DENBURY RESOURCES INC, 10-K filed on 2/28/2013
Annual Report
Document and Entity Information (USD $)
12 Months Ended
Dec. 31, 2012
Jan. 31, 2013
Jun. 30, 2012
Document And Company Information [Abstract]
 
 
 
Entity Registrant Name
Denbury Resources Inc. 
 
 
Entity Central Index Key
0000945764 
 
 
Document Type
10-K 
 
 
Document Period End Date
Dec. 31, 2012 
 
 
Amendment Flag
false 
 
 
Document Fiscal Year Focus
2012 
 
 
Document Fiscal Period Focus
FY 
 
 
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 Public Float
 
 
$ 5,050,462,439 
Entity Common Stock, Shares Outstanding
 
373,462,597 
 
Consolidated Balance Sheets (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Current assets
 
 
Cash and cash equivalents
$ 98,511 
$ 18,693 
Restricted cash
1,050,015 
0 
Accrued production receivable
253,131 
294,689 
Trade and other receivables, net
81,971 
164,446 
Short-term investments
0 
86,682 
Derivative assets
19,477 
47,402 
Deferred tax assets
29,156 
50,156 
Other current assets
10,493 
22,045 
Total current assets
1,542,754 
684,113 
Oil and natural gas properties (using full cost accounting)
 
 
Proved
6,963,211 
7,026,579 
Unevaluated
809,154 
1,157,106 
CO2 properties
1,032,653 
596,003 
Pipelines and plants
2,035,126 
1,701,756 
Other property and equipment
417,207 
157,674 
Less accumulated depletion, depreciation, amortization and impairment
(3,180,241)
(2,627,493)
Net property and equipment
8,077,110 
8,011,625 
Derivative assets
36 
29 
Goodwill
1,283,590 
1,236,318 
Other assets
235,852 
252,339 
Total assets
11,139,342 
10,184,424 
Current liabilities
 
 
Accounts payable and accrued liabilities
414,668 
429,336 
Oil and gas production payable
161,945 
197,092 
Derivative liabilities
2,842 
26,523 
Current maturities of long-term debt
36,966 
8,316 
Total current liabilities
616,421 
661,267 
Long-term liabilities
 
 
Long-term debt, net of current portion
3,104,462 
2,669,729 
Asset retirement obligations
102,730 
88,726 
Derivative liabilities
23,781 
18,872 
Deferred taxes
2,153,452 
1,918,576 
Other liabilities
23,607 
20,756 
Total long-term liabilities
5,408,032 
4,716,659 
Commitments and contingencies (Note 11)
   
   
Stockholders' equity
 
 
Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding
0 
0 
Common stock, $.001 par value, 600,000,000 shares authorized; 406,163,194 and 402,946,070 shares issued, respectively
406 
403 
Paid-in capital in excess of par
3,136,461 
3,090,374 
Retained earnings
2,434,835 
1,909,475 
Accumulated other comprehensive loss
(348)
(418)
Treasury stock, at cost, 30,601,262 and 13,965,673 shares, respectively
(456,465)
(193,336)
Total stockholders' equity
5,114,889 
4,806,498 
Total liabilities and stockholders' equity
$ 11,139,342 
$ 10,184,424 
Consolidated Balance Sheets (Parenthetical) (USD $)
Dec. 31, 2012
Dec. 31, 2011
Stockholders' equity
 
 
Preferred stock, par value
$ 0.001 
$ 0.001 
Preferred stock, shares authorized (actual number)
25,000,000 
25,000,000 
Preferred stock, shares issued (actual number)
0 
0 
Preferred stock, shares outstanding (actual number)
0 
0 
Common stock, par value
$ 0.001 
$ 0.001 
Common stock, shares authorized (actual number)
600,000,000 
600,000,000 
Common stock, shares issued (actual number)
406,163,194 
402,946,070 
Treasury stock, shares (actual number)
30,601,262 
13,965,673 
Consolidated Statements of Operations (USD $)
In Thousands, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Revenues and other income
 
 
 
Oil, natural gas, and related product sales
$ 2,409,867 
$ 2,269,151 
$ 1,793,292 
CO2 sales and transportation fees
26,453 
22,711 
19,204 
Gain on sale of interests in Genesis
0 
0 
101,537 
Interest income and other income
20,152 
17,462 
7,758 
Total revenues and other income
2,456,472 
2,309,324 
1,921,791 
Expenses
 
 
 
Lease operating expenses
532,359 
507,397 
470,364 
Marketing expenses
52,836 
26,047 
31,036 
CO2 discovery and operating expenses
14,694 
14,258 
7,801 
Taxes other than income
160,016 
147,534 
120,541 
General and administrative expenses
144,019 
125,525 
134,121 
Interest, net of amounts capitalized of $77,432, $61,586 and $66,815, respectively
153,581 
164,360 
176,113 
Depletion, depreciation and amortization
507,538 
409,196 
434,307 
Derivatives expense (income)
 
 
(23,833)
Loss on early extinguishment of debt
0 
16,131 
0 
Transaction and other costs related to the Encore Merger
0 
4,377 
92,271 
Impairment of assets
17,515 
22,951 
0 
Other expenses
21,891 
0 
0 
Total expenses
1,599,615 
1,385,279 
1,442,721 
Income before income taxes
856,857 
924,045 
479,070 
Income tax provision
331,497 
350,712 
193,543 
Consolidated net income
525,360 
573,333 
285,527 
Net income attributable to noncontrolling interest
0 
0 
(13,804)
Net income attributable to Denbury stockholders
$ 525,360 
$ 573,333 
$ 271,723 
Net income per common share - basic
$ 1.36 
$ 1.45 
$ 0.73 
Net income per common share - diluted
$ 1.35 
$ 1.43 
$ 0.72 
Weighted average common shares outstanding
 
 
 
Basic
385,205 
396,023 
370,876 
Diluted
388,938 
400,958 
376,255 
Consolidated Statements of Operations (Parenthetical) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Expenses
 
 
 
Interest, capitalized
$ 77,432 
$ 61,586 
$ 66,815 
Consolidated Statements of Comprehensive Operations (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Statement of Other Comprehensive Income [Abstract]
 
 
 
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax
$ 70 
$ 70 
$ (14)
Consolidated net income
525,360 
573,333 
285,527 
Interest rate lock derivative contracts reclassified to income, net of tax of $43, $43 and $43, respectively
70 
70 
69 
Change in deferred hedge loss on interest rate swaps, net of tax benefit of $62
0 
0 
(83)
Total other comprehensive income (loss)
70 
70 
(14)
Comprehensive income
525,430 
573,403 
285,513 
Less: comprehensive income attributable to noncontrolling interest
0 
0 
(13,727)
Comprehensive income attributable to Denbury stockholders
$ 525,430 
$ 573,403 
$ 271,786 
Consolidated Statements of Comprehensive Operations (Parenthetical) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Other comprehensive income (loss), net of income tax:
 
 
 
Tax for interest rate lock derivative contracts reclassified to income
$ 43 
$ 43 
$ 43 
Tax for change in fair value of interest rate lock derivative contracts designated as a hedge
$ 0 
$ 0 
$ (62)
Consolidated Statements of Cash Flows (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Cash flow from operating activities:
 
 
 
Consolidated net income
$ 525,360 
$ 573,333 
$ 285,527 
Adjustments to reconcile consolidated net income to cash flow from operating activities:
 
 
 
Depletion, depreciation and amortization
507,538 
409,196 
434,307 
Deferred income taxes
255,743 
342,463 
160,349 
Gain on sale of interests in Genesis
0 
0 
(101,537)
Stock-based compensation
29,310 
33,190 
35,366 
Non-cash fair value derivative adjustments
13,159 
(50,008)
(55,445)
Loss on early extinguishment of debt
0 
16,131 
0 
Amortization of debt issuance costs and discounts
14,695 
16,954 
17,876 
Impairment of assets
17,515 
22,951 
0 
Other, net
16,804 
(4,302)
(2,144)
Changes in assets and liabilities, net of effects from acquisitions:
 
 
 
Accrued production receivable
36,234 
(74,781)
2,426 
Trade and other receivables
45,836 
(55,470)
24,977 
Other current and long-term assets
7,688 
(15,817)
(4,119)
Accounts payable and accrued liabilities
5,828 
(35,462)
48,549 
Oil and natural gas production payable
(23,460)
54,391 
15,565 
Other liabilities
(41,359)
(27,955)
(5,886)
Net cash provided by operating activities
1,410,891 
1,204,814 
855,811 
Cash flow used for investing activities:
 
 
 
Oil and natural gas capital expenditures
(1,122,615)
(1,082,853)
(671,574)
Acquisitions of oil and natural gas properties
(156,082)
(35,305)
(25,672)
Cash paid in Encore Merger and Riley Ridge acquisitions
0 
(199,263)
(947,241)
Cash received in Bakken Exchange Transaction
281,669 
0 
0 
CO2 capital expenditures
(131,043)
(84,789)
(93,556)
Pipelines and plants capital expenditures
(330,417)
(236,133)
(207,536)
Purchases of other assets
(25,765)
(28,838)
(28,684)
Net proceeds from sale of interests in Genesis
0 
0 
162,619 
Net proceeds from sales of oil and natural gas properties and equipment
34,750 
69,370 
1,458,029 
Net proceeds from sale of short-term investments
83,545 
0 
0 
Other
(10,883)
(8,147)
(1,165)
Net cash used for investing activities
(1,376,841)
(1,605,958)
(354,780)
Cash flow provided by (used for) financing activities:
 
 
 
Bank repayments
(1,555,000)
(330,000)
(1,530,000)
Bank borrowings
1,870,000 
715,000 
1,114,000 
Repayment of senior subordinated notes
0 
(525,000)
(609,424)
Premium paid on repayment of senior subordinated notes
0 
(13,137)
(7,213)
Net proceeds from issuance of senior subordinated notes
0 
400,000 
1,000,000 
Costs of debt financing
(34)
(13,123)
(76,251)
ENP distributions to noncontrolling interest
0 
0 
(36,738)
Common stock repurchase program
(251,480)
(195,227)
0 
Other
(17,718)
(545)
5,873 
Net cash provided by (used for) financing activities
45,768 
37,968 
(139,753)
Net increase (decrease) in cash and cash equivalents
79,818 
(363,176)
361,278 
Cash and cash equivalents at beginning of year
18,693 
381,869 
20,591 
Cash and cash equivalents at end of year
$ 98,511 
$ 18,693 
$ 381,869 
Consolidated Statements of Changes in Stockholders' Equity (USD $)
In Thousands, except Share data
Total
Denbury Stockholders' Equity
Common Stock ($.001 Par Value)
Paid-In Capital in Excess of par
Retained Earnings
Accumulated Other Comprehensive Income (Loss)
Treasury Stock (at cost)
Noncontrolling Interest
Beginning Balance at Dec. 31, 2009
$ 1,972,237 
$ 1,972,237 
$ 262 
$ 910,540 
$ 1,064,419 
$ (557)
$ (2,427)
$ 0 
Beginning balance, shares at Dec. 31, 2009
 
 
261,929,292 
 
 
 
156,284 
 
Repurchase of common stock, value
(6,729)
(6,729)
 
 
 
 
(6,729)
 
Repurchase of common stock, shares
 
 
 
 
 
 
413,869 
 
Issued pursuant to employee stock purchase plan, value
8,197 
8,197 
 
325 
 
 
7,872 
 
Issued pursuant to employee stock purchase plan, shares
 
 
 
 
 
 
(491,629)
 
Issued pursuant to employee stock option plan, value
4,868 
4,868 
1 
4,867 
 
 
 
 
Issued pursuant to employee stock option plan, shares
 
 
999,077 
 
 
 
 
 
Issued pursuant to directors' compensation plan, value
266 
266 
 
266 
 
 
 
 
Issued pursuant to directors' compensation plan, shares
 
 
16,118 
 
 
 
 
 
Issued pursuant to Encore Merger, value
2,085,681 
2,085,681 
135 
2,085,546 
 
 
 
 
Issued pursuant to Encore Merger, shares
135,200,000 
 
135,170,505 
 
 
 
 
 
Encore restricted stock grants, value
 
 
1 
(1)
 
 
 
 
Encore restricted stock grants, shares
 
 
1,070,686 
 
 
 
 
 
Restricted stock grants, value
1 
1 
1 
 
 
 
 
 
Restricted stock grants, shares
 
 
960,597 
 
 
 
 
 
Restricted stock grants - forfeited
 
 
(301,735)
 
 
 
 
 
Performance-based shares issued, shares
 
 
446,493 
 
 
 
 
 
Stock-based compensation
39,791 
39,791 
 
39,791 
 
 
 
 
Income tax benefit from equity awards
4,603 
4,603 
 
4,603 
 
 
 
 
ENP Revaluation At Encore Merger
515,210 
 
 
 
 
 
 
515,210 
ENP cash distributions to noncontrolling interest
(36,738)
 
 
 
 
 
 
(36,738)
Sale of ENP
(492,193)
 
 
 
 
 
 
(492,193)
Derivative contracts, net
(14)
69 
 
 
 
69 
 
(83)
Consolidated net income
285,527 
271,723 
 
 
271,723 
 
 
13,804 
Ending Balance at Dec. 31, 2010
4,380,707 
4,380,707 
400 
3,045,937 
1,336,142 
(488)
(1,284)
0 
Ending balance, shares at Dec. 31, 2010
 
 
400,291,033 
 
 
 
78,524 
 
Repurchase of common stock, value
(9,683)
(9,683)
 
 
 
 
(9,683)
 
Repurchase of common stock, shares
 
 
 
 
 
 
441,406 
 
Issued pursuant to employee stock purchase plan, value
11,235 
11,235 
 
(1,623)
 
 
12,858 
 
Issued pursuant to employee stock purchase plan, shares
 
 
(11,330)
 
 
 
(666,867)
 
Stock repurchase program, value
(195,227)
(195,227)
 
 
 
 
(195,227)
 
Stock repurchase program, shares
 
 
 
 
 
 
14,112,610 
 
Issued pursuant to employee stock option plan, value
4,686 
4,686 
1 
4,685 
 
 
 
 
Issued pursuant to employee stock option plan, shares
 
 
1,200,759 
 
 
 
 
 
Issued pursuant to directors' compensation plan, value
309 
309 
 
309 
 
 
 
 
Issued pursuant to directors' compensation plan, shares
 
 
19,745 
 
 
 
 
 
Issued pursuant to Encore Merger, value
0 
 
 
 
 
 
 
 
Restricted stock grants, value
1 
1 
1 
 
 
 
 
 
Restricted stock grants, shares
 
 
1,134,627 
 
 
 
 
 
Restricted stock grants - forfeited
 
 
(157,811)
 
 
 
 
 
Performance-based shares issued, Value
1 
1 
1 
 
 
 
 
 
Performance-based shares issued, shares
 
 
446,387 
 
 
 
 
 
Stock-based compensation
40,187 
40,187 
 
40,187 
 
 
 
 
Income tax benefit from equity awards
879 
879 
 
879 
 
 
 
 
Derivative contracts, net
70 
70 
 
 
 
70 
 
 
Consolidated net income
573,333 
573,333 
 
 
573,333 
 
 
 
Ending Balance at Dec. 31, 2011
4,806,498 
4,806,498 
403 
3,090,374 
1,909,475 
(418)
(193,336)
0 
Ending balance, shares at Dec. 31, 2011
 
 
402,946,070 
 
 
 
13,965,673 
 
Repurchase of common stock, value
(8,125)
(8,125)
 
 
 
 
(8,125)
 
Repurchase of common stock, shares
 
 
 
 
 
 
472,966 
 
Issued pursuant to employee stock purchase plan, value
13,260 
13,260 
 
1,607 
 
 
11,653 
 
Issued pursuant to employee stock purchase plan, shares
 
 
 
 
 
 
(815,385)
 
Stock repurchase program, value
(266,657)
(266,657)
 
 
 
 
(266,657)
 
Stock repurchase program, shares
 
 
 
 
 
 
16,978,008 
 
Issued pursuant to employee stock option plan, value
6,023 
6,023 
1 
6,022 
 
 
 
 
Issued pursuant to employee stock option plan, shares
2,029,570 
 
1,429,309 
 
 
 
 
 
Issued pursuant to directors' compensation plan, value
321 
321 
 
321 
 
 
 
 
Issued pursuant to directors' compensation plan, shares
 
 
19,648 
 
 
 
 
 
Issued pursuant to Encore Merger, value
0 
 
 
 
 
 
 
 
Restricted stock grants, value
1 
1 
2 
(1)
 
 
 
 
Restricted stock grants, shares
 
 
1,909,739 
 
 
 
 
 
Restricted stock grants - forfeited
 
 
(261,762)
 
 
 
 
 
Performance-based shares issued, shares
 
 
120,190 
 
 
 
 
 
Stock-based compensation
37,897 
37,897 
 
37,897 
 
 
 
 
Income tax benefit from equity awards
241 
241 
 
241 
 
 
 
 
Derivative contracts, net
70 
70 
 
 
 
70 
 
 
Consolidated net income
525,360 
525,360 
 
 
525,360 
 
 
 
Ending Balance at Dec. 31, 2012
$ 5,114,889 
$ 5,114,889 
$ 406 
$ 3,136,461 
$ 2,434,835 
$ (348)
$ (456,465)
$ 0 
Ending balance, shares at Dec. 31, 2012
 
 
406,163,194 
 
 
 
30,601,262 
 
Significant Accounting Policies
Significant Accounting Policies [Text Block]
Note 1. Significant Accounting Policies

Organization and Nature of Operations

Denbury Resources Inc., a Delaware corporation, is a growing independent oil and natural gas company.  We are the largest combined 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 our acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO2 tertiary recovery operations.

Encore Merger.  On March 9, 2010, we acquired Encore Acquisition Company (“Encore”), pursuant to an Agreement and Plan of Merger (the “Encore Merger Agreement”), under which Encore was merged with and into Denbury (the “Encore Merger”), with Denbury surviving the Encore Merger following approval by the stockholders of both Denbury and Encore, closing of a new revolving credit facility as part of the financing for the Encore Merger, and satisfaction of other conditions precedent.  The Encore Merger provided Encore stockholders stock and/or cash and included the assumption of Encore’s debt by Denbury.  Denbury has consolidated Encore’s results of operations since the March 9, 2010 acquisition date.  See Note 2, Acquisitions and Divestitures, for more information.

Principles of Reporting and Consolidation

The consolidated financial statements herein have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and include the accounts of Denbury and entities in which we hold a controlling financial interest.  Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis.  Investments in non-controlled entities over which we exercise significant influence are accounted for under the equity method.  Other investments are carried at cost.  All intercompany balances and transactions have been eliminated.

From March 9, 2010 through December 31, 2010, we owned approximately 46% of Encore Energy Partners LP (“ENP”) outstanding common units and 100% of Encore Energy Partners GP LLC (“ENP GP LLC”) membership interests, which was ENP’s general partner.  Considering the presumption of control of ENP 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 ENP GP LLC; therefore, we did not consolidate ENP in our Consolidated Balance Sheet as of December 31, 2010.  As presented in the accompanying Consolidated Statement of Operations for the year ended December 31, 2010, “Net income attributable to noncontrolling interest” of $13.8 million represents ENP’s results of operations attributable to limited partners other than Denbury for the portion of the year for which we consolidated ENP.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amount of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during each reporting period.  Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates.  Significant estimates underlying these financial statements include: (1) the fair value of financial derivative instruments; (2) the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom and the ceiling test; (3) the estimated quantities of proved and probable CO2 reserves used to compute depletion of CO2 properties; (4) accruals related to oil and natural gas sales volumes and revenues, capital expenditures and lease operating expenses; (5) the estimated costs and timing of future asset retirement obligations; (6) estimates made in the calculation of income taxes; and (7) estimates made in determining the fair values for purchase price allocations, including goodwill.  While management is not aware of any significant revisions to any of its estimates, there will likely be future revisions to its estimates resulting from matters such as revisions in estimated oil and natural gas volumes, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and natural gas industry, many of which require retroactive application.  These types of adjustments cannot be currently estimated and will be recorded in the period in which the adjustment occurs. 

Reclassifications

Certain prior period amounts have been reclassified to conform with the current year presentation. Such reclassifications had no impact on our reported net income, current assets, total assets, current liabilities, total liabilities or stockholders' equity.

Cash Equivalents

We consider all highly liquid investments to be cash equivalents if they have maturities of three months or less at the date of purchase.

Restricted Cash

Restricted cash at December 31, 2012 consists of proceeds from the exchange of oil and gas properties with Exxon Mobil Corporation and its wholly-owned subsidiary XTO Energy Inc. (see Note 2, Acquisitions and Divestitures) being held by a qualified intermediary through three separate financial institutions and which are restricted for application towards future potential acquisitions to facilitate an anticipated like-kind-exchange transaction for federal income tax purposes. We manage and control counterparty credit risk related to this restricted cash using a trust agreement, whereby the assets held in trust must be segregated from the financial institution's assets, and in the event of a bankruptcy, the funds would not be subject to payments to the creditors of the financial institution.

Short-term Investments

Short-term investments represent available-for-sale securities recorded at fair value with any unrealized gains or losses included in accumulated other comprehensive income.  At December 31, 2011, 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 (see Note 2, Acquisitions and Divestitures).  Our original cost basis of this investment was $93.0 million.  We received distributions of $7.2 million on the Vanguard common units we owned for the year ended December 31, 2011, which are included in “Interest income and other income” on our Consolidated Statements of Operations.  Due to the decline in the market value of this investment and the expectation that the investment would not recover its cost basis prior to the time of sale, we recorded a $6.3 million “other-than-temporary” impairment loss on this investment for the year ended December 31, 2011, which is included in “Impairment of assets” on our Consolidated Statements of Operations.  During January 2012, we sold our investment in Vanguard for cash consideration of $83.5 million, net of related transaction fees. The Company recognized a pretax loss on the sale of $3.1 million, which is included in “Other expenses” on our Consolidated Statements of Operations for the year ended December 31, 2012.

Oil and Natural Gas Properties

Capitalized Costs.  We follow the full cost method of accounting for oil and natural gas properties.  Under this method, all costs related to acquisitions, exploration and development of oil and natural gas reserves are capitalized and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States.  Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and nonproductive wells, capitalized interest on qualifying projects, and general and administrative expenses directly related to exploration and development activities, and do not include any costs related to production, general corporate overhead or similar activities.  We assign the purchase price of oil and natural gas properties we acquire to proved and unevaluated properties based on the estimated fair values as defined in the FASC Fair Value Measurements and Disclosures topic.  Proceeds received from disposals are credited against accumulated costs except when the sale represents a significant disposal of reserves, in which case a gain or loss would be recognized. A disposal of twenty-five percent or more of our proved reserves would be considered significant.

Depletion and Depreciation.  The costs capitalized, including production equipment and future development costs, are depleted or depreciated using the unit-of-production method, based on proved oil and natural gas reserves as determined by independent petroleum engineers.  Oil and natural gas reserves are converted to equivalent units on a basis of 6,000 cubic feet of natural gas to one barrel of crude oil.  The depletion and depreciation rate per BOE associated with our oil and gas producing activities was $18.69 in 2012, $16.42 in 2011 and $15.82 in 2010.

Under full cost accounting, we may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves can be assigned to such properties.  The costs classified as unevaluated are transferred to the full cost amortization base as the properties are developed, tested and evaluated.

Ceiling Test. The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling.  The cost center ceiling is defined as: (1) the present value of estimated future net revenues from proved reserves before future abandonment costs (discounted at 10%), based on the average first-day-of-the-month oil and natural gas price for each month during the 12-month period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects.  Our future net revenues from proved reserves are not reduced for development costs related to the cost of drilling for and developing CO2 reserves nor those related to the cost of constructing CO2 pipelines, as those costs have previously been incurred by the Company.  Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves.  The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes.  The cost center ceiling test is prepared quarterly.  We did not have a ceiling test write-down during the years ended December 31, 2012, 2011 or 2010. 

Joint Interest Operations.  Substantially all of our oil and natural gas exploration and production activities are conducted jointly with others.  These financial statements reflect only our proportionate interest in such activities, and any amounts due from other partners are included in trade receivables.
 
Tertiary Injection Costs.  Our tertiary operations are conducted in reservoirs that have already produced significant amounts of oil over many years; however, in accordance with the SEC rules and regulations for recording proved reserves, we cannot recognize proved reserves associated with enhanced recovery techniques, such as CO2 injection, until there is a production response to the injected CO2, or unless the field is analogous to an existing flood.  

We capitalize, as a development cost, injection costs in fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO2 injections (i.e., a production response).  These capitalized development costs are included in our unevaluated property costs if there are not already proved tertiary reserves in that field.  After we see a production response to the CO2 injections (i.e., the production stage), injection costs are expensed as incurred, and once proved reserves are recognized, previously deferred unevaluated development costs become subject to depletion.

CO2 Properties

We own and produce CO2 reserves, a non-hydrocarbon resource, that are used in our tertiary oil recovery operations on our own behalf and on behalf of other interest owners in enhanced recovery fields, with a portion sold to third-party industrial users.  We record revenue from our sales of CO2 to third parties when it is produced and sold.  Expenses related to the production of CO2 are allocated between volumes sold to third parties and volumes consumed internally that are directly related to our tertiary production.  The expenses related to third-party sales are recorded in “CO2 discovery and operating expenses,” and the expenses related to internal use are recorded in “Lease operating expenses” in the Consolidated Statements of Operations, or are capitalized as oil and gas properties in our Consolidated Balance Sheets, depending on the status of floods that receive the CO2 (see Tertiary Injection Costs above for further discussion).

During 2010 and 2011, we acquired interests in the Riley Ridge Federal Unit (“Riley Ridge”), in which helium and CO2 (non-hydrocarbon resources) as well as natural gas (a hydrocarbon resource) are present.  It is not possible to separately identify the capitalized costs related to the development of each product in the commingled gas stream; thus, these costs are allocated to each product based on the relative future revenue value of each product line and classified accordingly on the Consolidated Balance Sheets.

During 2010, we revised our capitalization policies for CO2 properties.  Previously, we accounted for our CO2 source properties in a manner similar to our method of accounting for oil and natural gas properties, as the process and activities to identify, develop and produce CO2 reserves are virtually identical to those used to identify, develop and produce oil and natural gas reserves.  However, because CO2 is not a hydrocarbon, it is excluded from the scope of FASC Topic 932, Extractive Industries – Oil and Gas; therefore, we are precluded from accounting for our CO2 operations in accordance with FASC Topic 932.  Accordingly, commencing in July 2010, costs incurred to search for CO2 are expensed as incurred until proved or probable reserves are established.  Once proved or probable reserves are established, costs incurred to obtain those reserves are capitalized and classified as “CO2 properties” on our Consolidated Balance Sheets.  Capitalized CO2 is aggregated by geologic formation and depleted on a unit-of-production basis over proved and probable reserves.  The impact of the revised accounting policy on our financial statements was not material to any individual year.  We recognized the cumulative impact of the revised accounting policy as a noncash net reduction to depletion, depreciation and amortization during the year ended December 31, 2010, resulting in a pretax credit of $9.6 million ($6.0 million after tax), which reflected a reduction to “CO2 properties” of $26.1 million offset by a decrease in “Accumulated depletion, depreciation and amortization” of $35.7 million.  The cumulative adjustment did not have an impact on our net cash flows.

The portion of our capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil reserves is included in the ceiling test as a reduction to future net revenues.  The remaining net capitalized CO2 properties, equipment and pipelines balance is evaluated for impairment by comparing the net carrying costs to the expected future net revenues from (1) the production of our probable and possible tertiary oil reserves and (2) the sale of CO2 to third-party industrial users.

Pipelines and Plants

CO2 used in our tertiary floods is transported to our fields through CO2 pipelines.  Costs of CO2 pipelines under construction are not depreciated until the pipelines are placed into service.  Pipelines are depreciated on a straight-line basis over their estimated useful lives, which range from 15 to 50 years.

Pipelines and plants include the Riley Ridge gas plant in southwestern Wyoming, which is currently under construction.  The plant is being withheld from depreciation until it is placed in service, which we currently expect to occur during mid-2013.

Property and Equipment – Other

Other property and equipment, which includes furniture and fixtures, vehicles, computer equipment and software, and capitalized leases, is depreciated principally on a straight-line basis over estimated useful lives.  Vehicles and furniture and fixtures are generally depreciated over a useful life of five to ten years, and computer equipment and software are generally depreciated over a useful life of three to five years.  Leasehold improvements are amortized over the shorter of the estimated useful life or the remaining lease term.

Leased property meeting certain capital lease criteria is capitalized, and the present value of the related lease payments is recorded as a liability.  Amortization of capitalized leased assets is computed using the straight-line method over the shorter of the estimated useful life or the initial lease term.

Maintenance and repair costs that do not extend the useful lives of property and equipment are charged to expense as incurred.

Asset Retirement Obligations

In general, our future asset retirement obligations relate to future costs associated with plugging and abandoning our oil, natural gas and CO2 wells, removing equipment and facilities from leased acreage, and returning land to its original condition.  The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit-adjusted-risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset.  The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset.  Revisions to estimated retirement obligations will result in an adjustment to the related capitalized asset and corresponding liability.  If the liability is settled for an amount other than the recorded amount, the difference is recorded to the full cost pool, unless significant.

Asset retirement obligations are estimated at the present value of expected future net cash flows and are discounted using our credit-adjusted-risk-free rate.  We utilize unobservable inputs in the estimation of asset retirement obligations that include, but are not limited to, costs of labor, costs of materials, profits on costs of labor and materials, the effect of inflation on estimated costs, and the discount rate.  Accordingly, asset retirement obligations are considered a Level 3 measurement under the FASC Fair Value Measurements and Disclosures topic.

Derivative Instruments and Hedging Activities

We utilize oil and natural gas derivative contracts to mitigate our exposure to commodity price risk associated with our future oil and natural gas production.  These derivative contracts have historically consisted of options, in the form of price floors or collars, and fixed price swaps.  From time to time, we have also used interest rate lock contracts to mitigate our exposure to interest rate fluctuations related to sale-leaseback financing of certain equipment used at our oilfield facilities.  Our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value.  We do not apply hedge accounting to our oil and natural gas derivative contracts; accordingly, the changes in the fair value of these instruments are recognized in our Consolidated Statements of Operations in the period of change.

Financial Instruments with Off-Balance-Sheet Risk and Concentrations of Credit Risk

Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents, trade and accrued production receivables, and the derivative instruments discussed above.  Our cash equivalents represent high-quality securities placed with various investment-grade institutions.  This investment practice limits our exposure to concentrations of credit risk.  Our trade and accrued production receivables are dispersed among various customers and purchasers; therefore, concentrations of credit risk are limited.  We evaluate the credit ratings of our purchasers, and if customers are considered a credit risk, letters of credit are the primary security obtained to support lines of credit.  We attempt to minimize our credit risk exposure to the counterparties of our oil and natural gas derivative contracts through formal credit policies, monitoring procedures and diversification.  All of our derivative contracts are with banks, which are part of the syndicate of banks in our bank credit facility, or with their affiliates.  There are no margin requirements with the counterparties of our derivative contracts.

Goodwill

Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Goodwill is not amortized; rather, it is tested for impairment annually during the fourth quarter and when events or changes in circumstances indicate that it is more likely than not the fair value of a reporting unit with goodwill has been reduced below its carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units.  However, we have only one reporting unit.  To assess impairment, we have the option to qualitatively assess if it is more likely than not that the fair value of the reporting unit is less than the carrying value.  Absent a qualitative assessment, or, through the qualitative assessment, if we determine it is more likely than not that the fair value of the reporting unit is less than the carrying value, a quantitative assessment is prepared to calculate the fair market value of the reporting unit.  If it is determined that the fair value of the reporting unit is less than the carrying value, the recorded goodwill is impaired to its implied fair value with a charge to operating expense.  We completed our annual goodwill impairment assessment during the fourth quarter of 2012 and did not record any goodwill impairment during 2012, nor have we recorded a goodwill impairment historically.

The following table summarizes the changes in goodwill for the years ended December 31, 2012 and 2011:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
Beginning of year balance
 
$
1,236,318

 
$
1,232,418

Goodwill related to the Riley Ridge acquisition
 
—

 
3,900

Goodwill related to the Thompson Field acquisition
 
47,272

 
—

End of year balance
 
$
1,283,590

 
$
1,236,318



Revenue Recognition

Revenue is recognized at the time oil and natural gas is produced and sold.  Any amounts due from purchasers of oil and natural gas are included in accrued production receivable.

We follow the sales method of accounting for our oil and natural gas revenue, whereby we recognize revenue on all oil or natural gas sold to our purchasers regardless of whether the sales are proportionate to our ownership in the property.  A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves.  As of December 31, 2012 and 2011, our aggregate oil and natural gas imbalances were not material to our consolidated financial statements.

We recognize revenue and expenses of purchased producing properties at the time we assume effective control, commencing from either the closing or purchase agreement date, depending on the underlying terms and agreements.  We follow the same methodology in reverse when we sell properties by recognizing revenue and expenses of the sold properties until the closing date.

Income Taxes

Income taxes are accounted for using the asset and liability method, under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year end.  The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date.  A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the position.  The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement.

