Document_and_Entity_Informatio
Document and Entity Information | 3 Months Ended | |
Mar. 31, 2015 | Apr. 30, 2015 | |
Document And Company Information [Abstract] | ||
Document Type | 10-Q | |
Document Period End Date | 31-Mar-15 | |
Amendment Flag | FALSE | |
Document Fiscal Year Focus | 2015 | |
Document Fiscal Period Focus | Q1 | |
Current Fiscal Year End Date | -19 | |
Entity Registrant Name | Denbury Resources Inc. | |
Entity Central Index Key | 945764 | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 356,932,779 |
Condensed_Consolidated_Balance
Condensed Consolidated Balance Sheets (Unaudited) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Current assets | ||
Cash and cash equivalents | $6,021 | $23,153 |
Accrued production receivable | 148,125 | 181,761 |
Trade and other receivables, net | 139,904 | 156,955 |
Derivative assets | 421,702 | 440,359 |
Deferred tax assets | 42,268 | 0 |
Other current assets | 10,634 | 10,452 |
Total current assets | 768,654 | 812,680 |
Oil and natural gas properties (using full cost accounting) | ||
Proved properties | 9,873,513 | 9,782,337 |
Unevaluated properties | 933,566 | 918,406 |
CO2 properties | 1,171,815 | 1,162,538 |
Pipelines and plants | 2,272,184 | 2,269,564 |
Other property and equipment | 465,886 | 468,051 |
Less accumulated depletion, depreciation, amortization and impairment | -4,536,890 | -4,248,652 |
Net property and equipment | 10,180,074 | 10,352,244 |
Derivative assets | 19,456 | 66,187 |
Goodwill | 1,283,590 | 1,283,590 |
Other assets | 216,282 | 213,101 |
Total assets | 12,468,056 | 12,727,802 |
Current liabilities | ||
Accounts payable and accrued liabilities | 234,541 | 394,758 |
Oil and gas production payable | 110,454 | 128,170 |
Deferred tax liabilities | 0 | 81,727 |
Current maturities of long-term debt | 36,679 | 35,470 |
Total current liabilities | 381,674 | 640,125 |
Long-term liabilities | ||
Long-term debt, net of current portion | 3,596,085 | 3,535,900 |
Asset retirement obligations | 128,599 | 126,411 |
Deferred tax liabilities | 2,752,857 | 2,694,842 |
Other liabilities | 25,360 | 26,668 |
Total long-term liabilities | 6,502,901 | 6,383,821 |
Commitments and contingencies (Note 6) | ||
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; 415,665,644 and 411,779,911 shares issued, respectively | 416 | 412 |
Paid-in capital in excess of par | 3,238,914 | 3,230,418 |
Retained earnings | 3,262,508 | 3,392,465 |
Accumulated other comprehensive loss | -192 | -209 |
Treasury stock, at cost, 58,651,623 and 58,415,507 shares, respectively | -918,165 | -919,230 |
Total stockholders' equity | 5,583,481 | 5,703,856 |
Total liabilities and stockholders' equity | $12,468,056 | $12,727,802 |
Condensed_Consolidated_Balance1
Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
Stockholders' equity | ||
Preferred stock, par value | $0.00 | $0.00 |
Preferred stock, shares authorized (actual number) | 25,000,000 | 25,000,000 |
Preferred stock, shares issued (actual number) | 0 | 0 |
Preferred stock, shares outstanding (actual number) | 0 | 0 |
Common stock, par value | $0.00 | $0.00 |
Common stock, shares authorized (actual number) | 600,000,000 | 600,000,000 |
Common stock, shares issued (actual number) | 415,665,644 | 411,779,911 |
Treasury stock, shares (actual number) | 58,651,623 | 58,415,507 |
Condensed_Consolidated_Stateme
Condensed Consolidated Statements of Operations (Unaudited) (USD $) | 3 Months Ended | |
In Thousands, except Per Share data, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Revenues and other income | ||
Oil, natural gas, and related product sales | $297,470 | $623,846 |
CO2 and helium sales and transportation fees | 6,972 | 10,761 |
Interest income and other income | 3,207 | 7,137 |
Total revenues and other income | 307,649 | 641,744 |
Expenses | ||
Lease operating expenses | 141,084 | 170,379 |
Marketing and plant operating expenses | 11,685 | 16,786 |
CO2 and helium discovery and operating expenses | 947 | 5,205 |
Taxes other than income | 26,679 | 45,945 |
General and administrative expenses | 46,280 | 43,693 |
Interest, net of amounts capitalized of $8,409 and $5,756, respectively | 40,099 | 48,834 |
Depletion, depreciation, and amortization | 149,958 | 141,130 |
Commodity derivatives expense (income) | -83,076 | 76,669 |
Write-down of oil and natural gas properties | 146,200 | 0 |
Total expenses | 479,856 | 548,641 |
Income (loss) before income taxes | -172,207 | 93,103 |
Income tax provision (benefit) | -64,461 | 34,793 |
Net income (loss) | ($107,746) | $58,310 |
Net income (loss) per common share | ||
Basic | ($0.31) | $0.17 |
Diluted | ($0.31) | $0.17 |
Dividends declared per common share | $0.06 | $0.06 |
Weighted average common shares outstanding | ||
Basic | 350,688 | 350,747 |
Diluted | 350,688 | 352,925 |
Condensed_Consolidated_Stateme1
Condensed Consolidated Statements of Operations (Unaudited) (Parenthetical) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Expenses | ||
Capitalized interest | $8,409 | $5,756 |
Condensed_Consolidated_Stateme2
Condensed Consolidated Statements of Comprehensive Operations (Unaudited) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Statement of Comprehensive Income [Abstract] | ||
Net income (loss) | ($107,746) | $58,310 |
Other comprehensive income, net of income tax: | ||
Interest rate lock derivative contracts reclassified to income, net of tax of $11 and $13, respectively | 17 | 15 |
Total other comprehensive income | 17 | 15 |
Comprehensive income (loss) | ($107,729) | $58,325 |
Condensed_Consolidated_Stateme3
Condensed Consolidated Statements of Comprehensive Operations (Unaudited) (Parenthetical) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Other comprehensive income, net of income tax: | ||
Tax for interest rate lock derivative contracts reclassified to income | $11 | $13 |
Condensed_Consolidated_Stateme4
Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Cash flows from operating activities | ||
Net income (loss) | ($107,746) | $58,310 |
Adjustments to reconcile net income (loss) to cash flow from operating activities | ||
Depletion, depreciation, and amortization | 149,958 | 141,130 |
Write-down of oil and natural gas properties | 146,200 | 0 |
Deferred income taxes | -66,036 | 30,175 |
Stock-based compensation | 7,849 | 8,346 |
Commodity derivatives expense (income) | -83,076 | 76,669 |
Settlements of commodity derivatives | 148,465 | -27,169 |
Amortization of debt issuance costs and discounts | 2,221 | 3,520 |
Other, net | -2,359 | -2,297 |
Changes in assets and liabilities, net of effects from acquisitions | ||
Accrued production receivable | 33,636 | -24,937 |
Trade and other receivables | 16,828 | 6,372 |
Other current and long-term assets | -6,136 | -5,459 |
Accounts payable and accrued liabilities | -83,248 | -52,580 |
Oil and natural gas production payable | -17,716 | 3,916 |
Other liabilities | -1,076 | -1,138 |
