Sale of Interests in Genesis
In February 2010, we sold our interest in Genesis Energy, LLC, the general partner of Genesis Energy, L.P. (“Genesis”), for net proceeds of approximately $84 million. In March 2010, we sold all of our Genesis common units in a secondary public offering for net proceeds of approximately $79 million. We recognized a pre-tax gain of approximately $101.5 million ($63.0 million after tax) on these dispositions.
2010 Sales of Non-Strategic Legacy Encore Properties In May 2010, we sold certain non-strategic legacy Encore properties, primarily located in the Permian Basin, the Mid-continent area and the East Texas Basin (the “Southern Assets”), to Quantum Resources Management, LLC for consideration of $892.1 million after closing adjustments. In August 2010, we sold additional legacy Encore properties, primarily located in the Cleveland Sand Play of western Oklahoma, for consideration of $32.1 million after closing adjustments. We did not record a gain or loss on the sales in accordance with the full cost method of accounting.
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Acquisitions and Divestitures (Details 1) (USD $) | 3 Months Ended | 9 Months Ended |
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Sep. 30, 2010 | Sep. 30, 2010 | |
Proforma revenue and net income (loss) | ||
Pro forma total revenues | $ 466,703,000 | $ 1,579,184,000 |
Pro forma net income attributable to Denbury stockholders | $ 29,104,000 | $ 276,527,000 |
Pro forma net income per common share: | ||
Basic | $ 0.07 | $ 0.70 |
Diluted | $ 0.07 | $ 0.69 |
Subsequent Events (Details Textuals) (USD $) In Millions, except Share data, unless otherwise specified | 1 Months Ended |
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Oct. 31, 2011 | |
Subsequent Event [Line Items] | |
Stock Repurchase Program, Authorized Amount | $ 500.00 |
Share Repurchase Program [Member] | |
Subsequent Event [Line Items] | |
Treasury Stock Acquired, Average Cost Per Share | $ 13.58 |
Treasury Stock, Shares, Acquired | 10,990,939 |
Treasury Stock, Value, Acquired, Cost Method | $ 149.30 |
Treasury Stock Acquired, Percentage of Outstanding | 2.70% |
Long-Term Debt (Details) (USD $) | Sep. 30, 2011 | Dec. 31, 2010 |
---|---|---|
Debt Instrument [Line Items] | ||
Credit Agreement | $ 110,000,000 | $ 0 |
Capital Lease Obligations | 5,010,000 | 6,806,000 |
Total | 2,404,726,000 | 2,424,156,000 |
Less current obligations | 8,177,000 | 7,948,000 |
Long-term debt and capital lease obligations | 2,396,549,000 | 2,416,208,000 |
7.5% Senior Subordinated Notes due 2013 [Member] | ||
Debt Instrument [Line Items] | ||
Senior Subordinated Notes | 0 | 224,563,000 |
7.5% Senior Subordinated Notes due 2015 [Member] | ||
Debt Instrument [Line Items] | ||
Senior Subordinated Notes | 0 | 300,427,000 |
9.5% Senior Subordinated Notes due 2016 [Member] | ||
Debt Instrument [Line Items] | ||
Senior Subordinated Notes | 237,458,000 | 239,509,000 |
9.75% Senior Subordinated Notes due 2016 [Member] | ||
Debt Instrument [Line Items] | ||
Senior Subordinated Notes | 407,425,000 | 404,211,000 |
6 3/8% Senior Subordinated Notes Due 2021 [Member] | ||
Debt Instrument [Line Items] | ||
Senior Subordinated Notes | 400,000,000 | 0 |
8.25% Senior Subordinated Notes due 2020 [Member] | ||
Debt Instrument [Line Items] | ||
Senior Subordinated Notes | 996,273,000 | 996,273,000 |
Other Subordinated Notes [Member] | ||
Debt Instrument [Line Items] | ||
Senior Subordinated Notes | 3,841,000 | 3,848,000 |
NEJD Financing [Member] | ||
Debt Instrument [Line Items] | ||
Financing Lease Obligations | 164,626,000 | 167,331,000 |
Free State Financing [Member] | ||
Debt Instrument [Line Items] | ||
Financing Lease Obligations | $ 80,093,000 | $ 81,188,000 |
Basis of Presentation (Tables) | 9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Weighted average shares used in the basic and diluted net income per common share |
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Anti-dilutive securities excluded from computation of diluted net earnings per share |
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Long-Term Debt | 9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Long-Term Debt [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-Term Debt | Note 3. Long-Term Debt
The following table shows the components of our long-term debt:
The parent company, Denbury Resources Inc. (“DRI”), is the sole issuer of all of our outstanding senior subordinated notes. DRI has no independent assets or operations. Each of the subsidiary guarantors is 100% owned by DRI; any subsidiaries of DRI other than the subsidiary guarantors are minor subsidiaries, and the subsidiary guarantors fully and unconditionally guarantee our senior subordinated debt jointly and severally.
