Document_And_Entity_Informatio
Document And Entity Information (USD $) | 12 Months Ended | ||
In Billions, except Share data, unless otherwise specified | Dec. 31, 2014 | Jan. 31, 2015 | Jun. 30, 2014 |
Document and Entity Information [Abstract] | |||
Document Type | 10-K | ||
Document Period End Date | 31-Dec-14 | ||
Amendment Flag | FALSE | ||
Entity Registrant Name | Linn Energy, LLC | ||
Entity Central Index Key | 1326428 | ||
Current Fiscal Year End Date | -19 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Public Float | $6.50 | ||
Entity Common Stock, Shares Outstanding | 335,562,043 | ||
Document Fiscal Year Focus | 2014 | ||
Document Fiscal Period Focus | FY |
CONSOLIDATED_BALANCE_SHEETS
CONSOLIDATED BALANCE SHEETS (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Current assets: | ||
Cash and cash equivalents | $1,809 | $52,171 |
Accounts receivable – trade, net | 471,684 | 488,202 |
Derivative instruments | 1,077,142 | 176,130 |
Other current assets | 155,955 | 99,437 |
Total current assets | 1,706,590 | 815,940 |
Noncurrent assets: | ||
Oil and natural gas properties (successful efforts method) | 18,068,900 | 17,888,559 |
Less accumulated depletion and amortization | -4,867,682 | -3,546,284 |
Oil and natural gas properties, successful efforts method, net | 13,201,218 | 14,342,275 |
Other property and equipment | 669,149 | 647,882 |
Less accumulated depreciation | -144,282 | -110,939 |
Other property and equipment, net | 524,867 | 536,943 |
Derivative instruments | 848,097 | 682,002 |
Other noncurrent assets | 142,737 | 127,804 |
Noncurrent assets, excluding property, total | 990,834 | 809,806 |
Total noncurrent assets | 14,716,919 | 15,689,024 |
Total assets | 16,423,509 | 16,504,964 |
Current liabilities: | ||
Accounts payable and accrued expenses | 814,809 | 849,624 |
Derivative instruments | 0 | 28,176 |
Other accrued liabilities | 167,736 | 163,375 |
Current portion of long-term debt | 0 | 211,558 |
Total current liabilities | 982,545 | 1,252,733 |
Noncurrent liabilities: | ||
Credit facilities | 2,968,175 | 2,733,175 |
Term loan | 500,000 | 500,000 |
Senior notes, net | 6,827,634 | 5,725,483 |
Derivative instruments | 684 | 4,649 |
Other noncurrent liabilities | 600,866 | 397,497 |
Total noncurrent liabilities | 10,897,359 | 9,360,804 |
Commitments and contingencies (Note 11) | ||
Unitholders’ capital: | ||
331,974,913 units and 329,661,161 units issued and outstanding at December 31, 2014, and December 31, 2013, respectively | 5,395,811 | 6,291,824 |
Accumulated deficit | -852,206 | -400,397 |
Total unitholders' capital | 4,543,605 | 5,891,427 |
Total liabilities and unitholders’ capital | $16,423,509 | $16,504,964 |
CONSOLIDATED_BALANCE_SHEETS_Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) | Dec. 31, 2014 | Dec. 31, 2013 |
Statement of Financial Position [Abstract] | ||
Unitholder's capital: Units issued | 331,974,913 | 329,661,161 |
Unitholders' capital: Units outstanding | 331,974,913 | 329,661,161 |
CONSOLIDATED_STATEMENTS_OF_OPE
CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) | 12 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Revenues and other: | |||
Oil, natural gas and natural gas liquids sales | $3,610,539 | $2,073,240 | $1,601,180 |
Gains on oil and natural gas derivatives | 1,206,179 | 177,857 | 124,762 |
Marketing revenues | 135,260 | 54,171 | 37,393 |
Other revenues | 31,325 | 26,387 | 10,905 |
Total revenues | 4,983,303 | 2,331,655 | 1,774,240 |
Expenses: | |||
Lease operating expenses | 805,164 | 372,523 | 317,699 |
Transportation expenses | 207,331 | 128,440 | 77,322 |
Marketing expenses | 117,465 | 37,892 | 31,821 |
General and administrative expenses | 293,073 | 236,271 | 173,206 |
Exploration costs | 125,037 | 5,251 | 1,915 |
Depreciation, depletion and amortization | 1,073,902 | 829,311 | 606,150 |
Impairment of long-lived assets | 2,303,749 | 828,317 | 422,499 |
Taxes, other than income taxes | 267,403 | 138,631 | 131,679 |
(Gains) losses on sale of assets and other, net | -366,500 | 13,637 | 1,539 |
Total expenses | 4,826,624 | 2,590,273 | 1,763,830 |
Other income and (expenses): | |||
Interest expense, net of amounts capitalized | -587,838 | -421,137 | -379,937 |
Loss on extinguishment of debt | 0 | -5,304 | 0 |
Other, net | -16,213 | -8,477 | -14,299 |
Total other income and (expenses) | -604,051 | -434,918 | -394,236 |
Loss before income taxes | -447,372 | -693,536 | -383,826 |
Income tax expense (benefit) | 4,437 | -2,199 | 2,790 |
Net loss | ($451,809) | ($691,337) | ($386,616) |
Net loss per unit: | |||
Basic (in usd per unit) | ($1.40) | ($2.94) | ($1.92) |
Diluted (in usd per unit) | ($1.40) | ($2.94) | ($1.92) |
Weighted average units outstanding: | |||
Basic (in units) | 328,918 | 237,544 | 203,775 |
Diluted (in units) | 328,918 | 237,544 | 203,775 |
Distributions declared per unit (in usd per unit) | $2.90 | $2.90 | $2.87 |
CONSOLIDATED_STATEMENT_OF_UNIT
CONSOLIDATED STATEMENT OF UNITHOLDERS' CAPITAL (USD $) | 3 Months Ended | 12 Months Ended | |||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Sale of units, net of underwriting discounts and expenses of $32,044 | $1,942,045 | ||||||
Balance Beginning | 5,891,427 | 4,427,180 | 5,891,427 | 4,427,180 | 3,428,910 | ||
Issuance of units | 13,354 | 2,783,907 | 7,061 | ||||
Distributions to unitholders | -962,048 | -682,241 | -596,935 | ||||
Unit-based compensation expenses | 53,284 | 42,703 | 29,533 | ||||
Reclassification of distributions paid on forfeited restricted units | 602 | 176 | 92 | ||||
Excess tax benefit from unit-based compensation and other | 347 | 160 | 3,090 | ||||
Deferred tax on capital contribution | -1,552 | 10,879 | |||||
Net loss | -154,502 | -85,337 | -784,549 | -221,885 | -451,809 | -691,337 | -386,616 |
Balance Ending | 4,543,605 | 5,891,427 | 4,543,605 | 5,891,427 | 4,427,180 | ||
Accumulated Income [Member] | |||||||
Sale of units, net of underwriting discounts and expenses of $32,044 | 0 | ||||||
Balance Beginning | -400,397 | 290,940 | -400,397 | 290,940 | 677,556 | ||
Issuance of units | 0 | 0 | 0 | ||||
Distributions to unitholders | 0 | 0 | 0 | ||||
Unit-based compensation expenses | 0 | 0 | 0 | ||||
Reclassification of distributions paid on forfeited restricted units | 0 | 0 | 0 | ||||
Excess tax benefit from unit-based compensation and other | 0 | 0 | 0 | ||||
Deferred tax on capital contribution | 0 | 0 | |||||
Net loss | -451,809 | -691,337 | -386,616 | ||||
Balance Ending | -852,206 | -400,397 | -852,206 | -400,397 | 290,940 | ||
Member Units [Member] | |||||||
Sale of units, net of underwriting discounts and expenses (in units) | 55,877 | ||||||
Common Units, Outstanding (in units) | 329,661 | 234,513 | 329,661 | 234,513 | 177,365 | ||
Issuance of units (in units) | 2,314 | 95,148 | 1,271 | ||||
Common Units, Outstanding (in units) | 331,975 | 329,661 | 331,975 | 329,661 | 234,513 | ||
Common Stock Including Additional Paid in Capital [Member] | |||||||
Sale of units, net of underwriting discounts and expenses of $32,044 | 1,942,045 | ||||||
Balance Beginning | 6,291,824 | 4,136,240 | 6,291,824 | 4,136,240 | 2,751,354 | ||
Issuance of units | 13,354 | 2,783,907 | 7,061 | ||||
Distributions to unitholders | -962,048 | -682,241 | -596,935 | ||||
Unit-based compensation expenses | 53,284 | 42,703 | 29,533 | ||||
Reclassification of distributions paid on forfeited restricted units | 602 | 176 | 92 | ||||
Excess tax benefit from unit-based compensation and other | 347 | 160 | 3,090 | ||||
Deferred tax on capital contribution | -1,552 | 10,879 | |||||
Net loss | 0 | 0 | 0 | ||||
Balance Ending | $5,395,811 | $6,291,824 | $5,395,811 | $6,291,824 | $4,136,240 |
CONSOLIDATED_STATEMENT_OF_UNIT1
CONSOLIDATED STATEMENT OF UNITHOLDERS' CAPITAL (Parenthetical) (USD $) | 12 Months Ended |
In Thousands, unless otherwise specified | Dec. 31, 2012 |
Statement of Stockholders' Equity [Abstract] | |
Underwriting discounts and expenses | $32,044 |
CONSOLIDATED_STATEMENTS_OF_CAS
CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Cash flow from operating activities: | |||
Net loss | ($451,809) | ($691,337) | ($386,616) |
Adjustments to reconcile net loss to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 1,073,902 | 829,311 | 606,150 |
Impairment of long-lived assets | 2,303,749 | 828,317 | 422,499 |
Unit-based compensation expenses | 53,284 | 42,703 | 29,533 |
Loss on extinguishment of debt | 0 | 5,304 | 0 |
Amortization and write-off of deferred financing fees | 50,926 | 21,507 | 25,598 |
(Gains) losses on sale of assets and other, net | -261,571 | 37,232 | 92 |
Deferred income taxes | 3,943 | -2,541 | -360 |
Derivatives activities: | |||
Total gains | -1,206,179 | -177,857 | -124,762 |
Cash settlements | 95,514 | 248,862 | 390,765 |
Cash settlements on canceled derivatives | 12,281 | 0 | 0 |
Premiums paid for derivatives | 0 | 0 | -583,434 |
Changes in assets and liabilities: | |||
(Increase) decrease in accounts receivable – trade, net | 5,064 | 89,188 | -77,573 |
(Increase) decrease in other assets | -17,824 | 16,179 | -5,451 |
Increase (decrease) in accounts payable and accrued expenses | 99,029 | -76,993 | 26,372 |
Increase (decrease) in other liabilities | -48,419 | -3,663 | 28,094 |
Net cash provided by operating activities | 1,711,890 | 1,166,212 | 350,907 |
Cash flow from investing activities: | |||
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired | -2,479,252 | -279,213 | -2,640,475 |
Development of oil and natural gas properties | -1,569,877 | -1,078,025 | -984,530 |
Purchases of other property and equipment | -74,540 | -92,352 | -60,549 |
Proceeds from sale of properties and equipment and other | 2,203,565 | 196,273 | 725 |
Net cash used in investing activities | -1,920,104 | -1,253,317 | -3,684,829 |
Cash flow from financing activities: | |||
Proceeds from sale of units | 0 | 0 | 1,973,989 |
Proceeds from borrowings | 5,940,024 | 2,230,000 | 5,439,802 |
Repayments of debt | -4,811,124 | -1,404,898 | -3,400,000 |
Distributions to unitholders | -962,048 | -682,241 | -596,935 |
Financing fees and offering expenses | 69,694 | 16,033 | 73,320 |
Excess tax benefit from unit-based compensation | 766 | 160 | 3,090 |
Other | 59,928 | 11,045 | -12,575 |
Net cash provided by financing activities | 157,852 | 138,033 | 3,334,051 |
Net increase (decrease) in cash and cash equivalents | -50,362 | 50,928 | 129 |
Cash and cash equivalents: | |||
Beginning | 52,171 | 1,243 | 1,114 |
Ending | $1,809 | $52,171 | $1,243 |
Basis_of_Presentation_and_Sign
Basis of Presentation and Significant Accounting Policies | 12 Months Ended | |
Dec. 31, 2014 | ||
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Basis of Presentation and Significant Accounting Policies | Basis of Presentation and Significant Accounting Policies | |
Nature of Business | ||
Linn Energy, LLC (“LINN Energy” or the “Company”) is an independent oil and natural gas company that began operations in March 2003 and was formed as a Delaware limited liability company in April 2005. The Company completed its initial public offering (“IPO”) in January 2006 and its units representing limited liability company interests (“units”) are listed on the NASDAQ Global Select Market under the symbol “LINE.” LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets. | ||
The Company’s properties are located in eight operating regions in the United States (“U.S.”): Rockies, which includes properties located in Wyoming (Green River, Washakie and Powder River basins), Utah (Uinta Basin), North Dakota (Williston Basin) and Colorado (Piceance Basin); Hugoton Basin, which includes properties located in Kansas, the Oklahoma Panhandle and the Shallow Texas Panhandle; California, which includes properties located in the San Joaquin Valley and Los Angeles basins; TexLa, which includes properties located in east Texas and north Louisiana; Mid-Continent, which includes properties located in the Anadarko and Arkoma basins in Oklahoma, as well as waterfloods in the Central Oklahoma Platform; Permian Basin, which includes properties located in west Texas and southeast New Mexico; Michigan/Illinois, which includes properties located in the Antrim Shale formation in north Michigan and oil properties in south Illinois; and South Texas. | ||
The operations of the Company are governed by the provisions of a limited liability company agreement executed by and among its members. The agreement includes specific provisions with respect to the maintenance of the capital accounts of each of the Company’s unitholders. Pursuant to applicable provisions of the Delaware Limited Liability Company Act (the “Delaware Act”) and the Third Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC, as amended (the “LLC Agreement”), unitholders have no liability for the debts, obligations and liabilities of the Company, except as expressly required in the LLC Agreement or the Delaware Act. The Company will remain in existence unless and until dissolved in accordance with the terms of the LLC Agreement. | ||
Principles of Consolidation and Reporting | ||
The Company presents its financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”). The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method. | ||
The consolidated financial statements for previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income (loss), unitholders’ capital or cash flows. | ||
Use of Estimates | ||
The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, fair values of commodity derivatives and fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods. | ||
Recently Issued Accounting Standards | ||
In May 2014, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that is intended to improve and converge the financial reporting requirements for revenue from contracts with customers. This ASU will be applied either retrospectively or as a cumulative-effect adjustment as of the date of adoption and is effective for fiscal years beginning after December 15, 2016, and interim periods within those years (early adoption prohibited). The Company is currently evaluating the impact, if any, of the adoption of this ASU on its consolidated financial statements and related disclosures. | ||
In April 2014, the FASB issued an ASU that changes the criteria for reporting discontinued operations and enhances disclosures in this area. This ASU is effective for annual and interim periods beginning after December 15, 2014, with early adoption permitted for disposals or for assets classified as held for sale that have not been reported in previously issued financial statements. The Company early adopted this ASU on a prospective basis beginning with the third quarter of 2014. The adoption had no effect on the Company’s consolidated financial statements. | ||
Cash Equivalents | ||
For purposes of the consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Outstanding checks in excess of funds on deposit are included in “accounts payable and accrued expenses” on the consolidated balance sheets and are classified as financing activities on the consolidated statements of cash flows. | ||
Accounts Receivable – Trade, Net | ||
Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging, and existing industry and national economic data. The Company reviews its allowance for doubtful accounts monthly. Past due balances over 90 days and over a specified amount are reviewed individually for collectibility. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential recovery is remote. The balance in the Company’s allowance for doubtful accounts related to trade accounts receivable was approximately $1 million at both December 31, 2014, and December 31, 2013. | ||
Inventories | ||
Materials, supplies and commodity inventories are valued at the lower of average cost or market. | ||
Oil and Natural Gas Properties | ||
Proved Properties | ||
The Company accounts for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively. | ||
The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows of proved and risk-adjusted probable and possible reserves are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use. The Company capitalized interest costs of approximately $9 million for the year ended December 31, 2014, and $2 million for each of the years ended December 31, 2013, and December 31, 2012. | ||
Impairment of Proved Properties | ||
Based on the analysis described above, for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, the Company recorded noncash impairment charges, before and after tax, of approximately $2.3 billion, $791 million and $422 million, respectively, associated with proved oil and natural gas properties. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the consolidated statements of operations. | ||
During the fourth quarter of 2014, the Company recorded noncash impairment charges, before and after tax, of approximately $1.7 billion associated with proved oil and natural gas properties throughout its various operating regions. The impairment was due to a steep decline in commodity prices. From September 30, 2014 to December 31, 2014, NYMEX oil and natural gas forward price curves decreased approximately 24% and 12%, respectively. Following are the impairment charges recorded by operating region: | ||
• | Permian Basin – $735 million; | |
• | Rockies – $586 million (in the Powder River Basin and Uinta Basin); | |
• | Mid-Continent – $244 million; | |
• | South Texas – $131 million; and | |
• | TexLa – $5 million. | |
In addition, during the third quarter of 2014, the Company recorded noncash impairment charges, before and after tax, of approximately $603 million associated with proved oil and natural gas properties in the Permian Basin region. The impairment was due to the divestiture of certain high valued unproved properties in the Midland Basin in which the expected cash flows were previously included in the impairment assessment for the proved oil and natural gas properties. | ||
During the year ended December 31, 2013, the Company recorded a noncash impairment charge, before and after tax, of approximately $791 million associated with proved oil and natural gas properties in the Granite Wash formation related to asset performance resulting in reserve revisions and a decline in commodity prices. During the year ended December 31, 2012, the Company recorded noncash impairment charges, before and after tax, of approximately $422 million associated with proved oil and natural gas properties in the Mississippi Shelf and Mayfield related to the SEC five-year development limitation on PUDs and a decline in commodity prices. | ||
Subsequent to December 31, 2014, the prices of oil, natural gas and NGL have continued to be volatile. In the future, if forward price curves continue to decline, the Company may have additional impairments which could have a material impact on its results of operations. | ||
Unproved Properties | ||
Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company assesses unproved properties for impairment quarterly on the basis of its experience in similar situations and other factors such as the primary lease terms of the properties, the average holding period of unproved properties and the relative proportion of such properties on which proved reserves have been found in the past. | ||
Exploration Costs | ||
Geological and geophysical costs, delay rentals, amortization and impairment of unproved leasehold costs and costs to drill exploratory wells that do not find proved reserves are expensed as exploration costs. The costs of any exploratory wells are carried as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as the Company is making sufficient progress towards assessing the reserves and the economic and operating viability of the project. The Company recorded noncash leasehold impairment expenses related to unproved properties of approximately $125 million, $5 million and $2 million for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively, which are included in “exploration costs” on the consolidated statements of operations. | ||
Other Property and Equipment | ||
Other property and equipment includes natural gas gathering systems, pipelines, buildings, software, data processing and telecommunications equipment, office furniture and equipment, and other fixed assets. These assets are recorded at cost and are depreciated using the straight-line method based on expected lives ranging from two to 39 years for the individual asset or group of assets. | ||
Revenue Recognition | ||
Revenues representative of the Company’s ownership interest in its properties are presented on a gross basis on the consolidated statements of operations. Sales of oil, natural gas and NGL are recognized when the product has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. | ||
The Company has elected the entitlements method to account for natural gas production imbalances. Imbalances occur when the Company sells more or less than its entitled ownership percentage of total natural gas production. In accordance with the entitlements method, any amount received in excess of the Company’s share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. Imbalance receivables and payables are valued at the lower of the price in effect at the time of production, the current market value or, if a contract is in hand, the contract price. At December 31, 2014, and December 31, 2013, the Company had natural gas production imbalance receivables of approximately $17 million and $27 million, respectively, which are included in “accounts receivable – trade, net” on the consolidated balance sheets and natural gas production imbalance payables of approximately $13 million and $16 million, respectively, which are included in “accounts payable and accrued expenses” on the consolidated balance sheets. | ||
The Company engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements. As such, the Company separately reports third-party marketing revenues and marketing expenses. | ||
The Company generates electricity with excess natural gas, which it uses to serve certain of its operating facilities in California. Any excess electricity is sold to the California wholesale power market. The revenue from this activity is included in “other revenues” on the consolidated statements of operations. | ||
Restricted Cash | ||
Restricted cash of approximately $6 million is included in “other noncurrent assets” on the consolidated balance sheets at both December 31, 2014, and December 31, 2013, and primarily represents cash the Company has deposited into a separate account and designated for asset retirement obligations in accordance with contractual agreements. | ||
Derivative Instruments | ||
The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of oil and natural gas. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in net cash provided by operating activities due to fluctuations in commodity prices. | ||
The Company enters into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price and, from time to time, put options that are designed to provide a fixed price floor with the opportunity for upside. A swap contract specifies a fixed price that the Company will receive from the counterparty as compared to floating market prices, and on the settlement date the Company will receive or pay the difference between the swap price and the market price. A put option requires the Company to pay the counterparty a premium equal to the fair value of the option at the purchase date and receive from the counterparty the excess, if any, of the fixed price floor over the market price at the settlement date. Also, the Company may from time to time enter into derivative contracts in the form of interest rate swaps to minimize the effects of fluctuations in interest rates. At December 31, 2014, the Company had no outstanding derivative contracts in the form of interest rate swaps. | ||
In addition, as part of the 2013 acquisition of Berry Petroleum Company, now Berry Petroleum Company, LLC (“Berry”) (see Note 2), the Company assumed certain derivative contracts that Berry had entered into prior to the acquisition date, including swap contracts, collars and three-way collars. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. Three-way collar contracts combine a short put (the lower price), a long put (the middle price) and a short call (the higher price) to provide a higher ceiling price as compared to a regular collar and limit downside risk to the market price plus the difference between the middle price and the lower price if the market price drops below the lower price. | ||
Derivative instruments (including certain derivative instruments embedded in other contracts that require bifurcation) are recorded at fair value and included on the consolidated balance sheets as assets or liabilities. The Company did not designate these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. The Company uses certain pricing models to determine the fair value of its derivative financial instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. See Note 7 and Note 8 for additional details about the Company’s derivative financial instruments. | ||
Unit-Based Compensation | ||
The Company recognizes expense for unit-based compensation over the requisite service period in an amount equal to the fair value of unit-based awards granted to employees and nonemployee directors. The fair value of unit-based awards, excluding liability awards, is computed at the date of grant and is not remeasured. The fair value of liability awards is remeasured at each reporting date through the settlement date with the change in fair value recognized as compensation expense over that period. The Company currently does not have any awards accounted for as liability awards. | ||
The Company has made a policy decision to recognize compensation expense for service-based awards on a straight-line basis over the requisite service period for the entire award. See Note 5 for additional details about the Company’s accounting for unit-based compensation. | ||
The benefit of tax deductions in excess of recognized compensation costs is required to be reported as financing cash flow rather than operating cash flow. This requirement reduces net operating cash flow and increases net financing cash flow in periods in which such tax benefit exists. The amount of the Company’s excess tax benefit is also reported in “excess tax benefit from unit-based compensation and other” on the consolidated statements of unitholders’ capital. | ||
Deferred Financing Fees | ||
The Company incurred legal and bank fees related to the issuance of debt. At December 31, 2014, and December 31, 2013, net deferred financing fees of approximately $129 million and $114 million, respectively, are included in “other noncurrent assets” on the consolidated balance sheets. These debt issuance costs are amortized over the life of the debt agreement. Upon early retirement or amendment to the debt agreement, certain fees are written off to expense. For the years ended December 31, 2014, December 31, 2013, and December 31, 2012, amortization expense of approximately $46 million, $18 million and $13 million, respectively, is included in “interest expense, net of amounts capitalized” on the consolidated statements of operations. For the year ended December 31, 2014, approximately $8 million were written off to expense and included in “other, net” on the consolidated statement of operations related to the VIE Term Loan (as defined in Note 6) and amendments to the Credit Facilities (as defined in Note 6). For the year ended December 31, 2012, approximately $8 million were written off to expense and included in “other, net” on the consolidated statement of operations related to amendments of the LINN Credit Facility (as defined in Note 6). No fees related to amendments of the Credit Facilities were written off to expense during the year ended December 31, 2013. | ||
Fair Value of Financial Instruments | ||
The carrying values of the Company’s receivables, payables and Credit Facilities are estimated to be substantially the same as their fair values at December 31, 2014, and December 31, 2013. See Note 6 for fair value disclosures related to the Company’s other outstanding debt. As noted above, the Company carries its derivative financial instruments at fair value. See Note 8 for details about the fair value of the Company’s derivative financial instruments. | ||
Income Taxes | ||
The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its unitholders. As such, with the exception of the state of Texas, the Company is not a taxable entity, it does not directly pay federal and state income tax and recognition has not been given to federal and state income taxes for the operations of the Company except as described below. | ||
Limited liability companies are subject to Texas margin tax. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes, which are accounted for using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and tax carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. See Note 14 for detail of amounts recorded in the consolidated financial statements. |
Exchanges_of_Properties_Acquis
Exchanges of Properties, Acquisitions, Divestitures and Joint-Venture Funding | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Business Combinations [Abstract] | |||||||||
Exchanges of Properties, Acquisitions, Divestitures and Joint-Venture Funding | Exchanges of Properties, Acquisitions, Divestitures and Joint-Venture Funding | ||||||||
Exchanges of Properties – 2014 | |||||||||
On November 21, 2014, the Company, through two of its wholly owned subsidiaries, completed the trade of a portion of its Permian Basin properties to Exxon Mobil Corporation in exchange for properties in California’s South Belridge Field. The noncash exchange was accounted for at fair value and the Company recognized a net gain of approximately $20 million, including costs to sell of approximately $3 million. The gain is equal to the difference between the carrying value and the fair value of the assets exchanged less costs to sell, and is included in “(gains) losses on sale of assets and other, net” on the consolidated statement of operations. The fair value measurements were based on inputs that are not observable and therefore represent Level 3 inputs under the fair value hierarchy. | |||||||||
On August 15, 2014, the Company, through two of its wholly owned subsidiaries, completed the trade of a portion of its Permian Basin properties to Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc., in exchange for properties in the Hugoton Basin. The noncash exchange was accounted for at fair value and the Company recognized a net gain of approximately $65 million, including costs to sell of approximately $3 million. The gain is equal to the difference between the carrying value and the fair value of the assets exchanged less costs to sell, and is included in “(gains) losses on sale of assets and other, net” on the consolidated statement of operations. The fair value measurements were based on inputs that are not observable in the market and therefore represent Level 3 inputs under the fair value hierarchy. | |||||||||
Acquisitions – 2014 | |||||||||
On September 11, 2014, the Company completed the acquisition of certain oil and natural gas properties located in the Hugoton Basin from Pioneer Natural Resources Company (“Pioneer” and the acquisition, the “Pioneer Assets Acquisition”) for total consideration of approximately $328 million. | |||||||||
On August 29, 2014, the Company completed the acquisition of certain oil and natural gas properties located in five operating regions in the U.S. from subsidiaries of Devon Energy Corporation (“Devon” and the acquisition, the “Devon Assets Acquisition”) for total consideration of approximately $2.1 billion. | |||||||||
The Pioneer Assets Acquisition was initially financed with borrowings under the LINN Credit Facility, and the Devon Assets Acquisition was initially financed with proceeds from the Bridge Loan and borrowings under the VIE Term Loan (see Note 6). The Company used the net proceeds from the sales of its Granite Wash properties as well as certain of its Wolfberry properties (see below) to repay the VIE Term Loan in full as well as repay a portion of the borrowings outstanding under the LINN Credit Facility. | |||||||||
The Pioneer Assets Acquisition and the Devon Assets Acquisition were structured as reverse like-kind exchanges pursuant to Section 1031 of the Internal Revenue Code, as amended (“Reverse 1031 Exchanges”). In connection with the Reverse 1031 Exchanges, the Company, through a subsidiary, assigned the rights to acquire legal title to the oil and natural gas properties from Pioneer and Devon to a variable interest entity (“VIE”) formed by an exchange accommodation titleholder. A subsidiary of LINN Energy operated the properties pursuant to management agreements with the VIE. Because the Company was the primary beneficiary of the VIE, the VIE was included in the consolidated financial statements from the time of its formation. | |||||||||
The assets acquired by the VIE in the Pioneer Assets Acquisition and the Devon Assets Acquisition were conveyed to LINN Energy and its subsidiaries, and the VIE structure was terminated, upon the completion of the Reverse 1031 Exchanges (which occurred in December 2014 and included the Granite Wash Assets Sale and the Permian Basin Assets Sale, each as defined below). | |||||||||
During the year ended December 31, 2014, the Company also completed other smaller acquisitions of oil and natural gas properties located in its various operating regions. The Company, in the aggregate, paid approximately $5 million in total consideration for these properties. | |||||||||
These acquisitions were accounted for under the acquisition method of accounting. Accordingly, the Company conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated fair values on the acquisition dates, while transaction and integration costs associated with the acquisitions were expensed as incurred. The initial accounting for the business combinations is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates. The results of operations of all acquisitions have been included in the consolidated financial statements since the acquisition dates. | |||||||||
The following presents the values assigned to the net assets acquired as of the acquisition dates (in thousands): | |||||||||
Assets: | |||||||||
Current | $ | 26,007 | |||||||
Oil and natural gas properties | 2,532,439 | ||||||||
Other property and equipment | 121,101 | ||||||||
Total assets acquired | 2,679,547 | ||||||||
Liabilities: | |||||||||
Current | 21,976 | ||||||||
Asset retirement obligations, current and noncurrent | 171,057 | ||||||||
Noncurrent | 18,380 | ||||||||
Total liabilities assumed | 211,413 | ||||||||
Net assets acquired | $ | 2,468,134 | |||||||
Current assets include receivables and inventory. Current liabilities include payables and environmental liabilities. Noncurrent liabilities include out-of-market contracts. | |||||||||
The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs under the fair value hierarchy. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; and (v) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change. | |||||||||
The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the years ended December 31, 2014, and December 31, 2013, assuming the Devon Assets Acquisition and the 2013 acquisition of Berry (see below) had been completed as of January 1, 2013, including adjustments to reflect the values assigned to the net assets acquired. The pro forma financial information has been prepared for informational purposes only and does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The pro forma financial information does not give effect to the costs of any integration activities or benefits that may result from the realization of future cost savings from operating efficiencies, or any other synergies that may result from the transactions and changes in commodity and share prices. | |||||||||
Year Ended | |||||||||
December 31, | |||||||||
2014 | 2013 | ||||||||
(in thousands, except | |||||||||
per unit amounts) | |||||||||
Total revenues and other | $ | 5,335,442 | $ | 3,973,605 | |||||
Total operating expenses | $ | 5,039,311 | $ | 3,711,868 | |||||
Net loss | $ | (403,447 | ) | $ | (397,070 | ) | |||
Net loss per unit: | |||||||||
Basic | $ | (1.25 | ) | $ | (1.22 | ) | |||
Diluted | $ | (1.25 | ) | $ | (1.22 | ) | |||
The pro forma condensed combined statements of operations include adjustments to: | |||||||||
• | Reflect the results of the Devon Assets Acquisition and the Berry acquisition for all periods presented. | ||||||||
• | Reflect incremental depreciation, depletion and amortization expense, using the unit-of-production method related to oil and natural gas properties acquired and an estimated useful life of 10 years and 20 years for other property and equipment acquired in the Devon Assets Acquisition and the Berry acquisition, respectively. | ||||||||
• | Reflect incremental accretion expense related to asset retirement obligations on oil and natural gas properties acquired in the Devon Assets Acquisition. | ||||||||
• | Reflect an increase in interest expense related to incremental debt of $2.3 billion incurred to fund the purchase price of the Devon Assets Acquisition and a reduction in interest expense related to the amortization of the adjustment to fair value of Berry’s debt using the effective interest method. | ||||||||
• | Reflect incremental amortization of deferred financing fees associated with debt incurred to fund the purchase price of the Devon Assets Acquisition. | ||||||||
• | Exclude transaction costs related to the Devon Assets Acquisition and the Berry acquisition included in the historical statements of operations as they reflect nonrecurring charges not expected to have a continuing impact on the combined results. | ||||||||
• | Reflect approximately 93.8 million LINN Energy units assumed to be issued on January 1, 2013, in conjunction with the Berry acquisition. | ||||||||
Divestitures – 2014 | |||||||||
On December 15, 2014, the Company completed the sale of its entire position in the Granite Wash and Cleveland plays located in the Texas Panhandle and western Oklahoma to privately held institutional affiliates of EnerVest, Ltd. and its joint venture partner FourPoint Energy, LLC (the “Granite Wash Assets Sale”). Cash proceeds received from the sale of these properties were approximately $1.8 billion, net of costs to sell of approximately $10 million, and the Company recognized a net gain of approximately $294 million. | |||||||||
On November 14, 2014, the Company completed the sale of certain of its Wolfberry properties in Ector and Midland counties in the Permian Basin to Fleur de Lis Energy, LLC (the “Permian Basin Assets Sale”). Cash proceeds received from the sale of these properties were approximately $351 million, net of costs to sell of approximately $2 million, and the Company recognized a net loss of approximately $28 million. | |||||||||
On October 30, 2014, the Company completed the sale of its interests in certain non-producing oil and natural gas properties located in the Mid-Continent region. Cash proceeds received from the sale of these properties were approximately $44 million, and the Company recognized a net gain of approximately $36 million. | |||||||||
The gains and losses on divestitures are included in “(gains) losses on sales of assets and other, net” on the consolidated statement of operations. | |||||||||
The Company used the net cash proceeds received from these sales to repay in full the VIE Term Loan, as defined below, as well as repay a portion of the borrowings outstanding under the LINN Credit Facility, also defined below. | |||||||||
Joint-Venture Funding | |||||||||
For the year ended December 31, 2014, the Company paid approximately $25 million, including interest, to fund the commitment related to the joint-venture agreement it entered into with an affiliate of Anadarko in April 2012. For the years ended December 31, 2013, and December 31, 2012, the Company paid approximately $173 million and $202 million, respectively, to fund the commitment. As of February 2014, the Company had fully funded the total commitment of $400 million. | |||||||||
Berry Acquisition – 2013 | |||||||||
On December 16, 2013, the Company completed the transactions contemplated by the merger agreement between the Company, LinnCo, LLC (“LinnCo”), an affiliate of LINN Energy, and Berry under which LinnCo acquired all of the outstanding common shares of Berry and the contribution agreement between LinnCo and the Company, under which LinnCo contributed Berry to the Company in exchange for LINN Energy units. Under the merger agreement, as amended, Berry’s shareholders received 1.68 LinnCo common shares for each Berry common share they owned, totaling 93,756,674 LinnCo common shares. Under the contribution agreement, LinnCo contributed Berry to LINN Energy in exchange for 93,756,674 newly issued LINN Energy units, after which Berry became an indirect wholly owned subsidiary of LINN Energy. The transaction was valued at approximately $4.6 billion, including the assumption of approximately $2.3 billion of Berry’s debt and net of cash acquired of approximately $451 million. | |||||||||
Other Acquisitions – 2013 and 2012 | |||||||||
The following is a summary of significant acquisitions completed by the Company during the years ended December 31, 2013, and December 31, 2012: | |||||||||
• | On October 31, 2013, the Company completed the acquisition of certain oil and natural gas properties located in the Permian Basin for approximately $528 million. | ||||||||
• | On July 31, 2012, the Company completed the acquisition of certain oil and natural gas properties in the Jonah Field located in the Green River Basin of southwest Wyoming from BP for approximately $988 million. | ||||||||
• | On May 1, 2012, the Company completed the acquisition of certain oil and natural gas properties located in east Texas for approximately $164 million. | ||||||||
• | On April 3, 2012, the Company entered into a JV Agreement with an affiliate of Anadarko Petroleum Corporation (“Anadarko”) whereby the Company participates as a partner in the CO2 enhanced oil recovery development of the Salt Creek Field, located in the Powder River Basin of Wyoming. Anadarko assigned the Company 23% of its interest in the field in exchange for future funding of $400 million of Anadarko’s development costs. The Company assigned approximately $392 million to the net assets acquired as of the JV Agreement date, which reflects an imputed discount of approximately $8 million on the future funding of this transaction. | ||||||||
• | On March 30, 2012, the Company completed the acquisition of certain oil and natural gas properties and the Jayhawk natural gas processing plant located in the Hugoton Basin in Kansas from BP for approximately $1.17 billion. | ||||||||