Net cash provided by operating activities | 137,764 | 214,858 |
Cash flows from investing activities | ||
Oil and natural gas capital expenditures | -162,192 | -198,237 |
Acquisitions of oil and natural gas properties | -261 | 0 |
CO2 capital expenditures | -14,855 | -15,909 |
Pipelines and plants capital expenditures | -12,455 | -22,597 |
Purchases of other assets | -2,965 | -1,645 |
Other | 150 | 1,634 |
Net cash used in investing activities | -192,578 | -236,754 |
Cash flows from financing activities | ||
Bank repayments | -595,000 | -815,000 |
Bank borrowings | 665,000 | 1,075,000 |
Common stock repurchase program | 0 | -211,356 |
Cash dividends paid | -22,068 | -21,727 |
Other | -10,250 | -9,316 |
Net cash provided by financing activities | 37,682 | 17,601 |
Net decrease in cash and cash equivalents | -17,132 | -4,295 |
Cash and cash equivalents at beginning of period | 23,153 | 12,187 |
Cash and cash equivalents at end of period | $6,021 | $7,892 |
Basis_of_Presentation
Basis of Presentation | 3 Months Ended | ||||||
Mar. 31, 2015 | |||||||
Accounting Policies [Abstract] | |||||||
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 March 31, 2015, our consolidated results of operations for the three months ended March 31, 2015 and 2014, and our consolidated cash flows for the three months ended March 31, 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 months ended March 31, 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 | |||||||
March 31, | |||||||
In thousands | 2015 | 2014 | |||||
Basic weighted average common shares outstanding | 350,688 | 350,747 | |||||
Potentially dilutive securities | |||||||
Restricted stock, stock options, SARs and performance-based equity awards | — | 2,178 | |||||
Diluted weighted average common shares outstanding | 350,688 | 352,925 | |||||
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 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 months ended March 31, 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 | |||||||
March 31, | |||||||
In thousands | 2015 | 2014 | |||||
Stock options and SARs | 10,507 | 4,254 | |||||
Restricted stock and performance-based equity awards | 2,948 | 21 | |||||
Oil and Natural Gas Properties | |||||||
Ceiling Test. The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as (1) the present value of estimated future net revenues from proved 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. | |||||||
We recognized a full cost pool ceiling test write-down of $146.2 million during the three months ended March 31, 2015, with first-day-of-the-month prices for the preceding 12 months, after adjustments for market differentials by field, of $79.55 per Bbl for crude oil and $3.95 per Mcf for natural gas. If oil prices remain at or near late-April 2015 levels in subsequent periods, we expect that we could record significantly larger write-downs in subsequent quarters, as the 12-month average price used in determining the full cost ceiling value will continue to decline during each rolling quarterly period in 2015. | |||||||
Goodwill | |||||||
We test goodwill for impairment annually during the fourth quarter; however, as a result of the relationship between our market capitalization and our book value of stockholders' equity and the sustained decrease in our share price, we also performed a goodwill impairment assessment as of March 31, 2015. Because our enterprise value (combined market capitalization plus a control premium of 10% and the fair value of our long-term debt) was below the combined book value of our stockholders' equity and long-term debt as of March 31, 2015, we were required to proceed to step two of the goodwill impairment test. Oil and natural gas reserves, which represent the most significant assets requiring valuation, were estimated using the expected present value of future cash flows method based on March 31, 2015, NYMEX oil and natural gas futures prices for the next five years, adjusted for current price differentials. Consistent with the results of our fourth quarter 2014 goodwill analysis, the implied fair value of goodwill calculated in this quantitative assessment significantly exceeded the corresponding book value of goodwill. Therefore, we did not record any goodwill impairment during the first quarter of 2015, nor have we recorded a goodwill impairment historically. | |||||||
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. Management is currently assessing the impact the adoption of ASU 2015-03 will have on our consolidated financial statements. | |||||||
Consolidation. In February 2015, the FASB issued ASU 2015-02, Consolidation: Amendments to the Consolidation Analysis ("ASU 2015-02"). ASU 2015-02 amends the guidance for consolidation of certain types of legal entities. Under the ASU, all reporting entities are required to evaluate whether they should consolidate certain legal entities under the revised consolidation model. The amendment focuses on limited partnerships and similar legal entities, fees paid to a decision maker or a service provider as a variable interest, fee arrangements and related party effects on the primary beneficiary determination, and certain investment funds. The amendments in this ASU are effective for annual periods beginning after December 15, 2015, and interim periods within those years, and early adoption is permitted. Entities can transition to the standard either retrospectively to each period presented or as a cumulative-effect adjustment as of the beginning of the fiscal year of adoption. The adoption of ASU 2015-02 is currently not expected to have a material effect on our consolidated financial statements. | |||||||
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. The amendments in this ASU are currently effective for reporting periods beginning after December 15, 2017, and early adoption is prohibited. However, in April 2015, the FASB proposed delaying the effective date for one year. 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 will have on our consolidated financial statements. |
LongTerm_Debt
Long-Term Debt | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Debt Disclosure [Abstract] | |||||||||
Long-Term Debt | Note 2. Long-Term Debt | ||||||||
The following long-term debt and capital lease obligations were outstanding as of the dates indicated: | |||||||||
March 31, | December 31, | ||||||||
In thousands | 2015 | 2014 | |||||||
Bank Credit Agreement | $ | 465,000 | $ | 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 $10 and $11, respectively | 2,744 | 2,746 | |||||||
Pipeline financings | 218,486 | 220,583 | |||||||
Capital lease obligations | 96,534 | 103,041 | |||||||
Total | 3,632,764 | 3,571,370 | |||||||
Less: current obligations | (36,679 | ) | (35,470 | ) | |||||
