DENBURY RESOURCES INC, 10-Q filed on 11/6/2015
Quarterly Report
Document and Entity Information
9 Months Ended
Sep. 30, 2015
Oct. 31, 2015
Document And Company Information [Abstract]
 
 
Document Type
10-Q 
 
Document Period End Date
Sep. 30, 2015 
 
Amendment Flag
false 
 
Document Fiscal Year Focus
2015 
 
Document Fiscal Period Focus
Q3 
 
Trading Symbol
DNR 
 
Current Fiscal Year End Date
--12-31 
 
Entity Registrant Name
Denbury Resources Inc. 
 
Entity Central Index Key
0000945764 
 
Entity Current Reporting Status
Yes 
 
Entity Filer Category
Large Accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
351,162,058 
Condensed Consolidated Balance Sheets (Unaudited) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2015
Dec. 31, 2014
Current assets
 
 
Cash and cash equivalents
$ 12,212 
$ 23,153 
Accrued production receivable
123,759 
181,761 
Trade and other receivables, net
118,457 
156,955 
Derivative assets
199,431 
440,359 
Other current assets
11,758 
10,452 
Total current assets
465,617 
812,680 
Oil and natural gas properties (using full cost accounting)
 
 
Proved properties
10,102,698 
9,782,337 
Unevaluated properties
917,463 
918,406 
CO2 properties
1,178,827 
1,162,538 
Pipelines and plants
2,285,152 
2,269,564 
Other property and equipment
450,053 
468,051 
Less accumulated depletion, depreciation, amortization and impairment
(8,252,335)
(4,248,652)
Net property and equipment
6,681,858 
10,352,244 
Derivative assets
0 
66,187 
Goodwill
0 
1,283,590 
Other assets
207,677 
213,101 
Total assets
7,355,152 
12,727,802 
Current liabilities
 
 
Accounts payable and accrued liabilities
250,514 
394,758 
Oil and gas production payable
101,692 
128,170 
Deferred tax liabilities
7,884 
81,727 
Current maturities of long-term debt
36,038 
35,470 
Total current liabilities
396,128 
640,125 
Long-term liabilities
 
 
Long-term debt, net of current portion
3,321,315 
3,535,900 
Asset retirement obligations
136,238 
126,411 
Deferred tax liabilities
1,336,247 
2,694,842 
Other liabilities
28,892 
26,668 
Total long-term liabilities
4,822,692 
6,383,821 
Commitments and contingencies (Note 7)
   
   
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; 414,322,723 and 411,779,911 shares issued, respectively
414 
412 
Paid-in capital in excess of par
3,235,266 
3,230,418 
Retained earnings (accumulated deficit)
(173,892)
3,392,465 
Accumulated other comprehensive loss
(157)
(209)
Treasury stock, at cost, 61,373,201 and 58,415,507 shares, respectively
(925,299)
(919,230)
Total stockholders' equity
2,136,332 
5,703,856 
Total liabilities and stockholders' equity
$ 7,355,152 
$ 12,727,802 
Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $)
Sep. 30, 2015
Dec. 31, 2014
Stockholders' equity
 
 
Preferred stock, par value
$ 0.001 
$ 0.001 
Preferred stock, shares authorized
25,000,000 
25,000,000 
Preferred stock, shares issued
0 
0 
Preferred stock, shares outstanding
0 
0 
Common stock, par value
$ 0.001 
$ 0.001 
Common stock, shares authorized
600,000,000 
600,000,000 
Common stock, shares issued
414,322,723 
411,779,911 
Treasury stock, shares
61,373,201 
58,415,507 
Condensed Consolidated Statements of Operations (Unaudited) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Revenues and other income
 
 
 
 
Oil, natural gas, and related product sales
$ 290,388 
$ 622,005 
$ 954,749 
$ 1,902,880 
CO2 and helium sales and transportation fees
9,144 
11,378 
23,268 
33,961 
Interest income and other income
4,068 
4,274 
9,926 
14,680 
Total revenues and other income
303,600 
637,657 
987,943 
1,951,521 
Expenses
 
 
 
 
Lease operating expenses
113,902 
155,198 
387,156 
488,827 
Marketing and plant operating expenses
14,458 
15,328 
40,358 
50,263 
CO2 and helium discovery and operating expenses
1,017 
11,434 
2,909 
22,229 
Taxes other than income
25,607 
39,966 
85,841 
136,761 
General and administrative expenses
32,907 
40,366 
117,134 
123,011 
Interest, net of amounts capitalized of $8,081, $5,862, $25,228, and $17,413, respectively
39,225 
44,752 
119,187 
140,136 
Depletion, depreciation, and amortization
121,406 
146,560 
419,304 
435,854 
Commodity derivatives expense (income)
(92,028)
(252,265)
(126,178)
(825)
Loss on early extinguishment of debt
0 
0 
0 
113,908 
Write-down of oil and natural gas properties
1,760,600 
0 
3,612,600 
0 
Impairment of goodwill
1,261,512 
0 
1,261,512 
0 
Total expenses
3,278,606 
201,339 
5,919,823 
1,510,164 
Income (loss) before income taxes
(2,975,006)
436,318 
(4,931,880)
441,357 
Income tax provision (benefit)
(730,880)
167,570 
(1,431,509)
169,499 
Net income (loss)
$ (2,244,126)
$ 268,748 
$ (3,500,371)
$ 271,858 
Net income (loss) per common share
 
 
 
 
Basic
$ (6.41)
$ 0.77 
$ (10.01)
$ 0.78 
Diluted
$ (6.41)
$ 0.77 
$ (10.01)
$ 0.77 
Dividends declared per common share
$ 0.0625 
$ 0.0625 
$ 0.1875 
$ 0.1875 
Weighted average common shares outstanding
 
 
 
 
Basic
350,052 
348,454 
349,787 
348,993 
Diluted
350,052 
350,918 
349,787 
351,347 
Condensed Consolidated Statements of Operations (Unaudited) (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Expenses
 
 
 
 
Capitalized interest
$ 8,081 
$ 5,862 
$ 25,228 
$ 17,413 
Condensed Consolidated Statements of Comprehensive Operations (Unaudited) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Statement of Comprehensive Income [Abstract]
 
 
 
 
Net income (loss)
$ (2,244,126)
$ 268,748 
$ (3,500,371)
$ 271,858 
Other comprehensive income, net of income tax:
 
 
 
 
Interest rate lock derivative contracts reclassified to income, net of tax of $11, $11, $32, and $35, respectively
17 
18 
52 
50 
Total other comprehensive income
17 
18 
52 
50 
Comprehensive income (loss)
$ (2,244,109)
$ 268,766 
$ (3,500,319)
$ 271,908 
Condensed Consolidated Statements of Comprehensive Operations (Unaudited) (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Other comprehensive income, net of income tax:
 
 
 
 
Tax for interest rate lock derivative contracts reclassified to income
$ 11 
$ 11 
$ 32 
$ 35 
Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)
In Thousands, unless otherwise specified
9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Cash flows from operating activities
 
 
Net income (loss)
$ (3,500,371)
$ 271,858 
Adjustments to reconcile net income (loss) to cash flow from operating activities
 
 
Depletion, depreciation, and amortization
419,304 
435,854 
Write-down of oil and natural gas properties
3,612,600 
0 
Impairment of goodwill
1,261,512 
0 
Deferred income taxes
(1,432,572)
168,967 
Stock-based compensation
22,637 
26,104 
Commodity derivatives expense (income)
(126,178)
(825)
Receipt (payment) on settlements of commodity derivatives
433,293 
(102,255)
Loss on early extinguishment of debt
0 
113,908 
Amortization of debt issuance costs and discounts
6,810 
10,433 
Other, net
(7,457)
(5,037)
Changes in assets and liabilities, net of effects from acquisitions
 
 
Accrued production receivable
57,867 
565 
Trade and other receivables
37,463 
(6,885)
Other current and long-term assets
(1,771)
(370)
Accounts payable and accrued liabilities
(53,124)
(7,195)
Oil and natural gas production payable
(26,478)
(17,225)
Other liabilities
(4,138)
(2,800)
Net cash provided by operating activities
699,397 
885,097 
Cash flows from investing activities
 
 
Oil and natural gas capital expenditures
(364,948)
(699,012)
Acquisitions of oil and natural gas properties
(21,171)
(1,684)
CO2 capital expenditures
(21,894)
(38,272)
Pipelines and plants capital expenditures
(25,767)
(47,521)
Purchases of other assets
(5,539)
(6,253)
Net proceeds from sales of oil and natural gas properties and equipment
327 
3,011 
Other
11,452 
808 
Net cash used in investing activities
(427,540)
(788,923)
Cash flows from financing activities
 
 
Bank repayments
(1,491,000)
(1,827,000)
Bank borrowings
1,306,000 
1,897,000 
Repayment of senior subordinated notes
(485)
(997,345)
Premium paid on repayment of senior subordinated notes
0 
(101,342)
Proceeds from issuance of senior subordinated notes
0 
1,250,000 
Costs of debt financing
(1,639)
(17,551)
Common stock repurchase program
(2,692)
(211,356)
Cash dividends paid
(65,422)
(65,241)
Other
(27,560)
(16,090)
Net cash used in financing activities
(282,798)
(88,925)
Net increase (decrease) in cash and cash equivalents
(10,941)
7,249 
Cash and cash equivalents at beginning of period
23,153 
12,187 
Cash and cash equivalents at end of period
$ 12,212 
$ 19,436 
Basis of Presentation
Basis of Presentation and Significant Accounting Policies
Note 1. Basis of Presentation

Organization and Nature of Operations

Denbury Resources Inc., a Delaware corporation, is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions.  Our goal is to increase the value of our properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO2 enhanced oil recovery operations.

Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission ("SEC") and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements.  These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2014 (the "Form 10-K").  Unless indicated otherwise or the context requires, the terms "we," "our," "us," "Company" or "Denbury," refer to Denbury Resources Inc. and its subsidiaries.

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year.  In management's opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of September 30, 2015, our consolidated results of operations for the three and nine months ended September 30, 2015 and 2014, and our consolidated cash flows for the nine months ended September 30, 2015 and 2014.

Reclassifications

Certain prior period amounts have been reclassified to conform to 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.

Net Income (Loss) per Common Share

Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period.  Diluted net income (loss) 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-based equity awards.  For the three and nine months ended September 30, 2015 and 2014, there were no adjustments to net income (loss) for purposes of calculating basic and diluted net income (loss) per common share.

The following is a reconciliation of the weighted average shares used in the basic and diluted net income (loss) per common share calculations for the periods indicated:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
In thousands
 
2015
 
2014
 
2015
 
2014
Basic weighted average common shares outstanding
 
350,052

 
348,454

 
349,787

 
348,993

Potentially dilutive securities
 
 

 
 

 
 

 
 

Restricted stock, stock options, SARs and performance-based equity awards
 
—

 
2,464

 
—

 
2,354

Diluted weighted average common shares outstanding
 
350,052

 
350,918

 
349,787

 
351,347



Basic weighted average common shares exclude shares of nonvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income (loss) per common share (although all non-performance-based restricted stock is issued and outstanding upon grant).  For purposes of calculating diluted weighted average common shares during the three and nine months ended September 30, 2014, the nonvested restricted stock, stock options, SARs and performance-based equity awards are included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, the purchase price that the grantee will pay in the future for stock options, and any estimated future tax consequences recognized directly in equity.

The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
In thousands
 
2015
 
2014
 
2015
 
2014
Stock options and SARs
 
9,118

 
3,827

 
9,858

 
4,343

Restricted stock and performance-based equity awards
 
4,988

 
12

 
3,392

 
457



Write-Down of Oil and Natural Gas Properties

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 oil and natural gas 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 a 12-month rolling 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 oil and natural gas 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.

As a result of the precipitous and continuing decline in NYMEX oil prices since the fourth quarter of 2014, the rolling first-day-of-the-month average oil price for the preceding 12 months, after adjustments for market differentials by field, has fallen throughout 2015, from $79.55 per Bbl for the first quarter of 2015, to $68.48 per Bbl for the second quarter of 2015, and $56.74 per Bbl for the third quarter of 2015. In addition, the first-day-of-the-month average natural gas price for the preceding 12 months, after adjustments for market differentials by field, was $3.95 per Mcf for the first quarter of 2015, $3.74 per Mcf for the second quarter of 2015, and $3.64 per Mcf for the third quarter of 2015. These falling prices have led to our recognizing full cost pool ceiling test write-downs of $1.8 billion, $1.7 billion and $0.2 billion during the three months ended September 30, 2015, June 30, 2015, and March 31, 2015, respectively.

Impairment of Goodwill

We are required to test goodwill for impairment on an interim basis when we determine that it is more likely than not that the fair value of our reporting unit is less than its carrying amount. Our enterprise value (combined market capitalization plus a control premium of 10% and the fair value of our long-term debt) declined by approximately $2.5 billion between June 30 and September 30, 2015; therefore, we concluded that a goodwill impairment test was required to be performed in the third quarter.

For the goodwill impairment test, we compared the fair value of the reporting unit (enterprise value) to the fair value of its assets and liabilities. Oil and natural gas reserves, which represent the most significant assets requiring valuation, were estimated using the expected present value of future net cash flows method based on September 30, 2015, NYMEX oil and natural gas futures prices for the next five years, adjusted for current price differentials. In addition to future oil and natural gas pricing, the most significant assumptions impacting the projections of future net cash flows include projections of future rates of production, timing and amount of future development and operating costs, projected availability and cost of CO2, risk adjustment factors applied to probable and possible oil and natural gas reserve cash flows, projected recovery factors of oil and natural gas reserves, and a weighted average cost of capital discount rate applied to all net cash flows. Because the fair value of the reporting unit (enterprise value) did not exceed the fair value of assets and liabilities, we recorded a goodwill impairment charge of $1.3 billion during the three months ended September 30, 2015, to fully impair the carrying value of our goodwill. Approximately $1.0 billion of the $1.3 billion goodwill balance was associated with the March-2010 merger with Encore Acquisition Company.

Recent Accounting Pronouncements

Debt Issuance Costs. In April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03"). ASU 2015-03 requires debt issuance costs related to a recognized debt liability to be presented as a direct reduction of the carrying amount of that debt in the balance sheet, consistent with the presentation of debt discounts. The amendments in this ASU are effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years, and early adoption is permitted. Entities will be required to apply the guidance on a retrospective basis to each period presented as a change in accounting principle. In August 2015, the FASB issued ASU 2015-15, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-15") which amends ASU 2015-03 to clarify the presentation and subsequent measurement of debt issuance costs associated with line of credit arrangements, such that entities may continue to apply current practice. The adoption of ASU 2015-03 and 2015-15 are currently not expected to have a material effect on our consolidated financial statements, other than balance sheet reclassifications.

Revenue Recognition. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers ("ASU 2014-09"). ASU 2014-09 amends the guidance for revenue recognition to replace numerous, industry-specific requirements. The core principle of the ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU implements a five-step process for customer contract revenue recognition that focuses on transfer of control, as opposed to transfer of risk and rewards. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers ("ASU 2015-14") which amends ASU 2014-09 and delays the effective date for public companies, such that the amendments in the ASU are effective for reporting periods beginning after December 15, 2017, and early adoption will be permitted for periods beginning after December 15, 2016. Entities can transition to the standard either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. Management is currently assessing the impact the adoption of ASU 2014-09 and ASU 2015-14 will have on our consolidated financial statements.
Long-Term Debt
Long-Term Debt
Note 2. Long-Term Debt

The following long-term debt and capital lease obligations were outstanding as of the dates indicated:
 
 
September 30,
 
December 31,
In thousands
 
2015
 
2014
Bank Credit Agreement
 
$
210,000

 
$
395,000

6⅜% Senior Subordinated Notes due 2021
 
400,000

 
400,000

5½% Senior Subordinated Notes due 2022
 
1,250,000

 
1,250,000

4⅝% Senior Subordinated Notes due 2023
 
1,200,000

 
1,200,000

Other Subordinated Notes, including premium of $8 and $11, respectively
 
2,258

 
2,746

Pipeline financings
 
214,179

 
220,583

Capital lease obligations
 
80,916

 
103,041

Total
 
3,357,353

 
3,571,370

Less: current obligations
 
(36,038
)
 
(35,470
)
Long-term debt and capital lease obligations
 
$
3,321,315

 
$
3,535,900



The ultimate parent company in our corporate structure, 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, and the guarantees of the notes are full and unconditional and joint and several; any subsidiaries of DRI that are not subsidiary guarantors of certain of such notes are minor subsidiaries.

Bank Credit Facility

In December 2014, we entered into an Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the "Bank Credit Agreement"). The Bank Credit Agreement is a senior secured revolving credit facility with a current borrowing base of $2.6 billion and aggregate lender commitments of $1.6 billion. Our obligations under the Bank Credit Agreement are guaranteed jointly and severally by each subsidiary of DRI that is 100% owned, directly or indirectly, by DRI. The Bank Credit Agreement is secured by (1) a significant portion of our proved oil and natural gas properties, which are held through DRI's restricted subsidiaries; (2) the pledge of equity interests of such subsidiaries; and (3) a pledge of commodity derivative agreements of DRI and such subsidiaries (as applicable). Loans under the Bank Credit Agreement mature in December 2019. The weighted average interest rate on borrowings outstanding as of September 30, 2015, under the Bank Credit Agreement was 1.8%. The undrawn portion of the aggregate lender commitments under the Bank Credit Agreement is subject to a commitment fee ranging from 0.3% to 0.375% per annum. As of September 30, 2015, we were in compliance with all debt covenants under the Bank Credit Agreement.

Borrowing base redeterminations under our Bank Credit Agreement occur annually, and with our last such redetermination having been completed in early-May 2015, our next scheduled redetermination is set for May 2016. The lenders are entitled, at their election, to request one interim redetermination between annual scheduled redeterminations; however, as of November 4, 2015, there has been no such request to do so. In connection with the borrowing base redetermination completed in early-May 2015, we elected to maintain our aggregate lender commitments at $1.6 billion; however, due to a reduction in oil prices used by our lenders in determining the borrowing base value of our proved reserves attributable to our oil and natural gas properties, our borrowing base was reduced from the previous level of $3.0 billion to $2.6 billion. Because we continue to maintain a significant cushion between our borrowing base and the aggregate lender commitments, and because we had significant availability with respect to our aggregate lender commitments as of September 30, 2015, the borrowing base reduction has no impact on our liquidity.

In conjunction with the May 2015 redetermination, we also entered into the First Amendment to the Bank Credit Agreement (the "First Amendment") to restructure certain financial covenants in 2016, 2017, and 2018 in order to provide more flexibility in managing our balance sheet and managing the credit extended by our lenders if oil prices remain low over the next several years. The covenant changes included in the First Amendment were as follows:

•
In 2016 and 2017, suspend the maximum permitted ratio of consolidated total net debt to consolidated EBITDAX covenant of 4.25 to 1.0 and replace it with a maximum permitted ratio of consolidated senior secured debt to consolidated EBITDAX covenant of 2.5 to 1.0 during the same time period. Currently, only debt under our Bank Credit Agreement would be considered consolidated senior secured debt for purposes of this ratio.
•
Beginning in the first quarter of 2018, reinstate the ratio of consolidated total net debt to consolidated EBITDAX covenant utilizing an annualized EBITDAX amount for the first quarter of 2018 and building to a trailing four quarters by the end of 2018, with the maximum permitted ratios being 6.0 to 1.0 for the first quarter ended March 31, 2018, 5.5 to 1.0 for the second quarter ended June 30, 2018, and 5.0 to 1.0 for the third and fourth quarters ended September 30 and December 31, 2018, and returning to 4.25 to 1.0 for the first quarter ended March 31, 2019.
•
In 2016 and 2017, institute a minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 2.25 to 1.0.