Net Income Per Common Share

Basic net income per common share is computed by dividing the net income attributable to common 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 includes the impact of potentially dilutive securities. Potentially dilutive securities consist of stock options, stock appreciation rights (“SARs”), nonvested restricted stock and nonvested performance equity awards. For each of the three years in the period ended December 31, 2012, there were no adjustments to net income for purposes of calculating basic and diluted net income per common share.

The following is a reconciliation of the weighted average shares used in the basic and diluted net income per common share calculations for the periods indicated:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Basic weighted average common shares
 
385,205

 
396,023

 
370,876

Potentially dilutive securities:
 
 
 
 

 
 

Stock options and SARs
 
2,584

 
3,539

 
3,844

Performance equity awards
 
86

 
38

 
319

Restricted stock
 
1,063

 
1,358

 
1,216

Diluted weighted average common shares
 
388,938

 
400,958

 
376,255



Basic weighted average common shares excludes 3.7 million, 3.4 million and 3.2 million shares of nonvested restricted stock during the year ended December 31, 2012, 2011 and 2010, respectively.  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, the nonvested 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 not included in the computation of diluted net income per share, as their effect would have been antidilutive:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Stock options and SARs
 
4,068

 
5,017

 
3,671

Restricted stock
 
47

 
104

 
17



Recent Accounting Pronouncements

Presentation of Comprehensive Income. In June 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update ("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 was effective for Denbury beginning January 1, 2012. Since ASU 2011-05 only amended presentation requirements, it did not have a material effect on our consolidated financial statements.

Accumulated Other Comprehensive Income Reclassifications. In February 2013, the FASB issued ASU 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income ("ASU 2013-02"). ASU 2013-02 requires disclosure of amounts reclassified out of accumulated other comprehensive income by component.  In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required to be reclassified to net income in its entirety in the same reporting period.  For amounts not reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures that provide additional detail about those amounts. ASU 2013-02 is effective prospectively for our fiscal year beginning January 1, 2013. The adoption of ASU 2013-02 will not have a material effect on our consolidated financial statements.

Fair Value. 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 was effective for Denbury beginning January 1, 2012. The adoption of ASU 2011-04 did not have a material effect on our consolidated financial statements, but did require additional disclosures. See Note 10, Fair Value Measurements.

Balance Sheet Offsetting.  In December 2011, the FASB issued ASU 2011-11, Disclosure about Offsetting Assets and Liabilities (“ASU 2011-11”).  ASU 2011-11 requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position.  In January 2013, the FASB issued ASU 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities ("ASU 2013-01"). The update clarifies that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with the Derivatives and Hedging topic of the FASC, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset or subject to an enforceable master netting arrangement or similar agreement. ASU 2011-11 and ASU 2013-01 are effective for our fiscal year beginning January 1, 2013 and will be applied retrospectively for all comparative periods presented.  The adoption of ASU 2011-11 and ASU 2013-01 will not have a material effect on our consolidated financial statements, but may require additional disclosures.
Acquisitions and Divestitures
Acquisitions and Divestitures
Note 2. Acquisitions and Divestitures

Acquisitions and Exchange Transaction

Fair Value.  The FASC Fair Value Measurements and Disclosures topic defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (often referred to as the “exit price”). The fair value measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore, entity-specific intentions do not impact the measurement of fair value unless those assumptions are consistent with market participant views.

The fair value of oil and natural gas properties is based on significant inputs not observable in the market, which the FASC Fair Value Measurements and Disclosures topic defines as Level 3 inputs.  Key assumptions may include: (1) NYMEX oil and natural gas futures (this input is observable); (2) dollar-per-acre values of recent sale transactions (this input is observable); (3) projections of the estimated quantities of oil and natural gas reserves, including those classified as proved, probable and possible; (4) estimated oil and natural gas pricing differentials; (5) projections of future rates of production; (6) timing and amount of future development and operating costs; (7) projected costs of CO2 (to a market participant); (8) projected reserve recovery factors; and (9) risk-adjusted discount rates.

Bakken Exchange Transaction. In late 2012, we closed a sale and exchange transaction with Exxon Mobil Corporation and its wholly-owned subsidiary XTO Energy Inc. (collectively, “ExxonMobil”) under which we sold to ExxonMobil our Bakken area assets in North Dakota and Montana in exchange for $1.3 billion in cash (after preliminary closing adjustments) and the following assets:

•
operating interests in the Webster Field, a planned future tertiary field, located in southeastern Texas, made up of a nearly 100% working interest and nearly 80% revenue interest;
•
operating interests in the Hartzog Draw Field, a planned future tertiary field, located in Wyoming, consisting of an 83% working interest and 71% net revenue interest in the oil-producing Shannon Sandstone zone and a 67% working interest and 53% net revenue interest in the natural gas producing Big George Coal zone; and
•
approximately a one-third overriding royalty ownership interest in ExxonMobil's CO2 reserves in LaBarge Field in Wyoming.

The exchange of properties closed in two phases on November 30, 2012 and December 21, 2012, and is collectively referred to as the "Bakken Exchange Transaction".

Our acquisition of property interests constitutes a business combination under the FASC Business Combinations topic. Accordingly, the purchase price of the acquisition is measured as the fair value of consideration transferred, which consists of our Bakken area assets. The fair value of Bakken area net assets transferred to ExxonMobil in the Bakken Exchange Transaction was measured using a discounted future net cash flow model for developed properties and a market dollar-per-acre value for undeveloped properties. The fair value of assets transferred in the Bakken Exchange Transaction was measured at the dates control was transferred to ExxonMobil, which were November 30, 2012 and December 21, 2012 for 82.5% and 17.5%, respectively, of our interest in our Bakken area assets. The fair value of oil and gas properties received from ExxonMobil in such transaction was measured using a discounted future net cash flow model, and the fair value of CO2 interests received was measured using a market-based approach, at the date control was transferred to Denbury, which was November 30, 2012, for the acquisition of interests in Webster and Hartzog Draw fields and December 21, 2012, for the acquisition of interests in LaBarge Field. We did not record a gain or loss on the exchange in accordance with the full cost method of accounting.

The following table presents a summary of the preliminary fair value of assets acquired and liabilities assumed in the Bakken Exchange Transaction:
In thousands
 
 
Consideration:
 
 
Fair value of net assets transferred
 
$
1,903,280

 
 
 
Less: Fair value of assets acquired and liabilities assumed: (1)
 
 
Cash (2)
 
1,331,684

Oil and natural gas properties
 
 
Proved
 
201,301

Unevaluated
 
98,635

CO2 properties
 
314,505

Other assets
 
477

Other liabilities
 
(29,531
)
Asset retirement obligations
 
(13,791
)
Fair value of net assets acquired
 
$
1,903,280


(1)
Fair value of the assets acquired and liabilities assumed is preliminary, pending final closing adjustments and further evaluation of reserves and asset retirement obligations.

(2)
Cash proceeds include preliminary closing adjustments of $41.7 million primarily representing adjustments for net revenues and capital expenditures of the transferred oil and natural gas property assets from the Bakken Exchange Transaction effective date to the closing dates. Also see Note 12, Supplemental Information and Note 13, Subsequent Events, for additional information regarding the placement of $1.05 billion of the proceeds in a qualified trust to facilitate an anticipated like-kind-exchange transaction for federal income tax purposes.

June 2012 Acquisition of Reserves in the Gulf Coast region at Thompson Field. In June 2012, we acquired a nearly 100% working interest and 84.7% net revenue interest in Thompson Field for $366.2 million after preliminary closing adjustments. The field is located approximately 18 miles west of Hastings Field, which is an enhanced oil recovery field that we are currently flooding with CO2, and is the current terminus of the Green Pipeline which transports CO2 from the Jackson Dome, located near Jackson, Mississippi. Thompson Field is similar to Hastings Field, producing oil from the Frio zone at similar depths, and is also a planned future tertiary field. Under the terms of the Thompson Field acquisition agreement, the seller will retain approximately a 5% gross revenue interest (less severance taxes) once average monthly oil production exceeds 3,000 Bbls/d after the initiation of CO2 injection.

This acquisition meets the definition of a business under the FASC Business Combinations topic. As such, we estimated the fair value of assets acquired and liabilities assumed as of June 1, 2012, the closing date of the acquisition using a discounted future net cash flow model. In applying these accounting principles, we estimated the fair value of the assets acquired less liabilities assumed on the acquisition date to be approximately $318.9 million. This measurement resulted in the recognition of goodwill of approximately $47.3 million, which represents the excess of the cash paid to acquire the field over the acquisition date estimated fair value. This resultant goodwill is due primarily to two factors. The first factor is the decrease in average NYMEX oil futures prices between the date of signing the purchase agreement on April 24, 2012 and closing the purchase on June 1, 2012. The second factor is the fair value assigned to the estimated oil reserves recoverable through a CO2 EOR project. By building an 18-mile extension of the Green Pipeline, we will have access to CO2 reserves at Jackson Dome, one of the few known significant natural sources of CO2 in the United States, and the largest known source east of the Mississippi River, allowing us to carry out CO2 EOR activities in this field at a lower cost than other market participants. However, the FASC Fair Value Measurements and Disclosures topic does not allow entity-specific assumptions in the measurement of fair value. Therefore, we estimated the fair value of the oil reserves recoverable through CO2 EOR using a higher estimated cost of CO2 to other market participants, which lowers the discounted net revenue stream used in making the fair value estimate related to this field. All of the goodwill associated with the acquisition is deductible for tax purposes as property cost.

The fair value of the assets acquired and liabilities assumed was finalized during the fourth quarter of 2012, after consideration of final closing adjustments and evaluation of reserves and asset retirement obligations. The following table presents a summary of the fair value of assets acquired and liabilities assumed in the Thompson Field acquisition:
In thousands
 
 
Consideration:
 
 
Cash payment (1)
 
$
366,179

 
 
 
Less: Fair value of assets acquired and liabilities assumed:
 
 
Oil and natural gas properties
 
 
Proved
 
305,233

Unevaluated
 
12,023

Pipelines and plants
 
2,000

Other assets
 
2,957

Asset retirement obligations
 
(3,306
)
 
 
318,907

Goodwill
 
$
47,272


(1)
See Note 6, Income Taxes, for additional information regarding the like-kind-exchange transaction utilized to fund this purchase and Note 12, Supplemental Information, for supplemental cash flow information regarding the cash payment.

October 2010 and August 2011 Riley Ridge Acquisitions.  In October 2010, we acquired a 42.5% non-operated working interest in Riley Ridge, located in 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, and interests in certain surrounding properties. On August 1, 2011, we acquired the remaining 57.5% working interest in Riley Ridge that we did not already own, the remaining 57.5% interest in the gas plant, and interests in certain surrounding properties for $214.8 million after closing adjustments.  As a result of the transaction, we became the operator of both projects.  The purchase price includes a $15 million deferred payment to be made, subject to the terms of the purchase agreement, at the time the property's gas plant is operational and meets specific performance conditions. This deferred payment is measured at fair value on a quarterly basis using management's expectation of future cash flows. Because the Riley Ridge plant remains 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.

Each of the acquisitions of Riley Ridge meets the definition of a business under the FASC Business Combinations topic.  As such, we estimated the fair value of assets acquired and liabilities assumed using a discounted net cash flow model. Goodwill associated with the acquisitions is deductible for income tax purposes.  The fair values assigned to assets acquired and liabilities assumed in the August 2011 acquisition have been finalized, and no adjustments have been made to fair value amounts previously disclosed in our Form 10-K for the period ended December 31, 2011. The following table presents a summary of the fair value of assets acquired and liabilities assumed in the August 2011 Riley Ridge acquisition:
In thousands
 
 
Consideration:
 
 
Cash payment
 
$
199,779

Deferred payment
 
15,000

Total consideration
 
214,779

 
 
 
Less: Fair value of assets acquired and liabilities assumed:
 
 
Oil and natural gas properties
 
 
Proved
 
48,731

Unproved
 
12,542

CO2 properties
 
9,741

Pipelines and plants
 
91,594

Other assets (1)
 
48,660

Asset retirement obligations
 
(389
)
 
 
210,879

Goodwill
 
$
3,900


(1)
Other assets includes helium extraction rights of $36.7 million.  Helium reserves at Riley Ridge are owned by the U.S. government.  The fair value assigned to helium extraction rights was calculated using the income approach and represents the discounted future net revenues associated with our 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 unit-of-production basis.

2010 Merger with Encore Acquisition Company. On March 9, 2010, we acquired 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.  Under the Encore Merger Agreement, Encore was merged with and into Denbury, with Denbury surviving the Encore Merger.

In the Encore Merger, we issued approximately 135.2 million shares of common stock and paid approximately $833.9 million in cash to Encore stockholders.  The Denbury shares issued to Encore stockholders represented approximately 34% of Denbury’s common stock issued and outstanding immediately after the Encore Merger.  The total fair value of our common stock issued to Encore stockholders in the Encore Merger was approximately $2.1 billion based upon our closing price of $15.43 per share on March 9, 2010. The Encore Merger was financed through a combination of issuing $1.0 billion of 8¼% Senior Subordinated Notes due 2020, which we issued in February 2010, borrowings under a new $1.6 billion revolving credit agreement entered into in March 2010, and the assumption of Encore's remaining outstanding senior subordinated notes.

The Encore Merger met the definition of a business combination under the FASC Business Combinations topic.  As such, we estimated the fair value of Encore as of March 9, 2010, the acquisition date, which was the date on which we obtained control of Encore.  

For the period from March 9, 2010 to December 31, 2010, we recognized $623.4 million of oil, natural gas and related product sales related to properties acquired in the Encore Merger.  For the period from March 9, 2010 to December 31, 2010, we recognized $426.0 million net field operating income (oil, natural gas and related product sales less lease operating expenses and production taxes and marketing expenses) related to properties acquired in the Encore Merger.  Transaction and other costs related to the Encore Merger included in the Consolidated Statement of Operations for the year ended December 31, 2010 include $48.5 million of third-party, legal and accounting fees, which have been expensed as incurred, and $43.8 million of employee-related severance and termination costs, which were accrued over the employees’ service period.  Accrued employee-related severance costs totaled $19.8 million at December 31, 2010, of which $16.5 million was classified as accounts payable and accrued liabilities and $3.3 million was classified as long-term other liabilities on our balance sheet.  Transaction and other costs related to the Encore Merger included in the Consolidated Statement of Operations for the year ended December 31, 2011, include $0.8 million of third-party, legal and accounting fees, which have been expensed as incurred, and $3.6 million of employee-related severance and termination costs.

Unaudited Pro Forma Acquisition Information.  The following combined pro forma total revenues and other income and net income are presented as if the Bakken Exchange Transaction and Thompson Field acquisition had occurred on January 1, 2011:
 
 
Year Ended December 31,
In thousands, except per share data
 
2012
 
2011
Pro forma total revenues and other income
 
$
2,203,703

 
$
2,184,507

Pro forma net income
 
454,549

 
523,227

Pro forma net income per common share
 
 

 
 

Basic
 
$
1.18

 
$
1.32

Diluted
 
1.17

 
1.30


 The following combined pro forma total revenues and other income and net income attributable to Denbury stockholders are presented as if the acquisition of Encore occurred on January 1, 2010:
In thousands, except per share data
 
Year Ended December 31, 2010
Pro forma total revenues and other income
 
$
2,098,241

Pro forma net income attributable to Denbury stockholders
 
286,891

Pro forma net income per common share
 
 
Basic
 
$
0.73

Diluted
 
0.72



Divestitures

2012 Divestitures. In April 2012, we completed the sale of certain non-operated assets in the Paradox Basin of Utah for $75.0 million. The sale had an effective date of January 1, 2012, and proceeds received after consideration of final closing adjustments totaled $68.5 million. Closing adjustments included operating net revenues after January 1, 2012, net of capital and lease operating expenditures, along with other purchase price adjustments. We did not record a gain or loss on the sale in accordance with the full cost method of accounting.

In February 2012, we completed the sale of certain non-core assets primarily located in central and southern Mississippi and in southern Louisiana for $155.0 million to a privately held entity in which a member of our Board of Directors served as chairman of the board, in a sale for which there was a competing bid contained in a multi-property purchase proposal. We realized net proceeds of $141.8 million, after final closing adjustments. The sale had an effective date of December 1, 2011, and consequently, operating revenues of $13.5 million after the effective date, net of capital and lease operating expenditures, along with any other purchase price adjustments, were adjustments to the selling price. We did not record a gain or loss on the sale in accordance with the full cost method of accounting.

Certain of our 2012 divestitures were structured as like-kind-exchange transactions for federal income tax purposes. See Note 6, Income Taxes for further details.

2010 Divestitures.  In December 2010, we sold our ownership interests in ENP, which consisted of our 100% ownership in ENP GP LLC, ENP’s general partner, and 20.9 million ENP common units, to a subsidiary of Vanguard for consideration consisting of $300.0 million cash and 3,137,255 Vanguard common units valued at $93.0 million at the time of closing. In addition, Vanguard assumed all of ENP’s long-term bank debt of $234.0 million.  We did not record a gain or loss on the sale of oil and gas properties in accordance with the full cost method of accounting, nor did we record a gain or loss on the remainder of the net assets sold as the book value approximated fair value.

Pursuant to our plan of divesting non-strategic legacy Encore properties, certain oil and gas properties in the Permian Basin, Mid-continent area and East Texas Basin were sold in May 2010 for consideration of $892.1 million after final closing adjustments.  We subsequently divested our production and acreage in the Cleveland Sand Play of western Oklahoma for consideration of $32.1 million after closing adjustments and the Haynesville and East Texas natural gas properties for consideration of $213.8 million after closing adjustments.  Together with the sale of our ownership interest in ENP and ENP GP LLC discussed above, we received $1.5 billion in total consideration from these divestitures in 2010.  For all Encore legacy property dispositions during 2010, we reduced our full cost pool by the amount of the net proceeds and did not record a gain or loss on the sale in accordance with the full cost method of accounting.

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, after giving effect to the change of control provision of the incentive compensation agreement with Genesis’ management, which was triggered and under which we paid a total of $14.9 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 accounted for our investment in Genesis under the equity method, and we recognized a pre-tax gain of approximately $101.5 million ($63.0 million after tax) on these dispositions.
Asset Retirement Obligations
Asset Retirement Obligations
Note 3. Asset Retirement Obligations

The following table summarizes the changes in our asset retirement obligations for the years ended December 31, 2012 and 2011:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
Beginning asset retirement obligation
 
$
93,468

 
$
85,744

Liabilities incurred and assumed during period
 
50,956

 
12,477

Revisions in estimated retirement obligations
 
5,334

 
12,217

Liabilities settled and sold during period
 
(50,556
)
 
(23,257
)
Accretion expense
 
7,228

 
6,287

Ending asset retirement obligation
 
106,430

 
93,468

Less: current asset retirement obligation (1)
 
(3,700
)
 
(4,742
)
Long-term asset retirement obligation
 
$
102,730

 
$
88,726



(1)
Included in "Accounts payable and accrued liabilities" in our Consolidated Balance Sheets.

Liabilities incurred and assumed generally relate to the drilling of incremental wells and liabilities assumed upon the acquisition of Thompson, Webster and Hartzog Draw fields during 2012. Liabilities settled include the plugging of old wells in the Tinsley Field during 2012 and 2011. Sales of properties in 2012 primarily represent the sale of non-core assets located in the Paradox Basin of Utah, Gulf Coast region and Bakken area assets in North Dakota and Montana.

We have escrow accounts that are legally restricted for certain of our asset retirement obligations.  The balances of these escrow accounts were $35.2 million and $34.1 million at December 31, 2012 and 2011, respectively.  These balances are recorded at amortized cost and are included in “Other assets” in our Consolidated Balance Sheets.  The estimated fair market value of these investments approximate cost at December 31, 2012 and 2011.
Property And Equipment
Property, Plant and Equipment Disclosure [Text Block]
Note 4. Property and Equipment

The following table presents a summary of our net property and equipment balances as of December 31, 2012 and 2011:
 
 
December 31,
In thousands
 
2012
 
2011
Oil and natural gas properties
 
 
 
 
Proved properties
 
$
6,963,211

 
$
7,026,579

Unevaluated properties
 
809,154

 
1,157,106

Total
 
7,772,365

 
8,183,685

Accumulated depletion and depreciation
 
(2,827,256
)
 
(2,407,520
)
Net oil and natural gas properties
 
4,945,109

 
5,776,165

CO2 properties
 
 
 
 
CO2 properties
 
1,032,653

 
596,003

Accumulated depletion and depreciation
 
(119,784
)
 
(91,666
)
Net CO2 properties
 
912,869

 
504,337

Pipelines and plants
 
 
 
 
CO2 pipelines (1)
 
1,632,255

 
1,432,646

Plants under construction (2)
 
402,871

 
269,110

Total
 
2,035,126

 
1,701,756

Accumulated depletion and depreciation
 
(99,185
)
 
(65,392
)
Net plants and pipelines
 
1,935,941

 
1,636,364

Other property and equipment
 
 
 
 
Other property and equipment
 
417,207

 
157,674

Accumulated depletion and depreciation
 
(134,016
)
 
(62,915
)
Net other property and equipment
 
283,191

 
94,759

Net property and equipment
 
$
8,077,110

 
$
8,011,625


(1)
Amounts include $346.5 million of CO2 pipelines at December 31, 2012 that were not subject to depreciation during 2012.
(2)
Plants under construction are not subject to depreciation.

A summary of the unevaluated properties excluded from oil and natural gas properties being amortized at December 31, 2012, and the year in which they were incurred follows:
 
 
December 31, 2012
 
 
Costs Incurred During:
 
 
In thousands
 
2012
 
2011
 
2010
 
2009 and prior
 
Total
Property acquisition costs
 
$
110,658

 
$
12,543

 
$
351,712

 
$
115,075

 
$
589,988

Exploration and development
 
106,075

 
40,152

 
3,155

 
8,390

 
157,772

Capitalized interest
 
29,249

 
30,430

 
333

 
1,382

 
61,394

Total
 
$
245,982

 
$
83,125

 
$
355,200

 
$
124,847

 
$
809,154



Our 2012 property acquisition costs were primarily related to the fair value allocated to our Hartzog Draw and Thompson fields. Our 2010 property acquisition costs were primarily related to the fair value allocated to CO2 tertiary potential at our Bell Creek and Cedar Creek Anticline properties, acquired as part of the Encore Merger.  Property acquisition costs for 2009 and prior were primarily related to CO2 tertiary potential at Conroe Field. Exploration and development costs shown as unevaluated properties are primarily associated with our tertiary oil fields that are under development but did not have proved reserves at December 31, 2012.  The most significant development costs incurred during 2012 and 2011 relate to development in preparation for upcoming CO2 floods at Bell Creek and Grieve fields. We have not yet recognized proved reserves in these fields.

During 2012, we established proved reserves at Hastings and Oyster Bayou fields and, as a result, transferred $431.1 million of costs incurred on these projects into the amortization base. Costs are transferred into the amortization base on an ongoing basis as projects are evaluated and proved reserves established or impairment determined.  We review the excluded properties for impairment at least annually.  We currently estimate that evaluation of most of these properties and the inclusion of their costs in the amortization base is expected to be completed within five years.  Until we are able to determine whether there are any proved reserves attributable to the above costs, we are not able to assess the future impact on the amortization rate of the full cost pool.
Long-Term Debt
Long-Term Debt
Note 5. Long-Term Debt

The following long-term debt and capital lease obligations were outstanding as of December 31, 2012 and 2011:
 
 
December 31,
In thousands
 
2012
 
2011
Bank Credit Agreement
 
$
700,000

 
$
385,000

9½% Senior Subordinated Notes due 2016, including premium of $9,118 and $11,854, respectively
 
234,038

 
236,774

9¾% Senior Subordinated Notes due 2016, including discount of $13,569 and $17,854, respectively
 
412,781

 
408,496

8¼% Senior Subordinated Notes due 2020
 
996,273

 
996,273

6 3/8% Senior Subordinated Notes due 2021
 
400,000

 
400,000

Other Subordinated Notes, including premium of $25 and $33, respectively
 
3,832

 
3,840

Pipeline financings
 
236,244

 
243,274

Capital lease obligations
 
158,260

 
4,388

Total
 
3,141,428

 
2,678,045

Less: current obligations
 
(36,966
)
 
(8,316
)
Long-term debt and capital lease obligations
 
$
3,104,462

 
$
2,669,729



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 of such notes is 100% owned, directly or indirectly, by DRI; any subsidiaries of DRI other than the subsidiary guarantors are minor subsidiaries, and the guarantees of the notes are full and unconditional and joint and several.

February 2013 Issuance of 4 5/8% Senior Subordinated Notes due 2023

On February 5, 2013, we issued $1.2 billion of 4 5/8% Senior Subordinated Notes due 2023 (the “2023 Notes”). The 2023 Notes, which carry a coupon rate of 4.625%, were sold at par. We intend to use the net proceeds of $1.18 billion from the issuance of the 2023 Notes to repurchase or redeem our 9½% Senior Subordinated Notes due 2016 (the “9½% Notes”) and our 9¾% Senior Subordinated Notes due 2016 (the “9¾% Notes”) and to pay down a portion of outstanding borrowings on our Bank Credit Agreement. See Note 13, Subsequent Events, for more information.

$1.6 Billion Revolving Credit Agreement

In March 2010, we entered into a $1.6 billion revolving credit agreement with JPMorgan Chase Bank, N.A. (“JPMorgan”), as administrative agent, and other lenders party thereto (as amended, 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 not to exceed four months.  As part of the semi-annual review completed in September 2012 pursuant to the terms of the Bank Credit Agreement, our borrowing base was reaffirmed at $1.6 billion.  Loans under the Bank Credit Agreement mature in May 2016.

The Bank Credit Agreement is secured by substantially all of the proved oil and natural gas properties of our restricted subsidiaries and by the equity interests of our restricted subsidiaries.  In addition, our obligations under the Bank Credit Agreement are guaranteed jointly and severally by all of our subsidiaries, other than minor subsidiaries.

The Bank Credit Agreement contains several restrictive covenants including, among others:

•
a limitation on the ability to repurchase Denbury common stock and to pay dividends on Denbury common stock, in an aggregate amount not to exceed $1.2 billion during the term of the Bank Credit Agreement, subject to certain restrictions;
•
a requirement to maintain a current ratio, as determined under the Bank Credit Agreement, of not less than 1.0 to 1.0;
•
a maximum permitted ratio of debt to adjusted EBITDA (as defined in the Bank Credit Agreement) of us and our restricted subsidiaries of not more than 4.25 to 1.0; and
•
a prohibition against incurring debt, subject to permitted exceptions.

The Bank Credit Agreement also includes a limitation on the aggregate amount of forecasted oil and natural gas production that can be economically hedged with oil or natural gas derivative contracts. During 2012, we received a limited waiver of any oil hedging noncompliance that may occur as a result of the Bakken Exchange Transaction during the period commencing on the closing date continuing through and including December 31, 2013 (see Note 2, Acquisitions and Divestitures).

Under the Bank Credit Agreement, we are permitted to incur capital lease obligations in an aggregate amount outstanding at any time not to exceed $300 million, and are also permitted to incur up to $40 million of other unsecured debt (which include capital leases). The Bank Credit Agreement was amended during 2012 concurrent with our change in classification of equipment leases from operating to capital (see Capital Leases below), and we received a waiver of any applicable violations of the provisions of the Bank Credit Agreement resulting from such correction and the recording of our equipment leases as debt.

Loans under the Bank Credit Agreement are subject to varying rates of interest based on (1) the total outstanding borrowings in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan.  Eurodollar loans bear interest at the Adjusted Eurodollar Rate (as defined in the Bank Credit Agreement) plus the applicable margin in a range from 1.5% to 2.5% based on the ratio of outstanding borrowings to the borrowing base, and base rate loans bear interest at the Base Rate (as defined in the Bank Credit Agreement) plus the applicable margin in a range from 0.5% to 1.5% based on the ratio of outstanding borrowings to the borrowing base.  The “Eurodollar rate” for any interest period (either one, two, three, six, nine or twelve months, as selected by us) is the rate per year equal to LIBOR, as published by Reuters or another source designated by JPMorgan, for deposits in dollars for a similar interest period.  The “base rate” is calculated as the highest of (1) the annual rate of interest announced by JPMorgan as its “prime rate,” (2) the federal funds effective rate plus 0.5%, and (3) the Adjusted Eurodollar Rate (as defined in the Bank Credit Agreement) for a one-month interest period plus 1.0%.  We incur a commitment fee of either 0.375% or 0.5%, based on the ratio of outstanding borrowings to the borrowing base, on the unused availability under the Bank Credit Agreement.

2011 Redemption of our 2013 and 2015 Notes

Pursuant to cash tender offers, during March 2011, we repurchased $169.6 million in principal of our 7½% Senior Subordinated Notes due 2013 (the “2013 Notes”) at 100.625% of par, and $220.9 million in principal of our 7½% Senior Subordinated Notes due 2015 (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 year ended December 31, 2011 associated with the debt repurchases, which is included in our Consolidated Statements of Operations under the caption “Loss on early extinguishment of debt”.

9½% Senior Subordinated Notes due 2016

As a result of the Encore Merger, we became successor in interest to Encore under the Encore indenture with respect to the 9½% Notes in the original principal amount of $225 million.  Interest on the 9½% Notes is due semi-annually, on May 1 and November 1, at a rate of 9½%.  The 9½% Notes mature on May 1, 2016.  We may redeem the 9½% Notes, in whole or in part at our option beginning May 1, 2013, at the following redemption prices:  104.75% after May 1, 2013; 102.375% after May 1, 2014; and 100% after May 1, 2015.  At any time prior to May 1, 2013, we may redeem 100% of the principal amount of the 9½% Notes at a price equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest.   The indenture governing the 9½% Notes includes various covenants and restrictions, including providing a put right by holders upon a change of control. All of our subsidiaries, other than minor subsidiaries, guarantee this debt jointly and severally. Pursuant to a cash tender offer commenced during January 2013, during February 2013 we repurchased $186.7 million principal amount of our 9½% Notes at 106.87% of par, and the indenture governing the 9½% Notes was amended to eliminate most of its restrictive covenants and certain events of default. We intend to use a portion of the net proceeds from the recent issuance of our 2023 Notes to fund the redemption of the remaining outstanding principal amount of our 9½% Notes. See Note 13, Subsequent Events, for more information.

9¾% Senior Subordinated Notes due 2016

In February 2009, we issued $420.0 million of 9¾% Notes, which carry a coupon rate of 9.75%. The 9¾% Notes were sold at a discount (92.816% of par), which equates to an effective yield to maturity of approximately 11.25%. In June 2009, we issued an additional $6.4 million of 9¾% Notes.

The 9¾% Notes mature on March 1, 2016, and interest on the 9¾% Notes is payable March 1 and September 1 of each year.  The indenture governing the 9¾% Notes 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 9¾% Notes are not subject to any sinking fund requirements. All of our subsidiaries, other than minor subsidiaries, guarantee this debt jointly and severally. Pursuant to a cash tender offer commenced during January 2013, during February 2013 we repurchased $191.7 million principal amount of our 9¾% Notes at 105.425% of par. On February 5, 2013, we called the remaining 9¾% Notes for redemption on March 7, 2013, at 104.875% of par. See Note 13, Subsequent Events, for more information.

8¼% Senior Subordinated Notes due 2020

In February 2010, we issued $1.0 billion of 8¼% Senior Subordinated Notes due 2020 (the “2020 Notes”), for net proceeds after underwriting discounts and commissions of $980 million.  The 2020 Notes, which carry a coupon rate of 8.25%, were sold at par.  We subsequently redeemed $3.7 million principal amount of the 2020 Notes, as required under the indenture governing the 2020 Notes.

The 2020 Notes mature on February 15, 2020, and interest is payable on February 15 and August 15 of each year.  We may redeem the 2020 Notes in whole or in part at our option beginning February 15, 2015, at the following redemption prices: 104.125% after February 15, 2015; 102.75% after February 15, 2016; 101.375% after February 15, 2017; and 100% after February 15, 2018.  Prior to February 15, 2013, we may, at our option, redeem up to an aggregate of 35% of the principal amount of the 2020 Notes at a price of 108.25% with the proceeds of certain equity offerings. At any time prior to February 15, 2015, we may redeem 100% of the principal amount of the 2020 Notes at a price equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest.  The indenture governing the 2020 Notes 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 2020 Notes are not subject to any sinking fund requirements.  All of our subsidiaries, other than minor subsidiaries, guarantee this debt jointly and severally.

6 3/8% Senior Subordinated Notes due 2021

In February 2011, we issued $400 million of 6 3/8% 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 2013 Notes and 2015 Notes (see Redemption of our 2013 and 2015 Notes above).  The 2021 Notes mature on August 15, 2021, and interest is payable on February 15 and August 15 of each year.  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 governing the 2021 Notes 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, guarantee this debt jointly and severally.

Pipeline Financings

In May 2008, we closed two transactions with Genesis involving two of our pipelines.  The NEJD Pipeline system included a 20-year financing lease, and the Free State Pipeline included a long-term transportation service agreement.  We recorded both of these transactions as financing leases.

Debt Issuance Costs

In connection with the issuance of our outstanding long-term debt, we have incurred debt issuance costs, which are being amortized to interest expense using the effective interest method over the term of each related facility.  Remaining unamortized debt issuance costs were $56.5 million and $69.6 million at December 31, 2012 and 2011, respectively.  These balances are included in “Other assets” in our Consolidated Balance Sheets.