Bank Credit Agreement
In March 2010, we entered into a $1.6 billion revolving credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders as party thereto (the “Bank Credit Agreement”). Availability under the Bank Credit Agreement is subject to a borrowing base which is redetermined semi-annually on or prior to May 1 and November 1 and upon requested special redeterminations. The borrowing base is adjusted at the banks' discretion and is based in part upon external factors over which we have no control. If the borrowing base were to be less than outstanding borrowings under the Bank Credit Agreement, we would be required to repay the deficit over a period of four months. In May 2011, we entered into the Fifth Amendment to the Bank Credit Agreement (the “Fifth Amendment”). The Fifth Amendment extends the maturity of the Bank Credit Agreement from March 2014 to May 2016, reduces the applicable margin on outstanding borrowings, reduces the letter of credit fee and adjusts the maximum permitted ratio of debt to adjusted EBITDA. Under the Fifth Amendment, the margin on outstanding Eurodollar loans bears interest at the Eurodollar rate (as defined in the Bank Credit Agreement) plus the applicable margin of 1.5% to 2.5% (previously 2.0% to 3.0%) based on the ratio of outstanding borrowings to the borrowing base, and the base rate loans bear interest at the base rate (as defined in the Bank Credit Agreement) plus the applicable margin of 0.5% to 1.5% (previously 1.0% to 1.5%) based on the ratio of outstanding borrowings to the borrowing base. The Fifth Amendment also prescribes a commitment fee ranging between 0.375% and 0.5% on the unused portion of the credit facility or if less, the borrowing base, and adjusts the maximum permitted ratio of debt to adjusted EBITDA of Denbury and its subsidiaries from 4.0x to 4.25x. In September 2011, we entered into the Sixth Amendment to the Bank Credit Agreement (the “Sixth Amendment”). The Sixth Amendment permits Denbury to make distributions to its equity holders, including specifically repurchase of its common stock and/or making cash dividends with respect thereto, in an aggregate amount of up to $500 million during the term of the Credit Facility, subject to certain restrictions, including pro forma availability of no less than 25% of the borrowing base at the time of any such transactions. The Sixth Amendment provides us the flexibility to repurchase our common stock and/or pay cash dividends (within the $500 million limit) from time to time as deemed appropriate by, and subject to pre-approval of, our Board of Directors. Also in September 2011, the banks reaffirmed our borrowing base of $1.6 billion under the Bank Credit Agreement until the next scheduled redetermination in May 2012.
6⅜% Senior Subordinated Notes due 2021
In February 2011, we issued $400 million of 6⅜% Senior Subordinated Notes due 2021 (“2021 Notes”). The 2021 Notes, which carry a coupon rate of 6.375%, were sold at par. The net proceeds of $393 million were used to repurchase a portion of our outstanding 2013 Notes and 2015 Notes (see Redemption of our 2013 and 2015 Notes below).