The restructuring of covenants through the First Amendment was executed in consideration of a fee paid to the lenders. The First Amendment has no impact on the current ratio financial performance covenant, which will remain in place in 2015 and beyond. All of the above descriptions of financial covenants are qualified by the express language and defined terms contained in the Bank Credit Agreement.

2014 Issuance of 5½% Senior Subordinated Notes due 2022

In April 2014, we issued $1.25 billion of 5½% Senior Subordinated Notes due 2022 (the "5½% Notes"), which were sold at par. The net proceeds, after issuance costs, of $1.23 billion were used to repurchase or redeem our outstanding $996.3 million of 8¼% Senior Subordinated Notes due 2020 (the "8¼% Notes") (see 2014 Repurchase and Redemption of 8¼% Senior Subordinated Notes due 2020 below) and to pay down a portion of outstanding borrowings under our previous bank credit agreement.

2014 Repurchase and Redemption of 8¼% Senior Subordinated Notes due 2020

During the second quarter of 2014, we repurchased and redeemed the entire $996.3 million outstanding principal amount of our 8¼% Notes using a portion of the proceeds from the issuance of the 5½% Notes. We recognized a $113.9 million loss associated with the debt repurchases during the second quarter of 2014, which loss consists of both premium payments made to repurchase or redeem the 8¼% Notes and the elimination of unamortized debt issuance costs related to these notes. The loss is included in our Unaudited Condensed Consolidated Statements of Operations under the caption "Loss on early extinguishment of debt," and premium payments made to repurchase the notes are classified as a financing cash outflow on our Unaudited Condensed Consolidated Statements of Cash Flows under the caption "Premium paid on repayment of senior subordinated notes."
Income Taxes
Income Tax Disclosure
Note 3. Income Taxes

We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. As of September 30, 2015, we had $37.0 million of deferred tax assets associated with State of Louisiana net operating losses. As the result of a new tax law enacted in the State of Louisiana effective June 30, 2015, which limits a company's utilization of certain deductions, including our net operating loss carryforwards, we recognized a tax valuation allowance of $30.5 million during the second quarter of 2015 to reduce the carrying value of our deferred tax assets. The valuation allowances will remain until the realization of future deferred tax benefits are more likely than not to become utilized. Our effective tax rate for the three months ended September 30, 2015, was lower than our estimated statutory rate, as a significant portion of the book value of our goodwill impaired during the quarter had no related tax basis. Therefore, no corresponding deferred tax benefit was recognized related to that portion of the goodwill impairment. Our effective tax rate for the nine months ended September 30, 2015, was further impacted by the tax valuation allowance discussed above, which also reduced the net deferred tax benefit recognized.
Stockholders' Equity
Stockholders' Equity
Note 4. Stockholders' Equity

During the second quarter of 2015, we reduced the number of shares of our common stock reported as outstanding by 1,430,819 shares (approximately 0.4% of our outstanding shares at March 31, 2015). This reduction was the result of a correction to properly reflect the number of shares actually issued in the merger with Encore Acquisition Company ("Encore") in March 2010. The stock and cash consideration originally issued and paid in the Encore merger was valued at $3.0 billion, which would have been reduced by $22.1 million for this share correction. As a result, we recorded adjustments to our Unaudited Condensed Consolidated Balance Sheet to reflect a decrease in consideration paid in the Encore merger through a reduction of "Goodwill" ($22.1 million), offset by a reduction in an equal amount of the Company's stockholders' equity ($22.1 million). We determined that this correction in outstanding shares (1) had no impact on net income (loss) for the second quarter of 2015, our estimated results of operations for the year ending December 31, 2015, or for any prior period, and (2) was not material to our consolidated balance sheet, statement of cash flows, or basic or diluted earnings per common share for the second quarter of 2015, or for any prior period, and therefore we recorded the cumulative effect of correcting these items during the three months ended June 30, 2015.

Dividends

In all four quarters of 2014 and in each of the first three quarters of 2015, the Company's Board of Directors declared quarterly cash dividends of $0.0625 per common share, or an annual rate of $0.25 per common share. On September 21, 2015, in light of the continuing low oil price environment and its desire to maintain our financial strength and flexibility, the Company's Board of Directors suspended our quarterly cash dividend, after payment of our third quarter dividend on September 29, 2015. By suspending the dividend, we will free up cash which can be directed to other uses. Dividends totaling $65.4 million and $65.2 million were paid to stockholders during the nine months ended September 30, 2015 and 2014, respectively.

Stock Repurchase Program

On September 21, 2015, the Company's Board of Directors reinstated the ability to repurchase shares under our share repurchase program, which authorization was suspended in November of 2014. During the three months ended September 30, 2015, we repurchased 2.7 million shares of Denbury common stock for $6.9 million, and in October 2015 we repurchased an additional 1.7 million shares of Denbury common stock for $4.8 million. During the three months ended March 31, 2014, we repurchased 12.4 million shares of Denbury common stock for $200.4 million. As of November 4, 2015, $210.1 million remains authorized for use under this repurchase program. Our share repurchases are based on various parameters including, but not limited to, the price of our common stock, oil prices, free cash flow, our leverage or other funding sources available to us. There is no requirement that the remaining balance under the program be utilized, and there is no set expiration date for the repurchase program.

Employee Stock Purchase Program

We previously provided for an Employee Stock Purchase Plan (the "Plan") in which funds from eligible employees, together with Company contributions, were 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. The Plan was terminated, effective at the end of the offering period ended on March 31, 2015, as all of the previously authorized shares reserved for issuance under the Plan had been issued.
Commodity Derivative Contracts
Commodity Derivative Contracts
Note 5. Commodity 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 settlements of expired contracts, are shown under "Commodity derivatives expense (income)" in our Unaudited Condensed Consolidated Statements of Operations.

Historically, we have entered 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 and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps and fixed-price swaps enhanced with a sold put. The production that we hedge has varied from year to year depending on our levels of debt, financial strength and expectation of future commodity prices. For the past several years, we have generally hedged a substantial portion of our forecasted production over an approximately 18 month to two year future period, as we believed it was beneficial to protect our future cash flows at then-projected oil prices for those future periods. However, during the significant and rapid decline in oil prices in the fourth quarter of 2014 and the first quarter of 2015, we deferred entering into new derivative contracts; we entered into limited oil hedging positions during the second quarter of 2015 covering the second and third quarters of 2016 as a result of the slight recovery in oil prices; and we have not entered into any additional hedges since the second quarter of 2015. Consequently, we currently have less of our production hedged and for a shorter future time period than we have generally had over the last several years.

We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis.  We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of September 30, 2015, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.
The following table summarizes our commodity derivative contracts as of September 30, 2015, none of which are classified as hedging instruments in accordance with the Financial Accounting Standards Board Codification ("FASC") Derivatives and Hedging topic:
Months
 
Index Price
 
Volume (2)
 
Contract Prices (1)
Range (3)
 
Weighted Average Price
Swap
 
Sold Put
 
Floor
 
Ceiling
Oil Contracts:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2015 Enhanced Swaps (4)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oct – Dec
 
NYMEX
 
12,000
 
$
91.15
–
94.00

 
$
92.42

 
$
68.00

 
$
—

 
$
—

Oct – Dec
 
LLS
 
8,000
 
 
93.80
–
96.50

 
94.94

 
68.00

 
—

 
—

2015 Three-Way Collars (5)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oct – Dec
 
NYMEX
 
10,000
 
$
85.00
–
102.00

 
$
—

 
$
68.00

 
$
85.00

 
$
99.00

Oct – Dec
 
LLS
 
8,000
 
 
88.00
–
104.25

 
—

 
68.00

 
88.00

 
100.99

2016 Enhanced Swaps (4)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jan – Mar
 
NYMEX
 
12,000
 
$
90.65
–
93.35

 
$
92.43

 
$
68.00

 
$
—

 
$
—

Jan – Mar
 
LLS
 
8,000
 
 
93.70
–
95.45

 
94.81

 
68.50

 
—

 
—

Apr – June
 
NYMEX
 
2,000
 
 
90.35
–
90.35

 
90.35

 
68.00

 
—

 
—

Apr – June
 
LLS
 
6,000
 
 
93.30
–
93.50

 
93.38

 
70.00

 
—

 
—

2016 Fixed-Price Swaps
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Apr – June
 
NYMEX
 
11,500
 
$
60.30
–
63.75

 
$
61.84

 
$
—

 
$
—

 
$
—

Apr – June
 
LLS
 
3,500
 
 
64.20
–
66.15

 
64.99

 
—

 
—

 
—

2016 Three-Way Collars (5)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jan – Mar
 
NYMEX
 
10,000
 
$
85.00
–
101.25

 
$
—

 
$
68.00

 
$
85.00

 
$
99.85

Jan – Mar
 
LLS
 
6,000
 
 
88.00
–
103.15

 
—

 
68.00

 
88.00

 
102.10

Apr – June
 
NYMEX
 
2,000
 
 
85.00
–
95.50

 
—

 
68.00

 
85.00

 
95.50

Apr – June
 
LLS
 
2,000
 
 
88.00
–
98.25

 
—

 
70.00

 
88.00

 
98.25

2016 Collars
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Apr – June
 
NYMEX
 
5,000
 
$
55.00
–
72.25

 
$
—

 
$
—

 
$
55.00

 
$
71.01

Apr – June
 
LLS
 
2,000
 
 
58.00
–
73.00

 
—

 
—

 
58.00

 
73.00

July – Sept
 
NYMEX
 
4,500
 
 
55.00
–
72.65

 
—

 
—

 
55.00

 
71.22

July – Sept
 
LLS
 
3,000
 
 
58.00
–
74.30

 
—

 
—

 
58.00

 
73.85

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural Gas Contracts:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2015 Collars
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oct – Dec
 