Indebtedness Repayment Schedule

At December 31, 2012, our indebtedness, including our capital and financing lease obligations but excluding the discount and premium on our senior subordinated debt, is payable over the next five years and thereafter as follows:
In thousands
 
 
2013
 
$
36,966

2014
 
38,481

2015
 
39,113

2016
 
1,388,592

2017
 
34,965

Thereafter
 
1,607,737

Total indebtedness
 
$
3,145,854

 

Capital Lease Obligations

During the second quarter of 2012, we corrected the accounting for our equipment leases from operating leases to capital leases to comply with the FASC Leases topic, as a result of the consideration of nonperformance-related default covenants included in our equipment lease agreements. We recorded a cumulative adjustment to establish the capital lease assets as “Other property and equipment” ($155.6 million) and the capital lease obligations as “Long-term debt” ($138.9 million) and “Current maturities of long-term debt” ($25.1 million) on the accompanying Consolidated Balance Sheets for the year ended December 31, 2012. We also recognized the cumulative pre-tax impact of $8.4 million ($5.2 million after tax) as “Other expenses” on the accompanying Consolidated Statements of Operations for the year ended December 31, 2012. Because the amounts involved were not material to our financial statements in any individual prior period and the cumulative impact is not material to the results of operations for the year ended December 31, 2012, we recorded the cumulative effect of correcting these items during 2012.
Income Taxes
Income Taxes
Note 6. Income Taxes

Our income tax provision (benefit) is as follows:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Current income tax expense (benefit)
 
 
 
 
 
 
Federal
 
$
57,720

 
$
(12,552
)
 
$
15,683

State
 
18,034

 
20,801

 
17,511

Total current income tax expense
 
75,754

 
8,249

 
33,194

 
 
 
 
 
 
 
Deferred income tax expense
 
 

 
 

 
 

Federal
 
239,862

 
329,715

 
143,381

State
 
15,881

 
12,748

 
16,968

Total deferred income tax expense
 
255,743

 
342,463

 
160,349

Total income tax expense
 
$
331,497

 
$
350,712

 
$
193,543



During 2012, for federal income tax purposes, we structured the divestitures of our Bakken area assets and certain non-core assets as like-kind-exchange transactions for interests acquired in Thompson, Webster, Hartzog Draw and LaBarge fields and assets to be acquired in the Pending CCA Acquisition (See Note 13, Subsequent Events), thereby deferring the majority of the taxable gain on those divestitures. The increase in current taxes during 2012 is primarily due to the taxable gain recognized in the Bakken Exchange Transaction that we were unable to defer through a like-kind-exchange transaction.

At December 31, 2012, we had tax-effected state net operating loss carryforwards (“NOLs”) totaling $35.0 million, an estimated $17.3 million of enhanced oil recovery credits to carry forward related to our tertiary operations, and $34.8 million of alternative minimum tax credits.  Our state NOLs expire in various years, starting in 2015, although most do not begin to expire until 2024. Our enhanced oil recovery credits will begin to expire in 2025.

Deferred income taxes reflect the available tax carryforwards and the temporary differences based on tax laws and statutory rates in effect at the December 31, 2012 and 2011 balance sheet dates.  We believe that we will be able to realize all of our deferred tax assets at December 31, 2012, and therefore, have provided no valuation allowance against our deferred tax assets.

Significant components of our deferred tax assets and liabilities as of December 31, 2012 and 2011 are as follows:
 
 
December 31,
In thousands
 
2012
 
2011
Deferred tax assets:
 
 
 
 
Loss carryforwards – federal
 
$
—

 
$
13,970

Loss carryforwards – state
 
35,007

 
41,960

Tax credit carryover
 
34,837

 
34,829

Derivative contracts
 
7,252

 
3,551

Enhanced oil recovery credit carryforwards
 
17,346

 
53,381

Stock based compensation
 
28,387

 
32,566

Other
 
37,226

 
35,279

Total deferred tax assets
 
160,055

 
215,536

 
 
 
 
 
Deferred tax liabilities:
 
 

 
 

Property and equipment
 
(2,277,388
)
 
(2,078,143
)
Other
 
(6,963
)
 
(5,813
)
Total deferred tax liabilities
 
(2,284,351
)
 
(2,083,956
)
Total net deferred tax liability
 
$
(2,124,296
)
 
$
(1,868,420
)


Our reconciliation of income tax expense computed by applying the U.S. federal statutory rate and the reported effective tax rate on income from continuing operations is as follows:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Income tax provision calculated using the federal statutory income tax rate
 
$
299,900

 
$
323,416

 
$
167,674

State income taxes, net of federal income tax benefit
 
30,955

 
29,555

 
13,087

Effect of statutory rate change
 
(429
)
 
(578
)
 
11,502

Other
 
1,071

 
(1,681
)
 
1,280

Total income tax expense
 
$
331,497

 
$
350,712

 
$
193,543


 
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 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.  Beginning with the 2011 tax year, we returned to capitalizing and depreciating the costs of these assets for tax purposes.  In December 2011, we received notification from the IRS that the review process was completed and that all issues related to the TAM were settled without further adjustments.  As a result of the prospective nature of the IRS’s determination, there was no change in our position with respect to the deductibility of these costs for 2007, 2008, 2009 and 2010.  Refund claims of $10.6 million for tax years through 2006 were received, plus accrued interest, in 2012.

We file consolidated and separate income tax returns in the U.S. federal jurisdiction and in many state jurisdictions.  The IRS concluded its examination of our 2006, 2007 and 2008 tax years during the fourth quarter of 2011 with no adjustments.  During the third quarter of 2012, the IRS concluded its audit of Encore Acquisition Company for the tax years 2008, 2009 and 2010 and Encore Operating LP for the tax years 2008 and 2009, with no significant adjustments. During the fourth quarter of 2012, the state of Mississippi concluded its audit of Denbury for the tax years 2004, 2005, 2006, and 2007, with no significant adjustments.  Our income tax returns for tax years ending 2009 through 2011 currently remain subject to examination by the appropriate taxing authorities. We have not paid any significant interest or penalties associated with our income taxes.
Stockholders' Equity
Stockholders' Equity
Note 7. Stockholders' Equity

Stock Repurchase Program

In October 2011, we commenced a common share repurchase program for up to $500 million of Denbury common shares, as approved by the Company's Board of Directors.  During 2012, the Board of Directors increased the dollar amount of Denbury common shares that can be purchased under the program to an aggregate of $771.2 million. The program has no pre-established ending date and may be suspended or discontinued at any time.  We are not obligated to repurchase any dollar amount or specific number of shares of our common stock under the program.  During 2012, we repurchased 17.0 million shares of Denbury common stock for $266.7 million, or $15.71 per share, and during 2011, we repurchased 14.1 million shares of Denbury common stock for $195.2 million, or $13.83 per share under this share repurchase program. From the time the share repurchase program commenced in October 2011 through December 31, 2012, we have purchased 31.1 million shares of Denbury common stock (approximately 7.7% of our outstanding shares of common stock at September 30, 2011) at a cost of $461.9 million, and at that date, we were authorized to spend an additional $309.3 million under this repurchase program. We account for treasury stock using the cost method and include treasury stock as a component of stockholders’ equity. See Note 13, Subsequent Events, for additional information.

Other share repurchases during 2012 and 2011, and all of our share repurchases during 2010 were from our employees who surrendered shares to the Company to satisfy their minimum tax withholding requirements as provided for under our stock compensation plans and were not part of a formal stock repurchase plan.

Employee Stock Purchase Plan

We have an Employee Stock Purchase Plan that is authorized to issue up to 9,900,000 shares of common stock.  As of December 31, 2012, there were 462,131 authorized shares remaining to be issued under the plan.  In accordance with the plan, eligible employees may contribute up to 10% of their base salary, and we match 75% of their contribution.  The combined funds are used to purchase previously unissued Denbury common stock or treasury stock that we purchased in the open market for that purpose, in either case, based on the market value of our common stock at the end of each quarter.  We recognize compensation expense for the 75% Company match portion, which totaled $5.7 million, $4.8 million and $3.5 million for the years ended December 31, 2012, 2011 and 2010, respectively.  This plan is administered by the Compensation Committee of our Board of Directors.

401(k) Plan

We offer a 401(k) plan to which employees may contribute tax-deferred earnings subject to IRS limitations.  We match 100% of an employee’s contribution, up to 6% of compensation, as defined by the plan, which is vested immediately.  During 2012, 2011 and 2010, our matching contributions to the 401(k) Plan were approximately $8.0 million, $7.1 million and $5.7 million, respectively.
Stock Compensation Plans
Disclosure of Compensation Related Costs, Share-based Payments [Text Block]
Note 8. Stock Compensation Plans

Stock Incentive Plans

We have two stock compensation plans.  The first plan (providing only for the issuance of stock options) has been in existence since 1995 (the “1995 Plan”) and expired in August 2005 (although options granted under the 1995 Plan prior to that time can remain outstanding for up to 10 years).  The second plan, the 2004 Omnibus Stock and Incentive Plan (the “2004 Plan”), has a 10-year term and was approved by the stockholders in May 2004.  The 2004 Plan provides for the issuance of incentive and non-qualified stock options, restricted stock awards, restricted stock units, SARs settled in stock, and performance awards that may be issued to officers, employees, directors and consultants.  Awards covering a total of 29.5 million shares of common stock have been authorized for issuance pursuant to the 2004 Plan.  At December 31, 2012, 11.3 million shares were available under the 2004 Plan for future issuance of awards, all of which could be issued in the form of restricted stock or performance vesting awards.  Our incentive compensation program is administered by the Compensation Committee of our Board of Directors.

Prior to January 1, 2006, we granted incentive and non-qualified stock options to our employees.  Effective January 1, 2006, we completely replaced the use of stock options for employees with SARs settled in stock, as SARs are less dilutive to our stockholders while providing an employee with essentially the same economic benefits as stock options.  The stock options and SARs generally become exercisable over a three- or four-year vesting period, with the specific terms of vesting determined at the time of grant based on guidelines established by the Compensation Committee of the Board of Directors.  The stock options and SARs expire over terms not to exceed 10 years from the date of grant, 90 days after termination of employment, 90 days or one year after permanent disability, depending on the plan, or one year after the death of the optionee.  The stock options and SARs are granted at the fair market value at the time of grant, which is defined in the 2004 Plan as the closing price on the NYSE on the date of grant.

Holders of restricted stock awards have the rights and privileges of owning the shares (including voting rights) except that the holders are not entitled to delivery of a portion thereof until certain requirements are met.  Restricted stock awards vest over three-to-four-year vesting periods, with the specific terms of vesting determined at the time of grant.

Annually, the Board of Directors grants performance-based equity awards to officers of Denbury.  These performance-based awards vest over 1.25 to 3.25 years and the number of performance-based shares earned (and eligible to vest) during the performance period will depend upon two sets of factors: (1) our level of success in achieving four specifically identified performance targets ("Performance-based Operational Awards") and (2) relative performance of our stock to that of a designated peer group ("Performance-based TSR Awards").  Generally, one-half of the maximum number of shares that could be earned under the performance-based awards will be earned for performance at the designated target levels (100% target vesting levels) or upon any earlier change of control, and twice the number of shares will be earned if the higher maximum target levels are met.  If performance is below the designated minimum levels for all performance targets, no performance-based shares will be earned.  Performance-based Operational Awards are valued using the fair market value of Denbury stock on the grant date and Performance-based TSR Awards are valued using a Monte Carlo simulation.

Stock-based compensation expense associated with our field employees is included in “Lease operating expense,” while such expense associated with non-field employees is included in “General and administrative expenses” in the Consolidated Statements of Operations.  Stock-based compensation associated with Encore Merger transition employees is included in “Transaction and other costs related to the Encore Merger” in the Consolidated Statements of Operations.  Stock-based compensation associated with our employees involved in exploration and drilling activities is capitalized as part of “Oil and natural gas properties” in the Consolidated Balance Sheets.

Stock-based compensation costs for the years ended December 31, 2012, 2011 and 2010, are as follows:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Stock-based compensation expensed:
 
 
 
 
 
 
General and administrative expenses
 
$
26,463

 
$
30,256

 
$
28,169

Lease operating expenses
 
2,847

 
2,621

 
2,056

Transaction and other costs related to the Encore Merger
 
—

 
313

 
5,866

Total stock-based compensation expensed
 
29,310

 
33,190

 
36,091

Stock-based compensation capitalized
 
8,587

 
6,998

 
3,702

Total cost of stock-based compensation arrangements
 
$
37,897

 
$
40,188

 
$
39,793

 
 
 
 
 
 
 
Income tax benefit realized for stock-based compensation arrangements
 
$
15,131

 
$
18,383

 
$
8,462



Stock Options and SARs

The fair value of each SARs award is estimated on the date of grant using the Black-Scholes option pricing model with the assumptions noted in the following table.  The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant.  The expected life of stock options and SARs granted was derived from examination of our historical option grants and subsequent exercises.  The contractual terms (cliff vesting and graded vesting) are evaluated separately for the expected life, as the exercise behavior for each is different.  Expected volatilities are based on the historical volatility of our common stock.  Implied volatility was not used in this analysis, as our tradable call option terms are short and the trading volume is low.  Our dividend yield is zero, as we have historically not paid dividends.
 
 
2012
 
2011
 
2010
Weighted average fair value of SARs granted
 
$
8.90

 
$
9.68

 
$
8.45

Risk-free interest rate
 
0.79
%
 
1.74
%
 
2.19
%
Expected life
 
4.0 to 5.0 years

 
4.0 to 5.0 years

 
4.0 to 4.3 years

Expected volatility
 
64.9
%
 
63.3
%
 
65.0
%
Dividend yield
 
—
%
 
—
%
 
—
%
  

The following is a summary of our stock option and SARs activity:
 
 
Number
of Awards
 
Weighted
Average
Exercise Price
 
Weighted Average Remaining Contractual Life
(in years)
 
Aggregate Intrinsic Value
(in thousands)
Outstanding at December 31, 2011
 
11,949,610

 
$
13.56

 
 
 
 
Granted
 
1,066,294

 
17.14

 
 
 
 
Exercised
 
(2,029,570
)
 
8.03

 
 
 
 
Forfeited or expired
 
(541,199
)
 
18.34

 
 
 
 
Outstanding at December 31, 2012
 
10,445,135

 
14.75

 
3.7
 
$
31,861

 
 
 
 
 
 
 
 
 
Exercisable at end of period
 
7,115,744

 
$
13.81

 
3.2
 
$
30,031



The following is a summary of the total intrinsic value of stock options and SARs exercised and grant-date fair value of stock options and SARs vested:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Intrinsic value of stock options exercised
 
$
17,315

 
$
20,463

 
$
12,670

Grant-date fair value of stock options and SARs vested
 
26,391

 
11,416

 
8,689


 
As of December 31, 2012, there was $13.8 million of total compensation cost to be recognized in future periods related to nonvested stock option and SARs share-based compensation arrangements.  The cost is expected to be recognized over a weighted-average period of 2.0 years.  The following is a summary of cash received from stock option exercises under share-based payment arrangements and tax benefits realized from the exercises of stock options and SARs:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Cash received from stock option exercises
 
$
6,022

 
$
4,685

 
$
4,867

Tax benefit realized for the exercises of stock options and SARs
 
241

 
879

 
4,603



Restricted Stock – 2004 Plan

As of December 31, 2012, there was $29.0 million of unrecognized compensation expense related to nonvested restricted stock grants.  This unrecognized compensation cost is expected to be recognized over a weighted-average period of 2.61 years.  The following is a summary of the total vesting date fair value of restricted stock under the 2004 Plan:

 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Fair value of restricted stock vested
 
$
22,332

 
$
12,355

 
$
12,731




A summary of the status of our nonvested restricted stock grants issued under our 2004 Plan and the changes during the year ended December 31, 2012 is presented below:
 
 
Number
of Shares
 
Weighted
Average
Grant-Date
Fair Value
Nonvested at December 31, 2011
 
3,131,435

 
$
14.82

Granted
 
1,909,739

 
16.94

Vested
 
(1,378,496
)
 
15.38

Forfeited
 
(256,471
)
 
17.08

Nonvested at December 31, 2012
 
3,406,207

 
15.60



Restricted Stock – Legacy Encore Plan

In February 2010, prior to the consummation of the Encore Merger, Encore issued a restricted stock grant to its employees under the Encore Acquisition Company 2008 Incentive Stock Plan (“Encore Plan”).  At the time of the Encore Merger, the shares were converted to shares of Denbury restricted stock.  The shares vest ratably over a four-year graded vesting period; however, legacy Encore employees who terminate their employment for Good Reason, as defined by Encore’s legacy Employee Severance Protection Plan, will automatically vest in their awards upon termination.  Encore employees who did not accept permanent positions with Denbury but who continued their employment through a predefined transition period were considered to have terminated for Good Reason and, accordingly, vested in their awards upon termination.  As of December 31, 2012, there was $0.5 million of unrecognized compensation expense related to non-vested restricted stock issued under the Encore Plan, which is expected to be recognized over a weighted-average period of 1.1 years.  The following is a summary of the total vesting date fair value of restricted stock under the Encore Plan:

 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Fair value of restricted stock vested
 
$
584

 
$
2,259

 
$
6,571



A summary of the status of the non-vested restricted stock grants under the Encore Plan and the changes during the year ended December 31, 2012 is presented below:
 
 
Number
of Shares
 
Weighted
Average
Grant-Date
Fair Value
Nonvested at December 31, 2011
 
103,043

 
$
15.43

Vested
 
(36,049
)
 
15.43

Forfeited
 
(10,736
)
 
15.43

Nonvested at December 31, 2012
 
56,258

 
15.43



Performance-Based Equity Awards

During 2012, we granted Performance-based Operational Awards and Performance-based TSR Awards to our officers. The range of assumptions used in the Monte Carlo simulation valuation approach for Performance-based TSR Awards, which were granted for the first time during 2012, are as follows:

 
 
2012
Weighted average fair value of Performance-based TSR Award granted
 
$
24.68

Risk-free interest rate
 
0.42
%
Expected life
 
2.81 years

Expected volatility
 
45.2
%
Dividend yield
 
—
%



A summary of the status of the nonvested performance-based equity awards (presented at the target level) during the year ended December 31, 2012 is as follows:
 
 
Performance-based Operational Awards
 
Performance-based TSR Awards
 
 
Number
of Awards
 
Weighted
Average
Grant-Date Fair Value
 
Number
of Awards
 
Weighted
Average
Grant-Date Fair Value
Nonvested at December 31, 2011
 
214,627

 
$
18.71

 
—

 
$
—

Granted
 
110,615

 
17.27

 
96,325

 
24.68

Vested(1)
 
(214,627
)
 
18.71

 
—

 
—

Forfeited
 
(10,422
)
 
17.27

 
(9,408
)
 
24.68

Nonvested at December 31, 2012
 
100,193

 
17.27

 
86,917

 
$
24.68


(1)
During 2012, the 2011 annual Performance-based Operational Awards vested, and award holders received shares equivalent to 56% of the number of target-level shares.

The following is a summary of the total vesting date fair value of performance-based equity awards:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Vesting date fair value of Performance-based Operational Awards
 
$
2,191

 
$
10,892

 
$
7,532

Derivative Instruments and Hedging Activities
Derivative Instruments and Hedging Activities
Note 9. Derivative Instruments and Hedging Activities

Oil and Natural Gas Derivative Contracts

We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; 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 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 approximately two years in the future from the current quarter, as we believe it is important to protect our future cash flow to provide a level of assurance for our capital spending in those future periods in light of current worldwide economic uncertainties and commodity price volatility. We do not have any natural gas derivative contracts for 2013 or beyond. Because our current and forecasted production is primarily oil, we currently use only oil derivative contracts in our commodity market risk management program.

The following is a summary of “Derivatives expense (income)” included in our Consolidated Statements of Operations:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Oil
 
 
 
 
 
 
Payment on settlements of derivative contracts
 
$
9,991

 
$
25,128

 
$
93,417

Fair value adjustments to derivative contracts – income
 
(10,904
)
 
(58,980
)
 
(44,441
)
Total derivatives expense (income) – oil
 
(913
)
 
(33,852
)
 
48,976

Natural gas
 
 

 
 

 
 

Receipt on settlements of derivative contracts
 
(27,871
)
 
(27,505
)
 
(61,805
)
Fair value adjustments to derivative contracts – expense (income)
 
23,950

 
8,860

 
(8,585
)
Total derivatives expense (income) – natural gas
 
(3,921
)
 
(18,645
)
 
(70,390
)
Ineffectiveness on interest rate swaps
 
—

 
—

 
(2,419
)
Derivatives expense (income)
 
$
(4,834
)
 
$
(52,497
)
 
$
(23,833
)


Commodity Derivative Contracts Not Classified as Hedging Instruments
 
 
 
 
 
 
 
 
 
Contract Prices per Barrel
 
 
 
 
Type of
 
Volume
 
 
 
 
Weighted Average Price
Year
 
Months
 
Contract
 
(Barrels per day)
 
 
Range
 
Floor
 
Ceiling
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil Contracts:
 
 
 
 
 
 
 
 
 
2013
 
Jan – Mar
 
Collar
 
55,000
 
$
70.00 – 113.00
 
$
78.91

 
$
108.01

 
 
Apr – June
 
Collar
 
56,000
 
 
75.00 – 121.50
 
79.64

 
108.61

 
 
July – Sept
 
Collar
 
56,000
 
 
75.00 – 133.10
 
79.64

 
109.15

 
 
Oct – Dec
 
Collar
 
54,000
 
 
80.00 – 127.50
 
80.00

 
117.53

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2014
 
Jan – Mar
 
Collar
 
52,000
 
$
80.00 – 104.50
 
$
80.00

 
$
102.44

 
 
Apr – June
 
Collar
 
52,000
 
 
80.00 – 104.50
 
80.00

 
102.44

 
 
July – Sept
 
Collar
 
48,000
 
 
80.00 – 98.80
 
80.00

 
97.46

 
 
Oct – Dec
 
Collar
 
48,000
 
 
80.00 – 98.80
 
80.00

 
97.46


Additional Disclosures about Derivative Instruments:

At December 31, 2012 and 2011, we had derivative financial instruments recorded in our Consolidated Balance Sheets as follows:
 
 
 
 
Estimated Fair Value
Asset (Liability)
December 31,
Type of Contract
 
Balance Sheet Location
 
2012
 
2011
 
 
 
 
In thousands
Derivatives not designated as hedging instruments:
 
 
 
 
Derivative Assets
 
 
 
 
 
 
Crude oil contracts
 
Derivative assets – current
 
$
19,477

 
$
23,452

Natural gas contracts
 
Derivative assets – current
 
—

 
23,950

Crude oil contracts
 
Derivative assets – long-term
 
36

 
29

Derivative Liabilities
 
 
 
 
 
 
Crude oil contracts
 
Derivative liabilities – current
 
(2,659
)
 
(22,610
)
Deferred premiums (1)
 
Derivative liabilities – current
 
(183
)
 
(3,913
)
Crude oil contracts
 
Derivative liabilities – long-term
 
(23,781
)
 
(18,702
)
Deferred premiums (1)
 
Derivative liabilities – long-term
 
—

 
(170
)
Total derivatives not designated as hedging instruments
 
$
(7,110
)
 
$
2,036


(1)
Deferred premiums payable relate to various oil floor contracts and are payable on a monthly basis through January 2013.
Fair Value Measurements
Fair Value Measurements
Note 10. Fair Value Measurements

The FASC Fair Value Measurements and Disclosures topic defines fair value as the price that would be received to sell an asset or would be 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.  Instruments in this category include non-exchange-traded oil and natural gas derivatives that are based on NYMEX pricing.  Our costless collars are valued using the Black-Scholes model, an industry standard option valuation model, that takes into account inputs such as contractual prices for the underlying instruments, including maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, 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.

•
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.  At December 31, 2011, instruments in this category also included non-exchange-traded natural gas derivatives swaps that were based on regional pricing other than NYMEX (i.e., Houston Ship Channel).  Our basis swaps were estimated using discounted cash flow calculations based upon forward commodity price curves.

We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and our 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 December 31, 2012 and 2011:
 
 
Fair Value Measurements Using:
 
 
Quoted Prices
in Active
Markets
 
Significant
Other
Observable
Inputs
 
Significant
Unobservable
Inputs
 
 
In thousands
 
(Level 1)
 
(Level 2)
 
(Level 3)
 
Total
December 31, 2012
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Oil derivative contracts
 
$
—

 
$
19,513

 
$
—

 
$
19,513

Liabilities:
 
 

 
 

 
 

 
 

Oil derivative contracts
 
—

 
(26,440
)
 
—

 
(26,440
)
Total
 
$
—

 
$
(6,927
)
 
$
—

 
$
(6,927
)
 
 
 
 
 
 
 
 
 
December 31, 2011
 
 

 
 

 
 

 
 

Assets:
 
 

 
 

 
 

 
 

Short-term investments
 
$
86,682

 
$
—

 
$
—

 
$
86,682

Oil and natural gas derivative contracts
 
—

 
23,481

 
23,950

 
47,431

Liabilities:
 
 

 
 

 
 

 
 

Oil and natural gas derivative contracts
 
—

 
(41,312
)
 
—

 
(41,312
)
Total
 
$
86,682

 
$
(17,831
)
 
$
23,950

 
$
92,801



The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the years ended December 31, 2012 and 2011:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
Fair value of Level 3 instruments, beginning of year
 
$
23,950

 
$
16,478

Unrealized gains on commodity derivative contracts included in earnings
 
3,921

 
13,384

Receipts on settlement of commodity derivative contracts
 
(27,871
)
 
(5,912
)
Fair value of Level 3 instruments, end of year
 
$
—

10

$
23,950

 
 
 
 
 
The amount of total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held at the reporting date
 
$
—

 
$
13,384



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 Consolidated Statements of Operations. Management's estimate of the fair market value of contingent consideration has not changed from the acquisition date to December 31, 2012; therefore, there has been no impact on the Consolidated Statements of Operations for the years ended December 31, 2012 and 2011.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

During 2012, we recorded a $15.1 million impairment charge for an investment in the preferred stock of an entity that was created to develop a gasification plant (in which we would offtake its CO2 to use in our tertiary oil operations) as a result of this project not moving forward. This charge is classified as “Impairment of assets” in the Consolidated Statement of Operations for the year ended December 31, 2012.

Other Fair Value Measurements

The carrying value of our revolving bank credit facility approximates fair value, as it is subject to short-term floating interest rates that approximate the rates available to us for those periods.  We use a market approach to determine fair value of our fixed-rate debt using observable market data. The fair values of our senior subordinated notes are based on quoted market prices.  The estimated fair value of our total long-term debt as of December 31, 2012 and 2011, excluding pipeline financing and capital lease obligations, is $2,956.9 million and $2,638.2 million, respectively.  We have other financial instruments consisting primarily of cash, cash equivalents, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.
Commitments And Contingencies
Commitments and Contingencies
Note 11. Commitments and Contingencies

Leases

We lease office space, equipment and vehicles that have non-cancelable lease terms.  Leases entered into during 2012 have terms up to thirteen years.  Lease payments associated with operating leases were $33.6 million, $52.3 million and $42.4 million in 2012, 2011 and 2010, respectively.  We have subleased part of the office space included in our operating leases for which we received approximately $2.7 million, $2.4 million and $0.5 million in 2012, 2011 and 2010, respectively.  In addition, we expect to receive approximately $3.6 million for 2013 through 2016 under these sublease agreements.

The following table summarizes by year the remaining non-cancelable future payments under these leases as of December 31, 2012:
In thousands
 
Pipeline
Financing
Leases
 
Capital
Leases
 
Operating
Leases
2013
 
$
30,817

 
$
35,429

 
$
10,656

2014
 
31,992

 
31,629

 
11,452

2015
 
32,591

 
30,139

 
12,300

2016
 
31,233

 
28,038

 
12,384

2017
 
30,678

 
22,052

 
12,720

Thereafter
 
296,226

 
31,806

 
80,562

Total minimum lease payments
 
453,537

 
179,093

 
$
140,074

Less: Amount representing interest
 
(217,293
)
 
(20,833
)
 
 

Present value of minimum lease payments
 
$
236,244

 
$
158,260

 
 



Commitments

We have entered into long-term commitments to purchase CO2 that are either non-cancelable or cancelable only upon the occurrence of specified future events.   The commitments continue for up to 20 years.  The price we will pay for CO2 varies depending on the amount of CO2 delivered and the price of oil.  We anticipate the contracts will provide us with approximately 335 MMcf/d to 675 MMcf/d of CO2 at a cost of approximately $95 million to $190 million per year, assuming a $100 per Bbl NYMEX oil price.

We are party to long-term contracts that require us to deliver CO2 to our industrial CO2 customers at various contracted prices, plus we have a CO2 delivery obligation to Genesis related to three CO2 volumetric production payments (“VPPs”). Based upon the maximum amounts deliverable as stated in the industrial contracts and the VPPs, we estimate that we may be obligated to deliver up to 327 Bcf of CO2 to these customers over the next 14 years. The maximum volume required in any given year is approximately 109 MMcf/d.  Given the size of our Jackson Dome proven CO2 reserves at December 31, 2012, our current production capabilities and our projected levels of CO2 usage for our own tertiary flooding program, we believe that we can meet these contractual delivery obligations.

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.  After the commencement date, the contract provides for the delivery of a minimum contracted quantity of helium, subject to adjustment after start-up of the Riley Ridge Plant, which if not supplied in accordance with the terms of the contract, may obligate us to compensate the third-party helium purchaser for the amount of the shortfall in an amount not to exceed $8.0 million per year.
 
Litigation

We are involved in various lawsuits, claims and 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 or overall trends in 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.

Other Contingencies

We are subject to audits in the various states in which we operate for sales and use taxes and severance taxes, and from time to time receive assessments for potential taxes that we may owe.  In the past, settlement of these matters has not had a material adverse financial impact on us, and currently we have no material assessments for potential taxes.

We are subject to various possible contingencies that arise primarily from interpretation of federal and state laws and regulations affecting the oil and natural gas industry.  Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters.  Although we believe that we have complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued.  In addition, production rates, marketing and environmental matters are subject to regulation by various federal and state agencies.

Supplemental Information
Supplemental Information
Note 12. Supplemental Information

Significant Oil and Natural Gas Purchasers

Oil and natural gas sales are made on a day-to-day basis or under short-term contracts at the current area market price.  We do not expect that the loss of any purchaser would have a material adverse effect upon our operations.  For the years ended December 31, 2012, 2011 and 2010, two purchasers accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company LLC (39%, 43% and 46% in 2012, 2011 and 2010, respectively) and Plains Marketing LP (17%, 16% and 14% in 2012, 2011 and 2010, respectively).

Allowance for Doubtful Accounts

We record an allowance for doubtful accounts for receivables that we determine to be uncollectible based on the specific identification basis. The allowance for doubtful accounts, which is netted against “Trade and other receivables” on the Consolidated Balance Sheets, was $0.3 million at December 31, 2012 and 2011.

Accounts Payable and Accrued Liabilities
 
 
December 31,
In thousands
 
2012
 
2011
Accrued exploration and development costs
 
$
109,939

 
$
141,868

Accounts payable
 
86,051

 
99,444

Accrued interest
 
60,698

 
60,923

Accrued compensation
 
48,451

 
35,861

Accrued lease operating expenses
 
23,862

 
24,185

Taxes payable
 
27,523

 
13,455

Other
 
58,144

 
53,600

Total
 
$
414,668

 
$
429,336



Supplemental Cash Flow Information
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Supplemental cash flow information:
 
 
 
 
 
 
Cash paid for interest, expensed
 
$
137,950

 
$
137,259

 
$
151,831

Cash paid for interest, capitalized
 
77,432

 
60,540

 
66,815

Cash paid for income taxes
 
99,194

 
45,912

 
17,960

Cash received from income tax refunds
 
(38,004
)
 
(24,677
)
 
(15,107
)
Non-cash investing activities:
 
 
 
 

 
 

Increase in asset retirement obligations
 
56,290

 
24,694

 
53,579

Increase (decrease) in liabilities for capital expenditures
 
(26,882
)
 
74,697

 
(237
)
Sale of non-core assets (1)
 
(212,544
)
 
—

 
—

Purchase of Thompson Field (1)
 
212,544

 
—

 
—

Sale of Bakken area assets in Bakken Exchange Transaction (2)
 
(1,621,611
)
 
—

 
—

Purchase of properties in Bakken Exchange Transaction (2)
 
571,596

 
—

 
—

Issuance of Denbury common stock in connection with the Encore Merger
 
—

 
—

 
2,085,681

Vanguard common units received as consideration for sale of ENP
 
—

 
—

 
93,020


(1)
During 2012, $212.5 million of proceeds from the sale of certain non-core assets were paid by the purchaser directly to a qualified intermediary to facilitate a like-kind-exchange transaction for federal income tax purposes. The qualified intermediary subsequently released the funds to the previous owner of the Thompson Field to fund our acquisition of Thompson Field.