Divestiture – 2013 | |||||||||
On May 31, 2013, the Company, through one of its wholly owned subsidiaries, together with the Company’s partners, Panther Energy, LLC and Red Willow Mid-Continent, LLC, completed the sale of its interests in certain oil and natural gas properties located in the Mid-Continent region (“Panther Operated Cleveland Properties”) to Midstates Petroleum Company, Inc. During the year ended December 31, 2013, the Company recorded a noncash impairment charge, before and after tax, of approximately $37 million associated with the write-down of the carrying value of the Panther Operated Cleveland Properties. Cash proceeds received from the sale of these properties were approximately $218 million, net of costs to sell of approximately $2 million. The Company used the net proceeds from the sale to repay borrowings under the LINN Credit Facility. |
Unitholders_Capital
Unitholders' Capital | 12 Months Ended |
Dec. 31, 2014 | |
Equity [Abstract] | |
Unitholders' Capital | Unitholders’ Capital |
Berry Acquisition | |
On December 16, 2013, the Company completed the transactions contemplated by the merger agreement under which LinnCo, an affiliate of LINN Energy, acquired all of the outstanding common shares of Berry and the contribution agreement between LinnCo and the Company, under which LinnCo contributed Berry to the Company in exchange for LINN Energy units. Under the merger agreement, as amended, Berry’s shareholders received 1.68 LinnCo common shares for each Berry common share they owned, totaling 93,756,674 LinnCo common shares. Under the contribution agreement, LinnCo contributed Berry to LINN Energy in exchange for 93,756,674 newly issued LINN Energy units with a value of approximately $2.8 billion. | |
LinnCo Initial Public Offering | |
In October 2012, LinnCo completed its IPO of 34,787,500 common shares representing limited liability company interests to the public at a price of $36.50 per share ($34.858 per share, net of underwriting discount and structuring fee) for net proceeds of approximately $1.2 billion (after underwriting discount and structuring fee of approximately $57 million). The net proceeds LinnCo received from the offering were used to acquire 34,787,500 LINN Energy units which are equal to the number of LinnCo shares sold in the offering. The Company used the proceeds from the sale of these units to LinnCo to pay the expenses of the offering and repay a portion of the borrowings outstanding under the LINN Credit Facility. | |
Public Offering of Units | |
In January 2012, the Company sold 19,550,000 units representing limited liability company interests at $35.95 per unit ($34.512 per unit, net of underwriting discount) for net proceeds of approximately $674 million (after underwriting discount and offering expenses of approximately $28 million). The Company used the net proceeds from the sale of these units to repay a portion of the borrowings outstanding under the LINN Credit Facility. | |
At-the-Market Offering Program | |
In January 2012, the Company, under an equity distribution agreement pursuant to which it may from time to time issue and sell units representing limited liability company interests, issued and sold 1,539,651 units representing limited liability company interests at an average unit price of $38.02 for net proceeds of approximately $57 million (net of approximately $1 million in commissions). In connection with the issuance and sale of these units, the Company also incurred professional service expenses of approximately $700,000. The Company used the net proceeds for general corporate purposes, including the repayment of a portion of the borrowings outstanding under the LINN Credit Facility. | |
In August 2014, the Board of Directors increased the authority under the existing at-the-market offering program to $500 million, and as of December 31, 2014, no units had been sold under the increased authority. Sales of units, if any, will be made through a sales agent by means of ordinary brokers’ transactions, in block transactions, or as otherwise agreed with the agent. The Company expects to use the net proceeds from any sale of the units for general corporate purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt. | |
Unit Repurchase Plan | |
In August 2014, the Board of Directors of the Company authorized the repurchase of up to $250 million of the Company’s outstanding units from time to time on the open market or in negotiated purchases. The timing and amounts of any such repurchases are at the discretion of management, subject to market conditions and other factors, and in accordance with applicable securities laws and other legal requirements. The repurchase plan does not obligate the Company to acquire any specific number of units and may be discontinued at any time. Units are repurchased at fair market value. The Company did not repurchase any units during the years ended December 31, 2014, December 31, 2013, and December 31, 2012, and as of December 31, 2014, the entire amount remained available for unit repurchase under the program. | |
Distributions | |
Under the Company’s LLC Agreement, unitholders are entitled to receive a distribution of available cash, which includes cash on hand plus borrowings less any reserves established by the Company’s Board of Directors to provide for the proper conduct of the Company’s business (including reserves for future capital expenditures, including drilling, acquisitions and anticipated future credit needs) or to fund distributions over the next four quarters. Distributions paid by the Company are presented on the consolidated statements of unitholders’ capital and the consolidated statements of cash flows. In April 2013, the Company’s Board of Directors approved a change in its distribution policy that provides a distribution with respect to any quarter may be made, at the discretion of the Board of Directors, (i) within 45 days following the end of each quarter or (ii) in three equal installments within 15, 45 and 75 days following the end of each quarter. On January 2, 2015, the Company’s Board of Directors declared a cash distribution of $0.3125 per unit with respect to the fourth quarter of 2014, to be paid in three equal monthly installments of $0.1042 per unit. The current distribution represents an approximate 57% decrease from the distribution of $0.725 paid for the previous quarter. The first monthly distribution, totaling approximately $35 million, was paid on January 15, 2015, to unitholders of record as of the close of business on January 12, 2015, and the second monthly distribution, totaling approximately $35 million, was paid on February 17, 2015, to unitholders of record as of the close of business on February 10, 2015. |
Business_and_Credit_Concentrat
Business and Credit Concentrations | 12 Months Ended |
Dec. 31, 2014 | |
Risks and Uncertainties [Abstract] | |
Business and Credit Concentrations | Business and Credit Concentrations |
Cash | |
The Company maintains its cash in bank deposit accounts which at times may exceed federally insured amounts. The Company has not experienced any losses in such accounts. The Company believes it is not exposed to any significant credit risk on its cash. | |
Revenue and Trade Receivables | |
The Company has a concentration of customers who are engaged in oil and natural gas purchasing, transportation and/or refining within the U.S. This concentration of customers may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. The Company’s customers consist primarily of major oil and natural gas purchasers and the Company generally does not require collateral since it has not experienced significant credit losses on such sales. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectibility (see Note 1). | |
For the year ended December 31, 2014, the Company’s largest customer represented approximately 14% of the Company’s sales. For the year ended December 31, 2013, the Company’s largest customer represented approximately 12% of the Company’s sales. For the year ended December 31, 2012, the Company’s two largest customers represented approximately 12% and 11%, respectively, of the Company’s sales. | |
At December 31, 2014, trade accounts receivable from one customer represented approximately 11% of the Company’s receivables. At December 31, 2013, trade accounts receivable from two customers represented approximately 19% and 14%, respectively, of the Company’s receivables. |
UnitBased_Compensation_and_Oth
Unit-Based Compensation and Other Benefit Plans | 12 Months Ended | |||||||||||||
Dec. 31, 2014 | ||||||||||||||
Unit Based Compensation and Other Benefit Plans [Abstract] | ||||||||||||||
Unit-Based Compensation and Other Benefit Plans | Unit-Based Compensation and Other Benefit Plans | |||||||||||||
Incentive Plan Summary | ||||||||||||||
The Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, as amended (the “Plan”), originally became effective in December 2005. The Plan, which is administered by the Compensation Committee of the Board of Directors (“Compensation Committee”), permits granting unrestricted units, restricted units, phantom units, unit options, performance units and unit appreciation rights to employees, consultants and nonemployee directors under the terms of the Plan. The restricted units, phantom units and unit options generally vest ratably over three years. The contractual life of unit options is 10 years. Performance units were granted for the first time in January 2014 to certain executive officers. The initial 2014 awards vest 50% in two years and 50% in three years from the award date. Performance units granted in January 2015 vest three years from the award date. | ||||||||||||||
The Plan limits the number of units that may be delivered pursuant to awards to 21 million units. The Board of Directors and the Compensation Committee have the right to alter or amend the Plan or any part of the Plan from time to time, including increasing the number of units that may be granted, subject to unitholder approval as required by the exchange upon which the units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the benefits to the participant without the consent of the participant. | ||||||||||||||
Units to be delivered as restricted units, upon the vesting of phantom units or performance units, or upon exercise of a unit option or unit appreciation right may be new units issued by the Company, units acquired by the Company in the open market, units acquired by the Company from any other person, units already owned by the Company, or any combination of the foregoing. If the Company issues new units upon the grant of restricted units, vesting of phantom units or performance units, or exercise of a unit option or unit appreciation right, the total number of units outstanding will increase. To date, the Company has issued awards of unrestricted units, restricted units, phantom units, performance units and unit options. The Plan provides for all of the following types of awards: | ||||||||||||||
Unit Grants – A unit grant is the grant of an unrestricted unit that vests immediately upon issuance. | ||||||||||||||
Restricted Units – A restricted unit is a unit that vests over a period of time and that during such time is subject to forfeiture. The Company intends the restricted units under the Plan to serve as a means of incentive compensation for performance. Therefore, Plan participants will not pay any consideration for the units they receive. If a grantee’s employment, consulting relationship or membership on the Company’s Board of Directors terminates for any reason, other than death, the grantee’s restricted units will be automatically forfeited unless, and to the extent, the Compensation Committee or the terms of the award agreement provide otherwise. The restricted units will vest upon a change of control, unless provided otherwise by the Compensation Committee. | ||||||||||||||
Phantom Units – A phantom unit entitles the grantee to receive a unit upon the vesting of the phantom unit or, in the discretion of the Compensation Committee, cash equivalent to the value of a unit. The Compensation Committee may grant tandem distribution equivalent rights with respect to phantom units that entitle the holder to receive cash equal to any cash distributions made on units while the phantom units are outstanding. The Compensation Committee will determine the period over which phantom units will vest, subject to applicable minimum vesting periods except with respect to phantom unit grants to nonemployee directors. The Company intends the phantom units under the Plan to serve as a means of incentive compensation for performance. Therefore, Plan participants will not pay any consideration for the units they receive. If a grantee’s employment, consulting relationship or membership on the Company’s Board of Directors terminates for any reason, other than death or retirement, the grantee’s phantom units will be automatically forfeited unless, and to the extent, the Compensation Committee or the terms of the award agreement provide otherwise. The phantom units will vest upon a change of control, unless provided otherwise by the Compensation Committee. | ||||||||||||||
Unit Options – A unit option is a right to purchase a unit at a specified price. Unit options will have an exercise price that will not be less than the fair market value of the units on the date of grant. If a grantee’s employment, consulting relationship or membership on the Company’s Board of Directors terminates for any reason, the grantee’s unvested unit options will be automatically forfeited unless, and to the extent, the Compensation Committee or the terms of the award agreement provide otherwise. The unit options will become exercisable upon a change of control, unless provided otherwise by the Compensation Committee. | ||||||||||||||
Performance Units – A performance unit is a unit that vests over a period of time in an amount based on certain comparative performance criteria. The Company intends the performance units under the Plan to serve as a means of incentive compensation for performance. Therefore, Plan participants will not pay any consideration for the units they receive. Upon termination of employment with the Company other than for “Cause” or with “Good Reason” (as those terms are defined in the employment agreement), the performance units vest on the originally scheduled vesting date at the performance level multiplier applicable on that date. If employment terminates by reason of death or “Disability” (as defined in the employment agreement), the performance units immediately vest at the target level. Additionally, the performance units vest upon a change of control and the number of units awarded is determined as if the vesting period ended on the change of control date instead of the originally scheduled date. | ||||||||||||||
Unit Appreciation Rights – A unit appreciation right is an award that, upon exercise, entitles the participant to receive the excess of the fair market value of a unit on the exercise date over the exercise price established for the unit appreciation right. The excess may be paid in the Company’s units, cash or a combination thereof, as determined by the Compensation Committee in its discretion. To date, the Company has not granted any unit appreciation rights. | ||||||||||||||
Securities Authorized for Issuance Under the Plan | ||||||||||||||
As of December 31, 2014, approximately 8.3 million units were issuable under the Plan pursuant to outstanding award or other agreements, including unvested restricted units, phantom units and outstanding unit options, and 4.7 million additional units were reserved for future issuance under the Plan. | ||||||||||||||
Accounting for Unit-Based Compensation | ||||||||||||||
The Company recognizes as expense, beginning at the grant date, the fair value of equity-based compensation issued to employees and nonemployee directors. The value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service period using the straight-line method in the Company’s consolidated statements of operations. A summary of unit-based compensation expenses included in the consolidated statements of operations is presented below: | ||||||||||||||
Year Ended December 31, | ||||||||||||||
2014 | 2013 | 2012 | ||||||||||||
(in thousands) | ||||||||||||||
General and administrative expenses | $ | 45,195 | $ | 37,375 | $ | 27,641 | ||||||||
Lease operating expenses | 8,089 | 5,328 | 1,892 | |||||||||||
Total unit-based compensation expenses | $ | 53,284 | $ | 42,703 | $ | 29,533 | ||||||||
Income tax benefit | $ | 19,688 | $ | 15,779 | $ | 10,912 | ||||||||
Restricted Units/Phantom Units/Unrestricted Units | ||||||||||||||
The fair value of restricted units, phantom units and unrestricted unit grants issued is determined based on the fair market value of the Company units on the date of grant. A summary of the status of the nonvested units as of December 31, 2014, is presented below: | ||||||||||||||
Number of | Weighted Average | |||||||||||||
Nonvested | Grant-Date | |||||||||||||
Units | Fair Value | |||||||||||||
Nonvested units at December 31, 2013 | 2,571,410 | $ | 33.14 | |||||||||||
Granted | 1,789,038 | $ | 33.1 | |||||||||||
Vested | (1,282,509 | ) | $ | 32.77 | ||||||||||
Forfeited | (238,966 | ) | $ | 32.25 | ||||||||||
Nonvested units at December 31, 2014 | 2,838,973 | $ | 32.7 | |||||||||||
The weighted average grant-date fair value of restricted units, phantom units and unrestricted units granted was $30.71 and $37.42 during the years ended December 31, 2013, and December 31, 2012, respectively. The total fair value of units that vested was approximately $42 million, $31 million and $24 million for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively. As of December 31, 2014, there was approximately $40 million of unrecognized compensation cost related to nonvested restricted units and phantom units. The cost is expected to be recognized over a weighted average period of approximately 1.6 years. | ||||||||||||||
In January 2015, the Company granted 3,468,245 restricted units and 697,120 phantom units as part of its annual review of its employees’, including executives, compensation. The Company also granted 283,660 performance units (the maximum number of units available to be earned) to certain executive officers. | ||||||||||||||
Unit Options | ||||||||||||||
The following provides information related to unit option activity for the year ended December 31, 2014: | ||||||||||||||
Number of | Weighted Average | Weighted Average Remaining Contractual Life in Years | Aggregate Intrinsic Value in Millions | |||||||||||
Units Underlying Options | Exercise Price Per Unit | |||||||||||||
Outstanding at December 31, 2013 | 6,433,223 | $ | 30.22 | 6.66 | $ | 33 | ||||||||
Exercised | (813,806 | ) | $ | 16.56 | ||||||||||
Forfeited or expired | (175,000 | ) | $ | 40.01 | ||||||||||
Outstanding at December 31, 2014 | 5,444,417 | $ | 31.95 | 5.12 | $ | — | ||||||||
Exercisable at December 31, 2014 | 2,510,457 | $ | 22.57 | 5.5 | $ | — | ||||||||
No unit options were granted during the year ended December 31, 2014. During the years ended December 31, 2013, and December 31, 2012, the weighted average grant-date fair value of unit options granted was $7.52 and $5.31, respectively. All unit options granted in 2013 were replacement awards issued in exchange for options assumed in the Berry acquisition. The total intrinsic value of unit options exercised was approximately $11 million, $2 million and $3 million, during the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively. The Company received approximately $13 million from the exercise of unit options during the year ended December 31, 2014. As of December 31, 2014, total unrecognized compensation cost related to nonvested unit options was approximately $4 million. The cost is expected to be recognized over a weighted average period of approximately 1.1 years. | ||||||||||||||
The fair value of unit-based compensation for unit options was estimated on the date of grant using a Black-Scholes pricing model based on certain assumptions. That value may not be indicative of the fair value observed in a willing buyer/willing seller market transaction. The Company’s determination of the fair value of unit-based awards is affected by the Company’s unit price as well as assumptions consisting of a number of complex and subjective variables. The Company’s employee unit options have various restrictions including vesting provisions and restrictions on transfers and hedging, among others, and often are expected to be exercised prior to their contractual maturity. | ||||||||||||||
Expected volatilities used in the estimation of fair value of the unit option grants have been determined using available volatility data for the Company. Expected distributions are estimated based on the Company’s distribution rate at the date of grant. Forfeitures are estimated using historical Company data and are revised, if necessary, in subsequent periods if actual forfeitures differ from estimates. The risk-free rate for periods within the expected term of the unit option is based on the U.S. Treasury yield curve in effect at the time of grant. Historical data of the Company is used to estimate expected term. All employees granted awards have been determined to have similar behaviors for purposes of determining the expected term used to estimate fair value. The fair values of the Company’s unit option grants were based upon the following assumptions: | ||||||||||||||
2013 (1) | 2012 | |||||||||||||
Expected volatility | 29.65% – 50.88% | 34.10% | ||||||||||||
Expected distributions | 9.84% | 7.25% | ||||||||||||
Risk-free rate | 0.13% – 1.55% | 0.67% | ||||||||||||
Expected term | 0.68 years – 5 years | 5 years | ||||||||||||
(1) | All unit options granted in 2013 were replacement awards issued in exchange for options assumed in the Berry acquisition. | |||||||||||||
Berry Acquisition | ||||||||||||||
On December 16, 2013, in connection with the Berry acquisition (see Note 2), certain Berry awards were exchanged for awards issued by the Company. Each unvested Berry restricted stock unit (“RSU”) (excluding any Berry RSUs held by a former nonemployee director of Berry or by an employee of Berry whose employment was terminated in connection with the acquisition as agreed by the parties and any performance-based Berry RSUs) was converted into a restricted unit award in respect of the number of LINN Energy units. Each option to purchase shares of Berry common stock was converted into an option to purchase a number of LINN Energy units. | ||||||||||||||
Under the acquisition method of accounting, Berry employee RSUs and options were measured and recorded at their fair values on the acquisition date, resulting in additional purchase price consideration of approximately $19 million. The portion of the replacement awards attributable to post-combination service was calculated as the difference between the fair value of the replacement awards and the amount attributed to pre-combination service, and is recognized as compensation expense over the vesting period. | ||||||||||||||
Nonemployee Grants | ||||||||||||||
At December 31, 2014, the Company had 15,000 outstanding unit warrants with an exercise price of $25.50 per unit warrant, which are fully exercisable and expire in 2017. | ||||||||||||||
Defined Contribution Plan | ||||||||||||||
The Company sponsors a 401(k) defined contribution plan for eligible employees. Company contributions to the 401(k) plan consist of a discretionary matching contribution equal to 100% of the first 6% of eligible compensation contributed by the employee on a before-tax basis. The Company contributed approximately $10 million, $7 million and $5 million during the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively, to the 401(k) plan’s trustee account. The 401(k) plan funds are held in a trustee account on behalf of the plan participants. |
Debt
Debt | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Debt Disclosure [Abstract] | |||||||||||||||||
Debt | Debt | ||||||||||||||||
The following summarizes the Company’s outstanding debt: | |||||||||||||||||
December 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
(in thousands, except percentages) | |||||||||||||||||
LINN credit facility (1) | $ | 1,795,000 | $ | 1,560,000 | |||||||||||||
Berry credit facility (2) | 1,173,175 | 1,173,175 | |||||||||||||||
Term loan (3) | 500,000 | 500,000 | |||||||||||||||
10.25% Berry senior notes due June 2014 | — | 205,257 | |||||||||||||||
6.50% senior notes due May 2019 (4) | 1,200,000 | 750,000 | |||||||||||||||
6.25% senior notes due November 2019 | 1,800,000 | 1,800,000 | |||||||||||||||
8.625% senior notes due April 2020 | 1,300,000 | 1,300,000 | |||||||||||||||
6.75% Berry senior notes due November 2020 | 299,970 | 300,000 | |||||||||||||||
7.75% senior notes due February 2021 | 1,000,000 | 1,000,000 | |||||||||||||||
6.50% senior notes due September 2021 (4) | 650,000 | — | |||||||||||||||
6.375% Berry senior notes due September 2022 | 599,163 | 600,000 | |||||||||||||||
Net unamortized discounts and premiums | (21,499 | ) | (18,216 | ) | |||||||||||||
Total debt, net | 10,295,809 | 9,170,216 | |||||||||||||||
Less current maturities | — | (211,558 | ) | ||||||||||||||
Total long-term debt, net | $ | 10,295,809 | $ | 8,958,658 | |||||||||||||
(1) | Variable interest rate of 1.92% at both December 31, 2014, and December 31, 2013. | ||||||||||||||||
(2) | Variable interest rate of 2.67% at both December 31, 2014, and December 31, 2013. | ||||||||||||||||
(3) | Variable interest rates of 2.66% and 2.67% at December 31, 2014 and December 31, 2013, respectively. | ||||||||||||||||
(4) | $450 million of senior notes due May 2019 and $650 million of senior notes due September 2021 were issued on September 9, 2014. | ||||||||||||||||
Fair Value | |||||||||||||||||
The Company’s debt is recorded at the carrying amount in the consolidated balance sheets. The carrying amounts of the Company’s Credit Facilities and term loan approximate fair value because the interest rates are variable and reflective of market rates. The Company uses a market approach to determine the fair value of its senior notes using estimates based on prices quoted from third-party financial institutions, which is a Level 2 fair value measurement. | |||||||||||||||||
December 31, 2014 | December 31, 2013 | ||||||||||||||||
Carrying | Fair Value | Carrying | Fair Value | ||||||||||||||
Value | Value | ||||||||||||||||
(in thousands) | |||||||||||||||||
Credit facilities | $ | 2,968,175 | $ | 2,968,175 | $ | 2,733,175 | $ | 2,733,175 | |||||||||
Term loan | 500,000 | 500,000 | 500,000 | 500,000 | |||||||||||||
Senior notes, net | 6,827,634 | 5,703,649 | 5,937,041 | 6,162,402 | |||||||||||||
Total debt, net | $ | 10,295,809 | $ | 9,171,824 | $ | 9,170,216 | $ | 9,395,577 | |||||||||
Credit Facilities | |||||||||||||||||
LINN Credit Facility | |||||||||||||||||
The Company’s Sixth Amended and Restated Credit Agreement (“LINN Credit Facility”) provides for (1) a senior secured revolving credit facility and (2) a $500 million senior secured term loan, in aggregate subject to the then-effective borrowing base. Borrowing capacity under the revolving credit facility is limited to the lesser of (i) the then-effective borrowing base reduced by the $500 million term loan and (ii) the maximum commitment amount of $4.0 billion, and is currently $4.0 billion. At December 31, 2014, the borrowing base under the LINN Credit Facility was $4.5 billion and availability under the revolving credit facility was approximately $2.2 billion, which includes a $5 million reduction for outstanding letters of credit. | |||||||||||||||||
In April 2014, the Company entered into an amendment to the LINN Credit Facility to extend the maturity date from April 2018 to April 2019, among other items. In August 2014 and September 2014, the Company entered into amendments to the LINN Credit Facility to permit the Devon Assets Acquisition and the Pioneer Assets Acquisition, respectively, and the related Reverse 1031 Exchanges (see Note 2). As a result of the debt incurred under the Bridge Loan, as defined below, the borrowing base was reduced by 25% of the gross proceeds from the Bridge Loan, or $250 million, from $4.5 billion to $4.25 billion, resulting in a reduction of availability under the revolving credit facility of $250 million. Additionally, upon the issuance of an aggregate $1.1 billion of senior notes in the September 2014 offering (see below), the borrowing base was further reduced by $25 million to $4.225 billion, resulting in a further reduction of availability under the revolving credit facility of $25 million. The fall 2014 semi-annual redetermination occurred in December 2014 in order to coincide with the completion of the Reverse 1031 Exchanges, and as part of that redetermination, the borrowing base was restored to $4.5 billion with a maximum commitment amount of $4.0 billion. | |||||||||||||||||
Redetermination of the borrowing base under the LINN Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October. The administrative agent, at the direction of a super majority of certain of the lenders, has the right to request one interim borrowing base redetermination per year. The Company also has the right to request one interim borrowing base redetermination per year, as well as the right to an additional interim redetermination each year in connection with certain acquisitions. Significant declines in commodity prices may result in a decrease in the borrowing base. The Company’s obligations under the LINN Credit Facility are secured by mortgages on certain of its material subsidiaries’ oil and natural gas properties and other personal property as well as a pledge of all ownership interests in the Company’s direct and indirect material subsidiaries. The Company is required to maintain either: 1) mortgages on properties representing at least 80% of the total value of oil and natural gas properties included on its most recent reserve report, or 2) a Collateral Coverage Ratio of at least 2.5 to 1. Collateral Coverage Ratio is defined as the ratio of the present value of future cash flows from proved reserves from the currently mortgaged properties to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount. Additionally, the obligations under the LINN Credit Facility are guaranteed by all of the Company’s material subsidiaries, other than Berry, and are required to be guaranteed by any future material subsidiaries. The Company is in compliance with all financial and other covenants of the LINN Credit Facility. | |||||||||||||||||
At the Company’s election, interest on borrowings under the LINN Credit Facility is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 1.5% and 2.5% per annum (depending on the then-current level of borrowings under the LINN Credit Facility) or the alternate base rate (“ABR”) plus an applicable margin between 0.5% and 1.5% per annum (depending on the then-current level of borrowings under the LINN Credit Facility). Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at LIBOR. The Company is required to pay a commitment fee to the lenders under the LINN Credit Facility, which accrues at a rate per annum between 0.375% and 0.5% (depending on the then-current level of borrowings under the LINN Credit Facility) on the average daily unused amount of the maximum commitment amount of the lenders. | |||||||||||||||||
The $500 million term loan has a maturity date of April 2019 and incurs interest based on either the LIBOR plus a margin of 2.5% per annum or the ABR plus a margin of 1.5% per annum, at the Company’s election. Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at LIBOR. The term loan may be repaid at the option of the Company without premium or penalty, subject to breakage costs. While the term loan is outstanding, the Company is required to maintain either: 1) mortgages on properties representing at least 80% of the total value of oil and natural gas properties included on its most recent reserve report, or 2) a Term Loan Collateral Coverage Ratio of at least 2.5 to 1. The Term Loan Collateral Coverage Ratio is defined as the ratio of the present value of future cash flows from proved reserves from the currently mortgaged properties to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount and the aggregate amount of the term loan outstanding. The other terms and conditions of the LINN Credit Facility, including the financial and other restrictive covenants set forth therein, are applicable to the term loan. | |||||||||||||||||
Berry Credit Facility | |||||||||||||||||
Berry’s Second Amended and Restated Credit Agreement (“Berry Credit Facility”) has a borrowing base of $1.4 billion, subject to lender commitments. At December 31, 2014, lender commitments under the facility were $1.2 billion but there was less than $1 million of available borrowing capacity, including outstanding letters of credit. In February 2014, Berry entered into an amendment to the Berry Credit Facility to amend the terms of certain financial and reporting covenants, among other items. In April 2014, Berry entered into an amendment to the Berry Credit Facility to extend the maturity date from May 2016 to April 2019 and to amend the terms of certain financial covenants and definitions, among other items. | |||||||||||||||||
Redetermination of the borrowing base under the Berry Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October. A super-majority of the lenders under the Berry Credit Facility and Berry also have the right to request interim borrowing base redeterminations once between scheduled redeterminations. Significant declines in commodity prices may result in a decrease in the borrowing base. Berry’s obligations under the Berry Credit Facility are secured by mortgages on its oil and natural gas properties and other personal property. Berry is required to maintain mortgages on properties representing at least 80% of the present value of its oil and natural gas proved reserves. Berry is in compliance with all financial and other covenants of the Berry Credit Facility. | |||||||||||||||||
At Berry’s election, interest on borrowings under the Berry Credit Facility is determined by reference to either the LIBOR plus an applicable margin between 1.5% and 2.5% per annum (depending on the then-current level of borrowings under the Berry Credit Facility) or a Base Rate (as defined in the Berry Credit Facility) plus an applicable margin between 0.5% and 1.5% per annum (depending on the then-current level of borrowings under the Berry Credit Facility). Interest is generally payable quarterly for loans bearing interest based on the Base Rate and at the end of the applicable interest period for loans bearing interest at LIBOR. Berry is required to pay a commitment fee to the lenders under the Berry Credit Facility, which accrues at a rate per annum between 0.375% and 0.5% (depending on the then-current level of utilization under the Berry Credit Facility) on the average daily unused amount of the maximum commitment amount of the lenders. | |||||||||||||||||
The Company refers to the LINN Credit Facility and the Berry Credit Facility, collectively, as the “Credit Facilities.” | |||||||||||||||||
Bridge Loan | |||||||||||||||||
On August 29, 2014, the Company entered into a bridge loan agreement (the “Bridge Loan”) pursuant to which the Company borrowed an aggregate principal amount of $1.0 billion of term loans. The proceeds from the Bridge Loan were advanced to the VIE and used to partially fund the Devon Assets Acquisition (see Note 2). The Bridge Loan agreement was unsecured and was guaranteed by all of the Company’s material domestic subsidiaries which guarantee the LINN Credit Facility. | |||||||||||||||||
The Bridge Loan had an initial maturity date of August 29, 2015, with interest on the initial term loans determined by reference to either (i) LIBOR plus 5.0% plus an applicable margin per annum or (ii) alternate base rate plus 4.0% plus an applicable margin per annum. The applicable margin would have been 0% for the first three months after the funding date and, thereafter, increased by 0.50% at the end of each subsequent three-month period. | |||||||||||||||||
On September 9, 2014, the Company paid in full the outstanding indebtedness under the Bridge Loan using proceeds from the issuance of the New May 2019 Senior Notes and the September 2021 Senior Notes, each as defined below. | |||||||||||||||||
VIE Term Loan | |||||||||||||||||
On August 29, 2014, a subsidiary of the VIE, formed to facilitate the Reverse 1031 Exchange for the Devon Assets Acquisition (see Note 2) entered into a 364-day term loan agreement (the “VIE Term Loan”) pursuant to which it borrowed an aggregate principal amount of $1.3 billion of term loans. The proceeds from the VIE Term Loan were used to partially fund the Devon Assets Acquisition. The obligations under the VIE Term Loan were required to be secured by certain of the oil and natural gas properties and personal property of the VIE’s subsidiary and its material subsidiaries (if any), as well as a pledge of 100% of the equity interests in the subsidiary. Specifically, the VIE’s subsidiary was required to maintain mortgages on properties representing at least 80% of the total value of oil and natural gas properties included on its most recent reserve report. Additionally, the obligations under the VIE Term Loan were to be guaranteed by all of the material subsidiaries of the VIE’s subsidiary (if any). | |||||||||||||||||
In December 2014, the outstanding indebtedness under the VIE Term Loan was paid in full using a portion of the net cash proceeds received from the Granite Wash Assets Sale and the Permian Basin Assets Sale (see Note 2). | |||||||||||||||||
Senior Notes Due May 2019 and Senior Notes Due September 2021 | |||||||||||||||||
On September 9, 2014, the Company issued $1.1 billion in aggregate principal amount of senior notes consisting of $450 million aggregate principal amount of 6.50% senior notes due May 2019 (the “New May 2019 Senior Notes”) at a price of 102% of par and $650 million in aggregate principal amount of 6.50% senior notes due September 2021 (the “September 2021 Senior Notes”) at a price of 98.619% of par. The New May 2019 Senior Notes and the September 2021 Senior Notes were registered under the Securities Act of 1933, as amended (the “Securities Act”), pursuant to a shelf registration statement on Form S-3 filed on September 4, 2014, which was automatically effective upon filing. The Company received net proceeds of approximately $450 million from the issuance of the New May 2019 Senior Notes (after adding the premium of $9 million and deducting offering expenses of approximately $9 million) and approximately $628 million from the issuance of the September 2021 Senior Notes (after deducting the discount of approximately $9 million and offering expenses of approximately $13 million). The Company used the net proceeds from the New May 2019 Senior Notes and the September 2021 Senior Notes to repay all indebtedness outstanding under the Company’s Bridge Loan (see above) as well as repay a portion of the borrowings outstanding under the LINN Credit Facility. The financing fees and expenses of approximately $22 million incurred in connection with the New May 2019 Senior Notes and the September 2021 Senior Notes will be amortized over the life of the notes. Such amortized expenses, premium and discount are recorded in “interest expense, net of amounts capitalized” on the consolidated statements of operations. | |||||||||||||||||
The New May 2019 Senior Notes were issued as additional notes to the original $750 million in aggregate principal amount issued under an indenture (the “May 2019 Indenture”), dated as of May 13, 2011, mature May 15, 2019, and bear interest at 6.50%. Interest is payable in cash semi-annually in arrears on each May 15 and November 15. Interest will be payable to holders of record on the May 1 and November 1 immediately preceding the related interest payment date, and will be computed on the basis of a 360-day year consisting of twelve 30-day months. The May 2019 Senior Notes are general unsecured senior obligations of the Company and are effectively junior in right of payment to any secured indebtedness of the Company to the extent of the collateral securing such indebtedness. Each of the Company’s material subsidiaries, other than Berry, has guaranteed the May 2019 Senior Notes on a senior unsecured basis. The May 2019 Indenture provides that the Company may redeem: (i) prior to May 15, 2015, all or part of the May 2019 Senior Notes at a redemption price equal to the principal amount redeemed, plus a make-whole premium (as defined in the May 2019 Indenture) and accrued and unpaid interest; and (ii) on or after May 15, 2015, all or part of the May 2019 Senior Notes at a redemption price equal to 103.250%, and decreasing percentages thereafter, of the principal amount redeemed, plus accrued and unpaid interest. The May 2019 Indenture also provides that, if a change of control (as defined in the May 2019 Indenture) occurs, the holders have a right to require the Company to repurchase all or part of the May 2019 Senior Notes at a redemption price equal to 101%, plus accrued and unpaid interest. | |||||||||||||||||
The September 2021 Senior Notes were issued under an indenture dated September 9, 2014 (the “September 2021 Indenture”), mature September 15, 2021, and bear interest at 6.50%. Interest is payable in cash semi-annually in arrears on each March 15 and September 15, commencing March 15, 2015. Interest will be payable to holders of record on the March 1 and September 1 immediately preceding the related interest payment date, and will be computed on the basis of a 360-day year consisting of twelve 30-day months. The September 2021 Senior Notes are general unsecured senior obligations of the Company and are effectively junior in right of payment to any secured indebtedness of the Company to the extent of the collateral securing such indebtedness. Each of the Company’s material subsidiaries, other than Berry, has guaranteed the September 2021 Senior Notes on a senior unsecured basis. The September 2021 Indenture provides that the Company may redeem: (i) prior to September 15, 2017, up to 35% of the aggregate principal amount of the September 2021 Senior Notes at a redemption price of 106.500% of the principal amount redeemed, plus accrued and unpaid interest, with the net cash proceeds of one or more equity offerings; (ii) prior to September 15, 2017, all or part of the September 2021 Senior Notes at a redemption price equal to the principal amount redeemed, plus a make-whole premium (as defined in the September 2021 Indenture) and accrued and unpaid interest; and (iii) on or after September 15, 2017, all or part of the September 2021 Senior Notes at a redemption price equal to 103.250%, and decreasing percentages thereafter, of the principal amount redeemed, plus accrued and unpaid interest. The September 2021 Indenture also provides that, if a change of control (as defined in the September 2021 Indenture) occurs, the holders have a right to require the Company to repurchase all or part of the September 2021 Senior Notes at a redemption price equal to 101%, plus accrued and unpaid interest. | |||||||||||||||||
