Document_and_Entity_Informatio
Document and Entity Information (USD $) | 12 Months Ended | ||
In Billions, except Share data, unless otherwise specified | Dec. 31, 2014 | Feb. 24, 2015 | Jun. 30, 2014 |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | FALSE | ||
Document Period End Date | 31-Dec-14 | ||
Document Fiscal Year Focus | 2014 | ||
Document Fiscal Period Focus | FY | ||
Entity Registrant Name | Atlas Energy, L.P. | ||
Entity Central Index Key | 1347218 | ||
Current Fiscal Year End Date | -19 | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Public Float | $2.20 | ||
Entity Common Stock, Shares Outstanding | 52,021,532 | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Well-known Seasoned Issuer | Yes | ||
Trading Symbol | ATLS |
CONSOLIDATED_BALANCE_SHEETS
CONSOLIDATED BALANCE SHEETS (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Current assets: | ||
Cash and cash equivalents | $83,210 | $23,501 |
Accounts receivable | 355,817 | 279,464 |
Current portion of derivative asset | 232,266 | 2,066 |
Subscriptions receivable | 32,398 | 47,692 |
Prepaid expenses and other | 44,196 | 27,612 |
Total current assets | 747,887 | 380,335 |
Property, plant and equipment, net | 5,669,262 | 4,910,875 |
Intangible assets, net | 596,952 | 697,234 |
Investment in joint ventures | 177,212 | 248,301 |
Goodwill | 379,402 | 400,356 |
Long-term derivative asset | 168,000 | 30,868 |
Other assets, net | 127,921 | 124,672 |
Total assets | 7,866,636 | 6,792,641 |
Current liabilities: | ||
Current portion of long-term debt | 2,624 | 2,924 |
Accounts payable | 210,746 | 149,279 |
Liabilities associated with drilling contracts | 40,611 | 49,377 |
Accrued producer liabilities | 161,208 | 152,309 |
Current portion of derivative liability | 17,630 | |
Accrued interest | 53,419 | 47,402 |
Accrued well drilling and completion costs | 92,910 | 40,899 |
Accrued liabilities | 224,251 | 87,435 |
Total current liabilities | 785,769 | 547,255 |
Long-term debt, less current portion | 3,567,946 | 2,886,120 |
Deferred income taxes, net | 30,914 | 33,290 |
Asset retirement obligations | 108,101 | 91,214 |
Other long-term liabilities | 13,161 | 11,886 |
Commitments and contingencies | ||
Partners’ Capital: | ||
Common limited partners’ interests | 154,273 | 361,511 |
Accumulated other comprehensive income | 54,008 | 10,338 |
Total common limited partners' interest and accumulated other comprehensive income | 208,281 | 371,849 |
Non-controlling interests | 3,152,464 | 2,851,027 |
Total partners’ capital | 3,360,745 | 3,222,876 |
Total liabilities and partners' capital | $7,866,636 | $6,792,641 |
CONSOLIDATED_STATEMENTS_OF_OPE
CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) | 12 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Revenues: | |||
Gas and oil production | $475,758 | $273,906 | $92,901 |
Well construction and completion | 173,564 | 167,883 | 131,496 |
Gathering and processing | 2,836,322 | 2,139,694 | 1,219,815 |
Administration and oversight | 15,564 | 12,277 | 11,810 |
Well services | 24,959 | 19,492 | 20,041 |
Gain (loss) on mark-to-market derivatives | 133,883 | -28,764 | 31,940 |
Other, net | 8,653 | -6,973 | 13,440 |
Total revenues | 3,668,703 | 2,577,515 | 1,521,443 |
Costs and expenses: | |||
Gas and oil production | 184,296 | 100,178 | 26,624 |
Well construction and completion | 150,925 | 145,985 | 114,079 |
Gathering and processing | 2,420,759 | 1,802,618 | 1,009,100 |
Well services | 10,007 | 9,515 | 9,280 |
General and administrative | 217,371 | 197,976 | 165,777 |
Depreciation, depletion and amortization | 444,622 | 308,533 | 142,611 |
Asset impairment | 580,654 | 81,880 | 9,507 |
Total costs and expenses | 4,008,634 | 2,646,685 | 1,484,648 |
Operating income (loss) | -339,931 | -69,170 | 36,795 |
Gain (loss) on asset sales and disposal | 45,522 | -2,506 | -6,980 |
Interest expense | -173,357 | -132,581 | -46,520 |
Loss on early extinguishment of debt | -26,601 | ||
Net loss before tax | -467,766 | -230,858 | -16,705 |
Income tax (benefit) expense | -2,376 | -2,260 | 176 |
Net loss | -465,390 | -228,598 | -16,881 |
Loss (income) attributable to non-controlling interests | 273,132 | 153,231 | -35,532 |
Net loss attributable to common limited partners | -192,258 | -75,367 | -52,413 |
Net loss attributable to common limited partners per unit: | |||
Basic and Diluted | ($3.71) | ($1.47) | ($1.02) |
Weighted average common limited partner units outstanding: | |||
Basic and Diluted | 51,810 | 51,387 | 51,327 |
Chevron | |||
Costs and expenses: | |||
Chevron transaction expense | $7,670 |
CONSOLIDATED_STATEMENTS_OF_COM
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Statement Of Income And Comprehensive Income [Abstract] | |||
Net loss | ($465,390) | ($228,598) | ($16,881) |
Other comprehensive income (loss): | |||
Changes in fair value of derivative instruments accounted for as cash flow hedges | 156,551 | 15,828 | 10,921 |
Less: reclassification adjustment for realized (gains) losses of cash flow hedges in net loss | 7,739 | -10,216 | -14,891 |
Total other comprehensive income (loss) | 164,290 | 5,612 | -3,970 |
Comprehensive loss | -301,100 | -222,986 | -20,851 |
Comprehensive (income) loss attributable to non-controlling interests | 152,512 | 148,258 | -51,239 |
Comprehensive loss attributable to common limited partners | ($148,588) | ($74,728) | ($72,090) |
CONSOLIDATED_STATEMENT_OF_PART
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL (USD $) | Total | Common Limited Partners' Capital | Accumulated Other Comprehensive Income | Non-Controlling Interest |
Balance at Dec. 31, 2011 | $1,744,081,000 | $554,999,000 | $29,376,000 | $1,159,706,000 |
Balance units at Dec. 31, 2011 | 51,278,362 | |||
Distribution of Atlas Resource Partners, L.P. units | -84,892,000 | 84,892,000 | ||
Distributions to non-controlling interests | -120,456,000 | -120,456,000 | ||
Net issued and unissued units under incentive plans | 39,488,000 | 17,837,000 | 21,651,000 | |
Net issued and unissued units under incentive plans (units) | 87,220 | |||
Non-controlling interests’ capital contribution | 804,768,000 | 804,768,000 | ||
Atlas Pipeline Partners L.P. purchase price allocation | 89,440,000 | 89,440,000 | ||
Distributions paid to common limited partners | -51,837,000 | -51,837,000 | ||
Distribution equivalent rights paid on unissued units under incentive plans | -4,785,000 | -2,070,000 | -2,715,000 | |
Gain on sale of subsidiary unit issuances | 74,547,000 | -74,547,000 | ||
Other comprehensive income (loss) | -3,970,000 | -19,677,000 | 15,707,000 | |
Net income (loss) | -16,881,000 | -52,413,000 | 35,532,000 | |
Balance at Dec. 31, 2012 | 2,479,848,000 | 456,171,000 | 9,699,000 | 2,013,978,000 |
Balance units at Dec. 31, 2012 | 51,365,582 | |||
Distributions to non-controlling interests | -240,982,000 | -240,982,000 | ||
Contributions from Atlas Pipeline Partners, L.P.’s non-controlling interests | 17,021,000 | 17,021,000 | ||
Net issued and unissued units under incentive plans | 54,305,000 | 22,532,000 | 31,773,000 | |
Net issued and unissued units under incentive plans (units) | 47,982 | |||
Non-controlling interests’ capital contribution | 1,252,307,000 | 1,252,307,000 | ||
Atlas Pipeline Partners L.P. purchase price allocation | -30,535,000 | -30,535,000 | ||
Distributions paid to common limited partners | -77,598,000 | -77,598,000 | ||
Distribution equivalent rights paid on unissued units under incentive plans | -8,504,000 | -3,473,000 | -5,031,000 | |
Gain on sale of subsidiary unit issuances | 39,246,000 | -39,246,000 | ||
Other comprehensive income (loss) | 5,612,000 | 639,000 | 4,973,000 | |
Net income (loss) | -228,598,000 | -75,367,000 | -153,231,000 | |
Balance at Dec. 31, 2013 | 3,222,876,000 | 361,511,000 | 10,338,000 | 2,851,027,000 |
Balance units at Dec. 31, 2013 | 51,413,564 | |||
Distributions to non-controlling interests | -345,681,000 | -345,681,000 | ||
Contributions from Atlas Pipeline Partners, L.P.’s non-controlling interests | 11,720,000 | 11,720,000 | ||
Net issued and unissued units under incentive plans | 72,925,000 | 42,739,000 | 30,186,000 | |
Net issued and unissued units under incentive plans (units) | 548,737 | |||
Non-controlling interests’ capital contribution | 829,089,000 | 829,089,000 | ||
Distributions paid to common limited partners | -99,996,000 | -99,996,000 | ||
Distribution equivalent rights paid on unissued units under incentive plans | -11,839,000 | -5,431,000 | -6,408,000 | |
Gain on sale of subsidiary unit issuances | 47,708,000 | -47,708,000 | ||
Distributions payable | -17,249,000 | -17,249,000 | ||
Other comprehensive income (loss) | 164,290,000 | 43,670,000 | 120,620,000 | |
Net income (loss) | -465,390,000 | -192,258,000 | -273,132,000 | |
Balance at Dec. 31, 2014 | $3,360,745,000 | $154,273,000 | $54,008,000 | $3,152,464,000 |
Balance units at Dec. 31, 2014 | 51,962,301 |
CONSOLIDATED_STATEMENTS_OF_CAS
CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
CASH FLOWS FROM OPERATING ACTIVITIES: | |||
Net loss | ($465,390) | ($228,598) | ($16,881) |
Adjustments to reconcile net loss to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 444,622 | 308,533 | 142,611 |
Asset impairment | 580,654 | 81,880 | 9,507 |
Amortization of deferred financing costs | 18,305 | 17,649 | 6,720 |
Non-cash compensation expense | 77,354 | 55,008 | 40,300 |
(Gain) loss on asset sales and disposal | -45,522 | 2,506 | 6,980 |
Deferred income tax (benefit) expense | -2,376 | -2,260 | 176 |
Loss on early extinguishment of debt | 26,601 | ||
Distributions paid to non-controlling interests | -352,089 | -246,013 | -123,171 |
Equity (income) loss in unconsolidated companies | 12,871 | 2,142 | -7,863 |
Distributions received from unconsolidated companies | 6,959 | 8,422 | 8,131 |
Changes in operating assets and liabilities: | |||
Accounts receivable, prepaid expenses and other | -214,203 | -58,035 | -85,308 |
Accounts payable and accrued liabilities | 93,617 | 69,773 | 89,074 |
Net cash provided by operating activities | 154,802 | 37,608 | 70,276 |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Capital expenditures | -873,383 | -718,040 | -500,759 |
Net cash paid for acquisitions | -741,522 | -1,756,744 | -1,150,150 |
Net proceeds from asset sales and disposal | 133,946 | 1,236 | |
Investment in joint ventures | -8,061 | -13,366 | |
Other | 127 | -9,693 | 404 |
Net cash used in investing activities | -1,488,893 | -2,496,607 | -1,650,505 |
CASH FLOWS FROM FINANCING ACTIVITIES: | |||
Borrowings under credit facilities | 2,664,000 | 2,474,000 | 1,846,599 |
Repayments under credit facilities | -2,156,400 | -2,317,025 | -1,335,174 |
Net proceeds from issuance of subsidiary long-term debt | 170,596 | 1,538,488 | 495,374 |
Repayments of subsidiary long-term debt | -365,822 | ||
Net proceeds from subsidiary equity offerings | 829,089 | 1,252,307 | 611,606 |
Distributions paid to unitholders | -99,996 | -77,598 | -51,837 |
Contributions from non-controlling interests | 11,720 | 17,021 | |
Premium paid on retirement of Atlas Pipeline Partners, L.P. long-term debt | -25,581 | ||
Deferred financing costs, distribution equivalent rights and other | -25,209 | -50,070 | -26,935 |
Net cash provided by financing activities | 1,393,800 | 2,445,720 | 1,539,633 |
Net change in cash and cash equivalents | 59,709 | -13,279 | -40,596 |
Cash and cash equivalents, beginning of year | 23,501 | 36,780 | 77,376 |
Cash and cash equivalents, end of year | $83,210 | $23,501 | $36,780 |
Basis_of_Presentation
Basis of Presentation | 12 Months Ended | |
Dec. 31, 2014 | ||
Organization Consolidation And Presentation Of Financial Statements [Abstract] | ||
Basis of Presentation | ATLAS ENERGY, L.P. AND SUBSIDIARIES | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS | ||
NOTE 1 — BASIS OF PRESENTATION | ||
Atlas Energy, L.P., (the “Partnership” or “Atlas Energy”) is a publicly-traded Delaware master limited partnership (NYSE: ATLS). At December 31, 2014, the Partnership’s operations primarily consisted of its ownership interests in the following: | ||
— | Atlas Resource Partners, L.P. (“ARP”), a publicly-traded Delaware master limited partnership (NYSE: ARP) and an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”), with operations in basins across the United States. ARP sponsors and manages tax-advantaged investment partnerships (“Drilling Partnerships”), in which it coinvests, to finance a portion of its natural gas, crude oil and NGL production activities. At December 31, 2014, the Partnership owned 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 27.7% limited partner interest (20,962,485 common and 3,749,986 Class C preferred limited partner units) in ARP; | |
— | Atlas Pipeline Partners, L.P. (“APL”), a publicly-traded Delaware master limited partnership (NYSE: APL) and midstream energy service provider engaged in the gathering, processing and treating of natural gas in the mid-continent and southwestern regions of the United States and natural gas gathering services in the Appalachian Basin in the northeastern region of the United States and in the Eagle Ford Shale play in south Texas. At December 31, 2014, the Partnership owned a 2.0% general partner interest, all of the incentive distribution rights, and an approximate 5.5% limited partner interest in APL; | |
— | Lightfoot Capital Partners, L.P. (“Lightfoot LP”) and Lightfoot Capital Partners GP, LLC (“Lightfoot GP”), the general partner of Lightfoot L.P. (collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. At December 31, 2014, the Partnership had an approximate 15.9% general partner interest and 12.0% limited partner interest in Lightfoot (see Note 7); | |
— | Development Subsidiary, a subsidiary partnership that conducts natural gas and oil operations initially in the mid-continent region of the United States, currently in the Marble Falls formation in the Fort Worth Basin and Mississippi Lime area of the Anadarko basin in Oklahoma. At December 31, 2014, the Partnership owned a 1.7% limited partner interest in its Development Subsidiary and 80.0% of its outstanding general partner Class A units, which are entitled to receive 2.0% of the cash distributed without any obligation to make further capital contributions; and | |
— | Coal-bed methane producing assets in the Arkoma Basin in eastern Oklahoma, which were acquired by the Partnership in July 2013. | |
In February 2012, the board of directors (“the Board”) of the Partnership’s General Partner (“the General Partner”) approved the formation of ARP as a newly created exploration and production master limited partnership and the related transfer of substantially all of the Partnership’s exploration and production assets to ARP on March 5, 2012. The Board also approved the distribution of approximately 5.24 million ARP common units to the Partnership’s unitholders, which were distributed on March 13, 2012 using a ratio of 0.1021 ARP limited partner units for each of the Partnership’s common units owned on the record date of February 28, 2012. | ||
Summary_of_Significant_Account
Summary of Significant Accounting Policies | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Accounting Policies [Abstract] | |||||||||||||
Summary of Significant Accounting Policies | NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | ||||||||||||
Principles of Consolidation | |||||||||||||
The consolidated financial statements include the accounts of the Partnership and its consolidated subsidiaries, all of which are wholly-owned at December 31, 2014, except for ARP, APL and the Development Subsidiary, which are controlled by the Partnership. Due to the structure of the Partnership’s ownership interests in ARP, APL and the Development Subsidiary, the Partnership consolidates the financial statements of ARP, APL and the Development Subsidiary into its consolidated financial statements rather than present its ownership interest as equity investments. As such, the non-controlling interests in ARP, APL and the Development Subsidiary are reflected as (income) loss attributable to non-controlling interests in its consolidated statements of operations and as a component of partners’ capital on its consolidated balance sheets. All material intercompany transactions have been eliminated. Certain amounts in the prior years’ consolidated financial statements have been reclassified to conform to the current year presentation. | |||||||||||||
In accordance with established practice in the oil and gas industry, the Partnership’s consolidated financial statements include its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the Drilling Partnerships in which ARP has an interest. Such interests generally approximate 30%. The Partnership’s consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of ARP’s Drilling Partnerships. Rather, ARP calculates these items specific to its own economics as further explained under the heading “Property, Plant and Equipment” elsewhere within this note. | |||||||||||||
In connection with ARP’s acquisition of certain proved reserves and associated assets from Titan Operating, L.L.C. in July 2012, ARP issued 3.8 million ARP common units and 3.8 million newly-created convertible Class B ARP preferred units (“Class B ARP Preferred Units”). While outstanding, the preferred units will receive regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution. On December 23, 2014, 3,796,900 of Class B ARP preferred units were voluntarily converted into common units. In October 2014, in connection with ARP’s acquisition of assets in the Eagle Ford Shale (see Note 4), ARP issued 3.2 million of its 8.625% Class D cumulative redeemable perpetual preferred units (“Class D ARP Preferred Units”). The initial quarterly distribution on the Class D ARP Preferred Units was $0.616927 per unit, representing the distribution for the period from October 2, 2014 through January 14, 2015. Subsequent to January 14, 2015, ARP will pay a future quarterly distribution at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference. In March 2014, APL issued 5.1 million of its Class E cumulative redeemable perpetual preferred units (“Class E APL Preferred Units”). The initial distribution on the Class E APL Preferred Units was $0.67604 per unit, representing the distribution for the period March 17, 2014 through July 14, 2014. Subsequent to July 14, 2014, APL paid a quarterly distribution of $0.515625 per unit. In May 2013, APL issued Class D convertible preferred units (“Class D APL Preferred Units”), which received distributions of additional Class D APL Preferred Units for the first four full quarterly periods following their issuance in May 2013, and thereafter will receive distributions in Class D APL Preferred Units, or a combination of Class D APL Preferred Units and cash (see Note 15). At December 31, 2014 and 2013, $738.7 million and $547.3 million, respectively, related to ARP’s and APL’s preferred units is included within non-controlling interests on the Partnership’s consolidated statements of partners’ capital. | |||||||||||||
The Partnership’s consolidated financial statements include APL’s 95% ownership interest in certain joint ventures, which individually own a 100% ownership interest in the WestOK natural gas gathering system and processing plants and a 72.8% undivided interest in the WestTX natural gas gathering system and processing plants. These joint ventures have a $1.9 billion note receivable from the holder of the 5% ownership interest in the joint ventures, which was reflected within non-controlling interests on the Partnership’s consolidated balance sheets. | |||||||||||||
The Partnership’s consolidated financial statements also include APL’s 60% interest in Centrahoma Processing LLC (“Centrahoma”), which was acquired on December 20, 2012 as part of the acquisition of assets from Cardinal Midstream, LLC (the “Cardinal Acquisition”). The remaining 40% ownership interest is held by MarkWest Oklahoma Gas Company LLC (“MarkWest”), a wholly-owned subsidiary of MarkWest Energy Partners, L.P. (NYSE: MWE). | |||||||||||||
APL consolidates 100% of these joint ventures and the non-controlling interest in the joint venture is reflected on the Partnership’s consolidated statements of operations. The Partnership also reflects the non-controlling interest in the net assets of the joint venture as a component of partners’ capital on its consolidated balance sheets (see Note 5). | |||||||||||||
The West TX joint venture has a 72.8% undivided joint venture interest in the WestTX system, of which the remaining 27.2% interest is owned by Pioneer Natural Resources Company (NYSE: PXD). Due to the WestTX system’s status as an undivided joint venture, the WestTX joint venture proportionally consolidates its 72.8% ownership interest in the assets and liabilities and operating results of the WestTX system. | |||||||||||||
During the year ended December 31, 2014, the Development Subsidiary issued $81.7 million of its common limited partner units, which was included within non-controlling interests in partners’ capital on the Partnership’s consolidated balance sheet. During the year ended December 31, 2014, the Development Subsidiary paid $1.4 million to unitholders, which was included within distributions paid to non-controlling interests on the Partnership’s consolidated statement of cash flows. For the year ended December 31, 2014, in connection with the issuance of the Development Subsidiary’s common units, the Partnership recorded gains of $4.5 million within partners’ capital and a corresponding decrease in non-controlling interests on its consolidated statement of partners’ capital (see Note 15). | |||||||||||||
Use of Estimates | |||||||||||||
The preparation of the Partnership’s consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, asset impairments, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired and liabilities assumed. Actual results could differ from those estimates. | |||||||||||||
Cash Equivalents | |||||||||||||
The Partnership considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. These cash equivalents consist principally of temporary investments of cash in short-term money market instruments. | |||||||||||||
Receivables | |||||||||||||
Accounts receivable on the consolidated balance sheets consist primarily of the trade accounts receivable associated with the Partnership and its subsidiaries. In evaluating the realizability of its accounts receivable, management performs ongoing credit evaluations of customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of customers’ credit information. The Partnership and its subsidiaries extend credit on sales on an unsecured basis to many of their customers. At December 31, 2014 and 2013, the Partnership had recorded no allowance for uncollectible accounts receivable on its consolidated balance sheets. | |||||||||||||
Inventory | |||||||||||||
The Partnership had $23.7 million and $19.7 million of inventory at December 31, 2014 and 2013, respectively, which were included within prepaid expenses and other current assets on its consolidated balance sheets. The Partnership and its subsidiaries value inventories at the lower of cost or market. ARP’s inventories, which consist of materials, pipes, supplies and other inventories, were principally determined using the average cost method. APL’s crude oil and refined product inventory costs consist of APL’s natural gas liquids line fill, which represents amounts receivable for NGLs delivered to counterparties for which the counterparty will pay at a designated later period at a price determined by the then current market price. | |||||||||||||
Subscriptions Receivable | |||||||||||||
The Partnership receives contributions from limited partner investors of its Drilling Partnerships, which are used to fund well drilling activities within the programs. Limited partner investors in the Drilling Partnerships execute an investment agreement with Anthem Securities, Inc. (“Anthem”), a registered broker-dealer and wholly owned subsidiary of ARP, through third-party broker dealers, which is then delivered to Anthem. The investor contributions are then remitted to Anthem at a later date. Limited partner investor contributions are non-refundable upon the execution of an investment agreement. ARP recognizes the contributions associated with the executed investment agreements but for which contributions have not yet been received at the respective balance sheet date as subscriptions receivable. | |||||||||||||
Property, Plant and Equipment | |||||||||||||
Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Maintenance and repairs which generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements which generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the Partnership’s results of operations. APL follows the composite method of depreciation and has determined the composite groups to be the major asset classes of its gathering, processing and treating systems. Under the composite depreciation method, any gain or loss upon disposition or retirement of pipeline, gas gathering, processing and treating components is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the Partnership’s consolidated statements of operations. | |||||||||||||
The Partnership and ARP follow the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs to enhance or evaluate development of proved fields or areas are capitalized. All other geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to 6 Mcf of natural gas. Mcf is defined as one thousand cubic feet. | |||||||||||||
The Partnership and ARP’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves, and depletion rates for well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include ARP’s costs of property interests in proportionately consolidated Drilling Partnerships, joint venture wells, wells drilled solely by ARP for its interests, properties purchased and working interests with other outside operators. | |||||||||||||
Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Partnership’s consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Partnership’s consolidated balance sheets. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Partnership’s consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained. | |||||||||||||
Impairment of Long-Lived Assets | |||||||||||||
The Partnership and its subsidiaries review their long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value. | |||||||||||||
The review of oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Partnership’s and ARP’s plans to continue to produce and develop proved reserves. Expected future cash flows from the sale of production of reserves are calculated based on estimated future prices. The Partnership and ARP estimate prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets. | |||||||||||||
The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, ARP’s reserve estimates for its investment in the Drilling Partnerships are based on its own assumptions rather than its proportionate share of the limited partnerships’ reserves. These assumptions include ARP’s actual capital contributions and a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs. | |||||||||||||
ARP’s lower operating and administrative costs result from the limited partners in the Drilling Partnerships paying to ARP their proportionate share of these expenses plus a profit margin. These assumptions could result in ARP’s calculation of depletion and impairment being different than its proportionate share of the Drilling Partnerships’ calculations for these items. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership and ARP cannot predict what reserve revisions may be required in future periods. | |||||||||||||
ARP’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the Drilling Partnerships, which ARP sponsors and owns an interest in but does not control. ARP’s reserve quantities include reserves in excess of its proportionate share of reserves in Drilling Partnerships, which ARP may be unable to recover due to the Drilling Partnerships’ legal structure. ARP may have to pay additional consideration in the future as a Drilling Partnership’s wells become uneconomic to the Drilling Partnership under the terms of the Drilling Partnership’s drilling and operating agreement in order to recover these excess reserves, in addition to ARP becoming responsible for paying associated future operating, development and plugging costs of the well interests acquired, and to acquire any additional residual interests in the wells held by the Drilling Partnership’s limited partners. The acquisition of any such uneconomic well interest from the Drilling Partnership by ARP is governed under the Drilling Partnership’s limited partner agreement. In general, ARP will seek consent from the Drilling Partnership’s limited partners to acquire the well interests from the Drilling Partnership based upon ARP’s determination of fair market value. | |||||||||||||
Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate that the Partnership and ARP will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. During the year ended December 31, 2013, ARP recognized $13.5 million of asset impairments related to its gas and oil properties within property, plant and equipment, net on the Partnership’s consolidated balance sheet, primarily for its unproved acreage in the Chattanooga and New Albany Shales. There were no impairments of unproved gas and oil properties recorded by ARP for the year ended December 31, 2014 and 2012. | |||||||||||||
Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. During the year ended December 31, 2014, the Partnership recognized $562.6 million of asset impairment related to oil and gas properties within property, plant and equipment, net on its consolidated balance sheet primarily for ARP’s Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. Asset impairments for the year ended December 31, 2014 principally resulted from the decline in forward commodity prices during the fourth quarter of 2014 through the impairment testing date in January 2015. During the year ended December 31, 2013, ARP recognized $24.5 million of asset impairments related to its gas and oil properties within property, plant and equipment, net on the Partnership’s consolidated balance sheet for its shallow natural gas wells in the New Albany Shale. During the year ended December 31, 2012, ARP recognized $9.5 million of asset impairments related to gas and oil properties within property, plant and equipment, net on its consolidated balance sheet for its shallow natural gas wells in the Antrim and Niobrara Shales. | |||||||||||||
These impairments related to the carrying amounts of these gas and oil properties being in excess of the Development Subsidiary’s and ARP’s estimates of their fair values at December 31, 2014, 2013, and 2012 and ARP’s intention not to drill on certain expiring unproved acreage. The estimate of the fair values of these gas and oil properties was impacted by, among other factors, the deterioration of commodity prices at the date of measurement. | |||||||||||||
Capitalized Interest | |||||||||||||
ARP and APL capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rates used to capitalize interest on combined borrowed funds by ARP and APL were 5.6%, 5.9% and 5.8% for the years ended December 31, 2014, 2013 and 2012, respectively. The aggregate amounts of interest capitalized by ARP and APL were $25.7 million, $21.7 million and $10.8 million for the years ended December 31, 2014, 2013 and 2012, respectively. | |||||||||||||
Intangible Assets | |||||||||||||
Customer contracts and relationships. APL amortizes intangible assets with finite lives in connection with natural gas gathering contracts and customer relationships assumed in certain consummated acquisitions, including the acquisitions of assets from TEAK Midstream, LLC (“TEAK”) in 2013 (the “TEAK Acquisition”) (see Note 4), over their estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset must be amortized over the best estimate of its useful life. At a minimum, APL will assess the useful lives of all intangible assets on an annual basis to determine if adjustments are required. The estimated useful life for APL’s customer contract intangible assets is based upon the approximate average length of customer contracts in existence and expected renewals at the date of acquisition. The estimated useful life for APL’s customer relationship intangible assets is based upon the estimated average length of non-contracted customer relationships in existence at the date of acquisition, adjusted for APL’s management’s estimate of whether the individual relationships will continue in excess of or less than the average length. As part of the TEAK Acquisition, APL recognized $450.0 million of customer relationships with an estimated useful life of 13 years. | |||||||||||||
Partnership management and operating contracts. ARP has recorded intangible assets with finite lives in connection with partnership management and operating contracts acquired through prior consummated acquisitions. ARP amortizes contracts acquired on a declining balance method over their respective estimated useful lives. | |||||||||||||
The following table reflects the components of intangible assets being amortized at December 31, 2014 and 2013 (in thousands): | |||||||||||||
December 31, | Estimated | ||||||||||||
Useful Lives | |||||||||||||
In Years | |||||||||||||
2014 | 2013 | ||||||||||||
Gross Carrying Amount: | |||||||||||||
Customer contracts and relationships | $ | 871,072 | $ | 891,072 | 2–15 | ||||||||
Partnership management and operating contracts | 14,344 | 14,344 | 13 | ||||||||||
$ | 885,416 | $ | 905,416 | ||||||||||
Accumulated Amortization: | |||||||||||||
Customer contracts and relationships | $ | (274,811 | ) | $ | (194,801 | ) | |||||||
Partnership management and operating contracts | (13,653 | ) | (13,381 | ) | |||||||||
$ | (288,464 | ) | $ | (208,182 | ) | ||||||||
Net Carrying Amount: | |||||||||||||
Customer contracts and relationships | $ | 596,261 | $ | 696,271 | |||||||||
Partnership management and operating contracts | 691 | 963 | |||||||||||
$ | 596,952 | $ | 697,234 | ||||||||||
Amortization expense on intangible assets was $80.3 million, $69.3 million and $24.0 million for the years ended December 31, 2014, 2013 and 2012 respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2015 - $74.3 million; 2016 - $74.2 million; 2017 - $68.1 million; 2018 - $59.6 million; and 2019 - $59.6 million. | |||||||||||||
Goodwill | |||||||||||||
The following table reflects the carrying amounts of goodwill by reportable operating segments at December 31, 2014 and December 31, 2013 (in thousands): | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | ||||||||||||
Atlas Resource | $ | 13,639 | $ | 31,784 | |||||||||
Atlas Pipeline | 365,763 | 368,572 | |||||||||||
$ | 379,402 | $ | 400,356 | ||||||||||
At December 31, 2014, the Partnership had $379.4 million of goodwill, which consisted of $13.6 million related to acquisitions previously consummated by ARP and $365.8 million related to acquisitions previously consummated by APL. The change in ARP’s goodwill during the year end December 31, 2014 is related to goodwill impairment related to its gas and oil production reporting unit as a result of a decline in commodity prices. The change in APL’s goodwill during the year ended December 31, 2014 is primarily related to a $2.8 million decrease in goodwill related to an adjustment of the fair value of assets acquired and liabilities assumed from the TEAK Acquisition (see Note 4). | |||||||||||||
ARP and APL test goodwill for impairment at each year end by comparing their respective reporting unit estimated fair values to carrying values, with the exception of APL’s SouthTX reporting unit which is tested as of April 30, 2014. Because quoted market prices for the reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units. ARP’s and APL’s management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets and the available market data of the respective industry group. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to market capitalization. The observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity on a stand-alone basis. In most industries, including ARP’s and APL’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, ARP and APL also consider the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in ARP’s and APL’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in ARP’s and APL’s industry to determine whether those valuations appear reasonable in management’s judgment. ARP’s and APL’s management will continue to evaluate goodwill at least annually or when impairment indicators arise. | |||||||||||||
As a result of its impairment evaluation at December 31, 2014, ARP recognized an $18.1 million goodwill impairment charge within asset impairments on the Partnership’s consolidated statement of operations for the year ended December 31, 2014. The goodwill impairment resulted from the reduction in ARP’s estimated fair value of its gas and oil production reporting unit in comparison to its carrying amount at December 31, 2014. ARP’s estimated fair value of its gas and oil production reporting unit was impacted by a decline in overall commodity prices during the fourth quarter of 2014. During the years ended December 31, 2013 and 2012, no impairment indicators arose and no goodwill impairments were recognized for ARP by the Partnership. | |||||||||||||
Subsequent to recording the final estimated fair values of the assets acquired and liabilities assumed in the Cardinal Acquisition, APL determined that a portion of goodwill recorded in connection with the acquisition was impaired. APL performed a qualitative assessment for goodwill impairment of APL’s gas treating reporting unit. The assessment indicated the potential for goodwill to be impaired due to lower forecasted cash flows as compared to original forecasts. Using a combination of discounted cash flow models and market multiples for similar businesses, APL measured the amount of goodwill impairment to be $43.9 million, which was recorded within asset impairment on the Partnership’s consolidated statement of operations for the year ended December 31, 2013. | |||||||||||||
During the years ended December 31, 2014 and 2012, no impairment indicators arose and no goodwill impairments were recognized for APL by the Partnership. | |||||||||||||
Equity Method Investments | |||||||||||||
The Partnership’s consolidated financial statements include APL’s previous interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”) which was sold in May 2014 (see Note 5); and APL’s interests in T2 LaSalle Gathering Company L.L.C. (“T2 LaSalle”), T2 Eagle Ford Gathering Company L.L.C. (“T2 Eagle Ford”), and T2 EF Cogeneration Holdings L.L.C. (“T2 Co-Gen”) (the “T2 Joint Ventures”), which were acquired as part of APL’s acquisition of 100% of the equity interests of TEAK Midstream, LLC (“TEAK”) for $974.7 million in cash, including final purchase price adjustments, less cash received (the “TEAK Acquisition”) (see Notes 4 and 5). APL accounts for its investments in these joint ventures under the equity method of accounting. Under this method, APL records its proportionate share of the joint ventures’ net income (loss) as equity income on the Partnership’s consolidated statements of operations. Investments in excess of the underlying net assets of equity method investees identifiable to property, plant and equipment or finite lived intangible assets are amortized over the useful life of the related assets and recorded as a reduction to equity investment on the Partnership’s consolidated balance sheet with an offsetting reduction to equity income on the Partnership’s consolidated statements of operations. Equity method investments are subject to impairment evaluation as necessary when events and circumstances indicate the carrying value of an equity investment may be less than its fair value. APL noted no indicators of impairment for its equity method investments, and thus no impairment charges were recognized for the years ended as of December 31, 2014, 2013 and 2012. | |||||||||||||
The Partnership’s consolidated financial statements also include its interest in Lightfoot which is accounted for under the equity method of accounting (see Note 7). | |||||||||||||
Capital Leases | |||||||||||||
Leased property and equipment meeting capital lease criteria are capitalized based on the minimum payments required under the lease and are included within property, plant and equipment on the Partnership’s consolidated balance sheets. Obligations under capital leases are accounted for as current and noncurrent liabilities and are included within debt on the Partnership’s consolidated balance sheets. Amortization is calculated on a straight-line method based upon the estimated useful lives of the assets (see Note 9). | |||||||||||||
Derivative Instruments | |||||||||||||
The Partnership enters into certain financial contracts to manage its exposure to movement in commodity prices and interest rates (see Note 10). The derivative instruments recorded in the consolidated balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in the Partnership’s consolidated statements of operations unless specific hedge accounting criteria are met. | |||||||||||||
Asset Retirement Obligations | |||||||||||||
The Partnership and ARP recognize an estimated liability for the plugging and abandonment of their respective gas and oil wells and related facilities (see Note 8). The Partnership and ARP also recognize a liability for their respective future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership and its subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization. | |||||||||||||
APL performs ongoing analysis of asset removal and site restoration costs that it may be required to perform under law or contract once an asset has been permanently taken out of service. APL has property, plant and equipment at locations it owns and at sites leased or under right of way agreements. APL is under no contractual obligation to remove the assets at locations it owns. In evaluating its asset retirement obligation, APL reviews its lease agreements, right of way agreements, easements and permits to determine which agreements, if any, require an asset removal and restoration obligation. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including expected settlement dates, future retirement costs, future inflation rates and the credit-adjusted-risk-free interest rates. However, APL was not able to reasonably measure the fair value of the asset retirement obligation as of December 31, 2014 because the settlement dates were indeterminable. Any cost incurred in the future to remove assets and restore sites will be expensed as incurred. | |||||||||||||
Income Taxes | |||||||||||||
The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income (loss) reported in the accompanying consolidated financial statements. | |||||||||||||
The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its consolidated financial statements that would not meet this threshold. The Partnership’s policy is to record interest and penalties related to uncertain tax positions, when and if they become applicable. The Partnership has not recognized any potential interest or penalties in its consolidated financial statements for the years ended December 31, 2014, 2013 and 2012. | |||||||||||||
The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2011. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2014, except for an ongoing examination by the Texas Comptroller of Public Accounts related to APL’s Texas Franchise Tax for franchise report years 2008 through 2011. | |||||||||||||
Certain corporate subsidiaries of the Partnership are subject to federal and state income tax. With the exception of a corporate subsidiary acquired by APL through the Cardinal acquisition in 2012, the federal and state income taxes related to the Partnership and these corporate subsidiaries were immaterial to the consolidated financial statements as of December 31, 2014 and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for these corporate subsidiaries in the accompanying consolidated financial statements. APL’s corporate subsidiary accounts for income taxes under the asset and liability method. Deferred income taxes are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realization of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value. The effective tax rate differs from the statutory rate due primarily to APL earnings that are generally not subject to federal and state income taxes at the APL level (see Note 12). | |||||||||||||
Stock-Based Compensation | |||||||||||||
The Partnership recognizes all share-based payments to employees, including grants of employee stock options, in the consolidated financial statements based on their fair values (see Note 17). | |||||||||||||
Net Income (Loss) Per Common Unit | |||||||||||||
Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners, which is determined after the deduction of net income attributable to participating securities, if applicable, by the weighted average number of common limited partner units outstanding during the period. | |||||||||||||
Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit pursuant to the two-class method. The Partnership’s phantom unit awards, which consist of common units issuable under the terms of its long-term incentive plans and incentive compensation agreements (see Note 17), contain non-forfeitable rights to distribution equivalents of the Partnership. The participation rights result in a non-contingent transfer of value each time the Partnership declares a distribution or distribution equivalent right during the award’s vesting period. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. As such, the net income utilized in the calculation of net income (loss) per unit must be after the allocation of only net income to the phantom units on a pro-rata basis. | |||||||||||||
The following is a reconciliation of net income (loss) allocated to the common limited partners for purposes of calculating net income (loss) attributable to common limited partners per unit (in thousands, except unit data): | |||||||||||||
Years Ended December 31, | |||||||||||||
Continuing Operations: | 2014 | 2013 | 2012 | ||||||||||
Net loss | $ | (465,390 | ) | $ | (228,598 | ) | $ | (16,881 | ) | ||||
Loss (income) attributable to non-controlling interests | 273,132 | 153,231 | (35,532 | ) | |||||||||
Net loss attributable to common limited partners | (192,258 | ) | (75,367 | ) | (52,413 | ) | |||||||
Less: Net income attributable to participating securities – phantom units(1) | — | — | — | ||||||||||
Net loss utilized in the calculation of net loss attributable to common limited partners per unit | $ | (192,258 | ) | $ | (75,367 | ) | $ | (52,413 | ) | ||||
(1) | Net income attributable to common limited partners’ ownership interests is allocated to the phantom units on a pro-rata basis (weighted average phantom units outstanding as a percentage of the sum of the weighted average phantom units and common limited partner units outstanding). For the years ended December 31, 2014, 2013 and 2012, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 2,827,000, 2,278,000 and 2,058,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. | ||||||||||||
Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners, less income allocable to participating securities, by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of unit option awards, as calculated by the treasury stock method. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of the Partnership’s long-term incentive plans (see Note 17). | |||||||||||||
The following table sets forth the reconciliation of the Partnership’s weighted average number of common limited partner units used to compute basic net income (loss) attributable to common limited partners per unit with those used to compute diluted net income (loss) attributable to common limited partners per unit (in thousands): | |||||||||||||
Years Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Weighted average number of common limited partners per unit—basic | 51,810 | 51,387 | 51,327 | ||||||||||
Add effect of dilutive incentive awards(1) | — | — | — | ||||||||||
Weighted average number of common limited partners per unit—diluted | 51,810 | 51,387 | 51,327 | ||||||||||
(1) | For the years ended December 31, 2014, 2013 and 2012, approximately 4,473,000, 3,995,000 and 2,867,000 units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. | ||||||||||||
Environmental Matters | |||||||||||||
The Partnership and its subsidiaries are subject to various federal, state and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of the Partnership’s and its subsidiaries’ operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. The Partnership and its subsidiaries maintain insurance which may cover in whole or in part certain environmental expenditures. The Partnership and its subsidiaries had no environmental matters requiring specific disclosure or requiring the recognition of a liability for the years ended December 31, 2014 and 2013. During the year ended December 31, 2012, one of the Partnership’s subsidiaries entered into two agreements with the United States Environmental Protection Agency (the “EPA”) to settle alleged violations in connection with a fire that occurred at a natural gas well and associated well pad site in Washington County, Pennsylvania in 2010. The EPA alleged non-compliance with the Clean Air Act, including with respect to the storage and handling of the natural gas condensate, as well as non-compliance with the Emergency Planning and Community Right-to-Know Act of 1986. The subsidiary agreed to a civil penalty of $84,506 under a consent agreement and agreed to upgrade its facility pursuant to an administrative settlement agreement. | |||||||||||||
Concentration of Credit Risk | |||||||||||||
Financial instruments, which potentially subject the Partnership to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. The Partnership and its subsidiaries place their temporary cash investments in high-quality short-term money market instruments and deposits with high-quality financial institutions and brokerage firms. At December 31, 2014 and 2013, the Partnership had $86.5 million and $51.4 million, respectively, in deposits at various banks, of which $81.6 million and $48.8 million, respectively, were over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments to date. Cash on deposit at various banks may differ from the balance of cash and cash equivalents at period end due to certain reconciling items, including any outstanding checks as of period end. | |||||||||||||
The Partnership and its subsidiaries sell natural gas, crude oil and NGLs under contracts to various purchasers in the normal course of business. For the year ended December 31, 2014, ARP had four customers within its gas and oil production segment that individually accounted for approximately 25%, 15%, 14% and 13%, respectively, of its natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2013, ARP had three customers within its gas and oil production segment that individually accounted for approximately 19%, 11% and 10%, respectively, of its natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2012, ARP had two customers within its gas and oil production segment that individually accounted for approximately 43% and 11% of its natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. | |||||||||||||
For the year ended December 31, 2014, APL had three customers that individually accounted for approximately 26%, 13% and 11%, respectively, of its consolidated total third party revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2013, APL had three customers that individually accounted for approximately 29%, 17% and 14%, respectively, of its consolidated total third party revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2012, APL had two customers that individually accounted for approximately 48% and 15%, respectively, of its consolidated total third party revenues, excluding the impact of all financial derivative activity. | |||||||||||||
Accrued Producer Liabilities | |||||||||||||
Accrued producer liabilities on the Partnership’s consolidated balance sheets represent APL’s accrued purchase commitments payable to producers related to the natural gas gathered and processed through its system under its Percentage of Proceeds (“POP”) and Keep-Whole contracts (see “Revenue Recognition”). | |||||||||||||
Revenue Recognition | |||||||||||||
Natural gas and oil production. The Partnership and ARP generally sell natural gas, crude oil and NGLs at prevailing market prices. Typically, sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil and NGLs, in which the Partnership or ARP has an interest with other producers, are recognized on the basis of the entity’s percentage ownership of the working interest and/or overriding royalty. | |||||||||||||
ARP’s Drilling Partnerships. Certain energy activities are conducted by ARP through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. Drilling Partnership investor capital raised by ARP is deployed to drill and complete wells included within the partnership. As ARP deploys Drilling Partnership investor capital, it recognizes certain management fees it is entitled to receive, including well construction and completion revenue and a portion of administration and oversight revenue. At each period end, if ARP has Drilling Partnership investor capital that has not yet been deployed, it will recognize a current liability titled “Liabilities Associated with Drilling Contracts” on the Partnership’s consolidated balance sheets. After the Drilling Partnership well is completed and turned in line, ARP is entitled to receive additional operating and management fees, which are included within well services and administration and oversight revenue, respectively, on a monthly basis while the well is operating. In addition to the management fees it is entitled to receive for services provided, ARP is also entitled to its pro-rata share of Drilling Partnership gas and oil production revenue, which generally approximates 30%. ARP recognizes its Drilling Partnership management fees in the following manner: | |||||||||||||
— | Well construction and completion. For each well that is drilled by a Drilling Partnership, ARP receives a 15% mark-up on those costs incurred to drill and complete wells included within the partnership. Such fees are earned, in accordance with the partnership agreement, and recognized as the services are performed, typically between 60 and 270 days, using the percentage of completion method. | ||||||||||||
— | Administration and oversight. For each well drilled by a Drilling Partnership, ARP receives a fixed fee between $100,000 and $500,000, depending on the type of well drilled, which is earned in accordance with the partnership agreement and recognized at the initiation of the well. Additionally, the Drilling Partnership pays ARP a monthly per well administrative fee of $75 for the life of the well. The well administrative fee is earned on a monthly basis as the services are performed. | ||||||||||||
— | Well services. Each Drilling Partnership pays ARP a monthly per well operating fee, currently $1,000 to $2,000, depending on the type of well, for the life of the well. Such fees are earned on a monthly basis as the services are performed. | ||||||||||||
While its historical structure has varied, ARP has generally agreed to subordinate a portion of its share of Drilling Partnership gas and oil production revenue, net of corresponding production costs and up to a maximum of 50% of unhedged revenue, from certain Drilling Partnerships for the benefit of the limited partner investors until they have received specified returns, typically 10% to 12% per year determined on a cumulative basis, over a specified period, typically the first five to eight years, in accordance with the terms of the partnership agreements. ARP periodically compares the projected return on investment for limited partners in a Drilling Partnership during the subordination period, based upon historical and projected cumulative gas and oil production revenue and expenses, with the return on investment subject to subordination agreed upon within the Drilling Partnership agreement. If the projected return on investment falls below the agreed upon rate, ARP recognizes subordination as an estimated reduction of its pro-rata share of gas and oil production revenue, net of corresponding production costs, during the current period in an amount that will achieve the agreed upon investment return, subject to the limitation of 50% of unhedged cumulative net production revenues over the subordination period. For Drilling Partnerships for which ARP has recognized subordination in a historical period, if projected investment returns subsequently reflect that the agreed upon limited partner investment return will be achieved during the subordination period, ARP will recognize an estimated increase in its portion of historical cumulative gas and oil net production, subject to a limitation of the cumulative subordination previously recognized. | |||||||||||||
