Document_and_Entity_Informatio
Document and Entity Information Document (USD $) | 12 Months Ended | ||||
In Millions, except Share data, unless otherwise specified | Dec. 31, 2013 | Feb. 26, 2014 | Jun. 28, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Document and Entity Information [Abstract] | ' | ' | ' | ' | ' |
Entity Registrant Name | 'BreitBurn Energy Partners L.P. | ' | ' | ' | ' |
Entity Central Index Key | '0001357371 | ' | ' | ' | ' |
Current Fiscal Year End Date | '--12-31 | ' | ' | ' | ' |
Entity Filer Category | 'Large Accelerated Filer | ' | ' | ' | ' |
Document Type | '10-K | ' | ' | ' | ' |
Document Period End Date | 31-Dec-13 | ' | ' | ' | ' |
Document Fiscal Year Focus | '2013 | ' | ' | ' | ' |
Document Fiscal Period Focus | 'FY | ' | ' | ' | ' |
Amendment Flag | 'false | ' | ' | ' | ' |
Entity Common Stock, Shares Outstanding | ' | 119,201,681 | ' | 72,745,000 | 58,522,000 |
Entity Well-known Seasoned Issuer | 'Yes | ' | ' | ' | ' |
Entity Voluntary Filers | 'No | ' | ' | ' | ' |
Entity Current Reporting Status | 'Yes | ' | ' | ' | ' |
Entity Public Float | ' | ' | $1,806.60 | ' | ' |
Consolidated_Balance_Sheets
Consolidated Balance Sheets (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Current assets | ' | ' |
Cash | $2,458 | $4,507 |
Accounts and other receivables, net (note 2) | 96,862 | 67,862 |
Derivative instruments (note 4) | 7,914 | 34,018 |
Related party receivables (note 5) | 2,604 | 1,413 |
Inventory (note 6) | 3,890 | 3,086 |
Prepaid expenses | 3,334 | 2,779 |
Intangible Assets, Net (Excluding Goodwill) | 11,679 | 0 |
Total current assets | 117,062 | 113,665 |
Equity investments (note 7) | 6,641 | 7,004 |
Property, plant and equipment | ' | ' |
Oil and gas properties (note 3) | 4,818,639 | 3,363,946 |
Other properties | 21,338 | 14,367 |
Property, plant and equipment, gross | 4,839,977 | 3,378,313 |
Accumulated depletion and depreciation (note 8) | -924,601 | -666,420 |
Net property, plant and equipment | 3,915,376 | 2,711,893 |
Other long-term assets | ' | ' |
Derivative instruments (note 4) | 71,319 | 55,210 |
Other long-term assets (note 9) | 74,205 | 27,722 |
Total assets | 4,196,282 | 2,915,494 |
Current liabilities | ' | ' |
Accounts payable | 69,809 | 42,497 |
Derivative instruments (note 4) | 24,876 | 5,625 |
Revenue and royalties payable | 26,233 | 22,262 |
Wages and salaries payable | 15,359 | 10,857 |
Accrued interest payable | 19,690 | 13,002 |
Accrued liabilities | 26,922 | 20,997 |
Total current liabilities | 182,889 | 115,240 |
Credit facility (note 10) | 733,000 | 345,000 |
Senior notes, net (note 10) | 1,156,675 | 755,696 |
Deferred Tax Liabilities, Net | 2,749 | 2,487 |
Asset retirement obligation (note 13) | 123,769 | 98,480 |
Derivative instruments (note 4) | 2,560 | 4,393 |
Other long-term liabilities | 4,820 | 4,662 |
Total liabilities | 2,206,462 | 1,325,958 |
Equity | ' | ' |
Partners' equity (note 15) | 1,989,820 | 1,589,536 |
Total liabilities and equity | $4,196,282 | $2,915,494 |
Common units issued and outstanding | 119,170 | 84,668 |
Consolidated_Statements_of_Ope
Consolidated Statements of Operations (USD $) | 12 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Revenues and other income items | ' | ' | ' |
Oil, NGLs and natural gas sales | $660,665 | $413,867 | $394,393 |
Gain (loss) on commodity derivative instruments, net (note 4) | -29,182 | 5,580 | 81,667 |
Other revenue, net (note 7) | 3,175 | 3,548 | 4,310 |
Total revenues and other income items | 634,658 | 422,995 | 480,370 |
Operating costs and expenses | ' | ' | ' |
Operating costs | 262,822 | 195,779 | 165,969 |
Depletion, depreciation and amortization | 216,495 | 137,252 | 106,855 |
Impairments (note 8) | 54,373 | 12,313 | 648 |
General and administrative expenses | 58,707 | 55,465 | 53,200 |
(Gain) loss on sale of assets | 2,015 | -486 | 111 |
Total operating costs and expenses | 590,382 | 401,295 | 326,561 |
Operating income | 44,276 | 21,700 | 153,809 |
Interest expense, net of capitalized interest (note 10) | 87,067 | 61,206 | 39,165 |
Loss on interest rate swaps (note 4) | 0 | 1,101 | 2,777 |
Other expense (income), net | -25 | 48 | -19 |
Income (loss) before taxes | -42,766 | -40,655 | 111,886 |
Income tax expense (note 12) | 905 | 84 | 1,188 |
Net income (loss) | -43,671 | -40,739 | 110,698 |
Less: Net income attributable to noncontrolling interest (note 16) | 0 | -62 | -201 |
Net income (loss) attributable to the partnership | ($43,671) | ($40,801) | $110,497 |
Basic net income (loss) per unit (note 15) (in dollars per unit) | ($0.43) | ($0.56) | $1.80 |
Diluted net income (loss) per unit (note 15) (in dollars per unit) | ($0.43) | ($0.56) | $1.79 |
Consolidated_Statements_of_Cas
Consolidated Statements of Cash Flows (USD $) | 12 Months Ended | |||||
Share data in Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||
Cash flows from operating activities | ' | ' | ' | |||
Net income (loss) | ($43,671,000) | ($40,739,000) | $110,698,000 | |||
Adjustments to reconcile to cash flow from operating activities: | ' | ' | ' | |||
Depletion, depreciation and amortization | 216,495,000 | 137,252,000 | 106,855,000 | |||
Asset Impairment Charges | 54,373,000 | 12,313,000 | 648,000 | |||
Unit-based compensation expense | 19,955,000 | 22,266,000 | 22,043,000 | |||
Derivative, Gain (Loss) on Derivative, Net | -29,182,000 | 4,479,000 | 78,890,000 | |||
Derivative, Cash Received on Hedge | 8,083,000 | 84,615,000 | 17,455,000 | |||
Premiums paid for derivatives | ' | -30,043,000 | 0 | |||
Settlement payments on terminated derivatives | ' | 2,479,000 | 36,779,000 | |||
Settlement payments on terminated derivative instruments | -55,000 | 487,000 | 210,000 | |||
Income from equity affiliates, net | 262,000 | -316,000 | 714,000 | |||
(Gain) loss on sale of assets | 2,015,000 | -486,000 | 111,000 | |||
Other | 5,163,000 | 4,472,000 | -312,000 | |||
Changes in net assets and liabilities | ' | ' | ' | |||
Accounts receivable and other assets | -29,322,000 | 6,759,000 | -17,833,000 | |||
Inventory | -804,000 | 1,638,000 | 2,597,000 | |||
Net change in related party receivables and payables | -1,191,000 | 2,832,000 | 100,000 | |||
Accounts payable and other liabilities | 711,000 | -3,282,000 | 1,148,000 | |||
Net cash provided by operating activities | 257,166,000 | 191,782,000 | 128,543,000 | |||
Cash flows from investing activities | ' | ' | ' | |||
Property acquisitions | -266,308,000 | -135,932,000 | -78,107,000 | |||
Capital expenditures | 2,981,000 | [1] | 1,129,000 | [1] | 2,339,000 | [1] |
Payments for (Proceeds from) Other Investing Activities | -26,661,000 | 0 | 0 | |||
Proceeds from sale of assets | -1,175,817,000 | -562,356,000 | -338,805,000 | |||
Net cash used in investing activities | -1,465,805,000 | -697,159,000 | -414,573,000 | |||
Cash flows from financing activities | ' | ' | ' | |||
Issuance of common units, net | 618,013,000 | 370,234,000 | 99,443,000 | |||
Distributions | -186,868,000 | -132,420,000 | -102,686,000 | |||
Proceeds from issuance of long-term debt, net | 2,276,000,000 | 1,502,885,000 | 661,500,000 | |||
Repayments of long-term debt | -1,487,000,000 | -1,223,000,000 | -369,500,000 | |||
Change in bank overdraft | 2,013,000 | -3,176,000 | 2,636,000 | |||
Debt issuance costs | -15,568,000 | -9,967,000 | -3,665,000 | |||
Net cash provided by financing activities | 1,206,590,000 | 504,556,000 | 287,728,000 | |||
Increase (decrease) in cash | -2,049,000 | -821,000 | 1,698,000 | |||
Cash beginning of period | 4,507,000 | 5,328,000 | 3,630,000 | |||
Cash end of period | $2,458,000 | $4,507,000 | $5,328,000 | |||
[1] | (a) Non-cash investing activities in 2012 were $56 million, reflecting the issuance of approximately 3.01 million Common Units for the AEO Acquisition. |
Consolidated_Statements_of_Par
Consolidated Statements of Partners' Equity (USD $) | Total | Common Units [Member] |
In Thousands, unless otherwise specified | USD ($) | |
Distributions at Dec. 31, 2010 | ($97,590) | ' |
Partners' Equity, beginning balance at Dec. 31, 2010 | 1,208,803 | ' |
Common Units, beginning balance at Dec. 31, 2010 | ' | 53,957 |
Distribution made on common units | ' | 0 |
Increase (Decrease) in Partners' Capital [Roll Forward] | ' | ' |
Distributions paid on unissued units under incentive plans-Shares | ' | 0 |
Distributions paid on unissued units under incentive plans | -5,096 | ' |
Issuance of common units, Common Units | ' | 4,945 |
Issuance of common units, Partners' Equity | 99,443 | ' |
Units issued under incentive plans, Common Units | ' | 962 |
Units issued under incentive plans, Partners' Equity | 11,840 | ' |
Partners' Capital Account, Units, Unit-based Compensation | ' | 0 |
Unit-based compensation | -1,133 | ' |
Partners' Capital Account, Units, Period Increase (Decrease) | ' | 0 |
Net income (loss) attributable to the partnership | 110,497 | ' |
Partners' Equity, ending balance at Dec. 31, 2011 | 1,326,764 | ' |
Common Units, ending balance at Dec. 31, 2011 | ' | 59,864 |
Distributions at Dec. 31, 2011 | -127,748 | ' |
Distribution made on common units | ' | 0 |
Increase (Decrease) in Partners' Capital [Roll Forward] | ' | ' |
Distributions paid on unissued units under incentive plans-Shares | ' | 0 |
Distributions paid on unissued units under incentive plans | -4,672 | ' |
Issuance of common units, Common Units | ' | 20,699 |
Issuance of common units, Partners' Equity | 370,177 | ' |
Common units issued in acquisition, units | ' | 3,014 |
Common units issued in acquisition | 55,691 | ' |
Units issued under incentive plans, Common Units | ' | 1,091 |
Units issued under incentive plans, Partners' Equity | 24,381 | ' |
Partners' Capital Account, Units, Unit-based Compensation | ' | 0 |
Unit-based compensation | -14,314 | ' |
Partners' Capital Account, Units, Period Increase (Decrease) | ' | 0 |
Net income (loss) attributable to the partnership | -40,801 | ' |
Stockholders' Equity, Other Shares | ' | 0 |
Other | 58 | ' |
Partners' Equity, ending balance at Dec. 31, 2012 | 1,589,536 | ' |
Common Units, ending balance at Dec. 31, 2012 | 84,668 | 84,668 |
Distributions at Dec. 31, 2012 | -183,594 | ' |
Distribution made on common units | ' | 0 |
Increase (Decrease) in Partners' Capital [Roll Forward] | ' | ' |
Distributions paid on unissued units under incentive plans-Shares | ' | 0 |
Distributions paid on unissued units under incentive plans | -3,274 | ' |
Issuance of common units, Common Units | 33,925 | ' |
Issuance of common units, Partners' Equity | 617,752 | ' |
Units issued under incentive plans, Common Units | 577 | ' |
Units issued under incentive plans, Partners' Equity | 12,421 | ' |
Partners' Capital Account, Units, Unit-based Compensation | ' | 0 |
Unit-based compensation | 650 | ' |
Partners' Capital Account, Units, Period Increase (Decrease) | ' | 0 |
Net income (loss) attributable to the partnership | -43,671 | ' |
Partners' Equity, ending balance at Dec. 31, 2013 | $1,989,820 | ' |
Common Units, ending balance at Dec. 31, 2013 | 119,170 | ' |
Organization
Organization | 12 Months Ended |
Dec. 31, 2013 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ' |
Organization | ' |
Organization | |
We are a Delaware limited partnership formed on March 23, 2006. Our initial public offering was in October 2006. Pacific Coast Energy Company LP (“PCEC”), formerly BreitBurn Energy Company L.P., was our Predecessor. | |
Our general partner is BreitBurn GP, LLC, a Delaware limited liability company (the “General Partner”), also formed on March 23, 2006. The board of directors of our General Partner has sole responsibility for conducting our business and managing our operations. We conduct our operations through a wholly-owned subsidiary, BreitBurn Operating L.P., (“BOLP”) and BOLP’s general partner BreitBurn Operating GP, LLC (“BOGP”). We own all of the ownership interests in BOLP and BOGP. | |
Our wholly owned subsidiary, BreitBurn Management, manages our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. See Note 5 for information regarding our relationship with BreitBurn Management. Our wholly-owned subsidiary, BreitBurn Finance Corporation, was incorporated on June 1, 2009 under the laws of the State of Delaware. BreitBurn Finance Corporation has no assets or liabilities, and its activities are limited to co-issuing debt securities and engaging in other activities incidental thereto. Our wholly-owned subsidiary, BreitBurn Collingwood Utica LLC (“Utica”) holds certain non-producing oil and gas zones in the Collingwood-Utica shale play in Michigan and is classified as an unrestricted subsidiary under our credit facility. | |
We own 100% of the General Partner, BreitBurn Management, BOLP, BreitBurn Finance Corporation and Utica. | |
As of December 31, 2013, public unitholders owned 99.42% of our Common Units and the Strand Energy Company owned 0.7 million Common Units, representing a 0.58% limited partner interest. |
Summary_of_Significant_Account
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2013 | |
Accounting Policies [Abstract] | ' |
Summary of Significant Accounting Policies | ' |
2. Summary of Significant Accounting Policies | |
Principles of consolidation and basis of presentation | |
The consolidated financial statements include our accounts and the accounts of our wholly owned subsidiaries. Investments in affiliated companies with a 20% or greater ownership interest, and in which we have significant influence but do not have control, are accounted for on an equity basis. Investments in affiliated companies with less than a 20% ownership interest, and in which we do not have control, are accounted for on the cost basis. Investments in which we own greater than a 50% interest and in which we have control are consolidated. Investments in which we own less than a 50% interest but are deemed to have control, or where we have a variable interest in an entity in which we will absorb a majority of the entity’s expected losses or receive a majority of the entity’s expected residual returns or both, however, are consolidated. The effects of all intercompany transactions have been eliminated. | |
Certain reclassifications have been made to our 2012 and 2011 consolidated financial statements in order to conform them to the 2013 presentation. These reclassifications were not material to the financial statements | |
Use of estimates | |
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The financial statements are based on a number of significant estimates including acquisition purchase price allocations, fair value of derivative instruments, unit-based compensation and oil and gas reserve quantities, which are the basis for the calculation of depletion, depreciation and amortization (“DD&A”), asset retirement obligations and impairment of oil and gas properties. | |
Business segment information | |
We report our operations in one segment because our oil and gas operating areas have similar economic characteristics. We acquire, exploit, develop and produce oil and natural gas in the United States. Corporate management administers all properties as a whole rather than as discrete operating segments. Operational data is tracked by area; however, financial performance is measured as a single enterprise and not on an area-by-area basis. Allocation of capital resources is employed on a project-by-project basis across our entire asset base to maximize profitability without regard to individual areas. | |
Revenue recognition | |
We recognize revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred, (iii) the seller’s price to the buyer is fixed or determinable and (iv) collectability is reasonably assured. | |
Revenues from properties in which we have an interest with other partners are recognized on the basis of our working interest (“entitlement” method of accounting). We generally market most of our natural gas production from our operated properties and pay our partners for their working interest shares of natural gas production sold. As a result, we have no material natural gas producer imbalance positions. | |
Accounts receivable | |
Our accounts receivable are primarily from purchasers of oil and natural gas and counterparties to our financial instruments. Oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. At December 31, 2013 and 2012, we had an allowance for doubtful accounts receivable of $0.6 million and $0.6 million, respectively. | |
Inventory | |
Our inventory consists of oil held in storage tanks related to our Florida operations pending shipment by barge to the point of sale. Oil inventories are carried at the lower of cost to produce or market price. We match production expenses with oil sales. Production expenses associated with unsold oil inventory are recorded as inventory. | |
Investments in equity affiliates | |
Income from equity affiliates is included as a component of operating income, as the operations of these affiliates are associated with the processing and transportation of our natural gas production. | |
Property, plant and equipment | |
Oil and gas properties | |
We follow the successful efforts method of accounting. Lease acquisition and development costs (tangible and intangible) incurred relating to proved oil and gas properties are capitalized. Delay and surface rentals are charged to expense as incurred. Dry hole costs incurred on exploratory wells are expensed. Dry hole costs associated with developing proved fields are capitalized. Geological and geophysical costs related to exploratory operations are expensed as incurred. | |
The Partnership carries out tertiary recovery methods on certain of its oil and gas properties in Oklahoma in order to recover additional hydrocarbons that are not recoverable from primary or secondary recovery methods. Acquisition costs of tertiary injectants, such as purchased CO2, for enhanced oil recovery (“EOR”) activities that are used prior to the recognition of proved tertiary recovery reserves are expensed as incurred. After a project has been determined to be technically feasible and economically viable, all acquisition costs of tertiary injectants are capitalized as development costs and depleted, as they are incurred solely for obtaining access to reserves not otherwise recoverable and have future economic benefits over the life of the project. As CO2 is recovered together with oil and gas production, it is extracted and re-injected, and all the associated CO2 recycling costs are expensed as incurred. Likewise, other costs incurred to maintain reservoir pressure are also expensed. | |
Upon sale or retirement of proved properties, the cost thereof and the DD&A are removed from the accounts and any gain or loss is recognized in the statement of operations. Maintenance and repairs are charged to operating expenses. DD&A of proved oil and gas properties, including the estimated cost of future abandonment and restoration of well sites and associated facilities, is generally computed on a field-by-field basis where applicable and recognized using the units of production method net of any anticipated proceeds from equipment salvage and sale of surface rights. Other gathering and processing facilities are recorded at cost and are depreciated using the straight-line method over their estimated useful lives, generally over 20 years. | |
We capitalize interest costs to oil and gas properties on expenditures made in connection with major projects and the drilling and completion of new oil and natural gas wells. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the units of production method. During 2013, 2012 and 2011, interest of $0.1 million, $0.1 million and $0.1 million, respectively, was capitalized and included in our capital expenditures. | |
Non-oil and gas assets | |
Buildings and non-oil and gas assets are recorded at cost and depreciated using the straight-line method over their estimated useful lives, which range from three to ten years. | |
Oil and natural gas reserve quantities | |
Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion are made concurrently with changes to reserve estimates. We disclose reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with the Securities and Exchange Commission (the “SEC”) guidelines. The independent engineering firms adhere to the SEC definitions when preparing their reserve reports. | |
Asset retirement obligations | |
We have significant obligations to plug and abandon oil and natural gas wells and related equipment at the end of oil and natural gas production operations. The fair value of a liability for an asset retirement obligation (“ARO”) is recorded when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. Over time, changes in the present value of the liability are accreted and recorded as part of DD&A on the consolidated statements of operations. The capitalized asset costs are depreciated over the useful lives of the corresponding asset. Recognized liability amounts are based upon future retirement cost estimates and incorporate many assumptions such as: (1) expected economic recoveries of oil and natural gas, (2) time to abandonment, (3) future inflation rates and (4) the risk free rate of interest adjusted for our credit costs. Future revisions to ARO estimates will impact the present value of existing ARO liabilities and corresponding adjustments will be made to the capitalized asset retirement costs balance. | |
Impairment of assets | |
Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. A long-lived asset is tested for impairment periodically and when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is generally determined from estimated discounted future net cash flows. For purposes of performing an impairment test, the undiscounted future cash flows are based on total proved and risk-adjusted probable and possible reserves, and are forecast using five-year NYMEX forward strip prices at the end of the period and escalated along with expenses and capital starting year six and thereafter at 2.5% per year. For impairment charges, the associated property’s expected future net cash flows are discounted using a weighted average cost of capital which approximated 10% at December 31, 2013. Reserves are calculated based upon reports from third party engineers adjusted for acquisitions or other changes occurring during the year as determined to be appropriate in the good faith judgment of management. Unproved properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred. | |
We assess our long-lived assets for impairment generally on a field-by-field basis where applicable. See Note 8 for a discussion of our impairments. | |
Debt issuance costs | |
The costs incurred to obtain financing have been capitalized. Debt issuance costs are amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the effective interest method of amortization. | |
Equity-based compensation | |
BreitBurn Management has various forms of equity-based compensation outstanding under employee compensation plans that are described more fully in Note 17. Awards classified as equity are valued on the grant date and are recognized as compensation expense over the vesting period, which is part of the general and administrative (“G&A”) expenses line on the Consolidated Statements of Operations. We recognize equity-based compensation costs on a straight line basis over the annual vesting periods. | |
Fair market value of financial instruments | |
The carrying amount of our cash, accounts receivable, accounts payable, related party receivables and payables and accrued expenses approximate their respective fair value due to the relatively short term of the related instruments. The carrying amount of long-term debt under our credit facility approximates fair value; however, changes in the credit markets may impact our ability to enter into future credit facilities at similar terms. See Note 10 for the fair value of our Senior Notes under long-term debt. | |
Accounting for business combinations | |
We account for all business combinations using the acquisition method. Under the acquisition method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, equity or the assumption of liabilities. The assets and liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if material, is recognized as a gain at the time of acquisition. Similarly, the deficit of the fair value of assets acquired and liabilities assumed under the cost of an acquired entity, if material, is recognized as goodwill at the time of acquisition. All purchase price allocations are finalized within one year from the acquisition date. | |
Concentration of credit risk | |
We maintain our cash accounts primarily with a single bank and invest cash in money market accounts, which we believe to have minimal risk. At times, such balances may be in excess of the Federal Insurance Corporation insurance limit. As operator of jointly owned oil and gas properties, we sell oil and gas production to U.S. oil and gas purchasers and pay vendors on behalf of joint owners for oil and gas services. We periodically monitor our major purchasers’ credit ratings. We enter into commodity and interest rate derivative instruments. Our derivative counterparties are all lenders under our credit facility, and we periodically monitor their credit ratings. | |
Derivatives | |
Financial Accounting Standards Board (“FASB”) Accounting Standards establish accounting and reporting requirements for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities. These standards require recognition of all derivative instruments as assets or liabilities on our balance sheet and measurement of those instruments at fair value. The accounting treatment of changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge and if so, the type of hedge. We currently do not designate any of our derivatives as hedges for financial accounting purposes. Gains and losses on derivative instruments not designated as hedges are currently included in earnings. The resulting cash flows are reported as cash from operating activities. | |
Fair value measurement is based upon a hypothetical transaction to sell an asset or transfer a liability at the measurement date. The objective of fair value measurement is to determine the price that would be received in selling the asset or transferring the liability in an orderly transaction between market participants at the measurement date. If we have a principal market for the asset or liability, the fair value measurement shall represent the price in that market, otherwise the price will be determined based on the most advantageous market. | |
Income taxes | |
Our subsidiaries are mostly partnerships or limited liability companies treated as partnerships for federal tax purposes with essentially all taxable income or loss being passed through to the members. As such, no federal income tax for these entities has been provided. | |
We have three wholly-owned subsidiaries that are subject to corporate income taxes. Deferred income taxes are recorded under the asset and liability method. Where material, deferred income tax assets and liabilities are computed for differences between the financial statement and income tax bases of assets and liabilities that will result in taxable or deductible amounts in the future. Such deferred income tax asset and liability computations are based on enacted tax laws and rates applicable to periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable or refundable for the period plus or minus the change during the period in deferred income tax assets and liabilities. | |
FASB Accounting Standards clarify the accounting for uncertainty in income taxes recognized in a company’s financial statements. A company can only recognize an uncertain tax position in the financial statements if the position is more-likely-than-not to be upheld on audit based only on the technical merits of the tax position. This accounting standard also provides guidance on thresholds, measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition that is intended to provide better financial-statement comparability among different companies. | |
We performed analysis as of December 31, 2013 and 2012 and concluded that there were no uncertain tax positions requiring recognition in our financial statements. | |
Net Income or loss per unit | |
FASB Accounting Standards require use of the “two-class” method of computing earnings per unit for all periods presented. The “two-class” method is an earnings allocation formula that determines earnings per unit for each class of Common Unit and participating security as if all earnings for the period had been distributed. Unvested restricted unit awards that earn non-forfeitable dividend rights qualify as participating securities and, accordingly, are included in the basic computation. Our unvested restricted phantom units (“RPUs”) and convertible phantom units (“CPUs”) participate in dividends on an equal basis with Common Units; therefore, there is no difference in undistributed earnings allocated to each participating security. Accordingly, our calculation is prepared on a combined basis and is presented as net income (loss) per Common Unit. See Note 15 for our earnings per Common Unit calculation. | |
Environmental expenditures | |
We review, on an annual basis, our estimates of the cleanup costs of various sites. When it is probable that obligations have been incurred and where a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued. At December 31, 2013, we had a $2.2 million undiscounted environmental liability accrued that included cost estimates related to the maintenance of ground water monitoring wells associated with certain former well sites in Michigan that are no longer producing. At December 31, 2012, we had a $1.9 million undiscounted environmental liability accrued. | |
Accounting Standards | |
There were no new accounting standards issued but not yet effective that are expected to have a material impact on our financial position, results of operations or cash flows. |
Acquisitions
Acquisitions | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Business Combinations [Abstract] | ' | ||||||||||||
Acquisitions | ' | ||||||||||||
3. Acquisitions | |||||||||||||
We account for all business combinations using the acquisition method of accounting. The initial accounting applied to our acquisitions at the time of the purchase may not be complete and adjustment to provisional accounts, 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 date prior to concluding on the final purchase price of an acquisition. | |||||||||||||
Our purchase price allocations are based on discounted cash flows, quoted market prices and estimates made by management, and the most significant assumptions are those related to the estimated fair values assigned to oil and natural gas properties with proved and unproved reserves. To estimate the fair values of acquired properties, estimates of oil and natural gas reserves are prepared by management in consultation with independent engineers. We apply estimated future prices to the estimated reserve quantities acquired, and estimate future operating and development costs to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted average cost of capital. We also periodically employ third-party valuation firms to assist in the valuation of complex facilities, including pipelines, gathering lines and processing facilities. | |||||||||||||
We conducted assessments of net assets acquired and recognized certain amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values. Transaction and integration costs associated with our acquisitions are expensed as incurred. | |||||||||||||
The fair value measurements of oil and natural gas properties, other assets and ARO are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties, other assets and ARO 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 reserves, future operating and development costs, future commodity prices, estimated future cash flows and a market-based weighted average cost of capital rate. ARO assumptions include inputs such as expected economic recoveries of oil and natural gas, time to abandonment. These inputs require significant judgments and estimates by management at the time of the valuation and are subject to change. | |||||||||||||
2013 Acquisitions | |||||||||||||
Oklahoma Panhandle Acquisitions | |||||||||||||
On July 15, 2013, we completed the acquisition of certain oil and natural gas and midstream assets located in Oklahoma, New Mexico and Texas, certain carbon dioxide (“CO2”) supply contracts, certain oil swaps and interests in certain entities from Whiting Oil and Gas Corporation (“Whiting”) for approximately $845 million in cash (the “Whiting Acquisition”), including post-closing adjustments. We used borrowings under our credit facility to fund this acquisition. The purchase price for this acquisition was allocated to the assets acquired and liabilities assumed as follows: | |||||||||||||
Thousands of dollars | |||||||||||||
Oil and gas properties - proved | $ | 700,963 | |||||||||||
Oil and gas properties - unproved | 43,492 | ||||||||||||