(2)
During 2012, we sold our Bakken area assets with a fair value as determined in accordance with FASC rules of $1.9 billion to ExxonMobil in exchange for a combination of cash and various property interests valued in accordance with FASC rules at $571.6 million. ExxonMobil paid a portion of the cash proceeds ($1.05 billion) directly to a qualified intermediary to facilitate a like-kind-exchange transaction under federal income tax rules under which we expect our Pending CCA Acquisition to qualify (see Note 13, Subsequent Events). The remaining $281.7 million in cash proceeds are reported as an investing activity on our Statement of Cash Flows for the year ending December 31, 2012.
Subsequent Events
Subsequent Events
Note 13. Subsequent Events

Pending CCA Acquisition

In January 2013, we entered into an agreement to acquire producing assets in the Cedar Creek Anticline (“CCA”) of Montana and North Dakota from a wholly-owned subsidiary of ConocoPhillips for $1.05 billion in cash, before standard closing adjustments primarily for revenues and costs of the properties to be purchased from the January 1, 2013 effective date to the closing date. We plan to fund the acquisition out of a portion of the cash proceeds from the Bakken Exchange Transaction in order to qualify the acquisition for like-kind-exchange treatment under federal income tax rules. We expect the acquisition to close near the end of the first quarter of 2013.

New Senior Subordinated Notes

On February 5, 2013, we issued the 2023 Notes, which carry a coupon rate of 4.625%, and were sold at par. The net proceeds of $1.18 billion have been used to repurchase a portion of, or are intended to be used to redeem the remainder of, our outstanding 9½% Notes and 9¾% Notes and to reduce borrowings under our credit facility.

The 2023 Notes mature on July 15, 2023, and interest is payable on January 15 and July 15 of each year, commencing July 15, 2013. We may redeem the 2023 Notes in whole or in part at our option beginning January 15, 2018, at the following redemption prices: 102.313% on or after January 15, 2018; 101.542% on or after January 15, 2019; 100.771% on or after January 15, 2020; and 100% on or after January 15, 2021. Prior to July 15, 2016, we may at our option redeem up to an aggregate of 35% of the principal amount of the 2023 Notes at a price of 104.625% with the proceeds of certain equity offerings. In addition, at any time prior to July 15, 2018, we may redeem 100% of the principal amount of the 2023 Notes at a price equal to 100% of the principal amounts plus a “make whole” premium and accrued and unpaid interest. The indenture contains certain restrictions on our ability to: (1) incur additional debt; (2) pay dividends on our common stock or redeem, repurchase or retire such capital stock or subordinated debt unless certain leverage ratios are met; (3) make investments; (4) create liens on our assets; (5) create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to the Company; (6) engage in transactions with our affiliates; (7) transfer or sell assets; and (8) consolidate, merge or transfer all or substantially all of our assets and the assets of our subsidiaries. All of our significant subsidiaries fully and unconditionally guaranteed this debt.

Tender Offers

On January 22, 2013, we commenced cash tender offers to purchase $426.4 million principal amount of our 9¾% Notes and $224.9 million principal amount of our 9½% Notes. During February 2013, we accepted for purchase $191.7 million principal amount of the outstanding 9¾% Notes and $186.7 million principal amount of the outstanding 9½% Notes. We received sufficient consents in the solicitation to amend the indenture governing the 9½% Notes by entering into a supplemental indenture, which eliminated most of the restrictive covenants and certain events of default. The purchases under these tender offers were funded by the proceeds from the sale of our 2023 Notes. The tender offers expired on February 19, 2013. On February 5, 2013, we issued a notice of redemption for all remaining outstanding 9¾% Notes at 104.875% of par with a redemption date of March 7, 2013 and intend to call the 9½% Notes for redemption on or about May 1, 2013.

Stock Repurchase Program

Between January 1, 2013 and February 21, 2013, the Company repurchased an additional 3.5 million shares of Denbury common stock under the share repurchase program for $59.1 million, or $16.73 per share. From the time the share repurchase program commenced in October 2011 through February 21, 2013, we have repurchased a total of $521.0 million of common stock under the program, and are authorized to spend an additional $250.2 million under this repurchase program. See Note 7, Stockholders' Equity, for additional information.

Equity Award Grant

In January 2013, we granted equity incentive awards to our employees under the 2004 Plan.  The grant included 1,545,077 shares of restricted stock valued at $16.77 per share (the closing price of Denbury’s common stock on January 4, 2013) and 605,802 SARs with an exercise price of $16.77 and a weighted average grant date fair value ranging between $5.42 and $8.72 per unit. The awards generally vest 33% per year over a three-year period.
Supplemental Oil And Natural Gas Disclosures (Unaudited)
Supplemental Oil and Natural Gas Disclosures
Note 14. Supplemental Oil and Natural Gas Disclosures (Unaudited)

Costs Incurred

The following table summarizes costs incurred and capitalized in oil and natural gas property acquisition, exploration and development activities.  Property acquisition costs are those costs incurred to purchase, lease or otherwise acquire property, including both undeveloped leasehold and the purchase of reserves in place.  Exploration costs include costs of identifying areas that may warrant examination and examining specific areas that are considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs, and carrying costs on undeveloped properties.  Development costs are incurred to obtain access to proved reserve costs, including the cost of drilling development wells, and to provide facilities for extracting, treating, gathering and storing the oil and natural gas, and the cost of improved recovery systems.

We capitalize interest on unevaluated oil and natural gas properties that have ongoing development activities.  Included in costs incurred in the table below is capitalized interest of $36.5 million in 2012, $44.9 million in 2011 and $32.6 million in 2010.  Costs incurred also include new asset retirement obligations established, as well as changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates.  Asset retirement obligations included in the table below were $38.8 million in 2012, $24.2 million in 2011 and $45.1 million in 2010.  See Note 3, Asset Retirement Obligations, for additional information.

Costs incurred in oil and natural gas activities were as follows:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Property acquisitions:
 
 
 
 
 
 
Proved
 
$
491,041

 
$
86,465

 
$
3,373,450

Unevaluated
 
115,270

 
17,858

 
1,297,695

Exploration
 
12,019

 
31,483

 
8,728

Development
 
1,111,314

 
1,144,243

 
658,758

Total costs incurred (1)
 
$
1,729,644

 
$
1,280,049

 
$
5,338,631


(1)
Capitalized general and administrative costs that directly relate to exploration and development activities were $49.2 million, $35.0 million and $20.1 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Oil and Natural Gas Operating Results

Results of operations from oil and natural gas producing activities, excluding corporate overhead and interest costs, were as follows:
 
 
Year Ended December 31,
In thousands, except per BOE data
 
2012
 
2011
 
2010
Oil, natural gas, and related product sales
 
$
2,409,867

 
$
2,269,151

 
$
1,793,292

Lease operating costs
 
532,359

 
507,397

 
470,364

Marketing expenses
 
52,836

 
26,047

 
31,036

Taxes other than income
 
149,919

 
138,419

 
114,569

Depletion, depreciation and amortization
 
448,424

 
369,075

 
391,782

CO2 properties and pipelines depletion and depreciation (1)
 
42,064

 
24,460

 
29,206

Commodity derivatives expense (income)
 
(4,834
)
 
(52,497
)
 
(21,414
)
Net operating income
 
1,189,099

 
1,256,250

 
777,749

Income tax provision
 
457,803

 
477,375

 
295,545

Results of operations from oil and natural gas producing activities
 
$
731,296

 
$
778,875

 
$
482,204

 
 
 
 
 
 
 
Depletion, depreciation and amortization per BOE
 
$
18.69

 
$
16.42

 
$
15.82


(1)
Represents an allocation of the depletion, depreciation and amortization of our CO2 properties and pipelines associated with our tertiary oil producing activities.

Oil and Natural Gas Reserves

Net proved oil and natural gas reserve estimates for all years presented were prepared by DeGolyer and MacNaughton, independent petroleum engineers located in Dallas, Texas.  These oil and natural gas reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage.  The reserve estimates represent our net revenue interest in our properties.  See Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves below for a discussion of the effect of the different prices on reserve quantities and values.  Operating costs, production and ad valorem taxes, and future development costs were based on current costs.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures.  The following reserve data represents estimates only and should not be construed as being exact.  Moreover, the present values should not be construed as the current market value of our oil and natural gas reserves or the costs that would be incurred to obtain equivalent reserves.  Estimates of reserves as of year-end 2012, 2011 and 2010 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the applicable fiscal 12-month period.  All of our reserves are located in the United States.

Estimated Quantities of Proved Reserves
 
 
Year Ended December 31,
 
 
2012
 
2011
 
2010
 
 
Oil
(MBbl)
 
Gas
(MMcf)
 
Total
(MBOE)
 
Oil
(MBbl)
 
Gas
(MMcf)
 
Total
(MBOE)
 
Oil
(MBbl)
 
Gas
(MMcf)
 
Total
(MBOE)
Balance at beginning of year
 
357,733

 
625,208

 
461,934

 
338,276

 
357,893

 
397,925

 
192,879

 
87,975

 
207,542

Revisions of previous estimates
 
(7,099
)
 
(16,720
)
 
(9,886
)
 
(4,478
)
 
(14,058
)
 
(6,821
)
 
3,538

 
16,171

 
6,233

Revisions due to price changes
 
(401
)
 
(37,969
)
 
(6,729
)
 
2,558

 
485

 
2,639

 
2,780

 
811

 
2,915

Extensions and discoveries
 
14,910

 
10,005

 
16,579

 
42,936

 
52,339

 
51,658

 
26,313

 
130,245

 
48,021

Improved recovery (1)
 
69,543

 
—

 
69,543

 
264

 
—

 
264

 
30,173

 
—

 
30,173

Production

 
(24,462
)
 
(10,654
)
 
(26,238
)
 
(22,169
)
 
(10,783
)
 
(23,966
)
 
(21,870
)
 
(28,491
)
 
(26,619
)
Acquisition of minerals in place
 
24,677

 
20,598

 
28,110

 
346

 
239,332

 
40,235

 
155,021

 
622,984

 
258,852

Sales of minerals in place
 
(105,777
)
 
(108,827
)
 
(123,915
)
 
—

 
—

 
—

 
(50,558
)
 
(471,802
)
 
(129,192
)
Balance at end of year
 
329,124

 
481,641

 
409,398

 
357,733

 
625,208

 
461,934

 
338,276

 
357,893

 
397,925

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved Developed Reserves:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance at beginning of year
 
239,741

 
125,970

 
260,736

 
219,077

 
110,516

 
237,496

 
116,192

 
69,513

 
127,778

Balance at end of year
 
236,009

 
64,191

 
246,708

 
239,741

 
125,970

 
260,736

 
219,077

 
110,516

 
237,496


(1)
Improved recovery reflects reserve additions which result from the application of secondary recovery methods such as water flooding, or tertiary recovery methods such as CO2 flooding.  In order to recognize proved tertiary oil reserves, we must either have an oil production response to CO2 injections or the field must be analogous to an existing tertiary flood. The magnitude of proved reserves that we can book in any given year will depend on our progress with new floods and the timing of the production response.

We added 114.2 MMBOE of estimated proved reserves during 2012, including tertiary reserves of 69.5 MMBbls, primarily at Hastings and Oyster Bayou fields, 25.9 MMBOE from the acquisition of interests in the Thompson, Webster and Hartzog Draw fields and 11.5 MMBOE from our Bakken area assets prior to their sale in the fourth quarter of 2012. These increases were offset by the disposition of 123.9 MMBOE of reserves associated with disposed properties, including our Bakken area assets, and non-core assets in the Gulf Coast region and Paradox Basin in Utah.

Acquisitions of minerals in place during 2011 were primarily related to the acquisition of the remaining interest in Riley Ridge.  Extensions and discoveries primarily include proved undeveloped reserves and were added primarily through additional drilling in the Bakken.

Acquisitions of minerals in place during 2010 were primarily from the Encore Merger and the initial acquisition of interests at Riley Ridge.  The sales of minerals in place during 2010 were primarily due to the sale of the non-strategic Encore properties and our ownership interests in ENP.  Extensions and discoveries primarily include reserves added at our Bakken and Haynesville fields.  We added 39.4 MMBbls of tertiary proved oil reserves during 2010, primarily initial proved tertiary oil reserves at Delhi Field, plus upward revisions to reserves in other tertiary floods.

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves

The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves (“Standardized Measure”) does not purport to present the fair market value of our oil and natural gas properties.  An estimate of such value should consider, among other factors, anticipated future prices of oil and natural gas, the probability of recoveries in excess of existing proved reserves, the value of probable reserves and acreage prospects, and perhaps different discount rates.  It should be noted that estimates of reserve quantities, especially from new discoveries, are inherently imprecise and subject to substantial revision.

Under the Standardized Measure, future cash inflows were estimated by applying a first-day-of-the-month 12-month average price to the estimated future production of year-end proved reserves.  The product prices used in calculating these reserves have varied widely during the three-year period.  These prices have a significant impact on both the quantities and value of the proved reserves, as reductions in oil and natural gas prices can cause wells to reach the end of their economic life much sooner and can make certain proved undeveloped locations uneconomical, both of which reduce the reserves.  The following representative oil and natural gas prices were used in the Standardized Measure.  These prices were adjusted by field to arrive at the appropriate corporate net price.
 
 
December 31,
 
 
2012
 
2011
 
2010
Oil (NYMEX)
 
$
94.71

 
$
96.19

 
$
79.43

Natural Gas (Henry Hub)
 
2.85

 
4.16

 
4.40



Future cash inflows were reduced by estimated future production, development and abandonment costs based on current cost, with no escalation to determine pre-tax cash inflows.  Our future net inflows do not include a reduction for cash previously expended on our capitalized CO2 assets that will be consumed in the production of proved tertiary reserves.  Future income taxes were computed by applying the statutory tax rate to the excess of net cash inflows over our tax basis in the associated proved oil and natural gas properties.  Tax credits and net operating loss carryforwards were also considered in the future income tax calculation.  Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure.
 
 
December 31,
In thousands
 
2012
 
2011
 
2010
Future cash inflows
 
$
34,779,549

 
$
38,165,122

 
$
26,698,819

Future production costs
 
(13,114,740
)
 
(12,570,015
)
 
(9,702,896
)
Future development costs
 
(2,034,174
)
 
(3,026,898
)
 
(1,912,457
)
Future income taxes
 
(6,672,857
)
 
(7,379,972
)
 
(4,700,023
)
Future net cash flows
 
12,957,778

 
15,188,237

 
10,383,443

10% annual discount for estimated timing of cash flows
 
(6,543,398
)
 
(8,180,632
)
 
(5,465,516
)
Standardized measure of discounted future net cash flows
 
$
6,414,380

 
$
7,007,605

 
$
4,917,927


 
The following table sets forth an analysis of changes in the Standardized Measure of Discounted Future Net Cash Flows from proved oil and natural gas reserves:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Beginning of year
 
$
7,007,605

 
$
4,917,927

 
$
2,457,385

Sales of oil and natural gas produced, net of production costs
 
(1,673,253
)
 
(1,597,288
)
 
(1,177,322
)
Net changes in sales prices
 
(584,526
)
 
4,646,086

 
2,062,181

Extensions and discoveries, less applicable future development and production costs
 
291,558

 
762,370

 
295,074

Improved recovery (1)
 
1,901,109

 
15,708

 
623,622

Previously estimated development costs incurred
 
376,199

 
354,228

 
193,947

Revisions of previous estimates, including revised estimates of development costs, reserves and rates of production
 
(797,975
)
 
(1,673,283
)
 
(285,158
)
Accretion of discount
 
875,383

 
729,234

 
307,546

Acquisition of minerals in place
 
767,267

 
29,737

 
3,671,439

Sales of minerals in place
 
(1,805,309
)
 
—

 
(1,474,443
)
Net change in income taxes
 
56,322

 
(1,177,114
)
 
(1,756,344
)
End of year
 
$
6,414,380

 
$
7,007,605

 
$
4,917,927


(1)
Improved recovery additions result from the application of secondary recovery methods such as water flooding or tertiary recovery methods such as CO2 flooding.
Supplemental CO2 and Helium Disclosures Supplemental Helium Disclosures (Unauditied) (Notes)
Co2 And Helium Quantity Of Reserves Disclosures [Text Block]
Note 15. Supplemental CO2 and Helium Disclosures (Unaudited)

Based on engineering reports prepared by DeGolyer and MacNaughton, proved CO2 reserves, and helium reserves associated with our helium production rights, were estimated as follows (in MMcf):
 
 
Year Ended December 31,
 
 
2012
 
2011
 
2010
CO2 Reserves
 
 
 
 
 
 
Gulf Coast region (1)
 
6,073,175

 
6,685,412

 
7,085,131

Rocky Mountain region (2)
 
3,495,534

 
2,195,534

 
2,189,756

 
 
 
 
 
 
 
Helium Reserves Associated with Denbury's Production Rights
 
 
 
 
 
 
Rocky Mountain region (3)
 
12,712

 
12,004

 
7,159


(1)
Proved CO2 reserves in the Gulf Coast region consist of reserves from our reservoirs at Jackson Dome and are presented on a gross working interest (8/8ths) basis, of which our net revenue interest was approximately 4.8 Tcf, 5.3 Tcf and 5.6 Tcf at December 31, 2012, 2011 and 2010, respectively, and include reserves dedicated to volumetric production payments of 57.1 Bcf, 84.7 Bcf and 100.2 Bcf at December 31, 2012, 2011 and 2010, respectively.

(2)
Proved CO2 reserves in the Rocky Mountain region consist of our reserves at Riley Ridge (presented on a gross working interest (8/8ths) basis) and our overriding royalty interest in LaBarge Field, of which our net revenue interest was approximately 2.9 Tcf, 1.6 Tcf and 0.9 Tcf at December 31, 2012, 2011 and 2010, respectively.

(3)
Reserves associated with helium production rights include helium reserves located in acreage in the Rocky Mountain region for which we have the right to extract the helium.  The U.S. government retains title to the helium reserves and we retain the right to extract and sell the helium on behalf of the government in exchange for a fee.  The helium reserves are presented net of the fee we will remit to the U.S. government.
Unaudited Quarterly Information
Unaudited Quarterly Information
Note 16. Unaudited Quarterly Information

In thousands, except per share amounts
 
March 31
 
June 30
 
September 30
 
December 31
2012
 
 
 
 
 
 
 
 
Revenues and other income
 
$
645,116

 
$
601,781

 
$
600,371

 
$
609,204

Derivatives expense (income)
 
45,275

 
(139,109
)
 
61,631

 
27,369

Other expenses
 
420,529

 
398,089

 
399,361

 
386,470

Net income
 
113,467

 
211,865

 
85,367

 
114,661

Net income per share:
 
 

 
 

 
 

 
 

Basic
 
0.29

 
0.55

 
0.22

 
0.30

Diluted
 
0.29

 
0.54

 
0.22

 
0.30

Cash flow provided by operating activities
 
291,654

 
440,966

 
293,506

 
384,765

Cash flow used for investing activities
 
(288,883
)
 
(560,341
)
 
(388,748
)
 
(138,869
)
Cash flow provided by (used for) financing activities
 
55,902

 
70,122

 
91,163

 
(118,676
)
 
 
 
 
 
 
 
 
 
2011
 
 

 
 

 
 

 
 

Revenues and other income
 
$
514,165

 
$
601,397

 
$
576,505

 
$
617,257

Derivatives expense (income)
 
170,750

 
(172,904
)
 
(210,154
)
 
159,811

Other expenses
 
366,361

 
350,499

 
343,339

 
377,577

Net income (loss)
 
(14,190
)
 
259,246

 
275,670

 
52,607

Net income (loss) per share:
 
 

 
 

 
 

 
 

Basic
 
(0.04
)
 
0.65

 
0.69

 
0.14

Diluted
 
(0.04
)
 
0.64

 
0.68

 
0.13

Cash flow provided by operating activities
 
124,832

 
398,521

 
315,739

 
365,722

Cash flow used for investing activities
 
(285,043
)
 
(347,797
)
 
(525,412
)
 
(447,706
)
Cash flow provided by (used for) financing activities
 
(93,801
)
 
(56,789
)
 
112,244

 
76,314

Significant Accounting Policies (Policies)
Organization and Nature of Operations 
Organization and Nature of Operations

Denbury Resources Inc., a Delaware corporation, is a growing independent oil and natural gas company.  We are the largest combined 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 our acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO2 tertiary recovery operations.
Principles of Reporting and Consolidation 

Encore Merger.  On March 9, 2010, we acquired Encore Acquisition Company (“Encore”), pursuant to an Agreement and Plan of Merger (the “Encore Merger Agreement”), under which Encore was merged with and into Denbury (the “Encore Merger”), with Denbury surviving the Encore Merger following approval by the stockholders of both Denbury and Encore, closing of a new revolving credit facility as part of the financing for the Encore Merger, and satisfaction of other conditions precedent.  The Encore Merger provided Encore stockholders stock and/or cash and included the assumption of Encore’s debt by Denbury.  Denbury has consolidated Encore’s results of operations since the March 9, 2010 acquisition date.  See Note 2, Acquisitions and Divestitures, for more information.

Principles of Reporting and Consolidation

The consolidated financial statements herein have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and include the accounts of Denbury and entities in which we hold a controlling financial interest.  Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis.  Investments in non-controlled entities over which we exercise significant influence are accounted for under the equity method.  Other investments are carried at cost.  All intercompany balances and transactions have been eliminated.

From March 9, 2010 through December 31, 2010, we owned approximately 46% of Encore Energy Partners LP (“ENP”) outstanding common units and 100% of Encore Energy Partners GP LLC (“ENP GP LLC”) membership interests, which was ENP’s general partner.  Considering the presumption of control of ENP 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 ENP GP LLC; therefore, we did not consolidate ENP in our Consolidated Balance Sheet as of December 31, 2010.  As presented in the accompanying Consolidated Statement of Operations for the year ended December 31, 2010, “Net income attributable to noncontrolling interest” of $13.8 million represents ENP’s results of operations attributable to limited partners other than Denbury for the portion of the year for which we consolidated ENP.
Use Of Estimates 
Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amount of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during each reporting period.  Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates.  Significant estimates underlying these financial statements include: (1) the fair value of financial derivative instruments; (2) the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom and the ceiling test; (3) the estimated quantities of proved and probable CO2 reserves used to compute depletion of CO2 properties; (4) accruals related to oil and natural gas sales volumes and revenues, capital expenditures and lease operating expenses; (5) the estimated costs and timing of future asset retirement obligations; (6) estimates made in the calculation of income taxes; and (7) estimates made in determining the fair values for purchase price allocations, including goodwill.  While management is not aware of any significant revisions to any of its estimates, there will likely be future revisions to its estimates resulting from matters such as revisions in estimated oil and natural gas volumes, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and natural gas industry, many of which require retroactive application.  These types of adjustments cannot be currently estimated and will be recorded in the period in which the adjustment occurs. 
Reclassifications 
Reclassifications

Certain prior period amounts have been reclassified to conform with the current year presentation. Such reclassifications had no impact on our reported net income, current assets, total assets, current liabilities, total liabilities or stockholders' equity.

Cash Equivalents 
Cash Equivalents

We consider all highly liquid investments to be cash equivalents if they have maturities of three months or less at the date of purchase.
Restricted Cash 
Restricted Cash

Restricted cash at December 31, 2012 consists of proceeds from the exchange of oil and gas properties with Exxon Mobil Corporation and its wholly-owned subsidiary XTO Energy Inc. (see Note 2, Acquisitions and Divestitures) being held by a qualified intermediary through three separate financial institutions and which are restricted for application towards future potential acquisitions to facilitate an anticipated like-kind-exchange transaction for federal income tax purposes. We manage and control counterparty credit risk related to this restricted cash using a trust agreement, whereby the assets held in trust must be segregated from the financial institution's assets, and in the event of a bankruptcy, the funds would not be subject to payments to the creditors of the financial institution.

Short-term Investments 
Short-term Investments

Short-term investments represent available-for-sale securities recorded at fair value with any unrealized gains or losses included in accumulated other comprehensive income.  At December 31, 2011, 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 (see Note 2, Acquisitions and Divestitures).  Our original cost basis of this investment was $93.0 million.  We received distributions of $7.2 million on the Vanguard common units we owned for the year ended December 31, 2011, which are included in “Interest income and other income” on our Consolidated Statements of Operations.  Due to the decline in the market value of this investment and the expectation that the investment would not recover its cost basis prior to the time of sale, we recorded a $6.3 million “other-than-temporary” impairment loss on this investment for the year ended December 31, 2011, which is included in “Impairment of assets” on our Consolidated Statements of Operations.  During January 2012, we sold our investment in Vanguard for cash consideration of $83.5 million, net of related transaction fees. The Company recognized a pretax loss on the sale of $3.1 million, which is included in “Other expenses” on our Consolidated Statements of Operations for the year ended December 31, 2012.
Oil and Natural Gas Properties 
Oil and Natural Gas Properties

Capitalized Costs.  We follow the full cost method of accounting for oil and natural gas properties.  Under this method, all costs related to acquisitions, exploration and development of oil and natural gas reserves are capitalized and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States.  Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and nonproductive wells, capitalized interest on qualifying projects, and general and administrative expenses directly related to exploration and development activities, and do not include any costs related to production, general corporate overhead or similar activities.  We assign the purchase price of oil and natural gas properties we acquire to proved and unevaluated properties based on the estimated fair values as defined in the FASC Fair Value Measurements and Disclosures topic.  Proceeds received from disposals are credited against accumulated costs except when the sale represents a significant disposal of reserves, in which case a gain or loss would be recognized. A disposal of twenty-five percent or more of our proved reserves would be considered significant.

Depletion and Depreciation.  The costs capitalized, including production equipment and future development costs, are depleted or depreciated using the unit-of-production method, based on proved oil and natural gas reserves as determined by independent petroleum engineers.  Oil and natural gas reserves are converted to equivalent units on a basis of 6,000 cubic feet of natural gas to one barrel of crude oil.  The depletion and depreciation rate per BOE associated with our oil and gas producing activities was $18.69 in 2012, $16.42 in 2011 and $15.82 in 2010.

Under full cost accounting, we may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves can be assigned to such properties.  The costs classified as unevaluated are transferred to the full cost amortization base as the properties are developed, tested and evaluated.

Ceiling Test. The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling.  The cost center ceiling is defined as: (1) the present value of estimated future net revenues from proved reserves before future abandonment costs (discounted at 10%), based on the average first-day-of-the-month oil and natural gas price for each month during the 12-month period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects.  Our future net revenues from proved reserves are not reduced for development costs related to the cost of drilling for and developing CO2 reserves nor those related to the cost of constructing CO2 pipelines, as those costs have previously been incurred by the Company.  Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves.  The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes.  The cost center ceiling test is prepared quarterly.  We did not have a ceiling test write-down during the years ended December 31, 2012, 2011 or 2010. 

Joint Interest Operations.  Substantially all of our oil and natural gas exploration and production activities are conducted jointly with others.  These financial statements reflect only our proportionate interest in such activities, and any amounts due from other partners are included in trade receivables.
 
Tertiary Injection Costs.  Our tertiary operations are conducted in reservoirs that have already produced significant amounts of oil over many years; however, in accordance with the SEC rules and regulations for recording proved reserves, we cannot recognize proved reserves associated with enhanced recovery techniques, such as CO2 injection, until there is a production response to the injected CO2, or unless the field is analogous to an existing flood.  

We capitalize, as a development cost, injection costs in fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO2 injections (i.e., a production response).  These capitalized development costs are included in our unevaluated property costs if there are not already proved tertiary reserves in that field.  After we see a production response to the CO2 injections (i.e., the production stage), injection costs are expensed as incurred, and once proved reserves are recognized, previously deferred unevaluated development costs become subject to depletion.
Property, Plant, and Equipment Policy 
CO2 Properties

We own and produce CO2 reserves, a non-hydrocarbon resource, that are used in our tertiary oil recovery operations on our own behalf and on behalf of other interest owners in enhanced recovery fields, with a portion sold to third-party industrial users.  We record revenue from our sales of CO2 to third parties when it is produced and sold.  Expenses related to the production of CO2 are allocated between volumes sold to third parties and volumes consumed internally that are directly related to our tertiary production.  The expenses related to third-party sales are recorded in “CO2 discovery and operating expenses,” and the expenses related to internal use are recorded in “Lease operating expenses” in the Consolidated Statements of Operations, or are capitalized as oil and gas properties in our Consolidated Balance Sheets, depending on the status of floods that receive the CO2 (see Tertiary Injection Costs above for further discussion).

During 2010 and 2011, we acquired interests in the Riley Ridge Federal Unit (“Riley Ridge”), in which helium and CO2 (non-hydrocarbon resources) as well as natural gas (a hydrocarbon resource) are present.  It is not possible to separately identify the capitalized costs related to the development of each product in the commingled gas stream; thus, these costs are allocated to each product based on the relative future revenue value of each product line and classified accordingly on the Consolidated Balance Sheets.

During 2010, we revised our capitalization policies for CO2 properties.  Previously, we accounted for our CO2 source properties in a manner similar to our method of accounting for oil and natural gas properties, as the process and activities to identify, develop and produce CO2 reserves are virtually identical to those used to identify, develop and produce oil and natural gas reserves.  However, because CO2 is not a hydrocarbon, it is excluded from the scope of FASC Topic 932, Extractive Industries – Oil and Gas; therefore, we are precluded from accounting for our CO2 operations in accordance with FASC Topic 932.  Accordingly, commencing in July 2010, costs incurred to search for CO2 are expensed as incurred until proved or probable reserves are established.  Once proved or probable reserves are established, costs incurred to obtain those reserves are capitalized and classified as “CO2 properties” on our Consolidated Balance Sheets.  Capitalized CO2 is aggregated by geologic formation and depleted on a unit-of-production basis over proved and probable reserves.  The impact of the revised accounting policy on our financial statements was not material to any individual year.  We recognized the cumulative impact of the revised accounting policy as a noncash net reduction to depletion, depreciation and amortization during the year ended December 31, 2010, resulting in a pretax credit of $9.6 million ($6.0 million after tax), which reflected a reduction to “CO2 properties” of $26.1 million offset by a decrease in “Accumulated depletion, depreciation and amortization” of $35.7 million.  The cumulative adjustment did not have an impact on our net cash flows.

The portion of our capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil reserves is included in the ceiling test as a reduction to future net revenues.  The remaining net capitalized CO2 properties, equipment and pipelines balance is evaluated for impairment by comparing the net carrying costs to the expected future net revenues from (1) the production of our probable and possible tertiary oil reserves and (2) the sale of CO2 to third-party industrial users.

Pipelines and Plants

CO2 used in our tertiary floods is transported to our fields through CO2 pipelines.  Costs of CO2 pipelines under construction are not depreciated until the pipelines are placed into service.  Pipelines are depreciated on a straight-line basis over their estimated useful lives, which range from 15 to 50 years.

Pipelines and plants include the Riley Ridge gas plant in southwestern Wyoming, which is currently under construction.  The plant is being withheld from depreciation until it is placed in service, which we currently expect to occur during mid-2013.

Property and Equipment – Other

Other property and equipment, which includes furniture and fixtures, vehicles, computer equipment and software, and capitalized leases, is depreciated principally on a straight-line basis over estimated useful lives.  Vehicles and furniture and fixtures are generally depreciated over a useful life of five to ten years, and computer equipment and software are generally depreciated over a useful life of three to five years.  Leasehold improvements are amortized over the shorter of the estimated useful life or the remaining lease term.

Leased property meeting certain capital lease criteria is capitalized, and the present value of the related lease payments is recorded as a liability.  Amortization of capitalized leased assets is computed using the straight-line method over the shorter of the estimated useful life or the initial lease term.

Maintenance and repair costs that do not extend the useful lives of property and equipment are charged to expense as incurred.

Asset Retirement Obligations 
Asset Retirement Obligations

In general, our future asset retirement obligations relate to future costs associated with plugging and abandoning our oil, natural gas and CO2 wells, removing equipment and facilities from leased acreage, and returning land to its original condition.  The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit-adjusted-risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset.  The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset.  Revisions to estimated retirement obligations will result in an adjustment to the related capitalized asset and corresponding liability.  If the liability is settled for an amount other than the recorded amount, the difference is recorded to the full cost pool, unless significant.

Asset retirement obligations are estimated at the present value of expected future net cash flows and are discounted using our credit-adjusted-risk-free rate.  We utilize unobservable inputs in the estimation of asset retirement obligations that include, but are not limited to, costs of labor, costs of materials, profits on costs of labor and materials, the effect of inflation on estimated costs, and the discount rate.  Accordingly, asset retirement obligations are considered a Level 3 measurement under the FASC Fair Value Measurements and Disclosures topic.
Derivative Instruments and Hedging Activities 
Derivative Instruments and Hedging Activities

We utilize oil and natural gas derivative contracts to mitigate our exposure to commodity price risk associated with our future oil and natural gas production.  These derivative contracts have historically consisted of options, in the form of price floors or collars, and fixed price swaps.  From time to time, we have also used interest rate lock contracts to mitigate our exposure to interest rate fluctuations related to sale-leaseback financing of certain equipment used at our oilfield facilities.  Our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value.  We do not apply hedge accounting to our oil and natural gas derivative contracts; accordingly, the changes in the fair value of these instruments are recognized in our Consolidated Statements of Operations in the period of change.

Oil and Natural Gas Derivative Contracts

We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; 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 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 approximately two years in the future from the current quarter, as we believe it is important to protect our future cash flow to provide a level of assurance for our capital spending in those future periods in light of current worldwide economic uncertainties and commodity price volatility. We do not have any natural gas derivative contracts for 2013 or beyond. Because our current and forecasted production is primarily oil, we currently use only oil derivative contracts in our commodity market risk management program.