NYMEX
 
8,000
 
$
4.00
–
4.53

 
$
—

 
$
—

 
$
4.00

 
$
4.51



(1)
Contract prices are stated in $/Bbl and $/MMBtu for oil and natural gas contracts, respectively.
(2)
Contract volumes are stated in Bbls/d and MMBtus/d for oil and natural gas contracts, respectively.
(3)
Ranges presented for fixed-price swaps and enhanced swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For collars and three-way collars, ranges represent the lowest floor price and highest ceiling price for all open contracts for the period presented.
(4)
An enhanced swap is a fixed-price swap contract combined with a sold put feature (at a lower price) with the same counterparty. The value associated with the sold put is used to increase or enhance the fixed price of the swap. At the contract settlement date, (1) if the index price is higher than the swap price, we pay the counterparty the difference between the index price and swap price for the contracted volumes, (2) if the index price is lower than the swap price but at or above the sold put price, the counterparty pays us the difference between the index price and the swap price for the contracted volumes and (3) if the index price is lower than the sold put price, the counterparty pays us the difference between the swap price and the sold put price for the contracted volumes.
(5)
A three-way collar is a costless collar contract combined with a sold put feature (at a lower price) with the same counterparty. The value received for the sold put is used to enhance the contracted floor and ceiling price of the related collar. At the contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price for the contracted volumes, (2) if the index price is between the floor and ceiling price, no settlements occur, (3) if the index price is lower than the floor price but at or above the sold put price, the counterparty pays us the difference between the index price and the floor price for the contracted volumes and (4) if the index price is lower than the sold put price, the counterparty pays us the difference between the floor price and the sold put price for the contracted volumes.
Fair Value Measurements
Fair Value Measurements
Note 6. Fair Value Measurements

The FASC Fair Value Measurement 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"). 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 income 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 and fixed-price swaps that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The fixed-price swap features of our enhanced swaps are valued using a discounted cash flow model based upon forward commodity price curves. Our costless collars and the sold put features of our enhanced oil swaps and three-way 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, 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. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. At September 30, 2015, instruments in this category include non-exchange-traded enhanced swaps, costless collars and three-way collars that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for enhanced swaps, costless collars and three-way collars are consistent with the methodologies described above; however, the implied volatilities utilized in the valuation of Level 3 instruments are developed using a benchmark, which is considered a significant unobservable input. An increase or decrease of 100 basis points in the implied volatility inputs utilized in our fair value measurement would result in a change of approximately $0.1 million in the fair value of these instruments as of September 30, 2015.

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 the periods indicated:
 
 
Fair Value Measurements Using:
In thousands
 
Quoted Prices
in Active
Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Total
September 30, 2015
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Oil and natural gas derivative contracts – current
 
$
—

 
$
116,557

 
$
82,874

 
$
199,431

Total Assets
 
$
—

 
$
116,557

 
$
82,874

 
$
199,431

 
 
 
 
 
 
 
 
 
December 31, 2014
 
 

 
 

 
 

 
 

Assets:
 
 

 
 

 
 

 
 

Oil and natural gas derivative contracts – current
 
$
—

 
$
283,238

 
$
157,121

 
$
440,359

Oil and natural gas derivative contracts – long-term
 
—

 
34,862

 
31,325

 
66,187

Total Assets
 
$
—

 
$
318,100

 
$
188,446

 
$
506,546



Since we do not apply hedge accounting for our commodity derivative contracts, any gains and losses on our assets and liabilities are included in "Commodity derivatives expense (income)" in the accompanying Unaudited Condensed Consolidated Statements of Operations.

Level 3 Fair Value Measurements

The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the three and nine months ended September 30, 2015 and 2014:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
In thousands
 
2015
 
2014
 
2015
 
2014
Fair value of Level 3 instruments, beginning of period
 
$
112,358

 
$
(39,116
)
 
$
188,446

 
$
6,709

Fair value adjustments on commodity derivatives
 
21,089

 
61,411

 
38,872

 
15,586

Receipts on settlements of commodity derivatives
 
(50,573
)
 
—

 
(144,444
)
 
—

Fair value of Level 3 instruments, end of period
 
$
82,874

 
$
22,295

 
$
82,874

 
$
22,295

 
 
 
 
 
 
 
 
 
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
 
$
15,332

 
$
61,411

 
$
25,456

 
$
15,586



We utilize an income approach to value our Level 3 enhanced swaps, costless collars and three-way collars. We obtain and ensure the appropriateness of the significant inputs to the calculation, including contractual prices for the underlying instruments, maturity, forward prices for commodities, interest rates, volatility factors and credit worthiness, and the fair value estimate is prepared and reviewed on a quarterly basis. The following table details fair value inputs related to implied volatilities utilized in the valuation of our Level 3 oil derivative contracts:
 
 
Fair Value at
9/30/2015
(in thousands)
 
Valuation Technique
 
Unobservable Input
 
Volatility Range
Oil derivative contracts
 
$
82,874

 
Discounted cash flow / Black-Scholes
 
Volatility of Light Louisiana Sweet for settlement periods beginning after September 30, 2015
 
30.2% – 37.5%


Other Fair Value Measurements

The carrying value of loans under our Bank Credit Agreement approximate fair value, as they are 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 long-term debt using observable market data. The fair values of our senior subordinated notes are based on quoted market prices, resulting in an estimated fair value of our debt as of September 30, 2015 and December 31, 2014, excluding pipeline financing and capital lease obligations, of $1,855.0 million and $2,938.6 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 7. Commitments and Contingencies

We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses.  We are also subject to audits for various taxes (income, sales and use, and severance) in the various states in which we operate, and from time to time receive assessments for potential taxes that we may owe. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows, litigation is subject to inherent uncertainties.  Although a single or multiple adverse rulings or settlements could possibly have a material adverse effect on our finances, we only accrue for losses from litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated.

Delhi Field Release

In June 2013, a release of well fluids, consisting of a mixture of carbon dioxide, saltwater, natural gas and oil, was discovered (and reported) within an area of the Denbury-operated Delhi Field located in northern Louisiana. Our remediation efforts with respect to such release were completed during the fourth quarter of 2013; however, we continue to monitor the impacted area to confirm the effectiveness of the remediation efforts. Virtually all of our total recorded cost of $130.8 million has been incurred.

We maintain insurance policies to cover certain costs, damages and claims related to releases of well fluids and remediation. We received a $25.0 million cost reimbursement in October 2014 related to the Delhi Field release and remediation from our insurance carrier providing the first layer of our excess liability insurance coverage, and an additional $4.5 million cost reimbursement in August 2015 from our insurance carrier providing well control coverage. We have not reached any agreement with our remaining carriers as to further reimbursements, but given our belief that under our policies we are entitled to reimbursement of between approximately one-third and two-thirds of our total costs, we have filed suit to pursue further reimbursements, the ultimate outcome of which cannot be predicted.

In March 2015, Evolution Petroleum Company ("Evolution"), the parent of the entity which sold Denbury Onshore, LLC ("Denbury Onshore") its original interest in Delhi Field, filed an amended petition in a lawsuit which has been pending in the Texas district court in Houston since December 2013. Originally, that lawsuit involved ongoing disputes between Denbury Onshore and Evolution regarding the terms of the purchase documents under which Denbury Onshore bought its original Delhi Field interest, including disputes regarding allocation of costs in determining "payout" as defined in the agreements, and the extent and terms of assignment of reversionary interests in the unit back to Evolution following payout, along with related contractual terms. The amended petition added allegations of negligence and gross negligence against Denbury Onshore in connection with the June 2013 Delhi Field release, and for the first time estimated its damages attributable to its allegations in the case as exceeding $200 million. The amended petition also adds a claim for unspecified punitive damages. There has only been limited discovery in the case to date, and Evolution has not specified the basis for the amount of its claimed damages estimate. The case is currently set for trial in April 2016. We believe Evolution's claims with respect to this matter are without merit and intend to vigorously defend against them and pursue our rights under the purchase documents.
Additional Balance Sheet Details
Supplemental Balance Sheet Disclosures
Note 8. Additional Balance Sheet Details

Trade and Other Receivables, Net
 
 
September 30,
 
December 31,
In thousands
 
2015
 
2014
Commodity derivatives settlement receivables
 
$
53,103

 
$
59,755

Trade accounts receivable, net
 
35,495

 
45,407

Federal income tax receivable, net
 
—

 
37,652

Other receivables
 
29,859

 
14,141

Total
 
$
118,457

 
$
156,955



Accounts Payable and Accrued Liabilities
 
 
September 30,
 
December 31,
In thousands
 
2015
 
2014
Accrued interest
 
$
45,844

 
$
48,255

Accrued compensation
 
43,864

 
62,513

Accrued taxes other than income
 
41,253

 
39,816

Accrued lease operating expenses
 
36,609

 
56,798

Accounts payable
 
34,661

 
64,604

Accrued exploration and development costs
 
14,836

 
90,939

Other
 
33,447

 
31,833

Total
 
$
250,514

 
$
394,758

Basis of Presentation (Policies)
Organization and Nature of Operations 
Organization and Nature of Operations

Denbury Resources Inc., a Delaware corporation, is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions.  Our goal is to increase the value of our properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO2 enhanced oil recovery operations.
Interim Financial Statements - Basis of Accounting, Policy 
Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission ("SEC") and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements.  These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2014 (the "Form 10-K").  Unless indicated otherwise or the context requires, the terms "we," "our," "us," "Company" or "Denbury," refer to Denbury Resources Inc. and its subsidiaries.
Interim Financial Statements - Use of Estimates 
Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year.  In management's opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of September 30, 2015, our consolidated results of operations for the three and nine months ended September 30, 2015 and 2014, and our consolidated cash flows for the nine months ended September 30, 2015 and 2014.
Reclassifications 
Reclassifications

Certain prior period amounts have been reclassified to conform to 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.
Net Income (Loss) per Common Share 
Net Income (Loss) per Common Share

Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period.  Diluted net income (loss) 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-based equity awards.  For the three and nine months ended September 30, 2015 and 2014, there were no adjustments to net income (loss) for purposes of calculating basic and diluted net income (loss) per common share.