Pipeline and processing facilities | 74,537 | ||||||||||||
Derivative assets - current | 15 | ||||||||||||
Intangibles | 14,739 | ||||||||||||
Derivative assets - long-term | 16,183 | ||||||||||||
Other long-term assets | 10,936 | ||||||||||||
Derivative liabilities - current | (6,347 | ) | |||||||||||
Accrued liabilities | (1,115 | ) | |||||||||||
Asset retirement obligation | (8,102 | ) | |||||||||||
$ | 845,301 | ||||||||||||
Whiting novated to us derivative contracts, with a counterparty that is a participant in our current credit facility, consisting of NYMEX West Texas Intermediate (“WTI”) fixed price oil swaps covering a total of approximately 5.4 million barrels of future production in 2013 and extending through 2016 at a weighted average hedge price of $95.44 per Bbl, which were valued as a net asset of $9.9 million at the acquisition date. The purchase price allocation also included finite-lived intangibles valued at $14.7 million relating to two CO2 purchase contracts that we received in the acquisition. An intangible asset was established to value the portion of the CO2 contracts that were above market at closing in the purchase price allocation. We amortize the CO2 contracts based on the amount of CO2 purchases made in each period over the contracts’ respective lives. We were also novated a $10.9 million long-term advance balances relating to future CO2 supply contract arrangements. The $10.9 million long-term advance was reflected on the initial purchase price of $835.4 million, included in our third quarter 2013 10-Q, as $1.0 million. See Note 9 for further details on the intangibles and other long-term assets acquired. | |||||||||||||
We also completed the acquisition of additional interests in certain of the acquired assets in the Oklahoma Panhandle from other sellers than Whiting for an additional $30 million in July 2013 (together with the Whiting Acquisition, the “Oklahoma Panhandle Acquisitions”). The additional interests were allocated $17.8 million to oil and gas properties and $12.4 million to pipeline facilities. | |||||||||||||
Acquisition-related costs for the Oklahoma Panhandle Acquisitions were $3.2 million for the year ended December 31, 2013 and are reflected in G&A expenses on the consolidated statements of operations. For the year ended December 31, 2013, we recorded $104.9 million in sales revenue and $29.9 million in lease operating expenses, including production and property taxes, from our Oklahoma Panhandle Acquisitions. | |||||||||||||
Permian Basin Acquisitions | |||||||||||||
On December 30, 2013, we completed acquisitions of oil and natural gas properties located in the Permian Basin in Texas from CrownRock, L.P. for approximately $282 million in cash (the “CrownRock III Acquisition”). We also completed the acquisition of additional interests in certain of the acquired assets in the Permian Basin from other sellers for an additional $20 million in December 2013 (together with the CrownRock III Acquisition, the “2013 Permian Basin Acquisitions”). The preliminary purchase price for 2013 Permian Acquisitions was allocated to the assets acquired and liabilities assumed as follows: | |||||||||||||
Thousands of dollars | |||||||||||||
Oil and gas properties - proved | $ | 258,728 | |||||||||||
Oil and gas properties - unproved | 44,451 | ||||||||||||
Asset retirement obligation | $ | (1,069 | ) | ||||||||||
$ | 302,110 | ||||||||||||
Acquisition-related costs for the 2013 Permian Basin Acquisitions were $0.1 million for the year ended December 31, 2013 and are reflected in G&A expenses on the consolidated statements of operations. For the year ended December 31, 2013, we recorded two days of sales revenue less lease operating expenses and production and property taxes, which was a net revenue of $0.2 million from our 2013 Permian Basin Acquisitions. | |||||||||||||
2012 Acquisitions | |||||||||||||
NiMin Acquisition | |||||||||||||
In June 2012, we completed the acquisition of oil properties located in Park County in the Bighorn Basin of | |||||||||||||
Wyoming from Legacy Energy, Inc., a wholly-owned subsidiary of NiMin Energy Corp. (the “NiMin Acquisition”). The final purchase price for this acquisition was approximately $95 million in cash, which was primarily allocated to oil and natural gas properties (including $36.2 million in unproved properties) and included $1.7 million of ARO. Acquisition-related costs for the NiMin Acquisition were $0.4 million and are reflected in G&A expenses on the consolidated statements of operations. Revenues and expenses from the NiMin properties are reflected in our consolidated statements of operations beginning June 28, 2012. For the year ended December 31, 2013 and 2012, we recorded $15.2 million and $6.6 million, respectively, in sales revenue and $6.1 million and $3.2 million, respectively, in lease operating expenses, including production and property taxes, from our NiMin properties. | |||||||||||||
Permian Basin Acquisitions | |||||||||||||
On July 2, 2012, we completed acquisitions of oil and natural gas properties located in the Permian Basin in Texas from Element Petroleum, LP and CrownRock, L.P. for approximately $148 million and $70 million, respectively. On December 28, 2012, we completed the acquisition of oil and natural gas properties located in the Permian Basin in Texas from CrownRock, L.P., Lynden USA Inc. and Piedra Energy I, LLC for approximately $164 million, $25 million and $10 million, respectively. The final purchase price for each of the 2012 acquisitions in the Permian Basin was primarily allocated to oil and natural gas properties, including $52.5 million of unproved oil and gas properties, with $44.3 million related to the Element Petroleum, LP acquisition and $8.2 million related to the first CrownRock, L.P., acquisition. Acquisition-related costs for the July 2012 Permian Basin acquisitions were $1.0 million and were recorded in G&A expenses on the consolidated statements of operations. Acquisition-related costs for the December 2012 Permian Basin acquisitions were $0.5 million and were recorded in G&A expenses on the consolidated statements of operations. For the year ended December 31, 2013 and December 31, 2012, we recorded $88.3 million and $19.1 million, respectively, in sales revenue and $19.0 million and $3.8 million, respectively, in lease operating expenses, including production and property taxes, from our Permian Basin properties. | |||||||||||||
AEO Acquisition | |||||||||||||
On November 30, 2012, we completed the acquisition of principally oil properties from American Energy Operations, Inc. (“AEO”) located in the Belridge Field in Kern County, California (the “AEO Acquisition”), with an effective date of November 1, 2012, for approximately $38 million in cash and 3.01 million Common Units. Of the final purchase price of $38 million in cash and $56 million in Common Units, $97.8 million was allocated to proved oil properties, and 4.0 million was allocated to ARO as follows: | |||||||||||||
Thousands of dollars | |||||||||||||
Oil and gas properties - proved | $ | 97,814 | |||||||||||
Asset retirement obligation | (4,014 | ) | |||||||||||
Net assets acquired | $ | 93,800 | |||||||||||
Acquisition-related costs for the AEO Acquisition were $0.4 million and were recorded in G&A expenses on the consolidated statements of operations beginning December 1, 2012. For the year ended December 31, 2013 and December 31, 2012, we recorded $36.8 million and $2.6 million in sales revenue, respectively, and $7.2 million and $0.6 million in lease operating expenses, including production and property taxes, respectively, from the properties acquired in the AEO Acquisition. | |||||||||||||
2011 Acquisitions | |||||||||||||
On July 28, 2011, we completed the acquisition of oil properties in the Powder River Basin in eastern Wyoming with an effective date of July 1, 2011 (the “Greasewood Acquisition”). We used borrowings under our credit facility to fund the Greasewood Acquisition. The final purchase price for the acquisition was approximately $57 million in cash, which was primarily allocated to proved oil properties. Acquisition-related costs for the Greasewood Acquisition were $0.1 million and were reflected in G&A expenses on the consolidated statements of operations. In 2011, we recorded $7.4 million in sales revenue and $1.9 million in lease operating expenses, including production and property taxes, from the properties acquired in the Greasewood Acquisition. | |||||||||||||
On October 6, 2011, we completed the acquisition of oil and gas properties from Cabot Oil & Gas Corporation located primarily in the Evanston and Green River Basins in southwestern Wyoming (the “Cabot Acquisition”), with an effective date of September 1, 2011. We used borrowings under our credit facility to fund the Cabot Acquisition. The assets acquired also include limited acreage and non-operated oil and gas interests in Colorado and Utah. The final purchase price of $281 million was allocated to the assets acquired and liabilities assumed as follows: | |||||||||||||
Thousands of dollars | |||||||||||||
Accounts receivable | $ | 767 | |||||||||||
Oil and gas properties | 294,500 | ||||||||||||
Accounts payable | (197 | ) | |||||||||||
Revenue and royalties payable | (798 | ) | |||||||||||
Asset retirement obligation | (10,845 | ) | |||||||||||
Other long-term liabilities | (2,820 | ) | |||||||||||
$ | 280,607 | ||||||||||||
Acquisition-related costs for the Cabot Acquisition were $0.6 million and were recorded in G&A expenses on the consolidated statements of operations. In 2011, we recorded $9.1 million in sales revenue and $3.9 million in lease operating expenses, including production and property taxes, from the properties acquired in the Cabot Acquisition. | |||||||||||||
Pro Forma (unaudited) | |||||||||||||
The following unaudited pro forma financial information presents a summary of our combined statements of operations for the years ended December 31, 2013, 2012, and 2011 assuming: (i) the Whiting Acquisition and additional acquired assets in the Oklahoma Panhandle acquisitions and the 2013 Permian Basin Acquisitions were completed on January 1, 2012, and (ii) the AEO Acquisition, the NiMin Acquisition, the 2012 acquisitions from Element Petroleum, LP, CrownRock, L.P., Piedra Energy I, LLC and Lynden USA Inc. and the Cabot Acquisition were completed on January 1, 2011. The pro forma results reflect the results of combining our statements of operations with the results of operations from all of our 2012 and 2013 acquisitions, adjusted for (1) the assumption of ARO and accretion expense for the properties acquired, (2) depletion and depreciation expense applied to the adjusted purchase price of the properties acquired, and (3) interest expense on additional borrowings necessary to finance the acquisitions, including the amortization of debt issuance costs. The pro forma financial information is not necessarily indicative of the results of operations if these acquisitions had been effective January 1, 2012 or 2011. | |||||||||||||
Pro Forma Year Ended December 31, | |||||||||||||
Thousands of dollars, except per unit amounts | 2013 | 2012 | 2011 | ||||||||||
Revenues | $ | 828,483 | $ | 781,342 | $ | 615,310 | |||||||
Net income (loss) attributable to the partnership | 27,518 | 85,594 | 146,992 | ||||||||||
Net income (loss) per common unit: | |||||||||||||
Basic | $ | 0.23 | $ | 0.73 | $ | 1.71 | |||||||
Diluted | $ | 0.23 | $ | 0.71 | $ | 1.71 | |||||||
Financial_Instruments_and_Fair
Financial Instruments and Fair Value Measurements | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
Financial Instruments [Abstract] | ' | ||||||||||||||||||||||||
Financial Instruments and Fair Value Measurement | ' | ||||||||||||||||||||||||
Financial Instruments and Fair Value Measurements | |||||||||||||||||||||||||
Our risk management programs are intended to reduce our exposure to commodity prices and interest rates and to assist with stabilizing cash flows. | |||||||||||||||||||||||||
Commodity Activities | |||||||||||||||||||||||||
Due to the historical volatility of oil and natural gas prices, we have entered into various derivative instruments to manage exposure to volatility in the market price of oil and natural gas to achieve more predictable cash flows. We use swaps, collars and options for managing risk relating to commodity prices. All contracts are settled with cash and do not require the delivery of physical volumes to satisfy settlement. While this strategy may result in us having lower revenues than we would otherwise have if we had not utilized these instruments in times of higher oil and natural gas prices, management believes that the resulting reduced volatility of prices and cash flow is beneficial. While our commodity price risk management program is intended to reduce our exposure to commodity prices and assist with stabilizing cash flow and distributions, to the extent we have hedged a significant portion of our expected production and the cost for goods and services increases, our margins would be adversely affected. | |||||||||||||||||||||||||
The derivative instruments we utilize are based on index prices that may and often do differ from the actual oil and natural gas prices realized in our operations. These variations often result in a lack of adequate correlation to enable these derivative instruments to qualify for cash flow hedges under FASB Accounting Standards. Accordingly, we do not attempt to account for our derivative instruments as cash flow hedges for financial accounting purposes and instead recognize changes in the fair value immediately in earnings. | |||||||||||||||||||||||||
We had the following oil contracts in place at December 31, 2013: | |||||||||||||||||||||||||
Year | |||||||||||||||||||||||||
2014 | 2015 | 2016 | 2017 | 2018 | |||||||||||||||||||||
Oil Positions: | |||||||||||||||||||||||||
Fixed Price Swaps - NYMEX WTI | |||||||||||||||||||||||||
Volume (Bbl/d) | 13,814 | 12,689 | 9,211 | 7,971 | 493 | ||||||||||||||||||||
Average Price ($/Bbl) | $ | 92.3 | $ | 93.01 | $ | 86.73 | $ | 84.23 | $ | 82.2 | |||||||||||||||
Fixed Price Swaps - ICE Brent | |||||||||||||||||||||||||
Volume (Bbl/d) | 4,800 | 3,300 | 4,300 | 298 | — | ||||||||||||||||||||
Average Price ($/Bbl) | $ | 98.88 | $ | 97.73 | $ | 95.17 | $ | 97.5 | $ | — | |||||||||||||||
Collars - NYMEX WTI | |||||||||||||||||||||||||
Volume (Bbl/d) | 1,000 | 1,000 | — | — | — | ||||||||||||||||||||
Average Floor Price ($/Bbl) | $ | 90 | $ | 90 | $ | — | $ | — | $ | — | |||||||||||||||
Average Ceiling Price ($/Bbl) | $ | 112 | $ | 113.5 | $ | — | $ | — | $ | — | |||||||||||||||
Collars - ICE Brent | |||||||||||||||||||||||||
Volume (Bbl/d) | — | 500 | 500 | — | — | ||||||||||||||||||||
Average Floor Price ($/Bbl) | $ | — | $ | 90 | $ | 90 | $ | — | $ | — | |||||||||||||||
Average Ceiling Price ($/Bbl) | $ | — | $ | 109.5 | $ | 101.25 | $ | — | $ | — | |||||||||||||||
Puts - NYMEX WTI | |||||||||||||||||||||||||
Volume (Bbl/d) | 500 | 500 | 1,000 | — | — | ||||||||||||||||||||
Average Price ($/Bbl) | $ | 90 | $ | 90 | $ | 90 | $ | — | $ | — | |||||||||||||||
Total: | |||||||||||||||||||||||||
Volume (Bbl/d) | 20,114 | 17,989 | 15,011 | 8,269 | 493 | ||||||||||||||||||||
Average Price ($/Bbl) | $ | 93.7 | $ | 93.54 | $ | 89.48 | $ | 84.71 | $ | 82.2 | |||||||||||||||
We had the following natural gas contracts in place at December 31, 2013: | |||||||||||||||||||||||||
Year | |||||||||||||||||||||||||
2014 | 2015 | 2016 | 2017 | 2018 | |||||||||||||||||||||
Gas Positions: | |||||||||||||||||||||||||
Fixed Price Swaps - MichCon City-Gate | |||||||||||||||||||||||||
Volume (MMBtu/d) | 7,500 | 7,500 | 17,000 | 10,000 | — | ||||||||||||||||||||
Average Price ($/MMBtu) | $ | 6 | $ | 6 | $ | 4.46 | $ | 4.48 | $ | — | |||||||||||||||
Fixed Price Swaps - Henry Hub | |||||||||||||||||||||||||
Volume (MMBtu/d) | 41,600 | 47,700 | 24,700 | 8,571 | 1,870 | ||||||||||||||||||||
Average Price ($/MMBtu) | $ | 4.75 | $ | 4.77 | $ | 4.23 | $ | 4.39 | $ | 4.15 | |||||||||||||||
Puts - Henry Hub | |||||||||||||||||||||||||
Volume (MMBtu/d) | 6,000 | 1,500 | — | — | — | ||||||||||||||||||||
Average Price ($/MMBtu) | $ | 5 | $ | 5 | $ | — | $ | — | $ | — | |||||||||||||||
Total: | |||||||||||||||||||||||||
Volume (MMBtu/d) | 55,100 | 56,700 | 41,700 | 18,571 | 1,870 | ||||||||||||||||||||
Average Price ($/MMBtu) | $ | 4.95 | $ | 4.94 | $ | 4.32 | $ | 4.44 | $ | 4.15 | |||||||||||||||
Calls - Henry Hub | |||||||||||||||||||||||||
Volume (MMBtu/d) | — | 15,000 | — | — | — | — | |||||||||||||||||||
Average Price ($/MMBtu) | — | $ | 9 | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
Deferred Premium ($/MMBtu) | $ | 0.12 | $ | — | $ | — | $ | — | $ | — | |||||||||||||||
During the year ended December 31, 2013, we did not enter into any derivative instruments that required prepaid premiums. During the year ended December 31, 2012, we paid $23.0 million and $7.0 million in premiums on oil and natural gas derivative instruments, respectively, that related to future periods. | |||||||||||||||||||||||||
During the year ended December 31, 2013 and 2012, $4.9 million and $0.9 million, respectively, of premiums paid in 2012 related to oil and gas derivatives settled. As of December 31, 2013, premiums paid in 2012 related to oil and natural gas derivatives to be settled in 2014 and beyond were as follows: | |||||||||||||||||||||||||
Year | |||||||||||||||||||||||||
Thousands of dollars | 2014 | 2015 | 2016 | 2017 | 2018 | ||||||||||||||||||||
Oil | $ | 4,479 | $ | 4,683 | $ | 7,438 | $ | 734 | $ | — | |||||||||||||||
Natural gas | $ | 4,015 | $ | 1,989 | $ | 952 | $ | — | $ | — | |||||||||||||||
Interest Rate Activities | |||||||||||||||||||||||||
We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. As of December 31, 2013 and 2012, we had no interest rate swaps in place. In order to mitigate our interest rate exposure, we had the following interest rate swaps, indexed to 1-month LIBOR, in place at December 31, 2011, to fix a portion of floating LIBOR-base debt under our credit facility. As of December 31, 2011, we had an interest rate swap covering January 1, 2012 to December 20, 2012 for $100 million at a fixed rate of 1.1550% and an interest rate swap covering January 20, 2012 to January 20, 2014 for $100 million at 2.4800%. The first contract expired in December 2012. In the fourth quarter of 2012, we terminated the second contract and realized a loss of $2.5 million. We did not designate these interest rate derivatives as hedges for financial accounting purposes. | |||||||||||||||||||||||||
Fair Value of Financial Instruments | |||||||||||||||||||||||||
FASB Accounting Standards require disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedge items are accounted for, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. The required disclosures are detailed below. | |||||||||||||||||||||||||
Fair value of derivative instruments not designated as hedging instruments: | |||||||||||||||||||||||||
Balance sheet location, thousands of dollars | Oil Commodity Derivatives | Natural Gas Commodity Derivatives | Commodity Derivatives Netting (a) | Total Financial Instruments | |||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||||
Assets | |||||||||||||||||||||||||
Current assets - derivative instruments | $ | 4,373 | $ | 15,419 | $ | (11,878 | ) | $ | 7,914 | ||||||||||||||||
Other long-term assets - derivative instruments | 59,412 | 23,750 | (11,843 | ) | 71,319 | ||||||||||||||||||||
Total assets | 63,785 | 39,169 | (23,721 | ) | 79,233 | ||||||||||||||||||||
Liabilities | |||||||||||||||||||||||||
Current liabilities - derivative instruments | (35,634 | ) | (1,120 | ) | 11,878 | (24,876 | ) | ||||||||||||||||||
Long-term liabilities - derivative instruments | (13,620 | ) | (783 | ) | 11,843 | (2,560 | ) | ||||||||||||||||||
Total liabilities | (49,254 | ) | (1,903 | ) | 23,721 | (27,436 | ) | ||||||||||||||||||
Net assets | $ | 14,531 | $ | 37,266 | $ | — | $ | 51,797 | |||||||||||||||||
As of December 31, 2012 | |||||||||||||||||||||||||
Assets | |||||||||||||||||||||||||
Current assets - derivative instruments | $ | 4,270 | $ | 46,724 | $ | (16,976 | ) | $ | 34,018 | ||||||||||||||||
Other long-term assets - derivative instruments | 38,919 | 33,443 | (17,152 | ) | 55,210 | ||||||||||||||||||||
Total assets | 43,189 | 80,167 | (34,128 | ) | 89,228 | ||||||||||||||||||||
Liabilities | |||||||||||||||||||||||||
Current liabilities - derivative instruments | (21,665 | ) | (936 | ) | 16,976 | (5,625 | ) | ||||||||||||||||||
Long-term liabilities - derivative instruments | (18,769 | ) | (2,776 | ) | 17,152 | (4,393 | ) | ||||||||||||||||||
Total liabilities | (40,434 | ) | (3,712 | ) | 34,128 | (10,018 | ) | ||||||||||||||||||
Net assets (liabilities) | $ | 2,755 | $ | 76,455 | $ | — | $ | 79,210 | |||||||||||||||||
(a) Represents counterparty netting under derivative netting agreements - these contracts are reflected net on the balance sheet. | |||||||||||||||||||||||||
Gains and losses on derivative instruments not designated as hedging instruments: | |||||||||||||||||||||||||
Location of gain/loss, thousands of dollars | Oil Commodity Derivatives (a) | Natural Gas Commodity Derivatives (a) | Interest Rate Derivatives (b) | Total Financial Instruments | |||||||||||||||||||||
Year Ended December 31, 2013 | |||||||||||||||||||||||||
Net gain (loss) | $ | (34,259 | ) | $ | 5,077 | $ | — | $ | (29,182 | ) | |||||||||||||||
Year Ended December 31, 2012 | |||||||||||||||||||||||||
Net gain (loss) | $ | (15,752 | ) | $ | 21,332 | $ | (1,101 | ) | $ | 4,479 | |||||||||||||||
Year Ended December 31, 2011 | |||||||||||||||||||||||||
Net gain (loss) | $ | 32 | $ | 81,635 | $ | (2,777 | ) | $ | 78,890 | ||||||||||||||||
(a) Included in gain (loss) on commodity derivative instruments, net on the consolidated statements of operations. | |||||||||||||||||||||||||
(b) Included in loss on interest rate swaps on the consolidated statements of operations included in gain (loss) on commodity derivative instruments, net on the consolidated statements of operations. | |||||||||||||||||||||||||
In the fourth quarter of 2011, in order to improve the effectiveness of our hedge portfolio, we terminated certain oil fixed price swaps at NYMEX WTI prices for a total termination cost of $36.8 million, included in 2011 realized as a reduction to the overall gain, and entered into new oil fixed price swaps for the same volumes and periods at ICE Brent prices. | |||||||||||||||||||||||||
FASB Accounting Standards define fair value, establish a framework for measuring fair value and establish required disclosures about fair value measurements. They also establish a fair value hierarchy that prioritizes the inputs to valuation techniques into three broad levels based upon how observable those inputs are. We use valuation techniques that maximize the use of observable inputs and obtain the majority of our inputs from published objective sources or third party market participants. We incorporate the impact of nonperformance risk, including credit risk, into our fair value measurements. The fair value hierarchy gives the highest priority of Level 1 to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority of Level 3 to unobservable inputs. We categorize our fair value financial instruments based upon the objectivity of the inputs and how observable those inputs are. The three levels of inputs are described further as follows: | |||||||||||||||||||||||||
Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date. Level 2 – Inputs other than quoted prices that are included in Level 1. Level 2 includes financial instruments that are actively traded but are valued using models or other valuation methodologies. We consider the over the counter (“OTC”) commodity and interest rate swaps in our portfolio to be Level 2. Level 3 – Inputs that are not directly observable for the asset or liability and are significant to the fair value of the asset or liability. Level 3 includes financial instruments that are not actively traded and have little or no observable data for input into industry standard models. Certain OTC derivatives that trade in less liquid markets or contain limited observable model inputs are currently included in Level 3. As of December 31, 2013 and 2012, our Level 3 derivative assets and liabilities consisted entirely of OTC commodity put and call options. | |||||||||||||||||||||||||
Financial assets and liabilities that are categorized in Level 3 may later be reclassified to the Level 2 category at the point we are able to obtain sufficient binding market data. We had no transfers in or out of Levels 1, 2 or 3 during the years ended December 31, 2013, 2012 and 2011. Our policy is to recognize transfers between levels as of the end of the period. | |||||||||||||||||||||||||
Our Treasury/Risk Management group calculates the fair value of our commodity and interest rate swaps and options. We compare these fair value amounts to the fair value amounts that we receive from the counterparties on a monthly basis. Any differences are resolved and any required changes are recorded prior to the issuance of our financial statements. | |||||||||||||||||||||||||
The model we utilize to calculate the fair value of our Level 2 and Level 3 commodity derivative instruments is a standard option pricing model. Level 2 inputs to the option pricing models include fixed monthly commodity strike prices and volumes from each specific contract, commodity prices from commodity forward price curves, volatility and interest rate factors and time to expiry. Model inputs are obtained from our counterparties and third party data providers and are verified to published data where available (e.g., NYMEX). Additional inputs to our Level 3 derivatives include option volatility, forward commodity prices and risk-free interest rates for present value discounting. We use the standard swap contract valuation method to value our interest rate derivatives, and inputs include LIBOR forward interest rates, one-month LIBOR rates and risk-free interest rates for present value discounting. | |||||||||||||||||||||||||
Assumed credit risk adjustments, based on published credit ratings and credit default swap rates, are applied to our derivative instruments. | |||||||||||||||||||||||||
Our assessment of the significance of an input to its fair value measurement requires judgment and can affect the valuation of the assets and liabilities as well as the category within which they are classified. Financial assets and liabilities carried at fair value on a recurring basis are presented in the following tables: | |||||||||||||||||||||||||
Thousands of dollars | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||||
Assets (liabilities) | |||||||||||||||||||||||||
Oil | |||||||||||||||||||||||||
Oil swaps | $ | — | $ | 5,573 | $ | — | $ | 5,573 | |||||||||||||||||
Oil collars | — | — | 2,683 | 2,683 | |||||||||||||||||||||
Oil puts | — | — | 6,275 | 6,275 | |||||||||||||||||||||
Natural gas | |||||||||||||||||||||||||
Natural gas swaps | — | 35,419 | — | 35,419 | |||||||||||||||||||||
Natural gas calls | — | — | (650 | ) | (650 | ) | |||||||||||||||||||
Natural gas puts | — | — | 2,497 | 2,497 | |||||||||||||||||||||
Net assets | $ | — | $ | 40,992 | $ | 10,805 | $ | 51,797 | |||||||||||||||||
As of December 31, 2012 | |||||||||||||||||||||||||
Assets (liabilities) | |||||||||||||||||||||||||
Oil | |||||||||||||||||||||||||
Oil swaps | $ | — | $ | (12,413 | ) | $ | — | $ | (12,413 | ) | |||||||||||||||
Oil collars | — | — | 4,024 | 4,024 | |||||||||||||||||||||
Oil puts | — | — | 11,144 | 11,144 | |||||||||||||||||||||
Natural gas | |||||||||||||||||||||||||
Natural gas swaps | — | 74,782 | — | 74,782 | |||||||||||||||||||||
Natural gas calls | — | — | (1,489 | ) | (1,489 | ) | |||||||||||||||||||
Natural gas puts | — | — | 3,162 | 3,162 | |||||||||||||||||||||
Net assets | $ | — | $ | 62,369 | $ | 16,841 | $ | 79,210 | |||||||||||||||||
The following table sets forth a reconciliation of changes in fair value of our derivative instruments classified as Level 3: | |||||||||||||||||||||||||
Year End December 31, | |||||||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||||||
Thousands of dollars | Oil | Natural Gas | Oil | Natural Gas | Oil | Natural Gas | |||||||||||||||||||
Assets (a): | |||||||||||||||||||||||||
Beginning balance | $ | 15,169 | $ | 1,672 | $ | 8,509 | $ | 37,049 | $ | 35,443 | $ | 50,810 | |||||||||||||
Derivative instrument settlements (b) | (125 | ) | (892 | ) | 14,131 | 42,401 | 16,646 | 27,640 | |||||||||||||||||
Gain (loss) (b)(c) | (6,087 | ) | 1,068 | (20,760 | ) | (81,556 | ) | (43,581 | ) | (41,401 | ) | ||||||||||||||
Purchases (b)(d) | — | — | 13,288 | — | — | — | |||||||||||||||||||
Ending balance | $ | 8,957 | $ | 1,848 | $ | 15,169 | $ | 1,672 | $ | 8,509 | $ | 37,049 | |||||||||||||
(a) We had no fair value changes for our derivative instruments classified as Level 3 related to sales or issuances. | |||||||||||||||||||||||||
(b) Included in gain (loss) on commodity derivative instruments, net on the consolidated statements of operations. | |||||||||||||||||||||||||
(c) Represents gain (loss) on mark-to-market of derivative instruments. | |||||||||||||||||||||||||
(d) Relates to natural gas put options entered into in June 2012 and oil options entered into in August 2012. | |||||||||||||||||||||||||
For Level 3 derivatives measured at fair value on a recurring basis as of December 31, 2013, the significant unobservable inputs used in the fair value measurements were as follows: | |||||||||||||||||||||||||
Fair Value at | Valuation | ||||||||||||||||||||||||
Thousands of dollars | December 31, 2013 | Technique | Unobservable Input | Range | |||||||||||||||||||||
Oil options | $ | 8,957 | Option Pricing Model | Oil forward commodity prices | $81.95/Bbl - $105.14/Bbl | ||||||||||||||||||||
Oil volatility | 15.51% - 17.59% | ||||||||||||||||||||||||
Own credit risk | 5% | ||||||||||||||||||||||||
Natural gas options | 1,848 | Option Pricing Model | Gas forward commodity prices | $4.01/MMBtu - $4.41/MMBtu | |||||||||||||||||||||
Gas volatility | 18.87% - 35.13% | ||||||||||||||||||||||||
Own credit risk | 5% | ||||||||||||||||||||||||
Total | $ | 10,805 | |||||||||||||||||||||||
For Level 3 derivatives measured at fair value on a recurring basis as of December 31, 2012, the significant unobservable inputs used in the fair value measurements were as follows: | |||||||||||||||||||||||||
Fair Value at | Valuation | ||||||||||||||||||||||||
Thousands of dollars | December 31, 2012 | Technique | Unobservable Input | Range | |||||||||||||||||||||
Oil options | $ | 15,169 | Option pricing model | Oil forward commodity prices | $86.78/Bbl - $110.46/Bbl | ||||||||||||||||||||
Oil volatility | 20.56% - 27.53% | ||||||||||||||||||||||||
Own credit risk | 5% | ||||||||||||||||||||||||
Natural gas options | 1,672 | Option pricing model | Gas forward commodity prices | $3.35/MMBtu - $4.87/MMBtu | |||||||||||||||||||||
Gas volatility | 20.55% - 35.88% | ||||||||||||||||||||||||
Own credit risk | 5% | ||||||||||||||||||||||||
Total | $ | 16,841 | |||||||||||||||||||||||
Credit and Counterparty Risk | |||||||||||||||||||||||||
Financial instruments, which potentially subject us to concentrations of credit risk consist principally of derivatives and accounts receivable. Our derivatives expose us to credit risk from counterparties. As of December 31, 2013, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse Energy LLC, Union Bank N.A, Wells Fargo Bank National Association, JP Morgan Chase Bank N.A., The Royal Bank of Scotland plc, The Bank of Nova Scotia, BNP Paribas, U.S Bank National Association, Toronto-Dominion Bank and Royal Bank of Canada. Our counterparties are all lenders under our Amended and Restated Credit Agreement. Our credit agreement is secured by our oil, NGL and natural gas reserves, so we are not required to post any collateral, and we conversely do not receive collateral from our counterparties. On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits and monitor the appropriateness of these limits on an ongoing basis. We periodically obtain credit default swap information on our counterparties. Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to fail to perform in accordance with the terms of the contract. This risk is managed by diversifying our derivatives portfolio. As of December 31, 2013, each of these financial institutions had an investment grade credit rating. As of December 31, 2013, our largest derivative asset balances were with Wells Fargo Bank National Association, Credit Suisse Energy LLC and Citibank, N.A., which accou |
Related_Party_Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2013 | |
Related Party Transactions [Abstract] | ' |
Related Party Transactions | ' |
Related Party Transactions | |