ARP’s Gathering and processing revenue. Gathering and processing revenue includes gathering fees ARP charges to the Drilling Partnership wells for ARP’s processing plants in the New Albany and the Chattanooga Shales. Generally, ARP charges a gathering fee to the Drilling Partnership wells equivalent to the fees ARP remits. In Appalachia, a majority of the Drilling Partnership wells are subject to a gathering agreement, whereby ARP remits a gathering fee of 16%. However, based on the respective Drilling Partnership agreements, ARP charges the Drilling Partnership wells a 13% gathering fee. As a result, some of ARP’s gathering expenses, specifically those in the Appalachian Basin, will generally exceed the revenues collected from the Drilling Partnerships by approximately 3%. | |||||||||||||
Atlas Pipeline. APL’s revenue primarily consists of the sale of natural gas and NGLs, along with the fees earned from its gathering, processing and treating operations. Under certain agreements, APL purchases natural gas from producers, moves it into receipt points on its pipeline systems and then sells the natural gas, or produced NGLs and condensate, if any, off delivery points on its systems. Under other agreements, APL gathers natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with the physical sale of natural gas and NGLs is recognized upon physical delivery. Revenue related to fees for providing natural gas gathering, processing and treating services is recognized based on throughput volumes during the period, with throughput volumes generally measured at the wellhead. In connection with its gathering, processing and treating operations, APL enters into the following types of contractual relationships with its producers and shippers: | |||||||||||||
POP Contracts. These contracts provide for APL to retain a negotiated percentage of the sale proceeds from residue gas and NGLs it gathers and processes, with the remainder being remitted to the producer. In this contract-type, APL and the producer are directly dependent on the volume of the commodity and its value; APL effectively owns a percentage of the commodity and revenues are directly correlated to its market value. | |||||||||||||
Keep-Whole Contracts. These contracts require APL, as the processor and gatherer, to gather or purchase raw natural gas at current market rates per MMBtu. The volume and energy content of gas gathered or purchased is based on the measurement at an agreed upon location (generally at the wellhead). The Btu quantity of gas redelivered or sold at the tailgate of APL’s processing facility may be lower than the Btu quantity purchased at the wellhead primarily due to the NGLs extracted from the natural gas when processed through a plant. APL must make up or “keep the producer whole” for this loss in Btu quantity. To offset the make-up obligation, APL retains the NGLs which are extracted and sells them for its own account. During 2014, APL renegotiated most of its Keep-Whole contracts and converted them into POP contracts. | |||||||||||||
Fee-based or POP contracts sometimes include fixed recovery terms, which mean products returned to the producer are calculated using an agreed NGL recovery factor, regardless of the volumes of NGLs actually recovered through processing. | |||||||||||||
The Partnership and its subsidiaries accrue unbilled revenue and APL accrues the related purchase costs due to timing differences between the delivery of natural gas, NGLs, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “Use of Estimates” for further description). The Partnership and its subsidiaries had unbilled revenues of $260.7 million and $191.8 million at December 31, 2014 and 2013, respectively, which were included in accounts receivable within its consolidated balance sheets. APL’s accrued purchase costs at December 31, 2014 and 2013 are included within accrued producer liabilities within the Partnership’s consolidated balance sheets. | |||||||||||||
Comprehensive Income (Loss) | |||||||||||||
Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on the Partnership’s consolidated financial statements, and for all periods presented, only include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges (see Note 10). The Partnership does not have any other type of transaction which would be included within other comprehensive income (loss). | |||||||||||||
Recently Adopted Accounting Standards | |||||||||||||
In November 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-17, Business Combinations (Topic 805) – Pushdown Accounting (“Update 2014-17”). The amendments in Update 2014-17 provide an acquired entity with an option to apply pushdown accounting in its separate financial statements upon occurrence of an event in which an acquirer obtains control of the acquired entity. The amendments in Update 2014-17 also provide U.S. GAAP guidance on whether and at what threshold an acquired entity that is a business can apply pushdown accounting in its separate financial statements. The amendments in Update 2014-17 became effective on November 18, 2014. After the effective date, an acquired entity can make an election to apply the guidance to future change-in-control events or to its most recent change-in-control event. However, if the financial statements for the period in which the most recent change-in-control event occurred already have been issued or made available to be issued, the application of this guidance would be a change in accounting principle. The Partnership adopted the requirements of Update 2014-17 upon its effective date of November 18, 2014, and it had no material impact on its financial position, results of operations or related disclosures. | |||||||||||||
In July 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-11, Income Taxes (Topic 740) – Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (“Update 2013-11”), which, among other changes, requires an entity to present an unrecognized tax benefit as a liability and not net with deferred tax assets when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date to settle any additional income taxes under the tax law of the applicable jurisdiction that would result from the disallowance of a tax position or when the tax law of the applicable tax jurisdiction does not require, and the entity does not intend to, use the deferred tax asset for such purpose. These requirements are effective for interim and annual reporting periods beginning after December 15, 2013. Early adoption was permitted. These amendments should be applied prospectively to all unrecognized tax benefits that exist at the effective date. Retrospective application was permitted. The Partnership adopted the requirements of Update 2013-11 upon its effective date of January 1, 2014, and it had no material impact on its financial position, results of operations or related disclosures. | |||||||||||||
In February 2013, the FASB issued ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements, for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements, for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership adopted the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it had no material impact on its financial position, results of operations or related disclosures. | |||||||||||||
Recently Issued Accounting Standards | |||||||||||||
In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“Update 2015-02”). The amendments in Update 2015-02 are intended to improve targeted areas of consolidation guidance for legal entities such as limited partnerships, limited liability corporations and securitization structures. The amendments simplify the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. The amendments in Update 2015-02 are effective for periods beginning after December 31, 2015. Early adoption is permitted, including adoption in an interim period. The Partnership will adopt the requirements of Update 2015-02 upon its effective date of January 1, 2016, and is evaluating the impact of adoption on its financial position, results of operations or related disclosures. | |||||||||||||
In January 2015, the FASB issued ASU 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items (“Update 2015-01”). The amendments in Update 2015-01 simplify the income statement presentation requirements in Subtopic 225-20 by eliminating the concept of extraordinary items. Extraordinary items are events and transactions that are distinguished by their unusual nature and by the infrequency of their occurrence. Eliminating the extraordinary classification simplifies income statement presentation by altogether removing the concept of extraordinary items from consideration. The amendments in Update 2015-01 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. A reporting entity may apply the amendments prospectively. A reporting entity may also apply the amendments retrospectively to all prior periods presented in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal year of adoption. The Partnership will adopt the requirements of Update 2015-01 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures. | |||||||||||||
In November 2014, the FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815) – Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share is More Akin to Debt or to Equity (“Update 2014-16”). Certain classes of shares include features that entitle the holders to preferences and rights (such as conversion rights, redemption rights, voting powers, and liquidation and dividend payment preferences) over the other shareholders. Shares that include embedded derivative features are referred to as hybrid financial instruments, which must be separated from the host contract and accounted for as a derivative if certain criteria are met under Subtopic 815-10. One criterion requires evaluating whether the nature of the host contract is more akin to debt or to equity and whether the economic characteristics and risks of the embedded derivative feature are “clearly and closely related” to the host contract. In making that evaluation, an issuer or investor may consider all terms and features in a hybrid financial instrument including the embedded derivative feature that is being evaluated for separate accounting or may consider all terms and features in the hybrid financial instrument except for the embedded derivative feature that is being evaluated for separate accounting. The use of different methods can result in different accounting outcomes for economically similar hybrid financial instruments. Additionally, there is diversity in practice with respect to the consideration of redemption features in relation to other features when determining whether the nature of a host contract is more akin to debt or to equity. The amendments in Update 2014-16 clarify how current GAAP should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. The effects of initially adopting the amendments in Update 2014-16 should be applied on a modified retrospective basis to existing hybrid financial instruments issued in the form of a share as of the beginning of the fiscal year for which the amendments are effective. Retrospective application is permitted to all relevant prior periods. The amendments in Update 2014-16 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption, including adoption in an interim period, is permitted. The Partnership will adopt the requirements of Update 2014-16 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures. | |||||||||||||
In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) (“Update 2014-15”). The amendments in Update 2014-15 provide U.S. GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management will be required to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. The Partnership will adopt the requirements of Update 2014-15 upon its effective date of January 1, 2017, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures. | |||||||||||||
In June 2014, the FASB issued ASU 2014-12, Compensation – Stock Compensation (Topic 718) (“Update 2014-12”). The amendments in Update 2014-12 require that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. As such, the performance target should not be reflected in estimating the grant date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved. The amendments in Update 2014-12 are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Earlier adoption is permitted. Entities may apply the amendments in Update 2014-12 either (a) prospectively to all awards granted or modified after the effective date, or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. The Partnership will adopt the requirements of Update 2014-12 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures. | |||||||||||||
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles – Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. The Partnership will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2017, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures. | |||||||||||||
Acquisition_from_Atlas_Energy_
Acquisition from Atlas Energy, Inc. | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Acquisitions | NOTE 4 – ACQUISITIONS | |||||||||
ARP’s Rangely Acquisition | ||||||||||
On June 30, 2014, ARP completed an acquisition of a 25% non-operated net working interest in oil and natural gas liquids producing assets in the Rangely field in northwest Colorado from Merit Management Partners I, L.P., Merit Energy Partners III, L.P. and Merit Energy Company, LLC (collectively, “Merit Energy”) for approximately $409.4 million in cash, net of purchase price adjustments (the “Rangely Acquisition”). The purchase price was funded through borrowings under ARP’s revolving credit facility, the issuance of an additional $100.0 million of ARP’s 7.75% senior notes due 2021 (“7.75% ARP Senior Notes”) (see Note 9) and the issuance of 15,525,000 of ARP’s common limited partner units (see Note 15). The Rangely Acquisition had an effective date of April 1, 2014. The Partnership’s combined consolidated financial statements reflected the operating results of the acquired business commencing June 30, 2014 with the transaction closing. | ||||||||||
ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). In conjunction with the issuance of ARP’s common limited partner units associated with the acquisition, ARP recorded $11.6 million of transaction fees which were included within non-controlling interests at December 31, 2014 on the Partnership’s consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred. Due to the recent date of the acquisition, the accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as ARP continues to evaluate the facts and circumstances that existed as of the acquisition date. | ||||||||||
The following table presents the preliminary values assigned to the assets acquired and liabilities assumed in the acquisition, based on their estimated fair values at the date of the acquisition (in thousands): | ||||||||||
Assets: | ||||||||||
Prepaid expenses and other | 4,041 | |||||||||
Property, plant and equipment | 405,876 | |||||||||
Other assets, net | 2,888 | |||||||||
Total assets acquired | $ | 412,805 | ||||||||
Liabilities: | ||||||||||
Accrued liabilities | 2,117 | |||||||||
Asset retirement obligation | 1,305 | |||||||||
Total liabilities assumed | 3,422 | |||||||||
Net assets acquired | $ | 409,383 | ||||||||
Revenues and net income of $41.5 million and $18.8 million, respectively, have been included in the Partnership’s consolidated statement of operations related to the Rangely Acquisition for the year ended December 31, 2014. | ||||||||||
ARP’s EP Energy Acquisition | ||||||||||
On July 31, 2013, ARP completed an acquisition of assets from EP Energy E&P Company, L.P. (“EP Energy”) for approximately $709.6 million in cash, net of purchase price adjustments (the “EP Energy Acquisition”). ARP funded the purchase price through borrowings under its revolving credit facility, the issuance of its 9.25% senior notes due 2021 (“9.25% ARP Senior Notes”) (see Note 9), and the issuance of 14,950,000 ARP common limited partner units and 3,749,986 newly created ARP Class C convertible preferred units (see Note 15). The assets acquired by ARP in the EP Energy Acquisition included coal-bed methane producing natural gas assets in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming. The EP Energy Acquisition had an effective date of May 1, 2013. The accompanying combined consolidated financial statements reflect the operating results of the acquired business commencing July 31, 2013 with the transaction closing. | ||||||||||
ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). In conjunction with the issuance of ARP’s common limited partner units associated with the acquisition, ARP recorded $12.1 million of transaction fees which were included within non-controlling interests for the year ended December 31, 2013 on Partnership’s combined consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred. | ||||||||||
The following table presents the values assigned to the assets acquired and liabilities assumed in the EP Energy Acquisition, based on their estimated fair values at the date of the acquisition (in thousands): | ||||||||||
Assets: | ||||||||||
Prepaid expenses and other | $5,268 | |||||||||
Property, plant and equipment | 723,842 | |||||||||
Total current assets | $729,110 | |||||||||
Liabilities: | ||||||||||
Accounts payable | 2,747 | |||||||||
Asset retirement obligation | 16,728 | |||||||||
Total liabilities assumed | 19,475 | |||||||||
Net assets acquired | $709,635 | |||||||||
ARP’s DTE Acquisition | ||||||||||
On December 20, 2012, ARP completed the acquisition of DTE Gas Resources, L.L.C. from DTE Energy Company (NYSE: DTE; “DTE”) for $257.4 million (the “DTE Acquisition”). In connection with entering into a purchase agreement related to the DTE Acquisition, ARP issued approximately 7.9 million of its common limited partner units through a public offering in November 2012 for $174.5 million, which was used to partially repay amounts outstanding under its revolving credit facility prior to closing (see Note 15). The cash paid at closing was funded through $179.8 million of borrowings under ARP’s revolving credit facility and $77.6 million through borrowings under ARP’s then-existing term loan credit facility (see Note 9). | ||||||||||
ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). In conjunction with the issuance of common units associated with the acquisition, ARP recorded $0.2 million of transaction fees which were included within non-controlling interests for the year ended December 31, 2012 on the Partnership’s combined consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred. | ||||||||||
The following table presents the values assigned to the assets acquired and liabilities assumed in the DTE Acquisition, based on their estimated fair values at the date of the acquisition (in thousands): | ||||||||||
Assets: | ||||||||||
Accounts receivable | $10,721 | |||||||||
Prepaid expenses and other | 2,100 | |||||||||
Total current assets | 12,821 | |||||||||
Property, plant and equipment | 263,194 | |||||||||
Other assets, net | 273 | |||||||||
Total assets acquired | $276,288 | |||||||||
Liabilities: | ||||||||||
Accounts payable | $7,760 | |||||||||
Accrued liabilities | 2,910 | |||||||||
Total current liabilities | 10,670 | |||||||||
Asset retirement obligation and other | 8,169 | |||||||||
Total liabilities assumed | 18,839 | |||||||||
Net assets acquired | $257,449 | |||||||||
ARP’s Titan Acquisition | ||||||||||
On July 25, 2012, ARP completed the acquisition of Titan Operating, L.L.C. (“Titan”) in exchange for 3.8 million common units and 3.8 million newly created convertible Class B preferred units (which had an estimated collective value of $193.2 million, based upon the closing price of ARP’s publicly traded units as of the acquisition closing date), as well as $15.4 million in cash for closing adjustments (see Note 15). The cash paid at closing was funded through borrowings under ARP’s credit facility. The common units and preferred units were issued and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”) (see Note 15). ARP’s acquisition of Titan in exchange for 3.8 million ARP common units and 3.8 million newly created convertible ARP Class B preferred units represented a non-cash transaction during the year ended December 31, 2012. | ||||||||||
ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). In conjunction with its issuance of common and preferred limited partner units associated with the acquisition, ARP recorded $3.5 million of transaction fees, which were included within non-controlling interests for the year ended December 31, 2012 on the Partnership’s combined consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred. | ||||||||||
The following table presents the values assigned to the assets acquired and liabilities assumed in the acquisition of Titan, based on their estimated fair values at the date of the acquisition (in thousands): | ||||||||||
Assets: | ||||||||||
Cash and cash equivalents | $372 | |||||||||
Accounts receivable | 5,253 | |||||||||
Prepaid expenses and other | 131 | |||||||||
Total current assets | 5,756 | |||||||||
Property, plant and equipment | 208,491 | |||||||||
Other assets, net | 2,344 | |||||||||
Total assets acquired | $216,591 | |||||||||
Liabilities: | ||||||||||
Accounts payable | $676 | |||||||||
Revenue distribution payable | 3,091 | |||||||||
Accrued liabilities | 1,816 | |||||||||
Total current liabilities | 5,583 | |||||||||
Asset retirement obligation and other | 2,418 | |||||||||
Total liabilities assumed | 8,001 | |||||||||
Net assets acquired | $208,590 | |||||||||
ARP’s Carrizo Acquisition | ||||||||||
On April 30, 2012, ARP completed the acquisition of certain oil and natural gas assets from Carrizo Oil and Gas, Inc. (NASDAQ: CRZO; “Carrizo”) for approximately $187.0 million in cash (the “Carrizo Acquisition”). The purchase price was funded through borrowings under ARP’s credit facility and $119.5 million of net proceeds from the sale of 6.0 million of its common units at a negotiated purchase price per unit of $20.00, of which $5.0 million was purchased by certain executives of Atlas Energy. The common units were issued in a private transaction exempt from registration under Section 4(2) of the Securities Act (see Note 15). | ||||||||||
ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). In conjunction with the issuance of ARP’s common limited partner units associated with the acquisition, ARP recorded $1.2 million of transaction fees which were included within non-controlling interests for the year ended December 31, 2012 on the Partnership’s combined consolidated balance sheet. All other costs associated with ARP’s acquisition of assets were expensed as incurred. | ||||||||||
The following table presents the values assigned to the assets acquired and liabilities assumed in the Carrizo Acquisition, based on their estimated fair values at the date of the acquisition (in thousands): | ||||||||||
Assets: | ||||||||||
Property, plant and equipment | $190,946 | |||||||||
Liabilities: | ||||||||||
Asset retirement obligation | 3,903 | |||||||||
Net assets acquired | $187,043 | |||||||||
APL’s TEAK Acquisition. | ||||||||||
On May 7, 2013, APL completed the TEAK Acquisition for $974.7 million in cash, including final purchase price adjustments, less cash received. Through the TEAK Acquisition, APL acquired natural gas gathering and processing facilities in Texas, which included a 75% interest in T2 LaSalle Gathering Company L.L.C. (“T2 LaSalle”), a 50% interest in T2 Eagle Ford Gathering Company L.L.C. (“T2 Eagle Ford”), and a 50% interest in T2 EF Cogeneration Holdings L.L.C. (“T2 Co-Gen”) (collectively, the “T2 Joint Ventures”). | ||||||||||
APL funded the purchase price for the TEAK Acquisition through: | ||||||||||
— | the private placement of $400.0 million of its Class D Preferred Units for net proceeds of $397.7 million, including the Partnership’s general partner contribution of $8.2 million to maintain its 2.0% general partner interest in APL (see Note 15); | |||||||||
— | the sale of 11,845,000 APL common limited partner units in a public offering at a purchase price of $34.00 per unit, generating net proceeds of approximately $388.4 million, plus the Partnership’s general partner contribution of $8.3 million to maintain its 2.0% general partner interest in APL (see Note 15); and | |||||||||
— | borrowings under its senior secured revolving credit facility. | |||||||||
Subsequent to the closing of the TEAK Acquisition, on May 10, 2013, APL issued $400.0 million of its 4.75% unsecured senior notes due November 15, 2021 (“4.75 APL Senior Notes”) for net proceeds of $391.2 million, which were used to reduce the level of borrowings under its revolving credit facility, including amounts borrowed in connection with the TEAK Acquisition (see Note 9). | ||||||||||
APL accounted for this transaction under the acquisition method of accounting. Accordingly, APL evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). In conjunction with the issuance of APL’s common and preferred limited partner units associated with the acquisition, $16.6 million of transaction fees were included in the net proceeds recorded within non-controlling interests on the Partnership’s consolidated balance sheet for the year ended December 31, 2013. In conjunction with APL’s issuance of the 4.75% APL Senior Notes and an amendment to its revolving credit facility (see Note 9), APL recorded $9.7 million of transaction fees as deferred financing costs, which are included in other assets, net on the Partnership’s consolidated balance sheet at December 31, 2013. All other costs associated with the acquisition were expensed as incurred. | ||||||||||
The following table presents the final values assigned to the assets acquired and liabilities assumed in the TEAK Acquisition, based on their fair values as the date of the acquisition (in thousands): | ||||||||||
Assets: | ||||||||||
Cash | $ | 8,074 | ||||||||
Accounts receivable | 11,055 | |||||||||
Prepaid expenses and other | 1,626 | |||||||||
Total current assets | 20,755 | |||||||||
Property, plant and equipment | 197,683 | |||||||||
Intangible assets | 430,000 | |||||||||
Goodwill | 186,050 | |||||||||
Equity method investment in joint ventures | 184,327 | |||||||||
Total assets acquired | $ | 1,018,815 | ||||||||
Liabilities: | ||||||||||
Accounts payable and accrued liabilities | 34,995 | |||||||||
Other long term liabilities | 1,075 | |||||||||
Total liabilities assumed | 36,070 | |||||||||
Net assets acquired | 982,745 | |||||||||
Less cash received | (8,074 | ) | ||||||||
Net cash paid for acquisition | $ | 974,671 | ||||||||
APL’s Cardinal Acquisition | ||||||||||
On December 20, 2012, APL completed the Cardinal Acquisition for $598.9 million in cash, including final purchase price adjustments. The assets from this acquisition (the “APL Arkoma assets”) include gas gathering, processing and treating facilities in Arkansas, Louisiana, Oklahoma and Texas and a 60% interest in Centrahoma. The remaining 40% ownership interest in Centrahoma is held by MarkWest Energy Partners, L.P. (NYSE: MWE). APL funded the purchase price for the Cardinal Acquisition in part from the private placement of $175.0 million of its 6.625% senior unsecured notes due October 1, 2020 (“6.625% APL Senior Notes”) at a premium of 3.0%, for net proceeds of $176.5 million (see Note 9); and from the sale of 10,507,033 APL common limited partner units in a public offering at a purchase price of $31.00 per unit, generating net proceeds of approximately $319.3 million, including the Partnership’s contribution of $6.7 million to maintain its 2.0% general partner interest in APL (see Note 15). APL funded the remaining purchase price from its senior secured revolving credit facility (see Note 9). | ||||||||||
APL accounted for this transaction under the acquisition method of accounting. Accordingly, APL evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). | ||||||||||