The following is a reconciliation of the weighted average shares used in the basic and diluted net income (loss) per common share calculations for the periods indicated:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
In thousands
 
2015
 
2014
 
2015
 
2014
Basic weighted average common shares outstanding
 
350,052

 
348,454

 
349,787

 
348,993

Potentially dilutive securities
 
 

 
 

 
 

 
 

Restricted stock, stock options, SARs and performance-based equity awards
 
—

 
2,464

 
—

 
2,354

Diluted weighted average common shares outstanding
 
350,052

 
350,918

 
349,787

 
351,347



Basic weighted average common shares exclude shares of nonvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income (loss) per common share (although all non-performance-based restricted stock is issued and outstanding upon grant).  For purposes of calculating diluted weighted average common shares during the three and nine months ended September 30, 2014, the nonvested restricted stock, stock options, SARs and performance-based equity awards are included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, the purchase price that the grantee will pay in the future for stock options, and any estimated future tax consequences recognized directly in equity.

The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
In thousands
 
2015
 
2014
 
2015
 
2014
Stock options and SARs
 
9,118

 
3,827

 
9,858

 
4,343

Restricted stock and performance-based equity awards
 
4,988

 
12

 
3,392

 
457

Oil and Natural Gas Properties Policy 
Write-Down of Oil and Natural Gas Properties

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 oil and natural gas 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 a 12-month rolling 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 oil and natural gas 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.

As a result of the precipitous and continuing decline in NYMEX oil prices since the fourth quarter of 2014, the rolling first-day-of-the-month average oil price for the preceding 12 months, after adjustments for market differentials by field, has fallen throughout 2015, from $79.55 per Bbl for the first quarter of 2015, to $68.48 per Bbl for the second quarter of 2015, and $56.74 per Bbl for the third quarter of 2015. In addition, the first-day-of-the-month average natural gas price for the preceding 12 months, after adjustments for market differentials by field, was $3.95 per Mcf for the first quarter of 2015, $3.74 per Mcf for the second quarter of 2015, and $3.64 per Mcf for the third quarter of 2015. These falling prices have led to our recognizing full cost pool ceiling test write-downs of $1.8 billion, $1.7 billion and $0.2 billion during the three months ended September 30, 2015, June 30, 2015, and March 31, 2015, respectively.
Goodwill Policy 
Impairment of Goodwill

We are required to test goodwill for impairment on an interim basis when we determine that it is more likely than not that the fair value of our reporting unit is less than its carrying amount. Our enterprise value (combined market capitalization plus a control premium of 10% and the fair value of our long-term debt) declined by approximately $2.5 billion between June 30 and September 30, 2015; therefore, we concluded that a goodwill impairment test was required to be performed in the third quarter.

For the goodwill impairment test, we compared the fair value of the reporting unit (enterprise value) to the fair value of its assets and liabilities. Oil and natural gas reserves, which represent the most significant assets requiring valuation, were estimated using the expected present value of future net cash flows method based on September 30, 2015, NYMEX oil and natural gas futures prices for the next five years, adjusted for current price differentials. In addition to future oil and natural gas pricing, the most significant assumptions impacting the projections of future net cash flows include projections of future rates of production, timing and amount of future development and operating costs, projected availability and cost of CO2, risk adjustment factors applied to probable and possible oil and natural gas reserve cash flows, projected recovery factors of oil and natural gas reserves, and a weighted average cost of capital discount rate applied to all net cash flows. Because the fair value of the reporting unit (enterprise value) did not exceed the fair value of assets and liabilities, we recorded a goodwill impairment charge of $1.3 billion during the three months ended September 30, 2015, to fully impair the carrying value of our goodwill. Approximately $1.0 billion of the $1.3 billion goodwill balance was associated with the March-2010 merger with Encore Acquisition Company.
Recent Accounting Pronouncements 
Recent Accounting Pronouncements

Debt Issuance Costs. In April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03"). ASU 2015-03 requires debt issuance costs related to a recognized debt liability to be presented as a direct reduction of the carrying amount of that debt in the balance sheet, consistent with the presentation of debt discounts. The amendments in this ASU are effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years, and early adoption is permitted. Entities will be required to apply the guidance on a retrospective basis to each period presented as a change in accounting principle. In August 2015, the FASB issued ASU 2015-15, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-15") which amends ASU 2015-03 to clarify the presentation and subsequent measurement of debt issuance costs associated with line of credit arrangements, such that entities may continue to apply current practice. The adoption of ASU 2015-03 and 2015-15 are currently not expected to have a material effect on our consolidated financial statements, other than balance sheet reclassifications.

Revenue Recognition. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers ("ASU 2014-09"). ASU 2014-09 amends the guidance for revenue recognition to replace numerous, industry-specific requirements. The core principle of the ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU implements a five-step process for customer contract revenue recognition that focuses on transfer of control, as opposed to transfer of risk and rewards. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers ("ASU 2015-14") which amends ASU 2014-09 and delays the effective date for public companies, such that the amendments in the ASU are effective for reporting periods beginning after December 15, 2017, and early adoption will be permitted for periods beginning after December 15, 2016. Entities can transition to the standard either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. Management is currently assessing the impact the adoption of ASU 2014-09 and ASU 2015-14 will have on our consolidated financial statements.
Commodity 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 settlements of expired contracts, are shown under "Commodity derivatives expense (income)" in our Unaudited Condensed Consolidated Statements of Operations.

Historically, we have entered 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 and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps and fixed-price swaps enhanced with a sold put. The production that we hedge has varied from year to year depending on our levels of debt, financial strength and expectation of future commodity prices. For the past several years, we have generally hedged a substantial portion of our forecasted production over an approximately 18 month to two year future period, as we believed it was beneficial to protect our future cash flows at then-projected oil prices for those future periods. However, during the significant and rapid decline in oil prices in the fourth quarter of 2014 and the first quarter of 2015, we deferred entering into new derivative contracts; we entered into limited oil hedging positions during the second quarter of 2015 covering the second and third quarters of 2016 as a result of the slight recovery in oil prices; and we have not entered into any additional hedges since the second quarter of 2015. Consequently, we currently have less of our production hedged and for a shorter future time period than we have generally had over the last several years.

We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis.  We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of September 30, 2015, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.
Fair Value Measurements 
The FASC Fair Value Measurement 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"). 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 income 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 and fixed-price swaps that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The fixed-price swap features of our enhanced swaps are valued using a discounted cash flow model based upon forward commodity price curves. Our costless collars and the sold put features of our enhanced oil swaps and three-way 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, 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. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. At September 30, 2015, instruments in this category include non-exchange-traded enhanced swaps, costless collars and three-way collars that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for enhanced swaps, costless collars and three-way collars are consistent with the methodologies described above; however, the implied volatilities utilized in the valuation of Level 3 instruments are developed using a benchmark, which is considered a significant unobservable input. An increase or decrease of 100 basis points in the implied volatility inputs utilized in our fair value measurement would result in a change of approximately $0.1 million in the fair value of these instruments as of September 30, 2015.

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.
Basis of Presentation (Tables)
Weighted average shares used in the basic and diluted net income (loss) per common share 
The following is a reconciliation of the weighted average shares used in the basic and diluted net income (loss) per common share calculations for the periods indicated:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
In thousands
 
2015
 
2014
 
2015
 
2014
Basic weighted average common shares outstanding
 
350,052

 
348,454

 
349,787

 
348,993

Potentially dilutive securities
 
 

 
 

 
 

 
 

Restricted stock, stock options, SARs and performance-based equity awards
 
—

 
2,464

 
—

 
2,354

Diluted weighted average common shares outstanding
 
350,052

 
350,918

 
349,787

 
351,347

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share 
The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
In thousands
 
2015
 
2014
 
2015
 
2014
Stock options and SARs
 
9,118

 
3,827

 
9,858

 
4,343

Restricted stock and performance-based equity awards
 
4,988

 
12

 
3,392

 
457

Long-Term Debt (Tables)
Components of Long-Term Debt
The following long-term debt and capital lease obligations were outstanding as of the dates indicated:
 
 
September 30,
 
December 31,
In thousands
 
2015
 
2014
Bank Credit Agreement
 
$
210,000

 
$
395,000

6⅜% Senior Subordinated Notes due 2021
 
400,000

 
400,000

5½% Senior Subordinated Notes due 2022
 
1,250,000

 
1,250,000

4⅝% Senior Subordinated Notes due 2023
 
1,200,000

 
1,200,000

Other Subordinated Notes, including premium of $8 and $11, respectively
 
2,258

 
2,746

Pipeline financings
 
214,179

 
220,583

Capital lease obligations
 
80,916

 
103,041

Total
 
3,357,353

 
3,571,370

Less: current obligations
 
(36,038
)
 