Long-term debt and capital lease obligations | $ | 3,596,085 | $ | 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 an initial borrowing base of $3.0 billion and aggregate lender commitments of $1.6 billion. Loans under the Bank Credit Agreement mature in December 2019. The weighted average interest rate on borrowings outstanding as of March 31, 2015, under the Bank Credit Agreement was 1.5%. 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 March 31, 2015, we were in compliance with all debt covenants under the Bank Credit Agreement. | |||||||||
In connection with the borrowing base redetermination completed in early May 2015 under our Bank Credit Agreement, 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, this borrowing base reduction has no impact on our liquidity. Redeterminations under our Bank Credit Agreement occur annually, making our next scheduled redetermination in May 2016. | |||||||||
In conjunction with the May 2015 redetermination, we also entered into the First Amendment to the Bank Credit Agreement (the "First Amendment"). This First Amendment restructures 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 were 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 filed on December 15, 2014, as Exhibit 10.1 to our Current Report on Form 8-K or the First Amendment, which is filed as Exhibit 10(a) to this Quarterly Report on Form 10-Q. |
Stockholders_Equity
Stockholders Equity | 3 Months Ended |
Mar. 31, 2015 | |
Stockholders' Equity Note [Abstract] | |
Stockholders' Equity | Note 3. Stockholders' Equity |
Dividends | |
During January of both 2015 and 2014, the Company's Board of Directors declared quarterly cash dividends of $0.0625 per common share. Dividends totaling $22.1 million and $21.7 million were paid to stockholders during the three months ended March 31, 2015 and 2014, respectively. See Note 8, Subsequent Event, for details regarding the dividend declared and to be paid in the second quarter of 2015. | |
Stock Repurchase Program | |
Under our board-authorized share repurchase program, we repurchased 12.4 million shares of Denbury common stock for $200.4 million during the first quarter of 2014. In November 2014, the Company's Board of Directors suspended the common share repurchase program in light of commodity price uncertainty and to protect our financial position. | |
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 ending 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 | 3 Months Ended | ||||||||||||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||
Commodity Derivative Contracts | Note 4. 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. | |||||||||||||||||||||||||||
From time to time, we enter into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production. We do not hold or issue derivative financial instruments for trading purposes. These contracts have historically consisted 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 employed a strategy to hedge a substantial portion of our forecasted production approximately 18 months to two years in the future (from the then-current quarter), as we believe it is important to protect our future cash flow to provide a level of assurance for our capital spending and dividends in those future periods. Due to the significant and rapid decline in oil prices over the last six months, we have deferred entering into new derivative contracts through the first quarter of 2015; thus, the percentage of our forecasted production we have hedged and the duration of our hedges are less than what we have had in the recent past. In April 2015, we began entering into new oil hedging positions in order to provide more certainty to our future cash flows. As of May 5, 2015, these fixed-price swaps and collars, which are not reflected in the table below and which comprise both NYMEX and LLS hedges, include (1) fixed-price swaps covering an additional 15,000 Bbls per day in the second quarter of 2016, with weighted-average prices of approximately $63 per Bbl and (2) collars covering an additional 4,500 Bbls per day and 5,000 Bbls per day in the second and third quarters of 2016, respectively, with weighted-average floors of approximately $56 per Bbl and weighted-average ceilings of approximately $72 per Bbl. | |||||||||||||||||||||||||||
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 March 31, 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 March 31, 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) | |||||||||||||||||||||||||||
Apr – June | NYMEX | 8,000 | $ | 90 | – | 90 | $ | 90 | $ | 65.75 | $ | — | $ | — | |||||||||||||
Apr – June | LLS | 16,000 | 93.2 | – | 94 | 93.65 | 68 | — | — | ||||||||||||||||||
July – Sept | NYMEX | 10,000 | 90 | – | 90.1 | 90.02 | 65.3 | — | — | ||||||||||||||||||
July – Sept | LLS | 16,000 | 93.2 | – | 94 | 93.65 | 68 | — | — | ||||||||||||||||||
Oct – Dec | NYMEX | 12,000 | 91.15 | – | 94 | 92.42 | 68 | — | — | ||||||||||||||||||
Oct – Dec | LLS | 8,000 | 93.8 | – | 96.5 | 94.94 | 68 | — | — | ||||||||||||||||||
2015 Collars | |||||||||||||||||||||||||||
Apr – June | NYMEX | 30,000 | $ | 80 | – | 95.25 | $ | — | $ | — | $ | 80 | $ | 94.72 | |||||||||||||
Apr – June | LLS | 4,000 | 85 | – | 102.5 | — | — | 85 | 101.75 | ||||||||||||||||||
July – Sept | NYMEX | 28,000 | 80 | – | 95.25 | — | — | 80 | 95.05 | ||||||||||||||||||
July – Sept | LLS | 4,000 | 85 | – | 100 | — | — | 85 | 99.5 | ||||||||||||||||||
2015 Three-Way Collars (5) | |||||||||||||||||||||||||||
Oct – Dec | NYMEX | 10,000 | $ | 85 | – | 102 | $ | — | $ | 68 | $ | 85 | $ | 99 | |||||||||||||
Oct – Dec | LLS | 8,000 | 88 | – | 104.25 | — | 68 | 88 | 100.99 | ||||||||||||||||||
2016 Enhanced Swaps (4) | |||||||||||||||||||||||||||
Jan – Mar | NYMEX | 12,000 | $ | 90.65 | – | 93.35 | $ | 92.43 | $ | 68 | $ | — | $ | — | |||||||||||||
Jan – Mar | LLS | 8,000 | 93.7 | – | 95.45 | 94.81 | 68.5 | — | — | ||||||||||||||||||
Apr – June | NYMEX | 2,000 | 90.35 | – | 90.35 | 90.35 | 68 | — | — | ||||||||||||||||||
Apr – June | LLS | 6,000 | 93.3 | – | 93.5 | 93.38 | 70 | — | — | ||||||||||||||||||
2016 Three-Way Collars (5) | |||||||||||||||||||||||||||
Jan – Mar | NYMEX | 10,000 | $ | 85 | – | 101.25 | $ | — | $ | 68 | $ | 85 | $ | 99.85 | |||||||||||||
Jan – Mar | LLS | 6,000 | 88 | – | 103.15 | — | 68 | 88 | 102.1 | ||||||||||||||||||
Apr – June | NYMEX | 2,000 | 85 | – | 95.5 | — | 68 | 85 | 95.5 | ||||||||||||||||||
Apr – June | LLS | 2,000 | 88 | – | 98.25 | — | 70 | 88 | 98.25 | ||||||||||||||||||
Natural Gas Contracts: | |||||||||||||||||||||||||||
2015 Collars | |||||||||||||||||||||||||||
Apr – Dec | NYMEX | 8,000 | $ | 4 | – | 4.53 | $ | — | $ | — | $ | 4 | $ | 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 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 | 3 Months Ended | ||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||||||
Fair Value Measurements | Note 5. 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. 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, including maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. | ||||||||||||||||
• | Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. At March 31, 2015, instruments in this category include non-exchange-traded oil derivatives 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, since the instruments are based on regional pricing other than NYMEX, certain inputs to the valuation are less observable. 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 $0.9 million in the fair value of these instruments as of March 31, 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 | Significant | Significant | Total | |||||||||||||
in Active | Other | Unobservable | |||||||||||||||
Markets | Observable | Inputs | |||||||||||||||
(Level 1) | Inputs | (Level 3) | |||||||||||||||
(Level 2) | |||||||||||||||||
March 31, 2015 | |||||||||||||||||
Assets: | |||||||||||||||||
Oil and natural gas derivative contracts – current | $ | — | $ | 270,126 | $ | 151,576 | $ | 421,702 | |||||||||
Oil and natural gas derivative contracts – long-term | — | 6,017 | 13,439 | 19,456 | |||||||||||||
Total Assets | $ | — | $ | 276,143 | $ | 165,015 | $ | 441,158 | |||||||||
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 months ended March 31, 2015 and 2014: | |||||||||||||||||
Three Months Ended | |||||||||||||||||
March 31, | |||||||||||||||||
In thousands | 2015 | 2014 | |||||||||||||||
Fair value of Level 3 instruments, beginning of period | $ | 188,446 | $ | 6,709 | |||||||||||||
Fair value adjustments on commodity derivatives | 25,085 | (12,806 | ) | ||||||||||||||
Receipt on settlements of commodity derivatives | (48,516 | ) | — | ||||||||||||||
Fair value of Level 3 instruments, end of period | $ | 165,015 | $ | (6,097 | ) | ||||||||||||
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets or liabilities still held at the reporting date | $ | 23,099 | $ | (12,806 | ) | ||||||||||||
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 | Valuation Technique | Unobservable Input | Range | ||||||||||||||
3/31/15 | |||||||||||||||||
(in thousands) | |||||||||||||||||
Oil derivative contracts | $ | 165,015 | Discounted cash flow / Black-Scholes | Volatility of Light Louisiana Sweet for settlement periods beginning after March 31, 2015 | 25.8% – 38.2% | ||||||||||||
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. The estimated fair value of our debt as of March 31, 2015 and December 31, 2014, excluding pipeline financing and capital lease obligations, was $2,998.6 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 | 3 Months Ended |
Mar. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Note 6. 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. We completed our remediation efforts with respect to such release 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 cost estimate 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 insurance 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 October 2015. We believe Evolution's claims in the First Amended Petition relating to the June 2013 Delhi Field release are without merit and intend to vigorously defend against them and pursue our rights under the purchase documents. |
Additional_Balance_Sheet_Detai
Additional Balance Sheet Details | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Accounts Payable and Accrued Liabilities, Current [Abstract] | |||||||||
Accounts Payable and Accrued Liabilities | Note 7. Additional Balance Sheet Details | ||||||||
Accounts Payable and Accrued Liabilities | |||||||||
March 31, | December 31, | ||||||||
In thousands | 2015 | 2014 | |||||||
Accounts payable | $ | 52,662 | $ | 64,604 | |||||
Accrued interest | 45,883 | 48,255 | |||||||
Accrued lease operating expenses | 38,197 | 56,798 | |||||||
Accrued exploration and development costs | 26,560 | 90,939 | |||||||
Accrued compensation | 24,517 | 62,513 | |||||||
Taxes payable | 16,697 | 39,816 | |||||||
Other | 30,025 | 31,833 | |||||||
Total | $ | 234,541 | $ | 394,758 | |||||
Subsequent_Event
Subsequent Event | 3 Months Ended |
Mar. 31, 2015 | |
Subsequent Events [Abstract] | |
Subsequent Event | Note 8. Subsequent Event |
Dividend Declaration | |
On April 28, 2015, the Board of Directors declared a dividend of $0.0625 per share on our outstanding common stock, payable on June 30, 2015, to stockholders of record at the close of business on May 26, 2015. |
Basis_of_Presentation_Policies
Basis of Presentation (Policies) | 3 Months Ended | ||||||
Mar. 31, 2015 | |||||||
Accounting Policies [Abstract] | |||||||
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 March 31, 2015, our consolidated results of operations for the three months ended March 31, 2015 and 2014, and our consolidated cash flows for the three months ended March 31, 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 months ended March 31, 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 | |||||||
March 31, | |||||||
In thousands | 2015 | 2014 | |||||
Basic weighted average common shares outstanding | 350,688 | 350,747 | |||||
Potentially dilutive securities | |||||||
Restricted stock, stock options, SARs and performance-based equity awards | — | 2,178 | |||||
Diluted weighted average common shares outstanding | 350,688 | 352,925 | |||||
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 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 months ended March 31, 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 | |||||||
March 31, | |||||||
In thousands | 2015 | 2014 | |||||
Stock options and SARs | 10,507 | 4,254 | |||||
Restricted stock and performance-based equity awards | 2,948 | 21 | |||||
Oil and Natural Gas Properties Policy | Oil and Natural Gas Properties | ||||||
Ceiling Test. The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as (1) the present value of estimated future net revenues from proved 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. | |||||||
We recognized a full cost pool ceiling test write-down of $146.2 million during the three months ended March 31, 2015, with first-day-of-the-month prices for the preceding 12 months, after adjustments for market differentials by field, of $79.55 per Bbl for crude oil and $3.95 per Mcf for natural gas. If oil prices remain at or near late-April 2015 levels in subsequent periods, we expect that we could record significantly larger write-downs in subsequent quarters, as the 12-month average price used in determining the full cost ceiling value will continue to decline during each rolling quarterly period in 2015. | |||||||
Goodwill Policy | Goodwill | ||||||