The May 2019 Indenture and the September 2021 Indenture contain covenants that, among other things, limit the Company’s ability and the ability of the Company’s restricted subsidiaries to: (i) pay distributions on, purchase or redeem the Company’s units or redeem its subordinated debt; (ii) make investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create certain liens; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of the Company’s assets; (vii) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. | |||||||||||||||||
Senior Notes Due November 2019 | |||||||||||||||||
The Company has $1.8 billion in aggregate principal amount of 6.25% senior notes due November 2019 (the “November 2019 Senior Notes”). In connection with the issuance and sale of the November 2019 Senior Notes, the Company entered into a Registration Rights Agreement (“November 2019 Registration Rights Agreement”) with the initial purchasers. Under the November 2019 Registration Rights Agreement, the Company agreed to use its reasonable efforts to file with the SEC and cause to become effective a registration statement relating to an offer to issue new notes having terms substantially similar to the November 2019 Senior Notes in exchange for outstanding November 2019 Senior Notes within 400 days after the notes were issued. On March 22, 2013, the Company filed a registration statement on Form S-4 to register exchange notes that are substantially similar to the November 2019 Senior Notes. On June 2, 2014, the registration statement was declared effective and the Company commenced an offer to exchange any and all of its $1.8 billion outstanding principal amount of November 2019 Senior Notes for an equal amount of new November 2019 Senior Notes. | |||||||||||||||||
The terms of the new November 2019 Senior Notes are substantially similar in all material respects to those of the outstanding November 2019 Senior Notes, except that the transfer restrictions, registration rights and additional interest provisions related to the outstanding November 2019 Senior Notes do not apply to the new November 2019 Senior Notes. The exchange offer expired on June 28, 2014. The effective date of the registration statement was past the deadline in the registration rights agreement, and therefore, the Company paid additional interest of approximately $15 million since the deadline. | |||||||||||||||||
Senior Notes Due April 2020 and Senior Notes Due February 2021 | |||||||||||||||||
The Company has $1.3 billion in aggregate principal amount of 8.625% senior notes due April 2020 (the “April 2020 Senior Notes”) and $1.0 billion in aggregate principal amount of 7.75% senior notes due February 2021 (the “February 2021 Senior Notes,” and together with the April 2020 Senior Notes, the “2010 Issued Senior Notes”). The restrictive legends from each of the 2010 Issued Senior Notes have been removed making them freely tradable (other than with respect to persons that are affiliates of the Company), thereby terminating the Company’s obligations under each of the registration rights agreements entered into in connection with the issuance of the 2010 Issued Senior Notes. | |||||||||||||||||
Berry Senior Notes Due November 2020 | |||||||||||||||||
Berry has $300 million in aggregate principal amount of 6.75% senior notes due November 2020 (the “Berry November 2020 Senior Notes”). The Berry November 2020 Senior Notes were recorded at their fair value of $310 million on the Berry acquisition date including a $10 million premium which is being amortized to interest expense over the life of the related notes. | |||||||||||||||||
Berry Senior Notes Due September 2022 | |||||||||||||||||
Berry has $599 million in aggregate principal amount of 6.375% senior notes due September 2022 (the “Berry September 2022 Senior Notes”). The Berry September 2022 Senior Notes were recorded at their fair value of approximately $607 million on the Berry acquisition date including a $7 million premium which is being amortized to interest expense over the life of the related notes. | |||||||||||||||||
Payment of Berry June 2014 Senior Notes | |||||||||||||||||
On May 30, 2014, in accordance with the provisions of the indenture related to the Berry June 2014 Senior Notes, the Company paid in full the remaining outstanding principal amount of approximately $205 million. | |||||||||||||||||
Repurchases of Berry Senior Notes | |||||||||||||||||
In February 2014, in accordance with the indentures related to Berry’s senior notes, the Company repurchased through cash tender offers $321,000, $30,000 and $837,000 of Berry’s 10.25% senior notes due June 2014 (the “Berry June 2014 Senior Notes”), November 2020 Senior Notes and September 2022 Senior Notes, respectively. | |||||||||||||||||
Redemptions of Senior Notes Due May 2017 and Senior Notes Due July 2018 | |||||||||||||||||
In accordance with the provisions of the indentures related to the Company’s 11.75% senior notes due May 2017 (the “May 2017 Senior Notes”) and 9.875% senior notes due July 2018 (the “July 2018 Senior Notes” and together with the May 2017 Senior Notes, the “Original Senior Notes”), in June 2013 and July 2013, the Company redeemed the remaining outstanding principal amounts of approximately $41 million and $14 million, respectively. In connection with the redemptions of the Original Senior Notes, the Company recorded a loss on extinguishment of debt of approximately $5 million for the year ended December 31, 2013. | |||||||||||||||||
Senior Notes Covenants | |||||||||||||||||
The Company’s senior notes contain covenants that, among other things, may limit its ability to: (i) pay distributions on, purchase or redeem the Company’s units or redeem its subordinated debt; (ii) make investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create certain liens; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of the Company’s assets; (vii) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. The Company is in compliance with all financial and other covenants of its senior notes. | |||||||||||||||||
Berry’s senior notes contain covenants that, among other things, may limit its ability to: (i) incur or guarantee additional indebtedness; (ii) pay distributions on Berry’s equity or redeem its subordinated debt; (iii) create certain liens; (iv) enter into agreements that restrict distributions or other payments from Berry’s restricted subsidiaries to Berry; (v) sell assets; (vi) engage in transactions with affiliates; and (vii) consolidate, merge or transfer all or substantially all of Berry’s assets. Berry is in compliance with all financial and other covenants of its senior notes. | |||||||||||||||||
In addition, any cash generated by Berry is currently being used by Berry to fund its activities and is not currently being distributed to LINN Energy. To the extent that Berry generates cash in excess of its needs, the indentures governing Berry’s senior notes limit the amount it may distribute to LINN Energy to the amount available under a “restricted payments basket,” and Berry may not distribute any such amounts unless it is permitted by the indentures to incur additional debt pursuant to the consolidated coverage ratio test set forth in the Berry indentures. Berry’s restricted payments basket may be increased in accordance with the terms of the Berry indentures by, among other things, 50% of Berry’s future net income, reductions in its indebtedness and restricted investments, and future capital contributions. |
Derivatives
Derivatives | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||||||||||||||||
Derivatives | Derivatives | |||||||||||||||
Commodity Derivatives | ||||||||||||||||
The Company hedges a significant portion of its forecasted production to reduce exposure to fluctuations in the prices of oil and natural gas and provide long-term cash flow predictability to manage its business, service debt and pay distributions. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. As a result, currently, the Company directly hedges only its oil and natural gas production. | ||||||||||||||||
The Company enters into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price and, from time to time, put options that are designed to provide a fixed price floor with the opportunity for upside. The Company enters into these transactions with respect to a portion of its projected production to provide an economic hedge of the risk related to the future commodity prices received. The Company does not enter into derivative contracts for trading purposes. In connection with the Berry acquisition (see Note 2), the Company assumed certain derivative contracts that Berry had entered into prior to the acquisition date, including swap contracts, collars and three-way collars. The Company did not designate any of its contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for fair value disclosures about oil and natural gas commodity derivatives. | ||||||||||||||||
The following table summarizes derivative positions for the periods indicated as of December 31, 2014: | ||||||||||||||||
2015 | 2016 | 2017 | 2018 | |||||||||||||
Natural gas positions: | ||||||||||||||||
Fixed price swaps (NYMEX Henry Hub): | ||||||||||||||||
Hedged volume (MMMBtu) | 118,041 | 121,841 | 120,122 | 36,500 | ||||||||||||
Average price ($/MMBtu) | $ | 5.19 | $ | 4.2 | $ | 4.26 | $ | 5 | ||||||||
Put options (NYMEX Henry Hub): | ||||||||||||||||
Hedged volume (MMMBtu) | 71,854 | 76,269 | 66,886 | — | ||||||||||||
Average price ($/MMBtu) | $ | 5 | $ | 5 | $ | 4.88 | $ | — | ||||||||
Oil positions: | ||||||||||||||||
Fixed price swaps (NYMEX WTI): (1) | ||||||||||||||||
Hedged volume (MBbls) | 11,599 | 11,465 | 4,755 | — | ||||||||||||
Average price ($/Bbl) | $ | 96.23 | $ | 90.56 | $ | 89.02 | $ | — | ||||||||
Three-way collars (NYMEX WTI): | ||||||||||||||||
Hedged volume (MBbls) | 1,095 | — | — | — | ||||||||||||
Short put ($/Bbl) | $ | 70 | $ | — | $ | — | $ | — | ||||||||
Long put ($/Bbl) | $ | 90 | $ | — | $ | — | $ | — | ||||||||
Short call ($/Bbl) | $ | 101.62 | $ | — | $ | — | $ | — | ||||||||
Put options (NYMEX WTI): | ||||||||||||||||
Hedged volume (MBbls) | 3,426 | 3,271 | 384 | — | ||||||||||||
Average price ($/Bbl) | $ | 90 | $ | 90 | $ | 90 | $ | — | ||||||||
Natural gas basis differential positions: (2) | ||||||||||||||||
Panhandle basis swaps: | ||||||||||||||||
Hedged volume (MMMBtu) | 87,162 | 59,954 | 59,138 | 16,425 | ||||||||||||
Hedged differential ($/MMBtu) | $ | (0.33 | ) | $ | (0.32 | ) | $ | (0.33 | ) | $ | (0.33 | ) | ||||
NWPL Rockies basis swaps: | ||||||||||||||||
Hedged volume (MMMBtu) | 43,292 | 46,294 | 38,880 | 10,804 | ||||||||||||
Hedged differential ($/MMBtu) | $ | (0.20 | ) | $ | (0.20 | ) | $ | (0.19 | ) | $ | (0.19 | ) | ||||
MichCon basis swaps: | ||||||||||||||||
Hedged volume (MMMBtu) | 9,344 | 7,768 | 7,437 | 2,044 | ||||||||||||
Hedged differential ($/MMBtu) | $ | 0.06 | $ | 0.05 | $ | 0.05 | $ | 0.05 | ||||||||
Houston Ship Channel basis swaps: | ||||||||||||||||
Hedged volume (MMMBtu) | 4,891 | 4,575 | 3,604 | 986 | ||||||||||||
Hedged differential ($/MMBtu) | $ | (0.10 | ) | $ | (0.10 | ) | $ | (0.08 | ) | $ | (0.08 | ) | ||||
Permian basis swaps: | ||||||||||||||||
Hedged volume (MMMBtu) | 5,074 | 4,219 | 4,819 | 1,314 | ||||||||||||
Hedged differential ($/MMBtu) | $ | (0.21 | ) | $ | (0.20 | ) | $ | (0.20 | ) | $ | (0.20 | ) | ||||
Oil timing differential positions: | ||||||||||||||||
Trade month roll swaps (NYMEX WTI): (3) | ||||||||||||||||
Hedged volume (MBbls) | 7,251 | 7,446 | 6,486 | — | ||||||||||||
Hedged differential ($/Bbl) | $ | 0.24 | $ | 0.25 | $ | 0.25 | $ | — | ||||||||
(1) | Includes certain outstanding fixed price oil swaps of approximately 5,384 MBbls which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2017, and December 31, 2018, and $90.00 per Bbl for the year ending December 31, 2019, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years. | |||||||||||||||
(2) | Settle on the respective pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price. | |||||||||||||||
(3) | The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX WTI price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”). | |||||||||||||||
During the fourth quarter of 2014, the Company canceled all of its ICE Brent – NYMEX WTI basis swaps for 2015 and received cash settlements of approximately $12 million. Currently, the Company has no outstanding ICE Brent – NYMEX WTI basis swaps. | ||||||||||||||||
During the year ended December 31, 2013, the Company entered into commodity derivative contracts consisting of oil basis swaps for 2013 and natural gas basis swaps for 2013 through 2018. Also, in connection with the Berry acquisition (see Note 2), the Company assumed certain derivative contracts that Berry had entered into prior to the acquisition date, including oil swaps, oil trade month roll swaps and oil collars through 2014, and oil basis swaps and oil three-way collars through 2015. | ||||||||||||||||
During the year ended December 31, 2012, the Company entered into commodity derivative contracts consisting of oil swaps for 2012 through 2017, natural gas swaps for 2012 through 2018, and oil and natural gas puts for 2012 through 2017 and paid premiums for put options of approximately $583 million. The Company also entered into natural gas basis swaps for 2012 through 2016 and trade month roll swaps for 2012 through 2017. | ||||||||||||||||
Settled derivatives on natural gas production for the year ended December 31, 2014, included volumes of 177,029 MMMBtu at an average contract price of $5.14 per MMBtu. Settled derivatives on oil production for the year ended December 31, 2014, included volumes of 24,988 MBbls at an average contract price of $92.39 per Bbl. Settled derivatives on natural gas production for the year ended December 31, 2013, included volumes of 173,488 MMMBtu at an average contract price of $5.29 per MMBtu. Settled derivatives on oil production for the year ended December 31, 2013, included volumes of 15,590 MBbls at an average contract price of $95.35 per Bbl. Settled derivatives on natural gas production for the year ended December 31, 2012, included volumes of 140,884 MMMBtu at an average contract price of $5.41 per MMBtu. Settled derivatives on oil production for the year ended December 31, 2012, included volumes of 11,289 MBbls at an average contract price of $97.61 per Bbl. | ||||||||||||||||
The natural gas derivatives are settled based on the closing price of NYMEX natural gas on the last trading day for the delivery month, which occurs on the third business day preceding the delivery month, or the relevant index prices of natural gas published in Inside FERC’s Gas Market Report on the first business day of the delivery month. The oil derivatives are settled based on the average closing prices of NYMEX WTI and ICE Brent crude oil for each day of the delivery month. | ||||||||||||||||
Balance Sheet Presentation | ||||||||||||||||
The Company’s commodity derivatives are presented on a net basis in “derivative instruments” on the consolidated balance sheets. The following summarizes the fair value of derivatives outstanding on a gross basis: | ||||||||||||||||
December 31, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Commodity derivatives | $ | 2,014,815 | $ | 1,048,212 | ||||||||||||
Liabilities: | ||||||||||||||||
Commodity derivatives | $ | 90,260 | $ | 222,905 | ||||||||||||
By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are current participants or affiliates of participants in its Credit Facilities or were participants or affiliates of participants in its Credit Facilities at the time it originally entered into the derivatives. The Credit Facilities are secured by the Company’s oil, natural gas and NGL reserves; therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $2.0 billion at December 31, 2014. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated. | ||||||||||||||||
Gains (Losses) on Derivatives | ||||||||||||||||
Gains and losses on derivatives were net gains of approximately $1.2 billion, $178 million and $125 million for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively, and are reported on the consolidated statements of operations in “gains on oil and natural gas derivatives.” For the years ended December 31, 2014, December 31, 2013, and December 31, 2012, the Company received cash settlements of approximately $108 million, $249 million and $391 million, respectively. |
Fair_Value_Measurements_on_a_R
Fair Value Measurements on a Recurring Basis | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||
Fair Value Measurements on a Recurring Basis | Fair Value Measurements on a Recurring Basis | ||||||||||||
The Company accounts for its commodity derivatives at fair value (see Note 7) on a recurring basis. The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to the Company’s commodity derivatives. | |||||||||||||
Fair Value Hierarchy | |||||||||||||
In accordance with applicable accounting standards, the Company has categorized its financial instruments, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). | |||||||||||||
Financial assets and liabilities recorded in the consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows: | |||||||||||||
Level 1 | Financial assets and liabilities for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. | ||||||||||||
Level 2 | Financial assets and liabilities for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability (commodity derivatives). | ||||||||||||
Level 3 | Financial assets and liabilities for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability. | ||||||||||||
When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on a quarterly basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. | |||||||||||||
The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis: | |||||||||||||
December 31, 2014 | |||||||||||||
Level 2 | Netting (1) | Total | |||||||||||
(in thousands) | |||||||||||||
Assets: | |||||||||||||
Commodity derivatives | $ | 2,014,815 | $ | (89,576 | ) | $ | 1,925,239 | ||||||
Liabilities: | |||||||||||||
Commodity derivatives | $ | 90,260 | $ | (89,576 | ) | $ | 684 | ||||||
December 31, 2013 | |||||||||||||
Level 2 | Netting (1) | Total | |||||||||||
(in thousands) | |||||||||||||
Assets: | |||||||||||||
Commodity derivatives | $ | 1,048,212 | $ | (190,080 | ) | $ | 858,132 | ||||||
Liabilities: | |||||||||||||
Commodity derivatives | $ | 222,905 | $ | (190,080 | ) | $ | 32,825 | ||||||
(1) | Represents counterparty netting under agreements governing such derivatives. |
Other_Property_and_Equipment
Other Property and Equipment | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Property, Plant and Equipment [Abstract] | |||||||||
Other Property and Equipment | Other Property and Equipment | ||||||||
Other property and equipment consists of the following: | |||||||||
December 31, | |||||||||
2014 | 2013 | ||||||||
(in thousands) | |||||||||
Natural gas plant and pipeline | $ | 479,754 | $ | 507,342 | |||||
Buildings and leasehold improvements | 49,046 | 32,658 | |||||||
Vehicles | 36,534 | 27,964 | |||||||
Drilling and other equipment | 6,994 | 8,618 | |||||||
Furniture and office equipment | 88,893 | 65,909 | |||||||
Land | 7,928 | 5,391 | |||||||
669,149 | 647,882 | ||||||||
Less accumulated depreciation | (144,282 | ) | (110,939 | ) | |||||
$ | 524,867 | $ | 536,943 | ||||||
Asset_Retirement_Obligations
Asset Retirement Obligations | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Asset Retirement Obligation Disclosure [Abstract] | |||||||||
Asset Retirement Obligations | Asset Retirement Obligations | ||||||||
The Company has the obligation to plug and abandon oil and natural gas wells and related equipment at the end of production operations. Estimated asset retirement costs are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets when the obligation is incurred. The liabilities are included in “other accrued liabilities” and “other noncurrent liabilities” on the consolidated balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the consolidated statements of operations. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (2% for each of the years in the three-year period ended December 31, 2014); and (iv) a credit-adjusted risk-free interest rate (average of 5.3%, 6.2% and 6.8% for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively). These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change. | |||||||||
The following presents a reconciliation of the Company’s asset retirement obligations: | |||||||||
December 31, | |||||||||
2014 | 2013 | ||||||||
(in thousands) | |||||||||
Asset retirement obligations at beginning of year | $ | 289,321 | $ | 151,974 | |||||
Liabilities added from acquisitions | 176,538 | 98,343 | |||||||
Liabilities added from drilling | 10,476 | 4,048 | |||||||
Liabilities associated with assets divested | (25,656 | ) | (1,092 | ) | |||||
Current year accretion expense | 22,164 | 11,938 | |||||||
Settlements | (12,620 | ) | (5,136 | ) | |||||
Revision of estimates | 37,347 | 29,246 | |||||||
Asset retirement obligations at end of year | $ | 497,570 | $ | 289,321 | |||||
Commitments_and_Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2014 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies |
The Company has been named as a defendant in a number of lawsuits, including claims from royalty owners related to disputed royalty payments and royalty valuations. With respect to a certain statewide class action case, the Company has filed a motion to dismiss the case for failure to state a claim on which relief may be granted, and that motion has not yet been ruled on by the Court. While that motion has remained pending, the parties have agreed on a scheduling order, which provides for briefing on the class certification issues in late 2015 and first part of 2016. The Company has denied that it has liability on the claims asserted in the case and has denied that class certification is proper. If the Court accepts the Company’s arguments, there will be no liability to the Company in the case. For another statewide class action royalty payment dispute, briefing on class certification issues is expected to be completed during the summer of 2015. The Company has denied that it has any liability on the claims and has denied that class certification is proper. If the Court accepts the Company’s arguments, there will be no liability to the Company in the case. The Company is unable to estimate a possible loss, or range of possible loss, if any, in these cases. In addition, the Company is involved in various other disputes arising in the ordinary course of business. The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved. | |
Prior to the Company’s acquisition of Berry, Berry became a defendant in a certain statewide royalty class action case. The parties entered into a settlement agreement to settle past claims for approximately $2.4 million, which the Court approved on October 29, 2014. On December 17, 2014, Berry made a one-time lump sum payment of $2.4 million for damages related to production through April 30, 2014. On December 29, 2014, the Court issued an Order dismissing the matter with prejudice. Per the parties’ settlement agreement, Berry has agreed to a new methodology for calculating royalty payments beginning May 1, 2014. | |
In 2013, several class action complaints were filed and ultimately consolidated in the United States District Court, Southern District of New York (the “Federal Actions”) against LINN Energy, LinnCo, certain of their officers and directors and the various underwriters for LinnCo’s initial public offering. These cases collectively asserted claims based on allegations that LINN Energy made false or misleading statements relating to its (i) hedging strategy, (ii) the cash flow available for distribution to unitholders, and (iii) LINN Energy’s energy production in its Exchange Act filings; and additional claims based on alleged misstatements relating to these issues in the prospectus and registration statement for LinnCo’s initial public offering. Several derivative actions were also filed in federal and state court in Texas, and in the Delaware Court of Chancery (the “Derivative Actions”) asserting derivative claims on behalf of LINN Energy against the individual officers and directors for alleged breaches of fiduciary duty, waste of corporate assets, mismanagement, abuse of control, and unjust enrichment based on factual allegations similar to those in the Federal Actions. | |
In July 2014, the Court dismissed the claims of the plaintiffs in the Federal Actions with prejudice, concluding that the plaintiffs failed to demonstrate any material misstatement or omission by LINN Energy or LinnCo, or their officers and directors. The plaintiffs in the Federal Actions did not appeal the Court’s dismissal, and the appeals deadline has now passed. The plaintiffs in the Derivative Actions subsequently have dismissed their claims without prejudice. | |
During the years ended December 31, 2014, December 31, 2013, and December 31, 2012, the Company made no significant payments to settle any legal, environmental or tax proceedings. The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. | |
In 2008, Lehman Brothers Holdings Inc. and Lehman Brothers Commodity Services Inc. (together “Lehman”), filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code with the U.S. Bankruptcy Court for the Southern District of New York. In March 2011, the Company and Lehman entered into Termination Agreements under which the Company was granted general unsecured claims against Lehman in the amount of $51 million (the “Company Claim”). In December 2011, a Chapter 11 Plan (“Lehman Plan”) was approved by the Bankruptcy Court. Based on the recovery estimates described in the approved disclosure statement relating to the Lehman Plan, the Company expects to ultimately receive a substantial portion of the Company Claim. In 2014 and 2013, the Company received approximately $7 million and $11 million, respectively, of the Company Claim of which both amounts are included in “gains on oil and natural gas derivatives” on the consolidated statements of operations. In 2012, the Company received approximately $28 million of the Company Claim resulting in a gain of approximately $22 million included in “gains on oil and natural gas derivatives” on the consolidated statements of operations. In the aggregate, the Company has received approximately $46 million of the Company Claim. |
Earnings_Per_Unit
Earnings Per Unit | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Earnings Per Share [Abstract] | |||||||||||||
Earnings Per Unit | Earnings Per Unit | ||||||||||||
Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted average number of units outstanding during each period. Diluted earnings per unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents. The Company uses the treasury stock method to determine the dilutive effect. | |||||||||||||
The following table provides a reconciliation of the numerators and denominators of the basic and diluted per unit computations for net loss: | |||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(in thousands, except per unit data) | |||||||||||||
Net loss | $ | (451,809 | ) | $ | (691,337 | ) | $ | (386,616 | ) | ||||
Allocated to participating securities | (7,117 | ) | (5,935 | ) | (4,575 | ) | |||||||
$ | (458,926 | ) | $ | (697,272 | ) | $ | (391,191 | ) | |||||
Basic net loss per unit | $ | (1.40 | ) | $ | (2.94 | ) | $ | (1.92 | ) | ||||
Diluted net loss per unit | $ | (1.40 | ) | $ | (2.94 | ) | $ | (1.92 | ) | ||||
Basic weighted average units outstanding | 328,918 | 237,544 | 203,775 | ||||||||||
Dilutive effect of unit equivalents | — | — | — | ||||||||||
Diluted weighted average units outstanding | 328,918 | 237,544 | 203,775 | ||||||||||
Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to approximately 6 million, 4 million and 2 million unit options and warrants for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively. All equivalent units were anti-dilutive for the years ended December 31, 2014, December 31, 2013, and December 31, 2012. |
Operating_Leases
Operating Leases | 12 Months Ended | |||
Dec. 31, 2014 | ||||
Leases, Operating [Abstract] | ||||
Operating Leases | Operating Leases | |||
The Company leases office space and other property and equipment under lease agreements expiring on various dates through 2034. The Company recognized expense under operating leases of approximately $14 million, $7 million and $7 million, for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively. | ||||
As of December 31, 2014, future minimum lease payments were as follows (in thousands): | ||||
2015 | $ | 13,265 | ||
2016 | 10,288 | |||
2017 | 8,215 | |||
2018 | 7,130 | |||
2019 | 6,492 | |||
Thereafter | 1,046 | |||
$ | 46,436 | |||
Income_Taxes
Income Taxes | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Income Tax Disclosure [Abstract] | |||||||||||||
Income Taxes | Income Taxes | ||||||||||||
The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. As such, with the exception of the state of Texas and certain subsidiaries, the Company is not a taxable entity, it does not directly pay federal and state income taxes and recognition has not been given to federal and state income taxes for the operations of the Company, except as set forth in the tables below. Amounts recognized for income taxes are reported in “income tax expense (benefit)” on the consolidated statements of operations. | |||||||||||||
The Company’s taxable income or loss, which may vary substantially from the net income or net loss reported on the consolidated statements of operations, is includable in the federal and state income tax returns of each unitholder. The aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Company does not have access to information about each unitholder’s tax attributes. | |||||||||||||
Certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. Income tax expense (benefit) consisted of the following: | |||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(in thousands) | |||||||||||||
Current taxes: | |||||||||||||
Federal | $ | 473 | $ | 144 | $ | 2,711 | |||||||
State | 21 | 198 | 439 | ||||||||||
Deferred taxes: | |||||||||||||
Federal | (104 | ) | (2,805 | ) | 323 | ||||||||
State | 4,047 | 264 | (683 | ) | |||||||||
$ | 4,437 | $ | (2,199 | ) | $ | 2,790 | |||||||
As of December 31, 2014, the Company’s taxable entities had approximately $11 million of net operating loss carryforwards for federal income tax purposes which will begin expiring in 2031. | |||||||||||||
A reconciliation of the federal statutory tax rate to the effective tax rate is as follows: | |||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Federal statutory rate | 35 | % | 35 | % | 35 | % | |||||||
State, net of federal tax benefit | (0.9 | ) | (0.1 | ) | 0.1 | ||||||||
Loss excluded from nontaxable entities | (34.6 | ) | (34.6 | ) | (35.6 | ) | |||||||
Other items | (0.5 | ) | — | (0.2 | ) | ||||||||
Effective rate | (1.0 | )% | 0.3 | % | (0.7 | )% | |||||||
Significant components of the deferred tax assets and liabilities were as follows: | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | ||||||||||||
(in thousands) | |||||||||||||
Deferred tax assets: | |||||||||||||
Net operating loss carryforwards | $ | — | $ | 1,129 | |||||||||
Unit-based compensation | 22,105 | 21,965 | |||||||||||
Other | 6,857 | 7,759 | |||||||||||
Total deferred tax assets | 28,962 | 30,853 | |||||||||||
Deferred tax liabilities: | |||||||||||||
Property and equipment principally due to differences in depreciation | (10,991 | ) | (12,525 | ) | |||||||||
Other | (6,370 | ) | (1,509 | ) | |||||||||
Total deferred tax liabilities | (17,361 | ) | (14,034 | ) | |||||||||
Net deferred tax assets | $ | 11,601 | $ | 16,819 | |||||||||
Net deferred tax assets and liabilities were classified on the consolidated balance sheets as follows: | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | ||||||||||||
(in thousands) | |||||||||||||
Deferred tax assets | $ | 28,442 | $ | 29,204 | |||||||||
Deferred tax liabilities | (2,964 | ) | (10 | ) | |||||||||
Other current assets | $ | 25,478 | $ | 29,194 | |||||||||
Deferred tax assets | $ | 520 | $ | 1,649 | |||||||||
Deferred tax liabilities | (14,397 | ) | (14,024 | ) | |||||||||
Other noncurrent liabilities | $ | (13,877 | ) | $ | (12,375 | ) | |||||||
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2014, based on the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of these deductible differences. The amount of deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced. | |||||||||||||
In accordance with the applicable accounting standards, the Company recognizes only the impact of income tax positions that, based on their merits, are more likely than not to be sustained upon audit by a taxing authority. To evaluate its current tax positions in order to identify any material uncertain tax positions, the Company developed a policy of identifying and evaluating uncertain tax positions that considers support for each tax position, industry standards, tax return disclosures and schedules and the significance of each position. It is the Company’s policy to recognize interest and penalties, if any, related to unrecognized tax benefits in income tax expense. The Company had no material uncertain tax positions at December 31, 2014, and December 31, 2013. The tax years 2011 – 2013 remain open to examination for federal income tax purposes. |
Supplemental_Disclosures_to_th
Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Balance Sheet and Cash Flow Supplemental Disclosures [Abstract] | |||||||||||||
Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows | Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows | ||||||||||||
“Other accrued liabilities” reported on the consolidated balance sheets include the following: | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | ||||||||||||
(in thousands) | |||||||||||||
Accrued interest | $ | 105,310 | $ | 93,998 | |||||||||
Accrued compensation | 44,875 | 55,257 | |||||||||||
Asset retirement obligations | 16,187 | 12,616 | |||||||||||
Other | 1,364 | 1,504 | |||||||||||
$ | 167,736 | $ | 163,375 | ||||||||||
Supplemental disclosures to the consolidated statements of cash flows are presented below: | |||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(in thousands) | |||||||||||||
Cash payments for interest, net of amounts capitalized | $ | 542,775 | $ | 392,607 | $ | 343,331 | |||||||
Cash payments for income taxes | $ | — | $ | 14 | $ | 366 | |||||||
Noncash investing and financing activities: | |||||||||||||
In connection with the acquisition of oil and natural gas properties and joint-venture funding, assets were acquired and liabilities were assumed as follow: | |||||||||||||
Fair value of assets acquired | $ | 2,679,547 | $ | 5,726,681 | $ | 2,923,990 | |||||||
Cash paid, net of cash acquired | (2,395,339 | ) | (109,350 | ) | (2,640,475 | ) | |||||||
Units issued in connection with the Berry acquisition | — | (2,781,888 | ) | — | |||||||||
Noncash gains on exchanges of properties | (85,493 | ) | — | — | |||||||||
Receivables from sellers | 16,213 | (93 | ) | 2,132 | |||||||||
Payables to sellers | (3,515 | ) | (6,854 | ) | 443 | ||||||||
Liabilities assumed | $ | 211,413 | $ | 2,828,496 | $ | 286,090 | |||||||
Accrued capital expenditures | $ | 240,331 | $ | 334,542 | $ | 203,229 | |||||||
Included in “acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired” on the consolidated statements of cash flows for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, is approximately $25 million, $170 million and $197 million, respectively, paid by the Company towards the future funding commitment related to the joint-venture agreement entered into with Anadarko (see Note 2). | |||||||||||||
On November 21, 2014, the Company, through two of its wholly owned subsidiaries, completed a noncash exchange of a portion of its Permian Basin properties to Exxon Mobil Corporation in exchange for properties in California’s South Belridge Field. On August 15, 2014, the Company, through two of its wholly owned subsidiaries, completed a noncash exchange of a portion of its Permian Basin properties to Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc., for properties in the Hugoton Basin. | |||||||||||||
For purposes of the consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Restricted cash of approximately $6 million is included in “other noncurrent assets” on the consolidated balance sheets at both December 31, 2014, and December 31, 2013, and primarily represents cash the Company has deposited into a separate account and designated for asset retirement obligations in accordance with contractual agreements. | |||||||||||||
The Company manages its working capital and cash requirements to borrow only as needed from its Credit Facilities. At December 31, 2014, and December 31, 2013, net outstanding checks of approximately $95 million and $48 million, respectively, were reclassified and included in “accounts payable and accrued expenses” on the consolidated balance sheets. Net outstanding checks are presented as cash flows from financing activities and included in “other” on the consolidated statements of cash flows. |
Related_Party_Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2014 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions |
LinnCo | |
LinnCo, an affiliate of LINN Energy, was formed on April 30, 2012. LinnCo’s initial sole purpose was to own units in LINN Energy. In connection with the acquisition of Berry, LinnCo amended its limited liability company agreement to permit, among other things, the acquisition and subsequent contribution of assets to LINN Energy. All of LinnCo’s common shares are held by the public. As of December 31, 2014, LinnCo had no significant assets or operations other than those related to its interest in LINN Energy and owned approximately 39% of LINN Energy’s outstanding units. | |
On December 16, 2013, LinnCo and LINN Energy completed the transactions contemplated by the merger agreement, as amended, under which Berry’s shareholders received 1.68 LinnCo common shares for each Berry common share they owned, totaling 93,756,674 LinnCo common shares. Under the contribution agreement between LinnCo and LINN Energy, LinnCo contributed Berry to LINN Energy in exchange for 93,756,674 newly issued LINN Energy units valued at approximately $2.8 billion. | |
In October 2012, LinnCo completed its IPO and used the net proceeds of approximately $1.2 billion from the offering to acquire 34,787,500 of LINN Energy’s units. | |
LINN Energy has agreed to provide to LinnCo, or to pay on LinnCo’s behalf, any legal, accounting, tax advisory, financial advisory and engineering fees, printing costs or other administrative and out-of-pocket expenses incurred by LinnCo, along with any other expenses incurred in connection with any public offering of shares in LinnCo or incurred as a result of being a publicly traded entity. These expenses include costs associated with annual, quarterly and other reports to holders of LinnCo shares, tax return and Form 1099 preparation and distribution, NASDAQ listing fees, printing costs, independent auditor fees and expenses, legal counsel fees and expenses, limited liability company governance and compliance expenses and registrar and transfer agent fees. In addition, the Company has agreed to indemnify LinnCo and its officers and directors for damages suffered or costs incurred (other than income taxes payable by LinnCo) in connection with carrying out LinnCo’s activities. All expenses and costs paid by LINN Energy on LinnCo’s behalf are expensed by LINN Energy. | |
For the year ended December 31, 2014, LinnCo incurred total general and administrative expenses and certain offering costs of approximately $3 million, all of which had been paid by LINN Energy on LinnCo’s behalf as of December 31, 2014. The expenses for the year ended December 31, 2014, include approximately $2 million related to services provided by LINN Energy necessary for the conduct of LinnCo’s business, such as accounting, legal, tax, information technology and other expenses. In addition, during the year ended December 31, 2014, LINN Energy paid approximately $11 million on LinnCo’s behalf for general and administrative expenses incurred by LinnCo in 2013. | |
For the year ended December 31, 2013, LinnCo incurred total general and administrative expenses and certain offering costs of approximately $42 million. The expenses for the year ended December 31, 2013, include approximately $40 million of transaction costs related to the Berry acquisition (see Note 2), including approximately $9 million of noncash share-based compensation expense. The expenses for the year ended December 31, 2013, also include approximately $2 million related to services provided by LINN Energy necessary for the conduct of LinnCo’s business, such as accounting, legal, tax, information technology and other expenses. The offering costs of approximately $388,000 were incurred in connection with LinnCo’s registration statement on Form S-4 also related to the Berry acquisition. | |
During the years ended December 31, 2014, December 31, 2013, and December 31, 2012, the Company paid approximately $373 million, $101 million and $25 million, respectively, in distributions to LinnCo attributable to LinnCo’s interest in LINN Energy. | |
Other | |
One of the Company’s directors is the President and Chief Executive Officer of Superior Energy Services, Inc. (“Superior”), which provides oilfield services to the Company. For the years ended December 31, 2014, December 31, 2013, and December 31, 2012, the Company paid approximately $21 million, $26 million and $21 million, respectively, to Superior and its subsidiaries for services rendered to the Company. The transactions associated with these payments were consummated on terms equivalent to those that prevail in arm’s-length transactions. |
Subsidiary_Guarantors
Subsidiary Guarantors | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | ||||||||||||||||||||
Subsidiary Guarantors | Subsidiary Guarantors | |||||||||||||||||||