BreitBurn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. All of our employees, including our executives, are employees of BreitBurn Management. BreitBurn Management also operates the assets of PCEC, our Predecessor. In addition to a monthly fee for indirect expenses, BreitBurn Management charges PCEC for all direct expenses, including incentive plan costs and direct payroll and administrative costs related to PCEC properties and operations. | |
On January 6, 2012, Pacific Coast Oil Trust (the “Trust”), which was formed by PCEC, filed a registration statement on Form S-1 with the SEC in connection with an initial public offering by the Trust. On May 8, 2012, the Trust completed its initial public offering (the “Trust IPO”). We have no direct or indirect ownership interest in PCEC or the Trust. As part of the Trust IPO, PCEC conveyed net profits interests in its oil and natural gas production from certain of its properties to the Trust in exchange for Trust units. PCEC’s assets consist primarily of producing and non-producing oil reserves located in Santa Barbara, Los Angeles and Orange Counties in California, including certain interests in the East Coyote and Sawtelle Fields. Prior to the Trust IPO, PCEC operated the East Coyote and Sawtelle Fields for us and for its benefit. PCEC owned an average working interest of approximately 5% in the two fields and held a reversionary interest in both fields that was expected to result in an increase in PCEC’s ownership and accordingly decrease in our ownership in the properties. After the Trust IPO, PCEC’s ownership interest in both properties increased, and our ownership in these properties decreased from approximately 95% to 62%. | |
On May 8, 2012, BreitBurn Management entered into the Third Amended and Restated Administrative Services Agreement (the “Third Amended and Restated Administrative Services Agreement”) with PCEC, pursuant to which the parties agreed to increase the monthly fee charged by BreitBurn Management to PCEC for indirect costs. For the first three months of 2012, the monthly fee charged by BreitBurn Management to PCEC for indirect costs was set at $571,000, and the two parties agreed to increase that monthly fee to $700,000, effective April 1, 2012. In connection with the PCEC transactions and the Third Amended and Restated Administrative Services Agreement, PCEC also paid us a $250,000 fee. | |
In connection with the Trust IPO, we, BreitBurn GP, LLC and BreitBurn Management entered into the First Amendment to Omnibus Agreement, dated as of May 8, 2012, with PCEC, Pacific Coast Energy Holdings LLC, formerly known as BreitBurn Energy Holdings, LLC, and PCEC (GP) LLC, formerly known as BEC (GP) LLC (the “First Amendment to Omnibus Agreement”). Pursuant to the First Amendment to Omnibus Agreement, the parties agreed to amend the Omnibus Agreement among the parties, dated as of August 26, 2008 (the “Omnibus Agreement”), to remove Article III of the Omnibus Agreement, which contained our right of first offer with respect to the sale of assets by PCEC and its affiliates. | |
At December 31, 2013 and 2012, we had net current receivables of $2.5 million and $1.2 million, respectively, due from PCEC related to the applicable administrative services agreement, employee related costs and oil and gas sales made by PCEC on our behalf from certain properties. During 2013, the monthly charges to PCEC for indirect expenses totaled $8.4 million and charges for direct expenses including direct payroll and other direct costs totaled $10.6 million. During 2012, the monthly charges to PCEC for indirect expenses totaled $8.0 million and charges for direct expenses including direct payroll and other direct costs totaled $8.6 million. | |
At December 31, 2013 and 2012, we had receivables of $0.1 million and $0.2 million, respectively, due from certain of our other affiliates primarily representing investments in natural gas processing facilities for management fees due from them and operational expenses incurred on their behalf. |
Inventory
Inventory | 12 Months Ended |
Dec. 31, 2013 | |
Inventory Disclosure [Abstract] | ' |
Inventory | ' |
Inventory | |
As of December 31, 2013 and 2012, our Florida operations had oil inventory of $3.9 million and $3.1 million, respectively. For the year ended December 31, 2013, we sold 784 MBbls of oil and produced 779 MBbls from our Florida operations. For the year ended December 31, 2012, we sold 849 MBbls of oil and produced 830 MBbls from our Florida operations. Oil sales are a function of the number and size of oil shipments in each quarter, and thus, oil sales do not always coincide with volumes produced in a given quarter. We match production expenses with oil sales. Production expenses associated with unsold oil inventory are recorded as inventory. | |
We carry inventory at the lower of cost or market. When using lower of cost or market to value inventory, market should not exceed the net realizable value or the estimated selling price less costs of completion and disposal. We assessed our oil inventory at December 31, 2013 and December 31, 2012 and determined that its carrying value was below market value and therefore no write-down were necessary. | |
For our properties in Florida, there are a limited number of alternative methods of transportation for our production. Substantially all of our oil production is transported by pipelines, trucks and barges owned by third parties. The inability or unwillingness of these parties to provide transportation services for a reasonable fee could result in our having to find transportation alternatives, increased transportation costs or involuntary curtailment of our oil production, which could have a negative impact on our future consolidated financial position, results of operations and cash flows. |
Equity_Investments
Equity Investments | 12 Months Ended |
Dec. 31, 2013 | |
Equity Method Investments and Joint Ventures [Abstract] | ' |
Equity Investments | ' |
Equity Investments | |
We had equity investments at December 31, 2013 and December 31, 2012 totaling $6.6 million and $7.0 million, respectively, which primarily represent investments in natural gas processing facilities and product transportation pipelines. For the years ended December 31, 2013 and 2012, we recorded $0.5 million and $0.7 million, respectively, in earnings from equity investments and $0.5 million and $1.2 million, respectively, in dividends. In 2013, we dissolved one of our partnerships, which reduced the carrying value of our investments by $0.4 million. For the year ended December 31, 2011, we recorded $0.7 million in earnings from equity investments and $0.9 million in dividends. Earnings from equity investments are reported in other revenue, net on the consolidated statements of operations. | |
At December 31, 2013, our equity investments consisted primarily of a 24.5% limited partner interest and a 25.5% general partner interest in Wilderness Energy Services LP, with a combined carrying value of $6.0 million. The remaining $0.6 million consists of smaller interests in several other investments where we have significant influence. |
Impairments_and_Price_Related_
Impairments and Price Related Depletion and Depreciation Adjustments | 12 Months Ended |
Dec. 31, 2013 | |
Impairments and Price Related Depletion and Depreciation Adjustments [Abstract] | ' |
Impairments and Price Related Depletion and Depreciation Adjustments | ' |
Impairments | |
We assess our developed and undeveloped oil and gas properties and other long-lived assets for possible impairment periodically and whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable. Such indicators include changes in business plans, changes in commodity prices and, for oil and natural gas properties, significant downward revisions of estimated proved reserve quantities. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge is recorded for the excess of carrying value of the asset over its estimated fair value. | |
Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles and the outlook for market supply and demand conditions for oil and natural gas. For purposes of performing an impairment test, the undiscounted future cash flows are based on total proved and risk-adjusted probable and possible reserves and are forecast using five-year NYMEX forward strip prices at the end of the period and escalated along with expenses and capital starting year six and thereafter at 2.5% per year. For impairment charges, the associated property’s expected future net cash flows are discounted using a market-based weighted average cost of capital rate that currently approximates 10%. Additional inputs include oil and natural gas reserves, future operating and development costs and future commodity prices. We consider the inputs for our impairment calculations to be Level 3 inputs. The impairment reviews and calculations are based on assumptions that are consistent with our business plans. | |
During the year ended December 31, 2013, we recorded non-cash impairment charges of approximately $54.4 million, including $28.3 million of impairments to our Michigan non-Antrim oil and gas properties due to negative reserve adjustments due to lower performance and a decrease in expected future commodity prices, and $25.3 million of impairments to an oil property in our Bighorn Basin in Northern Wyoming due to a negative reserve adjustment due to lower performance and a decrease in expected future oil prices. Decreased drilling activity in Michigan was also a factor as the Partnership continues to allocate its capital expenditures more towards liquids-rich areas. During the year ended December 31, 2012, we recorded impairments of approximately $12.3 million primarily related to uneconomic proved properties in Michigan, Indiana and Kentucky due to a decrease in expected future natural gas prices. During the year ended December 31, 2011, we recorded impairments of approximately $0.6 million related to uneconomic proved properties in Michigan primarily due to a decrease in expected natural gas prices. | |
Given the number of assumptions involved in the estimates, an estimate as to the sensitivity to earnings for these periods if other assumptions had been used in impairment reviews and calculations is not practicable. Favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired. |
LongTerm_Debt
Long-Term Debt | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Long-term Debt, Unclassified [Abstract] | ' | ||||||||||||
Long-Term Debt | ' | ||||||||||||
Long-Term Debt | |||||||||||||
Credit Facility | |||||||||||||
BOLP, as borrower, and we and our wholly-owned subsidiaries, as guarantors, have a $3.0 billion revolving credit facility with Wells Fargo Bank National Association, as Administrative Agent, Swing Line Lender and Issuing Lender, and a syndicate of banks (the “Second Amended and Restated Credit Agreement”) with a maturity date of May 9, 2016. | |||||||||||||
Our credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based on their valuation of our proved reserves and their internal criteria. The borrowing base is redetermined semi-annually. Currently, our borrowing base for our credit facility is $1.5 billion, and the aggregate commitment of all lenders is $1.4 billion with the ability to increase our total commitments up to the $1.5 billion borrowing base upon lender approval. Our next borrowing base redetermination is scheduled for April 2014. | |||||||||||||
In May 2013, we entered into the Eighth Amendment to the Second Amended and Restated Credit Agreement, which increased our borrowing base to $1.2 billion and the aggregate commitment of all lenders to $1.0 billion, and which added eight lenders to our syndicate. | |||||||||||||
In July 2013, we entered into the Ninth Amendment to the Second Amended and Restated Credit Agreement, which increased our aggregate maximum credit amount from $1.5 billion to $3.0 billion, increased our borrowing base to $1.5 billion and increased the aggregate commitment of all lenders to $1.4 billion. The amendment also increased flexibility for the Total Leverage Ratio (defined as the ratio of total debt to EBITDAX). Both of these leverage ratios were eliminated from our credit facility in connection with the Eleventh Amendment (the “Eleventh Amendment”) to the Second Amended and Restated Credit Agreement discussed below. | |||||||||||||
In November 2013, we entered into the Tenth Amendment to the Second Amended and Restated Credit Agreement, which permitted us to declare and pay to our equity owners periodic cash dividends in accordance with our partnership agreement. | |||||||||||||
In February 2014, we entered into the Eleventh Amendment that eliminated the Maximum Total Leverage Ratio (defined as the ratio of total debt to EBITDAX) and Maximum Senior Secured Leverage Ratio (defined as the ratio of senior secured indebtedness to EBITDAX) requirements and added a provision requiring us to maintain an Interest Coverage Ratio (defined as EBITDAX divided by Consolidated Interest Expense) for the four quarters ending on the last day of each quarter beginning with the fourth quarter of 2013 of no less that 2.50 to 1.00. The amendment also provides that we cannot incur senior unsecured debt in excess of our borrowing base in effect at the time of the issuance of such debt. | |||||||||||||
EBITDAX is not a defined US GAAP measure. The Second Amended and Restated Credit Agreement defines EBITDAX as consolidated net income plus exploration expense, interest expense, income tax provision, DD&A, unrealized loss or gain on derivative instruments, non-cash charges, including non-cash unit-based compensation expense, loss or gain on sale of assets (excluding gain or loss on monetization of derivative instruments for the following twelve months), pro forma impact of acquisitions and disposition, cumulative effect of changes in accounting principles, cash distributions received from our unrestricted entities (as defined in the Second Amended and Restated Credit Agreement) and excluding income from our unrestricted entities. | |||||||||||||
As of December 31, 2013 and December 31, 2012, our borrowing base was $1.5 billion and $1.0 billion, respectively, and the aggregate commitment of all lenders was $1.4 billion and $900 million, respectively. | |||||||||||||
As of December 31, 2013 and December 31, 2012, we had $733.0 million and $345.0 million, respectively, in indebtedness outstanding under the credit facility. At December 31, 2013, the 1-month LIBOR interest rate plus an applicable spread was 2.167% on the 1-month LIBOR portion of $727.0 million and the prime rate plus an applicable spread was 4.25% on the prime portion of $6.0 million. At December 31, 2013, we had $13.7 million of unamortized debt issuance costs related to our credit facility. | |||||||||||||
Borrowings under the Second Amended and Restated Credit Agreement are secured by first-priority liens on and security interests in substantially all of our and certain of our subsidiaries’ assets, representing not less than 80% of the total value of our oil and gas properties. | |||||||||||||
The Second Amended and Restated Credit Agreement contains customary covenants, including restrictions on our ability to: incur additional indebtedness; make certain investments, loans or advances; make distributions to our unitholders or repurchase units (including the restriction on our ability to make distributions unless, after giving effect to such distribution, we remain in compliance with all terms and conditions of our credit facility); make dispositions or enter into sales and leasebacks; or enter into a merger or sale of our property or assets, including the sale or transfer of interests in our subsidiaries. | |||||||||||||
The Second Amended and Restated Credit Agreement also permits us to terminate derivative contracts without obtaining the consent of the lenders in the facility, provided that the net effect of such termination plus the aggregate value of all dispositions of oil and gas properties made during such period, together, does not exceed 5% of the borrowing base, and the borrowing base will be automatically reduced by an amount equal to the net effect of the termination. | |||||||||||||
The events that constitute an Event of Default (as defined in the Second Amended and Restated Credit Agreement) include: payment defaults; misrepresentations; breaches of covenants; cross-default and cross-acceleration to certain other indebtedness; adverse judgments against us in excess of a specified amount; changes in management or control; loss of permits; certain insolvency events; and assertion of certain environmental claims. | |||||||||||||
As of December 31, 2013, we were in compliance with our credit facility’s covenants. | |||||||||||||
Senior Notes Due 2020 | |||||||||||||
On October 6, 2010, we and BreitBurn Finance Corporation (the “Issuers”), and certain of our subsidiaries as guarantors (the “Guarantors”), issued $305 million in aggregate principal amount of 8.625% Senior Notes due 2020 (the “2020 Senior Notes”). The 2020 Senior Notes were offered at a discount price of 98.358%, or $300 million. The $5 million discount is being amortized over the life of the 2020 Senior Notes. As of December 31, 2013 and 2012, the 2020 Senior Notes had a carrying value of $301.6 million and $301.1 million, respectively, net of unamortized discount of $3.4 million and $3.9 million, respectively. In connection with the 2020 Senior Notes, we incurred financing fees and expenses of approximately $8.8 million, which are being amortized over the life of the 2020 Senior Notes. Interest on the 2020 Senior Notes is payable twice a year in April and October. | |||||||||||||
As of December 31, 2013 and 2012, the fair value of the 2020 Senior Notes was estimated to be $327 million and $330 million, respectively. We consider the inputs to the valuation of our 2020 Senior Notes to be Level 2, as fair value was estimated based on prices quoted from third party financial institutions. | |||||||||||||
Senior Notes Due 2022 | |||||||||||||
On January 10, 2012, the Issuers, and certain of our subsidiaries as Guarantors, issued $250 million in aggregate principal amount of 7.875% Senior Notes due 2022 (the “Initial Notes”), which were purchased by the initial purchasers as defined in the purchase agreement (the “Initial Purchasers”) and then resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”). The Initial Notes were issued at a discount of 99.154%, or $247.9 million. The $2.1 million discount is being amortized over the life of the Initial Notes. In connection with the Initial Notes, our financing fees and expenses were approximately $5.6 million, which are being amortized over the life of the Initial Notes. | |||||||||||||
On September 27, 2012 we issued an additional $200 million aggregate principal amount of our 7.875% Senior Notes due 2022 (the “2012 Additional Notes”), which were purchased by the Initial Purchasers and then resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act. The 2012 Additional Notes have identical terms, other than the issue date and initial interest payment date, and constitute part of the same series as and are fungible with the Initial Notes. The 2012 Additional Notes were issued at a premium of 103.500%, or $207.0 million. The $7.0 million premium is being amortized over the life of the 2012 Additional Notes. In connection with the 2012 Additional Notes, our financing fees and expenses were approximately $4.2 million, which are being amortized over the life of the 2012 Additional Notes. | |||||||||||||
In connection with the issuance of the Initial Notes and the 2012 Additional Notes, we entered into Registration Rights Agreements (the “Registration Rights Agreements”) with the Guarantors and Initial Purchasers. Under the Registration Rights Agreements, the Issuers and the Guarantors agreed to cause to be filed with the SEC a registration statement with respect to an offer to exchange the these notes for substantially identical notes that are registered under the Securities Act. The Issuers and the Guarantors agreed to use their commercially reasonable efforts to cause such exchange offer registration statement to become effective under the Securities Act. In addition, the Issuers and the Guarantors agreed to use their commercially reasonable efforts to cause the exchange offer to be consummated not later than 400 days after January 13, 2012. In December 2012, we filed a registration statement for the exchange offer for the Initial Notes and the 2012 Additional Notes. On December 27, 2012, the exchange registration statement became effective, and we commenced the exchange offer, which was completed on February 7, 2013. | |||||||||||||
On November 22, 2013, we completed a public offering of $400 million aggregate principal amount of our 7.875% Senior Notes due 2022 (the “2013 Additional Notes” and together with the 2012 Additional Notes and the Initial Notes, as the “2022 Senior Notes”). The 2013 Additional Notes have identical terms, other than the issue date and initial interest payment date, and constitute part of the same series as and are fungible with the Initial Notes. The 2013 Additional Notes were issued at a premium of 100.250%, or $401.0 million. The $1.0 million premium is being amortized over the life of the 2013 Additional Notes. In connection with the 2013 Additional Notes, our financing fees and expenses were approximately $7.7 million, which are being amortized over the life of the 2013 Additional Notes. | |||||||||||||
As of December 31, 2013, the 2022 Senior Notes had a carrying value of $855.1 million, net of unamortized premium of $5.1 million. Interest on the 2022 Senior Notes is payable twice a year in April and October. As of December 31, 2013, the fair value of the 2022 Senior Notes was estimated to be $890 million. We consider the inputs to the valuation of our 2022 Senior Notes to be Level 2, as fair value was estimated based on prices quoted from third party financial institutions. | |||||||||||||
The indentures governing both our 2020 Senior Notes and 2022 Senior Notes contain covenants that restrict our ability and the ability of certain of our subsidiaries to: (i) sell assets including equity interests in our subsidiaries; (ii) pay distributions on, redeem or repurchase our units or redeem or repurchase our subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us; (vii) consolidate, merge or transfer all or substantially all of our assets; (viii) engage in transactions with affiliates; (ix) create unrestricted subsidiaries; or (x) engage in certain business activities. If the senior notes achieve an investment grade rating from each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the indentures) has occurred and is continuing, many of these covenants will terminate. | |||||||||||||
As of December 31, 2013 and December 31, 2012, we were in compliance with the covenants on our 2020 and 2022 Senior Notes. | |||||||||||||
Interest Expense | |||||||||||||
Our interest expense is detailed in the following table: | |||||||||||||
Year Ended December 31, | |||||||||||||
Thousands of dollars | 2013 | 2012 | 2011 | ||||||||||
Credit facility (including commitment fees) | $ | 15,698 | $ | 7,114 | $ | 8,266 | |||||||
Senior notes | 65,068 | 49,279 | 26,233 | ||||||||||
Amortization of discount and deferred issuance costs | 6,429 | 4,867 | 4,743 | ||||||||||
Capitalized interest | (128 | ) | (54 | ) | (77 | ) | |||||||
Total | $ | 87,067 | $ | 61,206 | $ | 39,165 | |||||||
Cash paid for interest | $ | 74,078 | $ | 55,151 | $ | 37,756 | |||||||
Condensed_Consolidating_Financ
Condensed Consolidating Financial Statements | 12 Months Ended | |
Dec. 31, 2013 | ||
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | ' | |
Condensed Consolidating Financial Statements | ' | |
Condensed Consolidating Financial Statements | ||
We and BreitBurn Finance Corporation as co-issuers, and certain of our subsidiaries as guarantors, issued the 2020 Senior Notes and the 2022 Senior Notes. All but one of our subsidiaries have guaranteed our senior notes. Our only non-guarantor subsidiary, BreitBurn Collingwood Utica LLC, is a minor subsidiary. | ||
In accordance with Rule 3-10 of Regulation S-X, we are not presenting condensed consolidating financial statements as we have no independent assets or operations; BreitBurn Finance Corporation, the subsidiary co-issuer which does not guarantee our senior notes, is a 100% owned finance subsidiary; all of our material subsidiaries are 100% owned, have guaranteed our senior notes, and all of the guarantees are full, unconditional, joint and several. | ||
Each guarantee of each of the 2020 Senior Notes and the 2022 Senior Notes is subject to release in the following customary circumstances: | ||
-1 | a disposition of all or substantially all the assets of the guarantor subsidiary (including by way or merger or consolidation), to a third person, provided the disposition complies with the applicable indenture, | |
-2 | a disposition of the capital stock of the guarantor subsidiary to a third person, if the disposition complies with the applicable indenture and as a result the guarantor subsidiary ceases to be our subsidiary, | |
-3 | the designation by us of the guarantor subsidiary as an Unrestricted Subsidiary in accordance with the applicable indenture, | |
-4 | legal or covenant defeasance of such series of Senior Notes or satisfaction and discharge of the related indenture, | |
-5 | the liquidation or dissolution of the guarantor subsidiary, provided no default under the applicable indenture exists, or | |
-6 | the guarantor subsidiary ceases both (a) to guarantee any other indebtedness of ours or any other guarantor subsidiary and (b) to be an obligor under any bank credit facility. |
Income_Taxes
Income Taxes | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Income Tax Disclosure [Abstract] | ' | ||||||||||||
Income Taxes | ' | ||||||||||||
Income Taxes | |||||||||||||
We, and all of our subsidiaries, with the exception of Phoenix Production Company (“Phoenix”), Alamitos Company, BreitBurn Management and BreitBurn Finance Corporation, are partnerships or limited liability companies treated as partnerships for federal and state income tax purposes. Essentially all of our taxable income or loss, which may differ considerably from the net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of our partners. As such, we have not recorded any federal income tax expense for those pass-through entities. | |||||||||||||
The consolidated income tax expense (benefit) attributable to our tax-paying entities consisted of the following: | |||||||||||||
Year Ended December 31, | |||||||||||||
Thousands of dollars | 2013 | 2012 | 2011 | ||||||||||
Federal income tax expense (benefit) | |||||||||||||
Current | $ | 472 | $ | 223 | $ | 378 | |||||||
Deferred (a) | 262 | (316 | ) | 714 | |||||||||
State income tax expense (b) | 171 | 177 | 96 | ||||||||||
Total | $ | 905 | $ | 84 | $ | 1,188 | |||||||
(a) Related to Phoenix, our wholly-owned subsidiary. | |||||||||||||
(b) Primarily in California, Texas and Michigan. | |||||||||||||
The following is a reconciliation of federal income taxes at the statutory rates to federal income tax expense (benefit) for Phoenix: | |||||||||||||
Year Ended December 31, | |||||||||||||
Thousands of dollars | 2013 | 2012 | 2011 | ||||||||||
Income (loss) subject to federal income tax | $ | 750 | $ | (705 | ) | $ | 3,329 | ||||||
Federal income tax rate | 34 | % | 34 | % | 34 | % | |||||||
Income tax at statutory rate | 255 | (240 | ) | 1,132 | |||||||||
Statutory depletion from prior year | — | (248 | ) | — | |||||||||
Other | 13 | — | — | ||||||||||
Income tax expense (benefit) | $ | 268 | $ | (488 | ) | $ | 1,132 | ||||||
At December 31, 2013 and 2012, net deferred federal income tax liabilities of $2.7 million and $2.5 million, respectively, were reported in our consolidated balance sheet for Phoenix. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting and the amount used for income tax purposes. Significant components of our net deferred tax liabilities are presented in the following table: | |||||||||||||
December 31, | |||||||||||||
Thousands of dollars | 2013 | 2012 | |||||||||||
Deferred tax assets: | |||||||||||||
Asset retirement obligation | $ | 526 | $ | 470 | |||||||||
Unrealized hedge loss | 51 | 82 | |||||||||||
Deferred realized hedge loss | — | 149 | |||||||||||
Other | 627 | 571 | |||||||||||
Deferred tax liabilities: | |||||||||||||
Depreciation, depletion and intangible drilling costs | (3,953 | ) | (3,759 | ) | |||||||||
Net deferred tax liability | $ | (2,749 | ) | $ | (2,487 | ) | |||||||
At December 31, 2013, we had unused carryforwards of operating loss and minimum tax credit. We did not provide a valuation allowance against these deferred tax asset as we expect to fully utilize the carryforwards in the future. | |||||||||||||
On a consolidated basis, cash paid for federal and state income taxes totaled $0.5 million, $0.8 million and $0.3 million in 2013, 2012 and 2011, respectively. | |||||||||||||
FASB Accounting Standards clarify the accounting for uncertainty in income taxes recognized in a company’s financial statements. A company can only recognize the tax position in the financial statements if the position is more-likely-than-not to be upheld on audit based only on the technical merits of the tax position. FASB Accounting Standards also provide guidance on thresholds, measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition that is intended to provide better financial statement comparability among different companies. | |||||||||||||
We performed analysis as of December 31, 2013, 2012 and 2011 and concluded that there were no uncertain tax positions requiring recognition in our financial statements. |
Asset_Retirement_Obligation
Asset Retirement Obligation | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
Asset Retirement Obligation [Abstract] | ' | ||||||||
Asset Retirement Obligation | ' | ||||||||
Asset Retirement Obligation | |||||||||
ARO is based on our net ownership in wells and facilities and our estimate of the costs to abandon and remediate those wells and facilities together with our estimate of the future timing of the costs to be incurred. Payments to settle ARO occur over the operating lives of the assets, estimated to range from less than one year to 50 years. Estimated cash flows have been discounted at our credit adjusted risk free rate that approximates 7% and adjusted for inflation using a rate of 2%. Our credit adjusted risk free rate is calculated based on our cost of borrowing adjusted for the effect of our credit standing and specific industry and business risk. | |||||||||
During 2013 and 2012, we added ARO of $9.3 million and $6.3 million, respectively, from acquisitions. During 2013, we added $5.3 million reflecting increases in the number of wells drilled during the year. | |||||||||
Each year we review and, to the extent necessary, revise our ARO estimates. During 2013 and 2012, we obtained new estimates to evaluate the cost of abandoning our properties. As a result, we increased our ARO estimate by $4.3 million in 2013 to reflect primarily increases in cost estimates. Revisions in 2012 of $1.6 million reflect increases in estimated costs for plugging and abandonment, primarily in Wyoming and Florida, partially offset by a decrease in ARO related to the change in working interest ownership in two California fields. | |||||||||
We consider the inputs to our ARO valuation to be Level 3 as fair value is determined using discounted cash flow methodologies based on standardized inputs that are not readily observable in public markets. | |||||||||
Changes in the ARO are presented in the following table: | |||||||||
Year Ended December 31, | |||||||||
Thousands of dollars | 2013 | 2012 | |||||||
Carrying amount, beginning of period | $ | 98,480 | $ | 82,397 | |||||
Acquisitions | 9,287 | 6,279 | |||||||
Liabilities incurred | 5,313 | 2,468 | |||||||
Liabilities settled | (893 | ) | (86 | ) | |||||
Revisions | 4,299 | 1,553 | |||||||
Accretion expense | 7,283 | 5,869 | |||||||
Carrying amount, end of period | $ | 123,769 | $ | 98,480 | |||||
Commitments_and_Contingencies
Commitments and Contingencies | 12 Months Ended | ||||||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||||||
Commitments and Contingencies Disclosure [Abstract] | ' | ||||||||||||||||||||||||||||
Commitments and Contingencies | ' | ||||||||||||||||||||||||||||
Commitments and Contingencies | |||||||||||||||||||||||||||||
Lease Rental and Purchase Obligations | |||||||||||||||||||||||||||||
We have operating leases for office space and other property and equipment having initial or remaining non-cancelable lease terms in excess of one year. Our future minimum rental payments for operating leases at December 31, 2013 are presented below: | |||||||||||||||||||||||||||||
Payments Due by Year | |||||||||||||||||||||||||||||
Thousands of dollars | 2014 | 2015 | 2016 | 2017 | 2018 | Thereafter | Total | ||||||||||||||||||||||
Operating leases | $ | 5,910 | $ | 5,530 | $ | 4,498 | $ | 4,068 | $ | 633 | $ | — | $ | 20,639 | |||||||||||||||