We test goodwill for impairment annually during the fourth quarter; however, as a result of the relationship between our market capitalization and our book value of stockholders' equity and the sustained decrease in our share price, we also performed a goodwill impairment assessment as of March 31, 2015. Because our enterprise value (combined market capitalization plus a control premium of 10% and the fair value of our long-term debt) was below the combined book value of our stockholders' equity and long-term debt as of March 31, 2015, we were required to proceed to step two of the goodwill impairment test. Oil and natural gas reserves, which represent the most significant assets requiring valuation, were estimated using the expected present value of future cash flows method based on March 31, 2015, NYMEX oil and natural gas futures prices for the next five years, adjusted for current price differentials. Consistent with the results of our fourth quarter 2014 goodwill analysis, the implied fair value of goodwill calculated in this quantitative assessment significantly exceeded the corresponding book value of goodwill. Therefore, we did not record any goodwill impairment during the first quarter of 2015, nor have we recorded a goodwill impairment historically. | |||||||
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. Management is currently assessing the impact the adoption of ASU 2015-03 will have on our consolidated financial statements. | |||||||
Consolidation. In February 2015, the FASB issued ASU 2015-02, Consolidation: Amendments to the Consolidation Analysis ("ASU 2015-02"). ASU 2015-02 amends the guidance for consolidation of certain types of legal entities. Under the ASU, all reporting entities are required to evaluate whether they should consolidate certain legal entities under the revised consolidation model. The amendment focuses on limited partnerships and similar legal entities, fees paid to a decision maker or a service provider as a variable interest, fee arrangements and related party effects on the primary beneficiary determination, and certain investment funds. The amendments in this ASU are effective for annual periods beginning after December 15, 2015, and interim periods within those years, and early adoption is permitted. Entities can transition to the standard either retrospectively to each period presented or as a cumulative-effect adjustment as of the beginning of the fiscal year of adoption. The adoption of ASU 2015-02 is currently not expected to have a material effect on our consolidated financial statements. | |||||||
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. The amendments in this ASU are currently effective for reporting periods beginning after December 15, 2017, and early adoption is prohibited. However, in April 2015, the FASB proposed delaying the effective date for one year. 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 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. | ||||||
From time to time, we enter into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production. We do not hold or issue derivative financial instruments for trading purposes. These contracts have historically consisted 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 employed a strategy to hedge a substantial portion of our forecasted production approximately 18 months to two years in the future (from the then-current quarter), as we believe it is important to protect our future cash flow to provide a level of assurance for our capital spending and dividends in those future periods. Due to the significant and rapid decline in oil prices over the last six months, we have deferred entering into new derivative contracts through the first quarter of 2015; thus, the percentage of our forecasted production we have hedged and the duration of our hedges are less than what we have had in the recent past. In April 2015, we began entering into new oil hedging positions in order to provide more certainty to our future cash flows. As of May 5, 2015, these fixed-price swaps and collars, which are not reflected in the table below and which comprise both NYMEX and LLS hedges, include (1) fixed-price swaps covering an additional 15,000 Bbls per day in the second quarter of 2016, with weighted-average prices of approximately $63 per Bbl and (2) collars covering an additional 4,500 Bbls per day and 5,000 Bbls per day in the second and third quarters of 2016, respectively, with weighted-average floors of approximately $56 per Bbl and weighted-average ceilings of approximately $72 per Bbl. | |||||||
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 March 31, 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. 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, including maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. | ||||||
• | Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. At March 31, 2015, instruments in this category include non-exchange-traded oil derivatives 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, since the instruments are based on regional pricing other than NYMEX, certain inputs to the valuation are less observable. 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 $0.9 million in the fair value of these instruments as of March 31, 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
Basis of Presentation (Tables) | 3 Months Ended | ||||||
Mar. 31, 2015 | |||||||
Accounting Policies [Abstract] | |||||||
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 | |||||||
March 31, | |||||||
In thousands | 2015 | 2014 | |||||
Basic weighted average common shares outstanding | 350,688 | 350,747 | |||||
Potentially dilutive securities | |||||||
Restricted stock, stock options, SARs and performance-based equity awards | — | 2,178 | |||||
Diluted weighted average common shares outstanding | 350,688 | 352,925 | |||||
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 | |||||||
March 31, | |||||||
In thousands | 2015 | 2014 | |||||
Stock options and SARs | 10,507 | 4,254 | |||||
Restricted stock and performance-based equity awards | 2,948 | 21 | |||||
LongTerm_Debt_Tables
Long-Term Debt (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Debt Disclosure [Abstract] | |||||||||
Components of Long-Term Debt | The following long-term debt and capital lease obligations were outstanding as of the dates indicated: | ||||||||
March 31, | December 31, | ||||||||
In thousands | 2015 | 2014 | |||||||
Bank Credit Agreement | $ | 465,000 | $ | 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 $10 and $11, respectively | 2,744 | 2,746 | |||||||
Pipeline financings | 218,486 | 220,583 | |||||||
Capital lease obligations | 96,534 | 103,041 | |||||||
Total | 3,632,764 | 3,571,370 | |||||||
Less: current obligations | (36,679 | ) | (35,470 | ) | |||||
Long-term debt and capital lease obligations | $ | 3,596,085 | $ | 3,535,900 | |||||
Commodity_Derivative_Contracts1
Commodity Derivative Contracts (Tables) | 3 Months Ended | ||||||||||||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||
Commodity derivative contracts not classified as hedging instruments | The following table summarizes our commodity derivative contracts as of March 31, 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) | |||||||||||||||||||||||||||