The following table presents the values assigned to the assets acquired and liabilities assumed in the Cardinal Acquisition, based on their estimated fair values at the date of the acquisition, including the 40% non-controlling interest of Centrahoma held by MarkWest (in thousands): | ||||||||||
Assets: | ||||||||||
Cash | $ | 1,184 | ||||||||
Accounts receivable | 13,783 | |||||||||
Prepaid expenses and other | 1,289 | |||||||||
Property, plant and equipment | 246,787 | |||||||||
Intangible assets | 232,740 | |||||||||
Goodwill | 214,090 | |||||||||
Total assets acquired | 709,873 | |||||||||
Liabilities: | ||||||||||
Current portion of long-term debt | 341 | |||||||||
Accounts payable and accrued liabilities | 14,596 | |||||||||
Deferred tax liability, net | 35,353 | |||||||||
Long-term debt, less current portion | 604 | |||||||||
Total liabilities acquired | 50,894 | |||||||||
Non-controlling interest | 58,905 | |||||||||
Net assets acquired | 600,074 | |||||||||
Less cash received | (1,184 | ) | ||||||||
Net cash paid for acquisition | $ | 598,890 | ||||||||
The fair value of MarkWest’s 40% non-controlling interest in Centrahoma was based upon the purchase price allocated to the 60% controlling interest APL acquired using an income approach. This measurement uses significant inputs that are not observable in the market and thus represents a fair value measurement categorized within Level 3 of the fair value hierarchy. The 40% non-controlling interest in Centrahoma was reduced by a 5% adjustment for lack of control that market participants would consider when measuring its fair value. | ||||||||||
In 2013, subsequent to recording the final estimated fair values of the assets acquired and liabilities assumed in the Cardinal Acquisition, APL determined that a portion of goodwill recorded in connection with the acquisition was impaired (see Note 2 – Goodwill). | ||||||||||
Pro Forma Financial Information | ||||||||||
The following data presents pro forma revenues, net loss and basic and diluted net loss per unit for the Partnership as if the Rangely, EP Energy and TEAK acquisitions, including the related borrowings, net proceeds from the issuances of debt and issuances of common and preferred limited partner units had occurred on January 1, 2013. The Partnership prepared these pro forma unaudited financial results for comparative purposes only; they may not be indicative of the results that would have occurred if the Rangely, EP Energy and TEAK acquisitions and related offerings had occurred on January 1, 2013 or the results that will be attained in future periods (in thousands, except per share data; unaudited): | ||||||||||
Years Ended December 31, | ||||||||||
2014 | 2013 | |||||||||
Total revenues and other | $ | 3,714,704 | $ | 2,793,098 | ||||||
Net loss | (427,351 | ) | (141,776 | ) | ||||||
Net loss attributable to common limited partners | (181,455 | ) | (51,653 | ) | ||||||
Net loss attributable to common limited partners per unit: | ||||||||||
Basic and Diluted | $ | (3.50 | ) | $ | (1.01 | ) | ||||
Other Acquisitions | ||||||||||
On November 5, 2014, ARP and the Development Subsidiary completed an acquisition of oil and natural gas liquid interests in the Eagle Ford Shale in Atascosa County, Texas from Cima Resources, LLC and Cinco Resources, Inc. (together “Cinco”) for $339.2 million, net of purchase price adjustments (the “Eagle Ford Acquisition”). Approximately $179.5 million was paid in cash by ARP and $19.7 million was paid by the Development Subsidiary at closing, and approximately $140.0 million will be paid over the four quarters following closing. The deferred portion of the purchase price represents a non-cash transaction for statement of cash flow purposes during the year ended December 31, 2014. ARP will pay approximately $24.0 million of the deferred portion of the purchase price in three quarterly installments beginning March 31, 2015. The Development Subsidiary will pay approximately $116.0 million of the deferred portion purchase price in four quarterly installments following closing. ARP may pay up to $20.0 million of its deferred portion of the purchase price by issuing ARP’s 8.625% Class D cumulative redeemable perpetual preferred units (“Class D Preferred Units”) at a price of $25.00 per unit (see Note 13). In connection with the closing of the Eagle Ford Acquisition, ARP’s revolving credit facility was amended to increase the borrowing base to $900.0 million and to make certain amendments to allow for the deferred purchase payments (see Note 9). The Eagle Ford Acquisition had an effective date of July 1, 2014. The Partnership recorded $2.8 million of gains on mark-to-market derivatives in conjunction with the entering into derivative instruments upon signing the Eagle Ford Acquisition. | ||||||||||
On May 12, 2014, ARP completed the acquisition of certain assets from GeoMet, Inc. (“GeoMet”) (OTCQB: GMET) for approximately $97.9 million in cash, net of purchase price adjustments, with an effective date of January 1, 2014. The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia. | ||||||||||
On September 20, 2013, ARP completed the acquisition of certain assets from Norwood Natural Resources (“Norwood”) for $5.4 million (the “Norwood Acquisition”). The assets acquired included Norwood’s non-operating working interest in certain producing wells in the Barnett Shale. The Norwood Acquisition had an effective date of June 1, 2013. | ||||||||||
On July 31, 2013, the Partnership completed the acquisition of certain natural gas and oil producing assets in the Arkoma Basin from EP Energy for approximately $64.5 million, net of purchase price adjustments (the “Arkoma Acquisition”). The Arkoma Acquisition was funded with a portion of the proceeds from the issuance of the Partnership’s term loan facility (see Note 9). The Arkoma Acquisition had an effective date of May 1, 2013. | ||||||||||
In April 2012, ARP acquired a 50% interest in approximately 14,500 net undeveloped acres in the oil and NGL area of the Mississippi Lime play in northwestern Oklahoma for $18.0 million from subsidiaries of Equal Energy, Ltd. (NYSE: EQU; TSX: EQU; “Equal”). The transaction was funded through borrowings under ARP’s revolving credit facility. Concurrent with the purchase of acreage, ARP and Equal entered into a participation and development agreement for future drilling in the Mississippi Lime play. ARP served as the drilling and completion operator, while Equal undertook production operations, including water disposal. In September 2012, ARP acquired Equal’s remaining 50% interest in the undeveloped acres, as well as approximately 8 MMcfed of net production in the Mississippi Lime region and salt water disposal infrastructure for $41.3 million, including $1.3 million related to certain post-closing adjustments. Both transactions were financed through borrowings under ARP’s revolving credit facility. As a result of ARP’s acquisition of Equal’s remaining interest in the undeveloped acres, the existing joint venture agreement between ARP and Equal in the Mississippi Lime position was terminated and all infrastructure associated with the assets, principally the salt water disposal system, is operated by ARP. | ||||||||||
Transferred Business AEI | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Acquisitions | NOTE 3 – ACQUISITION FROM ATLAS ENERGY, INC. | |||||||||
On February 17, 2011, the Partnership acquired certain producing natural gas and oil properties, the partnership management business and other assets (the “Transferred Business”) from the former owner of its general partner, Atlas Energy, Inc. (“AEI”), including the following exploration and production assets that were transferred to ARP on March 5, 2012: | ||||||||||
— | AEI’s investment management business which sponsors tax-advantaged direct investment natural gas and oil partnerships, through which ARP funds a portion of its natural gas and oil well drilling; | |||||||||
— | proved reserves located in the Appalachian Basin, the Niobrara formation in Colorado, the New Albany Shale of west central Indiana, the Antrim Shale of northern Michigan and the Chattanooga Shale of northeastern Tennessee; and | |||||||||
— | certain producing natural gas and oil properties, upon which ARP is the developer and producer. | |||||||||
In addition to the exploration and production assets, the Transferred Business also included all of the ownership interests in Atlas Energy GP, LLC, the Partnership’s general partner, and a direct and indirect ownership interest in Lightfoot. | ||||||||||
For the assets acquired and liabilities assumed, the Partnership issued approximately 23.4 million of its common limited partner units and paid $30.0 million in cash consideration. Based on the Partnership’s February 17, 2011 common unit closing price of $15.92, the common units issued to AEI were valued at approximately $372.2 million. Concurrent with the Partnership’s acquisition of the Transferred Business, AEI was sold to Chevron Corporation (NYSE: CVX) (“Chevron”). In connection with the transaction, the Partnership received $118.7 million with respect to a contractual cash transaction adjustment from AEI related to certain exploration and production liabilities assumed by the Partnership. Including the cash transaction adjustment, the net book value of the Transferred Business was approximately $522.9 million. Certain amounts included within the contractual cash transaction adjustment were subject to a reconciliation period with Chevron following the consummation of the transaction. Liabilities related to the cash transaction adjustment were assumed by ARP on March 5, 2012, as certain amounts included within the contractual cash transaction adjustment remained in dispute between the parties. During the year ended December 31, 2012, ARP recognized a $7.7 million charge on the Partnership’s consolidated combined statement of operations regarding its reconciliation process with Chevron, which was settled in October 2012. | ||||||||||
Concurrent with the Partnership’s acquisition of the Transferred Business on February 17, 2011, including assets and liabilities transferred to ARP on March 5, 2012, AEI completed its merger with Chevron, whereby AEI became a wholly owned subsidiary of Chevron. Also concurrent with the Partnership’s acquisition of the Transferred Business and immediately preceding AEI’s merger with Chevron, APL completed its sale to AEI of its 49% non-controlling interest in Laurel Mountain. APL received $409.5 million in cash, including adjustments based on certain capital contributions APL made to and distributions it received from the Laurel Mountain joint venture after January 1, 2011. APL retained the preferred distribution rights under the limited liability company agreement of the Laurel Mountain joint venture entitling APL to receive all payments made under the note receivable issued to Laurel Mountain by Williams Laurel Mountain, LLC in connection with the formation of the Laurel Mountain joint venture. | ||||||||||
Management of the Partnership determined that the acquisition of the Transferred Business constituted a transaction between entities under common control. As such, the Partnership recognized the assets acquired and liabilities assumed at historical carrying value at the date of acquisition, with the difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital on its consolidated balance sheet. The Partnership recognized a non-cash decrease of $261.0 million in partners’ capital on its consolidated balance sheet based on the excess net book value above the value of the consideration paid to AEI. The following table presents the historical carrying values of the assets acquired and liabilities assumed by the Partnership, including the effect of cash transaction adjustments, as of February 17, 2011 (in thousands): | ||||||||||
Cash | $ | 153,350 | ||||||||
Accounts receivable | 18,090 | |||||||||
Accounts receivable – affiliate | 45,682 | |||||||||
Prepaid expenses and other | 6,955 | |||||||||
Total current assets | 224,077 | |||||||||
Property, plant and equipment, net | 516,625 | |||||||||
Goodwill | 31,784 | |||||||||
Intangible assets, net | 2,107 | |||||||||
Other assets, net | 20,416 | |||||||||
Total long-term assets | 570,932 | |||||||||
Total assets acquired | $ | 795,009 | ||||||||
Accounts payable | $ | 59,202 | ||||||||
Net liabilities associated with drilling contracts | 47,929 | |||||||||
Accrued well completion costs | 39,552 | |||||||||
Current portion of derivative payable to Drilling Partnerships | 25,659 | |||||||||
Accrued liabilities | 25,283 | |||||||||
Total current liabilities | 197,625 | |||||||||
Long-term derivative payable to Drilling Partnerships | 31,719 | |||||||||
Asset retirement obligations | 42,791 | |||||||||
Total long-term liabilities | 74,510 | |||||||||
Total liabilities assumed | $ | 272,135 | ||||||||
Historical carrying value of net assets acquired | $ | 522,874 | ||||||||
The Partnership reflected the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which the Transferred Business was acquired. | ||||||||||
Acquisitions
Acquisitions | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
Business Combinations [Abstract] | ||||||||||
Acquisitions | NOTE 4 – ACQUISITIONS | |||||||||
ARP’s Rangely Acquisition | ||||||||||
On June 30, 2014, ARP completed an acquisition of a 25% non-operated net working interest in oil and natural gas liquids producing assets in the Rangely field in northwest Colorado from Merit Management Partners I, L.P., Merit Energy Partners III, L.P. and Merit Energy Company, LLC (collectively, “Merit Energy”) for approximately $409.4 million in cash, net of purchase price adjustments (the “Rangely Acquisition”). The purchase price was funded through borrowings under ARP’s revolving credit facility, the issuance of an additional $100.0 million of ARP’s 7.75% senior notes due 2021 (“7.75% ARP Senior Notes”) (see Note 9) and the issuance of 15,525,000 of ARP’s common limited partner units (see Note 15). The Rangely Acquisition had an effective date of April 1, 2014. The Partnership’s combined consolidated financial statements reflected the operating results of the acquired business commencing June 30, 2014 with the transaction closing. | ||||||||||
ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). In conjunction with the issuance of ARP’s common limited partner units associated with the acquisition, ARP recorded $11.6 million of transaction fees which were included within non-controlling interests at December 31, 2014 on the Partnership’s consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred. Due to the recent date of the acquisition, the accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as ARP continues to evaluate the facts and circumstances that existed as of the acquisition date. | ||||||||||
The following table presents the preliminary values assigned to the assets acquired and liabilities assumed in the acquisition, based on their estimated fair values at the date of the acquisition (in thousands): | ||||||||||
Assets: | ||||||||||
Prepaid expenses and other | 4,041 | |||||||||
Property, plant and equipment | 405,876 | |||||||||
Other assets, net | 2,888 | |||||||||
Total assets acquired | $ | 412,805 | ||||||||
Liabilities: | ||||||||||
Accrued liabilities | 2,117 | |||||||||
Asset retirement obligation | 1,305 | |||||||||
Total liabilities assumed | 3,422 | |||||||||
Net assets acquired | $ | 409,383 | ||||||||
Revenues and net income of $41.5 million and $18.8 million, respectively, have been included in the Partnership’s consolidated statement of operations related to the Rangely Acquisition for the year ended December 31, 2014. | ||||||||||
ARP’s EP Energy Acquisition | ||||||||||
On July 31, 2013, ARP completed an acquisition of assets from EP Energy E&P Company, L.P. (“EP Energy”) for approximately $709.6 million in cash, net of purchase price adjustments (the “EP Energy Acquisition”). ARP funded the purchase price through borrowings under its revolving credit facility, the issuance of its 9.25% senior notes due 2021 (“9.25% ARP Senior Notes”) (see Note 9), and the issuance of 14,950,000 ARP common limited partner units and 3,749,986 newly created ARP Class C convertible preferred units (see Note 15). The assets acquired by ARP in the EP Energy Acquisition included coal-bed methane producing natural gas assets in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming. The EP Energy Acquisition had an effective date of May 1, 2013. The accompanying combined consolidated financial statements reflect the operating results of the acquired business commencing July 31, 2013 with the transaction closing. | ||||||||||
ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). In conjunction with the issuance of ARP’s common limited partner units associated with the acquisition, ARP recorded $12.1 million of transaction fees which were included within non-controlling interests for the year ended December 31, 2013 on Partnership’s combined consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred. | ||||||||||
The following table presents the values assigned to the assets acquired and liabilities assumed in the EP Energy Acquisition, based on their estimated fair values at the date of the acquisition (in thousands): | ||||||||||
Assets: | ||||||||||
Prepaid expenses and other | $5,268 | |||||||||
Property, plant and equipment | 723,842 | |||||||||
Total current assets | $729,110 | |||||||||
Liabilities: | ||||||||||
Accounts payable | 2,747 | |||||||||
Asset retirement obligation | 16,728 | |||||||||
Total liabilities assumed | 19,475 | |||||||||
Net assets acquired | $709,635 | |||||||||
ARP’s DTE Acquisition | ||||||||||
On December 20, 2012, ARP completed the acquisition of DTE Gas Resources, L.L.C. from DTE Energy Company (NYSE: DTE; “DTE”) for $257.4 million (the “DTE Acquisition”). In connection with entering into a purchase agreement related to the DTE Acquisition, ARP issued approximately 7.9 million of its common limited partner units through a public offering in November 2012 for $174.5 million, which was used to partially repay amounts outstanding under its revolving credit facility prior to closing (see Note 15). The cash paid at closing was funded through $179.8 million of borrowings under ARP’s revolving credit facility and $77.6 million through borrowings under ARP’s then-existing term loan credit facility (see Note 9). | ||||||||||
ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). In conjunction with the issuance of common units associated with the acquisition, ARP recorded $0.2 million of transaction fees which were included within non-controlling interests for the year ended December 31, 2012 on the Partnership’s combined consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred. | ||||||||||
The following table presents the values assigned to the assets acquired and liabilities assumed in the DTE Acquisition, based on their estimated fair values at the date of the acquisition (in thousands): | ||||||||||
Assets: | ||||||||||
Accounts receivable | $10,721 | |||||||||
Prepaid expenses and other | 2,100 | |||||||||
Total current assets | 12,821 | |||||||||
Property, plant and equipment | 263,194 | |||||||||
Other assets, net | 273 | |||||||||
Total assets acquired | $276,288 | |||||||||
Liabilities: | ||||||||||
Accounts payable | $7,760 | |||||||||
Accrued liabilities | 2,910 | |||||||||
Total current liabilities | 10,670 | |||||||||
Asset retirement obligation and other | 8,169 | |||||||||
Total liabilities assumed | 18,839 | |||||||||
Net assets acquired | $257,449 | |||||||||
ARP’s Titan Acquisition | ||||||||||
On July 25, 2012, ARP completed the acquisition of Titan Operating, L.L.C. (“Titan”) in exchange for 3.8 million common units and 3.8 million newly created convertible Class B preferred units (which had an estimated collective value of $193.2 million, based upon the closing price of ARP’s publicly traded units as of the acquisition closing date), as well as $15.4 million in cash for closing adjustments (see Note 15). The cash paid at closing was funded through borrowings under ARP’s credit facility. The common units and preferred units were issued and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”) (see Note 15). ARP’s acquisition of Titan in exchange for 3.8 million ARP common units and 3.8 million newly created convertible ARP Class B preferred units represented a non-cash transaction during the year ended December 31, 2012. | ||||||||||
ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). In conjunction with its issuance of common and preferred limited partner units associated with the acquisition, ARP recorded $3.5 million of transaction fees, which were included within non-controlling interests for the year ended December 31, 2012 on the Partnership’s combined consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred. | ||||||||||
The following table presents the values assigned to the assets acquired and liabilities assumed in the acquisition of Titan, based on their estimated fair values at the date of the acquisition (in thousands): | ||||||||||
Assets: | ||||||||||
Cash and cash equivalents | $372 | |||||||||
Accounts receivable | 5,253 | |||||||||
Prepaid expenses and other | 131 | |||||||||
Total current assets | 5,756 | |||||||||
Property, plant and equipment | 208,491 | |||||||||
Other assets, net | 2,344 | |||||||||
Total assets acquired | $216,591 | |||||||||
Liabilities: | ||||||||||
Accounts payable | $676 | |||||||||
Revenue distribution payable | 3,091 | |||||||||
Accrued liabilities | 1,816 | |||||||||
Total current liabilities | 5,583 | |||||||||
Asset retirement obligation and other | 2,418 | |||||||||
Total liabilities assumed | 8,001 | |||||||||
Net assets acquired | $208,590 | |||||||||
ARP’s Carrizo Acquisition | ||||||||||
On April 30, 2012, ARP completed the acquisition of certain oil and natural gas assets from Carrizo Oil and Gas, Inc. (NASDAQ: CRZO; “Carrizo”) for approximately $187.0 million in cash (the “Carrizo Acquisition”). The purchase price was funded through borrowings under ARP’s credit facility and $119.5 million of net proceeds from the sale of 6.0 million of its common units at a negotiated purchase price per unit of $20.00, of which $5.0 million was purchased by certain executives of Atlas Energy. The common units were issued in a private transaction exempt from registration under Section 4(2) of the Securities Act (see Note 15). | ||||||||||
ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). In conjunction with the issuance of ARP’s common limited partner units associated with the acquisition, ARP recorded $1.2 million of transaction fees which were included within non-controlling interests for the year ended December 31, 2012 on the Partnership’s combined consolidated balance sheet. All other costs associated with ARP’s acquisition of assets were expensed as incurred. | ||||||||||
The following table presents the values assigned to the assets acquired and liabilities assumed in the Carrizo Acquisition, based on their estimated fair values at the date of the acquisition (in thousands): | ||||||||||
Assets: | ||||||||||
Property, plant and equipment | $190,946 | |||||||||
Liabilities: | ||||||||||
Asset retirement obligation | 3,903 | |||||||||
Net assets acquired | $187,043 | |||||||||
APL’s TEAK Acquisition. | ||||||||||
On May 7, 2013, APL completed the TEAK Acquisition for $974.7 million in cash, including final purchase price adjustments, less cash received. Through the TEAK Acquisition, APL acquired natural gas gathering and processing facilities in Texas, which included a 75% interest in T2 LaSalle Gathering Company L.L.C. (“T2 LaSalle”), a 50% interest in T2 Eagle Ford Gathering Company L.L.C. (“T2 Eagle Ford”), and a 50% interest in T2 EF Cogeneration Holdings L.L.C. (“T2 Co-Gen”) (collectively, the “T2 Joint Ventures”). | ||||||||||
APL funded the purchase price for the TEAK Acquisition through: | ||||||||||
— | the private placement of $400.0 million of its Class D Preferred Units for net proceeds of $397.7 million, including the Partnership’s general partner contribution of $8.2 million to maintain its 2.0% general partner interest in APL (see Note 15); | |||||||||
— | the sale of 11,845,000 APL common limited partner units in a public offering at a purchase price of $34.00 per unit, generating net proceeds of approximately $388.4 million, plus the Partnership’s general partner contribution of $8.3 million to maintain its 2.0% general partner interest in APL (see Note 15); and | |||||||||
— | borrowings under its senior secured revolving credit facility. | |||||||||
Subsequent to the closing of the TEAK Acquisition, on May 10, 2013, APL issued $400.0 million of its 4.75% unsecured senior notes due November 15, 2021 (“4.75 APL Senior Notes”) for net proceeds of $391.2 million, which were used to reduce the level of borrowings under its revolving credit facility, including amounts borrowed in connection with the TEAK Acquisition (see Note 9). | ||||||||||
APL accounted for this transaction under the acquisition method of accounting. Accordingly, APL evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). In conjunction with the issuance of APL’s common and preferred limited partner units associated with the acquisition, $16.6 million of transaction fees were included in the net proceeds recorded within non-controlling interests on the Partnership’s consolidated balance sheet for the year ended December 31, 2013. In conjunction with APL’s issuance of the 4.75% APL Senior Notes and an amendment to its revolving credit facility (see Note 9), APL recorded $9.7 million of transaction fees as deferred financing costs, which are included in other assets, net on the Partnership’s consolidated balance sheet at December 31, 2013. All other costs associated with the acquisition were expensed as incurred. | ||||||||||
The following table presents the final values assigned to the assets acquired and liabilities assumed in the TEAK Acquisition, based on their fair values as the date of the acquisition (in thousands): | ||||||||||
Assets: | ||||||||||
Cash | $ | 8,074 | ||||||||
Accounts receivable | 11,055 | |||||||||
Prepaid expenses and other | 1,626 | |||||||||
Total current assets | 20,755 | |||||||||
Property, plant and equipment | 197,683 | |||||||||
Intangible assets | 430,000 | |||||||||
Goodwill | 186,050 | |||||||||
Equity method investment in joint ventures | 184,327 | |||||||||
Total assets acquired | $ | 1,018,815 | ||||||||
Liabilities: | ||||||||||
Accounts payable and accrued liabilities | 34,995 | |||||||||
Other long term liabilities | 1,075 | |||||||||
Total liabilities assumed | 36,070 | |||||||||
Net assets acquired | 982,745 | |||||||||
Less cash received | (8,074 | ) | ||||||||
Net cash paid for acquisition | $ | 974,671 | ||||||||
APL’s Cardinal Acquisition | ||||||||||
On December 20, 2012, APL completed the Cardinal Acquisition for $598.9 million in cash, including final purchase price adjustments. The assets from this acquisition (the “APL Arkoma assets”) include gas gathering, processing and treating facilities in Arkansas, Louisiana, Oklahoma and Texas and a 60% interest in Centrahoma. The remaining 40% ownership interest in Centrahoma is held by MarkWest Energy Partners, L.P. (NYSE: MWE). APL funded the purchase price for the Cardinal Acquisition in part from the private placement of $175.0 million of its 6.625% senior unsecured notes due October 1, 2020 (“6.625% APL Senior Notes”) at a premium of 3.0%, for net proceeds of $176.5 million (see Note 9); and from the sale of 10,507,033 APL common limited partner units in a public offering at a purchase price of $31.00 per unit, generating net proceeds of approximately $319.3 million, including the Partnership’s contribution of $6.7 million to maintain its 2.0% general partner interest in APL (see Note 15). APL funded the remaining purchase price from its senior secured revolving credit facility (see Note 9). | ||||||||||
APL accounted for this transaction under the acquisition method of accounting. Accordingly, APL evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). | ||||||||||
The following table presents the values assigned to the assets acquired and liabilities assumed in the Cardinal Acquisition, based on their estimated fair values at the date of the acquisition, including the 40% non-controlling interest of Centrahoma held by MarkWest (in thousands): | ||||||||||
Assets: | ||||||||||
Cash | $ | 1,184 | ||||||||
Accounts receivable | 13,783 | |||||||||
Prepaid expenses and other | 1,289 | |||||||||