(35,470
)
Long-term debt and capital lease obligations
 
$
3,321,315

 
$
3,535,900

Commodity Derivative Contracts (Tables)
Commodity derivative contracts not classified as hedging instruments
The following table summarizes our commodity derivative contracts as of September 30, 2015, none of which are classified as hedging instruments in accordance with the Financial Accounting Standards Board Codification ("FASC") Derivatives and Hedging topic:
Months
 
Index Price
 
Volume (2)
 
Contract Prices (1)
Range (3)
 
Weighted Average Price
Swap
 
Sold Put
 
Floor
 
Ceiling
Oil Contracts:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2015 Enhanced Swaps (4)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oct – Dec
 
NYMEX
 
12,000
 
$
91.15
–
94.00

 
$
92.42

 
$
68.00

 
$
—

 
$
—

Oct – Dec
 
LLS
 
8,000
 
 
93.80
–
96.50

 
94.94

 
68.00

 
—

 
—

2015 Three-Way Collars (5)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oct – Dec
 
NYMEX
 
10,000
 
$
85.00
–
102.00

 
$
—

 
$
68.00

 
$
85.00

 
$
99.00

Oct – Dec
 
LLS
 
8,000
 
 
88.00
–
104.25

 
—

 
68.00

 
88.00

 
100.99

2016 Enhanced Swaps (4)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jan – Mar
 
NYMEX
 
12,000
 
$
90.65
–
93.35

 
$
92.43

 
$
68.00

 
$
—

 
$
—

Jan – Mar
 
LLS
 
8,000
 
 
93.70
–
95.45

 
94.81

 
68.50

 
—

 
—

Apr – June
 
NYMEX
 
2,000
 
 
90.35
–
90.35

 
90.35

 
68.00

 
—

 
—

Apr – June
 
LLS
 
6,000
 
 
93.30
–
93.50

 
93.38

 
70.00

 
—

 
—

2016 Fixed-Price Swaps
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Apr – June
 
NYMEX
 
11,500
 
$
60.30
–
63.75

 
$
61.84

 
$
—

 
$
—

 
$
—

Apr – June
 
LLS
 
3,500
 
 
64.20
–
66.15

 
64.99

 
—

 
—

 
—

2016 Three-Way Collars (5)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jan – Mar
 
NYMEX
 
10,000
 
$
85.00
–
101.25

 
$
—

 
$
68.00

 
$
85.00

 
$
99.85

Jan – Mar
 
LLS
 
6,000
 
 
88.00
–
103.15

 
—

 
68.00

 
88.00

 
102.10

Apr – June
 
NYMEX
 
2,000
 
 
85.00
–
95.50

 
—

 
68.00

 
85.00

 
95.50

Apr – June
 
LLS
 
2,000
 
 
88.00
–
98.25

 
—

 
70.00

 
88.00

 
98.25

2016 Collars
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Apr – June
 
NYMEX
 
5,000
 
$
55.00
–
72.25

 
$
—

 
$
—

 
$
55.00

 
$
71.01

Apr – June
 
LLS
 
2,000
 
 
58.00
–
73.00

 
—

 
—

 
58.00

 
73.00

July – Sept
 
NYMEX
 
4,500
 
 
55.00
–
72.65

 
—

 
—

 
55.00

 
71.22

July – Sept
 
LLS
 
3,000
 
 
58.00
–
74.30

 
—

 
—

 
58.00

 
73.85

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural Gas Contracts:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2015 Collars
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oct – Dec
 
NYMEX
 
8,000
 
$
4.00
–
4.53

 
$
—

 
$
—

 
$
4.00

 
$
4.51



(1)
Contract prices are stated in $/Bbl and $/MMBtu for oil and natural gas contracts, respectively.
(2)
Contract volumes are stated in Bbls/d and MMBtus/d for oil and natural gas contracts, respectively.
(3)
Ranges presented for fixed-price swaps and enhanced swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For collars and three-way collars, ranges represent the lowest floor price and highest ceiling price for all open contracts for the period presented.
(4)
An enhanced swap is a fixed-price swap contract combined with a sold put feature (at a lower price) with the same counterparty. The value associated with the sold put is used to increase or enhance the fixed price of the swap. At the contract settlement date, (1) if the index price is higher than the swap price, we pay the counterparty the difference between the index price and swap price for the contracted volumes, (2) if the index price is lower than the swap price but at or above the sold put price, the counterparty pays us the difference between the index price and the swap price for the contracted volumes and (3) if the index price is lower than the sold put price, the counterparty pays us the difference between the swap price and the sold put price for the contracted volumes.
(5)
A three-way collar is a costless collar contract combined with a sold put feature (at a lower price) with the same counterparty. The value received for the sold put is used to enhance the contracted floor and ceiling price of the related collar. At the contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price for the contracted volumes, (2) if the index price is between the floor and ceiling price, no settlements occur, (3) if the index price is lower than the floor price but at or above the sold put price, the counterparty pays us the difference between the index price and the floor price for the contracted volumes and (4) if the index price is lower than the sold put price, the counterparty pays us the difference between the floor price and the sold put price for the contracted volumes.
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 the periods indicated:
 
 
Fair Value Measurements Using:
In thousands
 
Quoted Prices
in Active
Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Total
September 30, 2015
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Oil and natural gas derivative contracts – current
 
$
—

 
$
116,557

 
$
82,874

 
$
199,431

Total Assets
 
$
—

 
$
116,557

 
$
82,874

 
$
199,431

 
 
 
 
 
 
 
 
 
December 31, 2014
 
 

 
 

 
 

 
 

Assets:
 
 

 
 

 
 

 
 

Oil and natural gas derivative contracts – current
 
$
—

 
$
283,238

 
$
157,121

 
$
440,359

Oil and natural gas derivative contracts – long-term
 
—

 
34,862

 
31,325

 
66,187

Total Assets
 
$
—

 
$
318,100

 
$
188,446

 
$
506,546

Changes in fair value of Level 3 assets and liabilities 
The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the three and nine months ended September 30, 2015 and 2014:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
In thousands
 
2015
 
2014
 
2015
 
2014
Fair value of Level 3 instruments, beginning of period
 
$
112,358

 
$
(39,116
)
 
$
188,446

 
$
6,709

Fair value adjustments on commodity derivatives
 
21,089

 
61,411

 
38,872

 
15,586

Receipts on settlements of commodity derivatives
 
(50,573
)
 
—

 
(144,444
)
 
—

Fair value of Level 3 instruments, end of period
 
$
82,874

 
$
22,295

 
$
82,874

 
$
22,295

 
 
 
 
 
 
 
 
 
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
 
$
15,332

 
$
61,411

 
$
25,456

 
$
15,586

Quantitative valuation techniques for assets and liabilities measured on a recurring basis (Level 3) 
The following table details fair value inputs related to implied volatilities utilized in the valuation of our Level 3 oil derivative contracts:
 
 
Fair Value at
9/30/2015
(in thousands)
 
Valuation Technique
 
Unobservable Input
 
Volatility Range
Oil derivative contracts
 
$
82,874

 
Discounted cash flow / Black-Scholes
 
Volatility of Light Louisiana Sweet for settlement periods beginning after September 30, 2015
 
30.2% – 37.5%
Additional Balance Sheet Details (Tables)
Trade and Other Receivables, Net 
Trade and Other Receivables, Net
 
 
September 30,
 
December 31,
In thousands
 
2015
 
2014
Commodity derivatives settlement receivables
 
$
53,103

 
$
59,755

Trade accounts receivable, net
 
35,495

 
45,407

Federal income tax receivable, net
 
—

 
37,652

Other receivables
 
29,859

 
14,141

Total
 
$
118,457

 
$
156,955

Accounts Payable and Accrued Liabilities 
Accounts Payable and Accrued Liabilities
 
 
September 30,
 
December 31,
In thousands
 
2015
 
2014
Accrued interest
 
$
45,844

 
$
48,255

Accrued compensation
 
43,864

 
62,513

Accrued taxes other than income
 
41,253

 
39,816

Accrued lease operating expenses
 
36,609

 
56,798

Accounts payable
 
34,661

 
64,604

Accrued exploration and development costs
 
14,836

 
90,939

Other
 
33,447

 
31,833

Total
 
$
250,514

 
$
394,758

Basis of Presentation (Reconciliation of Weighted Average Shares Table) (Details)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Weighted average shares used in the basic and diluted net income per common share
 
 
 
 
Basic weighted average common shares outstanding
350,052 
348,454 
349,787 
348,993 
Potentially dilutive securities
 
 
 
 
Restricted stock, stock options, SARs and performance-based equity awards
0 
2,464 
0 
2,354 
Diluted weighted average common shares outstanding
350,052 
350,918 
349,787 
351,347 
Basis of Presentation (Antidilutive Securities) (Details)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Stock Options and SARs
 
 
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
 
 
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount
9,118 
3,827 
9,858 
4,343 
Restricted stock and performance-based equity awards
 
 
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
 
 
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount
4,988 
12 
3,392 
457 
Basis of Presentation (Details Textuals) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended 12 Months Ended
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Oil [Member]
Jun. 30, 2015
Oil [Member]
Mar. 31, 2015
Oil [Member]
Sep. 30, 2015
Natural Gas [Member]
Jun. 30, 2015
Natural Gas [Member]
Mar. 31, 2015
Natural Gas [Member]
Accounting Policies [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
Write-down of oil and natural gas properties
$ 1,760,600 
$ 1,700,000 
$ 200,000 
$ 0 
$ 3,612,600 
$ 0 
 