Financial Instruments with Off-Balance-Sheet Risk and Concentrations of Credit Risk 
Financial Instruments with Off-Balance-Sheet Risk and Concentrations of Credit Risk

Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents, trade and accrued production receivables, and the derivative instruments discussed above.  Our cash equivalents represent high-quality securities placed with various investment-grade institutions.  This investment practice limits our exposure to concentrations of credit risk.  Our trade and accrued production receivables are dispersed among various customers and purchasers; therefore, concentrations of credit risk are limited.  We evaluate the credit ratings of our purchasers, and if customers are considered a credit risk, letters of credit are the primary security obtained to support lines of credit.  We attempt to minimize our credit risk exposure to the counterparties of our oil and natural gas derivative contracts through formal credit policies, monitoring procedures and diversification.  All of our derivative contracts are with banks, which are part of the syndicate of banks in our bank credit facility, or with their affiliates.  There are no margin requirements with the counterparties of our derivative contracts.
Goodwill 
Goodwill

Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Goodwill is not amortized; rather, it is tested for impairment annually during the fourth quarter and when events or changes in circumstances indicate that it is more likely than not the fair value of a reporting unit with goodwill has been reduced below its carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units.  However, we have only one reporting unit.  To assess impairment, we have the option to qualitatively assess if it is more likely than not that the fair value of the reporting unit is less than the carrying value.  Absent a qualitative assessment, or, through the qualitative assessment, if we determine it is more likely than not that the fair value of the reporting unit is less than the carrying value, a quantitative assessment is prepared to calculate the fair market value of the reporting unit.  If it is determined that the fair value of the reporting unit is less than the carrying value, the recorded goodwill is impaired to its implied fair value with a charge to operating expense.  We completed our annual goodwill impairment assessment during the fourth quarter of 2012 and did not record any goodwill impairment during 2012, nor have we recorded a goodwill impairment historically.
Revenue Recognition 
Revenue Recognition

Revenue is recognized at the time oil and natural gas is produced and sold.  Any amounts due from purchasers of oil and natural gas are included in accrued production receivable.

We follow the sales method of accounting for our oil and natural gas revenue, whereby we recognize revenue on all oil or natural gas sold to our purchasers regardless of whether the sales are proportionate to our ownership in the property.  A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves.  As of December 31, 2012 and 2011, our aggregate oil and natural gas imbalances were not material to our consolidated financial statements.

We recognize revenue and expenses of purchased producing properties at the time we assume effective control, commencing from either the closing or purchase agreement date, depending on the underlying terms and agreements.  We follow the same methodology in reverse when we sell properties by recognizing revenue and expenses of the sold properties until the closing date.

Income Taxes 
Income Taxes

Income taxes are accounted for using the asset and liability method, under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year end.  The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date.  A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the position.  The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement.
Net Income Per Common Share 
Net Income Per Common Share

Basic net income per common share is computed by dividing the net income attributable to common 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 includes the impact of potentially dilutive securities. Potentially dilutive securities consist of stock options, stock appreciation rights (“SARs”), nonvested restricted stock and nonvested performance equity awards. For each of the three years in the period ended December 31, 2012, there were no adjustments to net income for purposes of calculating basic and diluted net income per common share.


Basic weighted average common shares excludes 3.7 million, 3.4 million and 3.2 million shares of nonvested restricted stock during the year ended December 31, 2012, 2011 and 2010, respectively.  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, the nonvested 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.
Recently Adopted Accounting Pronouncements 
Recent Accounting Pronouncements

Presentation of Comprehensive Income. In June 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update ("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 was effective for Denbury beginning January 1, 2012. Since ASU 2011-05 only amended presentation requirements, it did not have a material effect on our consolidated financial statements.

Fair Value. 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 was effective for Denbury beginning January 1, 2012. The adoption of ASU 2011-04 did not have a material effect on our consolidated financial statements, but did require additional disclosures. See Note 10, Fair Value Measurements.
Recently Issued Accounting Pronouncements 
Accumulated Other Comprehensive Income Reclassifications. In February 2013, the FASB issued ASU 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income ("ASU 2013-02"). ASU 2013-02 requires disclosure of amounts reclassified out of accumulated other comprehensive income by component.  In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required to be reclassified to net income in its entirety in the same reporting period.  For amounts not reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures that provide additional detail about those amounts. ASU 2013-02 is effective prospectively for our fiscal year beginning January 1, 2013. The adoption of ASU 2013-02 will not have a material effect on our consolidated financial statements.

Balance Sheet Offsetting.  In December 2011, the FASB issued ASU 2011-11, Disclosure about Offsetting Assets and Liabilities (“ASU 2011-11”).  ASU 2011-11 requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position.  In January 2013, the FASB issued ASU 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities ("ASU 2013-01"). The update clarifies that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with the Derivatives and Hedging topic of the FASC, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset or subject to an enforceable master netting arrangement or similar agreement. ASU 2011-11 and ASU 2013-01 are effective for our fiscal year beginning January 1, 2013 and will be applied retrospectively for all comparative periods presented.  The adoption of ASU 2011-11 and ASU 2013-01 will not have a material effect on our consolidated financial statements, but may require additional disclosures.
Fair Value Measurements and Disclosures 
The FASC Fair Value Measurements and Disclosures topic defines fair value as the price that would be received to sell an asset or would be 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.  Instruments in this category include non-exchange-traded oil and natural gas derivatives that are based on NYMEX pricing.  Our costless collars are valued using the Black-Scholes model, an industry standard option valuation model, that takes into account inputs such as contractual prices for the underlying instruments, including maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, 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.

•
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.  At December 31, 2011, instruments in this category also included non-exchange-traded natural gas derivatives swaps that were based on regional pricing other than NYMEX (i.e., Houston Ship Channel).  Our basis swaps were estimated using discounted cash flow calculations based upon forward commodity price curves.

We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and our credit quality for liability positions.  We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.
Significant Accounting Policies (Tables)
Changes in goodwill 
The following table summarizes the changes in goodwill for the years ended December 31, 2012 and 2011:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
Beginning of year balance
 
$
1,236,318

 
$
1,232,418

Goodwill related to the Riley Ridge acquisition
 
—

 
3,900

Goodwill related to the Thompson Field acquisition
 
47,272

 
—

End of year balance
 
$
1,283,590

 
$
1,236,318

Weighted average shares used in the basic and diluted net income per common share 
The following is a reconciliation of the weighted average shares used in the basic and diluted net income per common share calculations for the periods indicated:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Basic weighted average common shares
 
385,205

 
396,023

 
370,876

Potentially dilutive securities:
 
 
 
 

 
 

Stock options and SARs
 
2,584

 
3,539

 
3,844

Performance equity awards
 
86

 
38

 
319

Restricted stock
 
1,063

 
1,358

 
1,216

Diluted weighted average common shares
 
388,938

 
400,958

 
376,255

Anti-dilutive securites excluded from computation of diluted net earnings per share 
The following securities could potentially dilute earnings per share in the future but were not included in the computation of diluted net income per share, as their effect would have been antidilutive:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Stock options and SARs
 
4,068

 
5,017

 
3,671

Restricted stock
 
47

 
104

 
17

Acquisitions and Divestitures (Tables)
Schedule of Purchase Price Allocation [Table Text Block] 
The following table presents a summary of the preliminary fair value of assets acquired and liabilities assumed in the Bakken Exchange Transaction:
In thousands
 
 
Consideration:
 
 
Fair value of net assets transferred
 
$
1,903,280

 
 
 
Less: Fair value of assets acquired and liabilities assumed: (1)
 
 
Cash (2)
 
1,331,684

Oil and natural gas properties
 
 
Proved
 
201,301

Unevaluated
 
98,635

CO2 properties
 
314,505

Other assets
 
477

Other liabilities
 
(29,531
)
Asset retirement obligations
 
(13,791
)
Fair value of net assets acquired
 
$
1,903,280


(1)
Fair value of the assets acquired and liabilities assumed is preliminary, pending final closing adjustments and further evaluation of reserves and asset retirement obligations.

(2)
Cash proceeds include preliminary closing adjustments of $41.7 million primarily representing adjustments for net revenues and capital expenditures of the transferred oil and natural gas property assets from the Bakken Exchange Transaction effective date to the closing dates. Also see Note 12, Supplemental Information and Note 13, Subsequent Events, for additional information regarding the placement of $1.05 billion of the proceeds in a qualified trust to facilitate an anticipated like-kind-exchange transaction for federal income tax purposes.
Schedule of Purchase Price Allocation [Table Text Block] 
The following table presents a summary of the fair value of assets acquired and liabilities assumed in the Thompson Field acquisition:
In thousands
 
 
Consideration:
 
 
Cash payment (1)
 
$
366,179

 
 
 
Less: Fair value of assets acquired and liabilities assumed:
 
 
Oil and natural gas properties
 
 
Proved
 
305,233

Unevaluated
 
12,023

Pipelines and plants
 
2,000

Other assets
 
2,957

Asset retirement obligations
 
(3,306
)
 
 
318,907

Goodwill
 
$
47,272


(1)
See Note 6, Income Taxes, for additional information regarding the like-kind-exchange transaction utilized to fund this purchase and Note 12, Supplemental Information, for supplemental cash flow information regarding the cash payment.
Schedule of Purchase Price Allocation [Table Text Block] 
acquisitions of Riley Ridge meets the definition of a business under the FASC Business Combinations topic.  As such, we estimated the fair value of assets acquired and liabilities assumed using a discounted net cash flow model. Goodwill associated with the acquisitions is deductible for income tax purposes.  The fair values assigned to assets acquired and liabilities assumed in the August 2011 acquisition have been finalized, and no adjustments have been made to fair value amounts previously disclosed in our Form 10-K for the period ended December 31, 2011. The following table presents a summary of the fair value of assets acquired and liabilities assumed in the August 2011 Riley Ridge acquisition:
In thousands
 
 
Consideration:
 
 
Cash payment
 
$
199,779

Deferred payment
 
15,000

Total consideration
 
214,779

 
 
 
Less: Fair value of assets acquired and liabilities assumed:
 
 
Oil and natural gas properties
 
 
Proved
 
48,731

Unproved
 
12,542

CO2 properties
 
9,741

Pipelines and plants
 
91,594

Other assets (1)
 
48,660

Asset retirement obligations
 
(389
)
 
 
210,879

Goodwill
 
$
3,900


(1)
Other assets includes helium extraction rights of $36.7 million.  Helium reserves at Riley Ridge are owned by the U.S. government.  The fair value assigned to helium extraction rights was calculated using the income approach and represents the discounted future net revenues associated with our 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 unit-of-production basis.
Business Acquisition, Pro Forma Information [Table Text Block] 
Unaudited Pro Forma Acquisition Information.  The following combined pro forma total revenues and other income and net income are presented as if the Bakken Exchange Transaction and Thompson Field acquisition had occurred on January 1, 2011:
 
 
Year Ended December 31,
In thousands, except per share data
 
2012
 
2011
Pro forma total revenues and other income
 
$
2,203,703

 
$
2,184,507

Pro forma net income
 
454,549

 
523,227

Pro forma net income per common share
 
 

 
 

Basic
 
$
1.18

 
$
1.32

Diluted
 
1.17

 
1.30


Business Acquisition, Pro Forma Information [Table Text Block] 
 The following combined pro forma total revenues and other income and net income attributable to Denbury stockholders are presented as if the acquisition of Encore occurred on January 1, 2010:
In thousands, except per share data
 
Year Ended December 31, 2010
Pro forma total revenues and other income
 
$
2,098,241

Pro forma net income attributable to Denbury stockholders
 
286,891

Pro forma net income per common share
 
 
Basic
 
$
0.73

Diluted
 
0.72

Asset Retirement Obligations (Tables)
Changes In Asset Retirement Obligations [Text Block]
The following table summarizes the changes in our asset retirement obligations for the years ended December 31, 2012 and 2011:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
Beginning asset retirement obligation
 
$
93,468

 
$
85,744

Liabilities incurred and assumed during period
 
50,956

 
12,477

Revisions in estimated retirement obligations
 
5,334

 
12,217

Liabilities settled and sold during period
 
(50,556
)
 
(23,257
)
Accretion expense
 
7,228

 
6,287

Ending asset retirement obligation
 
106,430

 
93,468

Less: current asset retirement obligation (1)
 
(3,700
)
 
(4,742
)
Long-term asset retirement obligation
 
$
102,730

 
$
88,726

Property And Equipment (Tables)
Summary of net property and equipment balances 
The following table presents a summary of our net property and equipment balances as of December 31, 2012 and 2011:
 
 
December 31,
In thousands
 
2012
 
2011
Oil and natural gas properties
 
 
 
 
Proved properties
 
$
6,963,211

 
$
7,026,579

Unevaluated properties
 
809,154

 
1,157,106

Total
 
7,772,365

 
8,183,685

Accumulated depletion and depreciation
 
(2,827,256
)
 
(2,407,520
)
Net oil and natural gas properties
 
4,945,109

 
5,776,165

CO2 properties
 
 
 
 
CO2 properties
 
1,032,653

 
596,003

Accumulated depletion and depreciation
 
(119,784
)
 
(91,666
)
Net CO2 properties
 
912,869

 
504,337

Pipelines and plants
 
 
 
 
CO2 pipelines (1)
 
1,632,255

 
1,432,646

Plants under construction (2)
 
402,871

 
269,110

Total
 
2,035,126

 
1,701,756

Accumulated depletion and depreciation
 
(99,185
)
 
(65,392
)
Net plants and pipelines
 
1,935,941

 
1,636,364

Other property and equipment
 
 
 
 
Other property and equipment
 
417,207

 
157,674

Accumulated depletion and depreciation
 
(134,016
)
 
(62,915
)
Net other property and equipment
 
283,191

 
94,759

Net property and equipment
 
$
8,077,110

 
$
8,011,625


(1)
Amounts include $346.5 million of CO2 pipelines at December 31, 2012 that were not subject to depreciation during 2012.
(2)
Plants under construction are not subject to depreciation.

Summary of unevaluated properties excluded from oil and natural gas properties being amortized 
A summary of the unevaluated properties excluded from oil and natural gas properties being amortized at December 31, 2012, and the year in which they were incurred follows:
 
 
December 31, 2012
 
 
Costs Incurred During:
 
 
In thousands
 
2012
 
2011
 
2010
 
2009 and prior
 
Total
Property acquisition costs
 
$
110,658

 
$
12,543

 
$
351,712

 
$
115,075

 
$
589,988

Exploration and development
 
106,075

 
40,152

 
3,155

 
8,390

 
157,772

Capitalized interest
 
29,249

 
30,430

 
333

 
1,382

 
61,394

Total
 
$
245,982

 
$
83,125

 
$
355,200

 
$
124,847

 
$
809,154

Long-Term Debt (Tables)
Components of Long-Term Debt 
The following long-term debt and capital lease obligations were outstanding as of December 31, 2012 and 2011:
 
 
December 31,
In thousands
 
2012
 
2011
Bank Credit Agreement
 
$
700,000

 
$
385,000

9½% Senior Subordinated Notes due 2016, including premium of $9,118 and $11,854, respectively
 
234,038

 
236,774

9¾% Senior Subordinated Notes due 2016, including discount of $13,569 and $17,854, respectively
 
412,781

 
408,496

8¼% Senior Subordinated Notes due 2020
 
996,273

 
996,273

6 3/8% Senior Subordinated Notes due 2021
 
400,000

 
400,000

Other Subordinated Notes, including premium of $25 and $33, respectively
 
3,832

 
3,840

Pipeline financings
 
236,244

 
243,274

Capital lease obligations
 
158,260

 
4,388

Total
 
3,141,428

 
2,678,045

Less: current obligations
 
(36,966
)
 
(8,316
)
Long-term debt and capital lease obligations
 
$
3,104,462

 
$
2,669,729

Indebtedness repayable over the next five years and thereafter 
At December 31, 2012, our indebtedness, including our capital and financing lease obligations but excluding the discount and premium on our senior subordinated debt, is payable over the next five years and thereafter as follows:
In thousands
 
 
2013
 
$
36,966

2014
 
38,481

2015
 
39,113

2016
 
1,388,592

2017
 
34,965

Thereafter
 
1,607,737

Total indebtedness
 
$
3,145,854

 
Income Taxes (Tables)
Income Tax Provision (Benefit) [Table Text Block] 
Our income tax provision (benefit) is as follows:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Current income tax expense (benefit)
 
 
 
 
 
 
Federal
 
$
57,720

 
$
(12,552
)
 
$
15,683

State
 
18,034

 
20,801

 
17,511

Total current income tax expense
 
75,754

 
8,249

 
33,194

 
 
 
 
 
 
 
Deferred income tax expense
 
 

 
 

 
 

Federal
 
239,862

 
329,715

 
143,381

State
 
15,881

 
12,748

 
16,968

Total deferred income tax expense
 
255,743

 
342,463

 
160,349

Total income tax expense
 
$
331,497

 
$
350,712

 
$
193,543

Deferred Tax Assets And Liabilities [Table Text Block] 
Significant components of our deferred tax assets and liabilities as of December 31, 2012 and 2011 are as follows:
 
 
December 31,
In thousands
 
2012
 
2011
Deferred tax assets:
 
 
 
 
Loss carryforwards – federal
 
$
—

 
$
13,970

Loss carryforwards – state
 
35,007

 
41,960

Tax credit carryover
 
34,837

 
34,829

Derivative contracts
 
7,252

 
3,551

Enhanced oil recovery credit carryforwards
 
17,346

 
53,381

Stock based compensation
 
28,387

 
32,566

Other
 
37,226

 
35,279

Total deferred tax assets
 
160,055

 
215,536

 
 
 
 
 
Deferred tax liabilities:
 
 

 
 

Property and equipment
 
(2,277,388
)
 
(2,078,143
)
Other
 
(6,963
)
 
(5,813
)
Total deferred tax liabilities
 
(2,284,351
)
 
(2,083,956
)
Total net deferred tax liability
 
$
(2,124,296
)
 
$
(1,868,420
)
Income Tax Provision (Benefit) Continuing Operations Income Tax Reconciliation [Table Text Block] 
Our reconciliation of income tax expense computed by applying the U.S. federal statutory rate and the reported effective tax rate on income from continuing operations is as follows:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Income tax provision calculated using the federal statutory income tax rate
 
$
299,900

 
$
323,416

 
$
167,674

State income taxes, net of federal income tax benefit
 
30,955

 
29,555

 
13,087

Effect of statutory rate change
 
(429
)
 
(578
)
 
11,502

Other
 
1,071

 
(1,681
)
 
1,280

Total income tax expense
 
$
331,497

 
$
350,712

 
$
193,543

Stock Compensation Plans (Tables)
Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Table Text Block] 
Stock-based compensation costs for the years ended December 31, 2012, 2011 and 2010, are as follows:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Stock-based compensation expensed:
 
 
 
 
 
 
General and administrative expenses
 
$
26,463

 
$
30,256

 
$
28,169

Lease operating expenses
 
2,847

 
2,621

 
2,056

Transaction and other costs related to the Encore Merger
 
—

 
313

 
5,866

Total stock-based compensation expensed
 
29,310

 
33,190

 
36,091

Stock-based compensation capitalized
 
8,587

 
6,998

 
3,702

Total cost of stock-based compensation arrangements
 
$
37,897

 
$
40,188

 
$
39,793

 
 
 
 
 
 
 
Income tax benefit realized for stock-based compensation arrangements
 
$
15,131

 
$
18,383

 
$
8,462

Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block] 
 
 
2012
 
2011
 
2010
Weighted average fair value of SARs granted
 
$
8.90

 
$
9.68

 
$
8.45

Risk-free interest rate
 
0.79
%
 
1.74
%
 
2.19
%
Expected life
 
4.0 to 5.0 years

 
4.0 to 5.0 years

 
4.0 to 4.3 years

Expected volatility
 
64.9
%
 
63.3
%
 
65.0
%
Dividend yield
 
—
%
 
—
%
 
—
%
  
Summary of stock option and SARs activity 
The following is a summary of our stock option and SARs activity:
 
 
Number
of Awards
 
Weighted
Average
Exercise Price
 
Weighted Average Remaining Contractual Life
(in years)
 
Aggregate Intrinsic Value
(in thousands)
Outstanding at December 31, 2011
 
11,949,610

 
$
13.56

 
 
 
 
Granted
 
1,066,294

 
17.14

 
 
 
 
Exercised
 
(2,029,570
)
 
8.03

 
 
 
 
Forfeited or expired
 
(541,199
)
 
18.34

 
 
 
 
Outstanding at December 31, 2012
 
10,445,135

 
14.75

 
3.7
 
$
31,861

 
 
 
 
 
 
 
 
 
Exercisable at end of period
 
7,115,744

 
$
13.81

 
3.2
 
$
30,031

Disclosure of intrinsic value of stock options exercised and grant-date fair value of awards vested [Table Text Block] 
The following is a summary of the total intrinsic value of stock options and SARs exercised and grant-date fair value of stock options and SARs vested:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Intrinsic value of stock options exercised
 
$
17,315

 
$
20,463

 
$
12,670

Grant-date fair value of stock options and SARs vested
 
26,391

 
11,416

 
8,689

Schedule of Cash Proceeds Received from Share-based Payment Awards [Table Text Block] 
The following is a summary of cash received from stock option exercises under share-based payment arrangements and tax benefits realized from the exercises of stock options and SARs:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Cash received from stock option exercises
 
$
6,022

 
$
4,685

 
$
4,867

Tax benefit realized for the exercises of stock options and SARs
 
241

 
879

 
4,603

Summary of Vesting Date Fair Value Of Awards 
Restricted Stock – 2004 Plan

As of December 31, 2012, there was $29.0 million of unrecognized compensation expense related to nonvested restricted stock grants.  This unrecognized compensation cost is expected to be recognized over a weighted-average period of 2.61 years.  The following is a summary of the total vesting date fair value of restricted stock under the 2004 Plan:

 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Fair value of restricted stock vested
 
$
22,332

 
$
12,355

 
$
12,731

Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity [Table Text Block] 
A summary of the status of our nonvested restricted stock grants issued under our 2004 Plan and the changes during the year ended December 31, 2012 is presented below:
 
 
Number
of Shares
 
Weighted
Average
Grant-Date
Fair Value
Nonvested at December 31, 2011
 
3,131,435

 
$
14.82

Granted
 
1,909,739

 
16.94

Vested
 
(1,378,496
)
 
15.38

Forfeited
 
(256,471
)
 
17.08

Nonvested at December 31, 2012
 
3,406,207

 
15.60

Summary of Vesting Date Fair Value Of Awards 
The following is a summary of the total vesting date fair value of restricted stock under the Encore Plan:

 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Fair value of restricted stock vested
 
$
584

 
$
2,259

 
$
6,571

Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity [Table Text Block] 
A summary of the status of the non-vested restricted stock grants under the Encore Plan and the changes during the year ended December 31, 2012 is presented below:
 
 
Number
of Shares
 
Weighted
Average
Grant-Date
Fair Value
Nonvested at December 31, 2011
 
103,043

 
$
15.43

Vested
 
(36,049
)
 
15.43

Forfeited
 
(10,736
)
 
15.43

Nonvested at December 31, 2012
 
56,258

 
15.43

Summary of Share-Based Award Valuation Assumptions 
Performance-Based Equity Awards

During 2012, we granted Performance-based Operational Awards and Performance-based TSR Awards to our officers. The range of assumptions used in the Monte Carlo simulation valuation approach for Performance-based TSR Awards, which were granted for the first time during 2012, are as follows:

 
 
2012
Weighted average fair value of Performance-based TSR Award granted
 
$
24.68

Risk-free interest rate
 
0.42
%
Expected life
 
2.81 years

Expected volatility
 
45.2
%
Dividend yield
 
—
%
Summary of Vesting Date Fair Value Of Awards 
The following is a summary of the total vesting date fair value of performance-based equity awards:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Vesting date fair value of Performance-based Operational Awards
 
$
2,191

 
$
10,892

 
$
7,532

Schedule of Nonvested Performance-based Units Activity [Table Text Block] 
A summary of the status of the nonvested performance-based equity awards (presented at the target level) during the year ended December 31, 2012 is as follows:
 
 
Performance-based Operational Awards
 
Performance-based TSR Awards
 
 
Number
of Awards
 
Weighted
Average
Grant-Date Fair Value
 
Number
of Awards
 
Weighted
Average
Grant-Date Fair Value
Nonvested at December 31, 2011
 
214,627

 
$
18.71

 
—

 
$
—

Granted
 
110,615

 
17.27

 
96,325

 
24.68

Vested(1)
 
(214,627
)
 
18.71

 
—

 
—

Forfeited
 
(10,422
)
 
17.27

 
(9,408
)
 
24.68

Nonvested at December 31, 2012
 
100,193

 
17.27

 
86,917

 
$
24.68


(1)
During 2012, the 2011 annual Performance-based Operational Awards vested, and award holders received shares equivalent to 56% of the number of target-level shares.
Derivative Instruments and Hedging Activities (Tables)
Commodity derivative income (expense), included in our Consolidated Statements of Operations 
The following is a summary of “Derivatives expense (income)” included in our Consolidated Statements of Operations:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Oil
 
 
 
 
 
 
Payment on settlements of derivative contracts
 
$
9,991

 
$
25,128

 
$
93,417

Fair value adjustments to derivative contracts – income
 
(10,904
)
 
(58,980
)
 
(44,441
)
Total derivatives expense (income) – oil
 
(913
)
 
(33,852
)
 
48,976

Natural gas
 
 

 
 

 
 

Receipt on settlements of derivative contracts
 
(27,871
)
 
(27,505
)
 
(61,805
)
Fair value adjustments to derivative contracts – expense (income)
 
23,950

 
8,860

 
(8,585
)
Total derivatives expense (income) – natural gas
 
(3,921
)
 
(18,645
)
 
(70,390
)
Ineffectiveness on interest rate swaps
 
—

 
—

 
(2,419
)
Derivatives expense (income)
 
$
(4,834
)
 
$
(52,497
)
 
$
(23,833
)
Commodity derivative contracts not classified as hedging instruments 
Commodity Derivative Contracts Not Classified as Hedging Instruments
 
 
 
 
 
 
 
 
 
Contract Prices per Barrel
 
 
 
 
Type of
 
Volume
 
 
 
 
Weighted Average Price
Year
 
Months
 
Contract
 
(Barrels per day)
 
 
Range
 
Floor
 
Ceiling
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil Contracts:
 
 
 
 
 
 
 
 
 
2013
 
Jan – Mar
 
Collar
 
55,000
 
$
70.00 – 113.00
 
$
78.91

 
$
108.01

 
 
Apr – June
 
Collar
 
56,000
 
 
75.00 – 121.50
 
79.64

 
108.61

 
 
July – Sept
 
Collar
 
56,000
 
 
75.00 – 133.10
 
79.64

 
109.15

 
 
Oct – Dec
 
Collar
 
54,000
 
 
80.00 – 127.50
 
80.00

 
117.53

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2014
 
Jan – Mar
 
Collar
 
52,000
 
$
80.00 – 104.50
 
$
80.00

 
$
102.44

 
 
Apr – June
 
Collar
 
52,000
 
 
80.00 – 104.50
 
80.00

 
102.44

 
 
July – Sept
 
Collar
 
48,000
 
 
80.00 – 98.80
 
80.00

 
97.46

 
 
Oct – Dec
 
Collar
 
48,000
 
 
80.00 – 98.80
 
80.00

 
97.46


Derivative financial instruments in Balance Sheet 
At December 31, 2012 and 2011, we had derivative financial instruments recorded in our Consolidated Balance Sheets as follows:
 
 
 
 
Estimated Fair Value
Asset (Liability)
December 31,
Type of Contract
 
Balance Sheet Location
 
2012
 
2011
 
 
 
 
In thousands
Derivatives not designated as hedging instruments:
 
 
 
 
Derivative Assets
 
 
 
 
 
 
Crude oil contracts
 
Derivative assets – current
 
$
19,477

 
$
23,452

Natural gas contracts
 
Derivative assets – current
 
—

 
23,950

Crude oil contracts
 
Derivative assets – long-term
 
36

 
29

Derivative Liabilities
 
 
 
 
 
 
Crude oil contracts
 
Derivative liabilities – current
 
(2,659
)
 
(22,610
)
Deferred premiums (1)
 
Derivative liabilities – current
 
(183
)
 
(3,913
)
Crude oil contracts
 
Derivative liabilities – long-term
 
(23,781
)
 
(18,702
)
Deferred premiums (1)
 
Derivative liabilities – long-term
 
—

 
(170
)
Total derivatives not designated as hedging instruments
 
$
(7,110
)
 
$
2,036


(1)
Deferred premiums payable relate to various oil floor contracts and are payable on a monthly basis through January 2013.
Fair Value Measurements (Tables)
Fair value hierarchy of financial assets and liabilities 
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 December 31, 2012 and 2011:
 
 
Fair Value Measurements Using:
 
 
Quoted Prices
in Active
Markets
 
Significant
Other
Observable
Inputs
 
Significant
Unobservable
Inputs
 
 
In thousands
 
(Level 1)
 
(Level 2)
 
(Level 3)
 
Total
December 31, 2012
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Oil derivative contracts
 
$
—

 
$
19,513

 
$
—

 
$
19,513

Liabilities:
 
 

 
 

 
 

 
 

Oil derivative contracts
 
—

 
(26,440
)
 
—

 
(26,440
)
Total
 
$
—

 
$
(6,927
)
 
$
—

 
$
(6,927
)
 
 
 
 
 
 
 
 
 
December 31, 2011
 
 

 
 

 
 

 
 

Assets:
 
 

 
 

 
 

 
 

Short-term investments
 
$
86,682

 
$
—

 
$
—

 
$
86,682

Oil and natural gas derivative contracts
 
—

 
23,481

 
23,950

 
47,431

Liabilities:
 
 

 
 

 
 

 
 

Oil and natural gas derivative contracts
 
—

 
(41,312
)
 
—

 
(41,312
)
Total
 
$
86,682

 
$
(17,831
)
 
$
23,950

 
$
92,801

The changes in the fair value of Denbury's Level 3 assets and liabilities for the twelve months ended 
The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the years ended December 31, 2012 and 2011:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
Fair value of Level 3 instruments, beginning of year
 
$
23,950

 
$
16,478

Unrealized gains on commodity derivative contracts included in earnings
 
3,921

 
13,384

Receipts on settlement of commodity derivative contracts
 
(27,871
)
 
(5,912
)
Fair value of Level 3 instruments, end of year
 
$
—

10

$
23,950

 
 
 
 
 
The amount of total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held at the reporting date
 
$
—

 
$
13,384

Commitments and Contingencies (Tables)
Summary of long-term commitments which require future minimum rental payments
The following table summarizes by year the remaining non-cancelable future payments under these leases as of December 31, 2012:
In thousands
 
Pipeline
Financing
Leases
 
Capital
Leases
 
Operating
Leases
2013
 
$
30,817

 
$
35,429

 
$
10,656

2014
 
31,992

 
31,629

 
11,452

2015
 
32,591

 
30,139

 
12,300

2016
 
31,233

 
28,038

 
12,384

2017
 
30,678

 
22,052

 
12,720

Thereafter
 
296,226

 
31,806

 
80,562

Total minimum lease payments
 
453,537

 
179,093

 
$
140,074

Less: Amount representing interest
 
(217,293
)
 
(20,833
)
 
 

Present value of minimum lease payments
 
$
236,244

 
$
158,260

 
 

Supplemental Information (Tables)
Accounts Payable and Accrued Liabilities 
Accounts Payable and Accrued Liabilities
 
 
December 31,
In thousands
 
2012
 
2011
Accrued exploration and development costs
 
$
109,939

 
$
141,868

Accounts payable
 
86,051

 
99,444

Accrued interest
 
60,698

 
60,923

Accrued compensation
 
48,451

 
35,861

Accrued lease operating expenses
 
23,862

 
24,185

Taxes payable
 
27,523

 
13,455

Other
 
58,144

 
53,600

Total
 
$
414,668

 
$
429,336

Supplemental Cash Flow Information 
Supplemental Cash Flow Information
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Supplemental cash flow information:
 
 
 
 
 
 
Cash paid for interest, expensed
 
$
137,950

 
$
137,259

 
$
151,831

Cash paid for interest, capitalized
 
77,432

 
60,540

 
66,815

Cash paid for income taxes
 
99,194

 
45,912

 
17,960

Cash received from income tax refunds
 
(38,004
)
 
(24,677
)
 
(15,107
)
Non-cash investing activities:
 
 
 
 

 
 

Increase in asset retirement obligations
 
56,290

 
24,694

 
53,579

Increase (decrease) in liabilities for capital expenditures
 
(26,882
)
 
74,697

 
(237
)
Sale of non-core assets (1)
 
(212,544
)
 
—

 
—

Purchase of Thompson Field (1)
 
212,544

 
—

 
—

Sale of Bakken area assets in Bakken Exchange Transaction (2)
 
(1,621,611
)
 
—

 
—

Purchase of properties in Bakken Exchange Transaction (2)
 
571,596

 
—

 
—

Issuance of Denbury common stock in connection with the Encore Merger
 
—

 
—

 
2,085,681

Vanguard common units received as consideration for sale of ENP
 
—

 
—

 
93,020


(1)
During 2012, $212.5 million of proceeds from the sale of certain non-core assets were paid by the purchaser directly to a qualified intermediary to facilitate a like-kind-exchange transaction for federal income tax purposes. The qualified intermediary subsequently released the funds to the previous owner of the Thompson Field to fund our acquisition of Thompson Field.