LINN Energy, LLC’s May 2019 Senior Notes, November 2019 Senior Notes, September 2021 Senior Notes and 2010 Issued Senior Notes are guaranteed by all of the Company’s material subsidiaries, other than Berry Petroleum Company, LLC, which is an indirect 100% wholly owned subsidiary of the Company. | ||||||||||||||||||||
The following condensed consolidating financial information presents the financial information of LINN Energy, LLC, the guarantor subsidiaries and the non-guarantor subsidiary in accordance with SEC Regulation S-X Rule 3-10. The condensed consolidating financial information for the co-issuer, Linn Energy Finance Corp., is not presented as it has no assets, operations or cash flows. The financial information may not necessarily be indicative of the financial position or results of operations had the guarantor subsidiaries or non-guarantor subsidiary operated as independent entities. Condensed consolidating financial information is not provided for 2012 since during that period, the Company was a holding company that had no independent assets or operations of its own, the guarantees under each series of notes were full and unconditional and joint and several, and any subsidiaries of the Company other than the subsidiary guarantors were minor. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from the guarantor subsidiaries. | ||||||||||||||||||||
CONDENSED CONSOLIDATING BALANCE SHEETS | ||||||||||||||||||||
31-Dec-14 | ||||||||||||||||||||
LINN Energy, LLC | Guarantor Subsidiaries | Non- | Eliminations | Consolidated | ||||||||||||||||
Guarantor Subsidiary | ||||||||||||||||||||
(in thousands) | ||||||||||||||||||||
ASSETS | ||||||||||||||||||||
Current assets: | ||||||||||||||||||||
Cash and cash equivalents | $ | 38 | $ | 185 | $ | 1,586 | $ | — | $ | 1,809 | ||||||||||
Accounts receivable – trade, net | — | 371,325 | 100,359 | — | 471,684 | |||||||||||||||
Accounts receivable – affiliates | 4,028,890 | 13,205 | — | (4,042,095 | ) | — | ||||||||||||||
Derivative instruments | — | 1,033,448 | 43,694 | — | 1,077,142 | |||||||||||||||
Other current assets | 18 | 96,678 | 59,259 | — | 155,955 | |||||||||||||||
Total current assets | 4,028,946 | 1,514,841 | 204,898 | (4,042,095 | ) | 1,706,590 | ||||||||||||||
Noncurrent assets: | ||||||||||||||||||||
Oil and natural gas properties (successful efforts method) | — | 13,196,841 | 4,872,059 | — | 18,068,900 | |||||||||||||||
Less accumulated depletion and amortization | — | (4,342,675 | ) | (525,007 | ) | — | (4,867,682 | ) | ||||||||||||
— | 8,854,166 | 4,347,052 | — | 13,201,218 | ||||||||||||||||
Other property and equipment | — | 553,150 | 115,999 | — | 669,149 | |||||||||||||||
Less accumulated depreciation | — | (135,830 | ) | (8,452 | ) | — | (144,282 | ) | ||||||||||||
— | 417,320 | 107,547 | — | 524,867 | ||||||||||||||||
Derivative instruments | — | 848,097 | — | — | 848,097 | |||||||||||||||
Notes receivable – affiliates | 130,500 | — | — | (130,500 | ) | — | ||||||||||||||
Advance to affiliate | — | — | 293,627 | (293,627 | ) | — | ||||||||||||||
Investments in consolidated subsidiaries | 8,562,608 | — | — | (8,562,608 | ) | — | ||||||||||||||
Other noncurrent assets | 116,637 | 11,816 | 14,284 | — | 142,737 | |||||||||||||||
8,809,745 | 859,913 | 307,911 | (8,986,735 | ) | 990,834 | |||||||||||||||
Total noncurrent assets | 8,809,745 | 10,131,399 | 4,762,510 | (8,986,735 | ) | 14,716,919 | ||||||||||||||
Total assets | $ | 12,838,691 | $ | 11,646,240 | $ | 4,967,408 | $ | (13,028,830 | ) | $ | 16,423,509 | |||||||||
LIABILITIES AND UNITHOLDERS’ CAPITAL | ||||||||||||||||||||
Current liabilities: | ||||||||||||||||||||
Accounts payable and accrued expenses | $ | 3,784 | $ | 581,880 | $ | 229,145 | $ | — | $ | 814,809 | ||||||||||
Accounts payable – affiliates | — | 4,028,890 | 13,205 | (4,042,095 | ) | — | ||||||||||||||
Advance from affiliate | — | 293,627 | — | (293,627 | ) | — | ||||||||||||||
Derivative instruments | — | — | — | — | — | |||||||||||||||
Other accrued liabilities | 89,507 | 59,142 | 19,087 | — | 167,736 | |||||||||||||||
Total current liabilities | 93,291 | 4,963,539 | 261,437 | (4,335,722 | ) | 982,545 | ||||||||||||||
Noncurrent liabilities: | ||||||||||||||||||||
Credit facilities | 1,795,000 | — | 1,173,175 | — | 2,968,175 | |||||||||||||||
Term loan | 500,000 | — | — | — | 500,000 | |||||||||||||||
Senior notes, net | 5,913,857 | — | 913,777 | — | 6,827,634 | |||||||||||||||
Notes payable – affiliates | — | 130,500 | — | (130,500 | ) | — | ||||||||||||||
Derivative instruments | — | 684 | — | — | 684 | |||||||||||||||
Other noncurrent liabilities | — | 400,851 | 200,015 | — | 600,866 | |||||||||||||||
Total noncurrent liabilities | 8,208,857 | 532,035 | 2,286,967 | (130,500 | ) | 10,897,359 | ||||||||||||||
Unitholders’ capital: | ||||||||||||||||||||
Units issued and outstanding | 5,388,749 | 4,831,339 | 2,416,381 | (7,240,658 | ) | 5,395,811 | ||||||||||||||
Accumulated income (deficit) | (852,206 | ) | 1,319,327 | 2,623 | (1,321,950 | ) | (852,206 | ) | ||||||||||||
4,536,543 | 6,150,666 | 2,419,004 | (8,562,608 | ) | 4,543,605 | |||||||||||||||
Total liabilities and unitholders’ capital | $ | 12,838,691 | $ | 11,646,240 | $ | 4,967,408 | $ | (13,028,830 | ) | $ | 16,423,509 | |||||||||
CONDENSED CONSOLIDATING BALANCE SHEETS | ||||||||||||||||||||
31-Dec-13 | ||||||||||||||||||||
LINN Energy, LLC | Guarantor Subsidiaries | Non- | Eliminations | Consolidated | ||||||||||||||||
Guarantor Subsidiary | ||||||||||||||||||||
(in thousands) | ||||||||||||||||||||
ASSETS | ||||||||||||||||||||
Current assets: | ||||||||||||||||||||
Cash and cash equivalents | $ | 52 | $ | 1,078 | $ | 51,041 | $ | — | $ | 52,171 | ||||||||||
Accounts receivable – trade, net | — | 365,347 | 122,855 | — | 488,202 | |||||||||||||||
Accounts receivable – affiliates | 4,212,348 | 16,950 | — | (4,229,298 | ) | — | ||||||||||||||
Derivative instruments | — | 170,534 | 5,596 | — | 176,130 | |||||||||||||||
Other current assets | 330 | 68,274 | 30,833 | — | 99,437 | |||||||||||||||
Total current assets | 4,212,730 | 622,183 | 210,325 | (4,229,298 | ) | 815,940 | ||||||||||||||
Noncurrent assets: | ||||||||||||||||||||
Oil and natural gas properties (successful efforts method) | — | 13,074,900 | 4,813,659 | — | 17,888,559 | |||||||||||||||
Less accumulated depletion and amortization | — | (3,535,890 | ) | (10,394 | ) | — | (3,546,284 | ) | ||||||||||||
— | 9,539,010 | 4,803,265 | — | 14,342,275 | ||||||||||||||||
Other property and equipment | — | 564,756 | 83,126 | — | 647,882 | |||||||||||||||
Less accumulated depreciation | — | (110,706 | ) | (233 | ) | — | (110,939 | ) | ||||||||||||
— | 454,050 | 82,893 | — | 536,943 | ||||||||||||||||
Derivative instruments | — | 679,491 | 2,511 | — | 682,002 | |||||||||||||||
Notes receivable – affiliates | 86,200 | — | — | (86,200 | ) | — | ||||||||||||||
Investments in consolidated subsidiaries | 8,433,290 | — | — | (8,433,290 | ) | — | ||||||||||||||
Other noncurrent assets | 108,785 | 10,968 | 8,051 | — | 127,804 | |||||||||||||||
8,628,275 | 690,459 | 10,562 | (8,519,490 | ) | 809,806 | |||||||||||||||
Total noncurrent assets | 8,628,275 | 10,683,519 | 4,896,720 | (8,519,490 | ) | 15,689,024 | ||||||||||||||
Total assets | $ | 12,841,005 | $ | 11,305,702 | $ | 5,107,045 | $ | (12,748,788 | ) | $ | 16,504,964 | |||||||||
LIABILITIES AND UNITHOLDERS’ CAPITAL | ||||||||||||||||||||
Current liabilities: | ||||||||||||||||||||
Accounts payable and accrued expenses | $ | 14,529 | $ | 587,774 | $ | 247,321 | $ | — | $ | 849,624 | ||||||||||
Accounts payable – affiliates | — | 4,212,348 | 16,950 | (4,229,298 | ) | — | ||||||||||||||
Derivative instruments | — | 7,783 | 20,393 | — | 28,176 | |||||||||||||||
Other accrued liabilities | 75,071 | 59,311 | 28,993 | — | 163,375 | |||||||||||||||
Current portion of long-term debt | — | — | 211,558 | — | 211,558 | |||||||||||||||
Total current liabilities | 89,600 | 4,867,216 | 525,215 | (4,229,298 | ) | 1,252,733 | ||||||||||||||
Noncurrent liabilities: | ||||||||||||||||||||
Credit facilities | 1,560,000 | — | 1,173,175 | — | 2,733,175 | |||||||||||||||
Term loan | 500,000 | — | — | — | 500,000 | |||||||||||||||
Senior notes, net | 4,809,055 | — | 916,428 | — | 5,725,483 | |||||||||||||||
Notes payable – affiliates | — | 86,200 | — | (86,200 | ) | — | ||||||||||||||
Derivative instruments | — | — | 4,649 | — | 4,649 | |||||||||||||||
Other noncurrent liabilities | — | 205,406 | 192,091 | — | 397,497 | |||||||||||||||
Total noncurrent liabilities | 6,869,055 | 291,606 | 2,286,343 | (86,200 | ) | 9,360,804 | ||||||||||||||
Unitholders’ capital: | ||||||||||||||||||||
Units issued and outstanding | 6,282,747 | 4,833,354 | 2,315,460 | (7,139,737 | ) | 6,291,824 | ||||||||||||||
Accumulated income (deficit) | (400,397 | ) | 1,313,526 | (19,973 | ) | (1,293,553 | ) | (400,397 | ) | |||||||||||
5,882,350 | 6,146,880 | 2,295,487 | (8,433,290 | ) | 5,891,427 | |||||||||||||||
Total liabilities and unitholders’ capital | $ | 12,841,005 | $ | 11,305,702 | $ | 5,107,045 | $ | (12,748,788 | ) | $ | 16,504,964 | |||||||||
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS | ||||||||||||||||||||
For the Year Ended December 31, 2014 | ||||||||||||||||||||
LINN Energy, LLC | Guarantor Subsidiaries | Non- | Eliminations | Consolidated | ||||||||||||||||
Guarantor Subsidiary | ||||||||||||||||||||
(in thousands) | ||||||||||||||||||||
Revenues and other: | ||||||||||||||||||||
Oil, natural gas and natural gas liquids sales | $ | — | $ | 2,312,137 | $ | 1,298,402 | $ | — | $ | 3,610,539 | ||||||||||
Gains on oil and natural gas derivatives | — | 1,127,395 | 78,784 | — | 1,206,179 | |||||||||||||||
Marketing revenues | — | 84,349 | 50,911 | — | 135,260 | |||||||||||||||
Other revenues | — | 28,133 | 3,192 | — | 31,325 | |||||||||||||||
— | 3,552,014 | 1,431,289 | — | 4,983,303 | ||||||||||||||||
Expenses: | ||||||||||||||||||||
Lease operating expenses | — | 440,624 | 364,540 | — | 805,164 | |||||||||||||||
Transportation expenses | — | 165,489 | 41,842 | — | 207,331 | |||||||||||||||
Marketing expenses | — | 81,210 | 36,255 | — | 117,465 | |||||||||||||||
General and administrative expenses | — | 190,286 | 102,787 | — | 293,073 | |||||||||||||||
Exploration costs | — | 125,037 | — | — | 125,037 | |||||||||||||||
Depreciation, depletion and amortization | — | 771,549 | 302,353 | — | 1,073,902 | |||||||||||||||
Impairment of long-lived assets | — | 2,050,387 | 253,362 | — | 2,303,749 | |||||||||||||||
Taxes, other than income taxes | 40 | 169,655 | 97,708 | — | 267,403 | |||||||||||||||
(Gains) losses on sale of assets and other, net | — | (487,286 | ) | 120,786 | — | (366,500 | ) | |||||||||||||
40 | 3,506,951 | 1,319,633 | — | 4,826,624 | ||||||||||||||||
Other income and (expenses): | ||||||||||||||||||||
Interest expense, net of amounts capitalized | (480,259 | ) | (19,631 | ) | (87,948 | ) | — | (587,838 | ) | |||||||||||
Interest expense – affiliates | — | (7,954 | ) | — | 7,954 | — | ||||||||||||||
Interest income – affiliates | 7,954 | — | — | (7,954 | ) | — | ||||||||||||||
Equity in earnings from consolidated subsidiaries | 28,397 | — | — | (28,397 | ) | — | ||||||||||||||
Other, net | (7,861 | ) | (7,309 | ) | (1,043 | ) | — | (16,213 | ) | |||||||||||
(451,769 | ) | (34,894 | ) | (88,991 | ) | (28,397 | ) | (604,051 | ) | |||||||||||
Income (loss) before income taxes | (451,809 | ) | 10,169 | 22,665 | (28,397 | ) | (447,372 | ) | ||||||||||||
Income tax expense | — | 4,368 | 69 | — | 4,437 | |||||||||||||||
Net income (loss) | $ | (451,809 | ) | $ | 5,801 | $ | 22,596 | $ | (28,397 | ) | $ | (451,809 | ) | |||||||
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS | ||||||||||||||||||||
For the Year Ended December 31, 2013 | ||||||||||||||||||||
LINN Energy, LLC | Guarantor Subsidiaries | Non- | Eliminations | Consolidated | ||||||||||||||||
Guarantor Subsidiary | ||||||||||||||||||||
(in thousands) | ||||||||||||||||||||
Revenues and other: | ||||||||||||||||||||
Oil, natural gas and natural gas liquids sales | $ | — | $ | 2,022,916 | $ | 50,324 | $ | — | $ | 2,073,240 | ||||||||||
Gains (losses) on oil and natural gas derivatives | — | 182,906 | (5,049 | ) | — | 177,857 | ||||||||||||||
Marketing revenues | — | 52,328 | 1,843 | — | 54,171 | |||||||||||||||
Other revenues | — | 26,387 | — | — | 26,387 | |||||||||||||||
— | 2,284,537 | 47,118 | — | 2,331,655 | ||||||||||||||||
Expenses: | ||||||||||||||||||||
Lease operating expenses | — | 357,113 | 15,410 | — | 372,523 | |||||||||||||||
Transportation expenses | — | 125,864 | 2,576 | — | 128,440 | |||||||||||||||
Marketing expenses | — | 36,259 | 1,633 | — | 37,892 | |||||||||||||||
General and administrative expenses | — | 215,973 | 20,298 | — | 236,271 | |||||||||||||||
Exploration costs | — | 5,251 | — | — | 5,251 | |||||||||||||||
Depreciation, depletion and amortization | — | 818,466 | 10,845 | — | 829,311 | |||||||||||||||
Impairment of long-lived assets | — | 828,317 | — | — | 828,317 | |||||||||||||||
Taxes, other than income taxes | — | 136,501 | 2,130 | — | 138,631 | |||||||||||||||
Losses on sale of assets and other, net | 724 | 2,705 | 10,208 | — | 13,637 | |||||||||||||||
724 | 2,526,449 | 63,100 | — | 2,590,273 | ||||||||||||||||
Other income and (expenses): | ||||||||||||||||||||
Interest expense, net of amounts capitalized | (415,670 | ) | (1,504 | ) | (3,963 | ) | — | (421,137 | ) | |||||||||||
Interest expense – affiliates | — | (5,543 | ) | — | 5,543 | — | ||||||||||||||
Interest income – affiliates | 5,543 | — | — | (5,543 | ) | — | ||||||||||||||
Loss on extinguishment of debt | (5,304 | ) | — | — | — | (5,304 | ) | |||||||||||||
Equity in losses from consolidated subsidiaries | (266,899 | ) | — | — | 266,899 | — | ||||||||||||||
Other, net | (8,283 | ) | (166 | ) | (28 | ) | — | (8,477 | ) | |||||||||||
(690,613 | ) | (7,213 | ) | (3,991 | ) | 266,899 | (434,918 | ) | ||||||||||||
Loss before income taxes | (691,337 | ) | (249,125 | ) | (19,973 | ) | 266,899 | (693,536 | ) | |||||||||||
Income tax benefit | — | (2,199 | ) | — | — | (2,199 | ) | |||||||||||||
Net loss | $ | (691,337 | ) | $ | (246,926 | ) | $ | (19,973 | ) | $ | 266,899 | $ | (691,337 | ) | ||||||
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS | ||||||||||||||||||||
For the Year Ended December 31, 2014 | ||||||||||||||||||||
LINN Energy, LLC | Guarantor Subsidiaries | Non- | Eliminations | Consolidated | ||||||||||||||||
Guarantor Subsidiary | ||||||||||||||||||||
(in thousands) | ||||||||||||||||||||
Cash flow from operating activities: | ||||||||||||||||||||
Net income (loss) | $ | (451,809 | ) | $ | 5,801 | $ | 22,596 | $ | (28,397 | ) | $ | (451,809 | ) | |||||||
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | ||||||||||||||||||||
Depreciation, depletion and amortization | — | 771,549 | 302,353 | — | 1,073,902 | |||||||||||||||
Impairment of long-lived assets | — | 2,050,387 | 253,362 | — | 2,303,749 | |||||||||||||||
Unit-based compensation expenses | — | 53,284 | — | — | 53,284 | |||||||||||||||
Amortization and write-off of deferred financing fees | 38,785 | 17,054 | (4,913 | ) | — | 50,926 | ||||||||||||||
(Gains) losses on sale of assets and other, net | — | (372,945 | ) | 111,374 | — | (261,571 | ) | |||||||||||||
Equity in earnings from consolidated subsidiaries | (28,397 | ) | — | — | 28,397 | — | ||||||||||||||
Deferred income tax | — | 3,874 | 69 | — | 3,943 | |||||||||||||||
Derivatives activities: | ||||||||||||||||||||
Total gains | — | (1,127,395 | ) | (78,784 | ) | — | (1,206,179 | ) | ||||||||||||
Cash settlements | — | 88,776 | 6,738 | — | 95,514 | |||||||||||||||
Cash settlements on canceled derivatives | — | — | 12,281 | — | 12,281 | |||||||||||||||
Changes in assets and liabilities: | ||||||||||||||||||||
(Increase) decrease in accounts receivable – trade, net | — | (11,419 | ) | 16,483 | — | 5,064 | ||||||||||||||
Decrease in accounts receivable – affiliates | 257,485 | 16,950 | — | (274,435 | ) | — | ||||||||||||||
(Increase) decrease in other assets | 312 | (2,187 | ) | (15,949 | ) | — | (17,824 | ) | ||||||||||||
Increase in accounts payable and accrued expenses | — | 99,003 | 26 | — | 99,029 | |||||||||||||||
Decrease in accounts payable and accrued expenses – affiliates | — | (270,690 | ) | (3,745 | ) | 274,435 | — | |||||||||||||
Increase (decrease) in other liabilities | 14,465 | (24,473 | ) | (38,411 | ) | — | (48,419 | ) | ||||||||||||
Net cash provided by (used in) operating activities | (169,159 | ) | 1,297,569 | 583,480 | — | 1,711,890 | ||||||||||||||
Cash flow from investing activities: | ||||||||||||||||||||
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired | — | (2,475,315 | ) | (3,937 | ) | — | (2,479,252 | ) | ||||||||||||
Development of oil and natural gas properties | — | (1,061,395 | ) | (508,482 | ) | — | (1,569,877 | ) | ||||||||||||
Purchases of other property and equipment | — | (63,070 | ) | (11,470 | ) | — | (74,540 | ) | ||||||||||||
Investment in affiliates | (100,921 | ) | — | — | 100,921 | — | ||||||||||||||
Change in notes receivable with affiliate | (44,300 | ) | — | — | 44,300 | — | ||||||||||||||
Proceeds from sale of properties and equipment and other | (14,117 | ) | 2,210,015 | 7,667 | — | 2,203,565 | ||||||||||||||
Net cash used in investing activities | (159,338 | ) | (1,389,765 | ) | (516,222 | ) | 145,221 | (1,920,104 | ) | |||||||||||
LINN Energy, LLC | Guarantor Subsidiaries | Non- | Eliminations | Consolidated | ||||||||||||||||
Guarantor Subsidiary | ||||||||||||||||||||
(in thousands) | ||||||||||||||||||||
Cash flow from financing activities: | ||||||||||||||||||||
Proceeds from borrowings | 4,640,024 | 1,300,000 | — | — | 5,940,024 | |||||||||||||||
Repayments of debt | (3,305,000 | ) | (1,300,000 | ) | (206,124 | ) | — | (4,811,124 | ) | |||||||||||
Distributions to unitholders | (962,048 | ) | — | — | — | (962,048 | ) | |||||||||||||
Financing fees and offering expenses | (59,048 | ) | — | (10,646 | ) | — | (69,694 | ) | ||||||||||||
Change in note payable with affiliate | — | 44,300 | — | (44,300 | ) | — | ||||||||||||||
Capital contribution – affiliates | — | — | 100,921 | (100,921 | ) | — | ||||||||||||||
Excess tax benefit from unit-based compensation | 810 | (44 | ) | — | — | 766 | ||||||||||||||
Other | 13,745 | 47,047 | (864 | ) | — | 59,928 | ||||||||||||||
Net cash provided by (used in) financing activities | 328,483 | 91,303 | (116,713 | ) | (145,221 | ) | 157,852 | |||||||||||||
Net decrease in cash and cash equivalents | (14 | ) | (893 | ) | (49,455 | ) | — | (50,362 | ) | |||||||||||
Cash and cash equivalents: | ||||||||||||||||||||
Beginning | 52 | 1,078 | 51,041 | — | 52,171 | |||||||||||||||
Ending | $ | 38 | $ | 185 | $ | 1,586 | $ | — | $ | 1,809 | ||||||||||
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS | ||||||||||||||||||||
For the Year Ended December 31, 2013 | ||||||||||||||||||||
LINN Energy, LLC | Guarantor Subsidiaries | Non- | Eliminations | Consolidated | ||||||||||||||||
Guarantor Subsidiary | ||||||||||||||||||||
(in thousands) | ||||||||||||||||||||
Cash flow from operating activities: | ||||||||||||||||||||
Net loss | $ | (691,337 | ) | $ | (246,926 | ) | $ | (19,973 | ) | $ | 266,899 | $ | (691,337 | ) | ||||||
Adjustments to reconcile net loss to net cash provided by (used in) operating activities: | ||||||||||||||||||||
Depreciation, depletion and amortization | — | 818,466 | 10,845 | — | 829,311 | |||||||||||||||
Impairment of long-lived assets | — | 828,317 | — | — | 828,317 | |||||||||||||||
Unit-based compensation expenses | — | 42,703 | — | — | 42,703 | |||||||||||||||
Loss on extinguishment of debt | 5,304 | — | — | — | 5,304 | |||||||||||||||
Amortization and write-off of deferred financing fees | 22,122 | — | (615 | ) | — | 21,507 | ||||||||||||||
Losses on sale of assets and other, net | — | 37,232 | — | — | 37,232 | |||||||||||||||
Equity in losses from consolidated subsidiaries | 266,899 | — | — | (266,899 | ) | — | ||||||||||||||
Deferred income taxes | — | (2,541 | ) | — | — | (2,541 | ) | |||||||||||||
Derivatives activities: | ||||||||||||||||||||
Total (gains) losses | — | (182,906 | ) | 5,049 | — | (177,857 | ) | |||||||||||||
Cash settlements | — | 248,862 | — | — | 248,862 | |||||||||||||||
Changes in assets and liabilities: | ||||||||||||||||||||
Decrease in accounts receivable – trade, net | — | 17,754 | 71,434 | — | 89,188 | |||||||||||||||
Increase in accounts receivable – affiliates | (120,967 | ) | (16,950 | ) | — | 137,917 | — | |||||||||||||
(Increase) decrease in other assets | (330 | ) | 5,896 | 10,613 | — | 16,179 | ||||||||||||||
Increase (decrease) in accounts payable and accrued expenses | 178 | (52,143 | ) | (25,028 | ) | — | (76,993 | ) | ||||||||||||
Increase in accounts payable and accrued expenses – affiliates | — | 120,967 | 16,950 | (137,917 | ) | — | ||||||||||||||
Increase (decrease) in other liabilities | 2,092 | 6,842 | (12,597 | ) | — | (3,663 | ) | |||||||||||||
Net cash provided by (used in) operating activities | (516,039 | ) | 1,625,573 | 56,678 | — | 1,166,212 | ||||||||||||||
Cash flow from investing activities: | ||||||||||||||||||||
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired | — | (730,326 | ) | 451,113 | — | (279,213 | ) | |||||||||||||
Development of oil and natural gas properties | — | (1,060,547 | ) | (17,478 | ) | — | (1,078,025 | ) | ||||||||||||
Purchases of other property and equipment | — | (92,352 | ) | — | — | (92,352 | ) | |||||||||||||
Investment in affiliates | 435,000 | — | — | (435,000 | ) | — | ||||||||||||||
Change in notes receivable with affiliate | (26,700 | ) | — | — | 26,700 | — | ||||||||||||||
Proceeds from sale of properties and equipment and other | (22,039 | ) | 218,312 | — | — | 196,273 | ||||||||||||||
Net cash provided by (used in) investing activities | 386,261 | (1,664,913 | ) | 433,635 | (408,300 | ) | (1,253,317 | ) | ||||||||||||
LINN Energy, LLC | Guarantor Subsidiaries | Non- | Eliminations | Consolidated | ||||||||||||||||
Guarantor Subsidiary | ||||||||||||||||||||
(in thousands) | ||||||||||||||||||||
Cash flow from financing activities: | ||||||||||||||||||||
Proceeds from borrowings | 2,230,000 | — | — | — | 2,230,000 | |||||||||||||||
Repayments of debt | (1,404,898 | ) | — | — | — | (1,404,898 | ) | |||||||||||||
Distributions to unitholders | (682,241 | ) | — | — | — | (682,241 | ) | |||||||||||||
Financing fees and offering expenses | (16,033 | ) | — | — | — | (16,033 | ) | |||||||||||||
Change in note payable with affiliate | — | 26,700 | — | (26,700 | ) | — | ||||||||||||||
Capital contribution – affiliates | — | — | (435,000 | ) | 435,000 | — | ||||||||||||||
Excess tax benefit from unit-based compensation | — | 160 | — | — | 160 | |||||||||||||||
Other | 2,895 | 12,422 | (4,272 | ) | — | 11,045 | ||||||||||||||
Net cash provided by (used in) financing activities | 129,723 | 39,282 | (439,272 | ) | 408,300 | 138,033 | ||||||||||||||
Net increase (decrease) in cash and cash equivalents | (55 | ) | (58 | ) | 51,041 | — | 50,928 | |||||||||||||
Cash and cash equivalents: | ||||||||||||||||||||
Beginning | 107 | 1,136 | — | — | 1,243 | |||||||||||||||
Ending | $ | 52 | $ | 1,078 | $ | 51,041 | $ | — | $ | 52,171 | ||||||||||
SEC_Inquiry
SEC Inquiry | 12 Months Ended |
Dec. 31, 2014 | |
Subsequent Events [Abstract] | |
SEC Inquiry | SEC Inquiry |
As disclosed on July 1, 2013, the Company and its affiliate, LinnCo, were notified by the staff of the SEC that its Fort Worth Regional Office had commenced an inquiry regarding LINN Energy and LinnCo. The SEC staff was investigating whether any violations of federal securities laws had occurred. Both LINN Energy and LinnCo cooperated fully with the SEC in this matter. The Company was notified on February 4, 2015, that the SEC has closed its inquiry regarding LINN Energy and LinnCo and does not intend to recommend any enforcement action. |
Supplemental_Oil_and_Natural_G
Supplemental Oil and Natural Gas Data (Unaudited) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||||||||||||
Supplemental Oil and Natural Gas Data (Unaudited) | The following discussion and analysis should be read in conjunction with the “Consolidated Financial Statements” and “Notes to Consolidated Financial Statements,” which are included in this Annual Report on Form 10-K in Item 8. “Financial Statements and Supplementary Data.” | ||||||||||||
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities | |||||||||||||
Costs incurred in oil and natural gas property acquisition, exploration and development, whether capitalized or expensed, are presented below: | |||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(in thousands) | |||||||||||||
Property acquisition costs: (1) | |||||||||||||
Proved | $ | 2,784,852 | $ | 3,740,379 | $ | 2,531,419 | |||||||
Unproved | 788,682 | 1,638,302 | 181,124 | ||||||||||
Exploration costs | 792 | 13,096 | 452 | ||||||||||
Development costs | 1,487,204 | 1,153,770 | 1,062,043 | ||||||||||
Asset retirement costs | 20,919 | 7,351 | 4,675 | ||||||||||
Total costs incurred | $ | 5,082,449 | $ | 6,552,898 | $ | 3,779,713 | |||||||
(1) | See Note 2 for details about the Company’s acquisitions. | ||||||||||||
Oil and Natural Gas Capitalized Costs | |||||||||||||
Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below: | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | ||||||||||||
(in thousands) | |||||||||||||
Proved properties: | |||||||||||||
Leasehold acquisition | $ | 13,362,642 | $ | 12,277,089 | |||||||||
Development | 2,830,841 | 3,660,277 | |||||||||||
Unproved properties | 1,875,417 | 1,951,193 | |||||||||||
18,068,900 | 17,888,559 | ||||||||||||
Less accumulated depletion and amortization | (4,867,682 | ) | (3,546,284 | ) | |||||||||
$ | 13,201,218 | $ | 14,342,275 | ||||||||||
Results of Oil and Natural Gas Producing Activities | |||||||||||||
The results of operations for oil, natural gas and NGL producing activities (excluding corporate overhead and interest costs) are presented below: | |||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(in thousands) | |||||||||||||
Revenues and other: | |||||||||||||
Oil, natural gas and natural gas liquid sales | $ | 3,610,539 | $ | 2,073,240 | $ | 1,601,180 | |||||||
Gains on oil and natural gas derivatives | 1,206,179 | 177,857 | 124,762 | ||||||||||
4,816,718 | 2,251,097 | 1,725,942 | |||||||||||
Production costs: | |||||||||||||
Lease operating expenses | 805,164 | 372,523 | 317,699 | ||||||||||
Transportation expenses | 207,331 | 128,440 | 77,322 | ||||||||||
Severance taxes, ad valorem taxes and California carbon allowances | 267,100 | 139,202 | 130,805 | ||||||||||
1,279,595 | 640,165 | 525,826 | |||||||||||
Other costs: | |||||||||||||
Exploration costs | 125,037 | 5,251 | 1,915 | ||||||||||
Depletion and amortization | 1,020,674 | 790,320 | 579,382 | ||||||||||
Impairment of long-lived assets | 2,303,749 | 828,317 | 422,499 | ||||||||||
Gains on sale of assets and other, net | (388,733 | ) | (138 | ) | (1,369 | ) | |||||||
Texas margin tax expense (benefit) | 4,053 | 458 | (787 | ) | |||||||||
3,064,780 | 1,624,208 | 1,001,640 | |||||||||||
Results of operations | $ | 472,343 | $ | (13,276 | ) | $ | 198,476 | ||||||
There is no federal tax provision included in the results above because the Company’s subsidiaries subject to federal tax do not own any of the Company’s oil and natural gas interests. Limited liability companies are subject to Texas margin tax. See Note 14 for additional information about income taxes. | |||||||||||||
Proved Oil, Natural Gas and NGL Reserves | |||||||||||||
The proved reserves of oil, natural gas and NGL of the Company have been prepared by the independent engineering firm, DeGolyer and MacNaughton. In accordance with SEC regulations, reserves at December 31, 2014, December 31, 2013, and December 31, 2012, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. An analysis of the change in estimated quantities of oil, natural gas and NGL reserves, all of which are located within the U.S., is shown below: | |||||||||||||
Year Ended December 31, 2014 | |||||||||||||
Natural Gas | Oil | NGL | Total | ||||||||||
(Bcf) | (MMBbls) | (MMBbls) | (Bcfe) | ||||||||||
Proved developed and undeveloped reserves: | |||||||||||||
Beginning of year | 3,010 | 365.6 | 200 | 6,403 | |||||||||
Revisions of previous estimates | 96 | (22.3 | ) | (46.8 | ) | (318 | ) | ||||||
Purchases of minerals in place | 1,763 | 50 | 71.9 | 2,495 | |||||||||
Sales of minerals in place | (477 | ) | (51.7 | ) | (49.5 | ) | (1,084 | ) | |||||
Extensions, discoveries and other additions | 72 | 26.8 | 2.9 | 250 | |||||||||
Production | (209 | ) | (26.6 | ) | (12.2 | ) | (442 | ) | |||||
End of year | 4,255 | 341.8 | 166.3 | 7,304 | |||||||||
Proved developed reserves: | |||||||||||||
Beginning of year | 2,027 | 252.4 | 133.2 | 4,340 | |||||||||
End of year | 3,549 | 246 | 132.2 | 5,818 | |||||||||
Proved undeveloped reserves: | |||||||||||||
Beginning of year | 983 | 113.2 | 66.8 | 2,063 | |||||||||
End of year | 706 | 95.8 | 34.1 | 1,486 | |||||||||
Year Ended December 31, 2013 | |||||||||||||
Natural Gas (Bcf) | Oil | NGL (MMBbls) | Total | ||||||||||
(MMBbls) | (Bcfe) | ||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||
Beginning of year | 2,571 | 191.5 | 179.4 | 4,796 | |||||||||
Revisions of previous estimates | (17 | ) | (21.3 | ) | (2.0 | ) | (157 | ) | |||||
Purchases of minerals in place | 356 | 191.1 | 17.8 | 1,610 | |||||||||
Sales of minerals in place | (24 | ) | (5.2 | ) | (2.9 | ) | (73 | ) | |||||
Extensions, discoveries and other additions | 286 | 21.7 | 18.5 | 527 | |||||||||
Production | (162 | ) | (12.2 | ) | (10.8 | ) | (300 | ) | |||||
End of year | 3,010 | 365.6 | 200 | 6,403 | |||||||||
Proved developed reserves: | |||||||||||||
Beginning of year | 1,661 | 131.4 | 113 | 3,127 | |||||||||
End of year | 2,027 | 252.4 | 133.2 | 4,340 | |||||||||
Proved undeveloped reserves: | |||||||||||||
Beginning of year | 910 | 60.1 | 66.4 | 1,669 | |||||||||
End of year | 983 | 113.2 | 66.8 | 2,063 | |||||||||
Year Ended December 31, 2012 | |||||||||||||
Natural Gas (Bcf) | Oil | NGL (MMBbls) | Total | ||||||||||
(MMBbls) | (Bcfe) | ||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||
Beginning of year | 1,675 | 189 | 93.5 | 3,370 | |||||||||
Revisions of previous estimates | (559 | ) | (26.5 | ) | (14.1 | ) | (803 | ) | |||||
Purchases of minerals in place | 1,176 | 23.1 | 75.3 | 1,766 | |||||||||
Extensions, discoveries and other additions | 407 | 16.6 | 33.7 | 709 | |||||||||
Production | (128 | ) | (10.7 | ) | (9.0 | ) | (246 | ) | |||||
End of year | 2,571 | 191.5 | 179.4 | 4,796 | |||||||||
Proved developed reserves: | |||||||||||||
Beginning of year | 998 | 124.8 | 47.8 | 2,034 | |||||||||
End of year | 1,661 | 131.4 | 113 | 3,127 | |||||||||
Proved undeveloped reserves: | |||||||||||||
Beginning of year | 677 | 64.2 | 45.7 | 1,336 | |||||||||
End of year | 910 | 60.1 | 66.4 | 1,669 | |||||||||
The tables above include changes in estimated quantities of oil and NGL reserves shown in Mcf equivalents at a rate of one barrel per six Mcf. | |||||||||||||
Since the reserves were estimated in accordance with SEC regulations, using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, the Company had positive price revisions for the year ended December 31, 2014, even though there was a steep decline in commodity prices during the fourth quarter of 2014. From September 30, 2014 to December 31, 2014, NYMEX oil and natural gas prices decreased approximately 42% and 30%, respectively, to $53.27 per Bbl for oil and $2.89 per MMBtu for natural gas at December 31, 2014. For information about potential risks that could affect the Company if lower commodity prices were to continue, see Item 1A. “Risk Factors.” | |||||||||||||
Proved reserves increased by approximately 901 Bcfe to approximately 7,304 Bcfe for the year ended December 31, 2014, from 6,403 Bcfe for the year ended December 31, 2013. The year ended December 31, 2014, includes approximately 318 Bcfe of negative revisions of previous estimates, due primarily to 174 Bcfe of negative revisions due to ethane rejection in the Hugoton and Green River basins, 146 Bcfe of negative revisions due to the SEC five-year development limitation on PUDs and 43 Bcfe of negative revisions due to asset performance, partially offset by 45 Bcfe of positive revisions primarily due to higher natural gas prices. During the year ended December 31, 2014, acquisitions and properties acquired in the two exchanges with Exxon Mobil Corporation increased proved reserves by approximately 2,495 Bcfe and the 2014 divestitures and properties relinquished in the two exchanges with Exxon Mobil Corporation decreased proved reserves by approximately 1,084 Bcfe. In addition, extensions and discoveries, primarily from 917 productive wells drilled during the year, contributed approximately 250 Bcfe to the increase in proved reserves. | |||||||||||||
Proved reserves increased by approximately 1,607 Bcfe to approximately 6,403 Bcfe for the year ended December 31, 2013, from 4,796 Bcfe for the year ended December 31, 2012. The year ended December 31, 2013, includes 157 Bcfe of negative revisions of previous estimates, due primarily to 100 Bcfe of negative revisions due to asset performance, 109 Bcfe of negative revisions due to the SEC five-year development limitation on PUDs, partially offset by 52 Bcfe of positive revisions primarily due to higher natural gas prices. During the year ended December 31, 2013, three acquisitions increased proved reserves by approximately 1,610 Bcfe and the sale of the Panther Operated Cleveland Properties decreased proved reserves by approximately 73 Bcfe. In addition, extensions and discoveries, primarily from 557 productive wells drilled during the year, contributed approximately 527 Bcfe to the increase in proved reserves. | |||||||||||||
Proved reserves increased by approximately 1,426 Bcfe to approximately 4,796 Bcfe for the year ended December 31, 2012, from 3,370 Bcfe for the year ended December 31, 2011. The year ended December 31, 2012, includes 803 Bcfe of negative revisions of previous estimates, due primarily to 340 Bcfe of negative revisions due to asset performance, 248 Bcfe of negative revisions due to lower natural gas prices and 215 Bcfe of negative revisions due to the SEC five-year development limitation on PUDs. During the year ended December 31, 2012, seven acquisitions increased proved reserves by approximately 1,766 Bcfe. In addition, extensions and discoveries, primarily from 436 productive wells drilled during the year, contributed approximately 709 Bcfe to the increase in proved reserves. | |||||||||||||
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves | |||||||||||||
Information with respect to the standardized measure of discounted future net cash flows relating to proved reserves is summarized below. Future cash inflows are computed by applying applicable prices relating to the Company’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses because the Company is not subject to federal income taxes. Limited liability companies are subject to Texas margin tax; however, these amounts are not material. See Note 14 for additional information about income taxes. | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(in thousands) | |||||||||||||
Future estimated revenues | $ | 55,195,268 | $ | 51,112,346 | $ | 30,374,380 | |||||||
Future estimated production costs | (24,100,468 | ) | (19,306,728 | ) | (11,460,854 | ) | |||||||
Future estimated development costs | (4,032,588 | ) | (5,110,896 | ) | (3,574,058 | ) | |||||||
Future net cash flows | 27,062,212 | 26,694,722 | 15,339,468 | ||||||||||
10% annual discount for estimated timing of cash flows | (14,549,921 | ) | (14,795,393 | ) | (9,266,487 | ) | |||||||
Standardized measure of discounted future net cash flows | $ | 12,512,291 | $ | 11,899,329 | $ | 6,072,981 | |||||||
Representative NYMEX prices: (1) | |||||||||||||
Natural gas (MMBtu) | $ | 4.35 | $ | 3.67 | $ | 2.76 | |||||||
Oil (Bbl) | $ | 95.27 | $ | 96.89 | $ | 94.64 | |||||||
(1) | In accordance with SEC regulations, reserves at December 31, 2014, December 31, 2013, and December 31, 2012, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves. | ||||||||||||
The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows: | |||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(in thousands) | |||||||||||||
Sales and transfers of oil, natural gas and NGL produced during the period | $ | (2,330,944 | ) | $ | (1,433,075 | ) | $ | (1,075,354 | ) | ||||
Changes in estimated future development costs | 156,614 | 317,064 | 289,762 | ||||||||||
Net change in sales and transfer prices and production costs related to future production | (599,121 | ) | 203,370 | (1,463,820 | ) | ||||||||
Purchases of minerals in place | 3,021,768 | 5,113,335 | 2,153,651 | ||||||||||
Sales of minerals in place | (1,681,504 | ) | (139,384 | ) | — | ||||||||
Extensions, discoveries and improved recovery | 910,787 | 801,254 | 413,702 | ||||||||||
Previously estimated development costs incurred during the period | 819,987 | 444,861 | 442,322 | ||||||||||
Net change due to revisions in quantity estimates | (672,800 | ) | (220,224 | ) | (1,595,302 | ) | |||||||
Accretion of discount | 1,189,933 | 607,298 | 661,486 | ||||||||||
Changes in production rates and other | (201,758 | ) | 131,849 | (368,326 | ) | ||||||||
$ | 612,962 | $ | 5,826,348 | $ | (541,879 | ) | |||||||
The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and assumptions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein. |
Supplemental_Quarterly_Data_Un
Supplemental Quarterly Data (Unaudited) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Quarterly Financial Data [Abstract] | |||||||||||||||||
Supplemental Quarterly Data (Unaudited) | The following discussion and analysis should be read in conjunction with the “Consolidated Financial Statements” and “Notes to Consolidated Financial Statements,” which are included in this Annual Report on Form 10-K in Item 8. “Financial Statements and Supplementary Data.” | ||||||||||||||||
Quarterly Financial Data | |||||||||||||||||
Quarters Ended | |||||||||||||||||
31-Mar | 30-Jun | 30-Sep | December 31 | ||||||||||||||
(in thousands, except per unit amounts) | |||||||||||||||||
2014:00:00 | |||||||||||||||||
Oil, natural gas and natural gas liquid sales | $ | 938,877 | $ | 967,850 | $ | 937,458 | $ | 766,354 | |||||||||
Gains (losses) on oil and natural gas derivatives | (241,493 | ) | (408,788 | ) | 451,702 | 1,404,758 | |||||||||||
Total revenues and other | 733,587 | 596,951 | 1,435,115 | 2,217,650 | |||||||||||||
Total expenses (1) | 674,568 | 664,452 | 1,320,157 | 2,533,947 | |||||||||||||
(Gains) losses on sale of assets and other, net | 2,586 | 5,467 | (35,803 | ) | (338,750 | ) | |||||||||||
Net loss | (85,337 | ) | (207,870 | ) | (4,100 | ) | (154,502 | ) | |||||||||
Net loss per unit: | |||||||||||||||||
Basic | $ | (0.27 | ) | $ | (0.64 | ) | $ | (0.02 | ) | $ | (0.47 | ) | |||||
Diluted | $ | (0.27 | ) | $ | (0.64 | ) | $ | (0.02 | ) | $ | (0.47 | ) | |||||
Quarters Ended | |||||||||||||||||
31-Mar | 30-Jun | 30-Sep | December 31 | ||||||||||||||
(in thousands, except per unit amounts) | |||||||||||||||||
2013:00:00 | |||||||||||||||||
Oil, natural gas and natural gas liquid sales | $ | 462,732 | $ | 488,207 | $ | 537,671 | $ | 584,630 | |||||||||
Gains (losses) on oil and natural gas derivatives | (108,370 | ) | 326,733 | (63,931 | ) | 23,425 | |||||||||||
Total revenues and other | 369,060 | 838,825 | 494,562 | 629,208 | |||||||||||||
Total expenses (1) | 478,235 | 385,540 | 420,803 | 1,292,058 | |||||||||||||
(Gains) losses on sale of assets and other, net | 3,172 | (959 | ) | 827 | 10,597 | ||||||||||||
Net income (loss) | (221,885 | ) | 345,157 | (30,060 | ) | (784,549 | ) | ||||||||||
Net income (loss) per unit: | |||||||||||||||||
Basic | $ | (0.96 | ) | $ | 1.47 | $ | (0.13 | ) | $ | (3.15 | ) | ||||||
Diluted | $ | (0.96 | ) | $ | 1.46 | $ | (0.13 | ) | $ | (3.15 | ) | ||||||
(1) | Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, depreciation, depletion and amortization, impairment of long-lived assets and taxes, other than income taxes. |
Basis_of_Presentation_and_Sign1
Basis of Presentation and Significant Accounting Policies (Policies) | 12 Months Ended | |
Dec. 31, 2014 | ||
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Principles of Consolidation and Reporting | Principles of Consolidation and Reporting | |
The Company presents its financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”). The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method. | ||
The consolidated financial statements for previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income (loss), unitholders’ capital or cash flows. | ||
Use of Estimates | Use of Estimates | |
The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, fair values of commodity derivatives and fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods. | ||
Cash Equivalents | Cash Equivalents | |
For purposes of the consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Outstanding checks in excess of funds on deposit are included in “accounts payable and accrued expenses” on the consolidated balance sheets and are classified as financing activities on the consolidated statements of cash flows. | ||
Accounts Receivable - Trade, Net | Accounts Receivable – Trade, Net | |
Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging, and existing industry and national economic data. The Company reviews its allowance for doubtful accounts monthly. Past due balances over 90 days and over a specified amount are reviewed individually for collectibility. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential recovery is remote. The balance in the Company’s allowance for doubtful accounts related to trade accounts receivable was approximately $1 million at both December 31, 2014, and December 31, 2013. | ||
Inventories | Inventories | |
Materials, supplies and commodity inventories are valued at the lower of average cost or market. | ||
Oil and Natural Gas Properties | Oil and Natural Gas Properties | |
Proved Properties | ||
The Company accounts for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively. | ||
The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows of proved and risk-adjusted probable and possible reserves are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use. The Company capitalized interest costs of approximately $9 million for the year ended December 31, 2014, and $2 million for each of the years ended December 31, 2013, and December 31, 2012. | ||
Impairment of Proved Properties | ||
Based on the analysis described above, for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, the Company recorded noncash impairment charges, before and after tax, of approximately $2.3 billion, $791 million and $422 million, respectively, associated with proved oil and natural gas properties. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the consolidated statements of operations. | ||