Net rental expense under non-cancelable operating leases was $3.9 million, $3.7 million and $3.4 million in 2013, 2012 and 2011, respectively. | |||||||||||||||||||||||||||||
Purchase Contracts | |||||||||||||||||||||||||||||
On July 15, 2013, we completed the Whiting Acquisition. The Whiting Acquisition included the Postle Field, which currently has active CO2 enhanced recovery projects, and the Northeast Hardesty Unit, both of which are located in Texas County, Oklahoma. We have a contracted supply of CO2 in the Bravo Dome Field in New Mexico, with step-in rights, for 143 Bcf over the next 10 to 15 years, which we expect to provide volumes in excess of those required to produce our estimated proved reserves when coupled with recycled CO2. Under the take-or-pay provisions of these purchase agreements, we are committed to buying certain volumes of CO2 for use in our enhanced recovery project being carried out at the Postle field. We are obligated to purchase a minimum daily volume of CO2 (as calculated on an annual basis) or otherwise pay for any deficiencies at the price in effect when the minimum delivery was to have occurred. The CO2 volumes planned for use in our enhanced recovery projects in the Postle Field currently exceed the minimum daily volumes specified in these agreements. Therefore, we expect to avoid any deficiency payments. The table below shows our future minimum commitments under these purchase agreements as of December 31, 2013: | |||||||||||||||||||||||||||||
Year Ended December 31, | |||||||||||||||||||||||||||||
Thousands of dollars | 2014 | 2015 | 2016 | 2017 | 2018 | Thereafter | Total | ||||||||||||||||||||||
Purchase contracts | $ | 15,790 | $ | 28,942 | $ | 14,638 | $ | 15,663 | $ | 21,487 | $ | 45,353 | $ | 141,873 | |||||||||||||||
Surety Bonds and Letters of Credit | |||||||||||||||||||||||||||||
In the normal course of business, we have performance obligations that are secured, in whole or in part, by surety bonds or letters of credit. These obligations primarily relate to abandonments, environmental and other responsibilities where governmental and other organizations require such support. These surety bonds and letters of credit are issued by financial institutions and are required to be reimbursed by us if drawn upon. At December 31, 2013, we had $17.5 million in surety bonds and $2.8 million in letters of credit outstanding. At December 31, 2012, we had $16.2 million in surety bonds and $0.3 million in letters of credit outstanding. | |||||||||||||||||||||||||||||
Legal Proceedings | |||||||||||||||||||||||||||||
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statues to which we a |
Partners_Equity
Partners' Equity | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Partners' Capital [Abstract] | ' | ||||||||||||
Partners' Equity | ' | ||||||||||||
Partners’ Equity | |||||||||||||
At December 31, 2013 and 2012, we had approximately 119.2 million and 84.7 million in Common Units outstanding, respectively. | |||||||||||||
In February 2013, we sold approximately 14.95 million Common Units at a price to the public of $19.86 per Common Unit, resulting in net proceeds of $285.0 million, after deducting underwriting discounts and expenses. In November 2013, we sold 18.98 million Common Units at a price to the public of $18.22 per Common Unit resulting in net proceeds net of $333.2 million, after deducting underwriting discounts and estimated offering expenses. | |||||||||||||
In February 2012, we sold 9.20 million Common Units at a price to the public of $18.80 per Common Unit, resulting in net proceeds of $166.0 million after deducting underwriting discounts and offering expenses. In September 2012, we sold 11.50 million of our Common Units at a price to the public of $18.51 per Common Unit, resulting in proceeds, net of underwriting discount and offering expenses, of $204.1 million. In November 2012, we issued 3.01 million Common Units to AEO as partial consideration for the AEO Acquisition. The fair value of the units on the date of the acquisition was $18.48 per unit, or $56 million. | |||||||||||||
During the years ended December 31, 2013, 2012 and 2011, approximately 1.3 million, 1.0 million and 1.2 million Common Units, respectively, were issued to employees and outside directors pursuant to vested grants under our First Amended and Restated 2006 Long Term Incentive Plan (“LTIP”). | |||||||||||||
At December 31, 2013 and December 31, 2012, we had 9.7 million and 9.7 million, respectively, of Common Units authorized for issuance under our long-term incentive compensation plans, and there were 0.6 million and 0.9 million, respectively, of Common Units outstanding under grants that are eligible to be paid in Common Units upon vesting. | |||||||||||||
Earnings per common unit | |||||||||||||
FASB Accounting Standards require use of the “two-class” method of computing earnings per unit for all periods presented. The “two-class” method is an earnings allocation formula that determines earnings per unit for each class of common unit and participating security as if all earnings for the period had been distributed. Unvested restricted unit awards that earn non-forfeitable distribution rights qualify as participating securities and, accordingly, are included in the basic computation. Our unvested Restricted Phantom Units (“RPUs”) and Convertible Phantom Units (“CPUs”) participate in distributions on an equal basis with Common Units. Accordingly, the presentation below is prepared on a combined basis and is presented as net income (loss) per common unit. | |||||||||||||
The following is a reconciliation of net income (loss) and weighted average units for calculating basic net income (loss) per common unit and diluted net income (loss) per common unit. | |||||||||||||
Year Ended December 31, | |||||||||||||
Thousands, except per unit amounts | 2013 | 2012 | 2011 | ||||||||||
Net income (loss) attributable to limited partners | $ | (43,671 | ) | $ | (40,801 | ) | $ | 110,497 | |||||
Distributions on participating units not expected to vest | 21 | 82 | 29 | ||||||||||
Net income (loss) attributable to common unitholders and participating securities | $ | (43,650 | ) | $ | (40,719 | ) | $ | 110,526 | |||||
Weighted average number of units used to calculate basic and diluted net income (loss) per unit: | |||||||||||||
Common Units | 101,604 | 72,745 | 58,522 | ||||||||||
Participating securities (a) | — | — | 2,948 | ||||||||||
Denominator for basic earnings per common unit | 101,604 | 72,745 | 61,470 | ||||||||||
Dilutive units (b) | — | — | 134 | ||||||||||
Denominator for diluted earnings per common unit | 101,604 | 72,745 | 61,604 | ||||||||||
Net income (loss) per common unit | |||||||||||||
Basic | $ | (0.43 | ) | $ | (0.56 | ) | $ | 1.8 | |||||
Diluted | $ | (0.43 | ) | $ | (0.56 | ) | $ | 1.79 | |||||
(a) The year ended December 31, 2013 and 2012 excludes 1,649 and 2,452 of potentially issuable weighted average RPUs and CPUs from participating securities, respectively, as we were in a loss position. | |||||||||||||
(b) The year ended December 31, 2012 and 2012 excludes 364 and 55 weighted average anti-dilutive units from the calculation of the denominator for diluted earnings per common unit, respectively, as we were in a loss position. | |||||||||||||
Cash Distributions | |||||||||||||
The partnership agreement requires us to distribute all of our available cash quarterly. Available cash is cash on hand, including cash from borrowings, at the end of a quarter after the payment of expenses and the establishment of reserves for future capital expenditures and operational needs. We may fund a portion of capital expenditures with additional borrowings or issuances of additional units. We may also borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. The partnership agreement does not restrict our ability to borrow to pay distributions. The cash distribution policy reflects a basic judgment that unitholders will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it. Distributions are not cumulative. Consequently, if distributions on Common Units are not paid with respect to any fiscal quarter at the initial distribution rate, our unitholders will not be entitled to receive such payments in the future. | |||||||||||||
Prior to the fourth quarter of 2013, for the quarters for which we declared a distribution, distributions were paid within 45 days of the end of each fiscal quarter to holders of record on or about the first or second week of each such month. If the distribution date does not fall on a business day, the distribution will be made on the business day immediately preceding the indicated distribution date. On October 30, 2013, we amended our First Amended and Restated Agreement of Limited Partnership by adopting Amendment No. 5, which provided that, at the discretion of our General Partner, for the quarters for which we declare a distribution, we may pay distributions within 45 days following the end of each quarter or in three equal monthly payments within 17, 45 and 75 days following the end of each quarter. The Partnership changed its distribution payment policy from a quarterly payment schedule to a monthly payment schedule beginning with the distributions relating to the fourth quarter of 2013. | |||||||||||||
We do not have a legal obligation to pay distributions at any rate except as provided in the partnership agreement. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under the partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of reserves the General Partner determines is necessary or appropriate to provide for the conduct of the business, to comply with applicable law, any of its debt instruments or other agreements or to provide for future distributions to its unitholders for any one or more of the upcoming four quarters. The partnership agreement provides that any determination made by the General Partner in its capacity as general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by the partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or at equity. | |||||||||||||
During the years ended December 31, 2013, 2012 and 2011, we paid cash distributions of approximately $183.6 million, $127.7 million and $97.6 million. respectively, to our common unitholders. The distributions that were paid to unitholders totaled $1.91, $1.83 and $1.69 per Common Unit, respectively. We also paid cash equivalent to the distribution paid to our unitholders of $3.3 million, $4.7 million and $5.1 million, respectively, to holders of outstanding RPUs and CPUs issued under our LTIP. |
Noncontrolling_Interest
Noncontrolling Interest | 12 Months Ended |
Dec. 31, 2013 | |
Noncontrolling Interest [Abstract] | ' |
Noncontrolling Interest | ' |
Noncontrolling interest | |
FASB Accounting Standards require that noncontrolling interests be classified as a component of equity and establish reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. | |
In 2007, we acquired the limited partner interest 99% of BEPI. As such, we were fully consolidating the results of BEPI and were recognizing a noncontrolling interest representing the book value of BEPI’s general partner’s interests. Prior to April 1, 2012, BEPI’s general partner interest was held by PCEC, and PCEC held a 35% reversionary interest under the limited partnership agreement applicable to the East Coyote and Sawtelle Fields, which was expected to result in an increase in PCEC’s ownership and a corresponding decrease in our ownership in the properties during the second quarter of 2012. We and PCEC agreed to dissolve BEPI and liquidate the properties and assets of BEPI as of April 1, 2012. As a result of such agreement, PCEC’s ownership interest in both of these properties increased, and our ownership in the properties decreased from approximately 95% to 62%. |
Unit_and_Other_ValuationBased_
Unit and Other Valuation-Based Compensation Plans | 12 Months Ended | |||||||||||||||||||||
Dec. 31, 2013 | ||||||||||||||||||||||
Unit and Other Valuation Based Compensation Plans [Abstract] | ' | |||||||||||||||||||||
Unit and Other Valuation-Based Compensation Plans | ' | |||||||||||||||||||||
Unit Based Compensation Plans | ||||||||||||||||||||||
FASB Accounting Standards establish requirements for charging compensation expenses based on fair value provisions. At December 31, 2013, the RPUs and the CPUs granted under LTIP as well as the outstanding Directors RPUs discussed below were all classified as equity awards. These awards are being recognized as compensation expense on a straight line basis over the annual vesting periods as prescribed in the award agreements. | ||||||||||||||||||||||
We recognized $20.0 million, $22.2 million and $22.0 million of compensation expense related to our various plans for the years ended December 31, 2013, 2012 and 2011, respectively. | ||||||||||||||||||||||
Restricted Phantom Units | ||||||||||||||||||||||
RPUs are phantom equity awards that, to the extent vested, represent the right to receive actual partnership units upon specified payment events. Certain of our employees including our executives are eligible to receive RPU awards. We believe that RPUs properly incentivize holders of these awards to grow stable distributions for our common unitholders. RPUs generally vest in three equal annual installments on each anniversary of the vesting commencement date of the award. In addition, each RPU is granted in tandem with a distribution equivalent right that will remain outstanding from the grant of the RPU until the earlier to occur of its forfeiture or the payment of the underlying unit, and which entitles the grantee to receive payment of amounts equal to distributions paid to each holder of an actual partnership unit during such period. RPUs that do not vest for any reason are forfeited upon a grantee’s termination of employment. | ||||||||||||||||||||||
The fair value of the RPUs is determined based on the fair market value of our units on the date of grant. RPU awards were granted to BreitBurn Management employees during the years ended December 31, 2013, 2012 and 2011 as shown in the table below. We recorded compensation expense of $17.0 million, $17.4 million and $16.9 million in 2013, 2012 and 2011, respectively, related to the amortization of outstanding RPUs over their related vesting periods. As of December 31, 2013, there was $18.4 million of total unrecognized compensation cost remaining for the unvested RPUs. This amount is expected to be recognized over the next two years. The total fair value of units that vested during the years ended December 31, 2013, 2012 and 2011 was $17.2 million, $17.4 million, and $21.5 million, respectively. | ||||||||||||||||||||||
The following table summarizes information about RPUs: | ||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||
Number | Weighted | Number | Weighted | Number | Weighted | |||||||||||||||||
of | Average | of | Average | of | Average | |||||||||||||||||
Thousands, except per unit amounts | RPUs | Fair Value | RPUs | Fair Value | RPUs | Fair Value | ||||||||||||||||
Outstanding, beginning of period | 817 | $ | 20.92 | 983 | $ | 18.35 | 1,747 | $ | 13.4 | |||||||||||||
Granted | 919 | 20.77 | 887 | 19.61 | 758 | 21.6 | ||||||||||||||||
Exercised (a) | (833 | ) | 20.62 | (1,005 | ) | 17.33 | (1,505 | ) | 14.26 | |||||||||||||
Canceled | (7 | ) | 21.6 | (48 | ) | 19.06 | (17 | ) | 16.68 | |||||||||||||
Outstanding, end of period | 896 | $ | 21.05 | 817 | $ | 20.92 | 983 | $ | 18.35 | |||||||||||||
Exercisable, end of period | — | $ | — | — | $ | — | — | $ | — | |||||||||||||
(a) Includes 308, 394 and 521 units canceled at the time of distribution for income tax liability payments the Partnership made on behalf of the restricted unit grantees for years ended December 31, 2013, 2012 and 2011, respectively. | ||||||||||||||||||||||
Convertible Phantom Units | ||||||||||||||||||||||
On January 28, 2013, the Compensation and Governance Committee approved an amendment to the First Amended and Restated Partnership 2006 Long-Term Incentive Plan granting Participants CPU in tandem with a corresponding Performance Distribution Right (“PDR”) which will remain outstanding from the Grant Date until the earlier to occur of a Payment Date or the forfeiture of the CPU to which such PDR corresponds. Each CPU granted under this Agreement will be issued in tandem with a corresponding PDR, which will entitle the Participant to receive an amount determined by reference to Partnership distributions and which will be credited to the Participant in the form of additional CPUs equal to the product of (i) the aggregate per Unit distributions paid by the Partnership in respect of each quarter through which the PDR remains outstanding (provided that the PDR is outstanding as of the record date set by the Board of Directors of the Company for such distribution) (including any extraordinary non-recurring distributions paid during a quarter), if any, times (ii) the number of common unit equivalents (“CUEs”) underlying the relevant CPU during such quarter, divided by the closing price of the Unit on the date on which such distribution is paid to Unitholders. All such PDRs will be credited to the Participant in the form of additional CPUs as of the date of payment of any such distribution based on the Fair Market Value of a Unit on such date. Each additional CPU which results from such crediting of PDRs granted hereunder will be subject to the same vesting, forfeiture, payment or distribution, adjustment and other provisions which apply to the underlying CPU to which such additional CPU relates. PDRs will not entitle the Participant to any amounts relating to distributions occurring after the earlier to occur of the applicable Payment Date or the Participant’s forfeiture of the CPU to which such PDR relates in accordance herewith. The CPUs will vest and the number of CUEs underlying such CPUs (if any) on the earliest to occur of (i) an applicable accelerated vesting date, and (ii) December 28, 2015, in each case subject to the Participant’s continued employment with the Partnership through any such date. CPUs that vest will represent the right to receive payment in the form of a number of Units equal to (i) the product of (A) the number of CPUs so vested, times (B) the number of CUEs underlying such CPUs on the applicable Vesting Date, minus (ii) the applicable number of PDR Equalization Units, if any (such number of Units, the “Resultant Units”). Unless and until a CPU vests, the Participant will have no right to payment of Units in respect of any such CPU. Prior to actual payment in respect of any vested CPU, such CPU will represent an unsecured obligation of the Partnership, payable (if at all) only from the general assets of the Partnership. | ||||||||||||||||||||||
On January 28, 2013, 0.3 million units of CPUs (“2013 CPUs”) were granted at a price of $20.98 per Common Unit. We recorded compensation expense for the 2013 CPUs of $2.3 million in 2013. As of December 31, 2013, 0.4 million of unvested 2013 CPU units were outstanding and $4.7 million of total unrecognized compensation cost remained for the unvested 2013 CPUs. Such cost is expected to be recognized over the next three years. | ||||||||||||||||||||||
In December 2007, seven executives, Halbert Washburn, Randall Breitenbach, Mark Pease, James Jackson, Gregory Brown, Thurmon Andress and Jackson Washburn, received 0.7 million units of CPUs (“2007 CPUs”) at a grant price of $30.29 per Common Unit. Each of the 2007 CPU awards had the vesting commencement date of January 1, 2008 and were to vest on the earliest to occur of (i) January 1, 2013, (ii) the date on which the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than or equal to $3.10 per Common Unit and (iii) upon the occurrence of the death or “disability” of the grantee or his or her termination without “cause” or for “good reason” (as defined in the holder’s employment agreement, if applicable). | ||||||||||||||||||||||
On December 13, 2012, certain of our executive officers entered into an amendment with respect to their 2007 CPU grants, that provided that such grants could vest on December 28, 2012 instead of January 1, 2013. On vesting, each 2007 CPU converted into a number of CUEs equal to the number of Common Unit equivalents underlying the 2007 CPUs. The 2007 CPUs were converted to Common Units on a one-to-one basis and in total 0.7 million Common Units were issued. We recorded compensation expense for the 2007 CPUs of $4.1 million in 2012 and $4.1 million in 2011. | ||||||||||||||||||||||
Director Restricted Phantom Units | ||||||||||||||||||||||
Effective with the initial public offering until 2011, we also made grants of Restricted Phantom Units in the Partnership to the non-employee directors of our General Partner. Each phantom unit was accompanied by a distribution equivalent unit right entitling the holder to an additional number of phantom units with a value equal to the amount of distributions paid on each of our Common Units until settlement. Since 2010, the phantom units were paid in Common Units upon vesting, and the unit-settled awards are classified as equity. The estimated fair value associated with these phantom units is expensed in the statement of income over the vesting period. Since 2011, we have made grants of RPUs to the non-employee directors of our General Partner that are substantially similar to the ones granted to employees. | ||||||||||||||||||||||
We recorded compensation expense for the director’s phantom units of approximately $0.7 million, $0.6 million and, $1.0 million in 2013, 2012 and 2011, respectively. As of December 31, 2013, there was $0.7 million of total unrecognized compensation cost for the unvested Director Performance Units and such cost is expected to be recognized over the next two years. | ||||||||||||||||||||||
The following table summarizes information about the Director Restricted Phantom Units: | ||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||
Number | Weighted | Number | Weighted | Number | Weighted | |||||||||||||||||
of | Average | of | Average | of | Average | |||||||||||||||||
Thousands, except per unit amounts | Units | Fair Value | Units | Fair Value | Units | Fair Value | ||||||||||||||||
Outstanding, beginning of period | 48 | $ | 20.43 | 132 | $ | 13.45 | 131 | $ | 13.05 | |||||||||||||
Granted | 38 | 20.98 | 29 | $ | 19.63 | 41 | 21.68 | |||||||||||||||
Exercised | (19 | ) | 20.63 | (113 | ) | 12.11 | (40 | ) | 20.55 | |||||||||||||
Outstanding, end of period | 67 | $ | 20.69 | 48 | $ | 20.43 | 132 | $ | 13.45 | |||||||||||||
Exercisable, end of period | — | $ | — | — | $ | — | — | $ | — | |||||||||||||
Retirement_Plan
Retirement Plan | 12 Months Ended |
Dec. 31, 2013 | |
Compensation and Retirement Disclosure [Abstract] | ' |
Retirement Plan | ' |
Retirement Plan | |
BreitBurn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. All of our employees, including our executives, are employees of BreitBurn Management. BreitBurn Management has a defined contribution retirement plan, which covers substantially all of its employees commencing on the first day of the month following the month of hire. The plan provides for BreitBurn Management to make regular contributions based on employee contributions as provided for in the plan agreement. Employees fully vest in BreitBurn Management’s contributions after five years of service. PCEC is charged for a portion of the matching contributions made by BreitBurn Management. For the years ended December 31, 2013, 2012 and 2011, we recognized expense related to matching contributions of $2.0 million, $1.3 million and $1.1 million, respectively. |
Significant_Customers
Significant Customers | 12 Months Ended | |||||||||
Dec. 31, 2013 | ||||||||||
Risks and Uncertainties [Abstract] | ' | |||||||||
Significant Customers | ' | |||||||||
Significant Customers | ||||||||||
We sell oil, NGLs and natural gas primarily to large, established domestic refiners and utilities. For the years ended December 31, 2013, 2012 and 2011, we sold oil, NGL and natural gas production representing 10% or more of total revenue to the following purchasers: | ||||||||||
2013 | 2012 | 2011 | ||||||||
Phillips 66 (a) | 15 | % | 16 | % | — | % | ||||
Shell Trading | 15 | % | 2 | % | 4 | % | ||||
Marathon Oil Corporation | 10 | % | 14 | % | 15 | % | ||||
Plains Marketing & Transportation LLC | 9 | % | 17 | % | 16 | % | ||||
ConocoPhillips | 5 | % | 14 | % | 30 | % | ||||
(a) During 2012, Phillips 66 and ConocoPhillips became two separate entities. | ||||||||||
Our sales contracts are sold at market-sensitive or spot prices. Because commodity products are sold primarily on the basis of price and availability, we are not dependent upon one purchaser or a small group of purchasers. As a result, the loss of any one purchaser would not have a long-term material adverse effect on our ability to sell our production. |
Subsequent_Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2013 | |
Subsequent Events [Abstract] | ' |
Subsequent Events | ' |
s | |
On January 2, 2014, we announced a cash distribution to unitholders for the first monthly payment attributable to the fourth quarter of 2013 at the rate of $0.1642 per Common Unit, which was paid on January 16, 2014 to the record holders of common units at the close of business on January 13, 2014. | |
On January 30, 2014, we announced a cash distribution to unitholders for the second monthly payment attributable to the fourth quarter of 2013 at the rate of $0.1642 per Common Unit, which was paid on February 14, 2014 to the record holders of common units at the close of business on February 10, 2014. | |
On February 27, 2014, we announced a cash distribution to unitholders for the third monthly payment attributable to the fourth quarter of 2013 at the rate of $0.1642 per Common Unit, which will be paid on March 14, 2014 to the record holders of Common Units at the close of business on March 10, 2014. | |
In February 2014, we entered into the Eleventh Amendment to the Second Amended and Restated Credit Agreement that eliminated the Maximum Total Leverage Ratio (defined as the ratio of total debt to EBITDAX) and Maximum Senior Secured Leverage Ratio (defined as the ratio of senior secured indebtedness to EBITDAX) requirements and added a provision requiring us to maintain an Interest Coverage Ratio (defined as EBITDAX divided by Consolidated Interest Expense) for the four quarters ending on the last day of each quarter beginning with the fourth quarter of 2013 of no less than 2.50 to 1.00. The amendment also provides that we cannot incur senior unsecured debt in excess of our borrowing base in effect at the time of the issuance of such debt. |
Supplemental_Information_Quart
Supplemental Information: Quarterly Financial Data (Unaudited) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Quarterly Financial Data [Abstract] | ' | ||||||||||||||||
Quarterly Financial Data (Unaudited) | ' | ||||||||||||||||
Quarterly Financial Data (Unaudited) | |||||||||||||||||
Year ended December 31, 2013 | |||||||||||||||||
First | Second | Third | Fourth | ||||||||||||||
Thousands of dollars except per unit amounts | Quarter | Quarter | Quarter | Quarter | |||||||||||||
Oil, NGL and natural gas sales | $ | 120,362 | $ | 149,286 | $ | 197,413 | $ | 193,604 | |||||||||
Gain (loss) on derivative instruments, net | (24,176 | ) | 66,993 | (54,765 | ) | (17,234 | ) | ||||||||||
Other revenue, net | 758 | 702 | 737 | 978 | |||||||||||||
Total revenue | 96,944 | 216,981 | 143,385 | 177,348 | |||||||||||||
Operating income (loss) | (17,853 | ) | 95,419 | (1,435 | ) | (31,855 | ) | ||||||||||
Net income (loss) (a) | $ | (36,300 | ) | $ | 76,432 | $ | (25,011 | ) | $ | (58,792 | ) | ||||||
Basic net income (loss) per limited partner unit (b) | $ | (0.38 | ) | $ | 0.75 | $ | (0.25 | ) | $ | (0.52 | ) | ||||||
Diluted net income (loss) per limited partner unit (b) | $ | (0.38 | ) | $ | 0.75 | $ | (0.25 | ) | $ | (0.52 | ) | ||||||
(a) Fourth quarter 2013, we recognized and recorded an impairment charge of $54.4 million due to reserve adjustments due to lower performance and a decrease in expected future commodity prices. See Note 8 for details on impairments. | |||||||||||||||||
(b) Due to changes in the number of weighted average common units outstanding that may occur each quarter, the sum of the earnings per unit amounts for the quarters may not be additive to the full year earnings per unit amount. | |||||||||||||||||
Year ended December 31, 2012 | |||||||||||||||||
First | Second | Third | Fourth | ||||||||||||||
Thousands of dollars except per unit amounts | Quarter | Quarter | Quarter | Quarter | |||||||||||||
Oil, NGL and natural gas sales | $ | 94,007 | $ | 94,981 | $ | 111,700 | $ | 113,179 | |||||||||
Gain (loss) on derivative instruments, net | (36,005 | ) | 107,288 | (69,418 | ) | 3,715 | |||||||||||
Other revenue, net | 1,145 | 907 | 796 | 700 | |||||||||||||
Total revenue | 59,147 | 203,176 | 43,078 | 117,594 | |||||||||||||
Operating income (loss) | (36,194 | ) | 107,810 | (58,029 | ) | 8,113 | |||||||||||
Net income (loss) (a) | $ | (49,925 | ) | $ | 92,523 | $ | (73,003 | ) | $ | (10,334 | ) | ||||||
Basic net income (loss) per limited partner unit (b) | $ | (0.76 | ) | $ | 1.29 | $ | (1.00 | ) | $ | (0.13 | ) | ||||||
Diluted net income (loss) per limited partner unit (b) | $ | (0.76 | ) | $ | 1.29 | $ | (1.00 | ) | $ | (0.13 | ) | ||||||
(a) First quarter and Second quarter 2012, we recognized and recorded impairment charges of $9.0 million and $3.3 million, respectively, due to a decrease in future natural gas prices and reserve adjustments due to lower performance. See Note 8 for details on impairments. | |||||||||||||||||
(b) Due to changes in the number of weighted average common units outstanding that may occur each quarter, the sum of the earnings per unit amounts for the quarters may not be additive to the full year earnings per unit amount. |
Summary_of_Significant_Account1
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2013 | |
Accounting Policies [Abstract] | ' |
Summary of Significant Accounting Policies | ' |
2. Summary of Significant Accounting Policies | |
Principles of consolidation and basis of presentation | |
The consolidated financial statements include our accounts and the accounts of our wholly owned subsidiaries. Investments in affiliated companies with a 20% or greater ownership interest, and in which we have significant influence but do not have control, are accounted for on an equity basis. Investments in affiliated companies with less than a 20% ownership interest, and in which we do not have control, are accounted for on the cost basis. Investments in which we own greater than a 50% interest and in which we have control are consolidated. Investments in which we own less than a 50% interest but are deemed to have control, or where we have a variable interest in an entity in which we will absorb a majority of the entity’s expected losses or receive a majority of the entity’s expected residual returns or both, however, are consolidated. The effects of all intercompany transactions have been eliminated. | |
Certain reclassifications have been made to our 2012 and 2011 consolidated financial statements in order to conform them to the 2013 presentation. These reclassifications were not material to the financial statements | |
Use of estimates | |
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The financial statements are based on a number of significant estimates including acquisition purchase price allocations, fair value of derivative instruments, unit-based compensation and oil and gas reserve quantities, which are the basis for the calculation of depletion, depreciation and amortization (“DD&A”), asset retirement obligations and impairment of oil and gas properties. | |
Business segment information | |
We report our operations in one segment because our oil and gas operating areas have similar economic characteristics. We acquire, exploit, develop and produce oil and natural gas in the United States. Corporate management administers all properties as a whole rather than as discrete operating segments. Operational data is tracked by area; however, financial performance is measured as a single enterprise and not on an area-by-area basis. Allocation of capital resources is employed on a project-by-project basis across our entire asset base to maximize profitability without regard to individual areas. | |
Revenue recognition | |
We recognize revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred, (iii) the seller’s price to the buyer is fixed or determinable and (iv) collectability is reasonably assured. | |
Revenues from properties in which we have an interest with other partners are recognized on the basis of our working interest (“entitlement” method of accounting). We generally market most of our natural gas production from our operated properties and pay our partners for their working interest shares of natural gas production sold. As a result, we have no material natural gas producer imbalance positions. | |