Property, plant and equipment | 246,787 | |||||||||
Intangible assets | 232,740 | |||||||||
Goodwill | 214,090 | |||||||||
Total assets acquired | 709,873 | |||||||||
Liabilities: | ||||||||||
Current portion of long-term debt | 341 | |||||||||
Accounts payable and accrued liabilities | 14,596 | |||||||||
Deferred tax liability, net | 35,353 | |||||||||
Long-term debt, less current portion | 604 | |||||||||
Total liabilities acquired | 50,894 | |||||||||
Non-controlling interest | 58,905 | |||||||||
Net assets acquired | 600,074 | |||||||||
Less cash received | (1,184 | ) | ||||||||
Net cash paid for acquisition | $ | 598,890 | ||||||||
The fair value of MarkWest’s 40% non-controlling interest in Centrahoma was based upon the purchase price allocated to the 60% controlling interest APL acquired using an income approach. This measurement uses significant inputs that are not observable in the market and thus represents a fair value measurement categorized within Level 3 of the fair value hierarchy. The 40% non-controlling interest in Centrahoma was reduced by a 5% adjustment for lack of control that market participants would consider when measuring its fair value. | ||||||||||
In 2013, subsequent to recording the final estimated fair values of the assets acquired and liabilities assumed in the Cardinal Acquisition, APL determined that a portion of goodwill recorded in connection with the acquisition was impaired (see Note 2 – Goodwill). | ||||||||||
Pro Forma Financial Information | ||||||||||
The following data presents pro forma revenues, net loss and basic and diluted net loss per unit for the Partnership as if the Rangely, EP Energy and TEAK acquisitions, including the related borrowings, net proceeds from the issuances of debt and issuances of common and preferred limited partner units had occurred on January 1, 2013. The Partnership prepared these pro forma unaudited financial results for comparative purposes only; they may not be indicative of the results that would have occurred if the Rangely, EP Energy and TEAK acquisitions and related offerings had occurred on January 1, 2013 or the results that will be attained in future periods (in thousands, except per share data; unaudited): | ||||||||||
Years Ended December 31, | ||||||||||
2014 | 2013 | |||||||||
Total revenues and other | $ | 3,714,704 | $ | 2,793,098 | ||||||
Net loss | (427,351 | ) | (141,776 | ) | ||||||
Net loss attributable to common limited partners | (181,455 | ) | (51,653 | ) | ||||||
Net loss attributable to common limited partners per unit: | ||||||||||
Basic and Diluted | $ | (3.50 | ) | $ | (1.01 | ) | ||||
Other Acquisitions | ||||||||||
On November 5, 2014, ARP and the Development Subsidiary completed an acquisition of oil and natural gas liquid interests in the Eagle Ford Shale in Atascosa County, Texas from Cima Resources, LLC and Cinco Resources, Inc. (together “Cinco”) for $339.2 million, net of purchase price adjustments (the “Eagle Ford Acquisition”). Approximately $179.5 million was paid in cash by ARP and $19.7 million was paid by the Development Subsidiary at closing, and approximately $140.0 million will be paid over the four quarters following closing. The deferred portion of the purchase price represents a non-cash transaction for statement of cash flow purposes during the year ended December 31, 2014. ARP will pay approximately $24.0 million of the deferred portion of the purchase price in three quarterly installments beginning March 31, 2015. The Development Subsidiary will pay approximately $116.0 million of the deferred portion purchase price in four quarterly installments following closing. ARP may pay up to $20.0 million of its deferred portion of the purchase price by issuing ARP’s 8.625% Class D cumulative redeemable perpetual preferred units (“Class D Preferred Units”) at a price of $25.00 per unit (see Note 13). In connection with the closing of the Eagle Ford Acquisition, ARP’s revolving credit facility was amended to increase the borrowing base to $900.0 million and to make certain amendments to allow for the deferred purchase payments (see Note 9). The Eagle Ford Acquisition had an effective date of July 1, 2014. The Partnership recorded $2.8 million of gains on mark-to-market derivatives in conjunction with the entering into derivative instruments upon signing the Eagle Ford Acquisition. | ||||||||||
On May 12, 2014, ARP completed the acquisition of certain assets from GeoMet, Inc. (“GeoMet”) (OTCQB: GMET) for approximately $97.9 million in cash, net of purchase price adjustments, with an effective date of January 1, 2014. The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia. | ||||||||||
On September 20, 2013, ARP completed the acquisition of certain assets from Norwood Natural Resources (“Norwood”) for $5.4 million (the “Norwood Acquisition”). The assets acquired included Norwood’s non-operating working interest in certain producing wells in the Barnett Shale. The Norwood Acquisition had an effective date of June 1, 2013. | ||||||||||
On July 31, 2013, the Partnership completed the acquisition of certain natural gas and oil producing assets in the Arkoma Basin from EP Energy for approximately $64.5 million, net of purchase price adjustments (the “Arkoma Acquisition”). The Arkoma Acquisition was funded with a portion of the proceeds from the issuance of the Partnership’s term loan facility (see Note 9). The Arkoma Acquisition had an effective date of May 1, 2013. | ||||||||||
In April 2012, ARP acquired a 50% interest in approximately 14,500 net undeveloped acres in the oil and NGL area of the Mississippi Lime play in northwestern Oklahoma for $18.0 million from subsidiaries of Equal Energy, Ltd. (NYSE: EQU; TSX: EQU; “Equal”). The transaction was funded through borrowings under ARP’s revolving credit facility. Concurrent with the purchase of acreage, ARP and Equal entered into a participation and development agreement for future drilling in the Mississippi Lime play. ARP served as the drilling and completion operator, while Equal undertook production operations, including water disposal. In September 2012, ARP acquired Equal’s remaining 50% interest in the undeveloped acres, as well as approximately 8 MMcfed of net production in the Mississippi Lime region and salt water disposal infrastructure for $41.3 million, including $1.3 million related to certain post-closing adjustments. Both transactions were financed through borrowings under ARP’s revolving credit facility. As a result of ARP’s acquisition of Equal’s remaining interest in the undeveloped acres, the existing joint venture agreement between ARP and Equal in the Mississippi Lime position was terminated and all infrastructure associated with the assets, principally the salt water disposal system, is operated by ARP. |
APL_Equity_Method_Investments
APL Equity Method Investments | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
Equity Method Investments And Joint Ventures [Abstract] | ||||||||||
APL Equity Method Investments | NOTE 5 — APL EQUITY METHOD INVESTMENTS | |||||||||
West Texas LPG Pipeline Limited Partnership | ||||||||||
On May 14, 2014, APL completed the sale of two subsidiaries, which held an aggregate 20% interest in WTLPG, to a subsidiary of Martin Midstream Partners LP (NYSE: MMLP). APL received $131.0 million in proceeds, net of selling costs and final working capital adjustments, which were used to pay down APL’s revolving credit facility (see Note 9). As a result of the sale, APL recorded a $47.8 million gain on asset dispositions, which is included in the Partnership’s consolidated statements of operations for the year ended December 31, 2014. | ||||||||||
WTLPG owns a common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. Prior to the sale of WTLPG, APL accounted for its subsidiaries’ ownership interest in WTLPG under the equity method of accounting, with recognition of income of WTLPG as equity income in joint ventures on RemainCo’s consolidated statements of operations. | ||||||||||
T2 Joint Ventures | ||||||||||
On May 7, 2013, APL acquired the T2 Joint Ventures as part of the TEAK Acquisition (see Note 4). The T2 Joint Ventures are operated by a subsidiary of Southcross Holdings, L.P. (“Southcross”), the investor owning the remaining interests. The T2 Joint Ventures were formed to provide services for the benefit of the joint interest owners and have capacity lease agreements with the joint interest owners, which cover the costs of operations of the T2 Joint Ventures. | ||||||||||
APL evaluated whether the T2 Joint Ventures should be subject to consolidation. The T2 Joint Ventures do meet the qualifications of a VIE, but APL does not meet the qualifications as the primary beneficiary. Even though APL owns a 50% or greater interest in the T2 Joint Ventures, it does not have controlling financial interests in these entities. Since APL shares equal management rights with Southcross and Southcross is the operator of the T2 Joint Ventures, APL determined that it is not the primary beneficiary of the VIEs and should not consolidate the T2 Joint Ventures. APL accounts for its investment in the T2 Joint Ventures under the equity method, since APL does not have a controlling financial interest, but does have a significant influence. APL’s maximum exposure to loss as a result of its involvement with the T2 Joint Ventures includes its equity investment, any additional capital contribution commitments and APL’s share of any approved operating expenses incurred by the VIEs. | ||||||||||
The following tables present the values of APL’s equity method investments as of December 31, 2014 and 2013 and equity income (loss) in joint ventures for the years ended December 31, 2014 and 2013 (in thousands): | ||||||||||
December 31, | December 31, | |||||||||
2014 | 2013 | |||||||||
WTLPG | $ | - | $ | 85,790 | ||||||
T2 LaSalle | 55,911 | 50,534 | ||||||||
T2 Eagle Ford | 109,517 | 97,437 | ||||||||
T2 EF Co-Gen | 11,784 | 14,540 | ||||||||
Equity method investment in joint ventures | $ | 177,212 | $ | 248,301 | ||||||
Years Ended December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
WTLPG | 2,611 | 4,988 | 6,323 | |||||||
T2 LaSalle | (4,271 | ) | (3,127 | ) | - | |||||
T2 Eagle Ford | (8,754 | ) | (4,408 | ) | - | |||||
T2 EF Co-Gen | (3,593 | ) | (2,189 | ) | - | |||||
Equity income (loss) in joint ventures | $ | (14,007 | ) | $ | (4,736 | ) | $ | 6,323 | ||
Property_Plant_and_Equipment
Property, Plant and Equipment | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Property Plant And Equipment [Abstract] | |||||||||||||
Property, Plant and Equipment | NOTE 6 — PROPERTY, PLANT AND EQUIPMENT | ||||||||||||
The following is a summary of property, plant and equipment at the dates indicated (in thousands): | |||||||||||||
Estimated | |||||||||||||
December 31, | Useful Lives | ||||||||||||
2014 | 2013 | in Years | |||||||||||
Natural gas and oil properties: | |||||||||||||
Proved properties: | |||||||||||||
Leasehold interests | $ | 535,893 | $ | 322,217 | |||||||||
Pre-development costs | 7,378 | 4,367 | |||||||||||
Wells and related equipment | 3,096,562 | 2,231,213 | |||||||||||
Total proved properties | 3,639,833 | 2,557,797 | |||||||||||
Unproved properties | 217,321 | 211,851 | |||||||||||
Support equipment | 37,359 | 23,258 | |||||||||||
Total natural gas and oil properties | 3,894,513 | 2,792,906 | |||||||||||
Pipelines, processing and compression facilities | 3,576,551 | 2,926,134 | 2–40 | ||||||||||
Rights of way | 209,140 | 203,966 | 20–40 | ||||||||||
Land, buildings and improvements | 19,607 | 30,216 | 3–40 | ||||||||||
Other | 47,846 | 36,752 | 3–10 | ||||||||||
7,747,657 | 5,989,974 | ||||||||||||
Less – accumulated depreciation, depletion and | (2,078,395 | ) | (1,079,099 | ) | |||||||||
amortization | |||||||||||||
$ | 5,669,262 | $ | 4,910,875 | ||||||||||
During year ended December 31, 2014, the Partnership and its subsidiaries recognized $45.5 million of gain on asset sales and disposal, primarily related to APL’s gain on the sale of WTLPG, partially offset by ARP’s loss on the sale of producing wells in the Niobrara Shale in connection with the settlement of a third party farm out agreement. During the year ended December 31, 2013, the Partnership and its subsidiaries recognized $2.5 million of loss on asset sales and disposal, of which $1.0 million pertained to ARP, primarily pertaining to ARP’s loss on the sale of its Antrim assets. During the year ended December 31, 2013, APL recognized $1.5 million of loss on asset sales and disposal primarily related to its decision to not pursue a project to construct pipelines in an area where acquired rights of way had expired. During the year ended December 31, 2012, ARP recognized a $7.0 million loss on asset sales and disposal pertaining to its decision to terminate a farm-out agreement with a third party for well drilling in the South Knox area of the New Albany Shale that was originally entered into in 2010. The farm-out agreement contained certain well drilling targets for ARP to maintain ownership of the South Knox processing plant, which ARP’s management decided in 2012 to not achieve due to the then current natural gas price environment. As a result, ARP forfeited its interest in the processing plant and related properties and recorded a loss related to the net book values of those assets during the year ended December 31, 2012. | |||||||||||||
During the year ended December 31, 2014, the Partnership recognized $562.6 million of asset impairment related to oil and gas properties within property, plant and equipment, net on the Partnership’s consolidated balance sheet primarily for ARP’s Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. Asset impairments for the year ended December 31, 2014 principally resulted from the decline in forward commodity prices during the fourth quarter of 2014 through the impairment testing date in January 2015. During the year ended December 31, 2013, ARP recognized $38.0 million of asset impairments related to its gas and oil properties within property, plant and equipment, net on the Partnership’s consolidated balance sheet primarily for its shallow natural gas wells in the New Albany Shale and unproved acreage in the Chattanooga and New Albany Shales. During the year ended December 31, 2012, ARP recognized $9.5 million of asset impairments related to its gas and oil properties within property, plant and equipment, net on the Partnership’s consolidated balance sheet for ARP’s shallow natural gas wells in the Antrim and Niobrara shales. | |||||||||||||
These impairments related to the carrying amounts of gas and oil properties being in excess of the Development Subsidiary’s and ARP’s estimates of their fair values at December 31, 2014, 2013 and 2012 and ARP’s intention not to drill on certain expiring unproved acreage. The estimates of fair values of these gas and oil properties were impacted by, among other factors, the deterioration of commodity prices at the date of measurement. | |||||||||||||
During the years ended December 31, 2014 and 2013, the Partnership recognized $39.7 million and $8.7 million, respectively, of non-cash property, plant and equipment additions, which were included within the changes in accounts payable and accrued liabilities on the Partnership’s consolidated statements of cash flows. | |||||||||||||
Other_Assets
Other Assets | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Other Assets Noncurrent Disclosure [Abstract] | |||||||||
Other Assets | NOTE 7 — OTHER ASSETS | ||||||||
The following is a summary of other assets at the dates indicated (in thousands): | |||||||||
December 31, | |||||||||
2014 | 2013 | ||||||||
Deferred financing costs, net of accumulated amortization of $62,008 and $43,702 at December 31, 2014 and 2013, respectively | $ | 86,692 | $ | 86,617 | |||||
Investment in Lightfoot | 21,123 | 21,454 | |||||||
Rabbi trust | 3,925 | 3,705 | |||||||
Security deposits | 2,467 | 5,631 | |||||||
ARP notes receivable | 3,866 | 3,978 | |||||||
Other | 9,848 | 3,287 | |||||||
$ | 127,921 | $ | 124,672 | ||||||
Deferred financing costs. Deferred financing costs are recorded at cost and amortized over the terms of the respective debt agreements (see Note 9). Amortization expense of the Partnership and its subsidiaries’ deferred financing costs was $17.7 million, $14.4 million and $6.7 million for the years ended December 31, 2014, 2013 and 2012, respectively, which was recorded within interest expense on the Partnership’s consolidated statements of operations. During the year ended December 31, 2014, ARP recognized $0.6 million for accelerated amortization of deferred financing costs associated with a reduction of the borrowing base under its revolving credit facility. During the year ended December 31, 2013, ARP recognized $3.2 million for accelerated amortization of deferred financing costs associated with the retirement of a portion of its term loan facility and a portion of the outstanding indebtedness under its revolving credit facility with a portion of the proceeds from its issuance of senior unsecured notes due 2021 (“7.75% ARP Senior Notes”) (see Note 9). There was no accelerated amortization of deferred financing costs for ARP during the year ended December 31, 2012. | |||||||||
During the year ended December 31, 2013, APL recorded $5.3 million of accelerated amortization of deferred financing costs related to the retirement of its 8.75% unsecured senior notes due 2018 (“8.75% APL Senior Notes”) to loss on early extinguishment of debt on the Partnership’s consolidated statement of operations (see Note 9). There was no accelerated amortization of deferred financing costs for APL during the years ended December 31, 2014 and 2012. | |||||||||
ARP notes receivable. At December 31, 2014 and 2013, ARP had notes receivable with certain investors of its Drilling Partnerships, which were included within other assets, net on the Partnership’s consolidated balance sheet. The notes have a maturity date of March 31, 2022, and a 2.25% per annum interest rate. The maturity date of the notes can be extended to March 31, 2027, subject to certain closing conditions, including an extension fee of 1.0% of the outstanding principal balance. For each of the years ended December 31, 2014 and 2013, $0.1 million, respectively, of interest income, was recognized within other, net on the Partnership’s consolidated statement of operations. There was no interest income recognized for the year ended December 31, 2012. At December 31, 2014 and 2013, ARP recorded no allowance for credit losses within the Partnership’s consolidated balance sheets based upon payment history and ongoing credit evaluations associated with the ARP notes receivable. | |||||||||
Investment in Lightfoot. At December 31, 2014, the Partnership owned an approximate 12.0% interest in Lightfoot L.P. and an approximate 15.9% interest in Lightfoot G.P., the general partner of Lightfoot L.P., an entity for which Jonathan Cohen, Executive Chairman of the General Partner’s board of directors, is the Chairman of the Board. Lightfoot L.P. focuses its investments primarily on incubating new MLPs and providing capital to existing MLPs in need of additional equity or structured debt. The Partnership accounts for its investment in Lightfoot under the equity method of accounting. During the years ended December 31, 2014, 2013 and 2012, the Partnership recognized equity income of approximately $1.1 million, $2.6 million and $1.5 million, respectively, within other, net on the Partnership’s consolidated statements of operations. During the years ended December 31, 2014, 2013 and 2012, the Partnership received net cash distributions of $1.7 million, $1.0 million and $0.9 million, respectively. | |||||||||
On November 6, 2013, Arc Logistics Partners, L.P. (“ARCX”), an MLP, owned and controlled by Lightfoot, which is involved in terminalling, storage, throughput and transloading of crude oil and petroleum products, began trading publicly on the NYSE under the ticker symbol “ARCX”. | |||||||||
Asset_Retirement_Obligations
Asset Retirement Obligations | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Asset Retirement Obligation Disclosure [Abstract] | |||||||||||||
Asset Retirement Obligations | NOTE 8 — ASSET RETIREMENT OBLIGATIONS | ||||||||||||
The Partnership and ARP recognized an estimated liability for the plugging and abandonment of their respective gas and oil wells and related facilities. The Partnership and ARP also recognized a liability for their respective future asset retirement obligations where a reasonable estimate of the fair value of that liability could be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership and its subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization. | |||||||||||||
The estimated liability for asset retirement obligations was based on historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability was discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. The Partnership and ARP have no assets legally restricted for purposes of settling asset retirement obligations. Except for the Partnership and ARP’s gas and oil properties, the Partnership and its subsidiaries determined that there were no other material retirement obligations associated with tangible long-lived assets. | |||||||||||||
ARP proportionately consolidates its ownership interest of the asset retirement obligations of its Drilling Partnerships. At December 31, 2014, the Drilling Partnerships had $47.6 million of aggregate asset retirement obligation liabilities recognized on their combined balance sheets allocable to the limited partners, exclusive of ARP’s proportional interest in such liabilities. Under the terms of the respective partnership agreements, ARP maintains the right to retain a portion or all of the distributions to the limited partners of its Drilling Partnerships to cover the limited partners’ share of the plugging and abandonment costs up to a specified amount per month. As of December 31, 2014, ARP has withheld approximately $1.6 million of limited partner distributions related to the asset retirement obligations of certain Drilling Partnerships. ARP’s historical practice and continued intention is to retain distributions from the limited partners as the wells within each Drilling Partnership near the end of their useful life. On a partnership-by-partnership basis, ARP assesses its right to withhold amounts related to plugging and abandonment costs based on several factors including commodity price trends, the natural decline in the production of the wells, and current and future costs. Generally, ARP’s intention is to retain distributions from the limited partners as the fair value of the future cash flows of the limited partners’ interest approaches the fair value of the future plugging and abandonment cost. Upon ARP’s decision to retain all future distributions to the limited partners of its Drilling Partnerships, ARP will assume the related asset retirement obligations of the limited partners. | |||||||||||||
A reconciliation of the Partnership and ARP’s liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands): | |||||||||||||
Years Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Asset retirement obligations, beginning of | $ | 91,214 | $ | 64,794 | $ | 45,779 | |||||||
year | |||||||||||||
Liabilities incurred | 10,674 | 23,129 | 16,568 | ||||||||||
Liabilities settled | (1,664 | ) | (1,188 | ) | (546 | ) | |||||||
Accretion expense | 5,759 | 4,479 | 2,993 | ||||||||||
Revisions | 2,118 | - | - | ||||||||||
Asset retirement obligations, end of year | $ | 108,101 | $ | 91,214 | $ | 64,794 | |||||||
The above accretion expense was included in depreciation, depletion and amortization in the Partnership’s consolidated statements of operations. During the years ended December 31, 2014 and 2013, the Partnership incurred $0.1 million and $1.3 million, respectively, of future plugging and abandonment costs within purchase accounting related to the acquisition it consummated during the period. During the years ended December 31, 2014, 2013 and 2012, ARP incurred $7.0 million, $16.7 million and $15.6 million, respectively, of future plugging and abandonment liabilities within purchase accounting related to the acquisitions it consummated during the period. The Partnership did not incur any future plugging and abandonment costs related to acquisitions during the year ended December 31, 2012 (see Note 4). | |||||||||||||
Debt
Debt | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Debt Disclosure [Abstract] | |||||||||
Debt | NOTE 9 — DEBT | ||||||||
Total debt consists of the following at the dates indicated (in thousands): | |||||||||
December 31, | |||||||||
2014 | 2013 | ||||||||
Term loan facility | $ | 237,000 | $ | 239,400 | |||||
Revolving credit facility | — | — | |||||||
ARP revolving credit facility | 696,000 | 419,000 | |||||||
ARP 7.75% Senior Notes – due 2021 | 374,544 | 275,000 | |||||||
ARP 9.25% Senior Notes – due 2021 | 323,916 | 248,334 | |||||||
APL revolving credit facility | 385,000 | 152,000 | |||||||
APL 6.625% Senior Notes – due 2020 | 503,881 | 504,556 | |||||||
APL 5.875% Senior Notes – due 2023 | 650,000 | 650,000 | |||||||
APL 4.750% Senior Notes – due 2021 | 400,000 | 400,000 | |||||||
APL capital leases | 229 | 754 | |||||||
Total debt | 3,570,570 | 2,889,044 | |||||||
Less current maturities | (2,624 | ) | (2,924 | ) | |||||
Total long-term debt | $ | 3,567,946 | $ | 2,886,120 | |||||
Partnership’s Term Loan Facility. | |||||||||
On July 31, 2013, in connection with the Arkoma Acquisition (see Note 4), the Partnership entered into a $240.0 million secured term facility with a group of outside investors (the “Term Facility”). At December 31, 2014, $237.0 million was outstanding under the Term Facility. The Term Facility has a maturity date of July 31, 2019. Borrowings under the Term Facility bear interest, at the Partnership’s election at either an adjusted LIBOR rate plus an applicable margin of 5.50% per annum or the alternate base rate (as defined in the Term Facility) (“ABR”) plus an applicable margin of 4.50% per annum. Interest is generally payable quarterly for ABR loans and, for LIBOR loans at the interest periods selected by the Partnership. The Partnership is required to repay principal at the rate of $0.6 million per quarter commencing December 31, 2013 and continuing until the maturity date when the remaining balance is due. At December 31, 2014, the weighted average interest rate on outstanding borrowings under the Term Facility was 6.5%. | |||||||||
The Term Facility contains customary covenants, similar to those in the Partnership’s credit facility, that limit the Partnership’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of the Partnership’s assets. The Term Facility also contains covenants that require the Partnership to maintain a ratio of Total Funded Debt (as defined in the Term Facility) to EBITDA (as defined in the Term Facility), calculated over a period of four consecutive fiscal quarters, of not greater than 4.5 to 1.0 as of the last day of each of the quarters ending on or before September 30, 2014; 4.0 to 1.0 as of the last day of each of the quarters ending on or before September 30, 2015; and 3.5 to 1.0 for the last day of each of the quarters thereafter. At December 31, 2014, the Partnership was in compliance with these covenants. The events which constitute events of default are also customary for credit facilities of this nature, including payment defaults, breaches of representations, warranties or covenants, defaults in the payment of other indebtedness over a specified threshold, insolvency and change of control. | |||||||||
The Partnership’s obligations under the Term Facility are secured by first priority security interests in substantially all of its assets, including all of its ownership interests in its material subsidiaries and its ownership interests in APL and ARP. Additionally, the Partnership’s obligations under its Term Facility are guaranteed by its material wholly-owned subsidiaries (excluding Atlas Pipeline Partners GP, LLC) and may be guaranteed by future subsidiaries. Any of the Partnership’s subsidiaries, other than the subsidiary guarantors, are minor. The Term Facility is subject to an intercreditor agreement, which provides for certain rights and procedures, between the lenders under the Term Facility and the Partnership’s credit facility, with respect to enforcement of rights, collateral and application of payment proceeds. | |||||||||