Apr – June | NYMEX | 8,000 | $ | 90 | – | 90 | $ | 90 | $ | 65.75 | $ | — | $ | — | |||||||||||||
Apr – June | LLS | 16,000 | 93.2 | – | 94 | 93.65 | 68 | — | — | ||||||||||||||||||
July – Sept | NYMEX | 10,000 | 90 | – | 90.1 | 90.02 | 65.3 | — | — | ||||||||||||||||||
July – Sept | LLS | 16,000 | 93.2 | – | 94 | 93.65 | 68 | — | — | ||||||||||||||||||
Oct – Dec | NYMEX | 12,000 | 91.15 | – | 94 | 92.42 | 68 | — | — | ||||||||||||||||||
Oct – Dec | LLS | 8,000 | 93.8 | – | 96.5 | 94.94 | 68 | — | — | ||||||||||||||||||
2015 Collars | |||||||||||||||||||||||||||
Apr – June | NYMEX | 30,000 | $ | 80 | – | 95.25 | $ | — | $ | — | $ | 80 | $ | 94.72 | |||||||||||||
Apr – June | LLS | 4,000 | 85 | – | 102.5 | — | — | 85 | 101.75 | ||||||||||||||||||
July – Sept | NYMEX | 28,000 | 80 | – | 95.25 | — | — | 80 | 95.05 | ||||||||||||||||||
July – Sept | LLS | 4,000 | 85 | – | 100 | — | — | 85 | 99.5 | ||||||||||||||||||
2015 Three-Way Collars (5) | |||||||||||||||||||||||||||
Oct – Dec | NYMEX | 10,000 | $ | 85 | – | 102 | $ | — | $ | 68 | $ | 85 | $ | 99 | |||||||||||||
Oct – Dec | LLS | 8,000 | 88 | – | 104.25 | — | 68 | 88 | 100.99 | ||||||||||||||||||
2016 Enhanced Swaps (4) | |||||||||||||||||||||||||||
Jan – Mar | NYMEX | 12,000 | $ | 90.65 | – | 93.35 | $ | 92.43 | $ | 68 | $ | — | $ | — | |||||||||||||
Jan – Mar | LLS | 8,000 | 93.7 | – | 95.45 | 94.81 | 68.5 | — | — | ||||||||||||||||||
Apr – June | NYMEX | 2,000 | 90.35 | – | 90.35 | 90.35 | 68 | — | — | ||||||||||||||||||
Apr – June | LLS | 6,000 | 93.3 | – | 93.5 | 93.38 | 70 | — | — | ||||||||||||||||||
2016 Three-Way Collars (5) | |||||||||||||||||||||||||||
Jan – Mar | NYMEX | 10,000 | $ | 85 | – | 101.25 | $ | — | $ | 68 | $ | 85 | $ | 99.85 | |||||||||||||
Jan – Mar | LLS | 6,000 | 88 | – | 103.15 | — | 68 | 88 | 102.1 | ||||||||||||||||||
Apr – June | NYMEX | 2,000 | 85 | – | 95.5 | — | 68 | 85 | 95.5 | ||||||||||||||||||
Apr – June | LLS | 2,000 | 88 | – | 98.25 | — | 70 | 88 | 98.25 | ||||||||||||||||||
Natural Gas Contracts: | |||||||||||||||||||||||||||
2015 Collars | |||||||||||||||||||||||||||
Apr – Dec | NYMEX | 8,000 | $ | 4 | – | 4.53 | $ | — | $ | — | $ | 4 | $ | 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 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 Measurements (Tables) | 3 Months Ended | ||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||||||
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 | Significant | Significant | Total | |||||||||||||
in Active | Other | Unobservable | |||||||||||||||
Markets | Observable | Inputs | |||||||||||||||
(Level 1) | Inputs | (Level 3) | |||||||||||||||
(Level 2) | |||||||||||||||||
March 31, 2015 | |||||||||||||||||
Assets: | |||||||||||||||||
Oil and natural gas derivative contracts – current | $ | — | $ | 270,126 | $ | 151,576 | $ | 421,702 | |||||||||
Oil and natural gas derivative contracts – long-term | — | 6,017 | 13,439 | 19,456 | |||||||||||||
Total Assets | $ | — | $ | 276,143 | $ | 165,015 | $ | 441,158 | |||||||||
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 months ended March 31, 2015 and 2014: | ||||||||||||||||
Three Months Ended | |||||||||||||||||
March 31, | |||||||||||||||||
In thousands | 2015 | 2014 | |||||||||||||||
Fair value of Level 3 instruments, beginning of period | $ | 188,446 | $ | 6,709 | |||||||||||||
Fair value adjustments on commodity derivatives | 25,085 | (12,806 | ) | ||||||||||||||
Receipt on settlements of commodity derivatives | (48,516 | ) | — | ||||||||||||||
Fair value of Level 3 instruments, end of period | $ | 165,015 | $ | (6,097 | ) | ||||||||||||
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets or liabilities still held at the reporting date | $ | 23,099 | $ | (12,806 | ) | ||||||||||||
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 | Valuation Technique | Unobservable Input | Range | ||||||||||||||
3/31/15 | |||||||||||||||||
(in thousands) | |||||||||||||||||
Oil derivative contracts | $ | 165,015 | Discounted cash flow / Black-Scholes | Volatility of Light Louisiana Sweet for settlement periods beginning after March 31, 2015 | 25.8% – 38.2% | ||||||||||||
Additional_Balance_Sheet_Detai1
Additional Balance Sheet Details (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Accounts Payable and Accrued Liabilities, Current [Abstract] | |||||||||
Schedule of Accounts Payable and Accrued Liabilities | Accounts Payable and Accrued Liabilities | ||||||||
March 31, | December 31, | ||||||||
In thousands | 2015 | 2014 | |||||||
Accounts payable | $ | 52,662 | $ | 64,604 | |||||
Accrued interest | 45,883 | 48,255 | |||||||
Accrued lease operating expenses | 38,197 | 56,798 | |||||||
Accrued exploration and development costs | 26,560 | 90,939 | |||||||
Accrued compensation | 24,517 | 62,513 | |||||||
Taxes payable | 16,697 | 39,816 | |||||||
Other | 30,025 | 31,833 | |||||||
Total | $ | 234,541 | $ | 394,758 | |||||
Basis_of_Presentation_Reconcil
Basis of Presentation (Reconciliation of Weighted Average Shares Table) (Details) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Weighted average shares used in the basic and diluted net income per common share | ||
Basic weighted average common shares outstanding | 350,688 | 350,747 |
Potentially dilutive securities: | ||
Restricted stock, stock options, SARs and performance-based equity awards | 0 | 2,178 |
Diluted weighted average common shares outstanding | 350,688 | 352,925 |
Basis_of_Presentation_Antidilu
Basis of Presentation Antidilutive Securities (Details) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 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 | 10,507 | 4,254 |
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 | 2,948 | 21 |
Basis_of_Presentation_Details_
Basis of Presentation (Details Textuals) (USD $) | 3 Months Ended | 12 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 | Mar. 31, 2015 |
Accounting Policies [Abstract] | |||
Write-down of oil and natural gas properties | $146,200 | $0 | |
Oil [Member] | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Oil and Natural Gas Prices | 79.55 | ||
Natural Gas [Member] | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Oil and Natural Gas Prices | 3.95 |
LongTerm_Debt_Components_of_Lo
Long-Term Debt (Components of Long-Term Debt) (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Debt Instrument [Line Items] | ||
Bank Credit Agreement | $465,000 | $395,000 |
Pipeline financings | 218,486 | 220,583 |
Capital lease obligations | 96,534 | 103,041 |
Total | 3,632,764 | 3,571,370 |
Less current obligations | -36,679 | -35,470 |
Long-term debt and capital lease obligations | 3,596,085 | 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 | 6.38% | |
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 | 4.63% | |
Other Subordinated Notes | ||
Debt Instrument [Line Items] | ||
Senior Subordinated Notes | 2,744 | 2,746 |