Accounts receivable | |
Our accounts receivable are primarily from purchasers of oil and natural gas and counterparties to our financial instruments. Oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. At December 31, 2013 and 2012, we had an allowance for doubtful accounts receivable of $0.6 million and $0.6 million, respectively. | |
Inventory | |
Our inventory consists of oil held in storage tanks related to our Florida operations pending shipment by barge to the point of sale. Oil inventories are carried at the lower of cost to produce or market price. We match production expenses with oil sales. Production expenses associated with unsold oil inventory are recorded as inventory. | |
Investments in equity affiliates | |
Income from equity affiliates is included as a component of operating income, as the operations of these affiliates are associated with the processing and transportation of our natural gas production. | |
Property, plant and equipment | |
Oil and gas properties | |
We follow the successful efforts method of accounting. Lease acquisition and development costs (tangible and intangible) incurred relating to proved oil and gas properties are capitalized. Delay and surface rentals are charged to expense as incurred. Dry hole costs incurred on exploratory wells are expensed. Dry hole costs associated with developing proved fields are capitalized. Geological and geophysical costs related to exploratory operations are expensed as incurred. | |
The Partnership carries out tertiary recovery methods on certain of its oil and gas properties in Oklahoma in order to recover additional hydrocarbons that are not recoverable from primary or secondary recovery methods. Acquisition costs of tertiary injectants, such as purchased CO2, for enhanced oil recovery (“EOR”) activities that are used prior to the recognition of proved tertiary recovery reserves are expensed as incurred. After a project has been determined to be technically feasible and economically viable, all acquisition costs of tertiary injectants are capitalized as development costs and depleted, as they are incurred solely for obtaining access to reserves not otherwise recoverable and have future economic benefits over the life of the project. As CO2 is recovered together with oil and gas production, it is extracted and re-injected, and all the associated CO2 recycling costs are expensed as incurred. Likewise, other costs incurred to maintain reservoir pressure are also expensed. | |
Upon sale or retirement of proved properties, the cost thereof and the DD&A are removed from the accounts and any gain or loss is recognized in the statement of operations. Maintenance and repairs are charged to operating expenses. DD&A of proved oil and gas properties, including the estimated cost of future abandonment and restoration of well sites and associated facilities, is generally computed on a field-by-field basis where applicable and recognized using the units of production method net of any anticipated proceeds from equipment salvage and sale of surface rights. Other gathering and processing facilities are recorded at cost and are depreciated using the straight-line method over their estimated useful lives, generally over 20 years. | |
We capitalize interest costs to oil and gas properties on expenditures made in connection with major projects and the drilling and completion of new oil and natural gas wells. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the units of production method. During 2013, 2012 and 2011, interest of $0.1 million, $0.1 million and $0.1 million, respectively, was capitalized and included in our capital expenditures. | |
Non-oil and gas assets | |
Buildings and non-oil and gas assets are recorded at cost and depreciated using the straight-line method over their estimated useful lives, which range from three to ten years. | |
Oil and natural gas reserve quantities | |
Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion are made concurrently with changes to reserve estimates. We disclose reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with the Securities and Exchange Commission (the “SEC”) guidelines. The independent engineering firms adhere to the SEC definitions when preparing their reserve reports. | |
Asset retirement obligations | |
We have significant obligations to plug and abandon oil and natural gas wells and related equipment at the end of oil and natural gas production operations. The fair value of a liability for an asset retirement obligation (“ARO”) is recorded when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. Over time, changes in the present value of the liability are accreted and recorded as part of DD&A on the consolidated statements of operations. The capitalized asset costs are depreciated over the useful lives of the corresponding asset. Recognized liability amounts are based upon future retirement cost estimates and incorporate many assumptions such as: (1) expected economic recoveries of oil and natural gas, (2) time to abandonment, (3) future inflation rates and (4) the risk free rate of interest adjusted for our credit costs. Future revisions to ARO estimates will impact the present value of existing ARO liabilities and corresponding adjustments will be made to the capitalized asset retirement costs balance. | |
Impairment of assets | |
Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. A long-lived asset is tested for impairment periodically and when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is generally determined from estimated discounted future net cash flows. For purposes of performing an impairment test, the undiscounted future cash flows are based on total proved and risk-adjusted probable and possible reserves, and are forecast using five-year NYMEX forward strip prices at the end of the period and escalated along with expenses and capital starting year six and thereafter at 2.5% per year. For impairment charges, the associated property’s expected future net cash flows are discounted using a weighted average cost of capital which approximated 10% at December 31, 2013. Reserves are calculated based upon reports from third party engineers adjusted for acquisitions or other changes occurring during the year as determined to be appropriate in the good faith judgment of management. Unproved properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred. | |
We assess our long-lived assets for impairment generally on a field-by-field basis where applicable. See Note 8 for a discussion of our impairments. | |
Debt issuance costs | |
The costs incurred to obtain financing have been capitalized. Debt issuance costs are amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the effective interest method of amortization. | |
Equity-based compensation | |
BreitBurn Management has various forms of equity-based compensation outstanding under employee compensation plans that are described more fully in Note 17. Awards classified as equity are valued on the grant date and are recognized as compensation expense over the vesting period, which is part of the general and administrative (“G&A”) expenses line on the Consolidated Statements of Operations. We recognize equity-based compensation costs on a straight line basis over the annual vesting periods. | |
Fair market value of financial instruments | |
The carrying amount of our cash, accounts receivable, accounts payable, related party receivables and payables and accrued expenses approximate their respective fair value due to the relatively short term of the related instruments. The carrying amount of long-term debt under our credit facility approximates fair value; however, changes in the credit markets may impact our ability to enter into future credit facilities at similar terms. See Note 10 for the fair value of our Senior Notes under long-term debt. | |
Accounting for business combinations | |
We account for all business combinations using the acquisition method. Under the acquisition method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, equity or the assumption of liabilities. The assets and liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if material, is recognized as a gain at the time of acquisition. Similarly, the deficit of the fair value of assets acquired and liabilities assumed under the cost of an acquired entity, if material, is recognized as goodwill at the time of acquisition. All purchase price allocations are finalized within one year from the acquisition date. | |
Concentration of credit risk | |
We maintain our cash accounts primarily with a single bank and invest cash in money market accounts, which we believe to have minimal risk. At times, such balances may be in excess of the Federal Insurance Corporation insurance limit. As operator of jointly owned oil and gas properties, we sell oil and gas production to U.S. oil and gas purchasers and pay vendors on behalf of joint owners for oil and gas services. We periodically monitor our major purchasers’ credit ratings. We enter into commodity and interest rate derivative instruments. Our derivative counterparties are all lenders under our credit facility, and we periodically monitor their credit ratings. | |
Derivatives | |
Financial Accounting Standards Board (“FASB”) Accounting Standards establish accounting and reporting requirements for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities. These standards require recognition of all derivative instruments as assets or liabilities on our balance sheet and measurement of those instruments at fair value. The accounting treatment of changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge and if so, the type of hedge. We currently do not designate any of our derivatives as hedges for financial accounting purposes. Gains and losses on derivative instruments not designated as hedges are currently included in earnings. The resulting cash flows are reported as cash from operating activities. | |
Fair value measurement is based upon a hypothetical transaction to sell an asset or transfer a liability at the measurement date. The objective of fair value measurement is to determine the price that would be received in selling the asset or transferring the liability in an orderly transaction between market participants at the measurement date. If we have a principal market for the asset or liability, the fair value measurement shall represent the price in that market, otherwise the price will be determined based on the most advantageous market. | |
Income taxes | |
Our subsidiaries are mostly partnerships or limited liability companies treated as partnerships for federal tax purposes with essentially all taxable income or loss being passed through to the members. As such, no federal income tax for these entities has been provided. | |
We have three wholly-owned subsidiaries that are subject to corporate income taxes. Deferred income taxes are recorded under the asset and liability method. Where material, deferred income tax assets and liabilities are computed for differences between the financial statement and income tax bases of assets and liabilities that will result in taxable or deductible amounts in the future. Such deferred income tax asset and liability computations are based on enacted tax laws and rates applicable to periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable or refundable for the period plus or minus the change during the period in deferred income tax assets and liabilities. | |
FASB Accounting Standards clarify the accounting for uncertainty in income taxes recognized in a company’s financial statements. A company can only recognize an uncertain tax position in the financial statements if the position is more-likely-than-not to be upheld on audit based only on the technical merits of the tax position. This accounting standard also provides guidance on thresholds, measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition that is intended to provide better financial-statement comparability among different companies. | |
We performed analysis as of December 31, 2013 and 2012 and concluded that there were no uncertain tax positions requiring recognition in our financial statements. | |
Net Income or loss per unit | |
FASB Accounting Standards require use of the “two-class” method of computing earnings per unit for all periods presented. The “two-class” method is an earnings allocation formula that determines earnings per unit for each class of Common Unit and participating security as if all earnings for the period had been distributed. Unvested restricted unit awards that earn non-forfeitable dividend rights qualify as participating securities and, accordingly, are included in the basic computation. Our unvested restricted phantom units (“RPUs”) and convertible phantom units (“CPUs”) participate in dividends on an equal basis with Common Units; therefore, there is no difference in undistributed earnings allocated to each participating security. Accordingly, our calculation is prepared on a combined basis and is presented as net income (loss) per Common Unit. See Note 15 for our earnings per Common Unit calculation. | |
Environmental expenditures | |
We review, on an annual basis, our estimates of the cleanup costs of various sites. When it is probable that obligations have been incurred and where a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued. At December 31, 2013, we had a $2.2 million undiscounted environmental liability accrued that included cost estimates related to the maintenance of ground water monitoring wells associated with certain former well sites in Michigan that are no longer producing. At December 31, 2012, we had a $1.9 million undiscounted environmental liability accrued. | |
Accounting Standards | |
There were no new accounting standards issued but not yet effective that are expected to have a material impact on our financial position, results of operations or cash flows. | |
Principles of consolidation | ' |
Principles of consolidation and basis of presentation | |
The consolidated financial statements include our accounts and the accounts of our wholly owned subsidiaries. Investments in affiliated companies with a 20% or greater ownership interest, and in which we have significant influence but do not have control, are accounted for on an equity basis. Investments in affiliated companies with less than a 20% ownership interest, and in which we do not have control, are accounted for on the cost basis. Investments in which we own greater than a 50% interest and in which we have control are consolidated. Investments in which we own less than a 50% interest but are deemed to have control, or where we have a variable interest in an entity in which we will absorb a majority of the entity’s expected losses or receive a majority of the entity’s expected residual returns or both, however, are consolidated. The effects of all intercompany transactions have been eliminated. | |
Certain reclassifications have been made to our 2012 and 2011 consolidated financial statements in order to conform them to the 2013 presentation. These reclassifications were not material to the financial statements | |
Use of estimates | ' |
Use of estimates | |
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The financial statements are based on a number of significant estimates including acquisition purchase price allocations, fair value of derivative instruments, unit-based compensation and oil and gas reserve quantities, which are the basis for the calculation of depletion, depreciation and amortization (“DD&A”), asset retirement obligations and impairment of oil and gas properties. | |
Business segment information | ' |
Business segment information | |
We report our operations in one segment because our oil and gas operating areas have similar economic characteristics. We acquire, exploit, develop and produce oil and natural gas in the United States. Corporate management administers all properties as a whole rather than as discrete operating segments. Operational data is tracked by area; however, financial performance is measured as a single enterprise and not on an area-by-area basis. Allocation of capital resources is employed on a project-by-project basis across our entire asset base to maximize profitability without regard to individual areas. | |
Revenue recognition | ' |
Revenue recognition | |
We recognize revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred, (iii) the seller’s price to the buyer is fixed or determinable and (iv) collectability is reasonably assured. | |
Revenues from properties in which we have an interest with other partners are recognized on the basis of our working interest (“entitlement” method of accounting). We generally market most of our natural gas production from our operated properties and pay our partners for their working interest shares of natural gas production sold. As a result, we have no material natural gas producer imbalance positions. | |
Accounts Receivable | ' |
Accounts receivable | |
Our accounts receivable are primarily from purchasers of oil and natural gas and counterparties to our financial instruments. Oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. At December 31, 2013 and 2012, we had an allowance for doubtful accounts receivable of $0.6 million and $0.6 million, respectively. | |
Inventory | ' |
Inventory | |
Our inventory consists of oil held in storage tanks related to our Florida operations pending shipment by barge to the point of sale. Oil inventories are carried at the lower of cost to produce or market price. We match production expenses with oil sales. Production expenses associated with unsold oil inventory are recorded as inventory. | |
Investments in equity affiliates | ' |
Investments in equity affiliates | |
Income from equity affiliates is included as a component of operating income, as the operations of these affiliates are associated with the processing and transportation of our natural gas production. | |
Property, plant and equipment | ' |
Property, plant and equipment | |
Oil and gas properties | |
We follow the successful efforts method of accounting. Lease acquisition and development costs (tangible and intangible) incurred relating to proved oil and gas properties are capitalized. Delay and surface rentals are charged to expense as incurred. Dry hole costs incurred on exploratory wells are expensed. Dry hole costs associated with developing proved fields are capitalized. Geological and geophysical costs related to exploratory operations are expensed as incurred. | |
The Partnership carries out tertiary recovery methods on certain of its oil and gas properties in Oklahoma in order to recover additional hydrocarbons that are not recoverable from primary or secondary recovery methods. Acquisition costs of tertiary injectants, such as purchased CO2, for enhanced oil recovery (“EOR”) activities that are used prior to the recognition of proved tertiary recovery reserves are expensed as incurred. After a project has been determined to be technically feasible and economically viable, all acquisition costs of tertiary injectants are capitalized as development costs and depleted, as they are incurred solely for obtaining access to reserves not otherwise recoverable and have future economic benefits over the life of the project. As CO2 is recovered together with oil and gas production, it is extracted and re-injected, and all the associated CO2 recycling costs are expensed as incurred. Likewise, other costs incurred to maintain reservoir pressure are also expensed. | |
Upon sale or retirement of proved properties, the cost thereof and the DD&A are removed from the accounts and any gain or loss is recognized in the statement of operations. Maintenance and repairs are charged to operating expenses. DD&A of proved oil and gas properties, including the estimated cost of future abandonment and restoration of well sites and associated facilities, is generally computed on a field-by-field basis where applicable and recognized using the units of production method net of any anticipated proceeds from equipment salvage and sale of surface rights. Other gathering and processing facilities are recorded at cost and are depreciated using the straight-line method over their estimated useful lives, generally over 20 years. | |
We capitalize interest costs to oil and gas properties on expenditures made in connection with major projects and the drilling and completion of new oil and natural gas wells. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the units of production method. During 2013, 2012 and 2011, interest of $0.1 million, $0.1 million and $0.1 million, respectively, was capitalized and included in our capital expenditures. | |
Non-oil and gas assets | |
Buildings and non-oil and gas assets are recorded at cost and depreciated using the straight-line method over their estimated useful lives, which range from three to ten years. | |
Oil and natural gas reserve quantities | ' |
Oil and natural gas reserve quantities | |
Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion are made concurrently with changes to reserve estimates. We disclose reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with the Securities and Exchange Commission (the “SEC”) guidelines. The independent engineering firms adhere to the SEC definitions when preparing their reserve reports. | |
Asset retirement obligations | ' |
Asset retirement obligations | |
We have significant obligations to plug and abandon oil and natural gas wells and related equipment at the end of oil and natural gas production operations. The fair value of a liability for an asset retirement obligation (“ARO”) is recorded when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. Over time, changes in the present value of the liability are accreted and recorded as part of DD&A on the consolidated statements of operations. The capitalized asset costs are depreciated over the useful lives of the corresponding asset. Recognized liability amounts are based upon future retirement cost estimates and incorporate many assumptions such as: (1) expected economic recoveries of oil and natural gas, (2) time to abandonment, (3) future inflation rates and (4) the risk free rate of interest adjusted for our credit costs. Future revisions to ARO estimates will impact the present value of existing ARO liabilities and corresponding adjustments will be made to the capitalized asset retirement costs balance. | |
Impairment of assets | ' |
Impairment of assets | |
Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. A long-lived asset is tested for impairment periodically and when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is generally determined from estimated discounted future net cash flows. For purposes of performing an impairment test, the undiscounted future cash flows are based on total proved and risk-adjusted probable and possible reserves, and are forecast using five-year NYMEX forward strip prices at the end of the period and escalated along with expenses and capital starting year six and thereafter at 2.5% per year. For impairment charges, the associated property’s expected future net cash flows are discounted using a weighted average cost of capital which approximated 10% at December 31, 2013. Reserves are calculated based upon reports from third party engineers adjusted for acquisitions or other changes occurring during the year as determined to be appropriate in the good faith judgment of management. Unproved properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred. | |
We assess our long-lived assets for impairment generally on a field-by-field basis where applicable. See Note 8 for a discussion of our impairments | |
Debt issuance costs | ' |
Debt issuance costs | |
The costs incurred to obtain financing have been capitalized. Debt issuance costs are amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the effective interest method of amortization. | |
Equity-based compensation | ' |
Equity-based compensation | |
BreitBurn Management has various forms of equity-based compensation outstanding under employee compensation plans that are described more fully in Note 17. Awards classified as equity are valued on the grant date and are recognized as compensation expense over the vesting period, which is part of the general and administrative (“G&A”) expenses line on the Consolidated Statements of Operations. We recognize equity-based compensation costs on a straight line basis over the annual vesting periods. | |
Fair market value of financial instruments | ' |
Fair market value of financial instruments | |
The carrying amount of our cash, accounts receivable, accounts payable, related party receivables and payables and accrued expenses approximate their respective fair value due to the relatively short term of the related instruments. The carrying amount of long-term debt under our credit facility approximates fair value; however, changes in the credit markets may impact our ability to enter into future credit facilities at similar terms. See Note 10 for the fair value of our Senior Notes under long-term debt. | |
Accounting for business combinations | ' |
Accounting for business combinations | |
We account for all business combinations using the acquisition method. Under the acquisition method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, equity or the assumption of liabilities. The assets and liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if material, is recognized as a gain at the time of acquisition. Similarly, the deficit of the fair value of assets acquired and liabilities assumed under the cost of an acquired entity, if material, is recognized as goodwill at the time of acquisition. All purchase price allocations are finalized within one year from the acquisition date. | |
Concentration of credit risk | ' |
Concentration of credit risk | |
We maintain our cash accounts primarily with a single bank and invest cash in money market accounts, which we believe to have minimal risk. At times, such balances may be in excess of the Federal Insurance Corporation insurance limit. As operator of jointly owned oil and gas properties, we sell oil and gas production to U.S. oil and gas purchasers and pay vendors on behalf of joint owners for oil and gas services. We periodically monitor our major purchasers’ credit ratings. We enter into commodity and interest rate derivative instruments. Our derivative counterparties are all lenders under our credit facility, and we periodically monitor their credit ratings. | |
Derivatives | ' |
Derivatives | |
Financial Accounting Standards Board (“FASB”) Accounting Standards establish accounting and reporting requirements for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities. These standards require recognition of all derivative instruments as assets or liabilities on our balance sheet and measurement of those instruments at fair value. The accounting treatment of changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge and if so, the type of hedge. We currently do not designate any of our derivatives as hedges for financial accounting purposes. Gains and losses on derivative instruments not designated as hedges are currently included in earnings. The resulting cash flows are reported as cash from operating activities. | |
Fair value measurement is based upon a hypothetical transaction to sell an asset or transfer a liability at the measurement date. The objective of fair value measurement is to determine the price that would be received in selling the asset or transferring the liability in an orderly transaction between market participants at the measurement date. If we have a principal market for the asset or liability, the fair value measurement shall represent the price in that market, otherwise the price will be determined based on the most advantageous market. | |
Income taxes | ' |
Income taxes | |
Our subsidiaries are mostly partnerships or limited liability companies treated as partnerships for federal tax purposes with essentially all taxable income or loss being passed through to the members. As such, no federal income tax for these entities has been provided. | |
We have three wholly-owned subsidiaries that are subject to corporate income taxes. Deferred income taxes are recorded under the asset and liability method. Where material, deferred income tax assets and liabilities are computed for differences between the financial statement and income tax bases of assets and liabilities that will result in taxable or deductible amounts in the future. Such deferred income tax asset and liability computations are based on enacted tax laws and rates applicable to periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable or refundable for the period plus or minus the change during the period in deferred income tax assets and liabilities. | |
FASB Accounting Standards clarify the accounting for uncertainty in income taxes recognized in a company’s financial statements. A company can only recognize an uncertain tax position in the financial statements if the position is more-likely-than-not to be upheld on audit based only on the technical merits of the tax position. This accounting standard also provides guidance on thresholds, measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition that is intended to provide better financial-statement comparability among different companies. | |
We performed analysis as of December 31, 2013 and 2012 and concluded that there were no uncertain tax positions requiring recognition in our financial statements. | |
Net income or loss per unit | ' |
Net Income or loss per unit | |
FASB Accounting Standards require use of the “two-class” method of computing earnings per unit for all periods presented. The “two-class” method is an earnings allocation formula that determines earnings per unit for each class of Common Unit and participating security as if all earnings for the period had been distributed. Unvested restricted unit awards that earn non-forfeitable dividend rights qualify as participating securities and, accordingly, are included in the basic computation. Our unvested restricted phantom units (“RPUs”) and convertible phantom units (“CPUs”) participate in dividends on an equal basis with Common Units; therefore, there is no difference in undistributed earnings allocated to each participating security. Accordingly, our calculation is prepared on a combined basis and is presented as net income (loss) per Common Unit. See Note 15 for our earnings per Common Unit calculation. | |
Environmental expenditures | ' |
Environmental expenditures | |
We review, on an annual basis, our estimates of the cleanup costs of various sites. When it is probable that obligations have been incurred and where a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued. At December 31, 2013, we had a $2.2 million undiscounted environmental liability accrued that included cost estimates related to the maintenance of ground water monitoring wells associated with certain former well sites in Michigan that are no longer producing. At December 31, 2012, we had a $1.9 million undiscounted environmental liability accrued. | |
Accounting Standards | ' |
Accounting Standards | |
There were no new accounting standards issued but not yet effective that are expected to have a material impact on our financial position, results of operations or cash flows. |
Acquisitions_Tables
Acquisitions (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Business Acquisition [Line Items] | ' | ||||||||||||
Business Acquisition, Pro Forma Information | ' | ||||||||||||
Pro Forma Year Ended December 31, | |||||||||||||
Thousands of dollars, except per unit amounts | 2013 | 2012 | 2011 | ||||||||||
Revenues | $ | 828,483 | $ | 781,342 | $ | 615,310 | |||||||
Net income (loss) attributable to the partnership | 27,518 | 85,594 | 146,992 | ||||||||||
Net income (loss) per common unit: | |||||||||||||
Basic | $ | 0.23 | $ | 0.73 | $ | 1.71 | |||||||
Diluted | $ | 0.23 | $ | 0.71 | $ | 1.71 | |||||||
Oklahoma Panhandle - Whiting only [Domain] | ' | ||||||||||||
Business Acquisition [Line Items] | ' | ||||||||||||
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | ' | ||||||||||||
Thousands of dollars | |||||||||||||
Oil and gas properties - proved | $ | 700,963 | |||||||||||
Oil and gas properties - unproved | 43,492 | ||||||||||||
Pipeline and processing facilities | 74,537 | ||||||||||||
Derivative assets - current | 15 | ||||||||||||
Intangibles | 14,739 | ||||||||||||
Derivative assets - long-term | 16,183 | ||||||||||||
Other long-term assets | 10,936 | ||||||||||||
Derivative liabilities - current | (6,347 | ) | |||||||||||
Accrued liabilities | (1,115 | ) | |||||||||||
Asset retirement obligation | (8,102 | ) | |||||||||||
$ | 845,301 | ||||||||||||
2013 Permian Basin Acquisitions [Member] | ' | ||||||||||||
Business Acquisition [Line Items] | ' | ||||||||||||