The 2021 Notes mature on August 15, 2021, and interest is payable on February 15 and August 15 of each year, beginning August 15, 2011. We may redeem the 2021 Notes in whole or in part at our option beginning August 15, 2016 at the following redemption prices: 103.188% on or after August 15, 2016; 102.125% on or after August 15, 2017; 101.062% on or after August 15, 2018; and 100% on or after August 15, 2019. Prior to August 15, 2014, we may, at our option, redeem up to an aggregate of 35% of the principal amount of the 2021 Notes at a price of 106.375% with the proceeds of certain equity offerings. In addition, at any time prior to August 15, 2016, we may redeem 100% of the principal amount of the 2021 Notes at a price equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest. The indenture contains certain restrictions on our ability to incur additional debt, pay dividends on our common stock, make investments, create liens on our assets, engage in transactions with our affiliates, transfer or sell assets, consolidate or merge, or sell substantially all of our assets. The 2021 Notes are not subject to any sinking fund requirements. All of our subsidiaries, other than minor subsidiaries, fully and unconditionally guarantee this debt jointly and severally.
Redemption of our 2013 and 2015 Notes
On February 3, 2011, we commenced cash tender offers to purchase all $225.0 million principal amount of our 2013 Notes and all $300.0 million principal amount of our 2015 Notes. Upon expiration of the tender offers on March 3, 2011, we accepted for purchase $169.6 million in principal of the 2013 Notes at 100.625% of par, and $220.9 million in principal of the 2015 Notes at 104.125% of par. We called the remaining 2013 and 2015 Notes, repurchasing all of the remaining outstanding 2015 Notes ($79.1 million) at 103.75% of par on March 21, 2011 and all of the remaining outstanding 2013 Notes ($55.4 million) at par on April 1, 2011. We recognized a $16.1 million loss during the nine months ended September 30, 2011 associated with the debt repurchases, which is included in our Unaudited Condensed Consolidated Statements of Operations under the caption “Loss on early extinguishment of debt”. |
Long-Term Debt (Tables) | 9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Table Text Block Supplement [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Components of Long-Term Debt |
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Supplemental Information (Details 1) (USD $) | 9 Months Ended | |
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Sep. 30, 2011 | Sep. 30, 2010 | |
Supplemental Cash Flow Information | ||
Cash paid for interest, net of amounts capitalized | $ 137,289,000 | $ 114,012,000 |
Cash paid for interest, capitalized | 42,004,000 | 56,079,000 |
Cash paid for income taxes | 36,688,000 | 13,691,000 |
Cash received for income tax refunds | 21,990,000 | 13,525,000 |
Increase (decrease) in liabilities for capital expenditures | 86,769,000 | 13,880,000 |
Issuance of Denbury common stock in connection with the Encore Merger | $ 0 | $ 2,085,681,000 |
Acquisitions and Divestitures (Details Textuals) (USD $) | 3 Months Ended | 6 Months Ended | 9 Months Ended | 1 Months Ended | 1 Months Ended | |||||||||||
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Sep. 30, 2011 | Sep. 30, 2010 | Sep. 30, 2010 | Sep. 30, 2011 | Sep. 30, 2010 | Dec. 31, 2010 | Mar. 31, 2010 | Oct. 15, 2010
Riley Ridge [Member]
Acres | May 31, 2010
Southern Assets [Member] | Aug. 31, 2010
Cleveland Sand Play [Member] | Aug. 01, 2011
Riley Ridge Phase 2 [Member] | Aug. 01, 2011
Additional Acres Surrounding Riley Ridge [Member] | Aug. 01, 2011
Riley Ridge Gas Plant [Member] | Oct. 15, 2010
Riley Ridge Gas Plant [Member] | Mar. 31, 2010
Genesis Energy LP [Member] | Feb. 28, 2010
Genesis Energy LLC [Member] | |
Acquisitions and Divestitures (Textuals) [Abstract] | ||||||||||||||||
Value of Encore Merger | $ 4,800,000,000 | |||||||||||||||
Revenues recognized from current period acquisitions | 174,300,000 | 435,200,000 | ||||||||||||||
Transaction and other costs | 0 | 11,470,000 | 4,377,000 | 79,253,000 | ||||||||||||
Working interest in business acquisition | 42.50% | 57.50% | 33.00% | 57.50% | 42.50% | |||||||||||
Acreage adjacent to Riley Ridge | 28,000 | |||||||||||||||
Business Acquisition, Percentage of CO2 rights in additional 28,000 acres | 33.00% | |||||||||||||||