(2)
During 2012, we sold our Bakken area assets with a fair value as determined in accordance with FASC rules of $1.9 billion to ExxonMobil in exchange for a combination of cash and various property interests valued in accordance with FASC rules at $571.6 million. ExxonMobil paid a portion of the cash proceeds ($1.05 billion) directly to a qualified intermediary to facilitate a like-kind-exchange transaction under federal income tax rules under which we expect our Pending CCA Acquisition to qualify (see Note 13, Subsequent Events). The remaining $281.7 million in cash proceeds are reported as an investing activity on our Statement of Cash Flows for the year ending December 31, 2012.

Supplemental Oil and Natural Gas Disclosures (Unaudited) (Tables)
Cost incurred in oil and natural gas activities 
Costs incurred in oil and natural gas activities were as follows:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Property acquisitions:
 
 
 
 
 
 
Proved
 
$
491,041

 
$
86,465

 
$
3,373,450

Unevaluated
 
115,270

 
17,858

 
1,297,695

Exploration
 
12,019

 
31,483

 
8,728

Development
 
1,111,314

 
1,144,243

 
658,758

Total costs incurred (1)
 
$
1,729,644

 
$
1,280,049

 
$
5,338,631


(1)
Capitalized general and administrative costs that directly relate to exploration and development activities were $49.2 million, $35.0 million and $20.1 million for the years ended December 31, 2012, 2011 and 2010, respectively.
Results of operations from oil and natural gas producing activities excluding corporate overhead and interest costs 
Results of operations from oil and natural gas producing activities, excluding corporate overhead and interest costs, were as follows:
 
 
Year Ended December 31,
In thousands, except per BOE data
 
2012
 
2011
 
2010
Oil, natural gas, and related product sales
 
$
2,409,867

 
$
2,269,151

 
$
1,793,292

Lease operating costs
 
532,359

 
507,397

 
470,364

Marketing expenses
 
52,836

 
26,047

 
31,036

Taxes other than income
 
149,919

 
138,419

 
114,569

Depletion, depreciation and amortization
 
448,424

 
369,075

 
391,782

CO2 properties and pipelines depletion and depreciation (1)
 
42,064

 
24,460

 
29,206

Commodity derivatives expense (income)
 
(4,834
)
 
(52,497
)
 
(21,414
)
Net operating income
 
1,189,099

 
1,256,250

 
777,749

Income tax provision
 
457,803

 
477,375

 
295,545

Results of operations from oil and natural gas producing activities
 
$
731,296

 
$
778,875

 
$
482,204

 
 
 
 
 
 
 
Depletion, depreciation and amortization per BOE
 
$
18.69

 
$
16.42

 
$
15.82


(1)
Represents an allocation of the depletion, depreciation and amortization of our CO2 properties and pipelines associated with our tertiary oil producing activities.
Estimated quantities of reserves 
Estimated Quantities of Proved Reserves
 
 
Year Ended December 31,
 
 
2012
 
2011
 
2010
 
 
Oil
(MBbl)
 
Gas
(MMcf)
 
Total
(MBOE)
 
Oil
(MBbl)
 
Gas
(MMcf)
 
Total
(MBOE)
 
Oil
(MBbl)
 
Gas
(MMcf)
 
Total
(MBOE)
Balance at beginning of year
 
357,733

 
625,208

 
461,934

 
338,276

 
357,893

 
397,925

 
192,879

 
87,975

 
207,542

Revisions of previous estimates
 
(7,099
)
 
(16,720
)
 
(9,886
)
 
(4,478
)
 
(14,058
)
 
(6,821
)
 
3,538

 
16,171

 
6,233

Revisions due to price changes
 
(401
)
 
(37,969
)
 
(6,729
)
 
2,558

 
485

 
2,639

 
2,780

 
811

 
2,915

Extensions and discoveries
 
14,910

 
10,005

 
16,579

 
42,936

 
52,339

 
51,658

 
26,313

 
130,245

 
48,021

Improved recovery (1)
 
69,543

 
—

 
69,543

 
264

 
—

 
264

 
30,173

 
—

 
30,173

Production

 
(24,462
)
 
(10,654
)
 
(26,238
)
 
(22,169
)
 
(10,783
)
 
(23,966
)
 
(21,870
)
 
(28,491
)
 
(26,619
)
Acquisition of minerals in place
 
24,677

 
20,598

 
28,110

 
346

 
239,332

 
40,235

 
155,021

 
622,984

 
258,852

Sales of minerals in place
 
(105,777
)
 
(108,827
)
 
(123,915
)
 
—

 
—

 
—

 
(50,558
)
 
(471,802
)
 
(129,192
)
Balance at end of year
 
329,124

 
481,641

 
409,398

 
357,733

 
625,208

 
461,934

 
338,276

 
357,893

 
397,925

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved Developed Reserves:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance at beginning of year
 
239,741

 
125,970

 
260,736

 
219,077

 
110,516

 
237,496

 
116,192

 
69,513

 
127,778

Balance at end of year
 
236,009

 
64,191

 
246,708

 
239,741

 
125,970

 
260,736

 
219,077

 
110,516

 
237,496


(1)
Improved recovery reflects reserve additions which result from the application of secondary recovery methods such as water flooding, or tertiary recovery methods such as CO2 flooding.  In order to recognize proved tertiary oil reserves, we must either have an oil production response to CO2 injections or the field must be analogous to an existing tertiary flood. The magnitude of proved reserves that we can book in any given year will depend on our progress with new floods and the timing of the production response.
Oil and natural gas prices 
The following representative oil and natural gas prices were used in the Standardized Measure.  These prices were adjusted by field to arrive at the appropriate corporate net price.
 
 
December 31,
 
 
2012
 
2011
 
2010
Oil (NYMEX)
 
$
94.71

 
$
96.19

 
$
79.43

Natural Gas (Henry Hub)
 
2.85

 
4.16

 
4.40

Discounted future net cash inflows after income taxes 
 
 
December 31,
In thousands
 
2012
 
2011
 
2010
Future cash inflows
 
$
34,779,549

 
$
38,165,122

 
$
26,698,819

Future production costs
 
(13,114,740
)
 
(12,570,015
)
 
(9,702,896
)
Future development costs
 
(2,034,174
)
 
(3,026,898
)
 
(1,912,457
)
Future income taxes
 
(6,672,857
)
 
(7,379,972
)
 
(4,700,023
)
Future net cash flows
 
12,957,778

 
15,188,237

 
10,383,443

10% annual discount for estimated timing of cash flows
 
(6,543,398
)
 
(8,180,632
)
 
(5,465,516
)
Standardized measure of discounted future net cash flows
 
$
6,414,380

 
$
7,007,605

 
$
4,917,927

Analysis of changes in the Standardized Measure of Discounted Future Net Cash Flows from proved oil and natural gas reserves 
The following table sets forth an analysis of changes in the Standardized Measure of Discounted Future Net Cash Flows from proved oil and natural gas reserves:
 
 
Year Ended December 31,
In thousands
 
2012
 
2011
 
2010
Beginning of year
 
$
7,007,605

 
$
4,917,927

 
$
2,457,385

Sales of oil and natural gas produced, net of production costs
 
(1,673,253
)
 
(1,597,288
)
 
(1,177,322
)
Net changes in sales prices
 
(584,526
)
 
4,646,086

 
2,062,181

Extensions and discoveries, less applicable future development and production costs
 
291,558

 
762,370

 
295,074

Improved recovery (1)
 
1,901,109

 
15,708

 
623,622

Previously estimated development costs incurred
 
376,199

 
354,228

 
193,947

Revisions of previous estimates, including revised estimates of development costs, reserves and rates of production
 
(797,975
)
 
(1,673,283
)
 
(285,158
)
Accretion of discount
 
875,383

 
729,234

 
307,546

Acquisition of minerals in place
 
767,267

 
29,737

 
3,671,439

Sales of minerals in place
 
(1,805,309
)
 
—

 
(1,474,443
)
Net change in income taxes
 
56,322

 
(1,177,114
)
 
(1,756,344
)
End of year
 
$
6,414,380

 
$
7,007,605

 
$
4,917,927


(1)
Improved recovery additions result from the application of secondary recovery methods such as water flooding or tertiary recovery methods such as CO2 flooding.
Supplemental CO2 and Helium Disclosures (Unaudited) (Tables)
Proved CO2 and helium reserves
Based on engineering reports prepared by DeGolyer and MacNaughton, proved CO2 reserves, and helium reserves associated with our helium production rights, were estimated as follows (in MMcf):
 
 
Year Ended December 31,
 
 
2012
 
2011
 
2010
CO2 Reserves
 
 
 
 
 
 
Gulf Coast region (1)
 
6,073,175

 
6,685,412

 
7,085,131

Rocky Mountain region (2)
 
3,495,534

 
2,195,534

 
2,189,756

 
 
 
 
 
 
 
Helium Reserves Associated with Denbury's Production Rights
 
 
 
 
 
 
Rocky Mountain region (3)
 
12,712

 
12,004

 
7,159


(1)
Proved CO2 reserves in the Gulf Coast region consist of reserves from our reservoirs at Jackson Dome and are presented on a gross working interest (8/8ths) basis, of which our net revenue interest was approximately 4.8 Tcf, 5.3 Tcf and 5.6 Tcf at December 31, 2012, 2011 and 2010, respectively, and include reserves dedicated to volumetric production payments of 57.1 Bcf, 84.7 Bcf and 100.2 Bcf at December 31, 2012, 2011 and 2010, respectively.

(2)
Proved CO2 reserves in the Rocky Mountain region consist of our reserves at Riley Ridge (presented on a gross working interest (8/8ths) basis) and our overriding royalty interest in LaBarge Field, of which our net revenue interest was approximately 2.9 Tcf, 1.6 Tcf and 0.9 Tcf at December 31, 2012, 2011 and 2010, respectively.

(3)
Reserves associated with helium production rights include helium reserves located in acreage in the Rocky Mountain region for which we have the right to extract the helium.  The U.S. government retains title to the helium reserves and we retain the right to extract and sell the helium on behalf of the government in exchange for a fee.  The helium reserves are presented net of the fee we will remit to the U.S. government.
Unaudited Quarterly Information (Tables)
Unaudited Quarterly Information


In thousands, except per share amounts
 
March 31
 
June 30
 
September 30
 
December 31
2012
 
 
 
 
 
 
 
 
Revenues and other income
 
$
645,116

 
$
601,781

 
$
600,371

 
$
609,204

Derivatives expense (income)
 
45,275

 
(139,109
)
 
61,631

 
27,369

Other expenses
 
420,529

 
398,089

 
399,361

 
386,470

Net income
 
113,467

 
211,865

 
85,367

 
114,661

Net income per share:
 
 

 
 

 
 

 
 

Basic
 
0.29

 
0.55

 
0.22

 
0.30

Diluted
 
0.29

 
0.54

 
0.22

 
0.30

Cash flow provided by operating activities
 
291,654

 
440,966

 
293,506

 
384,765

Cash flow used for investing activities
 
(288,883
)
 
(560,341
)
 
(388,748
)
 
(138,869
)
Cash flow provided by (used for) financing activities
 
55,902

 
70,122

 
91,163

 
(118,676
)
 
 
 
 
 
 
 
 
 
2011
 
 

 
 

 
 

 
 

Revenues and other income
 
$
514,165

 
$
601,397

 
$
576,505

 
$
617,257

Derivatives expense (income)
 
170,750

 
(172,904
)
 
(210,154
)
 
159,811

Other expenses
 
366,361

 
350,499

 
343,339

 
377,577

Net income (loss)
 
(14,190
)
 
259,246

 
275,670

 
52,607

Net income (loss) per share:
 
 

 
 

 
 

 
 

Basic
 
(0.04
)
 
0.65

 
0.69

 
0.14

Diluted
 
(0.04
)
 
0.64

 
0.68

 
0.13

Cash flow provided by operating activities
 
124,832

 
398,521

 
315,739

 
365,722

Cash flow used for investing activities
 
(285,043
)
 
(347,797
)
 
(525,412
)
 
(447,706
)
Cash flow provided by (used for) financing activities
 
(93,801
)
 
(56,789
)
 
112,244

 
76,314

Significant Accounting Policies (Goodwill Rollforward) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2012
Riley Ridge Phase 2 [Member]
Dec. 31, 2011
Riley Ridge Phase 2 [Member]
Dec. 31, 2012
Thompson Field [Member]
Dec. 31, 2011
Thompson Field [Member]
Changes in goodwill
 
 
 
 
 
 
 
Goodwill, beginning balance
$ 1,283,590 
$ 1,236,318 
$ 1,232,418 
 
 
 
 
Goodwill acquired during period
 
 
 
0 
3,900 
47,272 
0 
Goodwill, ending balance
$ 1,283,590 
$ 1,236,318 
$ 1,232,418 
 
 
 
 
Significant Accounting Policies (Reconciliation of Weighted Average Shares Table) (Details 1)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Weighted average shares used in the basic and diluted net income per common share
 
 
 
Weighted average common shares - basic
385,205 
396,023 
370,876 
Potentially dilutive securities:
 
 
 
Performance equity awards
86 
38 
319 
Weighted average common shares - diluted
388,938 
400,958 
376,255 
Stock options and SARs [Member]
 
 
 
Potentially dilutive securities:
 
 
 
Stock options, SARs, and restricted stock awards
2,584 
3,539 
3,844 
Restricted Stock [Member]
 
 
 
Potentially dilutive securities:
 
 
 
Stock options, SARs, and restricted stock awards
1,063 
1,358 
1,216 
Significant Accounting Policies (Anti-dilutive Securities Excluded from Diluted Net EPS) (Details 2)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Stock Option And Stock Appreciation Rights [Member]
 
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
 
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share, Total
4,068 
5,017 
3,671 
Restricted Stock [Member]
 
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
 
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share, Total
47 
104 
17 
Significant Accounting Policies (Details Textuals) (USD $)
Share data in Millions, unless otherwise specified
1 Months Ended 12 Months Ended
Jan. 31, 2012
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Significant Accounting Policies [Line Items]
 
 
 
 
Reduction to CO2 properties
 
 
 
$ 26,100,000 
Adjustment to accumulated depletion, depreciation and amortization
 
 
 
35,700,000 
Available-for-sale Securities, Gross Realized Gain (Loss), Excluding Other than Temporary Impairments
 
3,100,000 
 
 
Net income attributable to noncontrolling interest
 
0 
0 
13,804,000 
Cost basis of Vanguard investment
 
 
 
93,000,000 
Interest and Other Income from Available-for-sale securities
 
 
7,200,000 
 
Other than Temporary Impairment Loss on Investments
 
 
6,300,000 
 
Proceeds from Sale of Available-for-sale Securities, Equity
83,500,000 
83,545,000 
0 
0 
Depletion, depreciation and amortization per BOE
 
18.69 
16.42 
15.82 
Impairment of Goodwill
 
0 
0 
0 
Non-vested restricted stock excluded from basic weighted average common shares
 
3.7 
3.4 
3.2 
Post-tax [Member]
 
 
 
 
Significant Accounting Policies [Line Items]
 
 
 
 
Cumulative effect of change in accounting policy, before tax
 
 
 
6,000,000 
Pre-tax [Member]
 
 
 
 
Significant Accounting Policies [Line Items]
 
 
 
 
Cumulative effect of change in accounting policy, before tax
 
 
 
$ 9,600,000 
Encore Energy Partners LP ("ENP") [Member]
 
 
 
 
Significant Accounting Policies [Line Items]
 
 
 
 
Ownership Percentage In Subsidiaries
 
 
 
46.00% 
Encore Energy Partners GP LLC ("GP LLC") [Member]
 
 
 
 
Significant Accounting Policies [Line Items]
 
 
 
 
Ownership Percentage In Subsidiaries
 
 
 
100.00% 
Minimum [Member] |
Co2 Property And Pipelines [Member]
 
 
 
 
Significant Accounting Policies [Line Items]
 
 
 
 
Estimated useful lives
 
15 years 
 
 
Minimum [Member] |
Vehicles and furniture and fixtures [Member]
 
 
 
 
Significant Accounting Policies [Line Items]
 
 
 
 
Estimated useful lives
 
5 years 
 
 
Minimum [Member] |
Computer equipment and software [Member]
 
 
 
 
Significant Accounting Policies [Line Items]
 
 
 
 
Estimated useful lives
 
3 years 
 
 
Maximum [Member] |
Co2 Property And Pipelines [Member]
 
 
 
 
Significant Accounting Policies [Line Items]
 
 
 
 
Estimated useful lives
 
50 years 
 
 
Maximum [Member] |
Vehicles and furniture and fixtures [Member]
 
 
 
 
Significant Accounting Policies [Line Items]
 
 
 
 
Estimated useful lives
 
10 years 
 
 
Maximum [Member] |
Computer equipment and software [Member]
 
 
 
 
Significant Accounting Policies [Line Items]
 
 
 
 
Estimated useful lives
 
5 years 
 
 
Acquisitions and Divestitures Acquisitions and Divestitures (Bakken Exchange Transaction PPA) (Details) (USD $)
12 Months Ended 6 Months Ended
Dec. 31, 2012
Dec. 21, 2012
Bakken Exchange Transaction [Member]
Dec. 31, 2012
Bakken Exchange Transaction [Member]
Dec. 31, 2012
Proved Reserves [Member]
Bakken Exchange Transaction [Member]
Dec. 31, 2012
Unevaluated Reserves [Domain]
Bakken Exchange Transaction [Member]
Business Acquisition [Line Items]
 
 
 
 
 
Fair value of net assets transferred
 
 
$ 1,903,280,000 
 
 
Cash
 
 
1,331,684,000 
 
 
Business Acquisition, Purchase Price Allocation, Natural Resources
 
 
 
201,301,000 
98,635,000 
CO2 properties
 
 
314,505,000 
 
 
Other assets
 
 
477,000 
 
 
Other liabilities
 
 
(29,531,000)
 
 
Asset retirement obligation
 
 
(13,791,000)
 
 
Fair value of net assets acquired
 
 
1,903,280,000 
 
 
Operating revenues Net Of Capital And Lease Operating Expense Between Effective Date And Closing Date Of Transaction
 
41,700,000 
 
 
 
Anticipated Pre Adjusted Cash Paid For Purchase Of Oil And Natural Gas Properties
$ 1,050,000,000 
 
 
 
 
Acquisitions and Divestitures Acquisitions and Divestitures (Thompson Field PPA) (Details 1) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2010
Dec. 31, 2012
Thompson Field [Member]
Dec. 31, 2012
Proved Reserves [Member]
Thompson Field [Member]
Dec. 31, 2012
Unevaluated Reserves [Domain]
Thompson Field [Member]
Business Acquisition [Line Items]
 
 
 
 
Cash payment
$ 833,900 
$ 366,179 
 
 
Business Acquisition, Purchase Price Allocation, Natural Resources
 
 
305,233 
12,023 
Pipelines and plants
 
2,000 
 
 
Other assets
 
2,957 
 
 
Asset retirement obligations
 
(3,306)
 
 
Business Acquisition, Purchase Price Allocation, Assets Acquired (Liabilities Assumed), Net
 
318,907 
 
 
Goodwill, acquired
 
$ 47,272 
 
 
Acquisitions and Divestitures (Riley Ridge Phase 2 PPA) (Details 2) (USD $)
Dec. 31, 2010
Dec. 31, 2011
Riley Ridge Phase 2 [Member]
Dec. 31, 2011
Proved Reserves [Member]
Riley Ridge Phase 2 [Member]
Dec. 31, 2011
Unevaluated Reserves [Domain]
Riley Ridge Phase 2 [Member]
Business Combination, Consideration Transferred [Abstract]
 
 
 
 
Cash payment
$ 833,900,000 
$ 199,779,000 
 
 
Deferred payment
 
15,000,000 
 
 
Total consideration
 
214,779,000 
 
 
Fair value of assets acquired and liabilities assumed:
 
 
 
 
Business Acquisition, Purchase Price Allocation, Natural Resources
 
 
48,731,000 
12,542,000 
CO2 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
 
3,900,000 
 
 
Helium extraction rights
 
$ 36,700,000 
 
 
Acquisitions And Divestitures (Pro Forma Table Thompson and Bakken) (Details 3) (Bakken and Thompson Transactions [Member], USD $)
In Thousands, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Bakken and Thompson Transactions [Member]
 
 
Proforma revenue and net income
 
 
Pro forma total revenues and other income
$ 2,203,703 
$ 2,184,507 
Pro forma net income
$ 454,549 
$ 523,227 
Pro forma net income per common share:
 
 
Basic
$ 1.18 
$ 1.32 
Diluted
$ 1.17 
$ 1.30 
Acquisitions and Divestitures Acquisitions and Divestitures (Pro Forma Table - Encore) (Details 4) (Encore Acquisition [Member], USD $)
In Thousands, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2010
Encore Acquisition [Member]
 
Proforma revenue and net income
 
Pro forma total revenues and other income
$ 2,098,241 
Pro forma net income attributable to Denbury stockholders
$ 286,891 
Pro forma net income per common share:
 
Basic
$ 0.73 
Diluted
$ 0.72 
Acquisitions and Divestitures (Details Textuals) (USD $)
1 Months Ended 10 Months Ended 12 Months Ended 1 Months Ended 3 Months Ended 1 Months Ended 12 Months Ended 12 Months Ended 3 Months Ended 6 Months Ended 3 Months Ended 1 Months Ended 1 Months Ended 3 Months Ended 12 Months Ended 1 Months Ended
Dec. 31, 2010
Dec. 31, 2010
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Mar. 31, 2010
Rate
Mar. 8, 2010
Dec. 31, 2010
Accrued Employee Compensation Costs Encore [Member]
Dec. 31, 2010
ENP GP Investment [Member]
Dec. 31, 2012
8.25% Senior Subordinated Notes due 2020 [Member]
Feb. 28, 2010
8.25% Senior Subordinated Notes due 2020 [Member]
Dec. 31, 2012
Bank Credit Agreement [Member]
Mar. 31, 2010
Bank Credit Agreement [Member]
Dec. 31, 2010
Encore Energy Partners LP [Member]
Mar. 31, 2010
Genesis Lp Unit [Member]
Mar. 31, 2010
Genesis Energy LLC [Member]
Feb. 28, 2010
Genesis Gp [Member]
Mar. 31, 2010
Genesis Gp [Member]
Dec. 31, 2010
Vanguard Natural Resources [Member]
Dec. 31, 2010
Haynesville and East Texas Natural Gas Properties [Member]
Dec. 31, 2010
Encore Acquisition [Member]
Mar. 31, 2010
Encore Acquisition [Member]
Dec. 31, 2011
Encore Acquisition [Member]
Third party legal and accounting fees [Member]
Dec. 31, 2010
Encore Acquisition [Member]
Third party legal and accounting fees [Member]
Dec. 31, 2011
Encore Acquisition [Member]
Employee related severance and termination costs [Member]
Dec. 31, 2010
Encore Acquisition [Member]
Employee related severance and termination costs [Member]
Dec. 31, 2012
Bakken Exchange Transaction [Member]
Dec. 21, 2012
Bakken Exchange Transaction [Member]
Nov. 30, 2012
Bakken Exchange Transaction [Member]
Dec. 31, 2012
Webster Field [Member]
Jun. 30, 2012
Thompson Field [Member]
Dec. 31, 2012
Thompson Field [Member]
Dec. 31, 2011
Riley Ridge Phase 2 [Member]
Aug. 1, 2011
Riley Ridge Phase 2 [Member]
Oct. 31, 2010
Riley Ridge Phase 1 [Member]
Apr. 30, 2012
Paradox Basin [Member]
Feb. 29, 2012
Non Core Gulf Coast Assets [Member]
Feb. 29, 2012
Non Core Gulf Coast Assets [Member]
Dec. 31, 2010
Cleveland Sand Play Properties [Member]
May 31, 2010
Southern Properties [Member]
Dec. 31, 2012
Shannon Sandstone [Member]
Hartzog Draw Field [Member]
Dec. 31, 2012
Big George Coal Zone [Member]
Hartzog Draw Field [Member]
Acquisitions and Divestitures (Textuals) [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Business Acquisition, Purchase Price Allocation, Current Assets, Cash and Cash Equivalents
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 1,331,684,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Working Interest Acquired In Purchase Of Oil And Natural Gas Properties
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
nearly 100% 
nearly 100% 
 
 
 
 
 
 
 
 
 
 
 
Revenue Interest Acquired In Purchase Of Oil And Gas Properties
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
nearly 80% 
 
 
 
 
 
 
 
 
 
 
 
 
Working Interest In Business Acquisition
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
57.50% 
42.50% 
 
 
 
 
 
83.00% 
67.00% 
Revenue Interest In Business Acquisition
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
84.70% 
 
 
 
 
 
 
 
 
 
71.00% 
53.00% 
Overriding Royalty Interest In CO2 Reserves In LaBarge Field
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
approximately a one-third 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage Of Assets Transferred At First Closing
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
82.50% 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage Of Assets Transferred At Second Closing
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
17.50% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Revenue Interest Retained By Seller
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5.00% 
 
 
 
 
 
 
 
 
 
 
 
Oil Production Threshold Barrels Per Day
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,000 
 
 
 
 
 
 
 
 
 
 
 
Business Acquisition Purchase Price Allocation Assets Acquired Less Liabilities Assumed
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
318,907,000 
 
 
 
 
 
 
 
 
 
 
Business Acquisition, Purchase Price Allocation, Assets Acquired (Liabilities Assumed), Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,903,280,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Business Acquisition, Purchase Price Allocation, Goodwill Amount
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
47,272,000 
3,900,000 
 
 
 
 
 
 
 
 
 
Business Acquisition, Cost of Acquired Entity, Purchase Price
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
214,779,000 
 
132,300,000 
 
 
 
 
 
 
 
Ownership interest in Riley Ridge plant
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
57.50% 
42.50% 
 
 
 
 
 
 
 
Deferred Riley Ridge acquisition consideration
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
15,000,000 
 
 
 
 
 
 
 
 
 
Aggregate purchase price
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4,800,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common stock issued to Encore stockholders
 
 
 
 
135,200,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash payment
833,900,000 
833,900,000 
 
 
833,900,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
366,179,000 
199,779,000 
 
 
 
 
 
 
 
 
 
Denbury shares issued in Encore merger as a percentage of outstanding Denbury shares
 
 
 
 
 
34.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total fair value of common stock issued
 
 
 
 
 
2,100,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Closing price per share of Denbury stock
 
 
 
 
 
 
$ 15.43 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Face value of senior subordinated notes
 
 
 
 
 
 
 
 
 
 
1,000,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Interest Rate, Stated Percentage
 
 
 
 
 
 
 
 
 
8.25% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Borrowing base of Bank Credit Agreement
 
 
 
 
 
 
 
 
 
 
 
1,600,000,000 
1,600,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues recognized from current period acquisitions
 
623,400,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Field Operating Income
 
426,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Business Combination, Acquisition Related Costs
 
 
0 
4,377,000 
92,271,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
800,000 
48,500,000 
3,600,000 
43,800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Employee Related Severance Costs Encore
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
19,800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accounts Payable and Accrued Liabilities, Current
 
 
414,668,000 
429,336,000 
 
 
 
16,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Liabilities, Noncurrent
 
 
23,607,000 
20,756,000 
 
 
 
3,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Anticipated Proceeds From Sale Of Oil And Natural Gas Properties
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
75,000,000 
155,000,000 
 
 
 
 
 
Business Acquisition, Effective Date of Acquisition
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jan. 01, 2012 
Dec. 01, 2011 
 
 
 
 
 
Closing Adjustments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
41,700,000 
 
 
 
 
 
 
 
 
 
13,500,000 
 
 
 
 
Net proceeds from sales of oil and natural gas properties and equipment
 
 
34,750,000 
69,370,000 
1,458,029,000 
 
 
 
 
 
 
 
 
300,000,000 
 
 
 
 
 
213,800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
68,500,000 
141,800,000 
 
32,100,000 
892,100,000 
 
 
Ownership percentage
 
 
 
 
 
 
 
 
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of units sold in the sale of investment
20,900,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of equity Shares received as consideration for sale of Business
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,137,255 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Equity consideration received on sale of business
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
93,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt transferred in disposition
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
234,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proceeds from Divestiture of Businesses
 
 
 
 
1,500,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net proceeds from sale of interest in Genesis Energy, LLC
 
 
 
 
 
 
 
 
 
 
 
 
 
 
79,000,000 
 
84,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Payment under incentive compensation agreement
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
14,900,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pre-tax gain on sale of interest in Genesis
 
 
0 
0 
101,537,000 
 
 
 
 
 
 
 
 
 
 
101,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
After-tax gain on sale of interest in Genesis
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 63,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Asset Retirement Obligations (Rollforward) (Details) (USD $)
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Asset Retirement Obligation Roll Forward Analysis [Roll Forward]
 
 
Beginning asset retirement obligation
$ 93,468,000 
$ 85,744,000 
Liabilities incurred and assumed during period
50,956,000 
12,477,000 
Revisions in estimated retirement obligations
5,334,000 
12,217,000 
Liabilities settled and sold during period
(50,556,000)
(23,257,000)
Accretion expense
7,228,000 
6,287,000 
Ending asset retirement obligation
106,430,000 
93,468,000 
Asset retirement obligations - current
(3,700,000)
(4,742,000)
Long-term asset retirement obligation
102,730,000 
88,726,000 
Asset Retirement Obligations (Textuals) [Abstract]
 
 
Balances in escrow accounts
$ 35,200,000 
$ 34,100,000 
Property And Equipment (Summary of Net Property and Equipment) (Details) (USD $)
Dec. 31, 2012
Dec. 31, 2011
Property, Plant and Equipment [Line Items]
 
 
Less accumulated depletion, depreciation, amortization and impairment
$ (3,180,241,000)
$ (2,627,493,000)
Net property and equipment
8,077,110,000 
8,011,625,000 
Oil and natural gas properties [Abstract]
 
 
Proved properties
6,963,211,000 
7,026,579,000 
Unevaluated properties
809,154,000 
1,157,106,000 
Total
7,772,365,000 
8,183,685,000 
Accumulated depletion and depreciation of oil and natural gas properties
(2,827,256,000)
(2,407,520,000)
Net oil and natural gas properties
4,945,109,000 
5,776,165,000 
CO2 Properties [Abstract]
 
 
CO2 properties
1,032,653,000 
596,003,000 
Pipelines and plants [Abstract]
 
 
CO2 pipelines
1,632,255,000 
1,432,646,000 
Plants under construction
402,871,000 
269,110,000 
Total
2,035,126,000 
1,701,756,000 
Other property and equipment [Abstract]
 
 
Other property and equipment
417,207,000 
157,674,000 
CO2 pipelines not placed in service
346,500,000 
 
Co2 Properties [Member]
 
 
Property, Plant and Equipment [Line Items]
 
 
Less accumulated depletion, depreciation, amortization and impairment
(119,784,000)
(91,666,000)
Net property and equipment
912,869,000 
504,337,000 
Pipelines And Plants [Member]
 
 
Property, Plant and Equipment [Line Items]
 
 
Less accumulated depletion, depreciation, amortization and impairment
(99,185,000)
(65,392,000)
Net property and equipment
1,935,941,000 
1,636,364,000 
Other property and equipment [Member]
 
 
Property, Plant and Equipment [Line Items]
 
 
Less accumulated depletion, depreciation, amortization and impairment
(134,016,000)
(62,915,000)
Net property and equipment
$ 283,191,000 
$ 94,759,000 
Property And Equipment (Summary of Unevaluated Properties Excluded from Amortization) (Details 1) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Summary of unevaluated properties excluded from oil and natural gas properties being amortized
 
 
 
 
Property acquisition costs
$ 110,658 
$ 12,543 
$ 351,712 
$ 115,075 
Exploration and development
106,075 
40,152 
3,155 
8,390 
Capitalized interest
29,249 
30,430 
333 
1,382 
Total
245,982 
83,125 
355,200 
124,847 
Property acquisition costs
589,988 
 
 
 
Exploration and development
157,772 
 
 
 
Capitalized interest
61,394 
 
 
 
Total
$ 809,154 
$ 1,157,106 
 
 
Property And Equipment (Details Textuals) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Property and Equipment (Textuals) [Abstract]
 
Description of Current Status of Project
Our 2012 property acquisition costs were primarily related to the fair value allocated to our Hartzog Draw and Thompson fields. Our 2010 property acquisition costs were primarily related to the fair value allocated to CO2 tertiary potential at our Bell Creek and Cedar Creek Anticline properties, acquired as part of the Encore Merger.  Property acquisition costs for 2009 and prior were primarily related to CO2 tertiary potential at Conroe Field. Exploration and development costs shown as unevaluated properties are primarily associated with our tertiary oil fields that are under development but did not have proved reserves at December 31, 2012.  The most significant development costs incurred during 2012 and 2011 relate to development in preparation for upcoming CO2 floods at Bell Creek and Grieve fields. We have not yet recognized proved reserves in these fields. 
Cost Incurred On Proved Reserves Transferred To Amortization Base
$ 431.1 
Anticipated Timing of Inclusion of Costs in Amortization Calculation
We currently estimate that evaluation of most of these properties and the inclusion of their costs in the amortization base is expected to be completed within five years. 
Long-Term Debt (Components of Long-Term Debt) (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Debt Instrument [Line Items]
 