 
 
 
 
 
Average Sales Price and Production Costs Per Unit of Production [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
Oil and Natural Gas Prices
 
 
 
 
 
 
56.74 
68.48 
79.55 
3.64 
3.74 
3.95 
Basis of Presentation Basis of Presentation (Impairment of Goodwill) (Details Textuals 2) (USD $)
3 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Jun. 30, 2015
Dec. 31, 2014
Business Combinations [Abstract]
 
 
 
 
 
 
Change in Enterprise Value
$ 2,500,000,000 
 
 
 
 
 
Goodwill, Impairment Loss
1,261,512,000 
0 
1,261,512,000 
0 
 
 
Business Acquisition [Line Items]
 
 
 
 
 
 
Goodwill
0 
 
0 
 
1,300,000,000 
1,283,590,000 
Encore Acquisition [Member]
 
 
 
 
 
 
Business Acquisition [Line Items]
 
 
 
 
 
 
Goodwill
 
 
 
 
$ 1,000,000,000 
 
Long-Term Debt (Components of Long-Term Debt) (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2015
Dec. 31, 2014
Debt Instrument [Line Items]
 
 
Bank Credit Agreement
$ 210,000 
$ 395,000 
Pipeline financings
214,179 
220,583 
Capital lease obligations
80,916 
103,041 
Total
3,357,353 
3,571,370 
Less current obligations
(36,038)
(35,470)
Long-term debt and capital lease obligations
3,321,315 
3,535,900 
6 3/8% Senior Subordinated Notes due 2021
 
 
Debt Instrument [Line Items]
 
 
Senior Subordinated Notes
400,000 
400,000 
Debt Instrument, Interest Rate, Stated Percentage
6.375% 
 
5 1/2% Senior Subordinated Notes due 2022
 
 
Debt Instrument [Line Items]
 
 
Senior Subordinated Notes
1,250,000 
1,250,000 
Debt Instrument, Interest Rate, Stated Percentage
5.50% 
 
4 5/8% Senior Subordinated Notes due 2023
 
 
Debt Instrument [Line Items]
 
 
Senior Subordinated Notes
1,200,000 
1,200,000 
Debt Instrument, Interest Rate, Stated Percentage
4.625% 
 
Other Subordinated Notes
 
 
Debt Instrument [Line Items]
 
 
Senior Subordinated Notes
2,258 
2,746 
Including premium of
$ 8 
$ 11 
Long-Term Debt (Details Textuals) (USD $)
1 Months Ended 3 Months Ended 9 Months Ended 1 Months Ended 9 Months Ended 0 Months Ended
May 31, 2015
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
May 1, 2015
Dec. 31, 2014
May 31, 2015
Year 2016
May 31, 2015
Year 2017
May 31, 2015
Q1
Year 2018
May 31, 2015
Q1
Year 2019
May 31, 2015
Q2
Year 2018
May 31, 2015
Q3
Year 2018
May 31, 2015
Q4
Year 2018
Sep. 30, 2015
Minimum
Sep. 30, 2015
Maximum
Apr. 30, 2014
5 1/2% Senior Subordinated Notes due 2022
Apr. 1, 2014
5 1/2% Senior Subordinated Notes due 2022
Jun. 30, 2014
8 1/4% Senior Subordinated Notes due 2020
Long Term Debt (Textuals) [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest in guarantor subsidiaries
 
100.00% 
 
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Repurchased Face Amount
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 996,300,000 
Gains (Losses) on Extinguishment of Debt
 
0 
0 
0 
113,908,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proceeds from issuance of senior subordinated notes
 
 
 
0 
1,250,000,000 
 
 
 
 
 
 
 
 
 
 
 
1,230,000,000 
 
 
Debt Instrument, Face Amount
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,250,000,000.00 
 
$1.6 Billion Revolving Credit Facility [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit, Borrowing Base
 
2,600,000,000.0 
 
2,600,000,000.0 
 
2,600,000,000.0 
3,000,000,000.0 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Current Borrowing Capacity
 
$ 1,600,000,000.0 
 
$ 1,600,000,000.0 
 
$ 1,600,000,000.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
Weighted average interest rate on Bank Credit Facility
 
 
 
1.80% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.30% 
0.375% 
 
 
 
Total Net Debt to EBITDAX Requirement
4.25 
 
 
 
 
 
 
 
 
6.0 
4.25 
5.5 
5.0 
5.0 
 
 
 
 
 
Senior Secured Debt to EBITDAX
 
 
 
 
 
 
 
2.5 
2.5 
 
 
 
 
 
 
 
 
 
 
EBITDAX to Consolidated Interest
 
 
 
 
 
 
 
2.25 
2.25 
 
 
 
 
 
 
 
 
 
 
Income Taxes (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2015
Income Tax Disclosure [Abstract]
 
Deferred Tax Assets, Valuation Allowance
$ 30.5 
Deferred Tax Assets, Operating Loss Carryforwards, State and Local
$ 37.0 
Stockholders' Equity (Details Textuals) (USD $)
1 Months Ended 3 Months Ended 9 Months Ended 1 Months Ended 3 Months Ended
Mar. 31, 2010
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Sep. 30, 2015
Sep. 30, 2014
Oct. 31, 2015
Subsequent Event
Nov. 4, 2015
Subsequent Event
Jun. 30, 2015
Adjustments for Error Correction
Mar. 31, 2015
Adjustments for Error Correction
Decrease in number of shares
 
 
 
 
 
 
 
 
 
 
 
 
1,430,819 
 
Share adjustment as a percentage of shares outstanding at March 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
0.40% 
Share correction amount
 
 
 
 
 
 
 
 
 
 
 
 
$ 22,100,000 
 
Reduction in goodwill
 
 
 
 
 
 
 
 
 
 
 
 
22,100,000 
 
Reduction in stockholders' equity
 
 
 
 
 
 
 
 
 
 
 
 
22,100,000 
 
Treasury Stock, Shares, Acquired
 
2,700,000 
 
 
 
 
 
12,400,000 
 
 
1,700,000 
 
 
 
Treasury Stock, Value, Acquired, Cost Method
 
6,900,000 
 
 
 
 
 
200,400,000 
 
 
4,800,000 
 
 
 
Stock Repurchase Program, Remaining Authorized Repurchase Amount
 
 
 
 
 
 
 
 
 
 
 
210,100,000 
 
 
Consideration issued
3,000,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dividends declared per common share
 
$ 0.0625 
$ 0.0625 
$ 0.0625 
$ 0.0625 
$ 0.0625 
$ 0.0625 
$ 0.0625 
$ 0.1875 
$ 0.1875 
 
 
 
 
Annualized common stock cash dividend per share
 
 
 
 
 
 
 
 
$ 0.25 
 
 
 
 
 
Cash dividend payment
 
 
 
 
 
 
 
 
$ 65,422,000 
$ 65,241,000 
 
 
 
 
Commodity Derivative Contracts (Details)
Sep. 30, 2015
Enhanced Swaps |
Crude Oil Contracts |
Year 2015 |
Q4 |
NYMEX
 
Derivative [Line Items]
 
Volume per Day
12,000 
Weighted average swap price
92.42 
Weighted average sold put price
68.00 
Enhanced Swaps |
Crude Oil Contracts |
Year 2015 |
Q4 |
NYMEX |
Minimum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
91.15 
Enhanced Swaps |
Crude Oil Contracts |
Year 2015 |
Q4 |
NYMEX |
Maximum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
94.00 
Enhanced Swaps |
Crude Oil Contracts |
Year 2015 |
Q4 |
LLS
 
Derivative [Line Items]
 
Volume per Day
8,000 
Weighted average swap price
94.94 
Weighted average sold put price
68.00 
Enhanced Swaps |
Crude Oil Contracts |
Year 2015 |
Q4 |
LLS |
Minimum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
93.80 
Enhanced Swaps |
Crude Oil Contracts |
Year 2015 |
Q4 |
LLS |
Maximum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
96.50 
Enhanced Swaps |
Crude Oil Contracts |
Year 2016 |
Q1 |
NYMEX
 
Derivative [Line Items]
 
Volume per Day
12,000 
Weighted average swap price
92.43 
Weighted average sold put price
68.00 
Enhanced Swaps |
Crude Oil Contracts |
Year 2016 |
Q1 |
NYMEX |
Minimum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
90.65 
Enhanced Swaps |
Crude Oil Contracts |
Year 2016 |
Q1 |
NYMEX |
Maximum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
93.35 
Enhanced Swaps |
Crude Oil Contracts |
Year 2016 |
Q1 |
LLS
 
Derivative [Line Items]
 
Volume per Day
8,000 
Weighted average swap price
94.81 
Weighted average sold put price
68.50 
Enhanced Swaps |
Crude Oil Contracts |
Year 2016 |
Q1 |
LLS |
Minimum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
93.70 
Enhanced Swaps |
Crude Oil Contracts |
Year 2016 |
Q1 |
LLS |
Maximum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
95.45 
Enhanced Swaps |
Crude Oil Contracts |
Year 2016 |
Q2 |
NYMEX
 
Derivative [Line Items]
 
Volume per Day
2,000 
Weighted average swap price
90.35 
Weighted average sold put price
68.00 
Enhanced Swaps |
Crude Oil Contracts |
Year 2016 |
Q2 |
NYMEX |
Minimum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
90.35 
Enhanced Swaps |
Crude Oil Contracts |
Year 2016 |
Q2 |
NYMEX |
Maximum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
90.35 
Enhanced Swaps |
Crude Oil Contracts |
Year 2016 |
Q2 |
LLS
 