Net Field Operating Income | 114,100,000 | 294,800,000 | ||||||||||||||
Net proceeds from sale of interest in Genesis | 79,000,000 | 84,000,000 | ||||||||||||||
Pre tax gain on sale of interest in Genesis | 0 | (3,000) | 0 | 101,537,000 | ||||||||||||
Gain on sale of interest in Genesis after tax | 63,000,000 | |||||||||||||||
Net proceeds from sales of oil and natural gas properties and equipment | 47,598,000 | 909,986,000 | 892,100,000 | 32,100,000 | ||||||||||||
Contingent payment to be paid at the time the property's gas processing facility is operational and meets specific performance conditions | $ 15,000,000 | $ 15,000,000 | $ 0 | $ 15,000,000 |
Condensed Consolidated Statements of Operations (Unaudited) (Parenthetical) (USD $) | 3 Months Ended | 9 Months Ended | ||
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Sep. 30, 2011 | Sep. 30, 2010 | Sep. 30, 2011 | Sep. 30, 2010 | |
Expenses | ||||
Interest capitalized | $ 17,853,000 | $ 10,917,000 | $ 42,004,000 | $ 56,079,000 |
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Fair value hierarchy of financial assets and liabilities |
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The changes in the fair value of Denbury's Level 3 assets and liabilities |
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Fair value of financial instruments that are not recorded at fair value in our Consolidated Financial Statements |
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Basis of Presentation (Details) | 3 Months Ended | 9 Months Ended | ||
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Sep. 30, 2011 | Sep. 30, 2010 | Sep. 30, 2011 | Sep. 30, 2010 | |
Weighted average shares used in the basic and diluted net income per common share | ||||
Weighted average common shares - basic | 399,040,000 | 395,913,000 | 398,371,000 | 362,241,000 |
Potentially dilutive securities: | ||||
Performance-Based Awards | 41,000 | 292,000 | 22,000 | 305,000 |
Weighted average common shares - diluted | 403,311,000 | 401,093,000 | 403,575,000 | 367,434,000 |
Stock Options and SARs [Member] | ||||
Potentially dilutive securities: | ||||
Stock options, SARs, and Restricted stock | 2,954,000 | 3,647,000 | 3,818,000 | 3,772,000 |
Restricted Stock [Member] | ||||
Potentially dilutive securities: | ||||
Stock options, SARs, and Restricted stock | 1,276,000 | 1,241,000 | 1,364,000 | 1,116,000 |
Condensed Consolidated Statements of Comprehensive Operations (Unaudited) (USD $) | 3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2011 | Sep. 30, 2010 | Sep. 30, 2011 | Sep. 30, 2010 | |
Condensed Consolidated Statements of Comprehensive Operations [Abstract] | ||||
Consolidated net income (loss) | $ 275,670,000 | $ 31,234,000 | $ 520,726,000 | $ 281,767,000 |
Other comprehensive income (loss), net of income tax: | ||||
Net unrealized losses on available-for-sale securities, net of tax | (3,949,000) | 0 | (6,925,000) | 0 |
Interest rate lock derivative contracts reclassified to income, net of tax | 17,000 | 17,000 | 52,000 | 52,000 |
Change in deferred hedge loss on interest rate swaps, net of tax | 0 | (68,000) | 0 | (155,000) |
Consolidated comprehensive income (loss) | 271,738,000 | 31,183,000 | 513,853,000 | 281,664,000 |
Less: comprehensive income attributable to noncontrolling interest | 0 | (2,074,000) | 0 | (20,308,000) |
Comprehensive income (loss) attributable to Denbury stockholders | $ 271,738,000 | $ 29,109,000 | $ 513,853,000 | $ 261,356,000 |
Subsequent Events | 9 Months Ended |
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Sep. 30, 2011 | |
Subsequent Events [Abstract] | |
Subsequent Events (Unaudited) | Note 8. Subsequent Event
In early October 2011, we announced the commencement of a common share repurchase program for up to $500 million of Denbury common shares, as approved by the Company's Board of Directors. The program has no pre-established ending date, and may be suspended or discontinued at any time. The Company is not obligated to repurchase any dollar amount or specific number of shares of its common stock under the program. Between early October 2011 and October 31, 2011, we repurchased 10,990,939 shares of Denbury common stock (approximately 2.7% of our outstanding shares of common stock at September 30, 2011) for $149.3 million, or $13.58 per share under this share repurchase program.