 
Bank Credit Agreement
$ 700,000 
$ 385,000 
Pipeline financings
236,244 
243,274 
Capital lease obligations
158,260 
4,388 
Total
3,141,428 
2,678,045 
Less: current obligations
(36,966)
(8,316)
Long-term debt and capital lease obligations
3,104,462 
2,669,729 
9.5% Senior Subordinated Notes due 2016 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior subordinated notes
234,038 
236,774 
Including premium of
9,118 
11,854 
Debt Instrument, Interest Rate, Stated Percentage
9.50% 
 
9.75% Senior Subordinated Notes due 2016 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior subordinated notes
412,781 
408,496 
Including discount of
13,569 
17,854 
Debt Instrument, Interest Rate, Stated Percentage
9.75% 
 
8.25% Senior Subordinated Notes due 2020 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior subordinated notes
996,273 
996,273 
Debt Instrument, Interest Rate, Stated Percentage
8.25% 
 
6 3/8% Senior Subordinated Notes due 2021 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior subordinated notes
400,000 
400,000 
Debt Instrument, Interest Rate, Stated Percentage
6.375% 
 
Other Subordinated Notes [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior subordinated notes
3,832 
3,840 
Including premium of
$ 25 
$ 33 
Long-Term Debt (Debt Maturity Schedule) (Details 1) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2012
Indebtedness repayment schedule
 
2013
$ 36,966 
2014
38,481 
2015
39,113 
2016
1,388,592 
2017
34,965 
Thereafter
1,607,737 
Total indebtedness
$ 3,145,854 
Long-Term Debt (Details Textuals) (USD $)
12 Months Ended 3 Months Ended 12 Months Ended 1 Months Ended 0 Months Ended 1 Months Ended 0 Months Ended 12 Months Ended 12 Months Ended 0 Months Ended 1 Months Ended 12 Months Ended 12 Months Ended 1 Months Ended 12 Months Ended 1 Months Ended 12 Months Ended 1 Months Ended 1 Months Ended 12 Months Ended 12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2012
Bank Credit Agreement [Member]
Dec. 31, 2012
Bank Credit Agreement [Member]
Mar. 31, 2010
Bank Credit Agreement [Member]
Mar. 31, 2011
7.5% Senior Subordinated Notes due 2013 [Member]
Extinguishment One [Member]
Mar. 31, 2011
7.5% Senior Subordinated Notes due 2013 [Member]
Extinguishment Two [Member]
Mar. 31, 2011
7.5% Senior Subordinated Notes due 2015 [Member]
Extinguishment One [Member]
Mar. 21, 2011
7.5% Senior Subordinated Notes due 2015 [Member]
Extinguishment Two [Member]
Feb. 19, 2013
9.5% Senior Subordinated Notes due 2016 [Member]
Dec. 31, 2012
9.5% Senior Subordinated Notes due 2016 [Member]
Mar. 8, 2010
9.5% Senior Subordinated Notes due 2016 [Member]
Dec. 31, 2012
9.5% Senior Subordinated Notes due 2016 [Member]
Debt Instrument, Redemption, Period One [Member]
Dec. 31, 2012
9.5% Senior Subordinated Notes due 2016 [Member]
Debt Instrument, Redemption, Period Two [Member]
Dec. 31, 2012
9.5% Senior Subordinated Notes due 2016 [Member]
Debt Instrument, Redemption, Period Three [Member]
Dec. 31, 2012
9.5% Senior Subordinated Notes due 2016 [Member]
Initial Redemption Period with Make-Whole Premium [Member]
Mar. 31, 2011
9.5% Senior Subordinated Notes due 2016 [Member]
Extinguishment Two [Member]
Feb. 19, 2013
9.75% Senior Subordinated Notes due 2016 [Member]
Feb. 27, 2013
9.75% Senior Subordinated Notes due 2016 [Member]
Feb. 28, 2009
9.75% Senior Subordinated Notes due 2016 [Member]
Dec. 31, 2012
9.75% Senior Subordinated Notes due 2016 [Member]
Jun. 30, 2009
9.75% Senior Subordinated Notes due 2016 [Member]
Dec. 31, 2012
9.75% Senior Subordinated Notes due 2016 [Member]
Debt Instrument, Redemption, Period One [Member]
Feb. 28, 2010
8.25% Senior Subordinated Notes due 2020 [Member]
Dec. 31, 2012
8.25% Senior Subordinated Notes due 2020 [Member]
Dec. 31, 2012
8.25% Senior Subordinated Notes due 2020 [Member]
Debt Instrument, Redemption, Period One [Member]
Dec. 31, 2012
8.25% Senior Subordinated Notes due 2020 [Member]
Debt Instrument, Redemption, Period Two [Member]
Dec. 31, 2012
8.25% Senior Subordinated Notes due 2020 [Member]
Debt Instrument, Redemption, Period Three [Member]
Dec. 31, 2012
8.25% Senior Subordinated Notes due 2020 [Member]
Debt Instrument, Redemption, Period Four [Member]
Dec. 31, 2012
8.25% Senior Subordinated Notes due 2020 [Member]
Initial Redemption Period with Proceeds from Equity Offering [Member]
Dec. 31, 2012
8.25% Senior Subordinated Notes due 2020 [Member]
Initial Redemption Period with Make-Whole Premium [Member]
Feb. 28, 2011
6 3/8% Senior Subordinated Notes due 2021 [Member]
Dec. 31, 2012
6 3/8% Senior Subordinated Notes due 2021 [Member]
Dec. 31, 2012
6 3/8% Senior Subordinated Notes due 2021 [Member]
Debt Instrument, Redemption, Period One [Member]
Dec. 31, 2012
6 3/8% Senior Subordinated Notes due 2021 [Member]
Debt Instrument, Redemption, Period Two [Member]
Dec. 31, 2012
6 3/8% Senior Subordinated Notes due 2021 [Member]
Debt Instrument, Redemption, Period Three [Member]
Dec. 31, 2012
6 3/8% Senior Subordinated Notes due 2021 [Member]
Debt Instrument, Redemption, Period Four [Member]
Dec. 31, 2012
6 3/8% Senior Subordinated Notes due 2021 [Member]
Initial Redemption Period with Proceeds from Equity Offering [Member]
Dec. 31, 2012
6 3/8% Senior Subordinated Notes due 2021 [Member]
Initial Redemption Period with Make-Whole Premium [Member]
Feb. 27, 2013
4 5/8% Senior Subordinated Notes due 2023 [Member]
Feb. 5, 2013
4 5/8% Senior Subordinated Notes due 2023 [Member]
Feb. 5, 2013
4 5/8% Senior Subordinated Notes due 2023 [Member]
Feb. 27, 2013
4 5/8% Senior Subordinated Notes due 2023 [Member]
Debt Instrument, Redemption, Period One [Member]
Feb. 27, 2013
4 5/8% Senior Subordinated Notes due 2023 [Member]
Debt Instrument, Redemption, Period Two [Member]
Feb. 27, 2013
4 5/8% Senior Subordinated Notes due 2023 [Member]
Debt Instrument, Redemption, Period Three [Member]
Feb. 27, 2013
4 5/8% Senior Subordinated Notes due 2023 [Member]
Debt Instrument, Redemption, Period Four [Member]
Feb. 27, 2013
4 5/8% Senior Subordinated Notes due 2023 [Member]
Initial Redemption Period with Proceeds from Equity Offering [Member]
Feb. 27, 2013
4 5/8% Senior Subordinated Notes due 2023 [Member]
Initial Redemption Period with Make-Whole Premium [Member]
Dec. 31, 2012
Minimum [Member]
Bank Credit Agreement [Member]
Dec. 31, 2012
Maximum [Member]
Bank Credit Agreement [Member]
Dec. 31, 2012
Equipment [Member]
Dec. 31, 2010
Post-tax [Member]
Dec. 31, 2012
Post-tax [Member]
Equipment [Member]
Dec. 31, 2010
Pre-tax [Member]
Dec. 31, 2012
Pre-tax [Member]
Equipment [Member]
Debt Instrument [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Property, Plant and Equipment, Other, Gross
$ 417,207,000 
$ 157,674,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 155,600,000 
 
 
 
 
$1.6 Billion Revolving Credit Agreement [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.375% 
0.50% 
 
 
 
 
 
Line of Credit Facility, Initiation Date
 
 
 
 
Mar. 31, 2010 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Borrowing base of Bank Credit Agreement
 
 
 
1,600,000,000 
1,600,000,000 
1,600,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maturity date of Bank Credit Agreement
 
 
 
 
May 31, 2016 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Collateral
 
 
 
 
The Bank Credit Agreement is secured by substantially all of the proved oil and natural gas properties of our restricted subsidiaries and by the equity interests of our restricted subsidiaries.  In addition, our obligations under the Bank Credit Agreement are guaranteed jointly and severally by all of our subsidiaries, other than minor subsidiaries. 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Covenant Compliance
 
 
 
During 2012, we received a limited waiver of any oil hedging noncompliance that may occur as a result of the Bakken Exchange Transaction during the period commencing on the closing date continuing through and including December 31, 2013 
The Bank Credit Agreement was amended during 2012 concurrent with our change in classification of equipment leases from operating to capital (see Capital Leases below), and we received a waiver of any applicable violations of the provisions of the Bank Credit Agreement resulting from such correction and the recording of our equipment leases as debt. 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Permissable Amount Of Capital Lease Obligations
 
 
 
300,000,000 
300,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Permissable Amount Of Other Unsecured Debt
 
 
 
40,000,000 
40,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Repayment terms of Bank Credit Agreement
 
 
 
 
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 not to exceed four months. 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount outstanding under revolving credit agreements
700,000,000 
385,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Restrictive covenants on Bank Credit Agreement
•a limitation on the ability to repurchase Denbury common stock and to pay dividends on Denbury common stock, in an aggregate amount not to exceed $1.2 billion during the term of the Bank Credit Agreement, subject to certain restrictions;•a requirement to maintain a current ratio, as determined under the Bank Credit Agreement, of not less than 1.0 to 1.0;•a maximum permitted ratio of debt to adjusted EBITDA (as defined in the Bank Credit Agreement) of us and our restricted subsidiaries of not more than 4.25 to 1.0; and•a prohibition against incurring debt, subject to permitted exceptions. 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest rates on Bank Credit Agreement
 
 
 
 
Loans under the Bank Credit Agreement are subject to varying rates of interest based on (1) the total outstanding borrowings in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan.  Eurodollar loans bear interest at the Adjusted Eurodollar Rate (as defined in the Bank Credit Agreement) plus the applicable margin in a range from 1.5% to 2.5% based on the ratio of outstanding borrowings to the borrowing base, and base rate loans bear interest at the Base Rate (as defined in the Bank Credit Agreement) plus the applicable margin in a range from 0.5% to 1.5% based on the ratio of outstanding borrowings to the borrowing base.  The “Eurodollar rate” for any interest period (either one, two, three, six, nine or twelve months, as selected by us) is the rate per year equal to LIBOR, as published by Reuters or another source designated by JPMorgan, for deposits in dollars for a similar interest period.  The “base rate” is calculated as the highest of (1) the annual rate of interest announced by JPMorgan as its “prime rate,” (2) the federal funds effective rate plus 0.5%, and (3) the Adjusted Eurodollar Rate (as defined in the Bank Credit Agreement) for a one-month interest period plus 1.0%. 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commitment fee on Bank Credit Agreement
 
 
 
 
We incur a commitment fee of either 0.375% or 0.5%, based on the ratio of outstanding borrowings to the borrowing base, on the unused availability under the Bank Credit Agreement. 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instruments [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
35.00% 
100.00% 
 
 
 
 
 
 
35.00% 
100.00% 
 
 
 
 
 
 
 
35.00% 
100.00% 
 
 
 
 
 
 
 
Debt Instrument, Issuance Date
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Feb. 28, 2009 
 
 
 
Feb. 28, 2010 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Redemption Period, Start Date
 
 
 
 
 
 
 
 
 
 
 
 
 
 
after May 1, 2014 
after May 1, 2015 
prior to May 1, 2013 
 
 
 
 
 
 
after May 1, 2013 
 
 
after February 15, 2015 
after February 15, 2016 
after February 15, 2017 
after February 15, 2018 
Prior to February 15, 2013 
prior to February 15, 2015 
 
 
August 15, 2016 
August 15, 2017 
August 15, 2018 
August 15, 2019 
Prior to August 15, 2014 
prior to August 15, 2016 
 
 
 
on or after January 15, 2018 
on or after January 15, 2019 
on or after January 15, 2020 
on or after January 15, 2021 
Prior to July 15, 2016 
 
 
 
 
 
 
 
 
Interest in guarantor subsidiaries
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Face value of senior subordinated notes
 
 
 
 
 
 
 
 
 
 
 
224,900,000 
225,000,000 
 
 
 
 
 
 
 
420,000,000 
426,400,000 
6,400,000 
 
1,000,000,000 
 
 
 
 
 
 
 
400,000,000 
 
 
 
 
 
 
 
 
 
1,200,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate on senior subordinated notes
 
 
 
 
 
 
 
 
 
 
 
9.50% 
 
 
 
 
 
 
 
 
 
9.75% 
 
 
 
8.25% 
 
 
 
 
 
 
 
6.375% 
 
 
 
 
 
 
 
4.625% 
4.625% 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proceeds From Issuance of Subordinated Long Term Debt, Net of Commissions and Fees
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
980,000,000 
 
 
 
 
 
 
 
393,000,000 
 
 
 
 
 
 
 
1,180,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maturity date
 
 
 
 
 
 
 
 
 
 
 
May 01, 2016 
 
 
 
 
 
 
 
 
 
Mar. 01, 2016 
 
 
 
Feb. 15, 2020 
 
 
 
 
 
 
 
Aug. 15, 2021 
 
 
 
 
 
 
Jul. 15, 2023 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Selling price of debt instrument as a percentage of par
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
92.816% 
 
 
 
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Description of covenants on senior subordinated notes
 
 
 
 
 
 
 
 
 
 
 
The indenture governing the 9½% Notes includes various covenants and restrictions, including providing a put right by holders upon a change of control. 
 
 
 
 
 
 
 
 
 
The indenture governing the 9¾% Notes 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 indenture governing the 2020 Notes 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 indenture governing the 2021 Notes 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. 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Sinking Fund Description
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
The 9¾% Notes are not subject to any sinking fund requirements. 
 
 
 
The 2020 Notes are not subject to any sinking fund requirements. 
 
 
 
 
 
 
 
The 2021 Notes are not subject to any sinking fund requirements. 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Collateral
 
 
 
 
 
 
 
 
 
 
 
All of our subsidiaries, other than minor subsidiaries, guarantee this debt jointly and severally. 
 
 
 
 
 
 
 
 
 
All of our subsidiaries, other than minor subsidiaries, guarantee this debt jointly and severally. 
 
 
 
All of our subsidiaries, other than minor subsidiaries, guarantee this debt jointly and severally. 
 
 
 
 
 
 
 
All of our subsidiaries, other than minor subsidiaries, guarantee this debt jointly and severally. 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Repurchased Face Amount
 
 
 
 
 
 
169,600,000 
 
220,900,000 
79,100,000 
186,700,000 
 
 
 
 
 
 
55,400,000 
191,700,000 
 
 
 
 
 
3,700,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Effective yield to maturity
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
11.25% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Redemption Price, Percentage
 
 
 
 
 
 
100.625% 
100.00% 
104.125% 
103.75% 
106.87% 
 
 
104.75% 
102.375% 
100.00% 
100.00% 
 
105.425% 
104.875% 
 
 
 
 
 
 
104.125% 
102.75% 
101.375% 
100.00% 
108.25% 
100.00% 
 
 
103.188% 
102.125% 
101.062% 
100.00% 
106.375% 
100.00% 
 
 
 
 
 
 
 
104.625% 
100.00% 
 
 
 
 
 
 
 
Debt Instrument, Frequency of Periodic Payment
 
 
 
 
 
 
 
 
 
 
 
semi-annually, on May 1 and November 1, at a rate of 9½% 
 
 
 
 
 
 
 
 
 
March 1 and September 1 of each year 
 
 
 
February 15 and August 15 of each year 
 
 
 
 
 
 
 
February 15 and August 15 of each year 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Quantifying Misstatement in Current Year Financial Statements, Amount
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6,000,000 
5,200,000 
9,600,000 
8,400,000 
Capital Lease Obligations, Noncurrent
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
138,900,000 
 
 
 
 
Capital Lease Obligations, Current
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
25,100,000 
 
 
 
 
Lease period included in long term transportation service agreement
20-year 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unamortized debt issuance costs
56,500,000 
69,600,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Loss on early extinguishment of debt
$ 0 
$ 16,131,000 
$ 0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Taxes (Income Tax Provision (Benefit)) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Current income tax expense (benefit)
 
 
 
Federal
$ 57,720 
$ (12,552)
$ 15,683 
State
18,034 
20,801 
17,511 
Total current income tax expense
75,754 
8,249 
33,194 
Deferred income tax expense
 
 
 
Federal
239,862 
329,715 
143,381 
State
15,881 
12,748 
16,968 
Total deferred income tax expense
255,743 
342,463 
160,349 
Total income tax expense
$ 331,497 
$ 350,712 
$ 193,543 
Income Taxes (Components of Deferred Tax Assets and Liabilities) (Details 1) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Deferred tax assets
 
 
Loss carryforwards - federal
$ 0 
$ 13,970 
Loss carryforwards - state
35,007 
41,960 
Tax credit carryover
34,837 
34,829 
Derivative contracts
7,252 
3,551 
Enhanced oil recovery credit carryforwards
17,346 
53,381 
Stock based compensation
28,387 
32,566 
Other
37,226 
35,279 
Total deferred tax assets
160,055 
215,536 
Deferred tax liabilities
 
 
Property and equipment
(2,277,388)
(2,078,143)
Other
(6,963)
(5,813)
Total deferred tax liabilities
(2,284,351)
(2,083,956)
Total net deferred tax liability
$ (2,124,296)
$ (1,868,420)
Income Taxes (Schedule of Effective Tax Rate Reconciliation) (Details 2) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Income Tax Expense (Benefit), Continuing Operations, Income Tax Reconciliation [Abstract]
 
 
 
Income tax provision calculated using the federal statutory income tax rate
$ 299,900 
$ 323,416 
$ 167,674 
State income taxes, net of federal income tax benefit
30,955 
29,555 
13,087 
Effect of statutory rate change
(429)
(578)
11,502 
Other
1,071 
(1,681)
1,280 
Total income tax expense
$ 331,497 
$ 350,712 
$ 193,543 
Income Taxes (Details Textuals) (USD $)
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Income Tax Disclosure [Abstract]
 
 
Loss carryforwards - state
$ 35,007,000 
$ 41,960,000 
Enhanced oil recovery credit carryforwards
17,346,000 
53,381,000 
Tax credit carryover
34,837,000 
34,829,000 
Operating Loss Carryforwards, Expiration Dates
Our state NOLs expire in various years, starting in 2015, although most do not begin to expire until 2024. 
 
Tax Credit Carryforward, Expiration Date
Jan. 01, 2025 
 
Valuation Allowance, Amount
0 
 
Tax refund due to change in tax accounting method
$ 10,600,000 
 
Income Tax Examination, Description
We file consolidated and separate income tax returns in the U.S. federal jurisdiction and in many state jurisdictions.  The IRS concluded its examination of our 2006, 2007 and 2008 tax years during the fourth quarter of 2011 with no adjustments.  During the third quarter of 2012, the IRS concluded its audit of Encore Acquisition Company for the tax years 2008, 2009 and 2010 and Encore Operating LP for the tax years 2008 and 2009, with no significant adjustments. During the fourth quarter of 2012, the state of Mississippi concluded its audit of Denbury for the tax years 2004, 2005, 2006, and 2007, with no significant adjustments.  Our income tax returns for tax years ending 2009 through 2011 currently remain subject to examination by the appropriate taxing authorities. We have not paid any significant interest or penalties associated with our income taxes. 
 
Stockholders' Equity (Details) (USD $)
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Defined Contribution Benefit Plans Disclosures [Line Items]
 
 
 
Shares available for future awards
11,300,000 
 
 
Total compensation expenses
$ 29,310,000 
$ 33,190,000 
$ 36,091,000 
Employee Stock Purchase Plan [Member]
 
 
 
Defined Contribution Benefit Plans Disclosures [Line Items]
 
 
 
Maximum number of common stock shares authorized for issuance under Plan
9,900,000 
 
 
Shares available for future awards
462,131 
 
 
Total compensation expenses
5,700,000 
4,800,000 
3,500,000 
Employee Stock Purchase Plan [Member] |
Maximum [Member]
 
 
 
Defined Contribution Benefit Plans Disclosures [Line Items]
 
 
 
Employee Contribution Rate
10.00% 
 
 
Employer Contribution Rate
75.00% 
 
 
Benefit Plan, 401K [Member]
 
 
 
Defined Contribution Benefit Plans Disclosures [Line Items]
 
 
 
Employer's matching contributions
$ 8,000,000 
$ 7,100,000 
$ 5,700,000 
Benefit Plan, 401K [Member] |
Maximum [Member]
 
 
 
Defined Contribution Benefit Plans Disclosures [Line Items]
 
 
 
Employee Contribution Rate
6.00% 
 
 
Employer Contribution Rate
100.00% 
 
 
Stockholders' Equity (Share Repurchase Program) (Details 1) (USD $)
12 Months Ended 15 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2012
Rate
Stock Repurchase Program, Authorized Amount
$ 771,200,000 
$ 500,000,000 
 
 
Treasury Stock, Shares, Acquired
 
 
 
31,100,000 
Treasury Stock Percentage Repurchased
 
 
 
7.70% 
Treasury Stock, Value, Acquired, Cost Method
(8,125,000)
(9,683,000)
(6,729,000)
(461,900,000)
Stock Repurchase Program, Remaining Authorized Repurchase Amount
309,300,000 
 
 
 
Treasury Stock Repurchase Program [Member]
 
 
 
 
Treasury Stock, Shares, Acquired
17,000,000 
14,100,000 
 
 
Treasury Stock, Value, Acquired, Cost Method
$ (266,700,000)
$ (195,200,000)
 
 
Treasury Stock Acquired, Average Cost Per Share
$ 15.71 
$ 13.83 
 
 
Stock Compensation Plans (Schedule of Share-Based Compensation) (Details 1) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
 
 
 
Total compensation expenses
$ 29,310 
$ 33,190 
$ 36,091 
Stock-based compensation capitalized
8,587 
6,998 
3,702 
Total Cost Of Stock Based Compensation Arrangements
37,897 
40,188 
39,793 
Income tax benefit recognized for stock-based compensation arrangements
15,131 
18,383 
8,462 
General and Administrative Expense [Member]
 
 
 
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
 
 
 
Total compensation expenses
26,463 
30,256 
28,169 
Lease Operating Expense [Member]
 
 
 
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
 
 
 
Total compensation expenses
2,847 
2,621 
2,056 
Encore Merger Expense [Member]
 
 
 
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
 
 
 
Total compensation expenses
$ 0 
$ 313 
$ 5,866 
Stock Compensation Plans (Summary of SAR Assumptions) (Details 2) (Stock Appreciation Rights (SARs) [Member], USD $)
1 Months Ended 12 Months Ended
Jan. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Summary of Stock Options and SARs
 
 
 
 
Weighted average grant-date fair value, granted
 
$ 8.90 
$ 9.68 
$ 8.45 
Risk-free interest rate
 
0.79% 
1.74% 
2.19% 
Expected volatility
 
64.90% 
63.30% 
65.00% 
Dividend yield
 
0.00% 
0.00% 
0.00% 
Minimum [Member]
 
 
 
 
Summary of Stock Options and SARs
 
 
 
 
Weighted average grant-date fair value, granted
$ 5.42 
 
 
 
Expected life
 
4 years 
4 years 
4 years 
Maximum [Member]
 
 
 
 
Summary of Stock Options and SARs
 
 
 
 
Weighted average grant-date fair value, granted
$ 8.72 
 
 
 
Expected life
 
5 years 
5 years 
4 years 3 months 
Stock Compensation Plans (Summary of Stock Option and SARs Activity) (Details 3) (USD $)
In Thousands, except Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Share-based Arrangements with Employees and Nonemployees [Abstract]
 
Outstanding at beginning of period
11,949,610 
Weighted Average Exercise Price, Beginning of Period
$ 13.56 
Granted
1,066,294 
Weighted average exercise price, granted
$ 17.14 
Exercised
(2,029,570)
Weighted average exercise price, exercised
$ 8.03 
Forfeited or expired
(541,199)
Weighted average exercise price, forfeited or expired
$ 18.34 
Outstanding at end of period
10,445,135 
Weighted Average Exercise Price, End of Period
$ 14.75 
Weighted average remaining contractual life of outstanding stock option and SARs
3 years 8 months 
Aggregate intrinsic value of stock option and SARs outstanding
$ 31,861 
Exercisable at end of period
7,115,744 
Weighted average price, exercisable at end of period
$ 13.81 
Weighted average remaining contractual life of exercisable stock option and SARs
3 years 2 months 
Aggregate intrinsic value of exercisable options and SARs
$ 30,031 
Stock Compensation Plans Stock Compensation Plans (Summary of Value of Stock Options and SARs) (Details 4) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
 
 
 
Intrinsic value of stock options exercised
$ 17,315 
$ 20,463 
$ 12,670 
Grant-date fair value of stock options and SARs vested
$ 26,391 
$ 11,416 
$ 8,689 
Stock Compensation Plans Stock Compensation Plans (Summary of Cash Received and Tax Benefit Realized) (Details 5) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Summary of Cash Received and Tax Benefit Realized [Abstract]
 
 
 
Cash received from stock option exercises
$ 6,022 
$ 4,685 
$ 4,867 
Tax benefit realized for the exercises of stock options and SARs
$ 241 
$ 879 
$ 4,603 
Stock Compensation Plans Stock Compensation Plans (Summary of Vesting Date Fair Value of Awards - 2004 Restricted Stock Plan) (Details 6) (Omnibus Stock and Incentive Plan [Member], USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Omnibus Stock and Incentive Plan [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Fair value of restricted stock vested
$ 22,332 
$ 12,355 
$ 12,731 
Stock Compensation Plans Stock Compensation Plans (Summary of 2004 Restricted Stock Plan) (Details 7) (Restricted Stock 2004 Plan [Member], USD $)
12 Months Ended
Dec. 31, 2012
Restricted Stock 2004 Plan [Member]
 
Nonvested Resticted Stock Outstanding [Line Items]
 
Non-vested at beginning of period
3,131,435 
Weighted average grant-date fair value, beginning of period
$ 14.82 
Granted
1,909,739 
Weighted average grant-date fair value, granted
$ 16.94 
Vested
(1,378,496)
Weighted average grant-date fair value, vested
$ 15.38 
Forfeited
(256,471)
Weighted average grant-date fair value, forfeited
$ 17.08 
Nonvested at end of period
3,406,207 
Weighted average grant-date fair value, end of period
$ 15.60 
Stock Compensation Plans Stock Compensation Plans (Summary of Vesting Date Fair Value of Awards - Restricted Stock Legacy Encore Plan) (Details 8) (Restricted Stock Encore [Member], USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Restricted Stock Encore [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Fair value of restricted stock vested
$ 584 
$ 2,259 
$ 6,571 
Stock Compensation Plans Stock Compensation Plans (Summary of Encore Restricted Stock) (Details 9) (Restricted Stock Encore [Member], USD $)
12 Months Ended
Dec. 31, 2012
Restricted Stock Encore [Member]
 
Nonvested Resticted Stock Outstanding [Line Items]
 
Non-vested at beginning of period
103,043 
Weighted average grant-date fair value, beginning of period
$ 15.43 
Vested
(36,049)
Weighted average grant-date fair value, vested
$ 15.43 
Forfeited
(10,736)
Weighted average grant-date fair value, forfeited
$ 15.43 
Nonvested at end of period
56,258 
Weighted average grant-date fair value, end of period
$ 15.43 
Stock Compensation Plans Stock Compensation Plans (TSR Award Assumptions) (Details 10) (TSR Performance Based Equity Awards Granted in 2012 [Member] [Member], USD $)
12 Months Ended
Dec. 31, 2012
Rate
TSR Performance Based Equity Awards Granted in 2012 [Member] [Member]
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
Weighted average grant-date fair value, granted
$ 24.68 
Risk-free interest rate
0.42% 
Expected life
2 years 9 months 22 days 
Expected volatility
45.20% 
Dividend yield
0.00% 
Stock Compensation Plans Stock Compensation Plans (Summary of Performance Based Equity Awards) (Details 11) (USD $)
12 Months Ended
Dec. 31, 2012
Performance Based TSR Awards [Member]
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
Non-vested at beginning of period
0 
Weighted average grant-date fair value, beginning of period
$ 0.00 
Granted
96,325 
Weighted average grant-date fair value, granted
$ 24.68 
Vested
0 
Weighted average grant-date fair value, vested
$ 0.00 
Forfeited
(9,408)
Weighted average grant-date fair value, forfeited
$ 24.68 
Nonvested at end of period
86,917 
Weighted average grant-date fair value, end of period
$ 24.68 
Performance Based Operational Award [Member]
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
Non-vested at beginning of period
214,627 
Weighted average grant-date fair value, beginning of period
$ 18.71 
Granted
110,615 
Weighted average grant-date fair value, granted
$ 17.27 
Vested
(214,627)
Weighted average grant-date fair value, vested
$ 18.71 
Forfeited
(10,422)
Weighted average grant-date fair value, forfeited
$ 17.27 
Nonvested at end of period
100,193 
Weighted average grant-date fair value, end of period
$ 17.27 
Stock Compensation Plans Stock Compensation Plans (Summary of Vesting Date Fair Value of Awards) (Details 12) (Performance Based Operational Award [Member], USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Performance Based Operational Award [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Vesting date fair value
$ 2,191 
$ 10,892 
$ 7,532 
Stock Compensation Plans (Details Textual) (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2012
plans
Stock Compensation Plans (Textuals) [Abstract]
 
Number of stock compensation plans
2 
Shares available for future awards
11,300,000 
Stock compensation plan term
The stock options and SARs expire over terms not to exceed 10 years from the date of grant, 90 days after termination of employment, 90 days or one year after permanent disability, depending on the plan, or one year after the death of the optionee. 
2004 Omnibus Stock and Incentive Plan
 
Stock Compensation Plans (Textuals) [Abstract]
 
Maximum number of common stock shares authorized for issuance under Plan
29,500,000 
Total compensation cost to be recognized in future periods
$ 29.0 
Weighted average period over which remaining cost will be recognized
2 years 7 months 10 days 
Performance Equity Awards [Member] |
Minimum [Member]
 
Stock Compensation Plans (Textuals) [Abstract]
 
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period
1 year 3 months 0 days 
Performance Equity Awards [Member] |
Maximum [Member]
 
Stock Compensation Plans (Textuals) [Abstract]
 
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period
3 years 3 months 0 days 
Stock Appreciation Rights (SARs) [Member]
 
Stock Compensation Plans (Textuals) [Abstract]
 
Total compensation cost to be recognized in future periods
13.8 
Weighted average period over which remaining cost will be recognized
2 years 
Encore Restricted Stock [Member]
 
Stock Compensation Plans (Textuals) [Abstract]
 
Total compensation cost to be recognized in future periods
$ 0.5 
Weighted average period over which remaining cost will be recognized
1 year 1 month 6 days 
Performance Based Equity Awards Granted in 2012 [Member]
 
Stock Compensation Plans (Textuals) [Abstract]
 
Vesting level (percentage)
56.00% 
Derivative Instruments and Hedging Activities (Summary of Derivative expense (income)) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
Total derivatives expense (income) - oil & natural gas
 
 
$ (23,833)
Derivatives expense (income)
(4,834)
(52,497)
(23,833)
Oil Contracts [Member]
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
Payment (receipt) on settlement of derivative contracts
9,991 
25,128 
93,417 
Fair value adjustments to derivative contracts - expense (income)
(10,904)
(58,980)
(44,441)
Total derivatives expense (income) - oil & natural gas
(913)
(33,852)
48,976 
Natural Gas Contracts [Member]
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
Payment (receipt) on settlement of derivative contracts
(27,871)
(27,505)
(61,805)
Fair value adjustments to derivative contracts - expense (income)
23,950 
8,860 
(8,585)
Total derivatives expense (income) - oil & natural gas
(3,921)
(18,645)
(70,390)
Interest Rate Swap [Member]
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
Ineffectiveness on interest rate swaps
$ 0 
$ 0 
$ (2,419)
Derivative Instruments and Hedging Activities (Oustanding commodity derivative contracts) (Details 1)
Dec. 31, 2012
Year 2013 [Member] |
Q1 [Member]
 
Derivative [Line Items]
 
Weighted average floor price
78.91 
Weighted average ceiling price
108.01 
Volume per day (Bbl per day)
55,000 
Year 2013 [Member] |
Q2 [Member]
 
Derivative [Line Items]
 