Partnership’s Revolving Credit Facility | |||||||||
On July 31, 2013, in connection with the Arkoma Acquisition (see Note 4), the Partnership amended its credit facility with a syndicate of banks that matures on July 31, 2018. The credit facility has a maximum credit amount of $50.0 million, of which up to $5.0 million may be in the form of standby letters of credit. At December 31, 2014, no amounts were outstanding under the credit facility. The Partnership’s obligations under the credit facility are secured by first priority security interests in substantially all of its assets, including all of its ownership interests in its material subsidiaries and its ownership interests in APL and ARP. Additionally, the Partnership’s obligations under the credit facility are guaranteed by its material wholly-owned subsidiaries (excluding Atlas Pipeline Partners GP, LLC) and may be guaranteed by future subsidiaries. Any of the Partnership’s subsidiaries, other than the subsidiary guarantors, are minor. At the Partnership’s election, interest on borrowings under the credit agreement is determined by reference to either an adjusted LIBOR rate plus an applicable margin of 5.50% per year or the ABR plus an applicable margin of 4.50% per year. Interest is generally payable quarterly for ABR loans and at the interest payment periods selected by the Partnership for LIBOR loans. The Partnership is required to pay a fee between 0.5% and 0.625% per annum on the unused portion of the commitments under the credit facility. | |||||||||
The credit facility contains customary covenants that limit the Partnership’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of the Partnership’s assets. The credit facility also contains covenants the same as those in the Partnership’s Term Facility with respect to the required ratio of Total Funded Debt (as defined in the credit facility) to EBITDA (as defined in the credit facility). At December 31, 2014, the Partnership was in compliance with these covenants. Based on the definition in the Partnership’s Term Facility and credit facility, the Partnership’s ratio of Total Funded Debt to EBITDA was 2.0 to 1.0. | |||||||||
The credit facility is subject to an intercreditor agreement as described above under the “Partnership’s Term Loan Facility”. | |||||||||
At December 31, 2014, the Partnership has not guaranteed any of ARP’s or APL’s debt obligations. | |||||||||
ARP’s Credit Facility | |||||||||
On November 24, 2014, ARP entered into a Fifth Amendment to its Second Amended and Restated Credit Agreement dated July 31, 2013 with Wells Fargo Bank National Association, as administrative agent, and the lenders party thereto, among ARP as borrower, the administrative agent and the lenders party thereto (the “ARP Credit Agreement”). The ARP Credit Agreement provides for a senior secured revolving credit facility with a syndicate of banks with a current borrowing base of $900.0 million and a maximum facility amount of $1.5 billion scheduled to mature in July 2018. | |||||||||
The Fifth Amendment was entered into in connection with the previously announced restructuring of ARP’s general partner and the sale of ATLS and its midstream assets (see Note 19). Among other things, the Fifth Amendment amended several definitions for the purpose of ensuring that the sale does not result in a Change of Control or Event of Default as defined in the ARP Credit Agreement. | |||||||||
On September 24, 2014, in connection with its Eagle Ford Acquisition (see Note 4), ARP entered into a fourth amendment to the ARP Credit Agreement. In connection with the closing of the Eagle Ford Acquisition, the borrowing base under ARP’s revolving credit facility was increased from $825.0 million to $900.0 million. The fourth amendment amended the ARP Credit Agreement to permit the guarantee by ARP of certain deferred purchase price obligations and contingent indemnity obligations in connection with the Eagle Ford Acquisition, and, with certain constraints, to permit ARP and its subsidiaries to enter into certain derivative instruments related to the producing wells to be acquired in the Eagle Ford Acquisition. | |||||||||
On June 30, 2014, in connection with the Rangely Acquisition (see Note 4), ARP entered into a third amendment to the ARP Credit Agreement. Among other things, pursuant to the third amendment: | |||||||||
· | the borrowing base was increased to $825.0 million; | ||||||||
· | if the borrowing base utilization is less than 25%, ARP will incur the applicable margin on Eurodollar loans of 1.50%, the applicable margin on alternative base rate loans of 0.50% and a commitment fee rate of 0.375%; and | ||||||||
· | the maximum ratio of Total Funded Debt to EBITDA was revised to be (i) 4.50 to 1.0 as of the last day of the quarters ended on June 30, 2014, September 30, 2014 and December 31, 2014, (ii) 4.25 to 1.0 as of the last day of the quarter ending on March 31, 2015 and (iii) 4.00 to 1.0 as of the last day of each quarter thereafter. | ||||||||
ARP’s borrowing base is scheduled for semi-annual redeterminations on May 1 and November 1 of each year. At December 31, 2014, $696.0 million was outstanding under the credit facility. Up to $20.0 million of the revolving credit facility may be in the form of standby letters of credit, of which $4.4 million was outstanding at December 31, 2014. ARP’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by certain of ARP’s material subsidiaries, and any non-guarantor subsidiaries of ARP are minor. Borrowings under the credit facility bear interest, at ARP’s election, at either an adjusted LIBOR rate plus an applicable margin between 1.50% and 2.75% per annum or the base rate (which is the higher of the bank’s prime rate, the Federal funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 0.50% and 1.75% per annum. ARP is also required to pay a fee on the unused portion of the borrowing base at a rate of 0.375% per annum if less than 50% of the borrowing base is utilized and 0.5% if 50% or more of the borrowing base is utilized, which is included within interest expense on the Partnership’s consolidated statements of operations. At December 31, 2014, the weighted average interest rate on outstanding borrowings under the credit facility was 2.9%. | |||||||||
The ARP Credit Agreement contains customary covenants that limit ARP’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. ARP was in compliance with these covenants as of December 31, 2014. The ARP Credit Agreement also requires ARP to maintain a ratio of Total Funded Debt (as defined in the ARP Credit Agreement) to EBITDA (as defined in the ARP Credit Agreement) (actual or annualized, as applicable), calculated over a period of four consecutive fiscal quarters, of not greater than 4.50 to 1.0 as of the last day of the quarters ended on June 30, 2014, September 30, 2014 and December 31, 2014, 4.25 to 1.0 as of the last day of the quarter ending March 31, 2015, and 4.00 to 1.0 as of the last day of fiscal quarters ending thereafter, and a ratio of current assets (as defined in the ARP Credit Agreement) to current liabilities (as defined in the ARP Credit Agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter. Based on the definitions contained in the ARP Credit Agreement, at December 31, 2014, ARP’s ratio of current assets to current liabilities was 1.2 to 1.0, and its ratio of Total Funded Debt to EBITDA was 3.6 to 1.0. | |||||||||
On February 23, 2015, ARP entered into a Sixth Amendment to the ARP Credit Agreement (the “Sixth Amendment”) and a Second Lien Credit Agreement (the “Second Lien Credit Agreement”) (see Note 19). | |||||||||
ARP Senior Notes | |||||||||
At December 31, 2014, ARP had $374.5 million outstanding of its 7.75% senior unsecured notes due 2021 (“7.75% ARP Senior Notes”), including $100.0 million of such notes issued in a private placement transaction on June 2, 2014 at an offering price of 99.5% of par value, yielding net proceeds of approximately $97.4 million. The net proceeds were used to partially fund the Rangely Acquisition (see Note 4). The 7.75% ARP Senior Notes were presented net of a $0.5 million unamortized discount as of December 31, 2014. Interest on the 7.75% ARP Senior Notes is payable semi-annually on January 15 and July 15. At any time prior to January 15, 2016, the 7.75% ARP Senior Notes are redeemable for up to 35% of the outstanding principal amount with the net cash proceeds of equity offerings at the redemption price of 107.75%. The 7.75% ARP Senior Notes are also subject to repurchase at a price equal to 101% of the principal amount, plus accrued and unpaid interest, upon a change of control. At any time prior to January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price as defined in the governing indenture, plus accrued and unpaid interest and additional interest, if any. On and after January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price of 103.875%, decreasing to 101.938% on January 15, 2018 and 100% on January 15, 2019. | |||||||||
ARP entered into registration rights agreements with respect to its 7.75% ARP Senior Notes. Under the registration rights agreements, ARP agreed to (a) file exchange offer registration statements with the SEC to exchange the privately issued notes for registered notes, (b) cause the exchange offer for the $275.0 million of 7.75% ARP Senior Notes issued on January 23, 2013 to be consummated not later than 365 days after the issuance of such notes and (c) cause the exchange offer for the $100.0 million of 7.75% ARP Senior Notes issued on June 2, 2014 to be consummated not later than 270 days after the issuance of such notes. A registration statement relating to the exchange offer for the $275.0 million of 7.75% ARP Senior Notes issued January 23, 2013 was declared effective on December 2, 2013, and the exchange offer for such notes was completed on January 2, 2014. A registration statement relating to the exchange offer for the $100.0 million of 7.75% ARP Senior Notes issued June 2, 2014 was declared effective on October 17, 2014 and the exchange offer for such notes was completed on November 18, 2014. | |||||||||
At December 31, 2014, ARP had $323.9 million outstanding of its 9.25% senior unsecured notes due 2021 (“9.25% ARP Senior Notes”), including $75.0 million of such notes issued in a private placement transaction on October 14, 2014 at an offering price of 100.5% of par value, which yielded net proceeds of approximately $73.6 million. The 9.25% ARP Senior Notes issued in October 2014 were presented net of a $0.4 million unamortized premium as of December 31, 2014. The 9.25% ARP Senior Notes issued in July 2013 were presented net of a $1.5 million unamortized discount as of December 31, 2014. ARP used the net proceeds from this offering to fund a portion of its Eagle Ford Acquisition (see Note 4). Interest on the 9.25% ARP Senior Notes is payable semi-annually on February 15 and August 15. At any time on or after August 15, 2017, ARP may redeem some or all of the 9.25% ARP Senior Notes at a redemption price of 104.625%. On or after August 15, 2018, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 102.313% and on or after August 15, 2019, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 100.0%. In addition, at any time prior to August 15, 2016, ARP may redeem up to 35% of the 9.25% ARP Senior Notes with the proceeds received from certain equity offerings at a redemption price of 109.250%. Under certain conditions, including if ARP sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, ARP must offer to repurchase the 9.25% ARP Senior Notes. | |||||||||
In connection with the issuance of the $75.0 million of 9.25% ARP Senior Notes on October 14, 2014, ARP entered into a registration rights agreement whereby ARP agreed to (a) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated not later than 270 days after the issuance of the 9.25% ARP Senior Notes. Under certain circumstances, in lieu of, or in addition to, a registered exchange offer, ARP has agreed to file a shelf registration statement with respect to the 9.25% ARP Senior Notes. If ARP fails to comply with its obligations to register the 9.25% ARP Senior Notes within the specified time period, ARP will be subject to additional interest, up to 1% per annum, until such time that the exchange offer is consummated or the shelf registration statement is declared effective, as applicable. | |||||||||
In connection with the issuance of the $250.0 million of 9.25% ARP Senior Notes on July 30, 2013, ARP entered into a registration rights agreement, whereby it agreed to (a) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated by July 30, 2014. On March 28, 2014, the registration statement relating to the exchange offer for the 9.25% ARP Senior Notes was declared effective, and the exchange offer was completed on April 29, 2014. | |||||||||
The 7.75% ARP Senior Notes and 9.25% ARP Senior Notes are guaranteed by certain of ARP’s material subsidiaries. The guarantees under the 7.75% ARP Senior Notes and 9.25% ARP Senior Notes are full and unconditional and joint and several and any subsidiaries of ARP, other than the subsidiary guarantors, are minor. There are no restrictions on ARP’s ability to obtain cash or any other distributions of funds from the guarantor subsidiaries. | |||||||||
The indentures governing the 7.75% ARP Senior Notes and 9.25% ARP Senior Notes contain covenants, including limitations of ARP’s ability to incur certain liens, incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase, or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of ARP’s assets. ARP was in compliance with these covenants as of December 31, 2014. | |||||||||
APL Credit Facility | |||||||||
At December 31, 2014, APL had an $800.0 million senior secured revolving credit facility with a syndicate of banks that matures in August 2019. Borrowings under the revolving credit facility bear interest, at APL’s option, at either (1) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) the LIBOR rate plus 1.0%, or (2) the LIBOR rate for the applicable period (each plus the applicable margin). The weighted average interest rate for borrowings on the revolving credit facility, at December 31, 2014, was 2.7%. Up to $50.0 million of the revolving credit facility may be utilized for letters of credit, of which $4.2 million was outstanding at December 31, 2014. These outstanding letters of credit amounts were not reflected as borrowings on the Partnership’s consolidated balance sheets. At December 31, 2014, APL had $410.8 million of remaining committed capacity under its revolving credit facility. | |||||||||
Borrowings under the revolving credit facility are secured by (i) a lien on and security interest in all the Partnership’s property and that of its subsidiaries, except for the assets owned by Atlas Pipeline Mid-Continent WestOk, LLC (“WestOK LLC”) and Atlas Pipeline Mid-Continent WestTex, LLC (“WestTX LLC”), entities in which APL has 95% interests, and Centrahoma, in which APL has a 60% interest; and their respective subsidiaries; and (ii) by the guaranty of each of APL’s consolidated subsidiaries other than the joint venture companies. The revolving credit facility contains customary covenants, including requirements that APL maintain certain financial thresholds and restrictions on APL’s ability to (1) incur additional indebtedness, (2) make certain acquisitions, loans or investments, (3) make distribution payments to its unitholders if an event of default exists, or (4) enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries, without approval of the lenders. APL is unable to borrow under its revolving credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to its partnership agreement. | |||||||||
The events that constitute an event of default for the revolving credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against APL in excess of a specified amount, and a change of control of its general partner. | |||||||||
On August 28, 2014, APL entered into a Second Amended and Restated Credit Agreement (the “Revised APL Credit Agreement”) which, among other changes: | |||||||||
— | extended the maturity date to August 28, 2019; | ||||||||
— | increased the revolving credit commitment from $600 million to $800 million and the incremental revolving credit amount from $200 million to $250 million; | ||||||||
— | reduced by 0.25% the applicable margin used to determine interest rates for LIBOR Rate Loans, as defined in the Revised APL Credit Agreement, and for Base Rate Loans, as defined in the Revised APL Credit Agreement, depending on APL’s Consolidated Funded Debt Ratio, as defined in the Revised APL Credit Agreement; | ||||||||
— | allows APL to request incremental term loans, provided the sum of any revolving credit commitments and incremental term loans may not exceed $1.05 billion; and | ||||||||
— | changed the per annum interest rate on borrowings to (i) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) the LIBOR rate plus 1.0%, or (ii) the LIBOR rate for the applicable period, in each case plus the applicable margin. | ||||||||
As of December 31, 2014, APL was in compliance with all covenants under the credit facility. | |||||||||
APL Senior Notes | |||||||||
At December 31, 2014, APL had $500.0 million principal outstanding of the 6.625% APL Senior Notes, $650.0 million principal outstanding of the 5.875% unsecured senior notes due August 1, 2023 (“5.875% APL Senior Notes”), and $400.0 million of the 4.75% APL Senior Notes (with the 6.625% APL Senior Notes and 5.875% APL Senior Notes, the “APL Senior Notes”). | |||||||||
The APL Senior Notes are subject to repurchase by APL at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if APL does not reinvest the net proceeds within 360 days. The APL Senior Notes are junior in right of payment to APL’s secured debt, including APL’s obligations under its revolving credit facility. | |||||||||
Indentures governing the APL Senior Notes contain covenants, including limitations of APL’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all its assets, without consent. APL is in compliance with these covenants as of December 31, 2014. | |||||||||
6.625% APL Senior Notes | |||||||||
The 6.625% APL Senior Notes are presented combined with a net $3.9 million unamortized premium as of December 31, 2014. Interest on the 6.625% APL Senior Notes is payable semi-annually in arrears on April 1 and October 1. The 6.625% APL Senior Notes are due on October 1, 2020 and redeemable at any time after October 1, 2016, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. | |||||||||
On September 28, 2012, APL issued $325.0 million of the 6.625% APL Senior Notes in a private placement transaction, at par. APL received net proceeds of $318.9 million after underwriting commissions and other transaction costs and utilized the proceeds to reduce the outstanding balance on its revolving credit facility. | |||||||||
On December 20, 2012, APL issued $175.0 million of the 6.625% APL Senior Notes in a private placement transaction. The 6.625% APL Senior Notes were issued at a premium of 103.0% of the principal amount for a yield of 6.0%. APL received net proceeds of $176.1 million after underwriting commissions and other transaction costs and utilized the proceeds to partially finance the Cardinal Acquisition (see Note 4). Of the $176.1 million net proceeds, $176.5 million were received during the year ended December 31, 2012, while additional expenses of $0.4 million were incurred during the year ended December 31, 2013. | |||||||||
5.875% APL Senior Notes | |||||||||
On February 11, 2013, APL issued $650.0 million of the 5.875% APL Senior Notes in a private placement transaction. The 5.875% APL Senior Notes were issued at par. APL received net proceeds of $637.3 million after underwriting commissions and other transactions costs and utilized the proceeds to redeem the 8.75% APL Senior Notes and repay a portion of the outstanding indebtedness under the revolving credit facility. Interest on the 5.875% APL Senior Notes is payable semi-annually in arrears on February 1 and August 1. The 5.875% APL Senior Notes are due on August 1, 2023, and redeemable any time after February 1, 2018, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. | |||||||||
4.75% APL Senior Notes | |||||||||
On May 10, 2013, APL issued $400.0 million of the 4.75% APL Senior Notes in a private placement transaction. The 4.75% APL Senior Notes were issued at par. APL received net proceeds of $391.2 million after underwriting commissions and other transactions costs and utilized the proceeds to repay a portion of the outstanding indebtedness under the revolving credit agreement as part of the TEAK Acquisition (see Note 4). Interest on the 4.75% APL Senior Notes is payable semi-annually in arrears on May 15 and November 15. The 4.75% APL Senior Notes is payable semi-annually in arrears on May 15 and November 15. The 4.75% APL Senior Notes are due on November 15, 2021 and are redeemable any time after March 15, 2016, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. | |||||||||
8.75% APL Senior Notes | |||||||||
On January 28, 2013, APL commenced a cash tender offer for any and all of its outstanding 8.75% APL Senior Notes and a solicitation of consents to eliminate most of the restrictive covenants and certain of the events of default contained in the indenture governing the 8.75% APL Senior Notes (“8.75% APL Senior Notes Indenture”). Approximately $268.4 million aggregate principal amount of the 8.75% APL Senior Notes were validly tendered as of the expiration date of the consent solicitation. In February 2013, APL accepted for purchase all 8.75% APL Senior Notes validly tendered as of the expiration of the consent solicitation and paid $291.4 million to redeem the $268.4 million principal plus $11.2 million make-whole premium, $3.7 million accrued interest and $8.0 million consent payment. APL entered into a supplemental indenture amending and supplementing the 8.75% APL Senior Notes Indenture. | |||||||||
On March 12, 2013, APL paid $105.6 million to redeem the remaining $97.3 million outstanding 8.75% APL Senior Notes not purchased in connection with the January 28, 2013 tender offer, plus a $6.3 million make-whole premium and $2.0 million in accrued interest. APL funded the redemption with a portion of the net proceeds from the issuance of the 5.875% APL Senior Notes. During the year ended December 31, 2013, APL recorded a loss of $26.6 million within loss on early extinguishment of debt on the Partnership’s consolidated statements of operations, related to the redemption of the 8.75% APL Senior Notes. The loss includes $17.5 million premiums paid; $8.0 million consent payment; $5.3 million write off of deferred financing costs, offset by $4.2 million recognition of unamortized premium. | |||||||||
The aggregate amount of the Partnership’s, ARP’s and APL’s debt maturities is as follows (in thousands): | |||||||||
Years Ended December 31: | |||||||||
2015 | $ | 2,624 | |||||||
2016 | 2,405 | ||||||||
2017 | 232,200 | ||||||||
2018 | 696,000 | ||||||||
2019 | 385,000 | ||||||||
Thereafter | 2,250,000 | ||||||||
Total principle maturities | 3,568,229 | ||||||||
Unamortized premiums | 4,245 | ||||||||
Unamortized discounts | (1,904 | ) | |||||||
Total debt | $ | 3,570,570 | |||||||
Cash payments for interest by the Partnership and its subsidiaries were $170.7 million, $96.6 million and $38.8 million for the years ended December 31, 2014, 2013 and 2012, respectively. |
Derivative_Instruments
Derivative Instruments | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |||||||||||||||||
Derivative Instruments | NOTE 10 — DERIVATIVE INSTRUMENTS | ||||||||||||||||
The Partnership and its subsidiaries use a number of different derivative instruments, principally swaps, collars, and options, in connection with their commodity and interest rate price risk management activities. The Partnership and its subsidiaries enter into financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold or interest payments on the underlying debt instrument are due. Under commodity-based swap agreements, the Partnership and its subsidiaries receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. To manage the risk of regional commodity price differences, the Partnership and its subsidiaries occasionally enter into basis swaps. Basis swaps are contractual arrangements that guarantee a price differential for a commodity from a specified delivery point price and the comparable national exchange price. For natural gas basis swaps, which have negative differentials to NYMEX, the Partnership and its subsidiaries receive or pay a payment from the counterparty if the price differential to NYMEX is greater or less than the stated terms of the contract. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike, price and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged. | |||||||||||||||||
The Partnership and ARP apply the principles of hedge accounting for derivatives qualifying as hedges. Accordingly, the Partnership and ARP formally document all relationships between hedging instruments and the items being hedged, including their risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity and interest derivative contracts to the forecasted transactions. The Partnership and ARP assess, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the Partnership and ARP will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which are determined by management through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated statements of operations. For derivatives qualifying as hedges, the Partnership and ARP recognize the effective portion of changes in fair value of derivative instruments in partners’ capital as accumulated other comprehensive income (loss) and reclassify the portion relating to the Partnership and ARP’s commodity derivatives within gas and oil production revenues and the portion relating to interest rate derivatives to interest expense within the Partnership’s consolidated statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, changes in fair value are recognized within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated statements of operations as they occur. | |||||||||||||||||
APL does not apply the principles of hedge accounting to its derivative instruments. Accordingly, any changes in the derivative fair value, which are determined by management through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated statements of operations. APL recognizes the portion relating to commodity derivatives within gathering and processing revenues on the Partnership’s consolidated statement of operations as the derivative instruments are settled. | |||||||||||||||||
The Partnership and its subsidiaries enter into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s consolidated balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s consolidated balance sheets as the initial value of the options. | |||||||||||||||||
The Partnership and its subsidiaries enter into commodity future option and collar contracts to achieve more predictable cash flows by hedging their exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. Natural gas liquids fixed price swaps are priced based on a WTI crude oil index, while other natural gas liquids contracts are based on an OPIS Mt. Belvieu index. | |||||||||||||||||
Derivatives are recorded on the Partnership’s consolidated balance sheets as assets or liabilities at fair value. The Partnership reflected net derivative assets on its consolidated balance sheets of $400.3 million and $14.9 million at December 31, 2014 and 2013, respectively. Of the $54.0 million of deferred gains in accumulated other comprehensive income within partners’ capital on the Partnership’s consolidated balance sheet related to derivatives at December 31, 2014, if the fair values of the instruments remain at current market values, the Partnership will reclassify $27.2 million of gains to gas and oil production revenue on its consolidated statement of operations over the next twelve month period as these contracts expire. Aggregate gains of $26.8 million of gas and oil production revenues will be reclassified to the Partnership’s consolidated statements of operations in later periods as the remaining contracts expire. Actual amounts that will be reclassified will vary as a result of future commodity price changes. In 2014 and 2013, approximately $2.5 million and $3.9 million of derivative gains were reclassified from other comprehensive income (loss) related to derivative instruments entered into during the years ended December 31, 2014 and 2013, respectively. | |||||||||||||||||