Including premium of | $10 | $11 |
LongTerm_Debt_Details_Textuals
Long-Term Debt (Details Textuals) (USD $) | 3 Months Ended | 0 Months Ended | |
In Billions, unless otherwise specified | Mar. 31, 2015 | 6-May-15 | Dec. 31, 2014 |
Long Term Debt (Textuals) [Abstract] | |||
Interest in guarantor subsidiaries | 100.00% | ||
$1.6 Billion Revolving Credit Facility [Abstract] | |||
Line of Credit, Borrowing Base | $3 | ||
Line of Credit Facility, Current Borrowing Capacity | 1.6 | ||
Weighted average interest rate on Bank Credit Facility | 1.50% | ||
Subsequent Event | |||
$1.6 Billion Revolving Credit Facility [Abstract] | |||
Line of Credit, Borrowing Base | 2.6 | ||
Line of Credit Facility, Current Borrowing Capacity | $1.60 | ||
Total Net Debt to EBITDAX Requirement | 4.25 | ||
Subsequent Event | Year 2016 | |||
$1.6 Billion Revolving Credit Facility [Abstract] | |||
Senior Secured Debt to EBITDAX | 2.5 | ||
EBITDAX to Consolidated Interest | 2.25 | ||
Subsequent Event | Year 2017 | |||
$1.6 Billion Revolving Credit Facility [Abstract] | |||
Senior Secured Debt to EBITDAX | 2.5 | ||
EBITDAX to Consolidated Interest | 2.25 | ||
Subsequent Event | Q1 | Year 2018 | |||
$1.6 Billion Revolving Credit Facility [Abstract] | |||
Total Net Debt to EBITDAX Requirement | 6 | ||
Subsequent Event | Q1 | Year 2019 | |||
$1.6 Billion Revolving Credit Facility [Abstract] | |||
Total Net Debt to EBITDAX Requirement | 4.25 | ||
Subsequent Event | Q2 | Year 2018 | |||
$1.6 Billion Revolving Credit Facility [Abstract] | |||
Total Net Debt to EBITDAX Requirement | 5.5 | ||
Subsequent Event | Q3 | Year 2018 | |||
$1.6 Billion Revolving Credit Facility [Abstract] | |||
Total Net Debt to EBITDAX Requirement | 5 | ||
Subsequent Event | Q4 | Year 2018 | |||
$1.6 Billion Revolving Credit Facility [Abstract] | |||
Total Net Debt to EBITDAX Requirement | 5 | ||
Minimum | |||
$1.6 Billion Revolving Credit Facility [Abstract] | |||
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.30% | ||
Maximum | |||
$1.6 Billion Revolving Credit Facility [Abstract] | |||
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.38% |
Stockholders_Equity_Details_Te
Stockholders' Equity (Details Textuals) (USD $) | 3 Months Ended | |
Share data in Millions, except Per Share data, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Stockholders' Equity Note [Abstract] | ||
Common stock cash dividend declared per share | $0.06 | $0.06 |
Cash dividend payment | $22,068,000 | $21,727,000 |
Treasury Stock, Shares, Acquired | 12.4 | |
Treasury Stock, Value, Acquired, Cost Method | $200,400,000 |
Commodity_Derivative_Contracts2
Commodity Derivative Contracts (Details) | Mar. 31, 2015 | 5-May-15 |
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q2 | NYMEX | ||
Derivative [Line Items] | ||
Volume per Day | 8,000 | |
Weighted average swap price | 90 | |
Weighted average sold put price | 65.75 | |
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q2 | NYMEX | Minimum | ||
Derivative [Line Items] | ||
Derivative, Swap Type, Fixed Price | 90 | |
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q2 | NYMEX | Maximum | ||
Derivative [Line Items] | ||
Derivative, Swap Type, Fixed Price | 90 | |
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q2 | LLS | ||
Derivative [Line Items] | ||
Volume per Day | 16,000 | |
Weighted average swap price | 93.65 | |
Weighted average sold put price | 68 | |
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q2 | LLS | Minimum | ||
Derivative [Line Items] | ||
Derivative, Swap Type, Fixed Price | 93.2 | |
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q2 | LLS | Maximum | ||
Derivative [Line Items] | ||
Derivative, Swap Type, Fixed Price | 94 | |
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q3 | NYMEX | ||
Derivative [Line Items] | ||
Volume per Day | 10,000 | |
Weighted average swap price | 90.02 | |
Weighted average sold put price | 65.3 | |
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q3 | NYMEX | Minimum | ||
Derivative [Line Items] | ||
Derivative, Swap Type, Fixed Price | 90 | |
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q3 | NYMEX | Maximum | ||
Derivative [Line Items] | ||
Derivative, Swap Type, Fixed Price | 90.1 | |
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q3 | LLS | ||
Derivative [Line Items] | ||
Volume per Day | 16,000 | |
Weighted average swap price | 93.65 | |
Weighted average sold put price | 68 | |
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q3 | LLS | Minimum | ||
Derivative [Line Items] | ||
Derivative, Swap Type, Fixed Price | 93.2 | |
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q3 | LLS | Maximum | ||
Derivative [Line Items] | ||
Derivative, Swap Type, Fixed Price | 94 | |
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 | |
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 | |
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 | |
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q4 | LLS | Minimum | ||
Derivative [Line Items] | ||
Derivative, Swap Type, Fixed Price | 93.8 | |
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q4 | LLS | Maximum | ||
Derivative [Line Items] | ||
Derivative, Swap Type, Fixed Price | 96.5 | |
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 | |
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 | 68.5 | |
Enhanced Swaps | Crude Oil Contracts | Year 2016 | Q1 | LLS | Minimum | ||
Derivative [Line Items] | ||
Derivative, Swap Type, Fixed Price | 93.7 | |
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 | ||
Derivative [Line Items] | ||
Volume per Day | 15,000 | |
Weighted average swap price | 63 | |
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 | |
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 | |
Enhanced Swaps | Crude Oil Contracts | Year 2016 | Q2 | LLS | Minimum | ||
Derivative [Line Items] | ||
Derivative, Swap Type, Fixed Price | 93.3 | |
Enhanced Swaps | Crude Oil Contracts | Year 2016 | Q2 | LLS | Maximum | ||
Derivative [Line Items] | ||
Derivative, Swap Type, Fixed Price | 93.5 | |
Collar | Crude Oil Contracts | Year 2015 | Q2 | NYMEX | ||
Derivative [Line Items] | ||
Volume per Day | 30,000 | |
Derivative, Floor Price | 80 | |
Derivative, Cap Price | 95.25 | |
Weighted average floor price | 80 | |
Weighted average ceiling price | 94.72 | |
Collar | Crude Oil Contracts | Year 2015 | Q2 | LLS | ||
Derivative [Line Items] | ||
Volume per Day | 4,000 | |
Derivative, Floor Price | 85 | |
Derivative, Cap Price | 102.5 | |
Weighted average floor price | 85 | |
Weighted average ceiling price | 101.75 | |
Collar | Crude Oil Contracts | Year 2015 | Q3 | NYMEX | ||
Derivative [Line Items] | ||
Volume per Day | 28,000 | |
Derivative, Floor Price | 80 | |
Derivative, Cap Price | 95.25 | |
Weighted average floor price | 80 | |
Weighted average ceiling price | 95.05 | |
Collar | Crude Oil Contracts | Year 2015 | Q3 | LLS | ||