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | ' | ||||||||||||
Thousands of dollars | |||||||||||||
Oil and gas properties - proved | $ | 258,728 | |||||||||||
Oil and gas properties - unproved | 44,451 | ||||||||||||
Asset retirement obligation | $ | (1,069 | ) | ||||||||||
$ | 302,110 | ||||||||||||
AEO [Member] | ' | ||||||||||||
Business Acquisition [Line Items] | ' | ||||||||||||
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | ' | ||||||||||||
properties, and 4.0 million was allocated to ARO as follows: | |||||||||||||
Thousands of dollars | |||||||||||||
Oil and gas properties - proved | $ | 97,814 | |||||||||||
Asset retirement obligation | (4,014 | ) | |||||||||||
Net assets acquired | $ | 93,800 | |||||||||||
AEO [Domain] | ' | ||||||||||||
Business Acquisition [Line Items] | ' | ||||||||||||
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | ' | ||||||||||||
Thousands of dollars | |||||||||||||
Oil and gas properties - proved | $ | 97,814 | |||||||||||
Asset retirement obligation | (4,014 | ) | |||||||||||
Net assets acquired | $ | 93,800 | |||||||||||
Cabot [Member] | ' | ||||||||||||
Business Acquisition [Line Items] | ' | ||||||||||||
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | ' | ||||||||||||
Thousands of dollars | |||||||||||||
Accounts receivable | $ | 767 | |||||||||||
Oil and gas properties | 294,500 | ||||||||||||
Accounts payable | (197 | ) | |||||||||||
Revenue and royalties payable | (798 | ) | |||||||||||
Asset retirement obligation | (10,845 | ) | |||||||||||
Other long-term liabilities | (2,820 | ) | |||||||||||
$ | 280,607 | ||||||||||||
Financial_Instruments_and_Fair1
Financial Instruments and Fair Value Measurements (Tables) | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
Oil and Gas Delivery Commitments and Contracts [Line Items] | ' | ||||||||||||||||||||||||
Prepaid Derivative Premiums [Table Text Block] | ' | ||||||||||||||||||||||||
Year | |||||||||||||||||||||||||
Thousands of dollars | 2014 | 2015 | 2016 | 2017 | 2018 | ||||||||||||||||||||
Oil | $ | 4,479 | $ | 4,683 | $ | 7,438 | $ | 734 | $ | — | |||||||||||||||
Natural gas | $ | 4,015 | $ | 1,989 | $ | 952 | $ | — | $ | — | |||||||||||||||
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value | ' | ||||||||||||||||||||||||
Fair value of derivative instruments not designated as hedging instruments: | |||||||||||||||||||||||||
Balance sheet location, thousands of dollars | Oil Commodity Derivatives | Natural Gas Commodity Derivatives | Commodity Derivatives Netting (a) | Total Financial Instruments | |||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||||
Assets | |||||||||||||||||||||||||
Current assets - derivative instruments | $ | 4,373 | $ | 15,419 | $ | (11,878 | ) | $ | 7,914 | ||||||||||||||||
Other long-term assets - derivative instruments | 59,412 | 23,750 | (11,843 | ) | 71,319 | ||||||||||||||||||||
Total assets | 63,785 | 39,169 | (23,721 | ) | 79,233 | ||||||||||||||||||||
Liabilities | |||||||||||||||||||||||||
Current liabilities - derivative instruments | (35,634 | ) | (1,120 | ) | 11,878 | (24,876 | ) | ||||||||||||||||||
Long-term liabilities - derivative instruments | (13,620 | ) | (783 | ) | 11,843 | (2,560 | ) | ||||||||||||||||||
Total liabilities | (49,254 | ) | (1,903 | ) | 23,721 | (27,436 | ) | ||||||||||||||||||
Net assets | $ | 14,531 | $ | 37,266 | $ | — | $ | 51,797 | |||||||||||||||||
As of December 31, 2012 | |||||||||||||||||||||||||
Assets | |||||||||||||||||||||||||
Current assets - derivative instruments | $ | 4,270 | $ | 46,724 | $ | (16,976 | ) | $ | 34,018 | ||||||||||||||||
Other long-term assets - derivative instruments | 38,919 | 33,443 | (17,152 | ) | 55,210 | ||||||||||||||||||||
Total assets | 43,189 | 80,167 | (34,128 | ) | 89,228 | ||||||||||||||||||||
Liabilities | |||||||||||||||||||||||||
Current liabilities - derivative instruments | (21,665 | ) | (936 | ) | 16,976 | (5,625 | ) | ||||||||||||||||||
Long-term liabilities - derivative instruments | (18,769 | ) | (2,776 | ) | 17,152 | (4,393 | ) | ||||||||||||||||||
Total liabilities | (40,434 | ) | (3,712 | ) | 34,128 | (10,018 | ) | ||||||||||||||||||
Net assets (liabilities) | $ | 2,755 | $ | 76,455 | $ | — | $ | 79,210 | |||||||||||||||||
(a) Represents counterparty netting under derivative netting agreements - these contracts are reflected net on the balance sheet. | |||||||||||||||||||||||||
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance | ' | ||||||||||||||||||||||||
Gains and losses on derivative instruments not designated as hedging instruments: | |||||||||||||||||||||||||
Location of gain/loss, thousands of dollars | Oil Commodity Derivatives (a) | Natural Gas Commodity Derivatives (a) | Interest Rate Derivatives (b) | Total Financial Instruments | |||||||||||||||||||||
Year Ended December 31, 2013 | |||||||||||||||||||||||||
Net gain (loss) | $ | (34,259 | ) | $ | 5,077 | $ | — | $ | (29,182 | ) | |||||||||||||||
Year Ended December 31, 2012 | |||||||||||||||||||||||||
Net gain (loss) | $ | (15,752 | ) | $ | 21,332 | $ | (1,101 | ) | $ | 4,479 | |||||||||||||||
Year Ended December 31, 2011 | |||||||||||||||||||||||||
Net gain (loss) | $ | 32 | $ | 81,635 | $ | (2,777 | ) | $ | 78,890 | ||||||||||||||||
(a) Included in gain (loss) on commodity derivative instruments, net on the consolidated statements of operations. | |||||||||||||||||||||||||
(b) Included in loss on interest rate swaps on the consolidated statements of operations | |||||||||||||||||||||||||
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | ' | ||||||||||||||||||||||||
Financial assets and liabilities carried at fair value on a recurring basis are presented in the following tables: | |||||||||||||||||||||||||
Thousands of dollars | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||||
Assets (liabilities) | |||||||||||||||||||||||||
Oil | |||||||||||||||||||||||||
Oil swaps | $ | — | $ | 5,573 | $ | — | $ | 5,573 | |||||||||||||||||
Oil collars | — | — | 2,683 | 2,683 | |||||||||||||||||||||
Oil puts | — | — | 6,275 | 6,275 | |||||||||||||||||||||
Natural gas | |||||||||||||||||||||||||
Natural gas swaps | — | 35,419 | — | 35,419 | |||||||||||||||||||||
Natural gas calls | — | — | (650 | ) | (650 | ) | |||||||||||||||||||
Natural gas puts | — | — | 2,497 | 2,497 | |||||||||||||||||||||
Net assets | $ | — | $ | 40,992 | $ | 10,805 | $ | 51,797 | |||||||||||||||||
As of December 31, 2012 | |||||||||||||||||||||||||
Assets (liabilities) | |||||||||||||||||||||||||
Oil | |||||||||||||||||||||||||
Oil swaps | $ | — | $ | (12,413 | ) | $ | — | $ | (12,413 | ) | |||||||||||||||
Oil collars | — | — | 4,024 | 4,024 | |||||||||||||||||||||
Oil puts | — | — | 11,144 | 11,144 | |||||||||||||||||||||
Natural gas | |||||||||||||||||||||||||
Natural gas swaps | — | 74,782 | — | 74,782 | |||||||||||||||||||||
Natural gas calls | — | — | (1,489 | ) | (1,489 | ) | |||||||||||||||||||
Natural gas puts | — | — | 3,162 | 3,162 | |||||||||||||||||||||
Net assets | $ | — | $ | 62,369 | $ | 16,841 | $ | 79,210 | |||||||||||||||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation | ' | ||||||||||||||||||||||||
The following table sets forth a reconciliation of changes in fair value of our derivative instruments classified as Level 3: | |||||||||||||||||||||||||
Year End December 31, | |||||||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||||||
Thousands of dollars | Oil | Natural Gas | Oil | Natural Gas | Oil | Natural Gas | |||||||||||||||||||
Assets (a): | |||||||||||||||||||||||||
Beginning balance | $ | 15,169 | $ | 1,672 | $ | 8,509 | $ | 37,049 | $ | 35,443 | $ | 50,810 | |||||||||||||
Derivative instrument settlements (b) | (125 | ) | (892 | ) | 14,131 | 42,401 | 16,646 | 27,640 | |||||||||||||||||
Gain (loss) (b)(c) | (6,087 | ) | 1,068 | (20,760 | ) | (81,556 | ) | (43,581 | ) | (41,401 | ) | ||||||||||||||
Purchases (b)(d) | — | — | 13,288 | — | — | — | |||||||||||||||||||
Ending balance | $ | 8,957 | $ | 1,848 | $ | 15,169 | $ | 1,672 | $ | 8,509 | $ | 37,049 | |||||||||||||
(a) We had no fair value changes for our derivative instruments classified as Level 3 related to sales or issuances. | |||||||||||||||||||||||||
(b) Included in gain (loss) on commodity derivative instruments, net on the consolidated statements of operations. | |||||||||||||||||||||||||
(c) Represents gain (loss) on mark-to-market of derivative instruments. | |||||||||||||||||||||||||
(d) Relates to natural gas put options entered into in June 2012 and oil options entered into in August 2012. | |||||||||||||||||||||||||
Fair Value Inputs, Assets, Quantitative Information | ' | ||||||||||||||||||||||||
For Level 3 derivatives measured at fair value on a recurring basis as of December 31, 2013, the significant unobservable inputs used in the fair value measurements were as follows: | |||||||||||||||||||||||||
Fair Value at | Valuation | ||||||||||||||||||||||||
Thousands of dollars | December 31, 2013 | Technique | Unobservable Input | Range | |||||||||||||||||||||
Oil options | $ | 8,957 | Option Pricing Model | Oil forward commodity prices | $81.95/Bbl - $105.14/Bbl | ||||||||||||||||||||
Oil volatility | 15.51% - 17.59% | ||||||||||||||||||||||||
Own credit risk | 5% | ||||||||||||||||||||||||
Natural gas options | 1,848 | Option Pricing Model | Gas forward commodity prices | $4.01/MMBtu - $4.41/MMBtu | |||||||||||||||||||||
Gas volatility | 18.87% - 35.13% | ||||||||||||||||||||||||
Own credit risk | 5% | ||||||||||||||||||||||||
Total | $ | 10,805 | |||||||||||||||||||||||
For Level 3 derivatives measured at fair value on a recurring basis as of December 31, 2012, the significant unobservable inputs used in the fair value measurements were as follows: | |||||||||||||||||||||||||
Fair Value at | Valuation | ||||||||||||||||||||||||
Thousands of dollars | December 31, 2012 | Technique | Unobservable Input | Range | |||||||||||||||||||||
Oil options | $ | 15,169 | Option pricing model | Oil forward commodity prices | $86.78/Bbl - $110.46/Bbl | ||||||||||||||||||||
Oil volatility | 20.56% - 27.53% | ||||||||||||||||||||||||
Own credit risk | 5% | ||||||||||||||||||||||||
Natural gas options | 1,672 | Option pricing model | Gas forward commodity prices | $3.35/MMBtu - $4.87/MMBtu | |||||||||||||||||||||
Gas volatility | 20.55% - 35.88% | ||||||||||||||||||||||||
Own credit risk | 5% | ||||||||||||||||||||||||
Total | $ | 16,841 | |||||||||||||||||||||||
Crude Oil [Member] | ' | ||||||||||||||||||||||||
Oil and Gas Delivery Commitments and Contracts [Line Items] | ' | ||||||||||||||||||||||||
Schedule of Price Risk Derivatives | ' | ||||||||||||||||||||||||
We had the following oil contracts in place at December 31, 2013: | |||||||||||||||||||||||||
Year | |||||||||||||||||||||||||
2014 | 2015 | 2016 | 2017 | 2018 | |||||||||||||||||||||
Oil Positions: | |||||||||||||||||||||||||
Fixed Price Swaps - NYMEX WTI | |||||||||||||||||||||||||
Volume (Bbl/d) | 13,814 | 12,689 | 9,211 | 7,971 | 493 | ||||||||||||||||||||
Average Price ($/Bbl) | $ | 92.3 | $ | 93.01 | $ | 86.73 | $ | 84.23 | $ | 82.2 | |||||||||||||||
Fixed Price Swaps - ICE Brent | |||||||||||||||||||||||||
Volume (Bbl/d) | 4,800 | 3,300 | 4,300 | 298 | — | ||||||||||||||||||||
Average Price ($/Bbl) | $ | 98.88 | $ | 97.73 | $ | 95.17 | $ | 97.5 | $ | — | |||||||||||||||
Collars - NYMEX WTI | |||||||||||||||||||||||||
Volume (Bbl/d) | 1,000 | 1,000 | — | — | — | ||||||||||||||||||||
Average Floor Price ($/Bbl) | $ | 90 | $ | 90 | $ | — | $ | — | $ | — | |||||||||||||||
Average Ceiling Price ($/Bbl) | $ | 112 | $ | 113.5 | $ | — | $ | — | $ | — | |||||||||||||||
Collars - ICE Brent | |||||||||||||||||||||||||
Volume (Bbl/d) | — | 500 | 500 | — | — | ||||||||||||||||||||
Average Floor Price ($/Bbl) | $ | — | $ | 90 | $ | 90 | $ | — | $ | — | |||||||||||||||
Average Ceiling Price ($/Bbl) | $ | — | $ | 109.5 | $ | 101.25 | $ | — | $ | — | |||||||||||||||
Puts - NYMEX WTI | |||||||||||||||||||||||||
Volume (Bbl/d) | 500 | 500 | 1,000 | — | — | ||||||||||||||||||||
Average Price ($/Bbl) | $ | 90 | $ | 90 | $ | 90 | $ | — | $ | — | |||||||||||||||
Total: | |||||||||||||||||||||||||
Volume (Bbl/d) | 20,114 | 17,989 | 15,011 | 8,269 | 493 | ||||||||||||||||||||
Average Price ($/Bbl) | $ | 93.7 | $ | 93.54 | $ | 89.48 | $ | 84.71 | $ | 82.2 | |||||||||||||||
Natural Gas Commodity Derivatives [Member] | ' | ||||||||||||||||||||||||
Oil and Gas Delivery Commitments and Contracts [Line Items] | ' | ||||||||||||||||||||||||
Schedule of Price Risk Derivatives | ' | ||||||||||||||||||||||||
We had the following natural gas contracts in place at December 31, 2013: | |||||||||||||||||||||||||
Year | |||||||||||||||||||||||||
2014 | 2015 | 2016 | 2017 | 2018 | |||||||||||||||||||||
Gas Positions: | |||||||||||||||||||||||||
Fixed Price Swaps - MichCon City-Gate | |||||||||||||||||||||||||
Volume (MMBtu/d) | 7,500 | 7,500 | 17,000 | 10,000 | — | ||||||||||||||||||||
Average Price ($/MMBtu) | $ | 6 | $ | 6 | $ | 4.46 | $ | 4.48 | $ | — | |||||||||||||||
Fixed Price Swaps - Henry Hub | |||||||||||||||||||||||||
Volume (MMBtu/d) | 41,600 | 47,700 | 24,700 | 8,571 | 1,870 | ||||||||||||||||||||
Average Price ($/MMBtu) | $ | 4.75 | $ | 4.77 | $ | 4.23 | $ | 4.39 | $ | 4.15 | |||||||||||||||
Puts - Henry Hub | |||||||||||||||||||||||||
Volume (MMBtu/d) | 6,000 | 1,500 | — | — | — | ||||||||||||||||||||
Average Price ($/MMBtu) | $ | 5 | $ | 5 | $ | — | $ | — | $ | — | |||||||||||||||
Total: | |||||||||||||||||||||||||
Volume (MMBtu/d) | 55,100 | 56,700 | 41,700 | 18,571 | 1,870 | ||||||||||||||||||||
Average Price ($/MMBtu) | $ | 4.95 | $ | 4.94 | $ | 4.32 | $ | 4.44 | $ | 4.15 | |||||||||||||||
Calls - Henry Hub | |||||||||||||||||||||||||
Volume (MMBtu/d) | — | 15,000 | — | — | — | — | |||||||||||||||||||
Average Price ($/MMBtu) | — | $ | 9 | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
Deferred Premium ($/MMBtu) | $ | 0.12 | $ | — | $ | — | $ | — | $ | — | |||||||||||||||
Other_Assets_Tables
Other Assets (Tables) | 12 Months Ended | ||||||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||||||
Intangible Asset Amortization [Abstract] | ' | ||||||||||||||||||||||||||||
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block] | ' | ||||||||||||||||||||||||||||
Year Ended December 31, | |||||||||||||||||||||||||||||
Thousands of dollars | 2014 | 2015 | 2016 | 2017 | 2018 | Thereafter | Total | ||||||||||||||||||||||
Intangible assets amortization | $ | 5,873 | $ | 879 | $ | 793 | $ | 710 | $ | 638 | $ | 2,276 | $ | 11,169 | |||||||||||||||
LongTerm_Debt_Tables
Long-Term Debt (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Long-term Debt, Unclassified [Abstract] | ' | ||||||||||||
Schedule of Interest Expense | ' | ||||||||||||
Year Ended December 31, | |||||||||||||
Thousands of dollars | 2013 | 2012 | 2011 | ||||||||||
Credit facility (including commitment fees) | $ | 15,698 | $ | 7,114 | $ | 8,266 | |||||||
Senior notes | 65,068 | 49,279 | 26,233 | ||||||||||
Amortization of discount and deferred issuance costs | 6,429 | 4,867 | 4,743 | ||||||||||
Capitalized interest | (128 | ) | (54 | ) | (77 | ) | |||||||
Total | $ | 87,067 | $ | 61,206 | $ | 39,165 | |||||||
Cash paid for interest | $ | 74,078 | $ | 55,151 | $ | 37,756 | |||||||
Income_Taxes_Tables
Income Taxes (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Income Tax Disclosure [Abstract] | ' | ||||||||||||
Schedule of Components of Income Tax Expense (Benefit) | ' | ||||||||||||
The consolidated income tax expense (benefit) attributable to our tax-paying entities consisted of the following: | |||||||||||||
Year Ended December 31, | |||||||||||||
Thousands of dollars | 2013 | 2012 | 2011 | ||||||||||
Federal income tax expense (benefit) | |||||||||||||
Current | $ | 472 | $ | 223 | $ | 378 | |||||||
Deferred (a) | 262 | (316 | ) | 714 | |||||||||
State income tax expense (b) | 171 | 177 | 96 | ||||||||||
Total | $ | 905 | $ | 84 | $ | 1,188 | |||||||
(a) Related to Phoenix, our wholly-owned subsidiary. | |||||||||||||
(b) Primarily in California, Texas and Michigan. | |||||||||||||
Schedule of Effective Income Tax Rate Reconciliation | ' | ||||||||||||
The following is a reconciliation of federal income taxes at the statutory rates to federal income tax expense (benefit) for Phoenix: | |||||||||||||
Year Ended December 31, | |||||||||||||
Thousands of dollars | 2013 | 2012 | 2011 | ||||||||||
Income (loss) subject to federal income tax | $ | 750 | $ | (705 | ) | $ | 3,329 | ||||||
Federal income tax rate | 34 | % | 34 | % | 34 | % | |||||||
Income tax at statutory rate | 255 | (240 | ) | 1,132 | |||||||||
Statutory depletion from prior year | — | (248 | ) | — | |||||||||
Other | 13 | — | — | ||||||||||
Income tax expense (benefit) | $ | 268 | $ | (488 | ) | $ | 1,132 | ||||||
Schedule of Deferred Tax Assets and Liabilities | ' | ||||||||||||
Significant components of our net deferred tax liabilities are presented in the following table: | |||||||||||||
December 31, | |||||||||||||
Thousands of dollars | 2013 | 2012 | |||||||||||
Deferred tax assets: | |||||||||||||
Asset retirement obligation | $ | 526 | $ | 470 | |||||||||
Unrealized hedge loss | 51 | 82 | |||||||||||
Deferred realized hedge loss | — | 149 | |||||||||||
Other | 627 | 571 | |||||||||||
Deferred tax liabilities: | |||||||||||||
Depreciation, depletion and intangible drilling costs | (3,953 | ) | (3,759 | ) | |||||||||
Net deferred tax liability | $ | (2,749 | ) | $ | (2,487 | ) |
Asset_Retirement_Obligation_Ta
Asset Retirement Obligation (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
Asset Retirement Obligation [Abstract] | ' | ||||||||
Schedule of Change in Asset Retirement Obligation | ' | ||||||||
Year Ended December 31, | |||||||||
Thousands of dollars | 2013 | 2012 | |||||||
Carrying amount, beginning of period | $ | 98,480 | $ | 82,397 | |||||
Acquisitions | 9,287 | 6,279 | |||||||
Liabilities incurred | 5,313 | 2,468 | |||||||
Liabilities settled | (893 | ) | (86 | ) | |||||
Revisions | 4,299 | 1,553 | |||||||
Accretion expense | 7,283 | 5,869 | |||||||
Carrying amount, end of period | $ | 123,769 | $ | 98,480 | |||||
Commitments_and_Contingencies_
Commitments and Contingencies (Tables) | 12 Months Ended | ||||||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||||||
Long-term Purchase Commitment [Line Items] | ' | ||||||||||||||||||||||||||||
Long-term Purchase Commitment [Table Text Block] | ' | ||||||||||||||||||||||||||||
Year Ended December 31, | |||||||||||||||||||||||||||||
Thousands of dollars | 2014 | 2015 | 2016 | 2017 | 2018 | Thereafter | Total | ||||||||||||||||||||||
Purchase contracts | $ | 15,790 | $ | 28,942 | $ | 14,638 | $ | 15,663 | $ | 21,487 | $ | 45,353 | $ | 141,873 | |||||||||||||||
Schedule of Future Minimum Rental Payments for Operating Leases | ' | ||||||||||||||||||||||||||||
Our future minimum rental payments for operating leases at December 31, 2013 are presented below: | |||||||||||||||||||||||||||||
Payments Due by Year | |||||||||||||||||||||||||||||
Thousands of dollars | 2014 | 2015 | 2016 | 2017 | 2018 | Thereafter | Total | ||||||||||||||||||||||
Operating leases | $ | 5,910 | $ | 5,530 | $ | 4,498 | $ | 4,068 | $ | 633 | $ | — | $ | 20,639 | |||||||||||||||
Partners_Equity_Tables
Partners' Equity (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Partners' Capital [Abstract] | ' | ||||||||||||
Schedule of Earnings Per Share, Basic and Diluted | ' | ||||||||||||
The following is a reconciliation of net income (loss) and weighted average units for calculating basic net income (loss) per common unit and diluted net income (loss) per common unit. | |||||||||||||
Year Ended December 31, | |||||||||||||
Thousands, except per unit amounts | 2013 | 2012 | 2011 | ||||||||||
Net income (loss) attributable to limited partners | $ | (43,671 | ) | $ | (40,801 | ) | $ | 110,497 | |||||
Distributions on participating units not expected to vest | 21 | 82 | 29 | ||||||||||
Net income (loss) attributable to common unitholders and participating securities | $ | (43,650 | ) | $ | (40,719 | ) | $ | 110,526 | |||||
Weighted average number of units used to calculate basic and diluted net income (loss) per unit: | |||||||||||||
Common Units | 101,604 | 72,745 | 58,522 | ||||||||||
Participating securities (a) | — | — | 2,948 | ||||||||||
Denominator for basic earnings per common unit | 101,604 | 72,745 | 61,470 | ||||||||||
Dilutive units (b) | — | — | 134 | ||||||||||
Denominator for diluted earnings per common unit | 101,604 | 72,745 | 61,604 | ||||||||||
Net income (loss) per common unit | |||||||||||||
Basic | $ | (0.43 | ) | $ | (0.56 | ) | $ | 1.8 | |||||
Diluted | $ | (0.43 | ) | $ | (0.56 | ) | $ | 1.79 | |||||
(a) The year ended December 31, 2013 and 2012 excludes 1,649 and 2,452 of potentially issuable weighted average RPUs and CPUs from participating securities, respectively, as we were in a loss position. | |||||||||||||
(b) The year ended December 31, 2012 and 2012 excludes 364 and 55 weighted average anti-dilutive units from the calculation of the denominator for diluted earnings per common unit, respectively, as we were in a loss position. |
Unit_and_Other_ValuationBased_1
Unit and Other Valuation-Based Compensation Plans (Tables) | 12 Months Ended | |||||||||||||||||||||
Dec. 31, 2013 | ||||||||||||||||||||||
Restricted Phantom Units (RPUs) [Member] | ' | |||||||||||||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | |||||||||||||||||||||
Schedule of Share-based Compensation, Restricted Stock Units Award Activity | ' | |||||||||||||||||||||
The following table summarizes information about RPUs: | ||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||
Number | Weighted | Number | Weighted | Number | Weighted | |||||||||||||||||
of | Average | of | Average | of | Average | |||||||||||||||||
Thousands, except per unit amounts | RPUs | Fair Value | RPUs | Fair Value | RPUs | Fair Value | ||||||||||||||||
Outstanding, beginning of period | 817 | $ | 20.92 | 983 | $ | 18.35 | 1,747 | $ | 13.4 | |||||||||||||
Granted | 919 | 20.77 | 887 | 19.61 | 758 | 21.6 | ||||||||||||||||
Exercised (a) | (833 | ) | 20.62 | (1,005 | ) | 17.33 | (1,505 | ) | 14.26 | |||||||||||||
Canceled | (7 | ) | 21.6 | (48 | ) | 19.06 | (17 | ) | 16.68 | |||||||||||||
Outstanding, end of period | 896 | $ | 21.05 | 817 | $ | 20.92 | 983 | $ | 18.35 | |||||||||||||
Exercisable, end of period | — | $ | — | — | $ | — | — | $ | — | |||||||||||||
(a) Includes 308, 394 and 521 units canceled at the time of distribution for income tax liability payments the Partnership made on behalf of the restricted unit grantees for years ended December 31, 2013, 2012 and 2011, respectively. | ||||||||||||||||||||||
Director Restricted Phantom Units [Member] | ' | |||||||||||||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | |||||||||||||||||||||
Schedule of Share-based Compensation, Restricted Stock Units Award Activity | ' | |||||||||||||||||||||
The following table summarizes information about the Director Restricted Phantom Units: | ||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||
Number | Weighted | Number | Weighted | Number | Weighted | |||||||||||||||||
of | Average | of | Average | of | Average | |||||||||||||||||
Thousands, except per unit amounts | Units | Fair Value | Units | Fair Value | Units | Fair Value | ||||||||||||||||
Outstanding, beginning of period | 48 | $ | 20.43 | 132 | $ | 13.45 | 131 | $ | 13.05 | |||||||||||||
Granted | 38 | 20.98 | 29 | $ | 19.63 | 41 | 21.68 | |||||||||||||||
Exercised | (19 | ) | 20.63 | (113 | ) | 12.11 | (40 | ) | 20.55 | |||||||||||||
Outstanding, end of period | 67 | $ | 20.69 | 48 | $ | 20.43 | 132 | $ | 13.45 | |||||||||||||
Exercisable, end of period | — | $ | — | — | $ | — | — | $ | — | |||||||||||||
Supplemental_Information_Quart1
Supplemental Information: Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended | |||||||||||||||||||||||||||||||||
Dec. 31, 2013 | Dec. 31, 2012 | |||||||||||||||||||||||||||||||||
Quarterly Financial Data [Abstract] | ' | ' | ||||||||||||||||||||||||||||||||
Schedule of Quarterly Financial Information | ' | ' | ||||||||||||||||||||||||||||||||
Year ended December 31, 2013 | Year ended December 31, 2012 | |||||||||||||||||||||||||||||||||
First | Second | Third | Fourth | First | Second | Third | Fourth | |||||||||||||||||||||||||||
Thousands of dollars except per unit amounts | Quarter | Quarter | Quarter | Quarter | Thousands of dollars except per unit amounts | Quarter | Quarter | Quarter | Quarter | |||||||||||||||||||||||||
Oil, NGL and natural gas sales | $ | 120,362 | $ | 149,286 | $ | 197,413 | $ | 193,604 | Oil, NGL and natural gas sales | $ | 94,007 | $ | 94,981 | $ | 111,700 | $ | 113,179 | |||||||||||||||||
Gain (loss) on derivative instruments, net | (24,176 | ) | 66,993 | (54,765 | ) | (17,234 | ) | Gain (loss) on derivative instruments, net | (36,005 | ) | 107,288 | (69,418 | ) | 3,715 | ||||||||||||||||||||
Other revenue, net | 758 | 702 | 737 | 978 | Other revenue, net | 1,145 | 907 | 796 | 700 | |||||||||||||||||||||||||
Total revenue | 96,944 | 216,981 | 143,385 | 177,348 | Total revenue | 59,147 | 203,176 | 43,078 | 117,594 | |||||||||||||||||||||||||
Operating income (loss) | (17,853 | ) | 95,419 | (1,435 | ) | (31,855 | ) | Operating income (loss) | (36,194 | ) | 107,810 | (58,029 | ) | 8,113 | ||||||||||||||||||||
Net income (loss) (a) | $ | (36,300 | ) | $ | 76,432 | $ | (25,011 | ) | $ | (58,792 | ) | Net income (loss) (a) | $ | (49,925 | ) | $ | 92,523 | $ | (73,003 | ) | $ | (10,334 | ) | |||||||||||
Basic net income (loss) per limited partner unit (b) | $ | (0.38 | ) | $ | 0.75 | $ | (0.25 | ) | $ | (0.52 | ) | Basic net income (loss) per limited partner unit (b) | $ | (0.76 | ) | $ | 1.29 | $ | (1.00 | ) | $ | (0.13 | ) | |||||||||||
Diluted net income (loss) per limited partner unit (b) | $ | (0.38 | ) | $ | 0.75 | $ | (0.25 | ) | $ | (0.52 | ) | Diluted net income (loss) per limited partner unit (b) | $ | (0.76 | ) | $ | 1.29 | $ | (1.00 | ) | $ | (0.13 | ) | |||||||||||
Organization_Details
Organization (Details) | 12 Months Ended | |||
Dec. 31, 2013 | Dec. 31, 2012 | Apr. 02, 2012 | Mar. 31, 2012 | |
Common units | 119,170,000 | 84,668,000 | ' | ' |
Partners' capital account, units | 33,925,000 | ' | ' | ' |
Ownership percentage, public unitholders | 99.42% | ' | ' | ' |
Equity investment, ownership percentage | ' | ' | 62.00% | 35.00% |
BreitBurn Corporation [Member] | ' | ' | ' | ' |
Common Units, non-public holder | 700,000 | ' | ' | ' |
Limited partnership, ownership interest | 0.58% | ' | ' | ' |
General Partner [Member] | ' | ' | ' | ' |
Equity investment, ownership percentage | 100.00% | ' | ' | ' |
Summary_of_Significant_Account2
Summary of Significant Accounting Policies (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Years | |||
Equity basis, ownership percentage | 20.00% | ' | ' |
Cost basis, ownership percentage | 20.00% | ' | ' |
Consolidated, ownership percentage | 50.00% | ' | ' |
Consolidated, controlling or variable interest, ownership percentage | 50.00% | ' | ' |
Allowance for Doubtful Accounts Receivable, Current | $600,000 | $600,000 | ' |
Interest costs, capitalized during period | -128,000 | -54,000 | -77,000 |
Percentage Rate Of Escalation, Impairment Of Assets | 2.50% | ' | ' |
Discount Rate, Future Net Revenues for Estimated Proved Reserves | 10.00% | ' | ' |
Period of Time, Finalization of Purchase Price Allocations from Acquisition Date, Maximum | 1 | ' | ' |
Accrued environmental loss contingencies | $2,200,000 | $1,900,000 | ' |
Maximum [Member] | ' | ' | ' |
Property, plant and equipment, useful life, average (in years) | '10 years | ' | ' |
Support Equipment and Facilities [Member] | ' | ' | ' |
Property, plant and equipment, useful life, average (in years) | '20 years | ' | ' |
Minimum [Member] | ' | ' | ' |
Property, plant and equipment, useful life, average (in years) | '3 years | ' | ' |
Crude Oil [Member] | ' | ' | ' |
Period that receivables are collected within (in days) | '30 days | ' | ' |
Natural Gas [Member] | ' | ' | ' |
Period that receivables are collected within (in days) | '60 days | ' | ' |
Acquisitions_Narrative_Details
Acquisitions - Narrative (Details) (USD $) | 12 Months Ended | 1 Months Ended | 3 Months Ended | 12 Months Ended | 3 Months Ended | 12 Months Ended | 1 Months Ended | 3 Months Ended | 12 Months Ended | 3 Months Ended | 12 Months Ended | |||||||||||
Share data in Millions, unless otherwise specified | Dec. 31, 2013 | Jul. 31, 2013 | Sep. 30, 2011 | Dec. 31, 2011 | Sep. 01, 2011 | Dec. 31, 2013 | Dec. 31, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Nov. 30, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2011 | Dec. 31, 2011 |
Oklahoma Panhandle - Others [Domain] | Cabot [Member] | Cabot [Member] | Cabot [Member] | 2013 Permian Basin Acquisitions-CrownRock [Domain] | 2013 Permian Basin Acquisitions-Others [Domain] | Element [Domain] | CrownRock [Domain] | CrownRock [Domain] | Lynden [Member] | Piedra [Member] | Permian Basin [Domain] | Permian Basin [Domain] | NiMin [Member] | NiMin [Member] | AEO [Domain] | AEO [Domain] | AEO [Domain] | AEO [Domain] | Greasewood Acquisition [Domain] | Greasewood Acquisition [Domain] | ||
Business Acquisition [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
CO2 Purchase Contract | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Business Acquisition, Transaction Costs | ' | ' | ' | ' | $280,607,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $93,800,000 | ' | ' | ' | ' | ' |
Discount Rate, Future Net Revenues for Estimated Proved Reserves | 10.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Purchase price | ' | 30,000,000 | 281,000,000 | ' | ' | 282,000,000 | 20,000,000 | 148,000,000 | 164,000,000 | 70,000,000 | 25,000,000 | 10,000,000 | ' | ' | ' | ' | ' | 38,000,000 | ' | ' | 57,000,000 | ' |
Common units issued during acquisition | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3.01 | ' | ' | ' | ' | ' |
Business Combination, Acquisition Related Costs | ' | ' | ' | 600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 400,000 | ' | ' | 400,000 | ' | ' | 100,000 |
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual | ' | ' | ' | 9,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | 88,300,000 | 19,100,000 | 15,200,000 | 6,600,000 | ' | ' | 36,800,000 | 2,600,000 | ' | 7,400,000 |
Business combination operating lease expense | ' | ' | ' | $3,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | $19,000,000 | $3,800,000 | $6,100,000 | $3,200,000 | ' | ' | $7,200,000 | $600,000 | ' | $1,900,000 |
Acquisitions_Purchase_Price_Al
Acquisitions - Purchase Price Allocation (Details) (USD $) | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 3 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Jan. 31, 2013 | Nov. 30, 2012 | Dec. 31, 2013 | Sep. 30, 2013 | Jul. 15, 2013 | Jul. 02, 2012 | Dec. 31, 2013 | Dec. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Jul. 02, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Nov. 30, 2012 | Jun. 30, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Jul. 02, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2011 | Sep. 01, 2011 | Dec. 31, 2012 | Dec. 31, 2012 | Jul. 15, 2013 | Jul. 15, 2013 | Jul. 15, 2013 | Jul. 15, 2013 | Jul. 15, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | |
Oklahoma Panhandle - Whiting only [Domain] | Oklahoma Panhandle - Whiting only [Domain] | Oklahoma Panhandle - Whiting only [Domain] | CrownRock [Domain] | Permian Basin III (Dec. 30, 2013) [Member] | Permian Basin III (Dec. 30, 2013) [Member] | Permian Basin [Domain] | Permian Basin [Domain] | Permian Basin [Domain] | AEO [Domain] | AEO [Domain] | AEO [Domain] | NiMin [Member] | NiMin [Member] | NiMin [Member] | Element [Domain] | Oklahoma Panhandle [Member] | Permian Basin Acquisition July 2012 [Member] | Permian Basin Acquisition December 2012 [Member] | Greasewood Acquisition [Domain] | Cabot [Member] | Cabot [Member] | Natural Gas [Member] | Crude Oil [Member] | Crude Oil [Member] | Swap [Member] | Swap [Member] | Oil and Gas Properties [Member] | Pipelines [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | ||||||
Oklahoma Panhandle - Whiting only [Domain] | NYMEX WTI [Member] | NYMEX WTI [Member] | Oklahoma Panhandle - Others [Domain] | Oklahoma Panhandle - Others [Domain] | Term of Calendar 2014 [Member] | Term of Calendar 2015 [Member] | Term of Calendar 2018 [Member] | Term of Calendar 2017 [Member] | Term of Calendar 2016 [Domain] | Mich Con City-Gate [Member] | Mich Con City-Gate [Member] | Mich Con City-Gate [Member] | Mich Con City-Gate [Member] | Mich Con City-Gate [Member] | Henry Hub [Member] | Henry Hub [Member] | Henry Hub [Member] | Henry Hub [Member] | Henry Hub [Member] | Henry Hub [Member] | Henry Hub [Member] | Henry Hub [Member] | Henry Hub [Member] | Henry Hub [Member] | Henry Hub [Member] | Henry Hub [Member] | Henry Hub [Member] | Henry Hub [Member] | Henry Hub [Member] | ||||||||||||||||||||||||||||||