During the fourth quarter of 2014, the Company recorded noncash impairment charges, before and after tax, of approximately $1.7 billion associated with proved oil and natural gas properties throughout its various operating regions. The impairment was due to a steep decline in commodity prices. From September 30, 2014 to December 31, 2014, NYMEX oil and natural gas forward price curves decreased approximately 24% and 12%, respectively. Following are the impairment charges recorded by operating region: | ||
• | Permian Basin – $735 million; | |
• | Rockies – $586 million (in the Powder River Basin and Uinta Basin); | |
• | Mid-Continent – $244 million; | |
• | South Texas – $131 million; and | |
• | TexLa – $5 million. | |
In addition, during the third quarter of 2014, the Company recorded noncash impairment charges, before and after tax, of approximately $603 million associated with proved oil and natural gas properties in the Permian Basin region. The impairment was due to the divestiture of certain high valued unproved properties in the Midland Basin in which the expected cash flows were previously included in the impairment assessment for the proved oil and natural gas properties. | ||
During the year ended December 31, 2013, the Company recorded a noncash impairment charge, before and after tax, of approximately $791 million associated with proved oil and natural gas properties in the Granite Wash formation related to asset performance resulting in reserve revisions and a decline in commodity prices. During the year ended December 31, 2012, the Company recorded noncash impairment charges, before and after tax, of approximately $422 million associated with proved oil and natural gas properties in the Mississippi Shelf and Mayfield related to the SEC five-year development limitation on PUDs and a decline in commodity prices. | ||
Subsequent to December 31, 2014, the prices of oil, natural gas and NGL have continued to be volatile. In the future, if forward price curves continue to decline, the Company may have additional impairments which could have a material impact on its results of operations. | ||
Unproved Properties | ||
Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company assesses unproved properties for impairment quarterly on the basis of its experience in similar situations and other factors such as the primary lease terms of the properties, the average holding period of unproved properties and the relative proportion of such properties on which proved reserves have been found in the past. | ||
Exploration Costs | ||
Geological and geophysical costs, delay rentals, amortization and impairment of unproved leasehold costs and costs to drill exploratory wells that do not find proved reserves are expensed as exploration costs. The costs of any exploratory wells are carried as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as the Company is making sufficient progress towards assessing the reserves and the economic and operating viability of the project. The Company recorded noncash leasehold impairment expenses related to unproved properties of approximately $125 million, $5 million and $2 million for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively, which are included in “exploration costs” on the consolidated statements of operations. | ||
Impairment of Proved Properties | Impairment of Proved Properties | |
Based on the analysis described above, for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, the Company recorded noncash impairment charges, before and after tax, of approximately $2.3 billion, $791 million and $422 million, respectively, associated with proved oil and natural gas properties. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the consolidated statements of operations. | ||
During the fourth quarter of 2014, the Company recorded noncash impairment charges, before and after tax, of approximately $1.7 billion associated with proved oil and natural gas properties throughout its various operating regions. The impairment was due to a steep decline in commodity prices. From September 30, 2014 to December 31, 2014, NYMEX oil and natural gas forward price curves decreased approximately 24% and 12%, respectively. Following are the impairment charges recorded by operating region: | ||
• | Permian Basin – $735 million; | |
• | Rockies – $586 million (in the Powder River Basin and Uinta Basin); | |
• | Mid-Continent – $244 million; | |
• | South Texas – $131 million; and | |
• | TexLa – $5 million. | |
In addition, during the third quarter of 2014, the Company recorded noncash impairment charges, before and after tax, of approximately $603 million associated with proved oil and natural gas properties in the Permian Basin region. The impairment was due to the divestiture of certain high valued unproved properties in the Midland Basin in which the expected cash flows were previously included in the impairment assessment for the proved oil and natural gas properties. | ||
During the year ended December 31, 2013, the Company recorded a noncash impairment charge, before and after tax, of approximately $791 million associated with proved oil and natural gas properties in the Granite Wash formation related to asset performance resulting in reserve revisions and a decline in commodity prices. During the year ended December 31, 2012, the Company recorded noncash impairment charges, before and after tax, of approximately $422 million associated with proved oil and natural gas properties in the Mississippi Shelf and Mayfield related to the SEC five-year development limitation on PUDs and a decline in commodity prices. | ||
Other Property and Equipment | Other Property and Equipment | |
Other property and equipment includes natural gas gathering systems, pipelines, buildings, software, data processing and telecommunications equipment, office furniture and equipment, and other fixed assets. These assets are recorded at cost and are depreciated using the straight-line method based on expected lives ranging from two to 39 years for the individual asset or group of assets. | ||
Revenue Recognition | Revenue Recognition | |
Revenues representative of the Company’s ownership interest in its properties are presented on a gross basis on the consolidated statements of operations. Sales of oil, natural gas and NGL are recognized when the product has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. | ||
The Company has elected the entitlements method to account for natural gas production imbalances. Imbalances occur when the Company sells more or less than its entitled ownership percentage of total natural gas production. In accordance with the entitlements method, any amount received in excess of the Company’s share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. Imbalance receivables and payables are valued at the lower of the price in effect at the time of production, the current market value or, if a contract is in hand, the contract price. At December 31, 2014, and December 31, 2013, the Company had natural gas production imbalance receivables of approximately $17 million and $27 million, respectively, which are included in “accounts receivable – trade, net” on the consolidated balance sheets and natural gas production imbalance payables of approximately $13 million and $16 million, respectively, which are included in “accounts payable and accrued expenses” on the consolidated balance sheets. | ||
The Company engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements. As such, the Company separately reports third-party marketing revenues and marketing expenses. | ||
The Company generates electricity with excess natural gas, which it uses to serve certain of its operating facilities in California. Any excess electricity is sold to the California wholesale power market. The revenue from this activity is included in “other revenues” on the consolidated statements of operations. | ||
Restricted Cash | Restricted Cash | |
Restricted cash of approximately $6 million is included in “other noncurrent assets” on the consolidated balance sheets at both December 31, 2014, and December 31, 2013, and primarily represents cash the Company has deposited into a separate account and designated for asset retirement obligations in accordance with contractual agreements. | ||
Derivative Instruments | Derivative Instruments | |
The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of oil and natural gas. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in net cash provided by operating activities due to fluctuations in commodity prices. | ||
The Company enters into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price and, from time to time, put options that are designed to provide a fixed price floor with the opportunity for upside. A swap contract specifies a fixed price that the Company will receive from the counterparty as compared to floating market prices, and on the settlement date the Company will receive or pay the difference between the swap price and the market price. A put option requires the Company to pay the counterparty a premium equal to the fair value of the option at the purchase date and receive from the counterparty the excess, if any, of the fixed price floor over the market price at the settlement date. Also, the Company may from time to time enter into derivative contracts in the form of interest rate swaps to minimize the effects of fluctuations in interest rates. At December 31, 2014, the Company had no outstanding derivative contracts in the form of interest rate swaps. | ||
In addition, as part of the 2013 acquisition of Berry Petroleum Company, now Berry Petroleum Company, LLC (“Berry”) (see Note 2), the Company assumed certain derivative contracts that Berry had entered into prior to the acquisition date, including swap contracts, collars and three-way collars. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. Three-way collar contracts combine a short put (the lower price), a long put (the middle price) and a short call (the higher price) to provide a higher ceiling price as compared to a regular collar and limit downside risk to the market price plus the difference between the middle price and the lower price if the market price drops below the lower price. | ||
Derivative instruments (including certain derivative instruments embedded in other contracts that require bifurcation) are recorded at fair value and included on the consolidated balance sheets as assets or liabilities. The Company did not designate these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. The Company uses certain pricing models to determine the fair value of its derivative financial instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. See Note 7 and Note 8 for additional details about the Company’s derivative financial instruments. | ||
Unit-Based Compensation | Unit-Based Compensation | |
The Company recognizes expense for unit-based compensation over the requisite service period in an amount equal to the fair value of unit-based awards granted to employees and nonemployee directors. The fair value of unit-based awards, excluding liability awards, is computed at the date of grant and is not remeasured. The fair value of liability awards is remeasured at each reporting date through the settlement date with the change in fair value recognized as compensation expense over that period. The Company currently does not have any awards accounted for as liability awards. | ||
The Company has made a policy decision to recognize compensation expense for service-based awards on a straight-line basis over the requisite service period for the entire award. See Note 5 for additional details about the Company’s accounting for unit-based compensation. | ||
The benefit of tax deductions in excess of recognized compensation costs is required to be reported as financing cash flow rather than operating cash flow. This requirement reduces net operating cash flow and increases net financing cash flow in periods in which such tax benefit exists. The amount of the Company’s excess tax benefit is also reported in “excess tax benefit from unit-based compensation and other” on the consolidated statements of unitholders’ capital. | ||
Deferred Financing Fees | Deferred Financing Fees | |
The Company incurred legal and bank fees related to the issuance of debt. At December 31, 2014, and December 31, 2013, net deferred financing fees of approximately $129 million and $114 million, respectively, are included in “other noncurrent assets” on the consolidated balance sheets. These debt issuance costs are amortized over the life of the debt agreement. Upon early retirement or amendment to the debt agreement, certain fees are written off to expense. For the years ended December 31, 2014, December 31, 2013, and December 31, 2012, amortization expense of approximately $46 million, $18 million and $13 million, respectively, is included in “interest expense, net of amounts capitalized” on the consolidated statements of operations. For the year ended December 31, 2014, approximately $8 million were written off to expense and included in “other, net” on the consolidated statement of operations related to the VIE Term Loan (as defined in Note 6) and amendments to the Credit Facilities (as defined in Note 6). For the year ended December 31, 2012, approximately $8 million were written off to expense and included in “other, net” on the consolidated statement of operations related to amendments of the LINN Credit Facility (as defined in Note 6). No fees related to amendments of the Credit Facilities were written off to expense during the year ended December 31, 2013. | ||
Fair Value of Financial Instruments | Fair Value of Financial Instruments | |
The carrying values of the Company’s receivables, payables and Credit Facilities are estimated to be substantially the same as their fair values at December 31, 2014, and December 31, 2013. See Note 6 for fair value disclosures related to the Company’s other outstanding debt. As noted above, the Company carries its derivative financial instruments at fair value. See Note 8 for details about the fair value of the Company’s derivative financial instruments. | ||
Income Taxes | Income Taxes | |
The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its unitholders. As such, with the exception of the state of Texas, the Company is not a taxable entity, it does not directly pay federal and state income tax and recognition has not been given to federal and state income taxes for the operations of the Company except as described below. | ||
Limited liability companies are subject to Texas margin tax. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes, which are accounted for using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and tax carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. See Note 14 for detail of amounts recorded in the consolidated financial statements. |
Exchanges_of_Properties_Acquis1
Exchanges of Properties, Acquisitions, Divestitures and Joint-Venture Funding (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Business Combinations [Abstract] | |||||||||
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | The following presents the values assigned to the net assets acquired as of the acquisition dates (in thousands): | ||||||||
Assets: | |||||||||
Current | $ | 26,007 | |||||||
Oil and natural gas properties | 2,532,439 | ||||||||
Other property and equipment | 121,101 | ||||||||
Total assets acquired | 2,679,547 | ||||||||
Liabilities: | |||||||||
Current | 21,976 | ||||||||
Asset retirement obligations, current and noncurrent | 171,057 | ||||||||
Noncurrent | 18,380 | ||||||||
Total liabilities assumed | 211,413 | ||||||||
Net assets acquired | $ | 2,468,134 | |||||||
Schedule of Pro Forma Results of Operations | The pro forma financial information does not give effect to the costs of any integration activities or benefits that may result from the realization of future cost savings from operating efficiencies, or any other synergies that may result from the transactions and changes in commodity and share prices. | ||||||||
Year Ended | |||||||||
December 31, | |||||||||
2014 | 2013 | ||||||||
(in thousands, except | |||||||||
per unit amounts) | |||||||||
Total revenues and other | $ | 5,335,442 | $ | 3,973,605 | |||||
Total operating expenses | $ | 5,039,311 | $ | 3,711,868 | |||||
Net loss | $ | (403,447 | ) | $ | (397,070 | ) | |||
Net loss per unit: | |||||||||
Basic | $ | (1.25 | ) | $ | (1.22 | ) | |||
Diluted | $ | (1.25 | ) | $ | (1.22 | ) | |||
The pro forma condensed combined statements of operations include adjustments to: | |||||||||
• | Reflect the results of the Devon Assets Acquisition and the Berry acquisition for all periods presented. | ||||||||
• | Reflect incremental depreciation, depletion and amortization expense, using the unit-of-production method related to oil and natural gas properties acquired and an estimated useful life of 10 years and 20 years for other property and equipment acquired in the Devon Assets Acquisition and the Berry acquisition, respectively. | ||||||||
• | Reflect incremental accretion expense related to asset retirement obligations on oil and natural gas properties acquired in the Devon Assets Acquisition. | ||||||||
• | Reflect an increase in interest expense related to incremental debt of $2.3 billion incurred to fund the purchase price of the Devon Assets Acquisition and a reduction in interest expense related to the amortization of the adjustment to fair value of Berry’s debt using the effective interest method. | ||||||||
• | Reflect incremental amortization of deferred financing fees associated with debt incurred to fund the purchase price of the Devon Assets Acquisition. | ||||||||
• | Exclude transaction costs related to the Devon Assets Acquisition and the Berry acquisition included in the historical statements of operations as they reflect nonrecurring charges not expected to have a continuing impact on the combined results. | ||||||||
• | Reflect approximately 93.8 million LINN Energy units assumed to be issued on January 1, 2013, in conjunction with the Berry acquisition. |
UnitBased_Compensation_and_Oth1
Unit-Based Compensation and Other Benefit Plans (Tables) | 12 Months Ended | |||||||||||||
Dec. 31, 2014 | ||||||||||||||
Unit Based Compensation and Other Benefit Plans [Abstract] | ||||||||||||||
Employee Service Share-Based Compensation Expense | A summary of unit-based compensation expenses included in the consolidated statements of operations is presented below: | |||||||||||||
Year Ended December 31, | ||||||||||||||
2014 | 2013 | 2012 | ||||||||||||
(in thousands) | ||||||||||||||
General and administrative expenses | $ | 45,195 | $ | 37,375 | $ | 27,641 | ||||||||
Lease operating expenses | 8,089 | 5,328 | 1,892 | |||||||||||
Total unit-based compensation expenses | $ | 53,284 | $ | 42,703 | $ | 29,533 | ||||||||
Income tax benefit | $ | 19,688 | $ | 15,779 | $ | 10,912 | ||||||||
Nonvested Units | A summary of the status of the nonvested units as of December 31, 2014, is presented below: | |||||||||||||
Number of | Weighted Average | |||||||||||||
Nonvested | Grant-Date | |||||||||||||
Units | Fair Value | |||||||||||||
Nonvested units at December 31, 2013 | 2,571,410 | $ | 33.14 | |||||||||||
Granted | 1,789,038 | $ | 33.1 | |||||||||||
Vested | (1,282,509 | ) | $ | 32.77 | ||||||||||
Forfeited | (238,966 | ) | $ | 32.25 | ||||||||||
Nonvested units at December 31, 2014 | 2,838,973 | $ | 32.7 | |||||||||||
Unit Options Activity | The following provides information related to unit option activity for the year ended December 31, 2014: | |||||||||||||
Number of | Weighted Average | Weighted Average Remaining Contractual Life in Years | Aggregate Intrinsic Value in Millions | |||||||||||
Units Underlying Options | Exercise Price Per Unit | |||||||||||||
Outstanding at December 31, 2013 | 6,433,223 | $ | 30.22 | 6.66 | $ | 33 | ||||||||
Exercised | (813,806 | ) | $ | 16.56 | ||||||||||
Forfeited or expired | (175,000 | ) | $ | 40.01 | ||||||||||
Outstanding at December 31, 2014 | 5,444,417 | $ | 31.95 | 5.12 | $ | — | ||||||||
Exercisable at December 31, 2014 | 2,510,457 | $ | 22.57 | 5.5 | $ | — | ||||||||
Valuation Assumptions | The fair values of the Company’s unit option grants were based upon the following assumptions: | |||||||||||||
2013 (1) | 2012 | |||||||||||||
Expected volatility | 29.65% – 50.88% | 34.10% | ||||||||||||
Expected distributions | 9.84% | 7.25% | ||||||||||||
Risk-free rate | 0.13% – 1.55% | 0.67% | ||||||||||||
Expected term | 0.68 years – 5 years | 5 years | ||||||||||||
(1) | All unit options granted in 2013 were replacement awards issued in exchange for options assumed in the Berry acquisition. |
Debt_Tables
Debt (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Debt Disclosure [Abstract] | |||||||||||||||||
Summary of Outstanding Debt | The following summarizes the Company’s outstanding debt: | ||||||||||||||||
December 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
(in thousands, except percentages) | |||||||||||||||||
LINN credit facility (1) | $ | 1,795,000 | $ | 1,560,000 | |||||||||||||
Berry credit facility (2) | 1,173,175 | 1,173,175 | |||||||||||||||
Term loan (3) | 500,000 | 500,000 | |||||||||||||||
10.25% Berry senior notes due June 2014 | — | 205,257 | |||||||||||||||
6.50% senior notes due May 2019 (4) | 1,200,000 | 750,000 | |||||||||||||||
6.25% senior notes due November 2019 | 1,800,000 | 1,800,000 | |||||||||||||||
8.625% senior notes due April 2020 | 1,300,000 | 1,300,000 | |||||||||||||||
6.75% Berry senior notes due November 2020 | 299,970 | 300,000 | |||||||||||||||
7.75% senior notes due February 2021 | 1,000,000 | 1,000,000 | |||||||||||||||
6.50% senior notes due September 2021 (4) | 650,000 | — | |||||||||||||||
6.375% Berry senior notes due September 2022 | 599,163 | 600,000 | |||||||||||||||
Net unamortized discounts and premiums | (21,499 | ) | (18,216 | ) | |||||||||||||
Total debt, net | 10,295,809 | 9,170,216 | |||||||||||||||
Less current maturities | — | (211,558 | ) | ||||||||||||||
Total long-term debt, net | $ | 10,295,809 | $ | 8,958,658 | |||||||||||||
(1) | Variable interest rate of 1.92% at both December 31, 2014, and December 31, 2013. | ||||||||||||||||
(2) | Variable interest rate of 2.67% at both December 31, 2014, and December 31, 2013. | ||||||||||||||||
(3) | Variable interest rates of 2.66% and 2.67% at December 31, 2014 and December 31, 2013, respectively. | ||||||||||||||||
(4) | $450 million of senior notes due May 2019 and $650 million of senior notes due September 2021 were issued on September 9, 2014. | ||||||||||||||||
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block] | |||||||||||||||||
December 31, 2014 | December 31, 2013 | ||||||||||||||||
Carrying | Fair Value | Carrying | Fair Value | ||||||||||||||
Value | Value | ||||||||||||||||
(in thousands) | |||||||||||||||||
Credit facilities | $ | 2,968,175 | $ | 2,968,175 | $ | 2,733,175 | $ | 2,733,175 | |||||||||
Term loan | 500,000 | 500,000 | 500,000 | 500,000 | |||||||||||||
Senior notes, net | 6,827,634 | 5,703,649 | 5,937,041 | 6,162,402 | |||||||||||||
Total debt, net | $ | 10,295,809 | $ | 9,171,824 | $ | 9,170,216 | $ | 9,395,577 | |||||||||
Derivatives_Tables
Derivatives (Tables) | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||||||||||||||||
Schedule of Derivative Instruments | The following table summarizes derivative positions for the periods indicated as of December 31, 2014: | |||||||||||||||
2015 | 2016 | 2017 | 2018 | |||||||||||||
Natural gas positions: | ||||||||||||||||
Fixed price swaps (NYMEX Henry Hub): | ||||||||||||||||
Hedged volume (MMMBtu) | 118,041 | 121,841 | 120,122 | 36,500 | ||||||||||||
Average price ($/MMBtu) | $ | 5.19 | $ | 4.2 | $ | 4.26 | $ | 5 | ||||||||
Put options (NYMEX Henry Hub): | ||||||||||||||||
Hedged volume (MMMBtu) | 71,854 | 76,269 | 66,886 | — | ||||||||||||
Average price ($/MMBtu) | $ | 5 | $ | 5 | $ | 4.88 | $ | — | ||||||||
Oil positions: | ||||||||||||||||
Fixed price swaps (NYMEX WTI): (1) | ||||||||||||||||
Hedged volume (MBbls) | 11,599 | 11,465 | 4,755 | — | ||||||||||||
Average price ($/Bbl) | $ | 96.23 | $ | 90.56 | $ | 89.02 | $ | — | ||||||||
Three-way collars (NYMEX WTI): | ||||||||||||||||
Hedged volume (MBbls) | 1,095 | — | — | — | ||||||||||||
Short put ($/Bbl) | $ | 70 | $ | — | $ | — | $ | — | ||||||||
Long put ($/Bbl) | $ | 90 | $ | — | $ | — | $ | — | ||||||||
Short call ($/Bbl) | $ | 101.62 | $ | — | $ | — | $ | — | ||||||||
Put options (NYMEX WTI): | ||||||||||||||||
Hedged volume (MBbls) | 3,426 | 3,271 | 384 | — | ||||||||||||
Average price ($/Bbl) | $ | 90 | $ | 90 | $ | 90 | $ | — | ||||||||
Natural gas basis differential positions: (2) | ||||||||||||||||
Panhandle basis swaps: | ||||||||||||||||
Hedged volume (MMMBtu) | 87,162 | 59,954 | 59,138 | 16,425 | ||||||||||||
Hedged differential ($/MMBtu) | $ | (0.33 | ) | $ | (0.32 | ) | $ | (0.33 | ) | $ | (0.33 | ) | ||||
NWPL Rockies basis swaps: | ||||||||||||||||
Hedged volume (MMMBtu) | 43,292 | 46,294 | 38,880 | 10,804 | ||||||||||||
Hedged differential ($/MMBtu) | $ | (0.20 | ) | $ | (0.20 | ) | $ | (0.19 | ) | $ | (0.19 | ) | ||||
MichCon basis swaps: | ||||||||||||||||
Hedged volume (MMMBtu) | 9,344 | 7,768 | 7,437 | 2,044 | ||||||||||||
Hedged differential ($/MMBtu) | $ | 0.06 | $ | 0.05 | $ | 0.05 | $ | 0.05 | ||||||||
Houston Ship Channel basis swaps: | ||||||||||||||||
Hedged volume (MMMBtu) | 4,891 | 4,575 | 3,604 | 986 | ||||||||||||
Hedged differential ($/MMBtu) | $ | (0.10 | ) | $ | (0.10 | ) | $ | (0.08 | ) | $ | (0.08 | ) | ||||
Permian basis swaps: | ||||||||||||||||
Hedged volume (MMMBtu) | 5,074 | 4,219 | 4,819 | 1,314 | ||||||||||||
Hedged differential ($/MMBtu) | $ | (0.21 | ) | $ | (0.20 | ) | $ | (0.20 | ) | $ | (0.20 | ) | ||||
Oil timing differential positions: | ||||||||||||||||
Trade month roll swaps (NYMEX WTI): (3) | ||||||||||||||||
Hedged volume (MBbls) | 7,251 | 7,446 | 6,486 | — | ||||||||||||
Hedged differential ($/Bbl) | $ | 0.24 | $ | 0.25 | $ | 0.25 | $ | — | ||||||||
(1) | Includes certain outstanding fixed price oil swaps of approximately 5,384 MBbls which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2017, and December 31, 2018, and $90.00 per Bbl for the year ending December 31, 2019, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years. | |||||||||||||||
(2) | Settle on the respective pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price. | |||||||||||||||
(3) | The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX WTI price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”). | |||||||||||||||
Fair Value of Derivatives Outstanding on a Gross Basis by Location on the Balance Sheet | The following summarizes the fair value of derivatives outstanding on a gross basis: | |||||||||||||||
December 31, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Commodity derivatives | $ | 2,014,815 | $ | 1,048,212 | ||||||||||||
Liabilities: | ||||||||||||||||
Commodity derivatives | $ | 90,260 | $ | 222,905 | ||||||||||||
Fair_Value_Measurements_on_a_R1
Fair Value Measurements on a Recurring Basis (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||
Fair Value Measurements on a Recurring Basis | The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis: | ||||||||||||
December 31, 2014 | |||||||||||||
Level 2 | Netting (1) | Total | |||||||||||
(in thousands) | |||||||||||||
Assets: | |||||||||||||
Commodity derivatives | $ | 2,014,815 | $ | (89,576 | ) | $ | 1,925,239 | ||||||
Liabilities: | |||||||||||||
Commodity derivatives | $ | 90,260 | $ | (89,576 | ) | $ | 684 | ||||||
December 31, 2013 | |||||||||||||
Level 2 | Netting (1) | Total | |||||||||||
(in thousands) | |||||||||||||
Assets: | |||||||||||||
Commodity derivatives | $ | 1,048,212 | $ | (190,080 | ) | $ | 858,132 | ||||||
Liabilities: | |||||||||||||
Commodity derivatives | $ | 222,905 | $ | (190,080 | ) | $ | 32,825 | ||||||
(1) | Represents counterparty netting under agreements governing such derivatives. |
Other_Property_and_Equipment_T
Other Property and Equipment (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Property, Plant and Equipment [Abstract] | |||||||||
Other Property and Equipment | Other property and equipment consists of the following: | ||||||||
December 31, | |||||||||
2014 | 2013 | ||||||||
(in thousands) | |||||||||
Natural gas plant and pipeline | $ | 479,754 | $ | 507,342 | |||||
Buildings and leasehold improvements | 49,046 | 32,658 | |||||||
Vehicles | 36,534 | 27,964 | |||||||
Drilling and other equipment | 6,994 | 8,618 | |||||||
Furniture and office equipment | 88,893 | 65,909 | |||||||
Land | 7,928 | 5,391 | |||||||
669,149 | 647,882 | ||||||||
Less accumulated depreciation | (144,282 | ) | (110,939 | ) | |||||
$ | 524,867 | $ | 536,943 | ||||||
Asset_Retirement_Obligations_T
Asset Retirement Obligations (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Asset Retirement Obligation Disclosure [Abstract] | |||||||||
Asset Retirement Obligations Reconciliation | The following presents a reconciliation of the Company’s asset retirement obligations: | ||||||||
December 31, | |||||||||
2014 | 2013 | ||||||||
(in thousands) | |||||||||
Asset retirement obligations at beginning of year | $ | 289,321 | $ | 151,974 | |||||
Liabilities added from acquisitions | 176,538 | 98,343 | |||||||
Liabilities added from drilling | 10,476 | 4,048 | |||||||
Liabilities associated with assets divested | (25,656 | ) | (1,092 | ) | |||||
Current year accretion expense | 22,164 | 11,938 | |||||||
Settlements | (12,620 | ) | (5,136 | ) | |||||
Revision of estimates | 37,347 | 29,246 | |||||||
Asset retirement obligations at end of year | $ | 497,570 | $ | 289,321 | |||||
Earnings_Per_Unit_Tables
Earnings Per Unit (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Earnings Per Share [Abstract] | |||||||||||||
Schedule of Earnings Per Share Reconciliation | The following table provides a reconciliation of the numerators and denominators of the basic and diluted per unit computations for net loss: | ||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(in thousands, except per unit data) | |||||||||||||
Net loss | $ | (451,809 | ) | $ | (691,337 | ) | $ | (386,616 | ) | ||||
Allocated to participating securities | (7,117 | ) | (5,935 | ) | (4,575 | ) | |||||||
$ | (458,926 | ) | $ | (697,272 | ) | $ | (391,191 | ) | |||||
Basic net loss per unit | $ | (1.40 | ) | $ | (2.94 | ) | $ | (1.92 | ) | ||||
Diluted net loss per unit | $ | (1.40 | ) | $ | (2.94 | ) | $ | (1.92 | ) | ||||
Basic weighted average units outstanding | 328,918 | 237,544 | 203,775 | ||||||||||
Dilutive effect of unit equivalents | — | — | — | ||||||||||
Diluted weighted average units outstanding | 328,918 | 237,544 | 203,775 | ||||||||||
Operating_Leases_Tables
Operating Leases (Tables) | 12 Months Ended | |||
Dec. 31, 2014 | ||||
Leases, Operating [Abstract] | ||||
Future Minimum Lease Payments | As of December 31, 2014, future minimum lease payments were as follows (in thousands): | |||
2015 | $ | 13,265 | ||
2016 | 10,288 | |||
2017 | 8,215 | |||
2018 | 7,130 | |||
2019 | 6,492 | |||
Thereafter | 1,046 | |||
$ | 46,436 | |||
Income_Taxes_Tables
Income Taxes (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Income Tax Disclosure [Abstract] | |||||||||||||
Components of income tax expense (benefit) | Certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. Income tax expense (benefit) consisted of the following: | ||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(in thousands) | |||||||||||||
Current taxes: | |||||||||||||
Federal | $ | 473 | $ | 144 | $ | 2,711 | |||||||
State | 21 | 198 | 439 | ||||||||||
Deferred taxes: | |||||||||||||
Federal | (104 | ) | (2,805 | ) | 323 | ||||||||
State | 4,047 | 264 | (683 | ) | |||||||||
$ | 4,437 | $ | (2,199 | ) | $ | 2,790 | |||||||
Effective income tax rate reconciliation | A reconciliation of the federal statutory tax rate to the effective tax rate is as follows: | ||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Federal statutory rate | 35 | % | 35 | % | 35 | % | |||||||
State, net of federal tax benefit | (0.9 | ) | (0.1 | ) | 0.1 | ||||||||
Loss excluded from nontaxable entities | (34.6 | ) | (34.6 | ) | (35.6 | ) | |||||||
Other items | (0.5 | ) | — | (0.2 | ) | ||||||||
Effective rate | (1.0 | )% | 0.3 | % | (0.7 | )% | |||||||
Significant components of the deferred tax assets and liabilities | Significant components of the deferred tax assets and liabilities were as follows: | ||||||||||||
December 31, | |||||||||||||
2014 | 2013 | ||||||||||||
(in thousands) | |||||||||||||
Deferred tax assets: | |||||||||||||
Net operating loss carryforwards | $ | — | $ | 1,129 | |||||||||
Unit-based compensation | 22,105 | 21,965 | |||||||||||
Other | 6,857 | 7,759 | |||||||||||
Total deferred tax assets | 28,962 | 30,853 | |||||||||||
Deferred tax liabilities: | |||||||||||||
Property and equipment principally due to differences in depreciation | (10,991 | ) | (12,525 | ) | |||||||||
Other | (6,370 | ) | (1,509 | ) | |||||||||
Total deferred tax liabilities | (17,361 | ) | (14,034 | ) | |||||||||
Net deferred tax assets | $ | 11,601 | $ | 16,819 | |||||||||
Classification of net deferred tax assets and liabilities in consolidated balance sheets | Net deferred tax assets and liabilities were classified on the consolidated balance sheets as follows: | ||||||||||||
December 31, | |||||||||||||
2014 | 2013 | ||||||||||||
(in thousands) | |||||||||||||
Deferred tax assets | $ | 28,442 | $ | 29,204 | |||||||||
Deferred tax liabilities | (2,964 | ) | (10 | ) | |||||||||
Other current assets | $ | 25,478 | $ | 29,194 | |||||||||
Deferred tax assets | $ | 520 | $ | 1,649 | |||||||||
Deferred tax liabilities | (14,397 | ) | (14,024 | ) | |||||||||
Other noncurrent liabilities | $ | (13,877 | ) | $ | (12,375 | ) |
Supplemental_Disclosures_to_th1
Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Balance Sheet and Cash Flow Supplemental Disclosures [Abstract] | |||||||||||||
Other Accrued Liabilities | “Other accrued liabilities” reported on the consolidated balance sheets include the following: | ||||||||||||
December 31, | |||||||||||||
2014 | 2013 | ||||||||||||
(in thousands) | |||||||||||||
Accrued interest | $ | 105,310 | $ | 93,998 | |||||||||
Accrued compensation | 44,875 | 55,257 | |||||||||||
Asset retirement obligations | 16,187 | 12,616 | |||||||||||
Other | 1,364 | 1,504 | |||||||||||
$ | 167,736 | $ | 163,375 | ||||||||||
Supplemental Cash Flow Disclosures | Supplemental disclosures to the consolidated statements of cash flows are presented below: | ||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(in thousands) | |||||||||||||
Cash payments for interest, net of amounts capitalized | $ | 542,775 | $ | 392,607 | $ | 343,331 | |||||||
Cash payments for income taxes | $ | — | $ | 14 | $ | 366 | |||||||
Noncash investing and financing activities: | |||||||||||||
In connection with the acquisition of oil and natural gas properties and joint-venture funding, assets were acquired and liabilities were assumed as follow: | |||||||||||||
Fair value of assets acquired | $ | 2,679,547 | $ | 5,726,681 | $ | 2,923,990 | |||||||
Cash paid, net of cash acquired | (2,395,339 | ) | (109,350 | ) | (2,640,475 | ) | |||||||
Units issued in connection with the Berry acquisition | — | (2,781,888 | ) | — | |||||||||
Noncash gains on exchanges of properties | (85,493 | ) | — | — | |||||||||
Receivables from sellers | 16,213 | (93 | ) | 2,132 | |||||||||
Payables to sellers | (3,515 | ) | (6,854 | ) | 443 | ||||||||
Liabilities assumed | $ | 211,413 | $ | 2,828,496 | $ | 286,090 | |||||||
Accrued capital expenditures | $ | 240,331 | $ | 334,542 | $ | 203,229 | |||||||
Subsidiary_Guarantors_Tables
Subsidiary Guarantors (Tables) | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | ||||||||||||||||||||
Condensed Consolidating Balance Sheets | CONDENSED CONSOLIDATING BALANCE SHEETS | |||||||||||||||||||
31-Dec-14 | ||||||||||||||||||||
LINN Energy, LLC | Guarantor Subsidiaries | Non- | Eliminations | Consolidated | ||||||||||||||||
Guarantor Subsidiary | ||||||||||||||||||||
(in thousands) | ||||||||||||||||||||
ASSETS | ||||||||||||||||||||
Current assets: | ||||||||||||||||||||
Cash and cash equivalents | $ | 38 | $ | 185 | $ | 1,586 | $ | — | $ | 1,809 | ||||||||||
Accounts receivable – trade, net | — | 371,325 | 100,359 | — | 471,684 | |||||||||||||||
Accounts receivable – affiliates | 4,028,890 | 13,205 | — | (4,042,095 | ) | — | ||||||||||||||
Derivative instruments | — | 1,033,448 | 43,694 | — | 1,077,142 | |||||||||||||||
Other current assets | 18 | 96,678 | 59,259 | — | 155,955 | |||||||||||||||
Total current assets | 4,028,946 | 1,514,841 | 204,898 | (4,042,095 | ) | 1,706,590 | ||||||||||||||
Noncurrent assets: | ||||||||||||||||||||
Oil and natural gas properties (successful efforts method) | — | 13,196,841 | 4,872,059 | — | 18,068,900 | |||||||||||||||
Less accumulated depletion and amortization | — | (4,342,675 | ) | (525,007 | ) | — | (4,867,682 | ) | ||||||||||||
— | 8,854,166 | 4,347,052 | — | 13,201,218 | ||||||||||||||||
Other property and equipment | — | 553,150 | 115,999 | — | 669,149 | |||||||||||||||
Less accumulated depreciation | — | (135,830 | ) | (8,452 | ) | — | (144,282 | ) | ||||||||||||
— | 417,320 | 107,547 | — | 524,867 | ||||||||||||||||
Derivative instruments | — | 848,097 | — | — | 848,097 | |||||||||||||||
Notes receivable – affiliates | 130,500 | — | — | (130,500 | ) | — | ||||||||||||||
Advance to affiliate | — | — | 293,627 | (293,627 | ) | — | ||||||||||||||
Investments in consolidated subsidiaries | 8,562,608 | — | — | (8,562,608 | ) | — | ||||||||||||||
Other noncurrent assets | 116,637 | 11,816 | 14,284 | — | 142,737 | |||||||||||||||
8,809,745 | 859,913 | 307,911 | (8,986,735 | ) | 990,834 | |||||||||||||||
Total noncurrent assets | 8,809,745 | 10,131,399 | 4,762,510 | (8,986,735 | ) | 14,716,919 | ||||||||||||||
Total assets | $ | 12,838,691 | $ | 11,646,240 | $ | 4,967,408 | $ | (13,028,830 | ) | $ | 16,423,509 | |||||||||
LIABILITIES AND UNITHOLDERS’ CAPITAL | ||||||||||||||||||||
Current liabilities: | ||||||||||||||||||||
Accounts payable and accrued expenses | $ | 3,784 | $ | 581,880 | $ | 229,145 | $ | — | $ | 814,809 | ||||||||||
Accounts payable – affiliates | — | 4,028,890 | 13,205 | (4,042,095 | ) | — | ||||||||||||||
Advance from affiliate | — | 293,627 | — | (293,627 | ) | — | ||||||||||||||
Derivative instruments | — | — | — | — | — | |||||||||||||||
Other accrued liabilities | 89,507 | 59,142 | 19,087 | — | 167,736 | |||||||||||||||
Total current liabilities | 93,291 | 4,963,539 | 261,437 | (4,335,722 | ) | 982,545 | ||||||||||||||
Noncurrent liabilities: | ||||||||||||||||||||
Credit facilities | 1,795,000 | — | 1,173,175 | — | 2,968,175 | |||||||||||||||
Term loan | 500,000 | — | — | — | 500,000 | |||||||||||||||
Senior notes, net | 5,913,857 | — | 913,777 | — | 6,827,634 | |||||||||||||||
Notes payable – affiliates | — | 130,500 | — | (130,500 | ) | — | ||||||||||||||
Derivative instruments | — | 684 | — | — | 684 | |||||||||||||||
Other noncurrent liabilities | — | 400,851 | 200,015 | — | 600,866 | |||||||||||||||
Total noncurrent liabilities | 8,208,857 | 532,035 | 2,286,967 | (130,500 | ) | 10,897,359 | ||||||||||||||
Unitholders’ capital: | ||||||||||||||||||||
Units issued and outstanding | 5,388,749 | 4,831,339 | 2,416,381 | (7,240,658 | ) | 5,395,811 | ||||||||||||||
Accumulated income (deficit) | (852,206 | ) | 1,319,327 | 2,623 | (1,321,950 | ) | (852,206 | ) | ||||||||||||
4,536,543 | 6,150,666 | 2,419,004 | (8,562,608 | ) | 4,543,605 | |||||||||||||||
Total liabilities and unitholders’ capital | $ | 12,838,691 | $ | 11,646,240 | $ | 4,967,408 | $ | (13,028,830 | ) | $ | 16,423,509 | |||||||||
CONDENSED CONSOLIDATING BALANCE SHEETS | ||||||||||||||||||||
31-Dec-13 | ||||||||||||||||||||
LINN Energy, LLC | Guarantor Subsidiaries | Non- | Eliminations | Consolidated | ||||||||||||||||
Guarantor Subsidiary | ||||||||||||||||||||
(in thousands) | ||||||||||||||||||||
ASSETS | ||||||||||||||||||||
Current assets: | ||||||||||||||||||||
Cash and cash equivalents | $ | 52 | $ | 1,078 | $ | 51,041 | $ | — | $ | 52,171 | ||||||||||
Accounts receivable – trade, net | — | 365,347 | 122,855 | — | 488,202 | |||||||||||||||
Accounts receivable – affiliates | 4,212,348 | 16,950 | — | (4,229,298 | ) | — | ||||||||||||||
Derivative instruments | — | 170,534 | 5,596 | — | 176,130 | |||||||||||||||
Other current assets | 330 | 68,274 | 30,833 | — | 99,437 | |||||||||||||||
Total current assets | 4,212,730 | 622,183 | 210,325 | (4,229,298 | ) | 815,940 | ||||||||||||||
Noncurrent assets: | ||||||||||||||||||||
Oil and natural gas properties (successful efforts method) | — | 13,074,900 | 4,813,659 | — | 17,888,559 | |||||||||||||||
Less accumulated depletion and amortization | — | (3,535,890 | ) | (10,394 | ) | — | (3,546,284 | ) | ||||||||||||
— | 9,539,010 | 4,803,265 | — | 14,342,275 | ||||||||||||||||
Other property and equipment | — | 564,756 | 83,126 | — | 647,882 | |||||||||||||||
Less accumulated depreciation | — | (110,706 | ) | (233 | ) | — | (110,939 | ) | ||||||||||||
— | 454,050 | 82,893 | — | 536,943 | ||||||||||||||||
Derivative instruments | — | 679,491 | 2,511 | — | 682,002 | |||||||||||||||
Notes receivable – affiliates | 86,200 | — | — | (86,200 | ) | — | ||||||||||||||
Investments in consolidated subsidiaries | 8,433,290 | — | — | (8,433,290 | ) | — | ||||||||||||||
Other noncurrent assets | 108,785 | 10,968 | 8,051 | — | 127,804 | |||||||||||||||
8,628,275 | 690,459 | 10,562 | (8,519,490 | ) | 809,806 | |||||||||||||||
Total noncurrent assets | 8,628,275 | 10,683,519 | 4,896,720 | (8,519,490 | ) | 15,689,024 | ||||||||||||||
Total assets | $ | 12,841,005 | $ | 11,305,702 | $ | 5,107,045 | $ | (12,748,788 | ) | $ | 16,504,964 | |||||||||
LIABILITIES AND UNITHOLDERS’ CAPITAL | ||||||||||||||||||||
Current liabilities: | ||||||||||||||||||||
Accounts payable and accrued expenses | $ | 14,529 | $ | 587,774 | $ | 247,321 | $ | — | $ | 849,624 | ||||||||||
Accounts payable – affiliates | — | 4,212,348 | 16,950 | (4,229,298 | ) | — | ||||||||||||||
Derivative instruments | — | 7,783 | 20,393 | — | 28,176 | |||||||||||||||
Other accrued liabilities | 75,071 | 59,311 | 28,993 | — | 163,375 | |||||||||||||||
Current portion of long-term debt | — | — | 211,558 | — | 211,558 | |||||||||||||||
Total current liabilities | 89,600 | 4,867,216 | 525,215 | (4,229,298 | ) | 1,252,733 | ||||||||||||||
Noncurrent liabilities: | ||||||||||||||||||||
Credit facilities | 1,560,000 | — | 1,173,175 | — | 2,733,175 | |||||||||||||||
Term loan | 500,000 | — | — | — | 500,000 | |||||||||||||||
Senior notes, net | 4,809,055 | — | 916,428 | — | 5,725,483 | |||||||||||||||
Notes payable – affiliates | — | 86,200 | — | (86,200 | ) | — | ||||||||||||||
Derivative instruments | — | — | 4,649 | — | 4,649 | |||||||||||||||
Other noncurrent liabilities | — | 205,406 | 192,091 | — | 397,497 | |||||||||||||||