The following table summarizes the Partnership’s and ARP’s gains or losses recognized in the Partnership’s consolidated statements of operations for effective derivative instruments, excluding the effect of non-controlling interest, for the periods indicated (in thousands): | |||||||||||||||||
Years Ended December 31, | |||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
(Gain) loss reclassified from accumulated other comprehensive income: | |||||||||||||||||
Gas and oil production revenue | $ | 7,739 | $ | (10,216 | ) | $ | (19,281 | ) | |||||||||
Gathering and processing revenue | — | — | 4,390 | ||||||||||||||
Total | $ | 7,739 | $ | (10,216 | ) | $ | (14,891 | ) | |||||||||
The Partnership | |||||||||||||||||
The following table summarizes the gross fair values of the Partnership’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Partnership’s consolidated balance sheets as of the dates indicated (in thousands): | |||||||||||||||||
Gross | Gross | Net Amount of | |||||||||||||||
Amounts of | Amounts | Assets | |||||||||||||||
Recognized | Offset in the | Presented in the | |||||||||||||||
Assets | Consolidated | Consolidated | |||||||||||||||
Balance Sheets | Balance Sheets | ||||||||||||||||
Offsetting Derivative Assets | |||||||||||||||||
As of December 31, 2014 | |||||||||||||||||
Current portion of derivative assets | $ | 2,893 | $ | — | $ | 2,893 | |||||||||||
Long-term portion of derivative assets | 2,669 | — | 2,669 | ||||||||||||||
Total derivative assets | $ | 5,562 | $ | — | $ | 5,562 | |||||||||||
As of December 31, 2013 | |||||||||||||||||
Current portion of derivative assets | $ | 24 | $ | (23 | ) | $ | 1 | ||||||||||
Long-term portion of derivative assets | 1,547 | (33 | ) | 1,514 | |||||||||||||
Current portion of derivative liabilities | 63 | (63 | ) | — | |||||||||||||
Total derivative assets | $ | 1,634 | $ | (119 | ) | $ | 1,515 | ||||||||||
Gross | Gross | Net Amount of | |||||||||||||||
Amounts of | Amounts | Liabilities | |||||||||||||||
Recognized | Offset in the | Presented in the | |||||||||||||||
Liabilities | Consolidated | Consolidated | |||||||||||||||
Balance Sheets | Balance Sheets | ||||||||||||||||
Offsetting Derivative Liabilities | |||||||||||||||||
As of December 31, 2014 | |||||||||||||||||
Long-term portion of derivative assets | $ | — | $ | — | $ | — | |||||||||||
Long-term portion of derivative assets | — | — | — | ||||||||||||||
Total derivative liabilities | $ | — | $ | — | $ | — | |||||||||||
As of December 31, 2013 | |||||||||||||||||
Current portion of derivative assets | $ | (23 | ) | $ | 23 | $ | — | ||||||||||
Long-term portion of derivative assets | (33 | ) | 33 | — | |||||||||||||
Current portion of derivative liabilities | (96 | ) | 63 | (33 | ) | ||||||||||||
Total derivative liabilities | $ | (152 | ) | $ | 119 | $ | (33 | ) | |||||||||
During the year ended December 31, 2014 and 2013, the Partnership recorded gains of $0.7 million and $0.5 million on settled derivative contracts within its consolidated statements of operations. These gains and losses were included within gas and oil production revenue in the Partnership’s consolidated statements of operations. No gains or losses were recorded on settled derivative contracts within the Partnership’s consolidated statement of operations for the year ended December 31, 2012 as the Partnership had no derivative contracts in 2012. As the underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the year ended December 31, 2014 and 2013 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges. | |||||||||||||||||
In connection with the Arkoma Acquisition, the Partnership entered into contracts which provided the option to enter into swap contracts for future production periods (“swaptions”) up through September 30, 2013 for production volumes related to the Arkoma assets acquired from EP Energy (see Note 3). In connection with the swaption contacts, the Partnership paid premiums of $2.3 million which represented their fair value on the date the transactions were initiated, were initially recorded as a derivative asset on the Partnership’s consolidated balance sheet and were fully amortized into other, net on the Partnership’s consolidated statement of operations as of September 30, 2013. Swaption contract premiums paid are amortized over the period from initiation of the contract through termination date. For the year ended December 31, 2013, the Partnership recognized approximately $2.3 million, respectively, of amortization expense in other, net on the Partnership’s consolidated statement of operations related to the swaption contracts. | |||||||||||||||||
At December 31, 2014, the Partnership had the following commodity derivatives: | |||||||||||||||||
Natural Gas – Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | |||||||||||||||
2015 | 2,280,000 | $ | 4.302 | $ | 2,893 | ||||||||||||
2016 | 1,440,000 | $ | 4.433 | 1,374 | |||||||||||||
2017 | 1,200,000 | $ | 4.59 | 960 | |||||||||||||
2018 | 420,000 | $ | 4.797 | 335 | |||||||||||||
The Partnership’s net asset | $ | 5,562 | |||||||||||||||
(1) | “MMBtu” represents million British Thermal Units. | ||||||||||||||||
(2) | Fair value based on forward NYMEX natural gas prices, as applicable. | ||||||||||||||||
Atlas Resource Partners | |||||||||||||||||
The following table summarizes the gross fair values of ARP’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Partnership’s consolidated balance sheets as of the dates indicated (in thousands): | |||||||||||||||||
Offsetting Derivative Assets | Gross | Gross | Net Amount of | ||||||||||||||
Amounts of | Amounts | Assets | |||||||||||||||
Recognized | Offset in the | Presented in the | |||||||||||||||
Assets | Consolidated | Consolidated | |||||||||||||||
Balance Sheets | Balance Sheets | ||||||||||||||||
As of December 31, 2014 | |||||||||||||||||
Current portion of derivative assets | $ | 141,464 | $ | (98 | ) | $ | 141,366 | ||||||||||
Long-term portion of derivative assets | 128,303 | (370 | ) | 127,933 | |||||||||||||
Total derivative assets | $ | 269,767 | $ | (468 | ) | $ | 269,299 | ||||||||||
As of December 31, 2013 | |||||||||||||||||
Current portion of derivative assets | $ | 2,664 | $ | (773 | ) | $ | 1,891 | ||||||||||
Long-term portion of derivative assets | 31,146 | (4,062 | ) | 27,084 | |||||||||||||
Current portion of derivative liabilities | 4,341 | (4,341 | ) | — | |||||||||||||
Long-term portion of derivative liabilities | 122 | (122 | ) | — | |||||||||||||
Total derivative assets | $ | 38,273 | $ | (9,298 | ) | $ | 28,975 | ||||||||||
Offsetting Derivative Liabilities | Gross | Gross | Net Amount of | ||||||||||||||
Amounts of | Amounts | Liabilities | |||||||||||||||
Recognized | Offset in the | Presented in the | |||||||||||||||
Liabilities | Consolidated | Consolidated | |||||||||||||||
Balance Sheets | Balance Sheets | ||||||||||||||||
As of December 31, 2014 | |||||||||||||||||
Current portion of derivative liabilities | $ | (98 | ) | $ | 98 | $ | — | ||||||||||
Long-term portion of derivative liabilities | (370 | ) | 370 | — | |||||||||||||
Total derivative liabilities | $ | (468 | ) | $ | 468 | $ | — | ||||||||||
As of December 31, 2013 | |||||||||||||||||
Current portion of derivative assets | $ | (773 | ) | $ | 773 | $ | — | ||||||||||
Long-term portion of derivative assets | (4,062 | ) | 4,062 | — | |||||||||||||
Current portion of derivative liabilities | (10,694 | ) | 4,341 | (6,353 | ) | ||||||||||||
Long-term portion of derivative liabilities | (189 | ) | 122 | (67 | ) | ||||||||||||
Total derivative liabilities | $ | (15,718 | ) | $ | 9,298 | $ | (6,420 | ) | |||||||||
During the year ended December 31, 2013, ARP entered into contracts which provided the option to enter into swaptions up through September 30, 2013 for production volumes related to assets acquired from EP Energy (see Note 4). In connection with these swaption contracts, ARP paid premiums of $14.5 million, which represented their fair value on the date the transactions were initiated and were initially recorded as a derivative asset on the Partnership’s consolidated balance sheet and were fully amortized as of September 30, 2013. Swaption contract premiums paid are amortized over the period from initiation of the contract through their termination date. For the year ended December 31, 2013, ARP recognized $14.5 million, respectively, of amortization expense in other, net on the Partnership’s consolidated statement of operations related to the swaption contracts. | |||||||||||||||||
During the year ended December 31, 2012, ARP entered into swaptions contracts up through May 31, 2012 for production volumes related to wells acquired from Carrizo (see Note 4). In connection with the swaption contracts, ARP paid premiums of $4.6 million, which represented their fair value on the date the transactions were initiated and were initially recorded as derivative assets on the Partnership’s consolidated balance sheet and were fully amortized as of June 30, 2012. For the year ended December 31, 2012, ARP recorded approximately $4.6 million of amortization expense in other, net on the Partnership’s consolidated statement of operations related to the swaption contracts. | |||||||||||||||||
In June 2012, ARP received approximately $3.9 million in net proceeds from the early termination of natural gas and oil derivative positions for production periods from 2015 through 2016. In conjunction with the early termination of these derivatives, ARP entered into new derivative positions at prevailing prices at the time of the transaction. The net proceeds from the early termination of these derivatives were used to reduce indebtedness under ARP’s credit facility. The gain recognized upon the early termination of these derivative positions will continue to be reported in accumulated other comprehensive income (loss) and will be reclassified into the Partnership’s consolidated statements of operations in the same periods in which the hedged production revenues would have been recognized in earnings. | |||||||||||||||||
ARP recognized losses of $7.1 million and gains of $9.7 million and $19.3 million for the years ended December 31, 2014, 2013, and 2012, respectively, on settled contracts covering commodity production. These gains and loss were included within gas and oil production revenue in the Partnership’s consolidated statements of operations. As the underlying prices and terms in ARP’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the years ended December 31, 2014, 2013, and 2012, respectively, for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges. | |||||||||||||||||
At December 31, 2014, ARP had the following commodity derivatives: | |||||||||||||||||
Natural Gas – Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | |||||||||||||||
2015 | 54,834,500 | $ | 4.226 | $ | 65,393 | ||||||||||||
2016 | 53,546,300 | $ | 4.229 | 40,428 | |||||||||||||
2017 | 46,320,000 | $ | 4.276 | 22,999 | |||||||||||||
2018 | 35,760,000 | $ | 4.25 | 9,881 | |||||||||||||
2019 | 9,720,000 | $ | 4.234 | 1,023 | |||||||||||||
$ | 139,724 | ||||||||||||||||
Natural Gas – Costless Collars | |||||||||||||||||
Production | Option Type | Volumes | Average Floor | Fair Value | |||||||||||||
Period Ending | and Cap | Asset/ | |||||||||||||||
December 31, | (Liability) | ||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | |||||||||||||||
2015 | Puts purchased | 3,480,000 | $ | 4.234 | $ | 4,478 | |||||||||||
2015 | Calls sold | 3,480,000 | $ | 5.129 | (59 | ) | |||||||||||
$ | 4,419 | ||||||||||||||||
Natural Gas – Put Options – Drilling Partnerships | |||||||||||||||||
Production | Option Type | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | |||||||||||||||
2015 | Puts purchased | 1,440,000 | $ | 4 | $ | 1,506 | |||||||||||
2016 | Puts purchased | 1,440,000 | $ | 4.15 | 1,261 | ||||||||||||
$ | 2,767 | ||||||||||||||||
Natural Gas – WAHA Basis Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(7) | |||||||||||||||
2015 | 5,250,000 | $ | (0.082 | ) | $ | 153 | |||||||||||
$ | 153 | ||||||||||||||||
Natural Gas Liquids – Natural Gasoline Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(8) | |||||||||||||||
2015 | 5,040,000 | $ | 1.983 | $ | 4,630 | ||||||||||||
$ | 4,630 | ||||||||||||||||
Natural Gas Liquids – Propane Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(4) | |||||||||||||||
2015 | 8,064,000 | $ | 1.016 | $ | 4,011 | ||||||||||||
$ | 4,011 | ||||||||||||||||
Natural Gas Liquids – Butane Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(5) | |||||||||||||||
2015 | 1,512,000 | $ | 1.248 | $ | 829 | ||||||||||||
$ | 829 | ||||||||||||||||
Natural Gas Liquids – Iso Butane Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(6) | |||||||||||||||
2015 | 1,512,000 | $ | 1.263 | $ | 826 | ||||||||||||
$ | 826 | ||||||||||||||||
Natural Gas Liquids – Crude Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | |||||||||||||||
2016 | 84,000 | $ | 85.651 | $ | 1,851 | ||||||||||||
2017 | 60,000 | $ | 83.78 | 984 | |||||||||||||
$ | 2,835 | ||||||||||||||||
Crude Oil – Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | |||||||||||||||
2015 | 1,743,000 | $ | 90.645 | $ | 58,765 | ||||||||||||
2016 | 1,209,000 | $ | 87.36 | 28,663 | |||||||||||||
2017 | 672,000 | $ | 85.669 | 12,248 | |||||||||||||
2018 | 540,000 | $ | 85.466 | 8,595 | |||||||||||||
$ | 108,271 | ||||||||||||||||
Crude Oil – Costless Collars | |||||||||||||||||
Production | Option Type | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Floor | Asset/ | |||||||||||||||
December 31, | and Cap | (Liability) | |||||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | |||||||||||||||
2015 | Puts purchased | 29,250 | $ | 83.846 | $ | 842 | |||||||||||
2015 | Calls sold | 29,250 | $ | 110.654 | (8 | ) | |||||||||||
$ | 834 | ||||||||||||||||
Total net assets | $ | 269,299 | |||||||||||||||
-1 | “MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons. | ||||||||||||||||
(2) | Fair value based on forward NYMEX natural gas prices, as applicable. | ||||||||||||||||
-3 | Fair value based on forward WTI crude oil prices, as applicable. | ||||||||||||||||
-4 | Fair value based on forward Mt. Belvieu propane prices, as applicable. | ||||||||||||||||
-5 | Fair value based on forward Mt. Belvieu butane prices, as applicable. | ||||||||||||||||
(6) | Fair value based on forward Mt. Belvieu iso butane prices, as applicable. | ||||||||||||||||
(7) | Fair value based on forward WAHA natural gas prices, as applicable | ||||||||||||||||
(8) | Fair value based on forward Mt. Belvieu natural gasoline prices, as applicable. | ||||||||||||||||
At December 31, 2014, ARP had net cash proceeds of $0.2 million related to hedging positions monetized on behalf of the Drilling Partnerships’ limited partners, which were included within cash and cash equivalents on the Partnership’s consolidated balance sheet. ARP will allocate the monetization net proceeds to the Drilling Partnerships’ limited partners based on their natural gas and oil production generated over the period of the original derivative contracts. | |||||||||||||||||
In June 2012, ARP entered into natural gas put option contracts which related to future natural gas production of the Drilling Partnerships. Therefore, a portion of any unrealized derivative gain or loss is allocable to the limited partners of the Drilling Partnerships based on their share of estimated gas production related to the derivatives not yet settled. At December 31, 2014 and 2013, net unrealized derivative assets of $2.8 million and $1.4 million, respectively, were payable to the limited partners in the Drilling Partnerships related to these natural gas put option contracts. | |||||||||||||||||
At December 31, 2014, ARP had a secured hedge facility agreement with a syndicate of banks under which certain Drilling Partnerships have the ability to enter into derivative contracts to manage their exposure to commodity price movements. Under its revolving credit facility (see Note 9), ARP is required to utilize this secured hedge facility for future commodity risk management activity for its equity production volumes within the participating Drilling Partnerships. Each participating Drilling Partnership’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets and by a guarantee of the general partner of the Drilling Partnership. ARP, as general partner of the Drilling Partnerships, administers the commodity price risk management activity for the Drilling Partnerships under the secured hedge facility. The secured hedge facility agreement contains covenants that limit each of the participating Drilling Partnerships’ ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of its assets. | |||||||||||||||||
Atlas Pipeline Partners | |||||||||||||||||
The following table summarizes APL’s gross fair values of its derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Partnership’s consolidated balance sheets as of the dates indicated (in thousands): | |||||||||||||||||
Offsetting Derivative Assets | Gross Amounts of Recognized Assets | Gross Amounts Offset in the Consolidated Balance Sheets | Net Amounts of Assets Presented in the Consolidated Balance Sheets | ||||||||||||||
As of December 31, 2014: | |||||||||||||||||
Current portion of derivative assets | $ | 88,007 | $ | - | $ | 88,007 | |||||||||||
Long-term portion of derivative assets | 37,398 | - | 37,398 | ||||||||||||||
Total derivative assets, net | $ | 125,405 | $ | - | $ | 125,405 | |||||||||||
As of December 31, 2013: | |||||||||||||||||
Current portion of derivative assets | $ | 1,310 | $ | (1,136 | ) | $ | 174 | ||||||||||
Long-term portion of derivative assets | 5,082 | (2,812 | ) | 2,270 | |||||||||||||
Current portion of derivative liabilities | 1,612 | (1,612 | ) | - | |||||||||||||
Long-term portion of derivative liabilities | 949 | (949 | ) | - | |||||||||||||
Total derivative assets, net | $ | 8,953 | $ | (6,509 | ) | $ | 2,444 | ||||||||||
Offsetting Derivative Liabilities | Gross Amounts of Recognized Liabilities | Gross Amounts Offset in the Consolidated Balance Sheets | Net Amounts of Liabilities Presented in the Consolidated Balance Sheets | ||||||||||||||
As of December 31, 2014: | |||||||||||||||||
Current portion of derivative assets | $ | - | $ | - | $ | - | |||||||||||
Long-term portion of derivative assets | - | - | - | ||||||||||||||
Total derivative liabilities, net | $ | - | $ | - | $ | - | |||||||||||
As of December 31, 2013: | |||||||||||||||||
Current portion of derivative assets | $ | (1,136 | ) | $ | 1,136 | $ | - | ||||||||||
Long-term portion of derivative assets | (2,812 | ) | 2,812 | - | |||||||||||||
Current portion of derivative liabilities | (12,856 | ) | 1,612 | (11,244 | ) | ||||||||||||
Long-term portion of derivative liabilities | (1,269 | ) | 949 | (320 | ) | ||||||||||||
Total derivative liabilities, net | $ | (18,073 | ) | $ | 6,509 | $ | (11,564 | ) | |||||||||
As of December 31, 2014, APL had the following commodity derivatives: | |||||||||||||||||
Production | Average Fixed Price | ||||||||||||||||
Period | Commodity | Volumes(1) | ($/Volume) | Fair Value(2) Asset | |||||||||||||
Sold fixed price swaps | (in thousands) | ||||||||||||||||
2015 | Natural gas | 27,010,000 | 4.18 | $ | 30,945 | ||||||||||||
2016 | Natural gas | 13,800,000 | 4.15 | 9,381 | |||||||||||||
2017 | Natural gas | 6,600,000 | 4.11 | 2,137 | |||||||||||||
2015 | NGLs | 71,442,000 | 1.22 | 43,094 | |||||||||||||
2016 | NGLs | 34,650,000 | 1.03 | 16,822 | |||||||||||||
2017 | NGLs | 10,080,000 | 1.04 | 4,777 | |||||||||||||
2015 | Crude oil | 210,000 | 90.26 | 7,274 | |||||||||||||
2016 | Crude oil | 30,000 | 90 | 848 | |||||||||||||
Total fixed price swaps | 115,278 | ||||||||||||||||
Purchased put options | |||||||||||||||||
2015 | NGLs | 3,150,000 | 0.94 | 1,353 | |||||||||||||
2015 | Crude oil | 270,000 | 89.18 | 8,774 | |||||||||||||
Sold call options | |||||||||||||||||
2015 | NGLs | 1,260,000 | 1.28 | - | |||||||||||||
Total options | 10,127 | ||||||||||||||||
APL’s net asset | $ | 125,405 | |||||||||||||||
-1 | NGL volumes are stated in gallons. Crude oil volumes are stated in barrels. Natural gas volumes are stated in MMBTUs. | ||||||||||||||||
-2 | See Note 2 for discussion on fair value methodology. | ||||||||||||||||
The following table summarizes APL’s derivatives not designated as hedges, which are included within gain (loss) on mark-to market derivatives on the Partnerships consolidated statements of operations: | |||||||||||||||||
Years Ended December 31, | |||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
Gain (loss) recognized in gain (loss) on mark-to-market derivatives: | |||||||||||||||||
Commodity contract—realized(1) | $ | (9,960 | ) | $ | (324 | ) | $ | 10,993 | |||||||||
Commodity contract – unrealized(2) | 141,024 | (28,440 | ) | 20,947 | |||||||||||||
Gain (loss) on mark-to-market derivatives | $ | 131,064 | $ | (28,764 | ) | $ | 31,940 | ||||||||||
(1) | Realized gain (loss) represents the gain (loss) incurred when the derivative contract expires and/or is cash settled. | ||||||||||||||||
(2) | Unrealized gain (loss) represents the mark-to-market gain (loss) recognized on open derivative contracts, which have not yet settled. | ||||||||||||||||
The fair value of the derivatives included in the Partnership’s consolidated balance sheets for the periods indicated was as follows (in thousands): | |||||||||||||||||
31-Dec | December 31, | ||||||||||||||||
2014 | 2013 | ||||||||||||||||
Current portion of derivative asset | $ | 232,266 | $ | 2,066 | |||||||||||||
Long-term derivative asset | 168,000 | 30,868 | |||||||||||||||
Current portion of derivative liability | — | (17,630 | ) | ||||||||||||||
Long-term derivative liability | — | (387 | ) | ||||||||||||||
Total Partnership net asset | $ | 400,266 | $ | 14,917 | |||||||||||||
Fair_Value_of_Financial_Instru
Fair Value of Financial Instruments | 12 Months Ended | |||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||
Fair Value Disclosures [Abstract] | ||||||||||||||||||||||||||||
Fair Value of Financial Instruments | NOTE 11 — FAIR VALUE OF FINANCIAL INSTRUMENTS | |||||||||||||||||||||||||||
The Partnership and its subsidiaries have established a hierarchy to measure their financial instruments at fair value which requires them to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources, whereas, unobservable inputs reflect the Partnership and its subsidiaries own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value: | ||||||||||||||||||||||||||||
Level 1– Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date. | ||||||||||||||||||||||||||||
Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability. | ||||||||||||||||||||||||||||
Level 3 – Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques. | ||||||||||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | ||||||||||||||||||||||||||||
The Partnership and its subsidiaries use a market approach fair value methodology to value the assets and liabilities for their outstanding derivative contracts (see Note 10) and investments held in the Partnership’s rabbi trust (see Note 17). The Partnership and its subsidiaries manage and report derivative assets and liabilities on the basis of their exposure to market risks and credit risks by counterparty. The Partnership and its subsidiaries’ commodity derivative contracts, with the exception of APL’s NGL fixed price swaps and NGL options, are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. These derivative instruments are calculated by utilizing commodity indices quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument. Investments held within the Partnership’s rabbi trust are publicly traded equity and debt securities and are therefore defined as Level 1 fair value measurements. | ||||||||||||||||||||||||||||
Valuations for APL’s NGL fixed price swaps are based on forward price curves provided by a third party, which are considered to be Level 3 inputs. The prices are adjusted based upon the relationship between the prices for the product/locations quoted by the third party and the underlying product/locations utilized for the swap contracts, as determined by a regression model of the historical settlement prices for the different product/locations. The regression model is recalculated on a quarterly basis. This adjustment is an unobservable Level 3 input. The NGL fixed price swaps are over the counter instruments which are not actively traded in an open market. However, the prices for the underlying products and locations do have a direct correlation to the prices for the products and locations provided by the third party, which are based upon trading activity for the products and locations quoted. A change in the relationship between these prices would have a direct impact upon the unobservable adjustment utilized to calculate the fair value of the NGL fixed price swaps. Valuations for APL’s NGL options are based on forward price curves developed by financial institutions, and therefore are defined as Level 3 assets and liabilities. The NGL options are over the counter instruments that are not actively traded in an open market, thus APL utilizes the valuations provided by the financial institutions that provide the NGL options for trade. These valuations are tested for reasonableness through the use of an internal valuation model. | ||||||||||||||||||||||||||||
Information for the Partnership’s, ARP’s and APL’s assets and liabilities measured at fair value at December 31, 2014 and 2013 was as follows (in thousands): | ||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||
As of December 31, 2014 | ||||||||||||||||||||||||||||
Assets, gross | ||||||||||||||||||||||||||||
Rabbi trust | $ | 3,925 | $ | — | $ | — | $ | 3,925 | ||||||||||||||||||||
Commodity swaps | — | 5,562 | — | 5,562 | ||||||||||||||||||||||||
ARP Commodity swaps | — | 261,680 | — | 261,680 | ||||||||||||||||||||||||
ARP Commodity puts | — | 2,767 | — | 2,767 | ||||||||||||||||||||||||
ARP Commodity options | — | 5,320 | — | 5,320 | ||||||||||||||||||||||||
APL Commodity swaps | — | 50,585 | 64,693 | 115,278 | ||||||||||||||||||||||||
APL Commodity options | — | 8,774 | 1,353 | 10,127 | ||||||||||||||||||||||||
Total assets, gross | 3,925 | 334,688 | 66,046 | 404,659 | ||||||||||||||||||||||||
Liabilities, gross | ||||||||||||||||||||||||||||
Commodity swaps | — | — | — | — | ||||||||||||||||||||||||
ARP Commodity swaps | — | (401 | ) | — | (401 | ) | ||||||||||||||||||||||
ARP Commodity options | — | (67 | ) | — | (67 | ) | ||||||||||||||||||||||
APL Commodity swaps | — | — | — | — | ||||||||||||||||||||||||
APL Commodity options | — | — | — | — | ||||||||||||||||||||||||
Total liabilities, gross | — | (468 | ) | — | (468 | ) | ||||||||||||||||||||||
Total assets, fair value, net | $ | 3,925 | $ | 334,220 | $ | 66,046 | $ | 404,191 | ||||||||||||||||||||
As of December 31, 2013 | ||||||||||||||||||||||||||||
Assets, gross | ||||||||||||||||||||||||||||
Rabbi trust | $ | 3,705 | $ | — | $ | — | $ | 3,705 | ||||||||||||||||||||
Commodity swaps | — | 1,634 | $ | — | 1,634 | |||||||||||||||||||||||
ARP Commodity swaps | — | 33,594 | — | 33,594 | ||||||||||||||||||||||||
ARP Commodity puts | — | 1,374 | — | 1,374 | ||||||||||||||||||||||||
ARP Commodity options | — | 3,305 | — | 3,305 | ||||||||||||||||||||||||
APL Commodity swaps | — | 2,994 | 1,412 | 4,406 | ||||||||||||||||||||||||
APL Commodity options | — | 4,337 | 210 | 4,547 | ||||||||||||||||||||||||
Total assets, gross | 3,705 | 47,238 | 1,622 | 52,565 | ||||||||||||||||||||||||
Liabilities, gross | ||||||||||||||||||||||||||||
Commodity swaps | — | (152 | ) | — | (152 | ) | ||||||||||||||||||||||
ARP Commodity swaps | — | (14,624 | ) | — | (14,624 | ) | ||||||||||||||||||||||
ARP Commodity options | — | (1,094 | ) | — | (1,094 | ) | ||||||||||||||||||||||
APL Commodity swaps | — | (4,695 | ) | (13,378 | ) | (18,073 | ) | |||||||||||||||||||||
Total derivative liabilities, gross | — | (20,565 | ) | (13,378 | ) | (33,943 | ) | |||||||||||||||||||||
Total derivatives, fair value, net | $ | 3,705 | $ | 26,673 | $ | (11,756 | ) | $ | 18,622 | |||||||||||||||||||
APL’s Level 3 fair value amounts relate to its derivative contracts on NGL fixed price swaps and NGL options. The following table provides a summary of changes in fair value of APL’s Level 3 derivative instruments for the periods indicated (in thousands): | ||||||||||||||||||||||||||||