Term of Calendar 2013-2016 [Member] | Term of Calendar 2013 [Member] | Swap [Member] | Swap [Member] | Swap [Member] | Swap [Member] | Swap [Member] | Swap [Member] | Swap [Member] | Swap [Member] | Swap [Member] | Swap [Member] | Put Option [Member] | Put Option [Member] | Put Option [Member] | Put Option [Member] | Put Option [Member] | Call Option [Member] | Call Option [Member] | Call Option [Member] | Call Option [Member] | Call Option [Member] | ||||||||||||||||||||||||||||||||||||||
Crude Oil [Member] | Crude Oil [Member] | Term of Calendar 2014 [Member] | Term of Calendar 2015 [Member] | Term of Calendar 2018 [Member] | Term of Calendar 2017 [Member] | Term of Calendar 2016 [Domain] | Term of Calendar 2014 [Member] | Term of Calendar 2015 [Member] | Term of Calendar 2018 [Member] | Term of Calendar 2017 [Member] | Term of Calendar 2016 [Domain] | Term of Calendar 2014 [Member] | Term of Calendar 2015 [Member] | Term of Calendar 2018 [Member] | Term of Calendar 2017 [Member] | Term of Calendar 2016 [Domain] | Term of Calendar 2014 [Member] | Term of Calendar 2015 [Member] | Term of Calendar 2018 [Member] | Term of Calendar 2017 [Member] | Term of Calendar 2016 [Domain] | ||||||||||||||||||||||||||||||||||||||
Oklahoma Panhandle - Whiting only [Domain] | Oklahoma Panhandle - Whiting only [Domain] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Accounts and other receivables, net (note 2) | $96,862,000 | $67,862,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $767,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Premiums paid for derivatives | ' | 30,043,000 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,000,000 | 23,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Derivative, Nonmonetary Notional Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,400,000 | ' | ' | ' | 55,100 | 56,700 | 1,870 | 18,571 | 41,700 | 7,500 | 7,500 | 0 | 10,000 | 17,000 | 41,600 | 47,700 | 1,870 | 8,571 | 24,700 | 6,000 | 1,500 | 0 | 0 | 0 | 15,000 | 0 | 0 | 0 | 0 |
Derivative, Average Price Risk Option Strike Price | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5 | 5 | 0 | 0 | 0 | ' | ' | ' | ' | ' |
Proved Oil and Gas Property, Successful Effort Method | ' | ' | ' | ' | ' | ' | ' | 700,963,000 | ' | ' | 258,728,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net | ' | ' | ' | ' | ' | ' | 835,400,000 | 845,301,000 | ' | ' | 302,110,000 | ' | ' | ' | ' | ' | 97,814,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual | ' | ' | ' | ' | ' | ' | ' | ' | ' | 200,000 | ' | 88,300,000 | 19,100,000 | ' | 36,800,000 | 2,600,000 | ' | ' | 15,200,000 | 6,600,000 | ' | 104,900,000 | ' | ' | 7,400,000 | 9,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Business combination operating lease expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 19,000,000 | 3,800,000 | ' | 7,200,000 | 600,000 | ' | ' | 6,100,000 | 3,200,000 | ' | 29,900,000 | ' | ' | 1,900,000 | 3,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Payments to Acquire Businesses, Net of Cash Acquired | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 95,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Business Acquisition, Transaction Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 93,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 280,607,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned | ' | ' | ' | ' | 56,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 56,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Unproved Oil and Gas Property, Successful Effort Method | ' | ' | ' | ' | ' | ' | ' | 43,492,000 | 8,200,000 | ' | 44,451,000 | ' | ' | 52,500,000 | ' | ' | ' | 36,200,000 | ' | ' | 44,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Asset Retirement Obligation | -123,769,000 | -98,480,000 | -82,397,000 | -98,480,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -1,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | -10,845,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Other Liabilities, Noncurrent | -4,820,000 | -4,662,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -2,820,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Property, Plant and Equipment, Net | 3,915,376,000 | 2,711,893,000 | ' | ' | ' | ' | ' | 74,537,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 17,800,000 | 12,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Derivative instruments (note 4) | 7,914,000 | 34,018,000 | ' | ' | ' | ' | ' | 15,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Finite-Lived Intangible Assets, Net | ' | ' | ' | ' | ' | 11,100,000 | ' | 14,739,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Derivative instruments (note 4) | 71,319,000 | 55,210,000 | ' | ' | ' | ' | ' | 16,183,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Other long-term assets (note 9) | 74,205,000 | 27,722,000 | ' | ' | ' | ' | 1,000,000 | 10,936,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Derivative instruments (note 4) | 24,876,000 | 5,625,000 | ' | ' | ' | ' | ' | 6,347,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Asset Retirement Obligations, Noncurrent | -123,769,000 | -98,480,000 | ' | ' | ' | ' | ' | -8,102,000 | ' | ' | -1,069,000 | ' | ' | ' | ' | ' | -4,014,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Accrued Liabilities, Current | -26,922,000 | -20,997,000 | ' | ' | ' | ' | ' | -1,115,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Derivative, Swap Type, Average Fixed Price | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 95.44 | ' | ' | ' | ' | ' | ' | ' | 6 | 6 | 0 | 4.48 | 4.46 | 4.75 | 4.77 | 4.15 | 4.39 | 4.23 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Derivative, Fair Value, Net | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Accounts Payable, Current | -26,233,000 | -22,262,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -798,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Payments to Acquire Oil and Gas Property | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 294,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Accounts Payable, Current | -69,809,000 | -42,497,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -197,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Business Combination, Acquisition Related Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | $100,000 | ' | ' | ' | ' | $400,000 | ' | ' | ' | ' | $400,000 | ' | $3,200,000 | $1,000,000 | $500,000 | $100,000 | $600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Derivative, Average Forward Price | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4.95 | 4.94 | 4.15 | 4.44 | 4.32 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9 | 0 | 0 | 0 | 0 |
Derivative, Pemium, Per Unit | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.12 | 0 | 0 | 0 | 0 |
Acquisitions_Pro_Forma_Details
Acquisitions - Pro Forma (Details) (USD $) | 12 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Acquisitions 2013 and 2012 - For pro forma [Domain] | Acquisitions 2012 and 2011 - For pro forma [Domain] | Acquisitions 2011 and 2010 - For pro forma [Domain] | |
Business Acquisition [Line Items] | ' | ' | ' |
Business Acquisition, Pro Forma Revenue | $828,483 | $781,342 | $615,310 |
Business Acquisition, Pro Forma Net Income (Loss) | $27,518 | $85,594 | $146,992 |
Business Acquisition, Pro Forma Earnings Per Share, Basic | $0.23 | $0.73 | $1.71 |
Business Acquisition, Pro Forma Earnings Per Share, Diluted | $0.23 | $0.71 | $1.71 |
Financial_Instruments_and_Fair2
Financial Instruments and Fair Value Measurements - Narrative (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2011 |
Well Fargo Bank National Association [Member] | Credit Suisse [Member] | The Royal Bank of Scotland plc [Member] | NYMEX WTI [Member] | |||
Derivative Financial Instruments, Assets [Member] | Derivative Financial Instruments, Assets [Member] | Derivative Financial Instruments, Assets [Member] | Crude Oil [Member] | |||
Derivative [Line Items] | ' | ' | ' | ' | ' | ' |
Derivative Instruments Cost of Termination | ' | ' | ' | ' | ' | $36,800,000 |
Financial institutions, percentage of derivative balances | ' | ' | 30.00% | 26.00% | 13.00% | ' |
Line of credit facility, amount outstanding | $733,000,000 | $345,000,000 | ' | ' | ' | ' |
Financial_Instruments_and_Fair3
Financial Instruments and Fair Value Measurements - Oil and Natural Gas Contracts (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Derivative [Line Items] | ' | ' | ' |
Premiums paid for derivatives | ' | $30,043,000 | $0 |
Oil (NYMEX WTI) [Member] | Term of Calendar 2016 [Domain] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Swap Type, Average Fixed Price | 89.48 | ' | ' |
Derivative, Nonmonetary Notional Amount | 15,011 | ' | ' |
Oil (NYMEX WTI) [Member] | Term of Calendar 2018 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Swap Type, Average Fixed Price | 82.2 | ' | ' |
Derivative, Nonmonetary Notional Amount | 493 | ' | ' |
Oil (NYMEX WTI) [Member] | Term of Calendar 2014 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Swap Type, Average Fixed Price | 93.7 | ' | ' |
Derivative, Nonmonetary Notional Amount | 20,114 | ' | ' |
Oil (NYMEX WTI) [Member] | Term of Calendar 2015 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Swap Type, Average Fixed Price | 93.54 | ' | ' |
Derivative, Nonmonetary Notional Amount | 17,989 | ' | ' |
Oil (NYMEX WTI) [Member] | Term of Calendar 2017 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Swap Type, Average Fixed Price | 84.71 | ' | ' |
Derivative, Nonmonetary Notional Amount | 8,269 | ' | ' |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Swap [Member] | Term of Calendar 2016 [Domain] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Swap Type, Average Fixed Price | 86.73 | ' | ' |
Derivative, Nonmonetary Notional Amount | 9,211 | ' | ' |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Swap [Member] | Term of Calendar 2018 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Swap Type, Average Fixed Price | 82.2 | ' | ' |
Derivative, Nonmonetary Notional Amount | 493 | ' | ' |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Swap [Member] | Term of Calendar 2014 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Swap Type, Average Fixed Price | 92.3 | ' | ' |
Derivative, Nonmonetary Notional Amount | 13,814 | ' | ' |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Swap [Member] | Term of Calendar 2015 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Swap Type, Average Fixed Price | 93.01 | ' | ' |
Derivative, Nonmonetary Notional Amount | 12,689 | ' | ' |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Swap [Member] | Term of Calendar 2017 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Swap Type, Average Fixed Price | 84.23 | ' | ' |
Derivative, Nonmonetary Notional Amount | 7,971 | ' | ' |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Collars [Member] | Term of Calendar 2016 [Domain] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Average floor price | 0 | ' | ' |
Derivative, Average ceiling price | 0 | ' | ' |
Derivative, Nonmonetary Notional Amount | 0 | ' | ' |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Collars [Member] | Term of Calendar 2018 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Average floor price | 0 | ' | ' |
Derivative, Average ceiling price | 0 | ' | ' |
Derivative, Nonmonetary Notional Amount | 0 | ' | ' |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Collars [Member] | Term of Calendar 2014 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Average floor price | 90 | ' | ' |
Derivative, Average ceiling price | 112 | ' | ' |
Derivative, Nonmonetary Notional Amount | 1,000 | ' | ' |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Collars [Member] | Term of Calendar 2015 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Average floor price | 90 | ' | ' |
Derivative, Average ceiling price | 113.5 | ' | ' |
Derivative, Nonmonetary Notional Amount | 1,000 | ' | ' |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Collars [Member] | Term of Calendar 2017 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Average floor price | 0 | ' | ' |
Derivative, Average ceiling price | 0 | ' | ' |
Derivative, Nonmonetary Notional Amount | 0 | ' | ' |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Put Option [Member] | Term of Calendar 2016 [Domain] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Nonmonetary Notional Amount | 1,000 | ' | ' |
Derivative, Average Price Risk Option Strike Price | 90 | ' | ' |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Put Option [Member] | Term of Calendar 2018 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Nonmonetary Notional Amount | 0 | ' | ' |
Derivative, Average Price Risk Option Strike Price | 0 | ' | ' |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Put Option [Member] | Term of Calendar 2014 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Nonmonetary Notional Amount | 500 | ' | ' |
Derivative, Average Price Risk Option Strike Price | 90 | ' | ' |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Put Option [Member] | Term of Calendar 2015 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Nonmonetary Notional Amount | 500 | ' | ' |
Derivative, Average Price Risk Option Strike Price | 90 | ' | ' |
NYMEX WTI [Member] | Oil (NYMEX WTI) [Member] | Put Option [Member] | Term of Calendar 2017 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Nonmonetary Notional Amount | 0 | ' | ' |
Derivative, Average Price Risk Option Strike Price | 0 | ' | ' |
IPE Brent [Member] | Oil (NYMEX WTI) [Member] | Swap [Member] | Term of Calendar 2016 [Domain] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Swap Type, Average Fixed Price | 95.17 | ' | ' |
Derivative, Nonmonetary Notional Amount | 4,300 | ' | ' |
IPE Brent [Member] | Oil (NYMEX WTI) [Member] | Swap [Member] | Term of Calendar 2018 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Swap Type, Average Fixed Price | 0 | ' | ' |
Derivative, Nonmonetary Notional Amount | 0 | ' | ' |
IPE Brent [Member] | Oil (NYMEX WTI) [Member] | Swap [Member] | Term of Calendar 2014 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Swap Type, Average Fixed Price | 98.88 | ' | ' |
Derivative, Nonmonetary Notional Amount | 4,800 | ' | ' |
IPE Brent [Member] | Oil (NYMEX WTI) [Member] | Swap [Member] | Term of Calendar 2015 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Swap Type, Average Fixed Price | 97.73 | ' | ' |
Derivative, Nonmonetary Notional Amount | 3,300 | ' | ' |
IPE Brent [Member] | Oil (NYMEX WTI) [Member] | Swap [Member] | Term of Calendar 2017 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Swap Type, Average Fixed Price | 97.5 | ' | ' |
Derivative, Nonmonetary Notional Amount | 298 | ' | ' |
IPE Brent [Member] | Oil (NYMEX WTI) [Member] | Collars [Member] | Term of Calendar 2016 [Domain] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Average floor price | 90 | ' | ' |
Derivative, Average ceiling price | 101.25 | ' | ' |
Derivative, Nonmonetary Notional Amount | 500 | ' | ' |
IPE Brent [Member] | Oil (NYMEX WTI) [Member] | Collars [Member] | Term of Calendar 2018 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Average floor price | 0 | ' | ' |
Derivative, Average ceiling price | 0 | ' | ' |
Derivative, Nonmonetary Notional Amount | 0 | ' | ' |
IPE Brent [Member] | Oil (NYMEX WTI) [Member] | Collars [Member] | Term of Calendar 2014 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Average floor price | 0 | ' | ' |
Derivative, Average ceiling price | 0 | ' | ' |
Derivative, Nonmonetary Notional Amount | 0 | ' | ' |
IPE Brent [Member] | Oil (NYMEX WTI) [Member] | Collars [Member] | Term of Calendar 2015 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Average floor price | 90 | ' | ' |
Derivative, Average ceiling price | 109.5 | ' | ' |
Derivative, Nonmonetary Notional Amount | 500 | ' | ' |
IPE Brent [Member] | Oil (NYMEX WTI) [Member] | Collars [Member] | Term of Calendar 2017 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative, Average floor price | 0 | ' | ' |
Derivative, Average ceiling price | 0 | ' | ' |
Derivative, Nonmonetary Notional Amount | 0 | ' | ' |
Natural Gas [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Premiums paid for derivatives | ' | 7,000,000 | ' |
Natural Gas [Member] | Term of Calendar 2016 [Domain] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Prepaid Derivative Premium | 952,000 | ' | ' |
Natural Gas [Member] | Term of Calendar 2018 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Prepaid Derivative Premium | 0 | ' | ' |
Natural Gas [Member] | Term of Calendar 2014 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Prepaid Derivative Premium | 4,015,000 | ' | ' |
Natural Gas [Member] | Term of Calendar 2015 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Prepaid Derivative Premium | 1,989,000 | ' | ' |
Natural Gas [Member] | Term of Calendar 2017 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Prepaid Derivative Premium | 0 | ' | ' |
Crude Oil [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Premiums paid for derivatives | ' | 23,000,000 | ' |
Crude Oil [Member] | Term of Calendar 2016 [Domain] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Prepaid Derivative Premium | 7,438,000 | ' | ' |
Crude Oil [Member] | Term of Calendar 2018 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Prepaid Derivative Premium | 0 | ' | ' |
Crude Oil [Member] | Term of Calendar 2014 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Prepaid Derivative Premium | 4,479,000 | ' | ' |
Crude Oil [Member] | Term of Calendar 2015 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Prepaid Derivative Premium | 4,683,000 | ' | ' |
Crude Oil [Member] | Term of Calendar 2017 [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Prepaid Derivative Premium | $734,000 | ' | ' |
Financial_Instruments_and_Fair4
Financial Instruments and Fair Value Measurements - Interest Rate Activities (Details) (USD $) | Dec. 31, 2011 | Dec. 31, 2011 | Dec. 31, 2012 |
In Millions, unless otherwise specified | January 20, 2012 to January 20, 2014 [Member] | January 1, 2012 to December 20, 2012 [Member] | NYMEX WTI [Member] |
Interest Rate Contract [Member] | |||
Derivative [Line Items] | ' | ' | ' |
Derivative, Notional Amount | $100 | ' | ' |
Derivative, Fixed Interest Rate | 2.48% | 1.16% | ' |
Derivative Instruments Cost of Termination | ' | ' | 2.5 |
Derivative Asset, Notional Amount | ' | $100 | ' |
Financial_Instruments_and_Fair5
Financial Instruments and Fair Value Measurements - Not Designated As Hedging Instruments (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2011 | Dec. 31, 2010 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | ||
Crude Oil [Member] | Crude Oil [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | |||||
Not Designated as Hedging Instrument [Member] | Not Designated as Hedging Instrument [Member] | Not Designated as Hedging Instrument [Member] | Not Designated as Hedging Instrument [Member] | Not Designated as Hedging Instrument [Member] | Not Designated as Hedging Instrument [Member] | Not Designated as Hedging Instrument [Member] | Not Designated as Hedging Instrument [Member] | ||||||||||
Netting and Collateral [Member] | Netting and Collateral [Member] | ||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Current assets - derivative instruments | $7,914,000 | $34,018,000 | $4,373,000 | $4,270,000 | ' | ' | ' | $15,419,000 | $46,724,000 | ' | ' | $7,914,000 | $34,018,000 | ($11,878,000) | [1] | ($16,976,000) | [1] |
Other long-term assets - derivative instruments | 71,319,000 | 55,210,000 | 59,412,000 | 38,919,000 | ' | ' | ' | 23,750,000 | 33,443,000 | ' | ' | 71,319,000 | 55,210,000 | -11,843,000 | [1] | -17,152,000 | [1] |
Total assets | ' | ' | 63,785,000 | 43,189,000 | ' | ' | ' | 39,169,000 | 80,167,000 | ' | ' | 79,233,000 | 89,228,000 | -23,721,000 | [1] | -34,128,000 | [1] |
Current liabilities - derivative instruments | -24,876,000 | -5,625,000 | -35,634,000 | -21,665,000 | ' | ' | ' | -1,120,000 | -936,000 | ' | ' | -24,876,000 | -5,625,000 | 11,878,000 | [1] | 16,976,000 | [1] |
Long-term liabilities - derivative instruments | -2,560,000 | -4,393,000 | -13,620,000 | -18,769,000 | ' | ' | ' | -783,000 | -2,776,000 | ' | ' | -2,560,000 | -4,393,000 | 11,843,000 | [1] | 17,152,000 | [1] |
Total liabilities | ' | ' | 49,254,000 | 40,434,000 | ' | ' | ' | 1,903,000 | 3,712,000 | ' | ' | 27,436,000 | 10,018,000 | -23,721,000 | [1] | -34,128,000 | [1] |
Net assets (liabilities) | ' | ' | $14,531,000 | $2,755,000 | $1,848,000 | $37,049,000 | $50,810,000 | $37,266,000 | $76,455,000 | $51,797,000 | $79,210,000 | $51,797,000 | $79,210,000 | $0 | [1] | $0 | [1] |
[1] | Represents counterparty netting under derivative netting agreements - these contracts are reflected net on the balance sheet. |
Financial_Instruments_and_Fair6
Financial Instruments and Fair Value Measurements - Gains and Losses on Derivative Instruments Not Designated As Hedging Instruments (Details) (USD $) | 3 Months Ended | 12 Months Ended | 3 Months Ended | 12 Months Ended | |||||||||||||||||||||||||||||
Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||||||||
Interest Rate Derivatives [Member] | Interest Rate Derivatives [Member] | Interest Rate Derivatives [Member] | Crude Oil [Member] | Crude Oil [Member] | Crude Oil [Member] | Crude Oil [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | |||||||||||||||||||||
Not Designated as Hedging Instrument [Member] | Not Designated as Hedging Instrument [Member] | Not Designated as Hedging Instrument [Member] | Not Designated as Hedging Instrument [Member] | Not Designated as Hedging Instrument [Member] | Not Designated as Hedging Instrument [Member] | NYMEX WTI [Member] | Not Designated as Hedging Instrument [Member] | Not Designated as Hedging Instrument [Member] | Not Designated as Hedging Instrument [Member] | Not Designated as Hedging Instrument [Member] | Not Designated as Hedging Instrument [Member] | Not Designated as Hedging Instrument [Member] | |||||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||
Derivative Instruments Cost of Termination | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $36,800,000 | ' | ' | ' | ' | ' | ' | |||||||||
Derivative, Gain (Loss) on Derivative, Net | ' | ' | ' | ' | ' | ' | ' | ' | -29,182,000 | 4,479,000 | 78,890,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||
Gain (loss) on commodity derivative instruments, net (note 4) | ($17,234,000) | ($54,765,000) | $66,993,000 | ($24,176,000) | $3,715,000 | ($69,418,000) | $107,288,000 | ($36,005,000) | ($29,182,000) | $5,580,000 | $81,667,000 | $0 | [1] | ($1,101,000) | [1] | ($2,777,000) | [1] | ($34,259,000) | [2] | ($15,752,000) | [2] | $32,000 | [2] | ' | $5,077,000 | [2] | $21,332,000 | [2] | $81,635,000 | [2] | ($29,182,000) | $4,479,000 | $78,890,000 |
[1] | Included in loss on interest rate swaps on the consolidated statements of operations included in gain (loss) on commodity derivative instruments, net on the consolidated statements of operations. | ||||||||||||||||||||||||||||||||
[2] | Included in gain (loss) on commodity derivative instruments, net on the consolidated statements of operations.( |
Financial_Instruments_and_Fair7
Financial Instruments and Fair Value Measurements - Fair Value Measurements (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2011 | Dec. 31, 2010 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2010 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | ||||
Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Crude Oil [Member] | Crude Oil [Member] | Crude Oil [Member] | Crude Oil [Member] | Collars [Member] | Collars [Member] | Collars [Member] | Collars [Member] | Collars [Member] | Collars [Member] | Collars [Member] | Collars [Member] | Call Option [Member] | Call Option [Member] | Call Option [Member] | Call Option [Member] | Call Option [Member] | Call Option [Member] | Call Option [Member] | Call Option [Member] | Put Option [Member] | Put Option [Member] | Put Option [Member] | Put Option [Member] | Put Option [Member] | Put Option [Member] | Put Option [Member] | Put Option [Member] | Put Option [Member] | Put Option [Member] | Put Option [Member] | Put Option [Member] | Put Option [Member] | Put Option [Member] | Put Option [Member] | Put Option [Member] | Swap [Member] | Swap [Member] | Swap [Member] | Swap [Member] | Swap [Member] | Swap [Member] | Swap [Member] | Swap [Member] | Swap [Member] | Swap [Member] | Swap [Member] | Swap [Member] | Swap [Member] | Swap [Member] | Swap [Member] | Swap [Member] | Option Pricing Model Valuation Technique [Member] | Option Pricing Model Valuation Technique [Member] | Option Pricing Model Valuation Technique [Member] | Option Pricing Model Valuation Technique [Member] | Option Pricing Model Valuation Technique [Member] | Option Pricing Model Valuation Technique [Member] | Minimum [Member] | Minimum [Member] | Maximum [Member] | Maximum [Member] | |||||
Level 3 [Member] | Level 3 [Member] | Level 1 [Member] | Level 1 [Member] | Level 2 [Member] | Level 2 [Member] | Level 3 [Member] | Level 3 [Member] | Level 3 [Member] | Level 3 [Member] | Level 3 [Member] | Level 3 [Member] | Crude Oil [Member] | Crude Oil [Member] | Crude Oil [Member] | Crude Oil [Member] | Crude Oil [Member] | Crude Oil [Member] | Crude Oil [Member] | Crude Oil [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Crude Oil [Member] | Crude Oil [Member] | Crude Oil [Member] | Crude Oil [Member] | Crude Oil [Member] | Crude Oil [Member] | Crude Oil [Member] | Crude Oil [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Crude Oil [Member] | Crude Oil [Member] | Crude Oil [Member] | Crude Oil [Member] | Crude Oil [Member] | Crude Oil [Member] | Crude Oil [Member] | Crude Oil [Member] | Derivative Financial Instruments, Assets [Member] | Derivative Financial Instruments, Assets [Member] | Derivative Financial Instruments, Assets [Member] | Derivative Financial Instruments, Assets [Member] | Derivative Financial Instruments, Assets [Member] | Derivative Financial Instruments, Assets [Member] | Option Pricing Model Valuation Technique [Member] | Option Pricing Model Valuation Technique [Member] | Option Pricing Model Valuation Technique [Member] | Option Pricing Model Valuation Technique [Member] | ||||||||||
Fair Value, Measurements, Recurring [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Level 1 [Member] | Level 2 [Member] | Level 2 [Member] | Level 3 [Member] | Level 3 [Member] | Level 1 [Member] | Level 1 [Member] | Level 2 [Member] | Level 2 [Member] | Level 3 [Member] | Level 3 [Member] | Level 1 [Member] | Level 1 [Member] | Level 2 [Member] | Level 2 [Member] | Level 3 [Member] | Level 3 [Member] | Level 1 [Member] | Level 1 [Member] | Level 2 [Member] | Level 2 [Member] | Level 3 [Member] | Level 3 [Member] | Level 1 [Member] | Level 1 [Member] | Level 2 [Member] | Level 2 [Member] | Level 3 [Member] | Level 3 [Member] | Level 1 [Member] | Level 1 [Member] | Level 2 [Member] | Level 2 [Member] | Level 3 [Member] | Level 3 [Member] | Level 3 [Member] | Level 3 [Member] | Natural Gas [Member] | Crude Oil [Member] | Crude Oil [Member] | Collars [Member] | Derivative Financial Instruments, Assets [Member] | Derivative Financial Instruments, Assets [Member] | Derivative Financial Instruments, Assets [Member] | Derivative Financial Instruments, Assets [Member] | ||||||||||||||||||||||||||||
Level 3 [Member] | Level 3 [Member] | Level 3 [Member] | Natural Gas [Member] | Natural Gas [Member] | Crude Oil [Member] | Natural Gas [Member] | Crude Oil [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Level 3 [Member] | Level 3 [Member] | Level 3 [Member] | Level 3 [Member] | Level 3 [Member] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Fair Value Inputs, Offered Quotes | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $3.35 | $86.78 | $4.87 | $110.46 | ||||
Assets, Fair Value Disclosure | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $10,805,000 | $16,841,000 | $1,672,000 | $8,957,000 | $15,169,000 | $1,848,000 | ' | ' | ' | ' | ||||
Derivative Assets (Liabilities), at Fair Value, Net | $1,848,000 | $37,049,000 | $50,810,000 | $1,672,000 | [1] | $37,049,000 | $51,797,000 | $79,210,000 | $0 | $0 | $40,992,000 | $62,369,000 | $10,805,000 | $16,841,000 | $8,957,000 | $15,169,000 | [1] | $8,509,000 | [1] | $35,443,000 | [1] | $2,683,000 | $4,024,000 | $0 | $0 | $0 | $0 | $2,683,000 | $4,024,000 | ($650,000) | ($1,489,000) | $0 | $0 | $0 | $0 | ($650,000) | ($1,489,000) | $2,497,000 | $3,162,000 | $0 | $0 | $0 | $0 | $2,497,000 | $3,162,000 | $6,275,000 | $11,144,000 | $0 | $0 | $0 | $0 | $6,275,000 | $11,144,000 | $35,419,000 | $74,782,000 | $0 | $0 | $35,419,000 | $74,782,000 | $0 | $0 | $5,573,000 | ($12,413,000) | $0 | $0 | $5,573,000 | ($12,413,000) | $0 | $0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Fair Value Inputs, Entity Credit Risk | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5.00% | 5.00% | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Fair Value Assumptions, Expected Volatility Rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20.60% | 20.60% | 35.90% | 27.50% | ||||
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Financial_Instruments_and_Fair8
Financial Instruments and Fair Value Measurements - Reconciation of Changes in Fair Value (Details) (USD $) | 12 Months Ended | 12 Months Ended | |||||||||||||||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2011 | Dec. 31, 2010 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||||
Crude Oil [Member] | Crude Oil [Member] | Crude Oil [Member] | Crude Oil [Member] | Crude Oil [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | Natural Gas [Member] | |||||||||
Fair Value, Measurements, Recurring [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Measurements, Recurring [Member] | ||||||||||||||
Level 3 [Member] | Level 3 [Member] | Level 3 [Member] | Level 3 [Member] | Level 3 [Member] | Level 3 [Member] | ||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Beginning balance | ' | ' | ' | ' | ' | $15,169,000 | [1] | $8,509,000 | [1] | $35,443,000 | [1] | ' | $37,049,000 | $50,810,000 | $1,672,000 | [1] | $37,049,000 | ' | |
Realized gain (loss) | 29,182,000 | -4,479,000 | -78,890,000 | ' | ' | -125,000 | [1] | 14,131,000 | [1] | 16,646,000 | [1] | ' | ' | ' | -892,000 | [1] | -42,401,000 | -27,640,000 | |
Derivative instruments, purchases | ' | ' | ' | 13,288,000 | 0 | 0 | ' | ' | 0 | ' | ' | ' | ' | 0 | |||||
Unrealized loss | ' | ' | ' | ' | ' | -6,087,000 | [2] | -20,760,000 | [2] | -43,581,000 | [2] | ' | ' | ' | 1,068,000 | [2] | 81,556,000 | 41,401,000 | |
Ending balance | ' | ' | ' | ' | ' | $8,957,000 | $15,169,000 | [1] | $8,509,000 | [1] | $1,848,000 | $37,049,000 | $50,810,000 | ' | $1,672,000 | [1] | $37,049,000 | ||
[1] | {F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjcwODhlYmM4Y2RjOTQ2MTU5ODIwZjI4OTI1NGY0MDYwfFRleHRTZWxlY3Rpb246NkVFMzFFOUYxNjJBQjhDMjhFNzlCOUUwNjU4QUMyM0MM} | ||||||||||||||||||
[2] | {F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjcwODhlYmM4Y2RjOTQ2MTU5ODIwZjI4OTI1NGY0MDYwfFRleHRTZWxlY3Rpb246OUMzREI2OTgwNDU3QUMwQUJFMzRCOUUwNjU4QTQ2NzIM} |
Financial_Instruments_and_Fair9
Financial Instruments and Fair Value Measurements Prepaid Premiums (Details) (Commodity Contract [Member], USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
Commodity Contract [Member] | ' | ' |
Prepaid Derivative Premiums [Line Items] | ' | ' |
Prepaid Derivative Premium | $4,900,000 | $900,000 |
Related_Party_Transactions_Det
Related Party Transactions (Details) (USD $) | 3 Months Ended | 12 Months Ended | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||||||||||||||
Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Apr. 02, 2012 | Mar. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | 7-May-12 | Dec. 31, 2013 | Dec. 31, 2012 | |
PCEC [Member] | PCEC [Member] | PCEC [Member] | PCEC [Member] | PCEC [Member] | Other Affiliates [Member] | Other Affiliates [Member] | |||||||||||||
Related Party Transaction [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Monthly fees associated with the Administrative Service Agreement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $571,000 | $700,000 | ' | ' | ' | ' | ' |
Related Party Transaction, Other Revenues from Transactions with Related Party | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 250,000 | ' | ' | ' | ' | ' | ' | ' |
Property ownership interest | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5.00% | 62.00% | ' | 62.00% | 95.00% | ' | ' |
Payroll and administrative expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10,600,000 | 8,600,000 | ' | ' | ' |
Current receivables | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,200,000 | 2,500,000 | 1,200,000 | ' | 100,000 | 200,000 |
Indirect expenses | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8,400,000 | 8,000,000 | ' | ' | ' |
Oil and gas sales | $193,604,000 | $197,413,000 | $149,286,000 | $120,362,000 | $113,179,000 | $111,700,000 | $94,981,000 | $94,007,000 | $660,665,000 | $413,867,000 | $394,393,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Inventory_Details
Inventory (Details) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 |
MMBbls | MMBbls | |
Crude oil inventory | 3,890 | 3,086 |
Crude Oil [Member] | ' | ' |