Total noncurrent liabilities | 6,869,055 | 291,606 | 2,286,343 | (86,200 | ) | 9,360,804 | ||||||||||||||
Unitholders’ capital: | ||||||||||||||||||||
Units issued and outstanding | 6,282,747 | 4,833,354 | 2,315,460 | (7,139,737 | ) | 6,291,824 | ||||||||||||||
Accumulated income (deficit) | (400,397 | ) | 1,313,526 | (19,973 | ) | (1,293,553 | ) | (400,397 | ) | |||||||||||
5,882,350 | 6,146,880 | 2,295,487 | (8,433,290 | ) | 5,891,427 | |||||||||||||||
Total liabilities and unitholders’ capital | $ | 12,841,005 | $ | 11,305,702 | $ | 5,107,045 | $ | (12,748,788 | ) | $ | 16,504,964 | |||||||||
Condensed Consolidating Statements of Operations | CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS | |||||||||||||||||||
For the Year Ended December 31, 2014 | ||||||||||||||||||||
LINN Energy, LLC | Guarantor Subsidiaries | Non- | Eliminations | Consolidated | ||||||||||||||||
Guarantor Subsidiary | ||||||||||||||||||||
(in thousands) | ||||||||||||||||||||
Revenues and other: | ||||||||||||||||||||
Oil, natural gas and natural gas liquids sales | $ | — | $ | 2,312,137 | $ | 1,298,402 | $ | — | $ | 3,610,539 | ||||||||||
Gains on oil and natural gas derivatives | — | 1,127,395 | 78,784 | — | 1,206,179 | |||||||||||||||
Marketing revenues | — | 84,349 | 50,911 | — | 135,260 | |||||||||||||||
Other revenues | — | 28,133 | 3,192 | — | 31,325 | |||||||||||||||
— | 3,552,014 | 1,431,289 | — | 4,983,303 | ||||||||||||||||
Expenses: | ||||||||||||||||||||
Lease operating expenses | — | 440,624 | 364,540 | — | 805,164 | |||||||||||||||
Transportation expenses | — | 165,489 | 41,842 | — | 207,331 | |||||||||||||||
Marketing expenses | — | 81,210 | 36,255 | — | 117,465 | |||||||||||||||
General and administrative expenses | — | 190,286 | 102,787 | — | 293,073 | |||||||||||||||
Exploration costs | — | 125,037 | — | — | 125,037 | |||||||||||||||
Depreciation, depletion and amortization | — | 771,549 | 302,353 | — | 1,073,902 | |||||||||||||||
Impairment of long-lived assets | — | 2,050,387 | 253,362 | — | 2,303,749 | |||||||||||||||
Taxes, other than income taxes | 40 | 169,655 | 97,708 | — | 267,403 | |||||||||||||||
(Gains) losses on sale of assets and other, net | — | (487,286 | ) | 120,786 | — | (366,500 | ) | |||||||||||||
40 | 3,506,951 | 1,319,633 | — | 4,826,624 | ||||||||||||||||
Other income and (expenses): | ||||||||||||||||||||
Interest expense, net of amounts capitalized | (480,259 | ) | (19,631 | ) | (87,948 | ) | — | (587,838 | ) | |||||||||||
Interest expense – affiliates | — | (7,954 | ) | — | 7,954 | — | ||||||||||||||
Interest income – affiliates | 7,954 | — | — | (7,954 | ) | — | ||||||||||||||
Equity in earnings from consolidated subsidiaries | 28,397 | — | — | (28,397 | ) | — | ||||||||||||||
Other, net | (7,861 | ) | (7,309 | ) | (1,043 | ) | — | (16,213 | ) | |||||||||||
(451,769 | ) | (34,894 | ) | (88,991 | ) | (28,397 | ) | (604,051 | ) | |||||||||||
Income (loss) before income taxes | (451,809 | ) | 10,169 | 22,665 | (28,397 | ) | (447,372 | ) | ||||||||||||
Income tax expense | — | 4,368 | 69 | — | 4,437 | |||||||||||||||
Net income (loss) | $ | (451,809 | ) | $ | 5,801 | $ | 22,596 | $ | (28,397 | ) | $ | (451,809 | ) | |||||||
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS | ||||||||||||||||||||
For the Year Ended December 31, 2013 | ||||||||||||||||||||
LINN Energy, LLC | Guarantor Subsidiaries | Non- | Eliminations | Consolidated | ||||||||||||||||
Guarantor Subsidiary | ||||||||||||||||||||
(in thousands) | ||||||||||||||||||||
Revenues and other: | ||||||||||||||||||||
Oil, natural gas and natural gas liquids sales | $ | — | $ | 2,022,916 | $ | 50,324 | $ | — | $ | 2,073,240 | ||||||||||
Gains (losses) on oil and natural gas derivatives | — | 182,906 | (5,049 | ) | — | 177,857 | ||||||||||||||
Marketing revenues | — | 52,328 | 1,843 | — | 54,171 | |||||||||||||||
Other revenues | — | 26,387 | — | — | 26,387 | |||||||||||||||
— | 2,284,537 | 47,118 | — | 2,331,655 | ||||||||||||||||
Expenses: | ||||||||||||||||||||
Lease operating expenses | — | 357,113 | 15,410 | — | 372,523 | |||||||||||||||
Transportation expenses | — | 125,864 | 2,576 | — | 128,440 | |||||||||||||||
Marketing expenses | — | 36,259 | 1,633 | — | 37,892 | |||||||||||||||
General and administrative expenses | — | 215,973 | 20,298 | — | 236,271 | |||||||||||||||
Exploration costs | — | 5,251 | — | — | 5,251 | |||||||||||||||
Depreciation, depletion and amortization | — | 818,466 | 10,845 | — | 829,311 | |||||||||||||||
Impairment of long-lived assets | — | 828,317 | — | — | 828,317 | |||||||||||||||
Taxes, other than income taxes | — | 136,501 | 2,130 | — | 138,631 | |||||||||||||||
Losses on sale of assets and other, net | 724 | 2,705 | 10,208 | — | 13,637 | |||||||||||||||
724 | 2,526,449 | 63,100 | — | 2,590,273 | ||||||||||||||||
Other income and (expenses): | ||||||||||||||||||||
Interest expense, net of amounts capitalized | (415,670 | ) | (1,504 | ) | (3,963 | ) | — | (421,137 | ) | |||||||||||
Interest expense – affiliates | — | (5,543 | ) | — | 5,543 | — | ||||||||||||||
Interest income – affiliates | 5,543 | — | — | (5,543 | ) | — | ||||||||||||||
Loss on extinguishment of debt | (5,304 | ) | — | — | — | (5,304 | ) | |||||||||||||
Equity in losses from consolidated subsidiaries | (266,899 | ) | — | — | 266,899 | — | ||||||||||||||
Other, net | (8,283 | ) | (166 | ) | (28 | ) | — | (8,477 | ) | |||||||||||
(690,613 | ) | (7,213 | ) | (3,991 | ) | 266,899 | (434,918 | ) | ||||||||||||
Loss before income taxes | (691,337 | ) | (249,125 | ) | (19,973 | ) | 266,899 | (693,536 | ) | |||||||||||
Income tax benefit | — | (2,199 | ) | — | — | (2,199 | ) | |||||||||||||
Net loss | $ | (691,337 | ) | $ | (246,926 | ) | $ | (19,973 | ) | $ | 266,899 | $ | (691,337 | ) | ||||||
Condensed Consolidating Statements of Cash Flow | CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS | |||||||||||||||||||
For the Year Ended December 31, 2014 | ||||||||||||||||||||
LINN Energy, LLC | Guarantor Subsidiaries | Non- | Eliminations | Consolidated | ||||||||||||||||
Guarantor Subsidiary | ||||||||||||||||||||
(in thousands) | ||||||||||||||||||||
Cash flow from operating activities: | ||||||||||||||||||||
Net income (loss) | $ | (451,809 | ) | $ | 5,801 | $ | 22,596 | $ | (28,397 | ) | $ | (451,809 | ) | |||||||
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | ||||||||||||||||||||
Depreciation, depletion and amortization | — | 771,549 | 302,353 | — | 1,073,902 | |||||||||||||||
Impairment of long-lived assets | — | 2,050,387 | 253,362 | — | 2,303,749 | |||||||||||||||
Unit-based compensation expenses | — | 53,284 | — | — | 53,284 | |||||||||||||||
Amortization and write-off of deferred financing fees | 38,785 | 17,054 | (4,913 | ) | — | 50,926 | ||||||||||||||
(Gains) losses on sale of assets and other, net | — | (372,945 | ) | 111,374 | — | (261,571 | ) | |||||||||||||
Equity in earnings from consolidated subsidiaries | (28,397 | ) | — | — | 28,397 | — | ||||||||||||||
Deferred income tax | — | 3,874 | 69 | — | 3,943 | |||||||||||||||
Derivatives activities: | ||||||||||||||||||||
Total gains | — | (1,127,395 | ) | (78,784 | ) | — | (1,206,179 | ) | ||||||||||||
Cash settlements | — | 88,776 | 6,738 | — | 95,514 | |||||||||||||||
Cash settlements on canceled derivatives | — | — | 12,281 | — | 12,281 | |||||||||||||||
Changes in assets and liabilities: | ||||||||||||||||||||
(Increase) decrease in accounts receivable – trade, net | — | (11,419 | ) | 16,483 | — | 5,064 | ||||||||||||||
Decrease in accounts receivable – affiliates | 257,485 | 16,950 | — | (274,435 | ) | — | ||||||||||||||
(Increase) decrease in other assets | 312 | (2,187 | ) | (15,949 | ) | — | (17,824 | ) | ||||||||||||
Increase in accounts payable and accrued expenses | — | 99,003 | 26 | — | 99,029 | |||||||||||||||
Decrease in accounts payable and accrued expenses – affiliates | — | (270,690 | ) | (3,745 | ) | 274,435 | — | |||||||||||||
Increase (decrease) in other liabilities | 14,465 | (24,473 | ) | (38,411 | ) | — | (48,419 | ) | ||||||||||||
Net cash provided by (used in) operating activities | (169,159 | ) | 1,297,569 | 583,480 | — | 1,711,890 | ||||||||||||||
Cash flow from investing activities: | ||||||||||||||||||||
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired | — | (2,475,315 | ) | (3,937 | ) | — | (2,479,252 | ) | ||||||||||||
Development of oil and natural gas properties | — | (1,061,395 | ) | (508,482 | ) | — | (1,569,877 | ) | ||||||||||||
Purchases of other property and equipment | — | (63,070 | ) | (11,470 | ) | — | (74,540 | ) | ||||||||||||
Investment in affiliates | (100,921 | ) | — | — | 100,921 | — | ||||||||||||||
Change in notes receivable with affiliate | (44,300 | ) | — | — | 44,300 | — | ||||||||||||||
Proceeds from sale of properties and equipment and other | (14,117 | ) | 2,210,015 | 7,667 | — | 2,203,565 | ||||||||||||||
Net cash used in investing activities | (159,338 | ) | (1,389,765 | ) | (516,222 | ) | 145,221 | (1,920,104 | ) | |||||||||||
LINN Energy, LLC | Guarantor Subsidiaries | Non- | Eliminations | Consolidated | ||||||||||||||||
Guarantor Subsidiary | ||||||||||||||||||||
(in thousands) | ||||||||||||||||||||
Cash flow from financing activities: | ||||||||||||||||||||
Proceeds from borrowings | 4,640,024 | 1,300,000 | — | — | 5,940,024 | |||||||||||||||
Repayments of debt | (3,305,000 | ) | (1,300,000 | ) | (206,124 | ) | — | (4,811,124 | ) | |||||||||||
Distributions to unitholders | (962,048 | ) | — | — | — | (962,048 | ) | |||||||||||||
Financing fees and offering expenses | (59,048 | ) | — | (10,646 | ) | — | (69,694 | ) | ||||||||||||
Change in note payable with affiliate | — | 44,300 | — | (44,300 | ) | — | ||||||||||||||
Capital contribution – affiliates | — | — | 100,921 | (100,921 | ) | — | ||||||||||||||
Excess tax benefit from unit-based compensation | 810 | (44 | ) | — | — | 766 | ||||||||||||||
Other | 13,745 | 47,047 | (864 | ) | — | 59,928 | ||||||||||||||
Net cash provided by (used in) financing activities | 328,483 | 91,303 | (116,713 | ) | (145,221 | ) | 157,852 | |||||||||||||
Net decrease in cash and cash equivalents | (14 | ) | (893 | ) | (49,455 | ) | — | (50,362 | ) | |||||||||||
Cash and cash equivalents: | ||||||||||||||||||||
Beginning | 52 | 1,078 | 51,041 | — | 52,171 | |||||||||||||||
Ending | $ | 38 | $ | 185 | $ | 1,586 | $ | — | $ | 1,809 | ||||||||||
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS | ||||||||||||||||||||
For the Year Ended December 31, 2013 | ||||||||||||||||||||
LINN Energy, LLC | Guarantor Subsidiaries | Non- | Eliminations | Consolidated | ||||||||||||||||
Guarantor Subsidiary | ||||||||||||||||||||
(in thousands) | ||||||||||||||||||||
Cash flow from operating activities: | ||||||||||||||||||||
Net loss | $ | (691,337 | ) | $ | (246,926 | ) | $ | (19,973 | ) | $ | 266,899 | $ | (691,337 | ) | ||||||
Adjustments to reconcile net loss to net cash provided by (used in) operating activities: | ||||||||||||||||||||
Depreciation, depletion and amortization | — | 818,466 | 10,845 | — | 829,311 | |||||||||||||||
Impairment of long-lived assets | — | 828,317 | — | — | 828,317 | |||||||||||||||
Unit-based compensation expenses | — | 42,703 | — | — | 42,703 | |||||||||||||||
Loss on extinguishment of debt | 5,304 | — | — | — | 5,304 | |||||||||||||||
Amortization and write-off of deferred financing fees | 22,122 | — | (615 | ) | — | 21,507 | ||||||||||||||
Losses on sale of assets and other, net | — | 37,232 | — | — | 37,232 | |||||||||||||||
Equity in losses from consolidated subsidiaries | 266,899 | — | — | (266,899 | ) | — | ||||||||||||||
Deferred income taxes | — | (2,541 | ) | — | — | (2,541 | ) | |||||||||||||
Derivatives activities: | ||||||||||||||||||||
Total (gains) losses | — | (182,906 | ) | 5,049 | — | (177,857 | ) | |||||||||||||
Cash settlements | — | 248,862 | — | — | 248,862 | |||||||||||||||
Changes in assets and liabilities: | ||||||||||||||||||||
Decrease in accounts receivable – trade, net | — | 17,754 | 71,434 | — | 89,188 | |||||||||||||||
Increase in accounts receivable – affiliates | (120,967 | ) | (16,950 | ) | — | 137,917 | — | |||||||||||||
(Increase) decrease in other assets | (330 | ) | 5,896 | 10,613 | — | 16,179 | ||||||||||||||
Increase (decrease) in accounts payable and accrued expenses | 178 | (52,143 | ) | (25,028 | ) | — | (76,993 | ) | ||||||||||||
Increase in accounts payable and accrued expenses – affiliates | — | 120,967 | 16,950 | (137,917 | ) | — | ||||||||||||||
Increase (decrease) in other liabilities | 2,092 | 6,842 | (12,597 | ) | — | (3,663 | ) | |||||||||||||
Net cash provided by (used in) operating activities | (516,039 | ) | 1,625,573 | 56,678 | — | 1,166,212 | ||||||||||||||
Cash flow from investing activities: | ||||||||||||||||||||
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired | — | (730,326 | ) | 451,113 | — | (279,213 | ) | |||||||||||||
Development of oil and natural gas properties | — | (1,060,547 | ) | (17,478 | ) | — | (1,078,025 | ) | ||||||||||||
Purchases of other property and equipment | — | (92,352 | ) | — | — | (92,352 | ) | |||||||||||||
Investment in affiliates | 435,000 | — | — | (435,000 | ) | — | ||||||||||||||
Change in notes receivable with affiliate | (26,700 | ) | — | — | 26,700 | — | ||||||||||||||
Proceeds from sale of properties and equipment and other | (22,039 | ) | 218,312 | — | — | 196,273 | ||||||||||||||
Net cash provided by (used in) investing activities | 386,261 | (1,664,913 | ) | 433,635 | (408,300 | ) | (1,253,317 | ) | ||||||||||||
LINN Energy, LLC | Guarantor Subsidiaries | Non- | Eliminations | Consolidated | ||||||||||||||||
Guarantor Subsidiary | ||||||||||||||||||||
(in thousands) | ||||||||||||||||||||
Cash flow from financing activities: | ||||||||||||||||||||
Proceeds from borrowings | 2,230,000 | — | — | — | 2,230,000 | |||||||||||||||
Repayments of debt | (1,404,898 | ) | — | — | — | (1,404,898 | ) | |||||||||||||
Distributions to unitholders | (682,241 | ) | — | — | — | (682,241 | ) | |||||||||||||
Financing fees and offering expenses | (16,033 | ) | — | — | — | (16,033 | ) | |||||||||||||
Change in note payable with affiliate | — | 26,700 | — | (26,700 | ) | — | ||||||||||||||
Capital contribution – affiliates | — | — | (435,000 | ) | 435,000 | — | ||||||||||||||
Excess tax benefit from unit-based compensation | — | 160 | — | — | 160 | |||||||||||||||
Other | 2,895 | 12,422 | (4,272 | ) | — | 11,045 | ||||||||||||||
Net cash provided by (used in) financing activities | 129,723 | 39,282 | (439,272 | ) | 408,300 | 138,033 | ||||||||||||||
Net increase (decrease) in cash and cash equivalents | (55 | ) | (58 | ) | 51,041 | — | 50,928 | |||||||||||||
Cash and cash equivalents: | ||||||||||||||||||||
Beginning | 107 | 1,136 | — | — | 1,243 | |||||||||||||||
Ending | $ | 52 | $ | 1,078 | $ | 51,041 | $ | — | $ | 52,171 | ||||||||||
Supplemental_Oil_and_Natural_G1
Supplemental Oil and Natural Gas Data (Unaudited) (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||||||||||||
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development | Costs incurred in oil and natural gas property acquisition, exploration and development, whether capitalized or expensed, are presented below: | ||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(in thousands) | |||||||||||||
Property acquisition costs: (1) | |||||||||||||
Proved | $ | 2,784,852 | $ | 3,740,379 | $ | 2,531,419 | |||||||
Unproved | 788,682 | 1,638,302 | 181,124 | ||||||||||
Exploration costs | 792 | 13,096 | 452 | ||||||||||
Development costs | 1,487,204 | 1,153,770 | 1,062,043 | ||||||||||
Asset retirement costs | 20,919 | 7,351 | 4,675 | ||||||||||
Total costs incurred | $ | 5,082,449 | $ | 6,552,898 | $ | 3,779,713 | |||||||
(1) | See Note 2 for details about the Company’s acquisitions. | ||||||||||||
Capitalized Costs Relating to Oil, Natural Gas and NGL Producing Activities | Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below: | ||||||||||||
December 31, | |||||||||||||
2014 | 2013 | ||||||||||||
(in thousands) | |||||||||||||
Proved properties: | |||||||||||||
Leasehold acquisition | $ | 13,362,642 | $ | 12,277,089 | |||||||||
Development | 2,830,841 | 3,660,277 | |||||||||||
Unproved properties | 1,875,417 | 1,951,193 | |||||||||||
18,068,900 | 17,888,559 | ||||||||||||
Less accumulated depletion and amortization | (4,867,682 | ) | (3,546,284 | ) | |||||||||
$ | 13,201,218 | $ | 14,342,275 | ||||||||||
Results of Operations for Oil and Gas Producing Activities | The results of operations for oil, natural gas and NGL producing activities (excluding corporate overhead and interest costs) are presented below: | ||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(in thousands) | |||||||||||||
Revenues and other: | |||||||||||||
Oil, natural gas and natural gas liquid sales | $ | 3,610,539 | $ | 2,073,240 | $ | 1,601,180 | |||||||
Gains on oil and natural gas derivatives | 1,206,179 | 177,857 | 124,762 | ||||||||||
4,816,718 | 2,251,097 | 1,725,942 | |||||||||||
Production costs: | |||||||||||||
Lease operating expenses | 805,164 | 372,523 | 317,699 | ||||||||||
Transportation expenses | 207,331 | 128,440 | 77,322 | ||||||||||
Severance taxes, ad valorem taxes and California carbon allowances | 267,100 | 139,202 | 130,805 | ||||||||||
1,279,595 | 640,165 | 525,826 | |||||||||||
Other costs: | |||||||||||||
Exploration costs | 125,037 | 5,251 | 1,915 | ||||||||||
Depletion and amortization | 1,020,674 | 790,320 | 579,382 | ||||||||||
Impairment of long-lived assets | 2,303,749 | 828,317 | 422,499 | ||||||||||
Gains on sale of assets and other, net | (388,733 | ) | (138 | ) | (1,369 | ) | |||||||
Texas margin tax expense (benefit) | 4,053 | 458 | (787 | ) | |||||||||
3,064,780 | 1,624,208 | 1,001,640 | |||||||||||
Results of operations | $ | 472,343 | $ | (13,276 | ) | $ | 198,476 | ||||||
There is no federal tax provision included in the results above because the Company’s subsidiaries subject to federal tax do not own any of the Company’s oil and natural gas interests. Limited liability companies are subject to Texas margin tax. See Note 14 for additional information about income taxes. | |||||||||||||
Estimated Quantities of Oil, Natural Gas and NGL Reserves | An analysis of the change in estimated quantities of oil, natural gas and NGL reserves, all of which are located within the U.S., is shown below: | ||||||||||||
Year Ended December 31, 2014 | |||||||||||||
Natural Gas | Oil | NGL | Total | ||||||||||
(Bcf) | (MMBbls) | (MMBbls) | (Bcfe) | ||||||||||
Proved developed and undeveloped reserves: | |||||||||||||
Beginning of year | 3,010 | 365.6 | 200 | 6,403 | |||||||||
Revisions of previous estimates | 96 | (22.3 | ) | (46.8 | ) | (318 | ) | ||||||
Purchases of minerals in place | 1,763 | 50 | 71.9 | 2,495 | |||||||||
Sales of minerals in place | (477 | ) | (51.7 | ) | (49.5 | ) | (1,084 | ) | |||||
Extensions, discoveries and other additions | 72 | 26.8 | 2.9 | 250 | |||||||||
Production | (209 | ) | (26.6 | ) | (12.2 | ) | (442 | ) | |||||
End of year | 4,255 | 341.8 | 166.3 | 7,304 | |||||||||
Proved developed reserves: | |||||||||||||
Beginning of year | 2,027 | 252.4 | 133.2 | 4,340 | |||||||||
End of year | 3,549 | 246 | 132.2 | 5,818 | |||||||||
Proved undeveloped reserves: | |||||||||||||
Beginning of year | 983 | 113.2 | 66.8 | 2,063 | |||||||||
End of year | 706 | 95.8 | 34.1 | 1,486 | |||||||||
Year Ended December 31, 2013 | |||||||||||||
Natural Gas (Bcf) | Oil | NGL (MMBbls) | Total | ||||||||||
(MMBbls) | (Bcfe) | ||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||
Beginning of year | 2,571 | 191.5 | 179.4 | 4,796 | |||||||||
Revisions of previous estimates | (17 | ) | (21.3 | ) | (2.0 | ) | (157 | ) | |||||
Purchases of minerals in place | 356 | 191.1 | 17.8 | 1,610 | |||||||||
Sales of minerals in place | (24 | ) | (5.2 | ) | (2.9 | ) | (73 | ) | |||||
Extensions, discoveries and other additions | 286 | 21.7 | 18.5 | 527 | |||||||||
Production | (162 | ) | (12.2 | ) | (10.8 | ) | (300 | ) | |||||
End of year | 3,010 | 365.6 | 200 | 6,403 | |||||||||
Proved developed reserves: | |||||||||||||
Beginning of year | 1,661 | 131.4 | 113 | 3,127 | |||||||||
End of year | 2,027 | 252.4 | 133.2 | 4,340 | |||||||||
Proved undeveloped reserves: | |||||||||||||
Beginning of year | 910 | 60.1 | 66.4 | 1,669 | |||||||||
End of year | 983 | 113.2 | 66.8 | 2,063 | |||||||||
Year Ended December 31, 2012 | |||||||||||||
Natural Gas (Bcf) | Oil | NGL (MMBbls) | Total | ||||||||||
(MMBbls) | (Bcfe) | ||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||
Beginning of year | 1,675 | 189 | 93.5 | 3,370 | |||||||||
Revisions of previous estimates | (559 | ) | (26.5 | ) | (14.1 | ) | (803 | ) | |||||
Purchases of minerals in place | 1,176 | 23.1 | 75.3 | 1,766 | |||||||||
Extensions, discoveries and other additions | 407 | 16.6 | 33.7 | 709 | |||||||||
Production | (128 | ) | (10.7 | ) | (9.0 | ) | (246 | ) | |||||
End of year | 2,571 | 191.5 | 179.4 | 4,796 | |||||||||
Proved developed reserves: | |||||||||||||
Beginning of year | 998 | 124.8 | 47.8 | 2,034 | |||||||||
End of year | 1,661 | 131.4 | 113 | 3,127 | |||||||||
Proved undeveloped reserves: | |||||||||||||
Beginning of year | 677 | 64.2 | 45.7 | 1,336 | |||||||||
End of year | 910 | 60.1 | 66.4 | 1,669 | |||||||||
The tables above include changes in estimated quantities of oil and NGL reserves shown in Mcf equivalents at a rate of one barrel per six Mcf. | |||||||||||||
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves | Information with respect to the standardized measure of discounted future net cash flows relating to proved reserves is summarized below. Future cash inflows are computed by applying applicable prices relating to the Company’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses because the Company is not subject to federal income taxes. Limited liability companies are subject to Texas margin tax; however, these amounts are not material. See Note 14 for additional information about income taxes. | ||||||||||||
December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(in thousands) | |||||||||||||
Future estimated revenues | $ | 55,195,268 | $ | 51,112,346 | $ | 30,374,380 | |||||||
Future estimated production costs | (24,100,468 | ) | (19,306,728 | ) | (11,460,854 | ) | |||||||
Future estimated development costs | (4,032,588 | ) | (5,110,896 | ) | (3,574,058 | ) | |||||||
Future net cash flows | 27,062,212 | 26,694,722 | 15,339,468 | ||||||||||
10% annual discount for estimated timing of cash flows | (14,549,921 | ) | (14,795,393 | ) | (9,266,487 | ) | |||||||
Standardized measure of discounted future net cash flows | $ | 12,512,291 | $ | 11,899,329 | $ | 6,072,981 | |||||||
Representative NYMEX prices: (1) | |||||||||||||
Natural gas (MMBtu) | $ | 4.35 | $ | 3.67 | $ | 2.76 | |||||||
Oil (Bbl) | $ | 95.27 | $ | 96.89 | $ | 94.64 | |||||||
(1) | In accordance with SEC regulations, reserves at December 31, 2014, December 31, 2013, and December 31, 2012, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves. | ||||||||||||
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow | The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows: | ||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(in thousands) | |||||||||||||
Sales and transfers of oil, natural gas and NGL produced during the period | $ | (2,330,944 | ) | $ | (1,433,075 | ) | $ | (1,075,354 | ) | ||||
Changes in estimated future development costs | 156,614 | 317,064 | 289,762 | ||||||||||
Net change in sales and transfer prices and production costs related to future production | (599,121 | ) | 203,370 | (1,463,820 | ) | ||||||||
Purchases of minerals in place | 3,021,768 | 5,113,335 | 2,153,651 | ||||||||||
Sales of minerals in place | (1,681,504 | ) | (139,384 | ) | — | ||||||||
Extensions, discoveries and improved recovery | 910,787 | 801,254 | 413,702 | ||||||||||
Previously estimated development costs incurred during the period | 819,987 | 444,861 | 442,322 | ||||||||||
Net change due to revisions in quantity estimates | (672,800 | ) | (220,224 | ) | (1,595,302 | ) | |||||||
Accretion of discount | 1,189,933 | 607,298 | 661,486 | ||||||||||
Changes in production rates and other | (201,758 | ) | 131,849 | (368,326 | ) | ||||||||
$ | 612,962 | $ | 5,826,348 | $ | (541,879 | ) | |||||||
Supplemental_Quarterly_Data_Un1
Supplemental Quarterly Data (Unaudited) (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Quarterly Financial Data [Abstract] | |||||||||||||||||
Quarterly financial data | Quarterly Financial Data | ||||||||||||||||
Quarters Ended | |||||||||||||||||
31-Mar | 30-Jun | 30-Sep | December 31 | ||||||||||||||
(in thousands, except per unit amounts) | |||||||||||||||||
2014:00:00 | |||||||||||||||||
Oil, natural gas and natural gas liquid sales | $ | 938,877 | $ | 967,850 | $ | 937,458 | $ | 766,354 | |||||||||
Gains (losses) on oil and natural gas derivatives | (241,493 | ) | (408,788 | ) | 451,702 | 1,404,758 | |||||||||||
Total revenues and other | 733,587 | 596,951 | 1,435,115 | 2,217,650 | |||||||||||||
Total expenses (1) | 674,568 | 664,452 | 1,320,157 | 2,533,947 | |||||||||||||
(Gains) losses on sale of assets and other, net | 2,586 | 5,467 | (35,803 | ) | (338,750 | ) | |||||||||||
Net loss | (85,337 | ) | (207,870 | ) | (4,100 | ) | (154,502 | ) | |||||||||
Net loss per unit: | |||||||||||||||||
Basic | $ | (0.27 | ) | $ | (0.64 | ) | $ | (0.02 | ) | $ | (0.47 | ) | |||||
Diluted | $ | (0.27 | ) | $ | (0.64 | ) | $ | (0.02 | ) | $ | (0.47 | ) | |||||
Quarters Ended | |||||||||||||||||
31-Mar | 30-Jun | 30-Sep | December 31 | ||||||||||||||
(in thousands, except per unit amounts) | |||||||||||||||||
2013:00:00 | |||||||||||||||||
Oil, natural gas and natural gas liquid sales | $ | 462,732 | $ | 488,207 | $ | 537,671 | $ | 584,630 | |||||||||
Gains (losses) on oil and natural gas derivatives | (108,370 | ) | 326,733 | (63,931 | ) | 23,425 | |||||||||||
Total revenues and other | 369,060 | 838,825 | 494,562 | 629,208 | |||||||||||||
Total expenses (1) | 478,235 | 385,540 | 420,803 | 1,292,058 | |||||||||||||
(Gains) losses on sale of assets and other, net | 3,172 | (959 | ) | 827 | 10,597 | ||||||||||||
Net income (loss) | (221,885 | ) | 345,157 | (30,060 | ) | (784,549 | ) | ||||||||||
Net income (loss) per unit: | |||||||||||||||||
Basic | $ | (0.96 | ) | $ | 1.47 | $ | (0.13 | ) | $ | (3.15 | ) | ||||||
Diluted | $ | (0.96 | ) | $ | 1.46 | $ | (0.13 | ) | $ | (3.15 | ) | ||||||
(1) | Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, depreciation, depletion and amortization, impairment of long-lived assets and taxes, other than income taxes. |
Basis_of_Presentation_and_Sign2
Basis of Presentation and Significant Accounting Policies (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2014 | Sep. 30, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||
Allowance for doubtful accounts | $1,000,000 | ||||
Capitalized interest costs | 9,000,000 | 2,000,000 | 2,000,000 | ||
Natural gas production imbalance payables | 13,000,000 | 13,000,000 | 16,000,000 | ||
Restricted cash | 6,000,000 | 6,000,000 | 6,000,000 | ||
Net deferred financing fees | 129,000,000 | 129,000,000 | 114,000,000 | ||
Debt issuance fees amortization expense | 46,000,000 | 18,000,000 | 13,000,000 | ||
Write-off of deferred financing fees | 8,000,000 | 0 | 8,000,000 | ||
Statement [Line Items] | |||||
Gas Balancing Asset (Liability) | 17,000,000 | 17,000,000 | 27,000,000 | ||
Impairment of long-lived assets | 1,700,000,000 | 603,000,000 | 2,303,749,000 | 828,317,000 | 422,499,000 |
Decline in oil prices | 24.00% | ||||
Decline in gas prices | 12.00% | ||||
Impairment Of Unproved Oil And Gas Properties | 125,000,000 | 5,000,000 | 2,000,000 | ||
Minimum [Member] | |||||
Statement [Line Items] | |||||
Useful lives of other property and equipment (in years) | 2 years | ||||
Maximum [Member] | |||||
Statement [Line Items] | |||||
Useful lives of other property and equipment (in years) | 39 years | ||||
Permian Basin [Member] | |||||
Statement [Line Items] | |||||
Impairment of long-lived assets | 735,000,000 | ||||
Rockies [Member] | |||||
Statement [Line Items] | |||||
Impairment of long-lived assets | 586,000,000 | ||||
Mid-Continent [Member] | |||||
Statement [Line Items] | |||||
Impairment of long-lived assets | 244,000,000 | 791,000,000 | |||
South Texas [Member] | |||||
Statement [Line Items] | |||||
Impairment of long-lived assets | 131,000,000 | ||||
TexLa [Member] | |||||
Statement [Line Items] | |||||
Impairment of long-lived assets | $5,000,000 |
Exchanges_of_Properties_Acquis2
Exchanges of Properties, Acquisitions, Divestitures and Joint-Venture Funding (Acquisitions, Joint-Venture Funding) (Details) (USD $) | 12 Months Ended | 0 Months Ended | |||||
Dec. 31, 2014 | Jul. 31, 2012 | 1-May-12 | Apr. 03, 2012 | Mar. 30, 2012 | Dec. 31, 2013 | Oct. 31, 2013 | |
Business Acquisition [Line Items] | |||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net | $2,468,134,000 | ||||||
Term loan | 500,000,000 | 500,000,000 | |||||
Pioneer Assets Acquisition [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Business Combination, Consideration Transferred | 328,000,000 | ||||||
Devon Assets Acquisition [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Business Combination, Consideration Transferred | 2,100,000,000 | ||||||
Business Acquisition, Permian, BC Operating | |||||||
Business Acquisition [Line Items] | |||||||
Term loan | 528,000,000 | ||||||
Business Acquisition Various | |||||||
Business Acquisition [Line Items] | |||||||
Business Combination, Consideration Transferred | 5,000,000 | ||||||
Business Acquisition BP Green River | |||||||
Business Acquisition [Line Items] | |||||||
Business Combination, Consideration Transferred | 988,000,000 | ||||||
Business Acquisition East Texas | |||||||
Business Acquisition [Line Items] | |||||||
Business Combination, Consideration Transferred | 164,000,000 | ||||||
Business Acquisition Anadarko | |||||||
Business Acquisition [Line Items] | |||||||
Joint Venture Interest Acquired | 23.00% | ||||||
Imputed discount on future funding of joint venture | 8,000,000 | ||||||
Future funding commitment of joint venture consideration transferred | 25,000,000 | ||||||
Future Funding Of Joint Venture Agreement | 400,000,000 | ||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net | 392,000,000 | ||||||
Business Acquisition BP | |||||||
Business Acquisition [Line Items] | |||||||
Business Combination, Consideration Transferred | $1,170,000,000 |
Exchanges_of_Properties_Acquis3
Exchanges of Properties, Acquisitions, Divestitures and Joint-Venture Funding Purchase Price (Details) (Business Acquisition, Berry, USD $) | 0 Months Ended | |
Dec. 17, 2013 | Dec. 16, 2013 | |
Business Acquisition [Line Items] | ||
Cash acquired | $451,000,000 | |
Exchange ratio | 168.00% | |
Preliminary value of acquisition | 4,600,000,000 | |
Long-term debt assumed | $2,300,000,000 | |
Linn Energy, LLC | ||
Business Acquisition [Line Items] | ||
LINN Energy units issued to LinnCo for LinnCo common shares issued | 93,756,674 | |
LinnCo | ||
Business Acquisition [Line Items] | ||
LINN Energy units issued to LinnCo for LinnCo common shares issued | 93,756,674 |
Exchanges_of_Properties_Acquis4
Exchanges of Properties, Acquisitions, Divestitures and Joint-Venture Funding (Purchase Price Allocation) (Details) (USD $) | Dec. 31, 2014 |
In Thousands, unless otherwise specified | |
Assets: | |
Current | $26,007 |
Oil and natural gas properties | 2,532,439 |
Other property and equipment | 121,101 |
Total assets acquired | 2,679,547 |
Liabilities: | |
Current | 21,976 |
Asset retirement obligations, current and noncurrent | 171,057 |
Noncurrent | 18,380 |
Total liabilities assumed | 211,413 |
Net assets acquired | $2,468,134 |
Exchanges_of_Properties_Acquis5
Exchanges of Properties, Acquisitions, Divestitures and Joint-Venture Funding (Pro Forma Financial Information) (Details) (USD $) | 12 Months Ended | 0 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 17, 2013 | |
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items] | |||
Debt Instrument, Face Amount | $2,300,000,000 | ||
Business Acquisition Pro Forma Results of Operations | |||
Total revenues and other | 5,335,442,000 | 3,973,605,000 | |
Total operating expenses | 5,039,311,000 | 3,711,868,000 | |
Net loss | ($403,447,000) | ($397,070,000) | |
Net loss per unit: | |||
Basic | ($1.25) | ($1.22) | |
Diluted | ($1.25) | ($1.22) | |
Devon Assets Acquisition [Member] | |||
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items] | |||
Useful lives of other property and equipment (in years) | 10 years | ||
Business Acquisition, Berry | |||
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items] | |||
Useful lives of other property and equipment (in years) | 20 years | ||
Linn Energy, LLC | Business Acquisition, Berry | |||
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items] | |||
LINN Energy units issued to LinnCo for LinnCo common shares issued | 93,756,674 |
Exchanges_of_Properties_Acquis6
Exchanges of Properties, Acquisitions, Divestitures and Joint-Venture Funding (Divestiture) (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Business Acquisition [Line Items] | |||||||||||
Gain (Loss) on Disposition of Assets | ($338,750,000) | ($35,803,000) | $5,467,000 | $2,586,000 | $10,597,000 | $827,000 | ($959,000) | $3,172,000 | $366,500,000 | ($13,637,000) | ($1,539,000) |
Gain (Loss) on Disposition of Oil and Gas Property | 85,493,000 | 0 | 0 | ||||||||
XOM II Exchange [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Gain (Loss) on Disposition of Assets | 20,000,000 | ||||||||||
Costs Associated With Sale of Oil and Gas Property and Equipment | 3,000,000 | ||||||||||
XOM I Exchange [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Gain (Loss) on Disposition of Assets | 65,000,000 | ||||||||||
Costs Associated With Sale of Oil and Gas Property and Equipment | 3,000,000 | ||||||||||
Granite Wash Assets Sale [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Costs Associated With Sale of Oil and Gas Property and Equipment | 10,000,000 | ||||||||||
Gain (Loss) on Disposition of Oil and Gas Property | 294,000,000 | ||||||||||
Proceeds from sale of oil and natural gas property | 1,800,000,000 | ||||||||||
Permian Basin Assets Sale [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Costs Associated With Sale of Oil and Gas Property and Equipment | 2,000,000 | ||||||||||
Gain (Loss) on Disposition of Oil and Gas Property | -28,000,000 | ||||||||||
Proceeds from sale of oil and natural gas property | 351,000,000 | ||||||||||
STACK acreage divestiture [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Gain (Loss) on Disposition of Oil and Gas Property | 36,000,000 | ||||||||||
Proceeds from sale of oil and natural gas property | 44,000,000 | ||||||||||
Panther Properties Sale [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Costs Associated With Sale of Oil and Gas Property and Equipment | 2,000,000 | ||||||||||
Proceeds from sale of oil and natural gas property | 218,000,000 | ||||||||||
Impairment of Long-Lived Assets to be Disposed of | $37,000,000 |
Unitholders_Capital_Details
Unitholders' Capital (Details) (USD $) | 1 Months Ended | 3 Months Ended | 12 Months Ended | 0 Months Ended | 1 Months Ended | 3 Months Ended | 6 Months Ended | |||
Jan. 31, 2012 | Dec. 31, 2014 | Dec. 31, 2014 | Oct. 17, 2012 | Dec. 17, 2013 | Feb. 28, 2015 | Jan. 31, 2015 | Mar. 31, 2015 | Mar. 31, 2015 | Dec. 16, 2013 | |
Subsequent Event [Line Items] | ||||||||||
Per unit cash dividend paid (in dollars per unit) | $0.73 | |||||||||
Related Party Transaction [Line Items] | ||||||||||
Public offering underwriting discount and offering expenses | $28,000,000 | |||||||||
Public Offering of Units [Abstract] | ||||||||||
Public offering units sold | 19,550,000 | |||||||||
Public offering price per unit | $35.95 | |||||||||
Public offering price per unit, net of underwriting discount | $34.51 | |||||||||
Public offering net proceeds | 674,000,000 | |||||||||
Public offering underwriting discount and offering expenses | 28,000,000 | |||||||||
Equity Distribution Agreement [Abstract] | ||||||||||
Equity distribution agreement maximum value | 500,000,000 | |||||||||
Equity distribution agreement professional service expenses | 700,000 | |||||||||
Equity distribution agreement units sold | 1,539,651 | |||||||||
Equity distribution agreement price per unit sold | $38.02 | |||||||||
Equity distribution agreement net proceeds | 57,000,000 | |||||||||
Equity Distribution Agreement Commissions And Professional Service Expenses | 1,000,000 | |||||||||
Unit Repurchase Plan [Abstract] | ||||||||||
Authorized repurchase value of units | 250,000,000 | 250,000,000 | ||||||||
LinnCo | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Inital public offering, shares issued (in shares) | 34,787,500 | |||||||||
Inital public offering, price per share (in usd per share) | $36.50 | |||||||||
Initial public offering, price per share, net (in usd per share) | $34.86 | |||||||||
Initial public offering, proceeds | 1,200,000,000 | |||||||||
Public offering underwriting discount and offering expenses | 57,000,000 | |||||||||
Units of LINN Energy acquired | 34,787,500 | |||||||||
Public Offering of Units [Abstract] | ||||||||||
Public offering underwriting discount and offering expenses | 57,000,000 | |||||||||
Berry | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Exchange ratio | 168.00% | |||||||||
Berry | Linn Energy, LLC | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
LinnCo common shares issued to acquire Berry | 93,756,674 | |||||||||
LINN Energy units issued to LinnCo for LinnCo common shares issued | 93,756,674 | |||||||||
Value of units issued to acquire Berry | 2,800,000,000 | |||||||||
Berry | LinnCo | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
LinnCo common shares issued to acquire Berry | 93,756,674 | |||||||||
LINN Energy units issued to LinnCo for LinnCo common shares issued | 93,756,674 | |||||||||
Subsequent Event [Member] | ||||||||||
Subsequent Event [Line Items] | ||||||||||
Per unit cash dividend paid (in dollars per unit) | $0.31 | |||||||||
Common Stock, Dividends, Per Share, Declared, Monthly (in dollars per unit) | $0.10 | |||||||||
Change in distributions declared | 57.00% | |||||||||
Distribution paid during period | $35,000,000 | $35,000,000 |
Business_and_Credit_Concentrat1
Business and Credit Concentrations (Details) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Sales [Member] | Customer Concentration Risk [Member] | |||
Concentration Risk [Line Items] | |||
Total number of largest customers represented in sales | 2 | ||
Customer 1 [Member] | Sales [Member] | Customer Concentration Risk [Member] | |||
Concentration Risk [Line Items] | |||
Concentration risk percentage (in hundredths) | 14.00% | 12.00% | 12.00% |
Customer 2 [Member] | Sales [Member] | Customer Concentration Risk [Member] | |||
Concentration Risk [Line Items] | |||
Concentration risk percentage (in hundredths) | 11.00% | ||
Credit Risk [Member] | Accounts Receivable [Member] | |||
Concentration Risk [Line Items] | |||
Total number of largest customers represented in sales | 1 | 2 | |
Credit Risk [Member] | Customer 1 [Member] | Accounts Receivable [Member] | |||
Concentration Risk [Line Items] | |||
Concentration risk percentage (in hundredths) | 11.00% | 19.00% | |
Credit Risk [Member] | Customer 2 [Member] | Accounts Receivable [Member] | |||
Concentration Risk [Line Items] | |||
Concentration risk percentage (in hundredths) | 14.00% |
UnitBased_Compensation_and_Oth2
Unit-Based Compensation and Other Benefit Plans (Details) (USD $) | 12 Months Ended | 1 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Jan. 31, 2014 | Dec. 16, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Berry employee unit-based awards | $19,000,000 | ||||
Number of shares available for grant (in units) | 4,700,000 | ||||
Units authorized for issuance (in units) | 8,300,000 | ||||
Units reserved for future issuance (in units) | 4,700,000 | ||||
Share-based Compensation [Abstract] | |||||
Allocated Share Based Compensation | 53,284,000 | 42,703,000 | 29,533,000 | ||
Income tax benefit | 19,688,000 | 15,779,000 | 10,912,000 | ||
Weighted Average Exercise Price Per Unit [Abstract] | |||||
Forfeited or expired (in dollars per unit) | $40.01 | ||||
Change in Unit Options and Unit Options Outstanding [Abstract] | |||||
Expected volatility | 34.10% | ||||
Expected volatility | 29.65% | ||||
Expected volatility | 50.88% | ||||
Expected distributions | 9.84% | 7.25% | |||
Risk-free rate | 0.67% | ||||
Risk-free rate | 0.13% | ||||
Risk-free rate | 1.55% | ||||
Expected term | 5 years | ||||
Defined Contribution Plan [Abstract] | |||||
Entity's matching contribution (in hundredths) | 100.00% | ||||
Participant's eligible contribution, (in hundredths) | 6.00% | ||||
Defined Contribution Plan, Cost Recognized | 10,000,000 | 7,000,000 | 5,000,000 | ||
General and Administrative Expense [Member] | |||||
Share-based Compensation [Abstract] | |||||
Allocated Share Based Compensation | 45,195,000 | 37,375,000 | 27,641,000 | ||
Lease Operating Expense [Member] | |||||
Share-based Compensation [Abstract] | |||||
Allocated Share Based Compensation | 8,089,000 | 5,328,000 | 1,892,000 | ||
Unit Options [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Awards vesting period (in years) | 3 years | ||||
Contractual life of unit options (in years) | 10 years | ||||
Restricted/Unrestricted Units [Abstract] | |||||
Unrecognized compensation cost | 4,000,000 | ||||
Unrecognized compensation cost recognition period (in years) | 1 year 1 month 1 day | ||||
Unit Options Activity [Roll Forward] | |||||
Outstanding, beginning (in units) | 5,444,417 | 6,433,223 | |||
Exercised (in units) | -813,806 | ||||
Forfeited or expired (in units) | -175,000 | ||||
Outstanding, ending (in units) | 5,444,417 | 6,433,223 | |||
Exercisable (in units) | 2,510,457 | ||||
Weighted Average Exercise Price Per Unit [Abstract] | |||||
Outstanding, beginning (in dollars per unit) | $31.95 | $30.22 | |||
Exercised (in dollars per unit) | $16.56 | ||||
Outstanding, ending (in dollars per unit) | $31.95 | $30.22 | |||
Exercisable (in dollars per unit) | $22.57 | ||||
Weighted Average Remaining Contractual Life in Years [Abstract] | |||||
Outstanding, beginning (in years) | 5 years 1 month 12 days | 6 years 7 months 28 days | |||
Outstanding, ending (in years) | 5 years 1 month 12 days | 6 years 7 months 28 days | |||
Exercisable (in years) | 5 years 6 months 0 days | ||||
Weighted Average Grant Date Fair Value Per Unit [Abstract] | |||||
Weighted average grant date fair value of options granted (in dollars per unit) | $7.52 | ||||
Change in Unit Options and Unit Options Outstanding [Abstract] | |||||
Weighted average grant date fair value of options granted (in dollars per unit) | $7.52 | ||||
Intrinsic value of options exercised | 11,000,000 | 2,000,000 | 3,000,000 | ||
Proceeds from exercise of unit warrants | 13,000,000 | ||||
Unrecognized compensation cost | 4,000,000 | ||||