Weighted average floor price
79.64 
Weighted average ceiling price
108.61 
Volume per day (Bbl per day)
56,000 
Year 2013 [Member] |
Q3 [Member]
 
Derivative [Line Items]
 
Weighted average floor price
79.64 
Weighted average ceiling price
109.15 
Volume per day (Bbl per day)
56,000 
Year 2013 [Member] |
Q4 [Member]
 
Derivative [Line Items]
 
Weighted average floor price
80.00 
Weighted average ceiling price
117.53 
Volume per day (Bbl per day)
54,000 
Year 2014 [Member] |
Q1 [Member]
 
Derivative [Line Items]
 
Weighted average floor price
80.00 
Weighted average ceiling price
102.44 
Volume per day (Bbl per day)
52,000 
Year 2014 [Member] |
Q2 [Member]
 
Derivative [Line Items]
 
Weighted average floor price
80.00 
Weighted average ceiling price
102.44 
Volume per day (Bbl per day)
52,000 
Year 2014 [Member] |
Q3 [Member]
 
Derivative [Line Items]
 
Weighted average floor price
80.00 
Weighted average ceiling price
97.46 
Volume per day (Bbl per day)
48,000 
Year 2014 [Member] |
Q4 [Member]
 
Derivative [Line Items]
 
Weighted average floor price
80.00 
Weighted average ceiling price
97.46 
Volume per day (Bbl per day)
48,000 
Minimum [Member] |
Year 2013 [Member] |
Q1 [Member]
 
Derivative [Line Items]
 
Derivative Price Range
70.00 
Minimum [Member] |
Year 2013 [Member] |
Q2 [Member]
 
Derivative [Line Items]
 
Derivative Price Range
75.00 
Minimum [Member] |
Year 2013 [Member] |
Q3 [Member]
 
Derivative [Line Items]
 
Derivative Price Range
75.00 
Minimum [Member] |
Year 2013 [Member] |
Q4 [Member]
 
Derivative [Line Items]
 
Derivative Price Range
80.00 
Minimum [Member] |
Year 2014 [Member] |
Q1 [Member]
 
Derivative [Line Items]
 
Derivative Price Range
80.00 
Minimum [Member] |
Year 2014 [Member] |
Q2 [Member]
 
Derivative [Line Items]
 
Derivative Price Range
80.00 
Minimum [Member] |
Year 2014 [Member] |
Q3 [Member]
 
Derivative [Line Items]
 
Derivative Price Range
80.00 
Minimum [Member] |
Year 2014 [Member] |
Q4 [Member]
 
Derivative [Line Items]
 
Derivative Price Range
80.00 
Maximum [Member] |
Year 2013 [Member] |
Q1 [Member]
 
Derivative [Line Items]
 
Derivative Price Range
113.00 
Maximum [Member] |
Year 2013 [Member] |
Q2 [Member]
 
Derivative [Line Items]
 
Derivative Price Range
121.50 
Maximum [Member] |
Year 2013 [Member] |
Q3 [Member]
 
Derivative [Line Items]
 
Derivative Price Range
133.10 
Maximum [Member] |
Year 2013 [Member] |
Q4 [Member]
 
Derivative [Line Items]
 
Derivative Price Range
127.50 
Maximum [Member] |
Year 2014 [Member] |
Q1 [Member]
 
Derivative [Line Items]
 
Derivative Price Range
104.50 
Maximum [Member] |
Year 2014 [Member] |
Q2 [Member]
 
Derivative [Line Items]
 
Derivative Price Range
104.50 
Maximum [Member] |
Year 2014 [Member] |
Q3 [Member]
 
Derivative [Line Items]
 
Derivative Price Range
98.80 
Maximum [Member] |
Year 2014 [Member] |
Q4 [Member]
 
Derivative [Line Items]
 
Derivative Price Range
98.80 
Derivative Instruments and Hedging Activities (Derivatives by balance sheet location) (Details 2) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Derivatives, Fair Value [Line Items]
 
 
Derivative Assets, Current
$ 19,477 
$ 47,402 
Derivative Assets, Noncurrent
36 
29 
Derivative Liabilities, Current
(2,842)
(26,523)
Derivative Liabilities, Noncurrent
(23,781)
(18,872)
Total derivatives not designated as hedging instruments
(7,110)
2,036 
Crude Oil Contracts [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative Assets, Current
19,477 
23,452 
Derivative Assets, Noncurrent
36 
29 
Derivative Liabilities, Current
(2,659)
(22,610)
Derivative Liabilities, Noncurrent
(23,781)
(18,702)
Natural Gas Contracts [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative Assets, Current
0 
23,950 
Deferred Premiums [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative Liabilities, Current
(183)
(3,913)
Derivative Liabilities, Noncurrent
$ 0 
$ (170)
Fair Value Measurements (Fair Value Hierarchy) (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Assets, Fair Value Disclosure [Abstract]
 
 
Short-term investments
$ 0 
$ 86,682 
Oil and natural gas derivative contracts
19,513 
47,431 
Liabilities, Fair Value Disclosure [Abstract]
 
 
Oil and natural gas derivative contracts
(26,440)
(41,312)
Total
(6,927)
92,801 
Quoted Prices in Active Markets (Level 1) [Member]
 
 
Assets, Fair Value Disclosure [Abstract]
 
 
Short-term investments
 
86,682 
Oil and natural gas derivative contracts
0 
0 
Liabilities, Fair Value Disclosure [Abstract]
 
 
Oil and natural gas derivative contracts
0 
0 
Total
0 
86,682 
Significant Other Observable Inputs (Level 2) [Member]
 
 
Assets, Fair Value Disclosure [Abstract]
 
 
Short-term investments
 
0 
Oil and natural gas derivative contracts
19,513 
23,481 
Liabilities, Fair Value Disclosure [Abstract]
 
 
Oil and natural gas derivative contracts
(26,440)
(41,312)
Total
(6,927)
(17,831)
Significant Unobservable Inputs (Level 3) [Member]
 
 
Assets, Fair Value Disclosure [Abstract]
 
 
Short-term investments
 
0 
Oil and natural gas derivative contracts
0 
23,950 
Liabilities, Fair Value Disclosure [Abstract]
 
 
Oil and natural gas derivative contracts
0 
0 
Total
$ 0 
$ 23,950 
Fair Value Measurements (Level 3 Rollforward) (Details 1) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
The changes in the fair value of Denbury Level 3 assets and liabilities
 
 
Fair value of Level 3 instruments, beginning of year
$ 23,950 
$ 16,478 
Unrealized gains on commodity derivative contracts included in net earnings
3,921 
13,384 
Receipts on settlement of commodity derivative contracts
(27,871)
(5,912)
Fair value of Level 3 instruments, end of year
0 
23,950 
The amount of total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held at the reporting date
$ 0 
$ 13,384 
Fair Value Measurements (Details Textuals) (USD $)
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
 
Other Asset Impairment Charges
$ 17,515,000 
$ 22,951,000 
$ 0 
Long-term Debt, Fair Value
2,956,900,000 
2,638,200,000 
 
Bank Credit Facility, Fair Value Disclosure, Significant Assumptions
The carrying value of our revolving bank credit facility approximates fair value, as it is subject to short-term floating interest rates that approximate the rates available to us for those periods. 
 
 
Faustina Investment Impairment [Member]
 
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
 
Other Asset Impairment Charges
$ 15,100,000 
 
 
Commitments and Contingencies (Future Non-cancelable Lease Payments) (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2012
Commitments and Contingencies Disclosure [Abstract]
 
Pipeline Financing Leases in Year 1
$ 30,817 
Pipeline Financing Leases in Year 2
31,992 
Pipeline Financing Leases in Year 3
32,591 
Pipeline Financing Leases in Year 4
31,233 
Pipeline Financing Leases in Year 5
30,678 
Pipeline Financing Leases, Thereafter
296,226 
Pipeline financing leases, Total minimum lease payments
453,537 
Pipeline Financing Leases, Less: Amount representing interest
(217,293)
Present Value Of Future Minimum Lease Payments Sale Leaseback Transactions
236,244 
Capital Leases in Year 1
35,429 
Capital Leases in Year 2
31,629 
Capital Leases in Year 3
30,139 
Capital Leases in Year 4
28,038 
Capital Leases in Year 5
22,052 
Capital Leases, Thereafter
31,806 
Capital Leases, Total minimum lease payments
179,093 
Capital leases, Less: Amount representing interest
(20,833)
Capital leases, Present value of minimum lease payments
158,260 
Operating Leases in Year 1
10,656 
Operating Leases in Year 2
11,452 
Operating Leases in Year 3
12,300 
Operating Leases in Year 4
12,384 
Operating Leases in Year 5
12,720 
Operating Leases, Thereafter
80,562 
Operating Leases, Total minimum lease payments
$ 140,074 
Commitments And Contingencies Commitments and Contingencies - Leases (Details Textuals 1) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Operating Leases [Line Items]
 
 
 
Description of lease terms
terms up to thirteen years 
 
 
Lease payments associated with operating leases
$ 33.6 
$ 52.3 
$ 42.4 
Sublease income
2.7 
2.4 
0.5 
Year 2013 through 2016 [Member]
 
 
 
Operating Leases [Line Items]
 
 
 
Expected future receipts under sublease agreements
$ 3.6 
 
 
Commitments and Contingencies (Details Textuals 2) (USD $)
In Millions, unless otherwise specified
12 Months Ended 12 Months Ended 3 Months Ended
Dec. 31, 2012
Anthropogenic Co2 Contracts [Member]
Dec. 31, 2012
Anthropogenic Co2 Contracts [Member]
Maximum [Member]
MMcf
Dec. 31, 2012
Anthropogenic Co2 Contracts [Member]
Minimum [Member]
MMcf
Dec. 31, 2012
Volumetric production payments [Member]
Y
MMcf
Dec. 31, 2012
Volumetric production payments [Member]
Maximum [Member]
MMcf
Dec. 31, 2012
Riley Ridge [Member]
Dec. 31, 2012
Riley Ridge [Member]
Helium Supply Arrangement [Member]
Y
Long-term Purchase Commitment [Line Items]
 
 
 
 
 
 
 
Term of long-term purchase commitments
The commitments continue for up to 20 years. 
 
 
 
 
 
 
Expected amount of CO2 to be delivered by third parties in future years (MMcf/d)
 
675 
335 
 
 
 
 
Aggregate purchase obligation of CO2
 
$ 190 
$ 95 
 
 
 
 
Oil price assumption for obligation estimate ($/Bbl)
100 
 
 
 
 
 
 
Significant Supply Commitment Remaining Volume Committed
 
 
 
 
327,000 
 
 
Term of Long Term Supply Arrangement (years)
 
 
 
14 
 
 
20 
Significant Supply Commitment Yearly Maximum Volume Required
 
 
 
109 
 
 
 
Business Acquisition, Date of Acquisition Agreement
 
 
 
 
 
Aug. 01, 2011 
 
Annual Payment In Event Of Shortfall
 
 
 
 
 
 
$ 8.0 
Supplemental Information (Accounts Payable and Accrued Liabilities) (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Accounts Payable and Accrued Liabilities, Current [Abstract]
 
 
Accrued exploration and development costs
$ 109,939 
$ 141,868 
Accounts payable
86,051 
99,444 
Accrued interest
60,698 
60,923 
Accrued compensation
48,451 
35,861 
Accrued lease operating expenses
23,862 
24,185 
Taxes payable
27,523 
13,455 
Other
58,144 
53,600 
Total
$ 414,668 
$ 429,336 
Supplemental Information (Supplemental Cash Flow Information) (Details 1) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Supplemental Cash Flow Information [Abstract]
 
 
 
Cash paid for interest, expensed
$ 137,950 
$ 137,259 
$ 151,831 
Cash paid for interest, capitalized
77,432 
60,540 
66,815 
Cash paid for income taxes
99,194 
45,912 
17,960 
Cash received from income tax refunds
(38,004)
(24,677)
(15,107)
Non-cash investing activities:
 
 
 
Increase in asset retirement obligations
56,290 
24,694 
53,579 
Increase (decrease) in liabilities for capital expenditures
(26,882)
74,697 
(237)
Sale of non-core assets
(212,544)
0 
0 
Purchase of Thompson Field
212,544 
0 
0 
Sale of Bakken area assets in Bakken Exchange transaction
(1,621,611)
0 
0 
Purchase of properties in Bakken Exchange Transaction
571,596 
0 
0 
Issuance of Denbury common stock in connection with the Encore Merger
0 
0 
2,085,681 
Vanguard common units received as consideration for sale of ENP
0 
0 
93,020 
Restricted cash
1,050,015 
0 
 
Cash received in Bakken Exchange Transaction
281,669 
0 
0 
Bakken Exchange Transaction [Member]
 
 
 
Business Acquisition [Line Items]
 
 
 
Fair value of net assets transferred
$ 1,903,280 
 
 
Supplemental Information (Details Textuals) (USD $)
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Receivables [Abstract]
 
 
 
Allowance for doubtful accounts
$ 300,000 
$ 300,000 
 
Marathon Petroleum Company LLC [Member]
 
 
 
Major Customers [Line Items]
 
 
 
Revenue from major customer (percentage)
39.00% 
43.00% 
46.00% 
Plains Marketing LP [Member]
 
 
 
Major Customers [Line Items]
 
 
 
Revenue from major customer (percentage)
17.00% 
16.00% 
14.00% 
Subsequent Events (Details Textuals) (USD $)
1 Months Ended 12 Months Ended 15 Months Ended 1 Months Ended 1 Months Ended 12 Months Ended 1 Months Ended 1 Months Ended 0 Months Ended 1 Months Ended 12 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 12 Months Ended 2 Months Ended 17 Months Ended
Jan. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2012
Jan. 31, 2013
Restricted Stock 2004 Plan [Member]
Jan. 4, 2013
Restricted Stock 2004 Plan [Member]
Jan. 31, 2013
SARs [Member]
Dec. 31, 2012
SARs [Member]
Dec. 31, 2011
SARs [Member]
Dec. 31, 2010
SARs [Member]
Jan. 31, 2013
SARs [Member]
Minimum [Member]
Jan. 31, 2013
SARs [Member]
Maximum [Member]
Feb. 27, 2013
4 5/8% Senior Subordinated Notes due 2023 [Member]
Feb. 27, 2013
4 5/8% Senior Subordinated Notes due 2023 [Member]
Debt Instrument, Redemption, Period One [Member]
Feb. 27, 2013
4 5/8% Senior Subordinated Notes due 2023 [Member]
Debt Instrument, Redemption, Period Two [Member]
Feb. 27, 2013
4 5/8% Senior Subordinated Notes due 2023 [Member]
Debt Instrument, Redemption, Period Three [Member]
Feb. 27, 2013
4 5/8% Senior Subordinated Notes due 2023 [Member]
Debt Instrument, Redemption, Period Four [Member]
Feb. 27, 2013
4 5/8% Senior Subordinated Notes due 2023 [Member]
Feb. 5, 2013
4 5/8% Senior Subordinated Notes due 2023 [Member]
Feb. 5, 2013
4 5/8% Senior Subordinated Notes due 2023 [Member]
Feb. 27, 2013
4 5/8% Senior Subordinated Notes due 2023 [Member]
Debt Instrument, Redemption, Period One [Member]
Feb. 27, 2013
4 5/8% Senior Subordinated Notes due 2023 [Member]
Debt Instrument, Redemption, Period Two [Member]
Feb. 27, 2013
4 5/8% Senior Subordinated Notes due 2023 [Member]
Debt Instrument, Redemption, Period Three [Member]
Feb. 27, 2013
4 5/8% Senior Subordinated Notes due 2023 [Member]
Debt Instrument, Redemption, Period Four [Member]
Feb. 27, 2013
4 5/8% Senior Subordinated Notes due 2023 [Member]
Initial Redemption Period with Proceeds from Equity Offering [Member]
Feb. 27, 2013
4 5/8% Senior Subordinated Notes due 2023 [Member]
Initial Redemption Period with Make-Whole Premium [Member]
Feb. 19, 2013
9.75% Senior Subordinated Notes due 2016 [Member]
Feb. 27, 2013
9.75% Senior Subordinated Notes due 2016 [Member]
Feb. 28, 2009
9.75% Senior Subordinated Notes due 2016 [Member]
Dec. 31, 2012
9.75% Senior Subordinated Notes due 2016 [Member]
Jun. 30, 2009
9.75% Senior Subordinated Notes due 2016 [Member]
Dec. 31, 2012
9.75% Senior Subordinated Notes due 2016 [Member]
Debt Instrument, Redemption, Period One [Member]
Feb. 19, 2013
9.5% Senior Subordinated Notes due 2016 [Member]
Dec. 31, 2012
9.5% Senior Subordinated Notes due 2016 [Member]
Mar. 8, 2010
9.5% Senior Subordinated Notes due 2016 [Member]
Dec. 31, 2012
9.5% Senior Subordinated Notes due 2016 [Member]
Debt Instrument, Redemption, Period One [Member]
Dec. 31, 2012
9.5% Senior Subordinated Notes due 2016 [Member]
Debt Instrument, Redemption, Period Two [Member]
Dec. 31, 2012
9.5% Senior Subordinated Notes due 2016 [Member]
Debt Instrument, Redemption, Period Three [Member]
Dec. 31, 2012
9.5% Senior Subordinated Notes due 2016 [Member]
Initial Redemption Period with Make-Whole Premium [Member]
Feb. 21, 2013
Treasury Stock Repurchase Program [Member]
Feb. 21, 2013
Treasury Stock Repurchase Program [Member]
Subsequent Event [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Selling price of debt instrument as a percentage of par
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
100.00% 
 
 
 
 
 
 
 
 
 
 
92.816% 
 
 
 
 
 
 
 
 
 
 
 
 
Anticipated Pre Adjusted Cash Paid For Purchase Of Oil And Natural Gas Properties
 
$ 1,050,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Interest Rate, Stated Percentage
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4.625% 
4.625% 
 
 
 
 
 
 
 
 
 
9.75% 
 
 
 
9.50% 
 
 
 
 
 
 
 
Proceeds From Issuance of Subordinated Long Term Debt Net of Commissions and Fees
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,180,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Frequency of Periodic Payment
 
 
 
 
 
 
 
 
 
 
 
 
 
January 15 and July 15 of each year, commencing July 15, 2013 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
March 1 and September 1 of each year 
 
 
 
semi-annually, on May 1 and November 1, at a rate of 9½% 
 
 
 
 
 
 
 
Debt Instrument, Restrictive Covenants
 
 
 
 
 
 
 
 
 
 
 
 
 
The indenture contains certain restrictions on our ability to: (1) incur additional debt; (2) pay dividends on our common stock or redeem, repurchase or retire such capital stock or subordinated debt unless certain leverage ratios are met; (3) make investments; (4) create liens on our assets; (5) create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to the Company; (6) engage in transactions with our affiliates; (7) transfer or sell assets; and (8) consolidate, merge or transfer all or substantially all of our assets and the assets of our subsidiaries. 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Collateral
 
 
 
 
 
 
 
 
 
 
 
 
 
All of our significant subsidiaries fully and unconditionally guaranteed this debt. 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
All of our subsidiaries, other than minor subsidiaries, guarantee this debt jointly and severally. 
 
 
 
All of our subsidiaries, other than minor subsidiaries, guarantee this debt jointly and severally. 
 
 
 
 
 
 
 
Debt Instrument, Face Amount
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,200,000,000 
 
 
 
 
 
 
 
 
420,000,000 
426,400,000 
6,400,000 
 
 
224,900,000 
225,000,000 
 
 
 
 
 
 
Debt Instrument, Repurchased Face Amount
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
191,700,000 
 
 
 
 
 
186,700,000 
 
 
 
 
 
 
 
 
Maturity date
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jul. 15, 2023 
 
 
 
 
 
 
 
 
 
 
 
Mar. 01, 2016 
 
 
 
May 01, 2016 
 
 
 
 
 
 
 
Debt Instrument, Redemption Price, Percentage
 
 
 
 
 
 
 
 
 
 
 
 
 
 
102.313% 
101.542% 
100.771% 
100.00% 
 
 
 
 
 
 
 
104.625% 
100.00% 
105.425% 
104.875% 
 
 
 
 
106.87% 
 
 
104.75% 
102.375% 
100.00% 
100.00% 
 
 
Debt Instrument, Redemption Period, Start Date
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
on or after January 15, 2018 
on or after January 15, 2019 
on or after January 15, 2020 
on or after January 15, 2021 
Prior to July 15, 2016 
 
 
 
 
 
 
after May 1, 2013 
 
 
 
 
after May 1, 2014 
after May 1, 2015 
prior to May 1, 2013 
 
 
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
35.00% 
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
100.00% 
 
 
Treasury Stock, Shares, Acquired
 
 
 
 
31,100,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,500,000 
 
Treasury Stock, Value, Acquired, Cost Method
 
(8,125,000)
(9,683,000)
(6,729,000)
(461,900,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(59,100,000)
(521,000,000)
Treasury Stock Acquired, Average Cost Per Share
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 16.73 
 
Stock Repurchase Program, Remaining Authorized Repurchase Amount
 
$ 309,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 250,200,000 
 
Equity Award Grant
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Value (per share) of restricted stock grant
 
 
 
 
 
 
$ 16.77 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Awards Granted
 
 
 
 
 
1,545,077 
 
605,802 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exercise price of SARs granted
 
 
 
 
 
 
 
$ 16.77 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Weighted average grant-date fair value, granted
 
 
 
 
 
 
 
 
$ 8.90 
$ 9.68 
$ 8.45 
$ 5.42 
$ 8.72 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights
The awards generally vest 33% per year over a three-year period. 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Supplemental Oil and Natural Gas Disclosures (Unaudited) (Costs Incurred in Oil and Natural Gas Activities) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Property acquisitions.
 
 
 
Proved
$ 491,041 
$ 86,465 
$ 3,373,450 
Unevaluated
115,270 
17,858 
1,297,695 
Exploration
12,019 
31,483 
8,728 
Development
1,111,314 
1,144,243 
658,758 
Total costs incurred
$ 1,729,644 
$ 1,280,049 
$ 5,338,631 
Supplemental Oil and Natural Gas Disclosures (Unaudited) (Results of Operations from Oil and Natural Gas Producing Activities) (Details 1) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Results of operations from oil and natural gas producing activities excluding corporate overhead and interest costs
 
 
 
Oil, natural gas, and related product sales
$ 2,409,867 
$ 2,269,151 
$ 1,793,292 
Lease operating costs
532,359 
507,397 
470,364 
Marketing expenses
52,836 
26,047 
31,036 
Taxes other than income
160,016 
147,534 
120,541 
Derivatives expense (income)
 
 
(23,833)
Net operating income
1,189,099 
1,256,250 
777,749 
Income tax provision
457,803 
477,375 
295,545 
Results of operations from oil and natural gas producing activities
731,296 
778,875 
482,204 
Depletion, depreciation and amortization per BOE
18.69 
16.42 
15.82 
Oil and Gas [Member]
 
 
 
Results of operations from oil and natural gas producing activities excluding corporate overhead and interest costs
 
 
 
Depletion, depreciation and amortization
448,424 
369,075 
391,782 
Co2 Property And Pipelines [Member]
 
 
 
Results of operations from oil and natural gas producing activities excluding corporate overhead and interest costs
 
 
 
Depletion, depreciation and amortization
42,064 
24,460 
29,206 
Oil And Gas Producing Activities [Member]
 
 
 
Results of operations from oil and natural gas producing activities excluding corporate overhead and interest costs
 
 
 
Taxes other than income
149,919 
138,419 
114,569 
Derivatives expense (income)
$ (4,834)
$ (52,497)
$ (21,414)
Supplemental Oil and Natural Gas Disclosures (Unaudited) (Estimated Quantities of Proved Reserves) (Details 2)
12 Months Ended
Dec. 31, 2012
bbl
Dec. 31, 2011
bbl
Dec. 31, 2010
bbl
Estimated Quantities of Reserves
 
 
 
Extensions and discoveries
114.2 
 
 
Improved recovery
 
 
39.4 
Sales of minerals in place
123.9 
 
 
Oil Reserves (MBbl) [Member]
 
 
 
Estimated Quantities of Reserves
 
 
 
Balance at beginning of year
357,733 
338,276 
192,879 
Revisions of previous estimates
(7,099)
(4,478)
3,538 
Revisions due to price changes
(401)
2,558 
2,780 
Extensions and discoveries
14,910 
42,936 
26,313 
Improved recovery
69,543 
264 
30,173 
Production
(24,462)
(22,169)
(21,870)
Acquisition of minerals in place
24,677 
346 
155,021 
Sales of minerals in place
(105,777)
0 
(50,558)
Balance at end of year
329,124 
357,733 
338,276 
Proved Developed Reserves:
 
 
 
Balance at beginning of year
239,741 
219,077 
116,192 
Balance at end of year
236,009 
239,741 
219,077 
Gas Reserves (Mmcf) [Member]
 
 
 
Estimated Quantities of Reserves
 
 
 
Balance at beginning of year
625,208 
357,893 
87,975 
Revisions of previous estimates
(16,720)
(14,058)
16,171 
Revisions due to price changes
(37,969)
485 
811 
Extensions and discoveries
10,005 
52,339 
130,245 
Improved recovery
0 
0 
0 
Production
(10,654)
(10,783)
(28,491)
Acquisition of minerals in place
20,598 
239,332 
622,984 
Sales of minerals in place
(108,827)
0 
(471,802)
Balance at end of year
481,641 
625,208 
357,893 
Proved Developed Reserves:
 
 
 
Balance at beginning of year
125,970 
110,516 
69,513 
Balance at end of year
64,191 
125,970 
110,516 
Total Reserves (MBOE) [Member]
 
 
 
Estimated Quantities of Reserves
 
 
 
Balance at beginning of year
461,934 
397,925 
207,542 
Revisions of previous estimates
(9,886)
(6,821)
6,233 
Revisions due to price changes
(6,729)
2,639 
2,915 
Extensions and discoveries
16,579 
51,658 
48,021 
Improved recovery
69,543 
264 
30,173 
Production
(26,238)
(23,966)
(26,619)
Acquisition of minerals in place
28,110 
40,235 
258,852 
Sales of minerals in place
(123,915)
0 
(129,192)
Balance at end of year
409,398 
461,934 
397,925 
Proved Developed Reserves:
 
 
 
Balance at beginning of year (mBOE)
260,736 
237,496 
127,778 
Balance at end of year (mBOE)
246,708 
260,736 
237,496 
Supplemental Oil and Natural Gas Disclosures (Unaudited) (Oil and Natural Gas Prices) (Details 3)
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Oil Reserves [Member]
 
 
 
Oil and natural gas prices
 
 
 
Oil and natural gas prices
94.71 
96.19 
79.43 
Gas Reserves [Member]
 
 
 
Oil and natural gas prices
 
 
 
Oil and natural gas prices
2.85 
4.16 
4.40 
Supplemental Oil and Natural Gas Disclosures (Unaudited) (Standardized Measure) (Details 4) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure [Abstract]
 
 
 
Future cash inflows
$ 34,779,549 
$ 38,165,122 
$ 26,698,819 
Future production costs
(13,114,740)
(12,570,015)
(9,702,896)
Future development costs
(2,034,174)
(3,026,898)
(1,912,457)
Future income taxes
(6,672,857)
(7,379,972)
(4,700,023)
Future net cash flows
12,957,778 
15,188,237 
10,383,443 
10% annual discount for estimated timing of cash flows
(6,543,398)
(8,180,632)
(5,465,516)
Standardized measure of discounted future net cash flows
$ 6,414,380 
$ 7,007,605 
$ 4,917,927 
Supplemental Oil And Natural Gas Disclosures (Unaudited) (Changes in Standardized Measure) (Details 5) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract]
 
 
 
Beginning of year
$ 7,007,605 
$ 4,917,927 
$ 2,457,385 
Sales of oil and natural gas produced, net of production costs
(1,673,253)
(1,597,288)
(1,177,322)
Net changes in sales prices
(584,526)
4,646,086 
2,062,181 
Previously estimated development costs incurred
376,199 
354,228 
193,947 
Revisions of previous estimates, including revised estimates of development costs, reserves and rates of production
(797,975)
(1,673,283)
(285,158)
Accretion of discount
875,383 
729,234 
307,546 
Acquisition of minerals in place
767,267 
29,737 
3,671,439 
Sales of minerals in place
(1,805,309)
0 
(1,474,443)
Net change in income taxes
56,322 
(1,177,114)
(1,756,344)
End of year
6,414,380 
7,007,605 
4,917,927 
Tertiary Recovery [Member]
 
 
 
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract]
 
 
 
Extensions, Discoveries, Additions and Improved Recovery, Less Related Costs
1,901,109 
15,708 
623,622 
Non-tertiary
 
 
 
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract]
 
 
 
Extensions, Discoveries, Additions and Improved Recovery, Less Related Costs
$ 291,558 
$ 762,370 
$ 295,074 
Supplemental Oil And Natural Gas Disclosures (Unaudited) (Details Textuals) (USD $)
12 Months Ended
Dec. 31, 2012
bbl
Dec. 31, 2011
Dec. 31, 2010
bbl
Property, Plant and Equipment [Line Items]
 
 
 
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions
114.2 
 
 
Decrease Due to Sales of Minerals in Place
123.9 
 
 
Cash paid for interest, capitalized
$ 77,432,000 
$ 61,586,000 
$ 66,815,000 
Costs incurred include new asset retirement obligations established and changes to asset retirement cost estimates or abandonment dates obligations resulting from revisions in cost estimates or abandonment dates
38,800,000 
24,200,000 
45,100,000 
Capitalized general and administrative costs
49,200,000 
35,000,000 
20,100,000 
Improved recovery
 
 
39.4 
Oil and Gas Properties [Member]
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
Cash paid for interest, capitalized
$ 36,500,000 
$ 44,900,000 
$ 32,600,000 
Increase In Proved Reserves Related To Hastings And Oyster Bayou [Member]
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions
69.5 
 
 
Increase In Proved Reserves Related To Thompson Webster And Hartzog Draw [Member]
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place
25.9 
 
 
Increase In Proved Reserves Related To Bakken [Member]
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions
11.5 
 
 
Supplemental CO2 and Helium Disclosures (Unaudited) (Proved CO2 and Helium Reserves) (Details)
Dec. 31, 2012
Billion_cubic_feet
Dec. 31, 2011
Billion_cubic_feet
Dec. 31, 2010
Billion_cubic_feet
Reserve Quantities [Line Items]
 
 
 
CO2 VPP (in Bcf)
57.1 
84.7 
100.2 
Gulf Coast Region [Member]
 
 
 
Reserve Quantities [Line Items]
 
 
 
CO2 Reserves (in MMcf)
6,073,175 
6,685,412 
7,085,131 
Net Revenue Interest In Co2 Reserves (in Tcf)
4.8 
5.3 
5.6 
Rocky Mountain Region [Member]
 
 
 
Reserve Quantities [Line Items]
 
 
 
CO2 Reserves (in MMcf)
3,495,534 
2,195,534 
2,189,756 
Helium Reserves (in MMcf)
12,712 
12,004 
7,159 
Net Revenue Interest In Co2 Reserves (in Tcf)
2.9 
1.6 
0.9 
Unaudited Quarterly Information (Unaudited Quarterly Information) (Details) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2012
Sep. 30, 2012
Jun. 30, 2012
Mar. 31, 2012
Dec. 31, 2011
Sep. 30, 2011
Jun. 30, 2011
Mar. 31, 2011
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Quarterly Financial Data [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Revenues and other income
$ 609,204 
$ 600,371 
$ 601,781 
$ 645,116 
$ 617,257 
$ 576,505 
$ 601,397 
$ 514,165 
$ 2,456,472 
$ 2,309,324 
$ 1,921,791 
Derivatives expense (income)
27,369 
61,631 
(139,109)
45,275 
159,811 
(210,154)
(172,904)
170,750 
 
 
 
Other expenses
386,470 
399,361 
398,089 
420,529 
377,577 
343,339 
350,499 
366,361 
1,599,615 
1,385,279 
1,442,721 
Net income (loss)
114,661 
85,367 
211,865 
113,467 
52,607 
275,670 
259,246 
(14,190)
525,360 
573,333 
271,723 
Net income (loss) per share:
 
 
 
 
 
 
 
 
 
 
 
Basic
$ 0.30 
$ 0.22 
$ 0.55 
$ 0.29 
$ 0.14 
$ 0.69 
$ 0.65 
$ (0.04)
$ 1.36 
$ 1.45 
$ 0.73 
Diluted
$ 0.30 
$ 0.22 
$ 0.54 
$ 0.29 
$ 0.13 
$ 0.68 
$ 0.64 
$ (0.04)
$ 1.35 
$ 1.43 
$ 0.72 
Cash flow provided by operating activities
384,765 
293,506 
440,966 
291,654 
365,722 
315,739 
398,521 
124,832 
1,410,891 
1,204,814 
855,811 
Cash flow used for investing activities
(138,869)
(388,748)
(560,341)
(288,883)
(447,706)
(525,412)
(347,797)
(285,043)
(1,376,841)
(1,605,958)
(354,780)
Cash flow provided by (used for) financing activities
$ (118,676)
$ 91,163 
$ 70,122 
$ 55,902 
$ 76,314 
$ 112,244 
$ (56,789)
$ (93,801)
$ 45,768 
$ 37,968 
$ (139,753)