Derivative [Line Items] | ||
Volume per Day | 4,000 | |
Derivative, Floor Price | 85 | |
Derivative, Cap Price | 100 | |
Weighted average floor price | 85 | |
Weighted average ceiling price | 99.5 | |
Collar | Crude Oil Contracts | Year 2016 | Q2 | ||
Derivative [Line Items] | ||
Volume per Day | 4,500 | |
Collar | Crude Oil Contracts | Year 2016 | Q3 | ||
Derivative [Line Items] | ||
Volume per Day | 5,000 | |
Collar | Natural Gas Contracts | Year 2015 | NYMEX | ||
Derivative [Line Items] | ||
Volume per Day | 8,000 | |
Derivative, Floor Price | 4 | |
Derivative, Cap Price | 4.53 | |
Weighted average floor price | 4 | |
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 | |
Derivative, Cap Price | 102 | |
Weighted average sold put price | 68 | |
Weighted average floor price | 85 | |
Weighted average ceiling price | 99 | |
Three-way Collar | Crude Oil Contracts | Year 2015 | Q4 | LLS | ||
Derivative [Line Items] | ||
Volume per Day | 8,000 | |
Derivative, Floor Price | 88 | |
Derivative, Cap Price | 104.25 | |
Weighted average sold put price | 68 | |
Weighted average floor price | 88 | |
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 | |
Derivative, Cap Price | 101.25 | |
Weighted average sold put price | 68 | |
Weighted average floor price | 85 | |
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 | |
Derivative, Cap Price | 103.15 | |
Weighted average sold put price | 68 | |
Weighted average floor price | 88 | |
Weighted average ceiling price | 102.1 | |
Three-way Collar | Crude Oil Contracts | Year 2016 | Q2 | NYMEX | ||
Derivative [Line Items] | ||
Volume per Day | 2,000 | |
Derivative, Floor Price | 85 | |
Derivative, Cap Price | 95.5 | |
Weighted average sold put price | 68 | |
Weighted average floor price | 85 | |
Weighted average ceiling price | 95.5 | |
Three-way Collar | Crude Oil Contracts | Year 2016 | Q2 | LLS | ||
Derivative [Line Items] | ||
Volume per Day | 2,000 | |
Derivative, Floor Price | 88 | |
Derivative, Cap Price | 98.25 | |
Weighted average sold put price | 70 | |
Weighted average floor price | 88 | |
Weighted average ceiling price | 98.25 |
Commodity_Derivative_Contracts3
Commodity Derivative Contracts (Details Textuals) | 3 Months Ended | |
Mar. 31, 2015 | 5-May-15 | |
Crude Oil Contracts | Swap | Year 2016 | Q2 | ||
Subsequent Event [Line Items] | ||
Volume per Day | 15,000 | |
Weighted average swap price | 63 | |
Crude Oil Contracts | Collar | Year 2016 | Q3 | ||
Subsequent Event [Line Items] | ||
Volume per Day | 5,000 | |
Crude Oil Contracts | Collar | Year 2016 | Q2 | ||
Subsequent Event [Line Items] | ||
Volume per Day | 4,500 | |
Crude Oil Contracts | Collar | Year 2016 | Q2 and Q3 | ||
Subsequent Event [Line Items] | ||
Weighted average floor price | 56 | |
Weighted average ceiling price | 72 | |
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_V
Fair Value Measurements (Fair Value Hierarchy Table) (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative Asset, Current | $421,702 | $440,359 |
Derivative Asset, Long-term | 19,456 | 66,187 |
Total Derivative Assets | 441,158 | 506,546 |
Quoted Prices in Active Markets (Level 1) | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative Asset, Current | 0 | 0 |
Derivative Asset, Long-term | 0 | 0 |
Total Derivative Assets | 0 | 0 |
Significant Other Observable Inputs (Level 2) | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative Asset, Current | 270,126 | 283,238 |
Derivative Asset, Long-term | 6,017 | 34,862 |
Total Derivative Assets | 276,143 | 318,100 |
Significant Unobservable Inputs (Level 3) | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative Asset, Current | 151,576 | 157,121 |
Derivative Asset, Long-term | 13,439 | 31,325 |
Total Derivative Assets | $165,015 | $188,446 |
Fair_Value_Measurements_Level_
Fair Value Measurements (Level 3 Fair Value Measurements) (Details) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 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 | $188,446 | $6,709 |
Fair value adjustments on commodity derivatives | 25,085 | -12,806 |
Receipt on settlements of commodity derivatives | -48,516 | 0 |
Fair value of Level 3 instruments, end of period | 165,015 | -6,097 |
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets or liabilities still held at the reporting date | $23,099 | ($12,806) |
Fair_Value_Measurements_Level_1
Fair Value Measurements (Level 3 Valuation Techniques) (Details) (USD $) | 3 Months Ended | |||
In Thousands, unless otherwise specified | Mar. 31, 2015 | Dec. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 |
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items] | ||||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs | 165,015 | $188,446 | ($6,097) | $6,709 |
Income Approach Valuation Technique | Minimum | ||||
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items] | ||||
Expected Volatility Rate | 25.80% | |||
Income Approach Valuation Technique | Maximum | ||||
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items] | ||||
Expected Volatility Rate | 38.20% |
Fair_Value_Measurements_Detail
Fair Value Measurements (Details Textuals) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Millions, unless otherwise specified | ||
Fair Value Disclosures [Abstract] | ||
Sensitivity Analysis of Fair Value, Impact of 100 Basis Point Increase or Decrease in Level 3 Inputs | $0.90 | |
Debt, Fair Value | $2,998.60 | $2,938.60 |
Commitments_and_Contingencies_
Commitments and Contingencies (Details) (USD $) | 1 Months Ended | 22 Months Ended | 3 Months Ended |
Oct. 31, 2014 | Mar. 31, 2015 | Mar. 31, 2015 | |
Loss Contingencies [Line Items] | |||
Environmental remediation expense | $130,800,000 | ||
Gross proceeds from insurance settlement, operating activities | 25,000,000 | ||
Minimum | |||
Loss Contingencies [Line Items] | |||
Estimated percentage of environmental remediation expense estimate to be recovered through insurance proceeds | 33.33% | 33.33% | |
Loss Contingency, Damages Sought, Value | $200,000,000 | ||
Maximum | |||
Loss Contingencies [Line Items] | |||
Estimated percentage of environmental remediation expense estimate to be recovered through insurance proceeds | 66.67% | 66.67% |
Additional_Balance_Sheet_Detai2
Additional Balance Sheet Details (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Accounts Payable and Accrued Liabilities, Current [Abstract] | ||
Accounts payable | $52,662 | $64,604 |
Accrued interest | 45,883 | 48,255 |
Accrued lease operating expenses | 38,197 | 56,798 |
Accrued exploration and development costs | 26,560 | 90,939 |
Accrued compensation | 24,517 | 62,513 |
Taxes payable | 16,697 | 39,816 |
Other | 30,025 | 31,833 |
Total | $234,541 | $394,758 |
Subsequent_Event_Details_Textu
Subsequent Event (Details Textuals) (Subsequent Event, USD $) | Apr. 28, 2015 |
Subsequent Event | |
Subsequent Event [Line Items] | |
Common Stock, Dividends, Per Share, Declared | $0.06 |