Unrecognized compensation cost recognition period (in years) | 1 year 1 month 1 day | ||||
Intrinsic value of outstanding unit options | 0 | 33 | |||
Intrinsic value of exercisable unit options | 0 | ||||
Unit Options [Member] | Nonemployee [Member] | |||||
Nonemployee Grants [Abstract] | |||||
Unit warrants oustanding (in units) | 15,000 | ||||
Exercise price of unit warrants (in dollars per unit) | $25.50 | ||||
Restricted Unrestricted Units [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Number of shares available for grant (in units) | 21,000,000 | ||||
Units reserved for future issuance (in units) | 21,000,000 | ||||
Restricted/Unrestricted Nonvested Units [Roll Forward] | |||||
Granted (in dollars per unit) | $30.71 | $37.42 | |||
Performance Units [Member] | |||||
Restricted/Unrestricted Nonvested Units [Roll Forward] | |||||
Granted (in units) | 283,660 | ||||
Restricted/Unrestricted Units [Abstract] | |||||
Granted (in units) | 283,660 | ||||
Restricted Units [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Awards vesting period (in years) | 3 years | ||||
Restricted/Unrestricted Nonvested Units [Roll Forward] | |||||
Nonvested units, beginning (in units) | 2,838,973 | 2,571,410 | |||
Granted (in units) | 1,789,038 | 3,468,245 | |||
Vested (in units) | -1,282,509 | ||||
Forfeited (in units) | -238,966 | ||||
Nonvested units, ending (in units) | 2,838,973 | 2,571,410 | |||
Outstanding, beginning (in dollars per unit) | $32.70 | $33.14 | |||
Granted (in dollars per unit) | $33.10 | ||||
Vested (in dollars per unit) | $32.77 | ||||
Forfeited (in dollars per unit) | $32.25 | ||||
Outstanding, ending (in dollars per unit) | $32.70 | $33.14 | |||
Restricted/Unrestricted Units [Abstract] | |||||
Fair value of units vested | 42,000,000 | 31,000,000 | 24,000,000 | ||
Unrecognized compensation cost | 40,000,000 | ||||
Unrecognized compensation cost recognition period (in years) | 1 year 7 months 6 days | ||||
Granted (in units) | 1,789,038 | 3,468,245 | |||
Change in Unit Options and Unit Options Outstanding [Abstract] | |||||
Unrecognized compensation cost | $40,000,000 | ||||
Unrecognized compensation cost recognition period (in years) | 1 year 7 months 6 days | ||||
Phantom Share Units (PSUs) [Member] | |||||
Restricted/Unrestricted Nonvested Units [Roll Forward] | |||||
Granted (in units) | 697,120 | ||||
Restricted/Unrestricted Units [Abstract] | |||||
Granted (in units) | 697,120 | ||||
Minimum [Member] | |||||
Change in Unit Options and Unit Options Outstanding [Abstract] | |||||
Expected term | 0 years 8 months 5 days | ||||
Maximum [Member] | |||||
Change in Unit Options and Unit Options Outstanding [Abstract] | |||||
Expected term | 5 years | ||||
Tranche One | Unit Options [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Awards vesting period (in years) | 2 years | ||||
Award vesting rights | 50.00% | ||||
Tranche Two | Unit Options [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Awards vesting period (in years) | 3 years | ||||
Award vesting rights | 50.00% |
Debt_Details
Debt (Details) (USD $) | 12 Months Ended | 3 Months Ended | 0 Months Ended | 4 Months Ended | 3 Months Ended | ||||||||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Mar. 31, 2013 | Mar. 31, 2014 | Sep. 08, 2014 | Dec. 31, 2014 | Dec. 15, 2014 | Sep. 09, 2014 | Aug. 29, 2014 | Jun. 30, 2014 | Oct. 30, 2013 | ||||
Debt Instrument [Line Items] | |||||||||||||||
Term loan | $500,000,000 | $500,000,000 | $500,000,000 | ||||||||||||
Debt Instrument, Face Amount | 2,300,000,000 | 2,300,000,000 | |||||||||||||
Additional Interest Due To Late Registration | 15,000,000 | 15,000,000 | |||||||||||||
Long-term Debt, Fair Value | 9,171,824,000 | 9,395,577,000 | 9,171,824,000 | ||||||||||||
Loss on extinguishment of debt | 0 | 5,304,000 | 0 | ||||||||||||
Percent of future net income allowable to increase Berry's restricted payments basket | 0.5 | 0.5 | |||||||||||||
Line of Credit | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 4,500,000,000 | 4,500,000,000 | |||||||||||||
Line of Credit Facility, Current Borrowing Capacity | 4,000,000,000 | 4,000,000,000 | |||||||||||||
Percent Reduction of Borrowing Base Under Credit Facility | 25.00% | ||||||||||||||
Reduction of Borrowing Base Under Line of Credit | 25,000,000 | 250,000,000 | |||||||||||||
Redetermined Borrowing Base Under Line Of Credit | 4,225,000,000 | 4,250,000,000 | 4,500,000,000 | ||||||||||||
Reduction of Maximum Borrowing Capacity Under Line of Credit | 25,000,000 | 250,000,000 | |||||||||||||
Senior Notes [Member] | Senior Notes Due November 2019 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Number of days for effective registration statement | 400 days | ||||||||||||||
Berry | Line of Credit | Credit Facility | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Line of Credit Facility, Interest Rate at Period End | 2.67% | ||||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 1,400,000,000 | 1,400,000,000 | |||||||||||||
Line of Credit Facility, Current Borrowing Capacity | 1,200,000,000 | 1,200,000,000 | |||||||||||||
Line of Credit Facility, Remaining Borrowing Capacity | 1,000,000 | 1,000,000 | |||||||||||||
The percentage of properties that the company is required to maintain mortgages on (in hundredths) | 80.00% | ||||||||||||||
Berry | Line of Credit | Credit Facility | Minimum [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Line of credit facility unused capacity commitment fee percentage (in hundredths) | 0.38% | ||||||||||||||
Berry | Line of Credit | Credit Facility | Maximum [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Line of credit facility unused capacity commitment fee percentage (in hundredths) | 0.50% | ||||||||||||||
Berry | Senior Notes [Member] | Senior Notes Due 2014 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Face Amount | 205,000,000 | 205,000,000 | |||||||||||||
Extinguishment of Debt, Amount | 321,000 | ||||||||||||||
Debt Instrument, Interest Rate, Stated Percentage (in hundredths) | 10.25% | ||||||||||||||
Berry | Senior Notes [Member] | Senior Notes Due 2020 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Face Amount | 300,000,000 | 300,000,000 | |||||||||||||
Extinguishment of Debt, Amount | 30,000 | ||||||||||||||
Debt Instrument, Interest Rate, Stated Percentage (in hundredths) | 6.75% | 6.75% | |||||||||||||
Long-term Debt, Fair Value | 310,000,000 | 310,000,000 | |||||||||||||
Debt Instrument, Unamortized Premium | 10,000,000 | 10,000,000 | |||||||||||||
Berry | Senior Notes [Member] | Senior Notes Due 2022 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Face Amount | 599,000,000 | 599,000,000 | |||||||||||||
Extinguishment of Debt, Amount | 837,000 | ||||||||||||||
Debt Instrument, Interest Rate, Stated Percentage (in hundredths) | 6.38% | 6.38% | |||||||||||||
Long-term Debt, Fair Value | 607,000,000 | 607,000,000 | |||||||||||||
Debt Instrument, Unamortized Premium | 7,000,000 | 7,000,000 | |||||||||||||
Linn Energy, LLC | Line of Credit | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 4,500,000,000 | 4,500,000,000 | |||||||||||||
Line of Credit Facility, Current Borrowing Capacity | 4,000,000,000 | 4,000,000,000 | |||||||||||||
Line of Credit Facility, Remaining Borrowing Capacity | 2,200,000,000 | 2,200,000,000 | |||||||||||||
Outstanding letters of credit that reduce the credit facility availability | 5,000,000 | 5,000,000 | |||||||||||||
Linn Energy, LLC | Line of Credit | Credit Facility | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Line of Credit Facility, Interest Rate at Period End | 1.92% | ||||||||||||||
The percentage of properties that the company is required to maintain mortgages on (in hundredths) | 80.00% | ||||||||||||||
Line Of Credit Facility Collateral Coverage Ratio | 2.5 | 2.5 | |||||||||||||
Linn Energy, LLC | Line of Credit | Credit Facility | Minimum [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Line of credit facility unused capacity commitment fee percentage (in hundredths) | 0.38% | ||||||||||||||
Linn Energy, LLC | Line of Credit | Credit Facility | Maximum [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Line of credit facility unused capacity commitment fee percentage (in hundredths) | 0.50% | ||||||||||||||
Linn Energy, LLC | Loans Payable | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Term loan | 500,000,000 | [1] | 500,000,000 | [1] | 500,000,000 | [1] | |||||||||
Linn Energy, LLC | Loans Payable | Credit Facility | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Line of Credit Facility, Interest Rate at Period End | 2.66% | 2.67% | 2.66% | ||||||||||||
The percentage of properties that the company is required to maintain mortgages on (in hundredths) | 80.00% | ||||||||||||||
Line Of Credit Facility Collateral Coverage Ratio | 2.5 | 2.5 | |||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 0.00% | ||||||||||||||
Debt Instrument, Increase in Basis Spread on Variable Rate | 0.50% | ||||||||||||||
Long-term Debt, Gross | 500,000,000 | ||||||||||||||
Bridge Loan | 1,000,000,000 | ||||||||||||||
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due September 2021 and May 2019 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Face Amount | 1,100,000,000 | ||||||||||||||
Debt Issuance Cost | 22,000,000 | ||||||||||||||
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due 2017 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Face Amount | 41,000,000 | 41,000,000 | |||||||||||||
Debt Instrument, Interest Rate, Stated Percentage (in hundredths) | 11.75% | 11.75% | |||||||||||||
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due 2018 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Face Amount | 14,000,000 | 14,000,000 | |||||||||||||
Debt Instrument, Interest Rate, Stated Percentage (in hundredths) | 9.88% | 9.88% | |||||||||||||
Linn Energy, LLC | Senior Notes [Member] | Original Senior Notes | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Loss on extinguishment of debt | -5,000,000 | ||||||||||||||
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due May 2019 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Face Amount | 750,000,000 | 750,000,000 | |||||||||||||
Debt Instrument, Interest Rate, Stated Percentage (in hundredths) | 6.50% | 6.50% | 6.50% | ||||||||||||
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due November 2019 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Face Amount | 1,800,000,000 | 1,800,000,000 | |||||||||||||
Debt Instrument, Interest Rate, Stated Percentage (in hundredths) | 6.25% | 6.25% | |||||||||||||
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due 2020 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Face Amount | 1,300,000,000 | 1,300,000,000 | |||||||||||||
Debt Instrument, Interest Rate, Stated Percentage (in hundredths) | 8.63% | 8.63% | |||||||||||||
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due 2021 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Face Amount | 1,000,000,000 | 1,000,000,000 | |||||||||||||
Debt Instrument, Interest Rate, Stated Percentage (in hundredths) | 7.75% | 7.75% | |||||||||||||
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due September 2021 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Face Amount | 650,000,000 | 650,000,000 | 650,000,000 | ||||||||||||
Debt Instrument, Interest Rate, Stated Percentage (in hundredths) | 6.50% | ||||||||||||||
Maximum Percentage of September 2021 Senior Notes Redeemable On or Before 2017 | 35.00% | ||||||||||||||
Issue Price of Debt Instruments as a Percentage of Face Amount | 98.62% | ||||||||||||||
Proceeds from Debt, Net of Issuance Costs | 628,000,000 | ||||||||||||||
Debt Instrument, Unamortized Discount | 9,000,000 | ||||||||||||||
Debt Issuance Cost | 13,000,000 | ||||||||||||||
Variable Interest Entity, Primary Beneficiary [Member] | Loans Payable | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Equity in Subsidiaries Pledged to Secure Debt | 100.00% | ||||||||||||||
The percentage of properties that the company is required to maintain mortgages on (in hundredths) | 80.00% | ||||||||||||||
Term loan | 1,300,000,000 | ||||||||||||||
2014 [Member] | Senior Notes [Member] | Senior Notes Due September 2021 and May 2019 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Face Amount | 1,100,000,000 | ||||||||||||||
2014 [Member] | Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due May 2019 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Face Amount | 450,000,000 | 450,000,000 | 450,000,000 | ||||||||||||
Issue Price of Debt Instruments as a Percentage of Face Amount | 102.00% | ||||||||||||||
Proceeds from Debt, Net of Issuance Costs | 450,000,000 | ||||||||||||||
Debt Instrument, Unamortized Premium | 9,000,000 | ||||||||||||||
Debt Issuance Cost | $9,000,000 | ||||||||||||||
London Interbank Offered Rate (LIBOR) [Member] | Berry | Line of Credit | Credit Facility | Minimum [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 1.50% | ||||||||||||||
London Interbank Offered Rate (LIBOR) [Member] | Berry | Line of Credit | Credit Facility | Maximum [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 2.50% | ||||||||||||||
London Interbank Offered Rate (LIBOR) [Member] | Linn Energy, LLC | Line of Credit | Credit Facility | Minimum [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 1.50% | ||||||||||||||
London Interbank Offered Rate (LIBOR) [Member] | Linn Energy, LLC | Line of Credit | Credit Facility | Maximum [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 2.50% | ||||||||||||||
London Interbank Offered Rate (LIBOR) [Member] | Linn Energy, LLC | Loans Payable | Credit Facility | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 5.00% | ||||||||||||||
London Interbank Offered Rate (LIBOR) [Member] | Linn Energy, LLC | Loans Payable | Credit Facility | Maximum [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 2.50% | ||||||||||||||
ABR [Member] | Berry | Line of Credit | Credit Facility | Minimum [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 0.50% | ||||||||||||||
ABR [Member] | Berry | Line of Credit | Credit Facility | Maximum [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 1.50% | ||||||||||||||
ABR [Member] | Linn Energy, LLC | Line of Credit | Credit Facility | Minimum [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 0.50% | ||||||||||||||
ABR [Member] | Linn Energy, LLC | Line of Credit | Credit Facility | Maximum [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 1.50% | ||||||||||||||
ABR [Member] | Linn Energy, LLC | Loans Payable | Credit Facility | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 4.00% | ||||||||||||||
ABR [Member] | Linn Energy, LLC | Loans Payable | Credit Facility | Maximum [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 1.50% | ||||||||||||||
Debt Instrument, Redemption, Period One [Member] | Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due May 2019 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Redemption Price, Percentage | 103.25% | ||||||||||||||
Redemption Price of Senior Notes for Change of Control | 101.00% | ||||||||||||||
Debt Instrument, Redemption, Period One [Member] | Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due September 2021 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Redemption Price, Percentage | 106.50% | ||||||||||||||
Redemption Price of Senior Notes for Change of Control | 101.00% | ||||||||||||||
Debt Instrument, Redemption, Period Two [Member] | Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due September 2021 | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Debt Instrument, Redemption Price, Percentage | 103.25% | ||||||||||||||
[1] | Variable interest rates of 2.66% and 2.67% at December 31, 2014 and December 31, 2013, respectively. |
Debt_Schedule_of_LongTerm_Debt
Debt Schedule of Long-Term Debt (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | ||
In Thousands, unless otherwise specified | ||||
Debt Instrument [Line Items] | ||||
Credit facilities | $2,968,175 | $2,733,175 | ||
Term loan | 500,000 | 500,000 | ||
Senior notes, net | 6,827,634 | 5,937,041 | ||
Total debt, net | 10,295,809 | 9,170,216 | ||
Less current maturities | 0 | -211,558 | ||
Total long-term debt, net | 10,295,809 | 8,958,658 | ||
Senior Notes [Member] | ||||
Debt Instrument [Line Items] | ||||
Net unamortized discounts and premiums | 21,499 | 18,216 | ||
Linn Energy, LLC | Line of Credit | ||||
Debt Instrument [Line Items] | ||||
Credit facilities | 1,795,000 | [1] | 1,560,000 | [1] |
Linn Energy, LLC | Loans Payable | ||||
Debt Instrument [Line Items] | ||||
Term loan | 500,000 | [2] | 500,000 | [2] |
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due May 2019 | ||||
Debt Instrument [Line Items] | ||||
Senior notes, net | 1,200,000 | [3] | 750,000 | [3] |
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due November 2019 | ||||
Debt Instrument [Line Items] | ||||
Senior notes, net | 1,800,000 | 1,800,000 | ||
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due 2020 | ||||
Debt Instrument [Line Items] | ||||
Senior notes, net | 1,300,000 | 1,300,000 | ||
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due 2021 | ||||
Debt Instrument [Line Items] | ||||
Senior notes, net | 1,000,000 | 1,000,000 | ||
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due September 2021 | ||||
Debt Instrument [Line Items] | ||||
Senior notes, net | 650,000 | [3] | 0 | [3] |
Berry | Line of Credit | ||||
Debt Instrument [Line Items] | ||||
Credit facilities | 1,173,175 | [4] | 1,173,175 | [4] |
Berry | Senior Notes [Member] | Senior Notes Due 2014 | ||||
Debt Instrument [Line Items] | ||||
Senior notes, net | 0 | 205,257 | ||
Berry | Senior Notes [Member] | Senior Notes Due 2020 | ||||
Debt Instrument [Line Items] | ||||
Senior notes, net | 299,970 | 300,000 | ||
Berry | Senior Notes [Member] | Senior Notes Due 2022 | ||||
Debt Instrument [Line Items] | ||||
Senior notes, net | $599,163 | $600,000 | ||
[1] | Variable interest rate of 1.92% at both December 31, 2014, and December 31, 2013. | |||
[2] | Variable interest rates of 2.66% and 2.67% at December 31, 2014 and December 31, 2013, respectively. | |||
[3] | of senior notes due May 2019 and $650 million of senior notes due September 2021 were issued on September 9, 2014. | |||
[4] | Variable interest rate of 2.67% at both December 31, 2014, and December 31, 2013. |
Debt_Debt_Fair_Value_Disclosur
Debt Debt Fair Value Disclosure (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Carrying Value | ||
Credit facilities | $2,968,175 | $2,733,175 |
Term loan | 500,000 | 500,000 |
Senior notes, net | 6,827,634 | 5,937,041 |
Total debt, net | 10,295,809 | 9,170,216 |
Fair Value | ||
Credit facilities | 2,968,175 | 2,733,175 |
Term loan | 500,000 | 500,000 |
Senior notes, net | 5,703,649 | 6,162,402 |
Total debt, net | $9,171,824 | $9,395,577 |
Derivatives_Commodity_Derivati
Derivatives (Commodity Derivatives) (Details) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||
MMMBTU | MBbls | MMMBTU | ||
MBbls | MMMBTU | MBbls | ||
Derivative [Line Items] | ||||
Volumes of natural gas production on settled derivatives (in MMMbtu) | 177,029 | 173,488 | 140,884 | |
Average contract price per MMBtu on settled derivatives | 5.14 | 5.29 | 5.41 | |
Volumes of oil production on settled derivatives (in MBbls) | 24,988 | 15,590 | 11,289 | |
Average contract price per barrel on settled derivatives | 92.39 | 95.35 | 97.61 | |
2015 | Natural Gas Derivative Instruments | Fixed price swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 118,041 | |||
Average Fixed Price (in usd per energy unit) | 5.19 | |||
2015 | Natural Gas Derivative Instruments | Puts | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 71,854 | [1] | ||
Average Price (in usd per energy unit) | 5 | [1] | ||
2015 | Oil Derivative Instruments | Fixed price swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 11,599 | [2] | ||
Average Fixed Price (in usd per energy unit) | 96.23 | [2] | ||
2015 | Oil Derivative Instruments | Puts | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 3,426 | |||
Average Price (in usd per energy unit) | 90 | |||
2015 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 1,095 | |||
2015 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Short | ||||
Derivative [Line Items] | ||||
Derivative, Floor Price (in usd per energy unit) | 70 | |||
Short Call (in usd per energy unit) | 101.62 | |||
2015 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Long | ||||
Derivative [Line Items] | ||||
Derivative, Floor Price (in usd per energy unit) | 90 | |||
2015 | Natural Gas Basis Differential Positions | Panhandle basis swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 87,162 | [3] | ||
Hedged Differential (in usd per energy unit) | -0.33 | [3] | ||
2015 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 43,292 | [3] | ||
Hedged Differential (in usd per energy unit) | -0.2 | [3] | ||
2015 | Natural Gas Basis Differential Positions | MichCon basis swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 9,344 | [3] | ||
Hedged Differential (in usd per energy unit) | 0.06 | [3] | ||
2015 | Natural Gas Basis Differential Positions | Houston Ship Channel basis swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 4,891 | [3] | ||
Hedged Differential (in usd per energy unit) | -0.1 | [3] | ||
2015 | Natural Gas Basis Differential Positions | Permian basis swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 5,074 | [3] | ||
Hedged Differential (in usd per energy unit) | -0.21 | [3] | ||
2015 | Oil Timing Differential Positions | Trade month roll swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 7,251 | |||
Hedged Differential (in usd per energy unit) | 0.24 | |||
2016 | Natural Gas Derivative Instruments | Fixed price swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 121,841 | |||
Average Fixed Price (in usd per energy unit) | 4.2 | |||
2016 | Natural Gas Derivative Instruments | Puts | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 76,269 | [1] | ||
Average Price (in usd per energy unit) | 5 | [1] | ||
2016 | Oil Derivative Instruments | Fixed price swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 11,465 | [2] | ||
Average Fixed Price (in usd per energy unit) | 90.56 | [2] | ||
2016 | Oil Derivative Instruments | Puts | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 3,271 | |||
Average Price (in usd per energy unit) | 90 | |||
2016 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 0 | |||
2016 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Short | ||||
Derivative [Line Items] | ||||
Derivative, Floor Price (in usd per energy unit) | 0 | |||
Short Call (in usd per energy unit) | 0 | |||
2016 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Long | ||||
Derivative [Line Items] | ||||
Derivative, Floor Price (in usd per energy unit) | 0 | |||
2016 | Natural Gas Basis Differential Positions | Panhandle basis swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 59,954 | [3] | ||
Hedged Differential (in usd per energy unit) | -0.32 | [3] | ||
2016 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 46,294 | [3] | ||
Hedged Differential (in usd per energy unit) | -0.2 | [3] | ||
2016 | Natural Gas Basis Differential Positions | MichCon basis swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 7,768 | [3] | ||
Hedged Differential (in usd per energy unit) | 0.05 | [3] | ||
2016 | Natural Gas Basis Differential Positions | Houston Ship Channel basis swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 4,575 | [3] | ||
Hedged Differential (in usd per energy unit) | -0.1 | [3] | ||
2016 | Natural Gas Basis Differential Positions | Permian basis swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 4,219 | [3] | ||
Hedged Differential (in usd per energy unit) | -0.2 | [3] | ||
2016 | Oil Timing Differential Positions | Trade month roll swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 7,446 | |||
Hedged Differential (in usd per energy unit) | 0.25 | |||
2017 | Natural Gas Derivative Instruments | Fixed price swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 120,122 | |||
Average Fixed Price (in usd per energy unit) | 4.26 | |||
2017 | Natural Gas Derivative Instruments | Puts | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 66,886 | [1] | ||
Average Price (in usd per energy unit) | 4.88 | [1] | ||
2017 | Oil Derivative Instruments | Fixed price swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 4,755 | [2] | ||
Average Fixed Price (in usd per energy unit) | 89.02 | [2] | ||
2017 | Oil Derivative Instruments | Puts | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 384 | |||
Average Price (in usd per energy unit) | 90 | |||
2017 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 0 | |||
2017 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Short | ||||
Derivative [Line Items] | ||||
Derivative, Floor Price (in usd per energy unit) | 0 | |||
Short Call (in usd per energy unit) | 0 | |||
2017 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Long | ||||
Derivative [Line Items] | ||||
Derivative, Floor Price (in usd per energy unit) | 0 | |||
2017 | Oil Derivative Instruments | Extendible Fixed Price Swaps | ||||
Derivative [Line Items] | ||||
Average Fixed Price (in usd per energy unit) | 100 | |||
Amount of outstanding extendible fixed price oil swaps of daily production (in MBbls) | 5,384 | |||
2017 | Natural Gas Basis Differential Positions | Panhandle basis swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 59,138 | [3] | ||
Hedged Differential (in usd per energy unit) | -0.33 | [3] | ||
2017 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 38,880 | [3] | ||
Hedged Differential (in usd per energy unit) | -0.19 | [3] | ||
2017 | Natural Gas Basis Differential Positions | MichCon basis swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 7,437 | [3] | ||
Hedged Differential (in usd per energy unit) | 0.05 | [3] | ||
2017 | Natural Gas Basis Differential Positions | Houston Ship Channel basis swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 3,604 | [3] | ||
Hedged Differential (in usd per energy unit) | -0.08 | [3] | ||
2017 | Natural Gas Basis Differential Positions | Permian basis swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 4,819 | [3] | ||
Hedged Differential (in usd per energy unit) | -0.2 | [3] | ||
2017 | Oil Timing Differential Positions | Trade month roll swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 6,486 | |||
Hedged Differential (in usd per energy unit) | 0.25 | |||
2018 | Natural Gas Derivative Instruments | Fixed price swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 36,500 | |||
Average Fixed Price (in usd per energy unit) | 5 | |||
2018 | Natural Gas Derivative Instruments | Puts | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 0 | [1] | ||
Average Price (in usd per energy unit) | 0 | [1] | ||
2018 | Oil Derivative Instruments | Fixed price swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 0 | [2] | ||
Average Fixed Price (in usd per energy unit) | 0 | [2] | ||
2018 | Oil Derivative Instruments | Puts | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 0 | |||
Average Price (in usd per energy unit) | 0 | |||
2018 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 0 | |||
2018 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Short | ||||
Derivative [Line Items] | ||||
Derivative, Floor Price (in usd per energy unit) | 0 | |||
Short Call (in usd per energy unit) | 0 | |||
2018 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Long | ||||
Derivative [Line Items] | ||||
Derivative, Floor Price (in usd per energy unit) | 0 | |||
2018 | Oil Derivative Instruments | Extendible Fixed Price Swaps | ||||
Derivative [Line Items] | ||||
Average Fixed Price (in usd per energy unit) | 100 | |||
Amount of outstanding extendible fixed price oil swaps of daily production (in MBbls) | 5,384 | |||
2018 | Natural Gas Basis Differential Positions | Panhandle basis swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 16,425 | [3] | ||
Hedged Differential (in usd per energy unit) | -0.33 | [3] | ||
2018 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 10,804 | [3] | ||
Hedged Differential (in usd per energy unit) | -0.19 | [3] | ||
2018 | Natural Gas Basis Differential Positions | MichCon basis swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 2,044 | [3] | ||
Hedged Differential (in usd per energy unit) | 0.05 | [3] | ||
2018 | Natural Gas Basis Differential Positions | Houston Ship Channel basis swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 986 | [3] | ||
Hedged Differential (in usd per energy unit) | -0.08 | [3] | ||
2018 | Natural Gas Basis Differential Positions | Permian basis swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 1,314 | [3] | ||
Hedged Differential (in usd per energy unit) | -0.2 | [3] | ||
2018 | Oil Timing Differential Positions | Trade month roll swaps | ||||
Derivative [Line Items] | ||||
Hedged Volume (in energy unit) | 0 | |||
Hedged Differential (in usd per energy unit) | 0 | |||
2019 | Oil Derivative Instruments | Extendible Fixed Price Swaps | ||||
Derivative [Line Items] | ||||
Average Fixed Price (in usd per energy unit) | 90 | |||
Amount of outstanding extendible fixed price oil swaps of daily production (in MBbls) | 5,384 | |||
[1] | Includes certain outstanding fixed price oil swaps of approximately 5,384 MBbls which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2017, and December 31, 2018, and $90.00 per Bbl for the year ending December 31, 2019, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years. | |||
[2] | Settle on the respective pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price. | |||
[3] | The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX WTI price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month rollâ€). |
Derivatives_Balance_Sheet_Pres
Derivatives (Balance Sheet Presentation) (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Assets: | ||
Commodity derivatives | $2,014,815,000 | $1,048,212,000 |
Liabilities: | ||
Commodity derivatives | 90,260,000 | 222,905,000 |
Maximum Loss Upon All Counterparties Failing To Perform | $2,000,000,000 |
Derivatives_Gains_Losses_On_De
Derivatives (Gains (Losses) On Derivatives) (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||
Cash settlements on canceled derivatives | $12,281,000 | $0 | $0 | ||||||||
Gains on oil and natural gas derivatives | 1,404,758,000 | 451,702,000 | -408,788,000 | -241,493,000 | 23,425,000 | -63,931,000 | 326,733,000 | -108,370,000 | 1,206,179,000 | 177,857,000 | 124,762,000 |
Cash Settlements On Derivatives including canceled derivatives | 108,000,000 | 249,000,000 | 391,000,000 | ||||||||
Premiums paid for derivatives | $0 | $0 | $583,434,000 |
Fair_Value_Measurements_on_a_R2
Fair Value Measurements on a Recurring Basis (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | ||
In Thousands, unless otherwise specified | ||||
Assets: | ||||
Commodity derivatives | $2,014,815 | $1,048,212 | ||
Commodity derivatives | -89,576 | [1] | -190,080 | [1] |
Commodity derivatives | 1,925,239 | 858,132 | ||
Liabilities: | ||||
Commodity derivatives | 90,260 | 222,905 | ||
Commodity derivatives | -89,576 | [1] | -190,080 | [1] |
Commodity derivatives | $684 | $32,825 | ||
[1] | Represents counterparty netting under agreements governing such derivatives. |
Other_Property_and_Equipment_D
Other Property and Equipment (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment | $669,149 | $647,882 |
Less accumulated depreciation | -144,282 | -110,939 |
Other property and equipment, net | 524,867 | 536,943 |
Gas Gathering and Processing Equipment [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment | 479,754 | 507,342 |
Building and Building Improvements [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment | 49,046 | 32,658 |
Vehicles [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment | 36,534 | 27,964 |
Upstream Equipment [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment | 6,994 | 8,618 |
Furniture and Fixtures [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment | 88,893 | 65,909 |
Land [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment | $7,928 | $5,391 |
Asset_Retirement_Obligations_D
Asset Retirement Obligations (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Asset Retirement Obligation Disclosure [Abstract] | |||
Future inflation factor used in the calculation of the asset retirement obligations | 2.00% | 2.00% | 2.00% |
Credit adjusted risk-free interest rate for the calculation of the asset retirement obligations | 5.30% | 6.20% | 6.80% |
Asset retirement obligations rollforward | |||
Asset retirement obligations at beginning of year | $289,321 | $151,974 | |
Liabilities added from acquisitions | 176,538 | 98,343 | |
Liabilities added from drilling | 10,476 | 4,048 | |
Liabilities associated with assets divested | -25,656 | -1,092 | |
Current year accretion expense | 22,164 | 11,938 | |
Settlements | -12,620 | -5,136 | |
Revision of estimates | 37,347 | 29,246 | |
Asset retirement obligations at end of year | $497,570 | $289,321 | $151,974 |
Commitments_and_Contingencies_
Commitments and Contingencies (Details) (USD $) | 1 Months Ended | 12 Months Ended | 36 Months Ended | ||
Mar. 31, 2011 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2014 | |
Loss Contingencies [Line Items] | |||||
Litigation Settlement, Amount | $2,400,000 | ||||
Payments for Legal Settlements | 2,400,000 | ||||
Material payments for legal, environmental, or tax settlements | 0 | ||||
Amount of general unsecured claims from termination agreements | 51,000,000 | ||||
Distribution received under termination agreement | 7,000,000 | 11,000,000 | 28,000,000 | 46,000,000 | |
Recovery of bankruptcy claim included in gains (losses) on oil and natural gas derivatives | $22,000,000 |
Earnings_Per_Unit_Details
Earnings Per Unit (Details) (USD $) | 12 Months Ended | ||
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Earnings Per Share [Abstract] | |||
Net loss | ($451,809) | ($691,337) | ($386,616) |
Allocated to participating securities | -7,117 | -5,935 | -4,575 |
Net loss attributable to common unitholders | ($458,926) | ($697,272) | ($391,191) |
Earnings per share reconciliation | |||
Basic net loss per unit | ($1.40) | ($2.94) | ($1.92) |
Diluted net loss per unit | ($1.40) | ($2.94) | ($1.92) |
Weighted average units outstanding | |||
Basic weighted average units outstanding | 328,918,000 | 237,544,000 | 203,775,000 |
Dilutive effect of unit equivalents | 0 | 0 | 0 |
Diluted weighted average units outstanding | 328,918,000 | 237,544,000 | 203,775,000 |
Unit options and warrants | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Weighted average anti-dilutive unit equivalents excluded from computation of earnings per unit (in units) | 6,000,000 | 4,000,000 | 2,000,000 |
Operating_Leases_Details
Operating Leases (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Leases, Operating [Abstract] | |||
Operating lease expense | $14,000,000 | $7,000,000 | $7,000,000 |
Future Minimum Lease Payments [Abstract] | |||
2015 | 13,265,000 | ||
2016 | 10,288,000 | ||
2017 | 8,215,000 | ||
2018 | 7,130,000 | ||
2019 | 6,492,000 | ||
Thereafter | 1,046,000 | ||
Operating Leases, Future Minimum Payments Due, Total | $46,436,000 |
Income_Taxes_Details
Income Taxes (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Current taxes: | |||
Federal | $473,000 | $144,000 | $2,711,000 |
State | 21,000 | 198,000 | 439,000 |
Deferred taxes: | |||
Federal | -104,000 | -2,805,000 | 323,000 |
State | 4,047,000 | 264,000 | -683,000 |
Income tax expense (benefit) | 4,437,000 | -2,199,000 | 2,790,000 |
Operating Loss Carryforwards [Line Items] | |||
Material Uncertain Tax Position | 0 | 0 | |
Effective income tax rate reconciliation [Abstract] | |||
Federal statutory rate | 35.00% | 35.00% | 35.00% |
State, net of federal tax benefit | -0.90% | -0.10% | 0.10% |
Loss excluded from nontaxable entities | -34.60% | -34.60% | -35.60% |
Other items | -0.50% | 0.00% | -0.20% |
Effective rate | -1.00% | 0.30% | -0.70% |
Deferred tax assets: | |||
Net operating loss carryforwards | 0 | 1,129,000 | |
Unit-based compensation | 22,105,000 | 21,965,000 | |
Other | 6,857,000 | 7,759,000 | |
Total deferred tax assets | 28,962,000 | 30,853,000 | |
Deferred tax liabilities: | |||
Property and equipment principally due to differences in depreciation | -10,991,000 | -12,525,000 | |
Other | -6,370,000 | -1,509,000 | |
Total deferred tax liabilities | -17,361,000 | -14,034,000 | |
Net deferred tax assets | 11,601,000 | 16,819,000 | |
Net deferred tax assets and liabilities classified in consolidated balance sheets [Abstract] | |||
Deferred tax assets | 28,442,000 | 29,204,000 | |
Deferred tax liabilities | -2,964,000 | -10,000 | |
Other current assets | 25,478,000 | 29,194,000 | |
Deferred tax assets | 520,000 | 1,649,000 | |
Deferred tax liabilities | -14,397,000 | -14,024,000 | |
Other noncurrent liabilities | -13,877,000 | -12,375,000 | |
Federal [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Net operating loss carryforwards | $11,000,000 | ||
Net operating loss carryforwards, expiration dates | 31-Dec-31 |
Supplemental_Disclosures_to_th2
Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows (Balance Sheets) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
Balance Sheet and Cash Flow Supplemental Disclosures [Abstract] | ||
Accrued interest | $105,310,000 | $93,998,000 |
Accrued compensation | 44,875,000 | 55,257,000 |
Asset retirement obligations | 16,187,000 | 12,616,000 |
Other | 1,364,000 | 1,504,000 |
Other accrued liabilities | 167,736,000 | 163,375,000 |
Restricted cash | 6,000,000 | 6,000,000 |
Net Outstanding Checks | $95,000,000 | $48,000,000 |
Supplemental_Disclosures_to_th3
Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows (Cash Flows) (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Balance Sheet and Cash Flow Supplemental Disclosures [Abstract] | |||
Cash payments for interest, net of amounts capitalized | $542,775,000 | $392,607,000 | $343,331,000 |
Cash payments for income taxes | 0 | 14,000 | 366,000 |
Noncash investing and financing activities: | |||
Fair value of assets acquired | 2,679,547,000 | 5,726,681,000 | 2,923,990,000 |
Cash paid, net of cash acquired | -2,395,339,000 | -109,350,000 | -2,640,475,000 |
Units issued in connection with the Berry acquisition | 0 | -2,781,888,000 | 0 |
Gain (Loss) on Disposition of Oil and Gas Property | -85,493,000 | 0 | 0 |
Receivables from sellers | 16,213,000 | -93,000 | 2,132,000 |
Payables to sellers | -3,515,000 | -6,854,000 | 443,000 |
Liabilities assumed | 211,413,000 | 2,828,496,000 | 286,090,000 |
Joint-venture funding | $25,000,000 | $170,000,000 | $197,000,000 |
Related_Party_Transactions_Det
Related Party Transactions (Details) (USD $) | 12 Months Ended | 0 Months Ended | ||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Oct. 17, 2012 | Dec. 17, 2013 | Dec. 16, 2013 | |
Related Party Transaction [Line Items] | ||||||
General and administrative expenses | $293,073,000 | $236,271,000 | $173,206,000 | |||
Share-based compensation expense | 53,284,000 | 42,703,000 | 29,533,000 | |||
Distributions to unitholders | 962,048,000 | 682,241,000 | 596,935,000 | |||
LinnCo | ||||||
Related Party Transaction [Line Items] | ||||||
Initial public offering, proceeds | 1,200,000,000 | |||||
Units of LINN Energy acquired | 34,787,500 | |||||
Ownership percentage | 39.00% | |||||
General and administrative expenses | 2,900,000 | 42,000,000 | ||||
Third party transaction costs related to the pending acquisition of Berry | 40,000,000 | |||||
Share-based compensation expense | 9,000,000 | |||||
Distributions to unitholders | 373,000,000 | 101,000,000 | 25,000,000 | |||
Related party transaction, amounts of transaction | 1,900,000 | 2,000,000 | ||||
Offering costs paid on behalf of related party | 388,000 | |||||
Berry | ||||||
Related Party Transaction [Line Items] | ||||||
Exchange ratio | 168.00% | |||||
Director | ||||||
Related Party Transaction [Line Items] | ||||||
Related party transaction, amounts of transaction | 21,000,000 | 26,000,000 | 21,000,000 | |||
Linn Energy, LLC | Berry | ||||||
Related Party Transaction [Line Items] | ||||||
LinnCo common shares issued to acquire Berry | 93,756,674 | |||||
LINN Energy units issued to LinnCo for LinnCo common shares issued | 93,756,674 | |||||
Value of units issued to acquire Berry | 2,800,000,000 | |||||
LinnCo | Berry | ||||||
Related Party Transaction [Line Items] | ||||||
LinnCo common shares issued to acquire Berry | 93,756,674 | |||||
LINN Energy units issued to LinnCo for LinnCo common shares issued | 93,756,674 | |||||
FY 2013 [Member] | ||||||
Related Party Transaction [Line Items] | ||||||
General and administrative expenses paid on behalf of related party | $11,000,000 | |||||
Business Acquisition, Berry | ||||||
Related Party Transaction [Line Items] | ||||||
Exchange ratio | 168.00% | |||||
Business Acquisition, Berry | Linn Energy, LLC | ||||||
Related Party Transaction [Line Items] | ||||||
Units of LINN Energy acquired | 34,787,500 | |||||
LinnCo common shares issued to acquire Berry | 93,756,674 | |||||
LINN Energy units issued to LinnCo for LinnCo common shares issued | 93,756,674 | |||||
Business Acquisition, Berry | LinnCo | ||||||
Related Party Transaction [Line Items] | ||||||
LinnCo common shares issued to acquire Berry | 93,756,674 | |||||
LINN Energy units issued to LinnCo for LinnCo common shares issued | 93,756,674 |
Subsidiary_Guarantors_Condense
Subsidiary Guarantors Condensed Consolidating Balance Sheets (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
In Thousands, unless otherwise specified | ||||
Current assets: | ||||
Cash and cash equivalents | $1,809 | $52,171 | $1,243 | $1,114 |
Accounts receivable – trade, net | 471,684 | 488,202 | ||
Accounts receivable – affiliates | 0 | 0 | ||
Derivative instruments | 1,077,142 | 176,130 | ||
Other current assets | 155,955 | 99,437 | ||
Total current assets | 1,706,590 | 815,940 | ||
Noncurrent assets: | ||||
Oil and natural gas properties (successful efforts method) | 18,068,900 | 17,888,559 | ||
Less accumulated depletion and amortization | -4,867,682 | -3,546,284 | ||
Oil and natural gas properties, successful efforts method, net | 13,201,218 | 14,342,275 | ||
Other property and equipment | 669,149 | 647,882 | ||
Less accumulated depreciation | -144,282 | -110,939 | ||
Other property and equipment, net | 524,867 | 536,943 | ||
Derivative instruments | 848,097 | 682,002 | ||
Notes receivable – affiliates | 0 | 0 | ||
Advance to affiliate | 0 | |||
Investments in consolidated subsidiaries | 0 | 0 | ||
Other noncurrent assets | 142,737 | 127,804 | ||
Noncurrent assets, excluding property, total | 990,834 | 809,806 | ||
Total noncurrent assets | 14,716,919 | 15,689,024 | ||
Total assets | 16,423,509 | 16,504,964 | ||
Current liabilities: | ||||
Accounts payable and accrued expenses | 814,809 | 849,624 | ||
Accounts payable – affiliates | 0 | 0 | ||