Inventory, sold (in MBbls) | 784 | 849 |
Inventory, produced (in MBbls) | 779 | 830 |
Equity_Investments_Details
Equity Investments (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Schedule of Equity Method Investments [Line Items] | ' | ' | ' |
Equity investments | $6,641,000 | $7,004,000 | ' |
Income from equity investments | 500,000 | 700,000 | 700,000 |
Dividends from equity investments | -500,000 | -1,200,000 | 900,000 |
Frederic Hof [Member] | ' | ' | ' |
Schedule of Equity Method Investments [Line Items] | ' | ' | ' |
Equity investments | 400,000 | ' | ' |
Wilderness Energy Services, LP [Member] | ' | ' | ' |
Schedule of Equity Method Investments [Line Items] | ' | ' | ' |
Equity investments | 6,000,000 | ' | ' |
Limited Partner [Member] | Wilderness Energy Services, LP [Member] | ' | ' | ' |
Schedule of Equity Method Investments [Line Items] | ' | ' | ' |
Ownership interest | 24.50% | ' | ' |
General Partner [Member] | Wilderness Energy Services, LP [Member] | ' | ' | ' |
Schedule of Equity Method Investments [Line Items] | ' | ' | ' |
Ownership interest | 25.50% | ' | ' |
Equity Method Investments [Member] | ' | ' | ' |
Schedule of Equity Method Investments [Line Items] | ' | ' | ' |
Equity investments | $600,000 | ' | ' |
Impairments_and_Price_Related_1
Impairments and Price Related Depletion and Depreciation Adjustments (Details) (USD $) | 12 Months Ended | |||||||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Jul. 15, 2013 | |
MICHIGAN | MICHIGAN | Impairments [Member] | Proved [Member] | Unproved [Member] | Oklahoma Panhandle [Member] | Oklahoma Panhandle [Member] | ||||
WYOMING | MICHIGAN | |||||||||
Reserve Quantities [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Finite-Lived Intangible Assets, Net | ' | ' | ' | ' | ' | ' | ' | ' | $11,100,000 | $14,739,000 |
Percentage Rate Of Escalation, Impairment Of Assets | 2.50% | ' | ' | ' | ' | 2.50% | ' | ' | ' | ' |
Discount Rate, Impairment Of Assets | ' | ' | ' | ' | ' | 10.00% | ' | ' | ' | ' |
Impairment of Oil and Gas Properties | ' | ' | ' | 12,300,000 | 600,000 | ' | 25,300,000 | 28,300,000 | ' | ' |
Asset Impairment Charges | $54,373,000 | $12,313,000 | $648,000 | ' | ' | ' | ' | ' | ' | ' |
Other_Assets_Details
Other Assets (Details) (USD $) | 12 Months Ended | 12 Months Ended | |||||||||||
Dec. 31, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Sep. 30, 2013 | Jul. 15, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | |
Oklahoma Panhandle - Whiting only [Domain] | Oklahoma Panhandle - Whiting only [Domain] | Oklahoma Panhandle - Whiting only [Domain] | Term of Calendar 2014 [Member] | Thereafter [Member] | Term of Calendar 2017 [Member] | Term of Calendar 2016 [Member] | Term of Calendar 2015 [Member] | Term of Calendar 2018 [Member] | Term of Calendar Total [Member] | ||||
Finite-Lived Intangible Assets [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Finite-Lived Intangible Assets, Net | ' | ' | ' | $11,100,000 | ' | $14,739,000 | ' | ' | ' | ' | ' | ' | ' |
Finite-Lived Intangible Assets, Accumulated Amortization | ' | ' | ' | 3,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Finite-Lived Intangible Assets, Gross | 500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Other long-term assets (note 9) | 74,205,000 | ' | 27,722,000 | ' | 1,000,000 | 10,936,000 | ' | ' | ' | ' | ' | ' | ' |
Debt Issuance Cost | 35,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Deposits Assets, Noncurrent | 22,600,000 | 14,700,000 | ' | 15,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Amortization of Intangible Assets | ' | ' | ' | ' | ' | ' | $5,873,000 | $2,276,000 | $710,000 | $793,000 | $879,000 | $638,000 | $11,169,000 |
LongTerm_Debt_Senior_Notes_Det
Long-Term Debt - Senior Notes (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Oct. 06, 2010 | Oct. 06, 2010 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Nov. 19, 2013 | Sep. 27, 2012 | Jan. 10, 2012 | Oct. 06, 2010 |
Senior Notes [Member] | 8.625% Senior Notes due 2020 [Member] | 8.625% Senior Notes due 2020 [Member] | Senior Notes Two [Member] | Senior Notes Two [Member] | Senior Notes Two [Member] | Senior Notes Two [Member] | Senior Notes Two [Member] | |||||
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt instrument, face amount | ' | ' | ' | ' | $305,000,000 | ' | ' | ' | $400,000,000 | $200,000,000 | $250,000,000 | ' |
Interest rate, stated percentage | ' | ' | ' | ' | 8.63% | ' | ' | ' | 7.88% | ' | 7.88% | ' |
Deferred finance costs, net | ' | ' | ' | 8,800,000 | ' | ' | ' | ' | 7,700,000 | 4,200,000 | 5,600,000 | ' |
Notes Issued, Premium | ' | ' | ' | ' | ' | ' | ' | ' | 100.25% | ' | ' | ' |
Notes issued, discount | ' | ' | ' | ' | 98.36% | ' | ' | ' | ' | 103.50% | 99.15% | ' |
Subordinated long-term debt, noncurrent | 1,156,675,000 | 755,696,000 | ' | ' | 300,000,000 | 301,600,000 | 301,100,000 | 855,100,000 | 401,000,000 | 207,000,000 | 247,900,000 | ' |
Unamortized discount | ' | 3,400,000 | 3,900,000 | ' | ' | ' | ' | ' | 1,000,000 | 7,000,000 | 2,100,000 | 5,000,000 |
Fair value of debt instrument | ' | ' | ' | ' | ' | 327,000,000 | 330,000,000 | 890,000,000 | ' | ' | ' | ' |
Line of credit facility, amount outstanding | 733,000,000 | 345,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Unamortized Discount (Premium), Net | ' | ' | ' | ' | ' | ' | ' | $5,100,000 | ' | ' | ' | ' |
LongTerm_Debt_Credit_Facility_
Long-Term Debt - Credit Facility (Details) (USD $) | Dec. 31, 2013 | Jul. 15, 2013 | Jul. 14, 2013 | 22-May-13 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 |
Second Amended and Restated Credit Agreement [Member] | First Quarter of 2014 [Member] | Fourth Quarter of 2013 [Member] | Minimum Cash Proceeds from Issuance of Common Units [Member] | Minimum Cash Proceeds from Issuance of Common Units [Member] | London Interbank Offered Rate (LIBOR) [Member] | Prime Rate [Member] | Well Fargo Bank National Association [Member] | ||||||
Second Quarter of 2014 [Member] | Second Quarter of 2014 [Member] | ||||||||||||
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Line of credit facility, maximum borrowing capacity | $3,000,000,000 | $3,000,000,000 | $1,500,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Line of credit facility, current borrowing base | 1,500,000,000 | 1,500,000,000 | ' | 1,200,000,000 | 1,000,000,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Basis points | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2.17% | 4.25% | ' |
Line of credit facility, amount outstanding | 733,000,000 | ' | ' | ' | 345,000,000 | ' | ' | ' | ' | ' | 727,000,000 | 6,000,000 | ' |
Percentage of total value of borrowing secured by oil and gas properties | ' | ' | ' | ' | ' | 80.00% | ' | ' | ' | ' | ' | ' | ' |
Commitment from existing lenders, borrowing base | 1,400,000,000 | 1,400,000,000 | ' | 1,000,000,000 | 900,000,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Proceeds from Issuance of Common Stock | ' | ' | ' | ' | ' | ' | ' | ' | 350,000,000 | 175,000,000 | ' | ' | ' |
Maximum Total Leverage Ratio | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' |
Interest Coverage Ratio | 2.5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Maximum Senior Secured Leverage Ratio | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' | ' |
Unamortized Debt Issuance Expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $13,700,000 |
LongTerm_Debt_Interest_Expense
Long-Term Debt - Interest Expense (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Debt Instrument [Line Items] | ' | ' | ' |
Amortization of Financing Costs and Discounts | $6,429 | $4,867 | $4,743 |
Interest costs, capitalized during period | -128 | -54 | -77 |
Interest Costs Incurred | 87,067 | 61,206 | 39,165 |
Interest Paid | 74,078 | 55,151 | 37,756 |
Senior Notes [Member] | ' | ' | ' |
Debt Instrument [Line Items] | ' | ' | ' |
Interest Expense, Debt, Excluding Amortization | 65,068 | 49,279 | 26,233 |
Line of Credit [Member] | ' | ' | ' |
Debt Instrument [Line Items] | ' | ' | ' |
Interest Expense, Debt, Excluding Amortization | $15,698 | $7,114 | $8,266 |
Condensed_Consolidating_Financ1
Condensed Consolidating Financial Statements Condensed Consolidation (Details) | 12 Months Ended |
Dec. 31, 2013 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ' |
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% |
Income_Taxes_Details
Income Taxes (Details) (USD $) | 12 Months Ended | |||||
Share data in Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||
Current | $472,000 | $223,000 | $378,000 | |||
Deferred | 262,000 | [1] | -316,000 | [1] | 714,000 | [1] |
State income tax expense (benefit) | 171,000 | [2] | 177,000 | [2] | 96,000 | [2] |
Income (loss) subject to federal income tax | -42,766,000 | -40,655,000 | 111,886,000 | |||
Income tax expense (benefit) | 905,000 | 84,000 | 1,188,000 | |||
Deferred tax assets, Asset retirement obligations | 526,000 | 470,000 | ' | |||
Deferred Tax Assets, Unrealized Hedge Losses | 51,000 | 82,000 | ' | |||
Deferred tax assets, Unrealized hedge loss | 0 | 149,000 | ' | |||
Deferred tax assets, Other | 627,000 | 571,000 | ' | |||
Deferred tax liabilities, Depreciation, depletion and intangible drilling costs | -3,953,000 | -3,759,000 | ' | |||
Net deferred tax liability | 2,749,000 | 2,487,000 | ' | |||
Cash paid for federal and state income taxes | 500,000 | 800,000 | 300,000 | |||
Partners' capital account, units | 33,925 | ' | ' | |||
Phoenix [Member] | ' | ' | ' | |||
Income (loss) subject to federal income tax | 750,000 | -705,000 | 3,329,000 | |||
Federal income tax rate | 34.00% | 34.00% | 34.00% | |||
Income tax at statutory rate | 255,000 | -240,000 | 1,132,000 | |||
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Depletion | 0 | -248,000 | 0 | |||
Other | 13,000 | 0 | 0 | |||
Income tax expense (benefit) | $268,000 | ($488,000) | $1,132,000 | |||
[1] | Related to Phoenix, our wholly-owned subsidiary. | |||||
[2] | Primarily in California, Texas and Michigan. |
Asset_Retirement_Obligation_De
Asset Retirement Obligation (Details) (USD $) | 12 Months Ended | ||||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Jan. 31, 2013 | ||
Asset Retirement Obligations [Line Items] | ' | ' | ' | ||
Credit adjusted risk free rate | 7.00% | ' | ' | ||
Inflation adjustment rate | 2.00% | ' | ' | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ' | ' | ' | ||
Carrying amount, beginning of period | $98,480 | $82,397 | $98,480 | ||
Acquisitions | 9,287 | [1] | 6,279 | [1] | ' |
Liabilities incurred | 5,313 | 2,468 | ' | ||
Liabilities settled | -893 | -86 | ' | ||
Revisions | 4,299 | [1] | 1,553 | [1] | ' |
Accretion expense | 7,283 | 5,869 | ' | ||
Carrying amount, end of period | $123,769 | $98,480 | $98,480 | ||
Minimum [Member] | ' | ' | ' | ||
Asset Retirement Obligations [Line Items] | ' | ' | ' | ||
Finite-Lived Intangible Asset, Useful Life | '1 year | ' | ' | ||
Maximum [Member] | ' | ' | ' | ||
Asset Retirement Obligations [Line Items] | ' | ' | ' | ||
Finite-Lived Intangible Asset, Useful Life | '50 years | ' | ' | ||
[1] | Text selection found with no content. |
Commitments_and_Contingencies_1
Commitments and Contingencies (Details) (USD $) | 12 Months Ended | 57 Months Ended | 117 Months Ended | 126 Months Ended | 174 Months Ended | 186 Months Ended | |||||||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Sep. 30, 2023 | Sep. 30, 2023 | Dec. 31, 2023 | Jun. 30, 2028 | Dec. 31, 2028 | |
Mcf | |||||||||||||
Long-term Purchase Commitment [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long-term Purchase Commitment, Amount | $21,487,000 | $15,663,000 | $14,638,000 | $28,942,000 | $15,790,000 | ' | ' | ' | $45,353,000 | $141,873,000 | ' | ' | ' |
Long-term Purchase Commitment, Minimum Volume Required | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 142,500,000 | ' |
Long-term Purchase Commitment, Time Period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '10 | ' | '15 |
Lease and rental expense | ' | ' | ' | ' | ' | 3,900,000 | 3,700,000 | 3,400,000 | ' | ' | ' | ' | ' |
Surety bonds, current carrying value | ' | ' | ' | ' | ' | 17,500,000 | 16,200,000 | ' | ' | ' | ' | ' | ' |
Letters of credit outstanding, amount | ' | ' | ' | ' | ' | 2,800,000 | 300,000 | ' | ' | ' | ' | ' | ' |
Operating leases, 2013 | ' | ' | ' | ' | ' | 5,910,000 | ' | ' | ' | ' | ' | ' | ' |
Operating leases, 2014 | ' | ' | ' | ' | ' | 5,530,000 | ' | ' | ' | ' | ' | ' | ' |
Operating leases, 2015 | ' | ' | ' | ' | ' | 4,498,000 | ' | ' | ' | ' | ' | ' | ' |
Operating leases, 2016 | ' | ' | ' | ' | ' | 4,068,000 | ' | ' | ' | ' | ' | ' | ' |
Operating leases, 2017 | ' | ' | ' | ' | ' | 633,000 | ' | ' | ' | ' | ' | ' | ' |
Operating leases, after 2017 | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' |
Operating leases, Total | ' | ' | ' | ' | ' | $20,639,000 | ' | ' | ' | ' | ' | ' | ' |
Partners_Equity_Details
Partners' Equity (Details) (USD $) | 1 Months Ended | 12 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | |||||||||||||||||
In Millions, except Share data, unless otherwise specified | Nov. 30, 2013 | Feb. 28, 2013 | Sep. 30, 2012 | Feb. 29, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Nov. 30, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Nov. 30, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | |||||
Common Units [Member] | Common Units [Member] | Common Units [Member] | AEO [Domain] | Equivalent Units [Member] | Equivalent Units [Member] | Equivalent Units [Member] | Participating Securities [Member] | Participating Securities [Member] | ||||||||||||||
Capital Unit [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Partners' Capital, 2nd Monthly Installment Distribution | ' | ' | ' | ' | '45 days | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Participating securities | ' | ' | ' | ' | 0 | [1] | 0 | [1] | 2,948,000 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | 1,649,000 | [1] | 2,450,000 | [1] |
Partners' Capital, distribution period | ' | ' | ' | ' | '75 days | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Partners' Capital, 1st Monthly Distribution | ' | ' | ' | ' | '17 days | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Common units | ' | ' | ' | ' | 119,170,000 | 84,668,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Long-term incentive compensation plans, number of shares authorized | ' | ' | ' | ' | 9,700,000 | 9,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Number | ' | ' | ' | ' | 600,000 | 942,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Common Units issued pursuant to vest grants | ' | ' | ' | ' | ' | ' | ' | ' | 1,300,000 | 1,000,000 | 1,200,000 | ' | ' | ' | ' | ' | ' | |||||
Partners' Capital account, units, sold in public offering | 18,980,000 | 14,950,000 | 11,500,000 | 9,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Price Per Common Unit | 18.22 | 19.86 | 18.51 | 18.8 | ' | ' | ' | ' | ' | ' | ' | 18.48 | ' | ' | ' | ' | ' | |||||
Proceeds from Common Units sold to public | $333.20 | $285 | $204.10 | $166 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Common units issued during acquisition | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,010,000 | ' | ' | ' | ' | ' | |||||
Distribution Made to Limited Partner, Cash Distributions Paid | ' | ' | ' | ' | 183.6 | 127.7 | 97.6 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Distribution Made to Limited Partner, Distributions Declared, Per Unit | ' | ' | ' | ' | $1.91 | $1.83 | $1.69 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Dividends, Share-based Compensation, Cash | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3.3 | 4.7 | 5.1 | ' | ' | |||||
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned | ' | ' | ' | ' | ' | ' | ' | $56 | ' | ' | ' | $56 | ' | ' | ' | ' | ' | |||||
[1] | The year ended December 31, 2013 and 2012 excludes 1,649 and 2,452 of potentially issuable weighted average RPUs and CPUs from participating securities, respectively, as we were in a loss position. |
Partners_Equity_Earnings_Per_S
Partners' Equity - Earnings Per Share Reconciliation (Details) (USD $) | 12 Months Ended | ||||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Feb. 26, 2014 | ||||
Partners' Capital [Abstract] | ' | ' | ' | ' | |||
Net income (loss) attributable to the partnership | ($43,671,000) | ($40,801,000) | $110,497,000 | ' | |||
Distributions on participating units not expected to vest | 21,000 | 82,000 | 29,000 | ' | |||
Net income (loss) attributable to common unitholders and participating securities | -43,650,000 | -40,719,000 | 110,526,000 | ' | |||
Weighted average number of units used to calculate basic and diluted income loss per unit [Abstract] | ' | ' | ' | ' | |||
Weighted Partners' Capital Account, Units | 101,604,000 | ' | ' | ' | |||
Entity Common Stock, Shares Outstanding | ' | 72,745,000 | 58,522,000 | 119,201,681 | |||
Participating securities | 0 | [1] | 0 | [1] | 2,948,000 | [1] | ' |
Denominator for basic earnings per common unit | 101,604,000 | 72,745,000 | 61,470,000 | ' | |||
Dilutive units | 0 | [2] | 0 | [2] | 134,000 | [2] | ' |
Denominator for diluted earnings per common unit | 101,604,000 | 72,745,000 | 61,604,000 | ' | |||
Net income (loss) per common unit [Abstract] | ' | ' | ' | ' | |||
Basic | ($0.43) | ($0.56) | $1.80 | ' | |||
Diluted | ($0.43) | ($0.56) | $1.79 | ' | |||
Capital Unit [Line Items] | ' | ' | ' | ' | |||
Distribution Made to Limited Partner, Cash Distributions Paid | 183,600,000 | 127,700,000 | 97,600,000 | ' | |||
Distribution Made to Limited Partner, Distributions Declared, Per Unit | $1.91 | $1.83 | $1.69 | ' | |||
Weighted average anti-dilutive units excluded from the calculation | 364,000 | [2] | 55,000 | [2] | ' | ' | |
Equivalent Units [Member] | ' | ' | ' | ' | |||
Capital Unit [Line Items] | ' | ' | ' | ' | |||
Dividends, Share-based Compensation, Cash | $3,300,000 | $4,700,000 | $5,100,000 | ' | |||
Participating Securities [Member] | ' | ' | ' | ' | |||
Weighted average number of units used to calculate basic and diluted income loss per unit [Abstract] | ' | ' | ' | ' | |||
Participating securities | 1,649,000 | [1] | 2,450,000 | [1] | ' | ' | |
[1] | The year ended December 31, 2013 and 2012 excludes 1,649 and 2,452 of potentially issuable weighted average RPUs and CPUs from participating securities, respectively, as we were in a loss position. | ||||||
[2] | The year ended December 31, 2012 and 2012 excludes 364 and 55 weighted average anti-dilutive units from the calculation of the denominator for diluted earnings per common unit, respectively, as we were in a loss position. |
Noncontrolling_Interest_Detail
Noncontrolling Interest (Details) | Apr. 02, 2012 | Mar. 31, 2012 | Dec. 31, 2011 |
Noncontrolling Interest [Line Items] | ' | ' | ' |
Limited partner interest acquired | ' | ' | 99.00% |
Equity investment, ownership percentage | 62.00% | 35.00% | ' |
Noncontrolling Interest, Ownership Percentage by Parent | ' | 95.00% | ' |
Unit_and_Other_ValuationBased_2
Unit and Other Valuation-Based Compensation Plans - Narrative (Details) (USD $) | 1 Months Ended | 12 Months Ended | 1 Months Ended | 11 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | ||||||||||||||
Share data in Thousands, except Per Share data, unless otherwise specified | Nov. 30, 2013 | Feb. 28, 2013 | Sep. 30, 2012 | Feb. 29, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2010 | Jan. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Jan. 31, 2013 | Dec. 31, 2007 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Unit Based Compensation [Member] | Unit Based Compensation [Member] | Unit Based Compensation [Member] | 2013 Convertible Phantom Units (CPUs) [Member] [Member] | 2013 Convertible Phantom Units (CPUs) [Member] [Member] | Deferred Compensation, Share-based Payments [Member] | Deferred Compensation, Share-based Payments [Member] | Deferred Compensation, Share-based Payments [Member] | Convertible Phantom Units (CPUs) [Member] | Convertible Phantom Units (CPUs) [Member] | Convertible Phantom Units (CPUs) [Member] | Director Restricted Phantom Units [Member] | Director Restricted Phantom Units [Member] | Director Restricted Phantom Units [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Unit-based compensation expense | ' | ' | ' | ' | $19,955,000 | $22,266,000 | $22,043,000 | $20,000,000 | $22,200,000 | $22,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | $700,000 | $600,000 | $1,000,000 |
Allocated Share-based Compensation Expense | ' | ' | ' | ' | ' | ' | ' | 17,000,000 | 17,400,000 | 16,900,000 | ' | ' | 2,300,000 | 4,100,000 | 4,100,000 | ' | ' | ' | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Number | ' | ' | ' | ' | 600 | 942 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Award vesting period | ' | ' | ' | ' | '5 years | ' | ' | '3 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights | ' | ' | ' | ' | ' | ' | ' | 'were to vest on the earliest to occur of (i) January 1, 2013, (ii) the date on which the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than or equal to $3.10 per Common Unit and (iii) upon the occurrence of the death or bdisabilityb of the grantee or his or her termination without bcauseb or for bgood reasonb (as defined in the holderbs employment agreement, if applicable). | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Unrecognized compensation cost | ' | ' | ' | ' | ' | ' | ' | ' | 18,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 700,000 | ' | ' |
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition | ' | ' | ' | ' | ' | ' | ' | '2 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | '3 years | ' | ' | ' |
Fair value of vested units | ' | ' | ' | ' | ' | ' | ' | $17,200,000 | $17,400,000 | $21,500,000 | ' | ' | ' | ' | ' | ' | ' | $4,700,000 | ' | ' | ' |
Granted, Number | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 300 | 400 | ' | ' | ' | 700 | 700 | ' | ' | ' | ' |
Price Per Common Unit | 18.22 | 19.86 | 18.51 | 18.8 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30.29 | 20.98 | ' | ' | ' |
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | ' | ' | ' | ' | $1.91 | $1.83 | $1.69 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Unit_and_Other_ValuationBased_3
Unit and Other Valuation-Based Compensation Plans - Restricted Phantom Units (Details) (USD $) | 1 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | ||||||||||||||
Nov. 30, 2013 | Feb. 28, 2013 | Sep. 30, 2012 | Feb. 29, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Jan. 31, 2013 | Dec. 31, 2007 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2010 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2010 | Dec. 31, 2009 | Jan. 31, 2013 | |
Convertible Phantom Units (CPUs) [Member] | Convertible Phantom Units (CPUs) [Member] | Convertible Phantom Units (CPUs) [Member] | Unit Based Compensation [Member] | Unit Based Compensation [Member] | Unit Based Compensation [Member] | Restricted Phantom Units (RPUs) [Member] | Restricted Phantom Units (RPUs) [Member] | Restricted Phantom Units (RPUs) [Member] | Restricted Phantom Units (RPUs) [Member] | Restricted Phantom Units (RPUs) [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Granted, Number | ' | ' | ' | ' | ' | ' | ' | 700,000 | 700,000 | ' | ' | ' | ' | 919,000 | 887,000 | 758,000 | ' | ' |
Award vesting period | ' | ' | ' | ' | '5 years | ' | ' | ' | ' | ' | '3 years | ' | ' | ' | ' | ' | ' | ' |
Allocated Share-based Compensation Expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $17,000,000 | $17,400,000 | $16,900,000 | ' | ' | ' | ' | ' |
Fair value of vested units | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,700,000 | 17,200,000 | 17,400,000 | 21,500,000 | ' | ' | ' | ' | ' |
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition | ' | ' | ' | ' | ' | ' | ' | ' | ' | '3 years | '2 years | ' | ' | ' | ' | ' | ' | ' |
Outstanding, beginning of period, Number | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 817,000 | 983,000 | ' | ' | 817,000 |
Outstanding, beginning of period, Weighted Average Fair Value | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $20.92 | $18.35 | ' | ' | $20.92 |
Price Per Common Unit | 18.22 | 19.86 | 18.51 | 18.8 | ' | ' | ' | ' | 30.29 | 20.98 | ' | ' | ' | ' | ' | ' | ' | ' |
Granted, Weighted Average Fair Value | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $20.77 | $19.61 | $21.60 | ' | ' |
Exercised, Number | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -833,000 | -1,005,000 | -1,505,000 | ' | ' |
Exercised, Weighted Average Fair Value | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $20.62 | $17.33 | $14.26 | ' | ' |
Cancelled, Number | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -7,000 | -48,000 | -17,000 | ' | ' |
Cancelled, Weighted Average Fair Value | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $21.60 | $19.06 | $16.68 | ' | ' |
Outstanding, end of period, Number | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 896,000 | 817,000 | 1,747,000 | ' | 817,000 |
Outstanding, end of period, Weighted Average Fair Value | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $21.05 | $20.92 | $13.40 | ' | $20.92 |
Exercisable, end of period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | 0 | ' |
Exercisable, Weighted Average Fair Value | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $0 | $0 | ' | $0 | ' |
Unit-based compensation expense | ' | ' | ' | ' | 19,955,000 | 22,266,000 | 22,043,000 | ' | ' | ' | 20,000,000 | 22,200,000 | 22,000,000 | ' | ' | ' | ' | ' |
Unrecognized compensation cost | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $18,400,000 | ' | ' | ' | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 'were to vest on the earliest to occur of (i) January 1, 2013, (ii) the date on which the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than or equal to $3.10 per Common Unit and (iii) upon the occurrence of the death or bdisabilityb of the grantee or his or her termination without bcauseb or for bgood reasonb (as defined in the holderbs employment agreement, if applicable). | ' | ' | ' | ' | ' | ' | ' |
Unit_and_Other_ValuationBased_4
Unit and Other Valuation-Based Compensation Plans - Founders Plan (Details) (USD $) | 12 Months Ended | |||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' | |||
Unit-based compensation expense | $19,955,000 | $22,266,000 | $22,043,000 | |||
Director Restricted Phantom Units [Member] | ' | ' | ' | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' | |||
Unit-based compensation expense | 700,000 | 600,000 | 1,000,000 | |||
Outstanding, beginning of period, Number | 48,000 | 132,000 | 131,000 | |||
Outstanding, beginning of period, Weighted Average Fair Value | $20.43 | [1] | $13.45 | [1] | $13.05 | [1] |
Outstanding, end of period, Number | 67,000 | 48,000 | 132,000 | |||
Outstanding, end of period, Weighted Average Fair Value | $20.69 | [1] | $20.43 | [1] | $13.45 | [1] |
Exercisable, end of period | 0 | 0 | 0 | |||
Exercisable, Weighted Average Fair Value | $0 | [1] | $0 | [1] | $0 | [1] |
Unrecognized compensation cost | $700,000 | ' | ' | |||
[1] | Year Ended December 31, 2013B 2012B 2011 Number Weighted Number Weighted Number Weighted ofB AverageB ofB AverageB ofB AverageThousands, except per unit amounts UnitsB Fair Value UnitsB Fair Value UnitsB Fair ValueOutstanding, beginning of periodB 48B $20.43B 132B $13.45B 131B $13.05GrantedB 38B 20.98B 29B $19.63B 41B 21.68ExercisedB (19)B 20.63B (113)B 12.11B (40)B 20.55Outstanding, end of periodB 67B $20.69B 48B $20.43B 132B $13.45 Exercisable, end of periodB bB $bB bB $bB bB $b |
Unit_and_Other_ValuationBased_5
Unit and Other Valuation-Based Compensation Plans - Director Restricted Phantom Units (Details) (USD $) | 12 Months Ended | |||||
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' | |||
Unit-based compensation expense | $19,955 | $22,266 | $22,043 | |||
Director Restricted Phantom Units [Member] | ' | ' | ' | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' | |||
Share-based Compensation Arrangements by Share-based Payment Award, Options, Grants in Period, Weighted Average Exercise Price | $20.98 | [1] | $19.63 | [1] | $21.68 | [1] |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted | 38,000 | 29,000 | 41,000 | |||
Unit-based compensation expense | $700 | $600 | $1,000 | |||
Outstanding, beginning of period, Number | 48,000 | 132,000 | 131,000 | |||
Outstanding, beginning of period, Weighted Average Fair Value | $20.43 | [1] | $13.45 | [1] | $13.05 | [1] |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period | -19,000 | -113,000 | -40,000 | |||
Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price | $20.63 | [1] | $12.11 | [1] | $20.55 | [1] |
Outstanding, end of period, Number | 67,000 | 48,000 | 132,000 | |||
Outstanding, end of period, Weighted Average Fair Value | $20.69 | [1] | $20.43 | [1] | $13.45 | [1] |
Exercisable, end of period | 0 | 0 | 0 | |||
Exercisable, Weighted Average Fair Value | $0 | [1] | $0 | [1] | $0 | [1] |
[1] | Year Ended December 31, 2013B 2012B 2011 Number Weighted Number Weighted Number Weighted ofB AverageB ofB AverageB ofB AverageThousands, except per unit amounts UnitsB Fair Value UnitsB Fair Value UnitsB Fair ValueOutstanding, beginning of periodB 48B $20.43B 132B $13.45B 131B $13.05GrantedB 38B 20.98B 29B $19.63B 41B 21.68ExercisedB (19)B 20.63B (113)B 12.11B (40)B 20.55Outstanding, end of periodB 67B $20.69B 48B $20.43B 132B $13.45 Exercisable, end of periodB bB $bB bB $bB bB $b |
Retirement_Plan_Details
Retirement Plan (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Compensation and Retirement Disclosure [Abstract] | ' | ' | ' |
Award vesting period | '5 years | ' | ' |
Matching contributions expense | $2 | $1.30 | $1.10 |
Significant_Customers_Details
Significant Customers (Details) (Sales Revenue, Goods, Net [Member], Customer Concentration Risk [Member]) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Phillips 66 [Member] | ' | ' | ' |
Concentration Risk [Line Items] | ' | ' | ' |
Major customers, percentage of net sales | 15.00% | 16.00% | 0.00% |
Shell Trading [Member] | ' | ' | ' |
Concentration Risk [Line Items] | ' | ' | ' |
Major customers, percentage of net sales | 15.00% | 2.00% | 4.00% |
Marathon Oil [Member] | ' | ' | ' |
Concentration Risk [Line Items] | ' | ' | ' |
Major customers, percentage of net sales | 10.00% | 14.00% | 15.00% |
Plains Marketing and Transportation [Member] | ' | ' | ' |
Concentration Risk [Line Items] | ' | ' | ' |
Major customers, percentage of net sales | 9.00% | 17.00% | 16.00% |
ConocoPhillips [Member] [Member] | ' | ' | ' |
Concentration Risk [Line Items] | ' | ' | ' |
Major customers, percentage of net sales | 5.00% | 14.00% | 30.00% |
Subsequent_Events_Details
Subsequent Events (Details) (USD $) | 12 Months Ended | 1 Months Ended | 0 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Feb. 14, 2014 | Jan. 16, 2014 | |
Cash Distribution [Member] | Cash Distribution [Member] | ||||
Subsequent Event [Member] | Subsequent Event [Member] | ||||
Subsequent Event [Line Items] | ' | ' | ' | ' | ' |
Distribution Made to Limited Partner, Distributions Declared, Per Unit | $1.91 | $1.83 | $1.69 | $0 | $0 |
Interest Coverage Ratio | 2.5 | ' | ' | ' | ' |
Supplemental_Information_Quart2
Supplemental Information: Quarterly Financial Data (Unaudited) (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||||||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||||||
Effect of Fourth Quarter Events [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Distribution Made to Limited Partner, Distributions Declared, Per Unit | ' | ' | ' | ' | ' | ' | ' | ' | $1.91 | $1.83 | $1.69 | ||||||||
Oil, NGLs and natural gas sales | $193,604 | $197,413 | $149,286 | $120,362 | $113,179 | $111,700 | $94,981 | $94,007 | $660,665 | $413,867 | $394,393 | ||||||||
Gain (loss) on commodity derivative instruments, net | -17,234 | -54,765 | 66,993 | -24,176 | 3,715 | -69,418 | 107,288 | -36,005 | -29,182 | 5,580 | 81,667 | ||||||||
Other revenue, net | 978 | 737 | 702 | 758 | 700 | 796 | 907 | 1,145 | 3,175 | 3,548 | 4,310 | ||||||||
Total Revenue | 177,348 | 143,385 | 216,981 | 96,944 | 117,594 | 43,078 | 203,176 | 59,147 | 634,658 | 422,995 | 480,370 | ||||||||
Operating income (loss) | -31,855 | -1,435 | 95,419 | -17,853 | 8,113 | -58,029 | 107,810 | -36,194 | 44,276 | 21,700 | 153,809 | ||||||||
Net income (loss) | ($58,792) | ($25,011) | $76,432 | ($36,300) | ($10,334) | ($73,003) | $92,523 | ($49,925) | ($43,671) | ($40,739) | $110,698 | ||||||||
Basic net income (loss) per limited partner unit | ($0.52) | [1] | ($0.25) | [1] | $0.75 | [1] | ($0.38) | [1] | ($0.13) | [1] | ($1) | [1] | $1.29 | [1] | ($0.76) | [1] | ($0.43) | ($0.56) | $1.80 |
Diluted net income (loss) per limited partner unit | ($0.52) | [1] | ($0.25) | [1] | $0.75 | [1] | ($0.38) | [1] | ($0.13) | [1] | ($1) | [1] | $1.29 | [1] | ($0.76) | [1] | ($0.43) | ($0.56) | $1.79 |
[1] | b) Due to changes in the number of weighted average common units outstanding that may occur each quarter, the sum of the earnings per unit amounts for the quarters may not be additive to the full year earnings per unit amount. |