Derivative [Line Items]
 
Volume per Day
6,000 
Weighted average swap price
93.38 
Weighted average sold put price
70.00 
Enhanced Swaps |
Crude Oil Contracts |
Year 2016 |
Q2 |
LLS |
Minimum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
93.30 
Enhanced Swaps |
Crude Oil Contracts |
Year 2016 |
Q2 |
LLS |
Maximum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
93.50 
Collar |
Crude Oil Contracts |
Year 2016 |
Q2 |
NYMEX
 
Derivative [Line Items]
 
Volume per Day
5,000 
Derivative, Floor Price
55.00 
Derivative, Cap Price
72.25 
Weighted average floor price
55.00 
Weighted average ceiling price
71.01 
Collar |
Crude Oil Contracts |
Year 2016 |
Q2 |
LLS
 
Derivative [Line Items]
 
Volume per Day
2,000 
Derivative, Floor Price
58.00 
Derivative, Cap Price
73.00 
Weighted average floor price
58.00 
Weighted average ceiling price
73.00 
Collar |
Crude Oil Contracts |
Year 2016 |
Q3 |
NYMEX
 
Derivative [Line Items]
 
Volume per Day
4,500 
Derivative, Floor Price
55.00 
Derivative, Cap Price
72.65 
Weighted average floor price
55.00 
Weighted average ceiling price
71.22 
Collar |
Crude Oil Contracts |
Year 2016 |
Q3 |
LLS
 
Derivative [Line Items]
 
Volume per Day
3,000 
Derivative, Floor Price
58.00 
Derivative, Cap Price
74.30 
Weighted average floor price
58.00 
Weighted average ceiling price
73.85 
Collar |
Natural Gas Contracts |
Year 2015 |
Q4 |
NYMEX
 
Derivative [Line Items]
 
Volume per Day
8,000 
Derivative, Floor Price
4.00 
Derivative, Cap Price
4.53 
Weighted average floor price
4.00 
Weighted average ceiling price
4.51 
Three-way Collar |
Crude Oil Contracts |
Year 2015 |
Q4 |
NYMEX
 
Derivative [Line Items]
 
Volume per Day
10,000 
Derivative, Floor Price
85.00 
Derivative, Cap Price
102.00 
Weighted average sold put price
68.00 
Weighted average floor price
85.00 
Weighted average ceiling price
99.00 
Three-way Collar |
Crude Oil Contracts |
Year 2015 |
Q4 |
LLS
 
Derivative [Line Items]
 
Volume per Day
8,000 
Derivative, Floor Price
88.00 
Derivative, Cap Price
104.25 
Weighted average sold put price
68.00 
Weighted average floor price
88.00 
Weighted average ceiling price
100.99 
Three-way Collar |
Crude Oil Contracts |
Year 2016 |
Q1 |
NYMEX
 
Derivative [Line Items]
 
Volume per Day
10,000 
Derivative, Floor Price
85.00 
Derivative, Cap Price
101.25 
Weighted average sold put price
68.00 
Weighted average floor price
85.00 
Weighted average ceiling price
99.85 
Three-way Collar |
Crude Oil Contracts |
Year 2016 |
Q1 |
LLS
 
Derivative [Line Items]
 
Volume per Day
6,000 
Derivative, Floor Price
88.00 
Derivative, Cap Price
103.15 
Weighted average sold put price
68.00 
Weighted average floor price
88.00 
Weighted average ceiling price
102.10 
Three-way Collar |
Crude Oil Contracts |
Year 2016 |
Q2 |
NYMEX
 
Derivative [Line Items]
 
Volume per Day
2,000 
Derivative, Floor Price
85.00 
Derivative, Cap Price
95.50 
Weighted average sold put price
68.00 
Weighted average floor price
85.00 
Weighted average ceiling price
95.50 
Three-way Collar |
Crude Oil Contracts |
Year 2016 |
Q2 |
LLS
 
Derivative [Line Items]
 
Volume per Day
2,000 
Derivative, Floor Price
88.00 
Derivative, Cap Price
98.25 
Weighted average sold put price
70.00 
Weighted average floor price
88.00 
Weighted average ceiling price
98.25 
Swap |
Crude Oil Contracts |
Year 2016 |
Q2 |
NYMEX
 
Derivative [Line Items]
 
Volume per Day
11,500 
Weighted average swap price
61.84 
Swap |
Crude Oil Contracts |
Year 2016 |
Q2 |
NYMEX |
Minimum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
60.30 
Swap |
Crude Oil Contracts |
Year 2016 |
Q2 |
NYMEX |
Maximum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
63.75 
Swap |
Crude Oil Contracts |
Year 2016 |
Q2 |
LLS
 
Derivative [Line Items]
 
Volume per Day
3,500 
Weighted average swap price
64.99 
Swap |
Crude Oil Contracts |
Year 2016 |
Q2 |
LLS |
Minimum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
64.20 
Swap |
Crude Oil Contracts |
Year 2016 |
Q2 |
LLS |
Maximum
 
Derivative [Line Items]
 
Derivative, Swap Type, Fixed Price
66.15 
Commodity Derivative Contracts (Details Textuals)
9 Months Ended
Sep. 30, 2015
Minimum
 
Derivative [Line Items]
 
Derivative, Average Remaining Maturity
18 months 
Maximum
 
Derivative [Line Items]
 
Derivative, Average Remaining Maturity
2 years 0 months 
Fair Value Measurements (Fair Value Hierarchy Table) (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2015
Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
 
 
Oil and natural gas derivative contracts - current
$ 199,431 
$ 440,359 
Oil and natural gas derivative contracts - long-term
0 
66,187 
Total Assets
199,431 
506,546 
Quoted Prices in Active Markets (Level 1)
 
 
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
 
 
Oil and natural gas derivative contracts - current
0 
0 
Oil and natural gas derivative contracts - long-term
 
0 
Total Assets
0 
0 
Significant Other Observable Inputs (Level 2)
 
 
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
 
 
Oil and natural gas derivative contracts - current
116,557 
283,238 
Oil and natural gas derivative contracts - long-term
 
34,862 
Total Assets
116,557 
318,100 
Significant Unobservable Inputs (Level 3)
 
 
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
 
 
Oil and natural gas derivative contracts - current
82,874 
157,121 
Oil and natural gas derivative contracts - long-term
 
31,325 
Total Assets
$ 82,874 
$ 188,446 
Fair Value Measurements (Level 3 Fair Value Measurements) (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
 
 
 
 
Fair value of Level 3 instruments, beginning of period
$ 112,358 
$ (39,116)
$ 188,446 
$ 6,709 
Fair value adjustments on commodity derivatives
21,089 
61,411 
38,872 
15,586 
Receipts on settlements of commodity derivatives
(50,573)
0 
(144,444)
0 
Fair value of Level 3 instruments, end of period
82,874 
22,295 
82,874 
22,295 
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
$ 15,332 
$ 61,411 
$ 25,456 
$ 15,586 
Fair Value Measurements (Level 3 Valuation Techniques) (Details) (USD $)
In Thousands, unless otherwise specified
9 Months Ended
Sep. 30, 2015
Jun. 30, 2015
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Dec. 31, 2013
Sep. 30, 2015
Income Approach Valuation Technique
Sep. 30, 2015
Income Approach Valuation Technique
Minimum
Sep. 30, 2015
Income Approach Valuation Technique
Maximum
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
 
 
 
 
 
 
 
 
 
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs
$ 82,874 
$ 112,358 
$ 188,446 
$ 22,295 
$ (39,116)
$ 6,709 
$ 82,874 
 
 
Expected Volatility Range
 
 
 
 
 
 
 
30.20% 
37.50% 
Fair Value Measurements (Details Textuals) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2015
Dec. 31, 2014
Fair Value Disclosures [Abstract]
 
 
Sensitivity Analysis of Fair Value, Impact of 100 Basis Point Increase or Decrease in Level 3 Inputs
$ 0.1 
 
Debt, Fair Value
$ 1,855.0 
$ 2,938.6 
Commitments and Contingencies (Details) (USD $)
1 Months Ended 28 Months Ended 7 Months Ended
Aug. 31, 2015
Oct. 31, 2014
Sep. 30, 2015
Sep. 30, 2015
Minimum
Sep. 30, 2015
Maximum
Loss Contingencies [Line Items]
 
 
 
 
 
Environmental remediation expense
 
 
$ 130,800,000 
 
 
Gross proceeds from insurance settlement, operating activities
4,500,000 
25,000,000.0 
 
 
 
Estimated percentage of environmental remediation expense estimate to be recovered through insurance proceeds
 
 
 
33.3333% 
66.6667% 
Loss Contingency, Damages Sought, Value
 
 
 
$ 200,000,000 
 
Additional Balance Sheet Details (Trade and Other Receivables, Net) (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2015
Dec. 31, 2014
Receivables [Abstract]
 
 
Commodity derivatives settlement receivables
$ 53,103 
$ 59,755 
Trade accounts receivable, net
35,495 
45,407 
Federal income tax receivable, net
0 
37,652 
Other receivables
29,859 
14,141 
Total
$ 118,457 
$ 156,955 
Additional Balance Sheet Details (Accounts Payable and Accrued Liabilities) (Details) (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2015
Dec. 31, 2014
Accounts Payable and Accrued Liabilities, Current [Abstract]
 
 
Accrued interest
$ 45,844 
$ 48,255 
Accrued compensation
43,864 
62,513 
Accrued taxes other than income
41,253 
39,816 
Accrued lease operating expenses
36,609 
56,798 
Accounts payable
34,661 
64,604 
Accrued exploration and development costs
14,836 
90,939 
Other
33,447 
31,833 
Total
$ 250,514 
$ 394,758