Advance from affiliate | 0 | |||
Derivative instruments | 0 | 28,176 | ||
Other accrued liabilities | 167,736 | 163,375 | ||
Current portion of long-term debt | 0 | 211,558 | ||
Total current liabilities | 982,545 | 1,252,733 | ||
Noncurrent liabilities: | ||||
Credit facilities | 2,968,175 | 2,733,175 | ||
Term loan | 500,000 | 500,000 | ||
Senior notes, net | 6,827,634 | 5,725,483 | ||
Notes payable – affiliates | 0 | 0 | ||
Derivative instruments | 684 | 4,649 | ||
Other noncurrent liabilities | 600,866 | 397,497 | ||
Total noncurrent liabilities | 10,897,359 | 9,360,804 | ||
Unitholders’ capital: | ||||
Units issued and outstanding | 5,395,811 | 6,291,824 | ||
Accumulated income (deficit) | -852,206 | -400,397 | ||
Total unitholders' capital | 4,543,605 | 5,891,427 | 4,427,180 | 3,428,910 |
Total liabilities and unitholders’ capital | 16,423,509 | 16,504,964 | ||
Eliminations | ||||
Current assets: | ||||
Cash and cash equivalents | 0 | 0 | 0 | |
Accounts receivable – trade, net | 0 | 0 | ||
Accounts receivable – affiliates | -4,042,095 | -4,229,298 | ||
Derivative instruments | 0 | 0 | ||
Other current assets | 0 | 0 | ||
Total current assets | -4,042,095 | -4,229,298 | ||
Noncurrent assets: | ||||
Oil and natural gas properties (successful efforts method) | 0 | 0 | ||
Less accumulated depletion and amortization | 0 | 0 | ||
Oil and natural gas properties, successful efforts method, net | 0 | 0 | ||
Other property and equipment | 0 | 0 | ||
Less accumulated depreciation | 0 | 0 | ||
Other property and equipment, net | 0 | 0 | ||
Derivative instruments | 0 | 0 | ||
Notes receivable – affiliates | -130,500 | -86,200 | ||
Advance to affiliate | -293,627 | |||
Investments in consolidated subsidiaries | -8,562,608 | -8,433,290 | ||
Other noncurrent assets | 0 | 0 | ||
Noncurrent assets, excluding property, total | -8,986,735 | -8,519,490 | ||
Total noncurrent assets | -8,986,735 | -8,519,490 | ||
Total assets | -13,028,830 | -12,748,788 | ||
Current liabilities: | ||||
Accounts payable and accrued expenses | 0 | 0 | ||
Accounts payable – affiliates | -4,042,095 | -4,229,298 | ||
Advance from affiliate | -293,627 | |||
Derivative instruments | 0 | 0 | ||
Other accrued liabilities | 0 | 0 | ||
Current portion of long-term debt | 0 | |||
Total current liabilities | -4,335,722 | -4,229,298 | ||
Noncurrent liabilities: | ||||
Credit facilities | 0 | 0 | ||
Term loan | 0 | 0 | ||
Senior notes, net | 0 | 0 | ||
Notes payable – affiliates | -130,500 | -86,200 | ||
Derivative instruments | 0 | 0 | ||
Other noncurrent liabilities | 0 | 0 | ||
Total noncurrent liabilities | -130,500 | -86,200 | ||
Unitholders’ capital: | ||||
Units issued and outstanding | -7,240,658 | -7,139,737 | ||
Accumulated income (deficit) | -1,321,950 | -1,293,553 | ||
Total unitholders' capital | -8,562,608 | -8,433,290 | ||
Total liabilities and unitholders’ capital | -13,028,830 | -12,748,788 | ||
Linn Energy, LLC | Reportable Legal Entities | ||||
Current assets: | ||||
Cash and cash equivalents | 38 | 52 | 107 | |
Accounts receivable – trade, net | 0 | 0 | ||
Accounts receivable – affiliates | 4,028,890 | 4,212,348 | ||
Derivative instruments | 0 | 0 | ||
Other current assets | 18 | 330 | ||
Total current assets | 4,028,946 | 4,212,730 | ||
Noncurrent assets: | ||||
Oil and natural gas properties (successful efforts method) | 0 | 0 | ||
Less accumulated depletion and amortization | 0 | 0 | ||
Oil and natural gas properties, successful efforts method, net | 0 | 0 | ||
Other property and equipment | 0 | 0 | ||
Less accumulated depreciation | 0 | 0 | ||
Other property and equipment, net | 0 | 0 | ||
Derivative instruments | 0 | 0 | ||
Notes receivable – affiliates | 130,500 | 86,200 | ||
Advance to affiliate | 0 | |||
Investments in consolidated subsidiaries | 8,562,608 | 8,433,290 | ||
Other noncurrent assets | 116,637 | 108,785 | ||
Noncurrent assets, excluding property, total | 8,809,745 | 8,628,275 | ||
Total noncurrent assets | 8,809,745 | 8,628,275 | ||
Total assets | 12,838,691 | 12,841,005 | ||
Current liabilities: | ||||
Accounts payable and accrued expenses | 3,784 | 14,529 | ||
Accounts payable – affiliates | 0 | 0 | ||
Advance from affiliate | 0 | |||
Derivative instruments | 0 | 0 | ||
Other accrued liabilities | 89,507 | 75,071 | ||
Current portion of long-term debt | 0 | |||
Total current liabilities | 93,291 | 89,600 | ||
Noncurrent liabilities: | ||||
Credit facilities | 1,795,000 | 1,560,000 | ||
Term loan | 500,000 | 500,000 | ||
Senior notes, net | 5,913,857 | 4,809,055 | ||
Notes payable – affiliates | 0 | 0 | ||
Derivative instruments | 0 | 0 | ||
Other noncurrent liabilities | 0 | 0 | ||
Total noncurrent liabilities | 8,208,857 | 6,869,055 | ||
Unitholders’ capital: | ||||
Units issued and outstanding | 5,388,749 | 6,282,747 | ||
Accumulated income (deficit) | -852,206 | -400,397 | ||
Total unitholders' capital | 4,536,543 | 5,882,350 | ||
Total liabilities and unitholders’ capital | 12,838,691 | 12,841,005 | ||
Guarantor Subsidiaries | Reportable Legal Entities | ||||
Current assets: | ||||
Cash and cash equivalents | 185 | 1,078 | 1,136 | |
Accounts receivable – trade, net | 371,325 | 365,347 | ||
Accounts receivable – affiliates | 13,205 | 16,950 | ||
Derivative instruments | 1,033,448 | 170,534 | ||
Other current assets | 96,678 | 68,274 | ||
Total current assets | 1,514,841 | 622,183 | ||
Noncurrent assets: | ||||
Oil and natural gas properties (successful efforts method) | 13,196,841 | 13,074,900 | ||
Less accumulated depletion and amortization | -4,342,675 | -3,535,890 | ||
Oil and natural gas properties, successful efforts method, net | 8,854,166 | 9,539,010 | ||
Other property and equipment | 553,150 | 564,756 | ||
Less accumulated depreciation | -135,830 | -110,706 | ||
Other property and equipment, net | 417,320 | 454,050 | ||
Derivative instruments | 848,097 | 679,491 | ||
Notes receivable – affiliates | 0 | 0 | ||
Advance to affiliate | 0 | |||
Investments in consolidated subsidiaries | 0 | 0 | ||
Other noncurrent assets | 11,816 | 10,968 | ||
Noncurrent assets, excluding property, total | 859,913 | 690,459 | ||
Total noncurrent assets | 10,131,399 | 10,683,519 | ||
Total assets | 11,646,240 | 11,305,702 | ||
Current liabilities: | ||||
Accounts payable and accrued expenses | 581,880 | 587,774 | ||
Accounts payable – affiliates | 4,028,890 | 4,212,348 | ||
Advance from affiliate | 293,627 | |||
Derivative instruments | 0 | 7,783 | ||
Other accrued liabilities | 59,142 | 59,311 | ||
Current portion of long-term debt | 0 | |||
Total current liabilities | 4,963,539 | 4,867,216 | ||
Noncurrent liabilities: | ||||
Credit facilities | 0 | 0 | ||
Term loan | 0 | 0 | ||
Senior notes, net | 0 | 0 | ||
Notes payable – affiliates | 130,500 | 86,200 | ||
Derivative instruments | 684 | 0 | ||
Other noncurrent liabilities | 400,851 | 205,406 | ||
Total noncurrent liabilities | 532,035 | 291,606 | ||
Unitholders’ capital: | ||||
Units issued and outstanding | 4,831,339 | 4,833,354 | ||
Accumulated income (deficit) | 1,319,327 | 1,313,526 | ||
Total unitholders' capital | 6,150,666 | 6,146,880 | ||
Total liabilities and unitholders’ capital | 11,646,240 | 11,305,702 | ||
Non-Guarantor Subsidiary | Reportable Legal Entities | ||||
Current assets: | ||||
Cash and cash equivalents | 1,586 | 51,041 | 0 | |
Accounts receivable – trade, net | 100,359 | 122,855 | ||
Accounts receivable – affiliates | 0 | 0 | ||
Derivative instruments | 43,694 | 5,596 | ||
Other current assets | 59,259 | 30,833 | ||
Total current assets | 204,898 | 210,325 | ||
Noncurrent assets: | ||||
Oil and natural gas properties (successful efforts method) | 4,872,059 | 4,813,659 | ||
Less accumulated depletion and amortization | -525,007 | -10,394 | ||
Oil and natural gas properties, successful efforts method, net | 4,347,052 | 4,803,265 | ||
Other property and equipment | 115,999 | 83,126 | ||
Less accumulated depreciation | -8,452 | -233 | ||
Other property and equipment, net | 107,547 | 82,893 | ||
Derivative instruments | 0 | 2,511 | ||
Notes receivable – affiliates | 0 | 0 | ||
Advance to affiliate | 293,627 | |||
Investments in consolidated subsidiaries | 0 | 0 | ||
Other noncurrent assets | 14,284 | 8,051 | ||
Noncurrent assets, excluding property, total | 307,911 | 10,562 | ||
Total noncurrent assets | 4,762,510 | 4,896,720 | ||
Total assets | 4,967,408 | 5,107,045 | ||
Current liabilities: | ||||
Accounts payable and accrued expenses | 229,145 | 247,321 | ||
Accounts payable – affiliates | 13,205 | 16,950 | ||
Advance from affiliate | 0 | |||
Derivative instruments | 0 | 20,393 | ||
Other accrued liabilities | 19,087 | 28,993 | ||
Current portion of long-term debt | 211,558 | |||
Total current liabilities | 261,437 | 525,215 | ||
Noncurrent liabilities: | ||||
Credit facilities | 1,173,175 | 1,173,175 | ||
Term loan | 0 | 0 | ||
Senior notes, net | 913,777 | 916,428 | ||
Notes payable – affiliates | 0 | 0 | ||
Derivative instruments | 0 | 4,649 | ||
Other noncurrent liabilities | 200,015 | 192,091 | ||
Total noncurrent liabilities | 2,286,967 | 2,286,343 | ||
Unitholders’ capital: | ||||
Units issued and outstanding | 2,416,381 | 2,315,460 | ||
Accumulated income (deficit) | 2,623 | -19,973 | ||
Total unitholders' capital | 2,419,004 | 2,295,487 | ||
Total liabilities and unitholders’ capital | $4,967,408 | $5,107,045 |
Subsidiary_Guarantors_Condense1
Subsidiary Guarantors Condensed Consolidating Statements of Operations (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Revenues and other: | |||||||||||
Oil, natural gas and natural gas liquids sales | $766,354 | $937,458 | $967,850 | $938,877 | $584,630 | $537,671 | $488,207 | $462,732 | $3,610,539 | $2,073,240 | $1,601,180 |
Gains on oil and natural gas derivatives | 1,404,758 | 451,702 | -408,788 | -241,493 | 23,425 | -63,931 | 326,733 | -108,370 | 1,206,179 | 177,857 | 124,762 |
Marketing revenues | 135,260 | 54,171 | 37,393 | ||||||||
Other revenues | 31,325 | 26,387 | 10,905 | ||||||||
Total revenues | 2,217,650 | 1,435,115 | 596,951 | 733,587 | 629,208 | 494,562 | 838,825 | 369,060 | 4,983,303 | 2,331,655 | 1,774,240 |
Expenses: | |||||||||||
Lease operating expenses | 805,164 | 372,523 | 317,699 | ||||||||
Transportation expenses | 207,331 | 128,440 | 77,322 | ||||||||
Marketing expenses | 117,465 | 37,892 | 31,821 | ||||||||
General and administrative expenses | 293,073 | 236,271 | 173,206 | ||||||||
Exploration costs | 125,037 | 5,251 | 1,915 | ||||||||
Depreciation, depletion and amortization | 1,073,902 | 829,311 | 606,150 | ||||||||
Impairment of long-lived assets | 1,700,000 | 603,000 | 2,303,749 | 828,317 | 422,499 | ||||||
Taxes, other than income taxes | 267,403 | 138,631 | 131,679 | ||||||||
(Gains) losses on sale of assets and other, net | 338,750 | 35,803 | -5,467 | -2,586 | -10,597 | -827 | 959 | -3,172 | -366,500 | 13,637 | 1,539 |
Total expenses | 4,826,624 | 2,590,273 | 1,763,830 | ||||||||
Other income and (expenses): | |||||||||||
Interest expense, net of amounts capitalized | -587,838 | -421,137 | -379,937 | ||||||||
Interest expense – affiliates | 0 | 0 | |||||||||
Interest income – affiliates | 0 | 0 | |||||||||
Loss on extinguishment of debt | 0 | -5,304 | 0 | ||||||||
Equity in earnings from consolidated subsidiaries | 0 | 0 | |||||||||
Other, net | -16,213 | -8,477 | -14,299 | ||||||||
Total other income and (expenses) | -604,051 | -434,918 | -394,236 | ||||||||
Loss before income taxes | -447,372 | -693,536 | -383,826 | ||||||||
Income tax expense (benefit) | 4,437 | -2,199 | 2,790 | ||||||||
Net loss | -154,502 | -4,100 | -207,870 | -85,337 | -784,549 | -30,060 | 345,157 | -221,885 | -451,809 | -691,337 | -386,616 |
Eliminations | |||||||||||
Revenues and other: | |||||||||||
Oil, natural gas and natural gas liquids sales | 0 | 0 | |||||||||
Gains on oil and natural gas derivatives | 0 | 0 | |||||||||
Marketing revenues | 0 | 0 | |||||||||
Other revenues | 0 | 0 | |||||||||
Total revenues | 0 | 0 | |||||||||
Expenses: | |||||||||||
Lease operating expenses | 0 | 0 | |||||||||
Transportation expenses | 0 | 0 | |||||||||
Marketing expenses | 0 | 0 | |||||||||
General and administrative expenses | 0 | 0 | |||||||||
Exploration costs | 0 | 0 | |||||||||
Depreciation, depletion and amortization | 0 | 0 | |||||||||
Impairment of long-lived assets | 0 | 0 | |||||||||
Taxes, other than income taxes | 0 | 0 | |||||||||
(Gains) losses on sale of assets and other, net | 0 | 0 | |||||||||
Total expenses | 0 | 0 | |||||||||
Other income and (expenses): | |||||||||||
Interest expense, net of amounts capitalized | 0 | 0 | |||||||||
Interest expense – affiliates | 7,954 | 5,543 | |||||||||
Interest income – affiliates | -7,954 | -5,543 | |||||||||
Loss on extinguishment of debt | 0 | ||||||||||
Equity in earnings from consolidated subsidiaries | -28,397 | 266,899 | |||||||||
Other, net | 0 | 0 | |||||||||
Total other income and (expenses) | -28,397 | 266,899 | |||||||||
Loss before income taxes | -28,397 | 266,899 | |||||||||
Income tax expense (benefit) | 0 | 0 | |||||||||
Net loss | -28,397 | 266,899 | |||||||||
Linn Energy, LLC | Reportable Legal Entities | |||||||||||
Revenues and other: | |||||||||||
Oil, natural gas and natural gas liquids sales | 0 | 0 | |||||||||
Gains on oil and natural gas derivatives | 0 | 0 | |||||||||
Marketing revenues | 0 | 0 | |||||||||
Other revenues | 0 | 0 | |||||||||
Total revenues | 0 | 0 | |||||||||
Expenses: | |||||||||||
Lease operating expenses | 0 | 0 | |||||||||
Transportation expenses | 0 | 0 | |||||||||
Marketing expenses | 0 | 0 | |||||||||
General and administrative expenses | 0 | 0 | |||||||||
Exploration costs | 0 | 0 | |||||||||
Depreciation, depletion and amortization | 0 | 0 | |||||||||
Impairment of long-lived assets | 0 | 0 | |||||||||
Taxes, other than income taxes | 40 | 0 | |||||||||
(Gains) losses on sale of assets and other, net | 0 | 724 | |||||||||
Total expenses | 40 | 724 | |||||||||
Other income and (expenses): | |||||||||||
Interest expense, net of amounts capitalized | -480,259 | -415,670 | |||||||||
Interest expense – affiliates | 0 | 0 | |||||||||
Interest income – affiliates | 7,954 | 5,543 | |||||||||
Loss on extinguishment of debt | -5,304 | ||||||||||
Equity in earnings from consolidated subsidiaries | 28,397 | -266,899 | |||||||||
Other, net | -7,861 | -8,283 | |||||||||
Total other income and (expenses) | -451,769 | -690,613 | |||||||||
Loss before income taxes | -451,809 | -691,337 | |||||||||
Income tax expense (benefit) | 0 | 0 | |||||||||
Net loss | -451,809 | -691,337 | |||||||||
Guarantor Subsidiaries | Reportable Legal Entities | |||||||||||
Revenues and other: | |||||||||||
Oil, natural gas and natural gas liquids sales | 2,312,137 | 2,022,916 | |||||||||
Gains on oil and natural gas derivatives | 1,127,395 | 182,906 | |||||||||
Marketing revenues | 84,349 | 52,328 | |||||||||
Other revenues | 28,133 | 26,387 | |||||||||
Total revenues | 3,552,014 | 2,284,537 | |||||||||
Expenses: | |||||||||||
Lease operating expenses | 440,624 | 357,113 | |||||||||
Transportation expenses | 165,489 | 125,864 | |||||||||
Marketing expenses | 81,210 | 36,259 | |||||||||
General and administrative expenses | 190,286 | 215,973 | |||||||||
Exploration costs | 125,037 | 5,251 | |||||||||
Depreciation, depletion and amortization | 771,549 | 818,466 | |||||||||
Impairment of long-lived assets | 2,050,387 | 828,317 | |||||||||
Taxes, other than income taxes | 169,655 | 136,501 | |||||||||
(Gains) losses on sale of assets and other, net | -487,286 | 2,705 | |||||||||
Total expenses | 3,506,951 | 2,526,449 | |||||||||
Other income and (expenses): | |||||||||||
Interest expense, net of amounts capitalized | -19,631 | -1,504 | |||||||||
Interest expense – affiliates | -7,954 | -5,543 | |||||||||
Interest income – affiliates | 0 | 0 | |||||||||
Loss on extinguishment of debt | 0 | ||||||||||
Equity in earnings from consolidated subsidiaries | 0 | 0 | |||||||||
Other, net | -7,309 | -166 | |||||||||
Total other income and (expenses) | -34,894 | -7,213 | |||||||||
Loss before income taxes | 10,169 | -249,125 | |||||||||
Income tax expense (benefit) | 4,368 | -2,199 | |||||||||
Net loss | 5,801 | -246,926 | |||||||||
Non-Guarantor Subsidiary | Reportable Legal Entities | |||||||||||
Revenues and other: | |||||||||||
Oil, natural gas and natural gas liquids sales | 1,298,402 | 50,324 | |||||||||
Gains on oil and natural gas derivatives | 78,784 | -5,049 | |||||||||
Marketing revenues | 50,911 | 1,843 | |||||||||
Other revenues | 3,192 | 0 | |||||||||
Total revenues | 1,431,289 | 47,118 | |||||||||
Expenses: | |||||||||||
Lease operating expenses | 364,540 | 15,410 | |||||||||
Transportation expenses | 41,842 | 2,576 | |||||||||
Marketing expenses | 36,255 | 1,633 | |||||||||
General and administrative expenses | 102,787 | 20,298 | |||||||||
Exploration costs | 0 | 0 | |||||||||
Depreciation, depletion and amortization | 302,353 | 10,845 | |||||||||
Impairment of long-lived assets | 253,362 | 0 | |||||||||
Taxes, other than income taxes | 97,708 | 2,130 | |||||||||
(Gains) losses on sale of assets and other, net | 120,786 | 10,208 | |||||||||
Total expenses | 1,319,633 | 63,100 | |||||||||
Other income and (expenses): | |||||||||||
Interest expense, net of amounts capitalized | -87,948 | -3,963 | |||||||||
Interest expense – affiliates | 0 | 0 | |||||||||
Interest income – affiliates | 0 | 0 | |||||||||
Loss on extinguishment of debt | 0 | ||||||||||
Equity in earnings from consolidated subsidiaries | 0 | 0 | |||||||||
Other, net | -1,043 | -28 | |||||||||
Total other income and (expenses) | -88,991 | -3,991 | |||||||||
Loss before income taxes | 22,665 | -19,973 | |||||||||
Income tax expense (benefit) | 69 | 0 | |||||||||
Net loss | $22,596 | ($19,973) |
Subsidiary_Guarantors_Condense2
Subsidiary Guarantors Condensed Consolidating Statements of Cash Flow (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Cash flow from operating activities: | |||
Net loss | ($451,809) | ($691,337) | ($386,616) |
Adjustments to reconcile net loss to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 1,073,902 | 829,311 | 606,150 |
Impairment of long-lived assets | 2,303,749 | 828,317 | 422,499 |
Unit-based compensation expenses | 53,284 | 42,703 | 29,533 |
Amortization and write-off of deferred financing fees | 50,926 | 21,507 | 25,598 |
Loss on extinguishment of debt | 0 | 5,304 | 0 |
(Gains) losses on sale of assets and other, net | -261,571 | 37,232 | 92 |
Equity in earnings from consolidated subsidiaries | 0 | 0 | |
Deferred income taxes | 3,943 | -2,541 | -360 |
Derivatives activities: | |||
Total (gains) losses | 1,206,179 | 177,857 | 124,762 |
Cash settlements | 95,514 | 248,862 | 390,765 |
Cash settlements on canceled derivatives | 12,281 | 0 | 0 |
Changes in assets and liabilities: | |||
(Increase) decrease in accounts receivable – trade, net | 5,064 | 89,188 | -77,573 |
Increase in accounts receivable – affiliates | 0 | 0 | |
(Increase) decrease in other assets | -17,824 | 16,179 | -5,451 |
Increase (decrease) in accounts payable and accrued expenses | 99,029 | -76,993 | 26,372 |
Decrease in accounts payable and accrued expenses – affiliates | 0 | 0 | |
Increase in accounts payable and accrued expenses – affiliates | 0 | 0 | |
Increase (decrease) in other liabilities | -48,419 | -3,663 | 28,094 |
Net cash provided by operating activities | 1,711,890 | 1,166,212 | 350,907 |
Cash flow from investing activities: | |||
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired | -2,479,252 | -279,213 | -2,640,475 |
Development of oil and natural gas properties | -1,569,877 | -1,078,025 | -984,530 |
Purchases of other property and equipment | -74,540 | -92,352 | -60,549 |
Investment in affiliates | 0 | 0 | |
Change in notes receivable with affiliate | 0 | 0 | |
Proceeds from sale of properties and equipment and other | 2,203,565 | 196,273 | 725 |
Net cash used in investing activities | -1,920,104 | -1,253,317 | -3,684,829 |
Cash flow from financing activities: | |||
Proceeds from borrowings | 5,940,024 | 2,230,000 | 5,439,802 |
Repayments of debt | -4,811,124 | -1,404,898 | -3,400,000 |
Distributions to unitholders | -962,048 | -682,241 | -596,935 |
Financing fees and offering expenses | 69,694 | 16,033 | 73,320 |
Change in note payable with affiliate | 0 | 0 | |
Capital contribution – affiliates | 0 | 0 | |
Excess tax benefit from unit-based compensation | 766 | 160 | 3,090 |
Other | 59,928 | 11,045 | -12,575 |
Net cash provided by financing activities | 157,852 | 138,033 | 3,334,051 |
Net increase (decrease) in cash and cash equivalents | -50,362 | 50,928 | 129 |
Cash and cash equivalents: | |||
Beginning | 52,171 | 1,243 | 1,114 |
Ending | 1,809 | 52,171 | 1,243 |
Eliminations | |||
Cash flow from operating activities: | |||
Net loss | -28,397 | 266,899 | |
Adjustments to reconcile net loss to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 0 | 0 | |
Impairment of long-lived assets | 0 | 0 | |
Unit-based compensation expenses | 0 | 0 | |
Amortization and write-off of deferred financing fees | 0 | 0 | |
Loss on extinguishment of debt | 0 | ||
(Gains) losses on sale of assets and other, net | 0 | 0 | |
Equity in earnings from consolidated subsidiaries | -28,397 | 266,899 | |
Deferred income taxes | 0 | 0 | |
Derivatives activities: | |||
Total (gains) losses | 0 | 0 | |
Cash settlements | 0 | 0 | |
Cash settlements on canceled derivatives | 0 | ||
Changes in assets and liabilities: | |||
(Increase) decrease in accounts receivable – trade, net | 0 | 0 | |
Increase in accounts receivable – affiliates | 274,435 | -137,917 | |
(Increase) decrease in other assets | 0 | 0 | |
Increase (decrease) in accounts payable and accrued expenses | 0 | 0 | |
Decrease in accounts payable and accrued expenses – affiliates | 274,435 | -137,917 | |
Increase in accounts payable and accrued expenses – affiliates | 274,435 | -137,917 | |
Increase (decrease) in other liabilities | 0 | 0 | |
Net cash provided by operating activities | 0 | 0 | |
Cash flow from investing activities: | |||
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired | 0 | 0 | |
Development of oil and natural gas properties | 0 | 0 | |
Purchases of other property and equipment | 0 | 0 | |
Investment in affiliates | 100,921 | -435,000 | |
Change in notes receivable with affiliate | 44,300 | 26,700 | |
Proceeds from sale of properties and equipment and other | 0 | 0 | |
Net cash used in investing activities | 145,221 | -408,300 | |
Cash flow from financing activities: | |||
Proceeds from borrowings | 0 | 0 | |
Repayments of debt | 0 | 0 | |
Distributions to unitholders | 0 | 0 | |
Financing fees and offering expenses | 0 | 0 | |
Change in note payable with affiliate | -44,300 | -26,700 | |
Capital contribution – affiliates | -100,921 | 435,000 | |
Excess tax benefit from unit-based compensation | 0 | 0 | |
Other | 0 | 0 | |
Net cash provided by financing activities | -145,221 | 408,300 | |
Net increase (decrease) in cash and cash equivalents | 0 | 0 | |
Cash and cash equivalents: | |||
Beginning | 0 | 0 | |
Ending | 0 | 0 | |
Linn Energy, LLC | Reportable Legal Entities | |||
Cash flow from operating activities: | |||
Net loss | -451,809 | -691,337 | |
Adjustments to reconcile net loss to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 0 | 0 | |
Impairment of long-lived assets | 0 | 0 | |
Unit-based compensation expenses | 0 | 0 | |
Amortization and write-off of deferred financing fees | 38,785 | 22,122 | |
Loss on extinguishment of debt | 5,304 | ||
(Gains) losses on sale of assets and other, net | 0 | 0 | |
Equity in earnings from consolidated subsidiaries | 28,397 | -266,899 | |
Deferred income taxes | 0 | 0 | |
Derivatives activities: | |||
Total (gains) losses | 0 | 0 | |
Cash settlements | 0 | 0 | |
Cash settlements on canceled derivatives | 0 | ||
Changes in assets and liabilities: | |||
(Increase) decrease in accounts receivable – trade, net | 0 | 0 | |
Increase in accounts receivable – affiliates | -257,485 | 120,967 | |
(Increase) decrease in other assets | 312 | -330 | |
Increase (decrease) in accounts payable and accrued expenses | 0 | 178 | |
Decrease in accounts payable and accrued expenses – affiliates | 0 | 0 | |
Increase in accounts payable and accrued expenses – affiliates | 0 | 0 | |
Increase (decrease) in other liabilities | 14,465 | 2,092 | |
Net cash provided by operating activities | -169,159 | -516,039 | |
Cash flow from investing activities: | |||
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired | 0 | 0 | |
Development of oil and natural gas properties | 0 | 0 | |
Purchases of other property and equipment | 0 | 0 | |
Investment in affiliates | -100,921 | 435,000 | |
Change in notes receivable with affiliate | -44,300 | -26,700 | |
Proceeds from sale of properties and equipment and other | -14,117 | -22,039 | |
Net cash used in investing activities | -159,338 | 386,261 | |
Cash flow from financing activities: | |||
Proceeds from borrowings | 4,640,024 | 2,230,000 | |
Repayments of debt | -3,305,000 | -1,404,898 | |
Distributions to unitholders | -962,048 | -682,241 | |
Financing fees and offering expenses | 59,048 | 16,033 | |
Change in note payable with affiliate | 0 | 0 | |
Capital contribution – affiliates | 0 | 0 | |
Excess tax benefit from unit-based compensation | 810 | 0 | |
Other | 13,745 | 2,895 | |
Net cash provided by financing activities | 328,483 | 129,723 | |
Net increase (decrease) in cash and cash equivalents | -14 | -55 | |
Cash and cash equivalents: | |||
Beginning | 52 | 107 | |
Ending | 38 | 52 | |
Guarantor Subsidiaries | Reportable Legal Entities | |||
Cash flow from operating activities: | |||
Net loss | 5,801 | -246,926 | |
Adjustments to reconcile net loss to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 771,549 | 818,466 | |
Impairment of long-lived assets | 2,050,387 | 828,317 | |
Unit-based compensation expenses | 53,284 | 42,703 | |
Amortization and write-off of deferred financing fees | 17,054 | 0 | |
Loss on extinguishment of debt | 0 | ||
(Gains) losses on sale of assets and other, net | -372,945 | 37,232 | |
Equity in earnings from consolidated subsidiaries | 0 | 0 | |
Deferred income taxes | 3,874 | -2,541 | |
Derivatives activities: | |||
Total (gains) losses | 1,127,395 | 182,906 | |
Cash settlements | 88,776 | 248,862 | |
Cash settlements on canceled derivatives | 0 | ||
Changes in assets and liabilities: | |||
(Increase) decrease in accounts receivable – trade, net | -11,419 | 17,754 | |
Increase in accounts receivable – affiliates | -16,950 | 16,950 | |
(Increase) decrease in other assets | -2,187 | 5,896 | |
Increase (decrease) in accounts payable and accrued expenses | 99,003 | -52,143 | |
Decrease in accounts payable and accrued expenses – affiliates | -270,690 | 120,967 | |
Increase in accounts payable and accrued expenses – affiliates | -270,690 | 120,967 | |
Increase (decrease) in other liabilities | -24,473 | 6,842 | |
Net cash provided by operating activities | 1,297,569 | 1,625,573 | |
Cash flow from investing activities: | |||
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired | -2,475,315 | -730,326 | |
Development of oil and natural gas properties | -1,061,395 | -1,060,547 | |
Purchases of other property and equipment | -63,070 | -92,352 | |
Investment in affiliates | 0 | 0 | |
Change in notes receivable with affiliate | 0 | 0 | |
Proceeds from sale of properties and equipment and other | 2,210,015 | 218,312 | |
Net cash used in investing activities | -1,389,765 | -1,664,913 | |
Cash flow from financing activities: | |||
Proceeds from borrowings | 1,300,000 | 0 | |
Repayments of debt | -1,300,000 | 0 | |
Distributions to unitholders | 0 | 0 | |
Financing fees and offering expenses | 0 | 0 | |
Change in note payable with affiliate | 44,300 | 26,700 | |
Capital contribution – affiliates | 0 | 0 | |
Excess tax benefit from unit-based compensation | -44 | 160 | |
Other | 47,047 | 12,422 | |
Net cash provided by financing activities | 91,303 | 39,282 | |
Net increase (decrease) in cash and cash equivalents | -893 | -58 | |
Cash and cash equivalents: | |||
Beginning | 1,078 | 1,136 | |
Ending | 185 | 1,078 | |
Non-Guarantor Subsidiary | Reportable Legal Entities | |||
Cash flow from operating activities: | |||
Net loss | 22,596 | -19,973 | |
Adjustments to reconcile net loss to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 302,353 | 10,845 | |
Impairment of long-lived assets | 253,362 | 0 | |
Unit-based compensation expenses | 0 | 0 | |
Amortization and write-off of deferred financing fees | -4,913 | -615 | |
Loss on extinguishment of debt | 0 | ||
(Gains) losses on sale of assets and other, net | 111,374 | 0 | |
Equity in earnings from consolidated subsidiaries | 0 | 0 | |
Deferred income taxes | 69 | 0 | |
Derivatives activities: | |||
Total (gains) losses | 78,784 | -5,049 | |
Cash settlements | 6,738 | 0 | |
Cash settlements on canceled derivatives | 12,281 | ||
Changes in assets and liabilities: | |||
(Increase) decrease in accounts receivable – trade, net | 16,483 | 71,434 | |
Increase in accounts receivable – affiliates | 0 | 0 | |
(Increase) decrease in other assets | -15,949 | 10,613 | |
Increase (decrease) in accounts payable and accrued expenses | 26 | -25,028 | |
Decrease in accounts payable and accrued expenses – affiliates | -3,745 | 16,950 | |
Increase in accounts payable and accrued expenses – affiliates | -3,745 | 16,950 | |
Increase (decrease) in other liabilities | -38,411 | -12,597 | |
Net cash provided by operating activities | 583,480 | 56,678 | |
Cash flow from investing activities: | |||
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired | -3,937 | 451,113 | |
Development of oil and natural gas properties | -508,482 | -17,478 | |
Purchases of other property and equipment | -11,470 | 0 | |
Investment in affiliates | 0 | 0 | |
Change in notes receivable with affiliate | 0 | 0 | |
Proceeds from sale of properties and equipment and other | 7,667 | 0 | |
Net cash used in investing activities | -516,222 | 433,635 | |
Cash flow from financing activities: | |||
Proceeds from borrowings | 0 | 0 | |
Repayments of debt | -206,124 | 0 | |
Distributions to unitholders | 0 | 0 | |
Financing fees and offering expenses | 10,646 | 0 | |
Change in note payable with affiliate | 0 | 0 | |
Capital contribution – affiliates | 100,921 | -435,000 | |
Excess tax benefit from unit-based compensation | 0 | 0 | |
Other | -864 | -4,272 | |
Net cash provided by financing activities | -116,713 | -439,272 | |
Net increase (decrease) in cash and cash equivalents | -49,455 | 51,041 | |
Cash and cash equivalents: | |||
Beginning | 51,041 | 0 | |
Ending | $1,586 | $51,041 |
Subsidiary_Guarantors_Details_
Subsidiary Guarantors Details (Details) | 12 Months Ended |
Dec. 31, 2014 | |
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | |
Subsidiary or Equity Method Investee, Cumulative Percentage Ownership after All Transactions | 100.00% |
Supplemental_Oil_and_Natural_G2
Supplemental Oil and Natural Gas Data (Unaudited) (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||
Mcfe | Mcfe | Mcfe | Mcfe | Mcfe | Mcfe | ||||||||||
Revenues and other: | |||||||||||||||
Oil, natural gas and natural gas liquids sales | $766,354 | $937,458 | $967,850 | $938,877 | $584,630 | $537,671 | $488,207 | $462,732 | $3,610,539 | $2,073,240 | $1,601,180 | ||||
Gains on oil and natural gas derivatives | 1,404,758 | 451,702 | -408,788 | -241,493 | 23,425 | -63,931 | 326,733 | -108,370 | 1,206,179 | 177,857 | 124,762 | ||||
Results of Operations, Revenue from Oil and Gas Producing Activities | 4,816,718 | 2,251,097 | 1,725,942 | ||||||||||||
Production costs: | |||||||||||||||
Lease operating expenses | 805,164 | 372,523 | 317,699 | ||||||||||||
Transportation expenses | 207,331 | 128,440 | 77,322 | ||||||||||||
Severance taxes, ad valorem taxes and California carbon allowances | 267,100 | 139,202 | 130,805 | ||||||||||||
Total production costs | 1,279,595 | 640,165 | 525,826 | ||||||||||||
Other costs: | |||||||||||||||
Exploration costs | 125,037 | 5,251 | 1,915 | ||||||||||||
Depletion and amortization | 1,020,674 | 790,320 | 579,382 | ||||||||||||
Impairment of long-lived assets | 1,700,000 | 603,000 | 2,303,749 | 828,317 | 422,499 | ||||||||||
Gains on sale of assets and other, net | -388,733 | -138 | -1,369 | ||||||||||||
Texas margin tax expense (benefit) | 4,053 | 458 | -787 | ||||||||||||
Total other costs | 3,064,780 | 1,624,208 | 1,001,640 | ||||||||||||
Results of operations | 472,343 | -13,276 | 198,476 | ||||||||||||
Reserve Quantities [Line Items] | |||||||||||||||
Proved Developed and Undeveloped Reserve, Production (Energy) | 442,000,000 | 300,000,000 | 246,000,000 | ||||||||||||
Proved Undeveloped Reserves (Energy) | 1,486,000,000 | 2,063,000,000 | 1,486,000,000 | 2,063,000,000 | 1,669,000,000 | 1,336,000,000 | |||||||||
Proved Developed Reserves (Energy) | 5,818,000,000 | 4,340,000,000 | 5,818,000,000 | 4,340,000,000 | 3,127,000,000 | 2,034,000,000 | |||||||||
Proved developed and undeveloped reserves: | |||||||||||||||
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy) | -318,000,000 | -157,000,000 | -803,000,000 | ||||||||||||
Proved Developed and Undeveloped Reserve, Purchase of Mineral in Place (Energy) | 2,495,000,000 | 1,610,000,000 | 1,766,000,000 | ||||||||||||
Proved Developed and Undeveloped Reserve, Extension and Discovery (Energy) | 250,000,000 | 527,000,000 | 709,000,000 | ||||||||||||
Proved Developed and Undeveloped Reserves, Sale of Mineral in Place (Energy) | 1,084,000,000 | 73,000,000 | |||||||||||||
Proved undeveloped reserves: | |||||||||||||||
Conversion rate between oil and NGL volumes to natural gas | 6 | ||||||||||||||
Decline in NYMEX oil spot price | 42.00% | ||||||||||||||
Decline in NYMEX natural gas spot price. | 30.00% | ||||||||||||||
NYMEX oil price | 53.27 | 53.27 | |||||||||||||
NYMEX natural gas spot price | 2.89 | 2.89 | |||||||||||||
Change in proved reserves (in Mcfe) | 901,000,000 | 1,607,000,000 | 1,426,000,000 | ||||||||||||
Total Proved Developed and Undeveloped Reserves, Net | 7,304,000,000 | 6,403,000,000 | 7,304,000,000 | 6,403,000,000 | |||||||||||
Total Proved Developed and Undeveloped Reserves, Net | 7,304,000,000 | 6,403,000,000 | 7,304,000,000 | 6,403,000,000 | 4,796,000,000 | 3,370,000,000 | |||||||||
Change in proved reserves due to asset performance (in Mcfe) | 174,000,000 | 100,000,000 | 340,000,000 | ||||||||||||
Change in proved reserves due to change in commodity prices (in Mcfe) | 45,000,000 | 52,000,000 | 248,000,000 | ||||||||||||
Change in proved reserves due to the SEC five-year development limitation on PUDs | 146,000,000 | 109,000,000 | 215,000,000 | ||||||||||||
Number of acquisition of oil and natural gas properties | 3 | 7 | |||||||||||||
Productive wells drilled | 917 | 0 | 436 | ||||||||||||
Property acquisition costs [Abstract] | |||||||||||||||
Proved | 2,784,852 | [1] | 3,740,379 | [1] | 2,531,419 | [1] | |||||||||
Unproved | 788,682 | [1] | 1,638,302 | [1] | 181,124 | [1] | |||||||||
Exploration costs | 792 | 13,096 | 452 | ||||||||||||
Development costs | 1,487,204 | 1,153,770 | 1,062,043 | ||||||||||||
Costs Incurred, Asset Retirement Obligation Incurred | 20,919 | 7,351 | 4,675 | ||||||||||||
Total costs incurred | 5,082,449 | 6,552,898 | 3,779,713 | ||||||||||||
Proved properties [Abstract] | |||||||||||||||
Leasehold acquisition | 13,362,642 | 12,277,089 | 13,362,642 | 12,277,089 | |||||||||||
Development | 2,830,841 | 3,660,277 | 2,830,841 | 3,660,277 | |||||||||||
Unproved properties | 1,875,417 | 1,951,193 | 1,875,417 | 1,951,193 | |||||||||||
Capitalized cost, oil and gas producing activities | 18,068,900 | 17,888,559 | 18,068,900 | 17,888,559 | |||||||||||
Less accumulated depletion and amortization | -4,867,682 | -3,546,284 | -4,867,682 | -3,546,284 | |||||||||||
Capitalized costs, oil and gas producing activities, net | 13,201,218 | 14,342,275 | 13,201,218 | 14,342,275 | |||||||||||
Discounted future net cash flows relating to proved oil and gas reserves, future net cash Flows [Abstract] | |||||||||||||||
Future estimated revenues | 55,195,268 | 51,112,346 | 55,195,268 | 51,112,346 | 30,374,380 | ||||||||||
Future estimated production costs | -24,100,468 | -19,306,728 | -24,100,468 | -19,306,728 | -11,460,854 | ||||||||||
Future estimated development costs | -4,032,588 | -5,110,896 | -4,032,588 | -5,110,896 | -3,574,058 | ||||||||||
Future net cash flows | 27,062,212 | 26,694,722 | 27,062,212 | 26,694,722 | 15,339,468 | ||||||||||
10% annual discount for estimated timing of cash flows | -14,549,921 | -14,795,393 | -14,549,921 | -14,795,393 | -9,266,487 | ||||||||||
Standardized measure of discounted future net cash flows | 12,512,291 | 11,899,329 | 12,512,291 | 11,899,329 | 6,072,981 | ||||||||||
Representative NYMEX prices: (1) | |||||||||||||||
Natural gas (MMBtu) | 4.35 | [2] | 3.67 | [2] | 2.76 | [2] | |||||||||
Oil (Bbl) | 95.27 | [2] | 96.89 | [2] | 94.64 | [2] | |||||||||
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract] | |||||||||||||||
Sales and transfers of oil, natural gas and NGL produced during the period | -2,330,944 | -1,433,075 | -1,075,354 | ||||||||||||
Changes in estimated future development costs | 156,614 | 317,064 | 289,762 | ||||||||||||
Net change in sales and transfer prices and production costs related to future production | -599,121 | 203,370 | -1,463,820 | ||||||||||||
Purchases of minerals in place | 3,021,768 | 5,113,335 | 2,153,651 | ||||||||||||
Sales of minerals in place | -1,681,504 | -139,384 | 0 | ||||||||||||
Extensions, discoveries and improved recovery | 910,787 | 801,254 | 413,702 | ||||||||||||
Previously estimated development costs incurred during the period | 819,987 | 444,861 | 442,322 | ||||||||||||
Net change due to revisions in quantity estimates | -672,800 | -220,224 | -1,595,302 | ||||||||||||
Accretion of discount | 1,189,933 | 607,298 | 661,486 | ||||||||||||
Changes in production rates and other | -201,758 | 131,849 | -368,326 | ||||||||||||
Change in the standardized measure of discounted future net cash flows | $612,962 | $5,826,348 | ($541,879) | ||||||||||||
Natural Gas [Member] | |||||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||||
Beginning of year | 3,010,000,000 | 2,571,000,000 | 3,010,000,000 | 2,571,000,000 | 1,675,000,000 | ||||||||||
Revisions of previous estimates | 96,000,000 | -17,000,000 | -559,000,000 | ||||||||||||
Purchases of minerals in place | 1,763,000,000 | 356,000,000 | 1,176,000,000 | ||||||||||||
Extensions, discoveries and other additions | 72,000,000 | 286,000,000 | 407,000,000 | ||||||||||||
Production | -209,000,000 | -162,000,000 | -128,000,000 | ||||||||||||
End of year | 4,255,000,000 | 3,010,000,000 | 4,255,000,000 | 3,010,000,000 | 2,571,000,000 | ||||||||||
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place | 477,000,000 | 24,000,000 | |||||||||||||
Proved developed reserves: | |||||||||||||||
Beginning of year | 2,027,000,000 | 1,661,000,000 | 2,027,000,000 | 1,661,000,000 | 998,000,000 | ||||||||||
End of year | 3,549,000,000 | 2,027,000,000 | 3,549,000,000 | 2,027,000,000 | 1,661,000,000 | ||||||||||
Proved undeveloped reserves: | |||||||||||||||
Beginning of year | 983,000,000 | 910,000,000 | 983,000,000 | 910,000,000 | 677,000,000 | ||||||||||
End of year | 706,000,000 | 983,000,000 | 706,000,000 | 983,000,000 | 910,000,000 | ||||||||||
Oil [Member] | |||||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||||
Beginning of year | 365.6 | 191.5 | 365.6 | 191.5 | 189 | ||||||||||
Revisions of previous estimates | -22.3 | -21.3 | -26.5 | ||||||||||||
Purchases of minerals in place | 50 | 191.1 | 23.1 | ||||||||||||
Extensions, discoveries and other additions | 26.8 | 21.7 | 16.6 | ||||||||||||
Production | -26.6 | -12.2 | -10.7 | ||||||||||||
End of year | 341.8 | 365.6 | 341.8 | 365.6 | 191.5 | ||||||||||
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place | 51.7 | 5.2 | |||||||||||||
Proved developed reserves: | |||||||||||||||
Beginning of year | 252.4 | 131.4 | 252.4 | 131.4 | 124.8 | ||||||||||
End of year | 246 | 252.4 | 246 | 252.4 | 131.4 | ||||||||||
Proved undeveloped reserves: | |||||||||||||||
Beginning of year | 113.2 | 60.1 | 113.2 | 60.1 | 64.2 | ||||||||||
End of year | 95.8 | 113.2 | 95.8 | 113.2 | 60.1 | ||||||||||
NGL [Member] | |||||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||||
Beginning of year | 200 | 179.4 | 200 | 179.4 | 93.5 | ||||||||||
Revisions of previous estimates | -46.8 | -2 | -14.1 | ||||||||||||
Purchases of minerals in place | 71.9 | 17.8 | 75.3 | ||||||||||||
Extensions, discoveries and other additions | 2.9 | 18.5 | 33.7 | ||||||||||||
Production | -12.2 | -10.8 | -9 | ||||||||||||
End of year | 166.3 | 200 | 166.3 | 200 | 179.4 | ||||||||||
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place | 49.5 | 2.9 | |||||||||||||
Proved developed reserves: | |||||||||||||||
Beginning of year | 133.2 | 113 | 133.2 | 113 | 47.8 | ||||||||||
End of year | 132.2 | 133.2 | 132.2 | 133.2 | 113 | ||||||||||
Proved undeveloped reserves: | |||||||||||||||
Beginning of year | 66.8 | 66.4 | 66.8 | 66.4 | 45.7 | ||||||||||
End of year | 34.1 | 66.8 | 34.1 | 66.8 | 66.4 | ||||||||||
[1] | See Note 2 for details about the Company’s acquisitions. | ||||||||||||||
[2] | In accordance with SEC regulations, reserves at December 31, 2014, December 31, 2013, and December 31, 2012, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves. |
Supplemental_Quarterly_Data_Un2
Supplemental Quarterly Data (Unaudited) (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||||||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||||||
Quarterly Financial Data [Abstract] | |||||||||||||||||||
Oil, natural gas and natural gas liquids sales | $766,354 | $937,458 | $967,850 | $938,877 | $584,630 | $537,671 | $488,207 | $462,732 | $3,610,539 | $2,073,240 | $1,601,180 | ||||||||
Total (gains) losses | 1,404,758 | 451,702 | -408,788 | -241,493 | 23,425 | -63,931 | 326,733 | -108,370 | 1,206,179 | 177,857 | 124,762 | ||||||||
Total revenues and other | 2,217,650 | 1,435,115 | 596,951 | 733,587 | 629,208 | 494,562 | 838,825 | 369,060 | 4,983,303 | 2,331,655 | 1,774,240 | ||||||||
Total expenses (1) | 2,533,947 | [1] | 1,320,157 | [1] | 664,452 | [1] | 674,568 | [1] | 1,292,058 | [1] | 420,803 | [1] | 385,540 | [1] | 478,235 | [1] | |||
(Gains) losses on sale of assets and other, net | 338,750 | 35,803 | -5,467 | -2,586 | -10,597 | -827 | 959 | -3,172 | -366,500 | 13,637 | 1,539 | ||||||||
Net loss | ($154,502) | ($4,100) | ($207,870) | ($85,337) | ($784,549) | ($30,060) | $345,157 | ($221,885) | ($451,809) | ($691,337) | ($386,616) | ||||||||
Net loss per unit: | |||||||||||||||||||
Basic | ($0.47) | ($0.02) | ($0.64) | ($0.27) | ($3.15) | ($0.13) | $1.47 | ($0.96) | ($1.40) | ($2.94) | ($1.92) | ||||||||
Diluted | ($0.47) | ($0.02) | ($0.64) | ($0.27) | ($3.15) | ($0.13) | $1.46 | ($0.96) | ($1.40) | ($2.94) | ($1.92) | ||||||||
[1] | Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, depreciation, depletion and amortization, impairment of long-lived assets and taxes, other than income taxes. |