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Derivative Instruments and Hedging Activities (Details 2) (USD $) | Sep. 30, 2011 | Dec. 31, 2010 |
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Derivative financial instruments in Balance Sheet | ||
Total derivatives not designated as hedging instruments | $ 163,236,000 | $ (70,710,000) |
Oil contracts [Member] | Derivative assets-current [Member] | ||
Derivative financial instruments in Balance Sheet | ||
Derivative assets | 96,177,000 | 3,050,000 |
Natural Gas Contracts [Member] | Derivative assets-current [Member] | ||
Derivative financial instruments in Balance Sheet | ||
Derivative assets | 20,584,000 | 21,192,000 |
Oil contracts [Member] | Derivative assets - long - term [Member] | ||
Derivative financial instruments in Balance Sheet | ||
Derivative assets | 52,627,000 | 1,301,000 |
Natural Gas Contracts [Member] | Derivative assets - long - term [Member] | ||
Derivative financial instruments in Balance Sheet | ||
Derivative assets | 3,833,000 | 11,618,000 |
Oil contracts [Member] | Derivative liabilities-current [Member] | ||
Derivative financial instruments in Balance Sheet | ||
Derivative Liability | 60,000 | 55,256,000 |
Natural Gas Contracts [Member] | Derivative liabilities-current [Member] | ||
Derivative financial instruments in Balance Sheet | ||
Derivative Liability | 0 | 0 |
Derivative liabilities-current [Member] | Deferred Premiums [Member] | ||
Derivative financial instruments in Balance Sheet | ||
Derivative Liability | 9,193,000 | 22,928,000 |
Oil contracts [Member] | Derivative liabilities-long term [Member] | ||
Derivative financial instruments in Balance Sheet | ||
Derivative Liability | 70,000 | 25,906,000 |
Natural Gas Contracts [Member] | Derivative liabilities-long term [Member] | ||
Derivative financial instruments in Balance Sheet | ||
Derivative Liability | 0 | 0 |
Derivative liabilities-long term [Member] | Deferred Premiums [Member] | ||
Derivative financial instruments in Balance Sheet | ||
Derivative Liability | $ 662,000 | $ 3,781,000 |
Derivative Instruments and Hedging Activities (Tables) | 9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Derivative Instruments and Hedging Activities (Tables) [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commodity derivative expense (income), included in our Consolidated Statements of Operations |
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Commodity derivative contracts not classified as hedging instruments |
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Derivative financial instruments in Balance Sheet |
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Fair Value Measurements (Details 1) (USD $) | 3 Months Ended | 9 Months Ended | ||
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Sep. 30, 2011 | Sep. 30, 2010 | Sep. 30, 2011 | Sep. 30, 2010 | |
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract] | ||||
Balance, beginning of period | $ 6,638,000 | $ 40,283,000 | $ 16,478,000 | $ 0 |
Unrealized gains on commodity derivative contracts included in net earnings | 1,717,000 | 20,103,000 | (5,359,000) | 35,002,000 |
Commodity derivative contracts acquired from Encore | 0 | 0 | 0 | 38,093,000 |
Receipts on settlement of commodity derivative contracts | (1,378,000) | (9,035,000) | (4,142,000) | (21,744,000) |
Balance, end of period | $ 6,977,000 | $ 51,351,000 | $ 6,977,000 | $ 51,351,000 |