NGL Fixed Price Swaps | NGL Put Options | NGL Call Options | Total | |||||||||||||||||||||||||
Gallons | Amount | Gallons | Amount | Gallons | Amount | Amount | ||||||||||||||||||||||
Balance – January 1, 2013 | 87,066 | $ | 16,814 | 38,556 | $ | 6,269 | — | — | $ | 23,083 | ||||||||||||||||||
New contracts(1) | 104,328 | — | 7,560 | 816 | — | — | 816 | |||||||||||||||||||||
Cash settlements from unrealized (gain) loss(2)(3) | (61,236 | ) | (11,496 | ) | (39,816 | ) | 8,545 | — | — | (2,951 | ) | |||||||||||||||||
Net change in unrealized loss(2) | — | (17,284 | ) | — | (2,367 | ) | — | — | (19,651 | ) | ||||||||||||||||||
Deferred option premium recognition(3) | — | — | — | (13,053 | ) | — | — | (13,053 | ) | |||||||||||||||||||
Balance – December 31, 2013 | 130,158 | $ | (11,966 | ) | 6,300 | $ | 210 | — | — | $ | (11,756 | ) | ||||||||||||||||
New contracts(1) | 70,560 | — | 5,040 | 200 | 5,040 | (200 | ) | — | ||||||||||||||||||||
Cash settlements from unrealized (gain) loss(2)(3) | (84,546 | ) | 3,406 | (8,190 | ) | 100 | (3,780 | ) | (121 | ) | 3,385 | |||||||||||||||||
Net change in unrealized gain (loss)(2) | — | 73,253 | — | 1,448 | — | 200 | 74,901 | |||||||||||||||||||||
Deferred option premium recognition(3) | — | — | — | (605 | ) | — | 121 | (484 | ) | |||||||||||||||||||
Balance – December 31, 2014 | 116,172 | $ | 64,693 | 3,150 | $ | 1,353 | 1,260 | — | $ | 66,046 | ||||||||||||||||||
(1) | Swaps are entered into with no value on the date of trade. Options include premiums paid, which are included in the value of the derivatives on the date of trade. | |||||||||||||||||||||||||||
(2) | Included within gain (loss) on mark-to-market derivatives on the Partnership’s consolidated statements of operations. | |||||||||||||||||||||||||||
(3) | Includes option premium cost reclassified from unrealized gain (loss) to realized gain (loss) at time of option expiration. | |||||||||||||||||||||||||||
The following table provides a summary of the unobservable inputs used in the fair value measurement of APL’s NGL fixed price swaps at December 31, 2014 and December 31, 2013 (in thousands): | ||||||||||||||||||||||||||||
Gallons | Third Party Quotes(1) | Adjustments(2) | Total Amount | |||||||||||||||||||||||||
As of December 31, 2014 | ||||||||||||||||||||||||||||
Propane swaps | 101,556 | $ | 50,201 | $ | — | $ | 50,201 | |||||||||||||||||||||
Natural gasoline swaps | 14,616 | 14,859 | (367 | ) | 14,492 | |||||||||||||||||||||||
Total NGL swaps – December 31, 2014 | 116,172 | $ | 65,060 | $ | (367 | ) | $ | 64,693 | ||||||||||||||||||||
As of December 31, 2013 | ||||||||||||||||||||||||||||
Propane swaps | 100,296 | $ | (10,260 | ) | $ | — | $ | (10,260 | ) | |||||||||||||||||||
Isobutane swaps | 6,300 | (2,342 | ) | 955 | (1,387 | ) | ||||||||||||||||||||||
Normal butane swaps | 7,560 | 40 | 322 | 362 | ||||||||||||||||||||||||
Natural gasoline swaps | 16,002 | 132 | (813 | ) | (681 | ) | ||||||||||||||||||||||
Total NGL swaps – December 31, 2013 | 130,158 | $ | (12,430 | ) | $ | 464 | $ | (11,966 | ) | |||||||||||||||||||
(1) | Based upon the difference between the quoted market price provided by the third party and the fixed price of the swap. | |||||||||||||||||||||||||||
(2) | Product and location basis differentials calculated through the use of a regression model, which compares the difference between the settlement prices for the products and locations quoted by the third party and the settlement prices for the actual products and locations underlying the derivatives, using a three-year historical period. | |||||||||||||||||||||||||||
The following table provides a summary of the regression coefficient utilized in the calculation of the unobservable inputs for the Level 3 fair value measurements for APL’s NGL fixed price swaps for the periods indicated (in thousands): | ||||||||||||||||||||||||||||
Level 3 NGL Swap Fair | Adjustment based upon Regression Coefficient | |||||||||||||||||||||||||||
Value Adjustments | Lower 95% | Upper 95% | Average | |||||||||||||||||||||||||
As of December 31, 2014: | ||||||||||||||||||||||||||||
Natural gasoline | $ | (367 | ) | 0.9714 | 0.9748 | 0.9731 | ||||||||||||||||||||||
Total Level 3 adjustments – December 31, 2014 | $ | (367 | ) | |||||||||||||||||||||||||
As of December 31, 2013: | ||||||||||||||||||||||||||||
Isobutane | $ | 955 | 1.1184 | 1.1284 | 1.1234 | |||||||||||||||||||||||
Normal butane | 322 | 1.0341 | 1.0386 | 1.0364 | ||||||||||||||||||||||||
Natural gasoline | (813 | ) | 0.9727 | 0.9751 | 0.9739 | |||||||||||||||||||||||
Total Level 3 adjustments – December 31, 2013 | $ | 464 | ||||||||||||||||||||||||||
APL had $14.6 million and $14.5 million of NGL linefill at December 31, 2014 and 2013, respectively, which were included within prepaid expenses and other on the Partnership’s consolidated balance sheets. The NGL linefill represents amounts receivable for NGLs delivered to counterparties for which the counterparty will pay at a designated later period at a price determined by the then market price. APL’s NGL linefill held by some counterparties will be settled at various periods in the future and is defined as a Level 3 asset, which is valued at fair value using the same forward price curve utilized to value APL’s NGL fixed price swaps. The product/location adjustment based upon the multiple regression analysis, which was included in the value of the linefill, was an increase of $0.1 million and a decrease of $0.4 million as of December 31, 2014 and 2013, respectively. APL’s NGL linefill held by other counterparties is adjusted on a monthly basis according to the volumes delivered to the counterparties each period and is valued on a first in first out (“FIFO”) basis. During the year ended December 31, 2014, the contracts related to this linefill on the WestTX and SouthTX systems were revised and the settlement and valuation was converted from a FIFO method to a fair value method. | ||||||||||||||||||||||||||||
The following table provides a summary of changes in fair value of APL’s NGL linefill for the years ended December 31, 2014 and 2013 (in thousands): | ||||||||||||||||||||||||||||
Linefill Valued at Market | Linefill Valued on FIFO | Total NGL Linefill | ||||||||||||||||||||||||||
Gallons | Amount | Gallons | Amount | Gallons | Amount | |||||||||||||||||||||||
Balance –January 1, 2013 | 9,148 | $ | 7,783 | - | $ | - | 9,148 | $ | 7,783 | |||||||||||||||||||
Deliveries into NGL linefill | - | - | 80,758 | 60,565 | 80,758 | 60,565 | ||||||||||||||||||||||
NGL linefill sales | -3,360 | -2,795 | -71,433 | -52,155 | -74,793 | -54,950 | ||||||||||||||||||||||
Net change in NGL linefill valuation(1) | - | -249 | - | - | - | -249 | ||||||||||||||||||||||
Acquired NGL linefill(2) | - | - | 2,213 | 1,368 | 2,213 | 1,368 | ||||||||||||||||||||||
Balance – December 31, 2013 | 5,788 | $ | 4,739 | 11,538 | $ | 9,778 | 17,326 | $ | 14,517 | |||||||||||||||||||
Deliveries into NGL linefill | 4,385 | 2,919 | 59,273 | 38,451 | 63,658 | 41,370 | ||||||||||||||||||||||
NGL linefill sales | -4,629 | -3,917 | -49,335 | -31,470 | -53,964 | -35,387 | ||||||||||||||||||||||
Adjustments for linefill contract revision | 11,982 | 9,846 | -11,982 | -9,846 | - | - | ||||||||||||||||||||||
Net change in NGL linefill valuation(1) | - | -5,888 | - | - | - | -5,888 | ||||||||||||||||||||||
Balance – December 31, 2014 | 17,526 | $ | 7,699 | 9,494 | $ | 6,913 | 27,020 | $ | 14,612 | |||||||||||||||||||
-1 | Included within gathering and processing revenues on the Partnership’s consolidated statements of operations. | |||||||||||||||||||||||||||
-2 | NGL linefill acquired as part of APL’s TEAK and Cardinal acquisitions (see Note 4). | |||||||||||||||||||||||||||
Other Financial Instruments | ||||||||||||||||||||||||||||
The estimated fair value of the Partnership and its subsidiaries’ other financial instruments has been determined based upon its assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Partnership and its subsidiaries could realize upon the sale or refinancing of such financial instruments. | ||||||||||||||||||||||||||||
The Partnership and its subsidiaries’ other current assets and liabilities on its consolidated balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1. The estimated fair values of the Partnership and its subsidiaries’ debt at December 31, 2014 and 2013, which consist principally of ARP’s and APL’s senior notes and borrowings under the Partnership’s, ARP’s and APL’s revolving and term loan credit facilities, were $3,382.9 million and $2,841.7 million, respectively, compared with the carrying amounts of $3,570.6 million and $2,889.0 million, respectively. The carrying values of outstanding borrowings under the respective revolving and term loan credit facilities, which bear interest at variable interest rates, approximated their estimated fair values. The estimated fair values of the ARP and APL senior notes were based upon the market approach and calculated using the yields of the ARP and APL senior notes as provided by financial institutions and thus were categorized as Level 3 values. | ||||||||||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis | ||||||||||||||||||||||||||||
The Partnership and ARP estimate the fair value of their respective asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and ARP and estimated inflation rates (see Note 7). | ||||||||||||||||||||||||||||
Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the years ended December 31, 2014 and 2013 was as follows (in thousands): | ||||||||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||
Level 3 | Total | Level 3 | Total | |||||||||||||||||||||||||
Asset retirement obligations | $ | 10,674 | $ | 10,674 | $ | 23,129 | $ | 23,129 | ||||||||||||||||||||
Total | $ | 10,674 | $ | 10,674 | $ | 23,129 | $ | 23,129 | ||||||||||||||||||||
The Partnership and its subsidiaries estimate the fair value of its long-lived assets in connection with reviewing these assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions and judgments regarding such events or circumstances. For the years ended December 31, 2014, 2013 and 2012, the Partnership recognized $580.7 million, $38.0 million and $9.5 million, respectively, of impairment of long-lived assets which were defined as a Level 3 fair value measurements (see Note 2 – Impairment of Long-Lived Assets and Goodwill). | ||||||||||||||||||||||||||||
During the year ended December 31, 2014, ARP completed the Eagle Ford, Rangely and GeoMet acquisitions (see Note 4). During the year ended December 31, 2013, the Partnership completed the Arkoma Acquisition, ARP completed the EP Energy Acquisition and APL completed the TEAK Acquisition. During the year ended December 31, 2012, ARP completed the acquisitions of certain oil and gas assets from Carrizo, certain proved reserves and associated assets from Titan, Equal and DTE, while APL completed the Cardinal Acquisition (see Note 4). The fair value measurements of assets acquired and liabilities assumed for each of these acquisitions are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The estimated fair values of the assets acquired and liabilities assumed in the Eagle Ford, Rangely and GeoMet acquisitions as of the respective acquisition dates, which are reflected in the Partnership’s consolidated balance sheet as of December 31, 2014, are subject to change as the final valuations for these transactions have not yet been completed, and such changes may be material. The fair values of natural gas and oil properties were measured using a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, as well as the respective natural gas, oil and natural gas liquids forward price curves. The fair values of the asset retirement obligations were measured under the Partnership’s and ARP’s existing methodology for recognizing an estimated liability for the plugging and abandonment of its gas and oil wells (see Note 8). These inputs require significant judgments and estimates by the Partnership’s and ARP’s management at the time of the valuations and are subject to change. | ||||||||||||||||||||||||||||
In February 2012, APL acquired a gas gathering system and related assets for an initial net purchase price of $19.0 million. APL agreed to pay up to an additional $12.0 million in contingent payments, payable in two equal amounts, if certain volumes are achieved on the acquired gathering system within a specified time period. Sufficient volumes were achieved in December 2012, and APL paid the first contingent payment of $6.0 million in January 2013. As of December 31, 2014, the fair value of the remaining contingent payment resulted in a $6.0 million long-term liability, which was recorded within other long-term liabilities on the Partnership’s consolidated balance sheets. The range of the undiscounted amount APL could pay related to the remaining contingent payment is up to $6.0 million. | ||||||||||||||||||||||||||||
Income_Taxes
Income Taxes | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
Income Tax Disclosure [Abstract] | ||||||||||
Income Taxes | NOTE 12 – INCOME TAXES | |||||||||
APL owns a taxable subsidiary. The components of the federal and state income tax expense (benefit) for APL’s taxable subsidiary for the years ended December 31, 2014, 2013 and 2012 are as follows (in thousands): | ||||||||||
Years Ended December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
Income tax expense (benefit) : | ||||||||||
Federal | $ | -2,128 | $ | -2,024 | $ | 158 | ||||
State | -248 | -236 | 18 | |||||||
Total income tax expense (benefit) | $ | -2,376 | $ | -2,260 | $ | 176 | ||||
As of December 31, 2014 and 2013, APL had non-current net deferred income tax liabilities of $30.9 million and $33.3 million, respectively. The components of net deferred tax liabilities as of December 31, 2014 and 2013 consist of the following (in thousands): | ||||||||||
December 31, | December 31, | |||||||||
2014 | 2013 | |||||||||
Deferred tax assets: | ||||||||||
Net operating loss tax carryforwards and alternative minimum tax credits | $ | 17,269 | $ | 14,900 | ||||||
Deferred tax liabilities: | ||||||||||
Excess of asset carrying value over tax basis | -48,183 | -48,190 | ||||||||
Net deferred tax liabilities | $ | -30,914 | $ | -33,290 | ||||||
As of December 31, 2014, APL had net operating loss carry forwards for federal income tax purposes of approximately $44.7 million, which expire at various dates from 2029 to 2034. APL believes it more likely than not that the deferred tax asset will be fully utilized. APL expects all goodwill recorded to be deductible for tax purposes. |
Certain_Relationships_and_Rela
Certain Relationships and Related Party Transactions | 12 Months Ended |
Dec. 31, 2014 | |
Related Party Transactions [Abstract] | |
Certain Relationships And Related Party Transactions | NOTE 13 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS |
Relationship with Drilling Partnerships. ARP conducts certain activities through, and a portion of its revenues are attributable to, the Drilling Partnerships. ARP serves as general partner and operator of the Drilling Partnerships and assumes customary rights and obligations for the Drilling Partnerships. As the general partner, ARP is liable for the Drilling Partnerships’ liabilities and can be liable to limited partners of the Drilling Partnerships if it breaches its responsibilities with respect to the operations of the Drilling Partnerships. ARP is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Drilling Partnerships’ revenues and costs and expenses according to the respective partnership agreements. | |
Relationship between ARP and APL. In the Chattanooga Shale, a portion of the natural gas produced by ARP is gathered and processed by APL. For the years ended December 31, 2014, 2013 and 2012, $0.3 million, $0.3 million and $0.4 million of gathering fees paid by ARP to APL were eliminated in consolidation. | |
In addition, in Lycoming County, Pennsylvania, APL agreed to provide assistance in the design and construction management services for ARP with respect to a pipeline. ARP reimbursed approximately $1.8 million to APL for the year ended December 31, 2013. | |
Relationship with Resource America, Inc. In connection with the issuance of the Term Facility, CVC Credit Partners, LLC (“CVC”), which is a joint-venture between Resource America, Inc. and an unrelated third party private equity firm, was allocated an aggregate of $12.5 million of the Term Facility. The Partnership’s Chief Executive Officer and President is Chairman of the board of directors of Resource America, Inc., and the Partnership’s Executive Chairman of the General Partner’s board of directors is Chief Executive Officer and President and Resource America, Inc. |
Commitments_and_Contingencies
Commitments and Contingencies | 12 Months Ended | ||||
Dec. 31, 2014 | |||||
Commitments And Contingencies Disclosure [Abstract] | |||||
Commitments and Contingencies | NOTE 14 — COMMITMENTS AND CONTINGENCIES | ||||
General Commitments | |||||
The Partnership leases office space and equipment under leases with varying expiration dates. Rental expense was $32.6 million, $24.4 million and $9.6 million for the years ended December 31, 2014, 2013 and 2012, respectively. Future minimum rental commitments for the next five years are as follows (in thousands): | |||||
Years Ended December 31, | |||||
2015 | $ | 16,524 | |||
2016 | 11,917 | ||||
2017 | 8,216 | ||||
2018 | 7,314 | ||||
2019 | 1,951 | ||||
Thereafter | 3,415 | ||||
$ | 49,337 | ||||
ARP is the managing general partner of the Drilling Partnerships and has agreed to indemnify each investor partner from any liability that exceeds such partner’s share of Drilling Partnership assets. ARP has structured certain Drilling Partnerships to allow limited partners to have the right to present their interests for purchase. Generally for Drilling Partnerships with this structure, ARP is not obligated to purchase more than 5% to 10% of the units in any calendar year, no units may be purchased during the first five years after closing for the Drilling Partnership, and ARP may immediately suspend the presentment structure for a Drilling Partnership by giving notice to the limited partners that it does not have adequate liquidity for redemptions. In accordance with the Drilling Partnership agreement, the purchase price for limited partner interests would generally be based upon a percentage of the present value of future cash flows allocable to the interest, discounted at 10%, as of the date of presentment, subject to estimated changes by ARP to reflect current well performance, commodity prices and production costs, among other items. Based on its historical experience, as of December 31, 2014, the management of ARP believes that any such estimated liability for redemptions of limited partner interests in Drilling Partnerships which allow such transactions would not be material. | |||||
While its historical structure has varied, ARP has generally agreed to subordinate a portion of its share of Drilling Partnership gas and oil production revenue, net of corresponding production costs and up to a maximum of 50% of unhedged revenue, from certain Drilling Partnerships for the benefit of the limited partner investors until they have received specified returns, typically from 10% to 12% per year determined on a cumulative basis, over a specified period, typically the first five to eight years, in accordance with the terms of the partnership agreements. ARP periodically compares the projected return on investment for limited partners in a Drilling Partnership during the subordination period, based upon historical and projected cumulative gas and oil production revenue and expenses, with the return on investment subject to subordination agreed upon within the Drilling Partnership agreement. If the projected return on investment falls below the agreed upon rate, ARP recognizes subordination as an estimated reduction of its pro-rata share of gas and oil production revenue, net of corresponding production costs, during the current period in an amount that will achieve the agreed upon investment return, subject to the limitation of 50% of unhedged cumulative net production revenues over the subordination period. For Drilling Partnerships for which ARP has recognized subordination in a historical period, if projected investment returns subsequently reflect that the agreed upon limited partner investment return will be achieved during the subordination period, ARP will recognize an estimated increase in its portion of historical cumulative gas and oil net production, subject to a limitation of the cumulative subordination previously recognized. For the years ended December 31, 2014, 2013, and 2012, $5.3 million, $9.6 million, and $6.3 million, respectively, of ARP’s gas and oil production revenues, net of corresponding production costs, from certain Drilling Partnerships were subordinated, which reduced gas and oil production revenues and expenses. | |||||
The Partnership and its subsidiaries are party to employment agreements with certain executives that provide compensation and certain other benefits. The agreements also provide for severance payments under certain circumstances. | |||||
In connection with the Eagle Ford Acquisition (see Note 4), ARP guaranteed the Development Subsidiary’s deferred purchase obligation, whereby ARP provided a guaranty of timely payment of the deferred portion of the purchase price that is to be paid by the Development Subsidiary. Pursuant to the agreement between ARP and the Development Subsidiary, ARP will have the right to receive some or all of the assets acquired by the Development Subsidiary in the event of its failure to contribute its portion of any deferred payments. The deferred purchase obligation is included within accrued liabilities on the Partnership’s consolidated balance sheet at December 31, 2014. | |||||
In connection with ARP’s GeoMet Acquisition (see Note 4), ARP acquired certain long-term annual firm transportation obligations. Estimated fixed and determinable portions of ARP’s firm transportation obligations as of December 31, 2014 were as follows: 2015— $2.5 million; 2016— $2.4 million; 2017— $2.0 million; 2018— $1.8 million; 2019— $1.8 million; thereafter— $6.9 million. | |||||
In connection with ARP’s EP Energy Acquisition (see Note 4), ARP acquired certain long-term annual firm transportation obligations. Estimated fixed and determinable portions of ARP’s firm transportation obligations as of December 31, 2014 were as follows: 2015— $8.3 million; 2016— $2.1 million; and 2017 to 2019— none. | |||||
APL has certain long-term unconditional purchase obligations and commitments, primarily transportation contracts. These agreements provide for transportation services to be used in the ordinary course of APL’s operations. Transportation fees paid related to these contracts, including minimum shipment payments, were $28.3 million, $34.8 million and $10.5 million for the years ended December 31, 2014, 2013 and 2012, respectively. The unrecorded future fixed and determinable portion of the obligations as of December 31, 2014 was as follows: 2015 - $20.7 million; 2016 to 2017 - $23.9 million per year; 2018 - $21.8 million; and 2019 - $16.9 million. | |||||
As of December 31, 2014, the Partnership and its subsidiaries are committed to expend approximately $198.0 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades. | |||||
Legal Proceedings | |||||
The Partnership and its subsidiaries are party to various routine legal proceedings arising in the ordinary course of its business. The Partnership does not believe that any of these actions, individually or in the aggregate, will have a material adverse effect on is financial condition or results of operations. | |||||
Since the announcement on October 13, 2014 of the Merger and the APL Merger (see Note 19), the Partnership, APL and the other parties to the Atlas Mergers have been named as defendants in putative stockholder class action complaints challenging the transactions. Although Atlas Energy Group, LLC (“Atlas Energy Group”) has not been named as a defendant in these complaints, certain of the Partnership’s expected officers have been named as defendants, and the litigation could delay or impede the consummation of the separation and distribution. | |||||
As of February 24, 2015, the Partnership is aware that it, its general partner, TRC, GP Merger Sub (a subsidiary of TRC created in connection with the Merger), and the members of the Partnership’s board, including Edward E. Cohen and Jonathan Z. Cohen, New Atlas’s expected Chief Executive Officer and Executive Chairman, have been named as defendants in two putative stockholder class action complaint challenging the Atlas merger filed in the Court of Common Pleas for Allegheny County, Pennsylvania. These cases are captioned: Rick Kane v. Atlas Energy, L.P., et al., Case No. GD-14-019658 (Pa. Ct. Comm. Pls. Oct. 22, 2013) and Jeffrey Ayers v. Atlas Energy, L.P., et al., Case No. GD-14-020255 (Pa. Ct. Comm. Pls. Nov. 3, 2014) (the “ATLS Lawsuits”). The ATLS Lawsuits were consolidated as In re Atlas Energy, L.P. Unitholder Litigation, Case No. GD-14-019658, in the Court of Common Pleas for Allegheny County, Pennsylvania (the “Consolidated ATLS Lawsuit”), although the Kane litigation has since been voluntarily dismissed. The Partnership is also aware that APL, APL’s general partner, the Partnership, TRC, TRP, TRP GP, MLP Merger Sub (a subsidiary of TRP created in connection with the APL Merger), and the members of the APL board, including Edward E. Cohen and Jonathan Z. Cohen, New Atlas’s expected Chief Executive Officer and Executive Chairman, have been named as defendants in five putative stockholder class action complaints challenging the APL Merger, four filed in the Court of Common Pleas for Allegheny County, Pennsylvania and one filed in the District Court of Tulsa County, Oklahoma. These cases are captioned: Michael Envin v. Atlas Pipeline Partners, L.P., et al., Case No. GD-14-019245 (Pa. Ct. Comm. Pls. Oct. 17, 2013), Greenthal Living Trust U/A 01/26/88 v. Atlas Pipeline Partners, L.P., et al., Case No. GD-14-020108 (Pa. Ct. Comm. Pls. Oct. 31, 2014), Mike Welborn v. Atlas Pipeline Partners, L.P., et al., Case No. GD-14-020729 (Pa. Ct. Comm. Pls. Nov. 10, 2014), Irving Feldbaum v. Atlas Pipeline Partners, L.P., et al., Case No. GD-14-22208 (Pa. Ct. Comm. Pls. Dec. 5, 2014) and William B. Federman Family Wealth Preservation Trust v. Atlas Pipeline Partners, L.P., et al., Case No. CJ-2014-04087 (Okla. D. Ct. Oct. 28, 2014) (the “APL Lawsuits” and, together with the ATLS Lawsuits, the “Lawsuits”). The Evnin, Greenthal, Welborn and Feldbaum APL Lawsuits have been consolidated as In re Atlas Pipeline Partners, L.P. Unitholder Litigation, Case No. GD-14-019245, in the Court of Common Pleas for Allegheny County, Pennsylvania (the “Consolidated APL Lawsuit”). The Federman lawsuit has subsequently been voluntarily dismissed. | |||||
The Lawsuits generally allege that the individual defendants breached their fiduciary duties and/or contractual obligations by, among other things, failing to obtain sufficient value for the ATLS and APL unitholders in, respectively, each of the Merger and the APL Merger, agreeing to certain terms in each of the merger agreements that allegedly restrict the defendants’ ability to obtain a more favorable offer, favoring their self-interests over the interests of ATLS and APL unitholders, and omitting material information from the Proxy Statements. The Lawsuits further allege that those breaches were aided and abetted by some combination of the Partnership, APL, TRC, TRP, or various affiliates of those entities named above. The plaintiffs seek, among other things, injunctive relief, unspecified compensatory and/or rescissory damages, attorney’s fees, other expenses, and costs. | |||||
Additionally, a putative stockholder class action and derivative lawsuit, captioned Inspired Investors v. Perkins et. al., Case No. 2015-04961, was filed purportedly on behalf of Targa Resources shareholders in the District Court of Harris County, Texas on January 28, 2015 and amended on February 23, 2015. The lawsuit names the Partnership and the individual members of the board of directors of TRC as defendants and TRC as a nominal defendant. The lawsuit generally alleges that the individual defendants breached their fiduciary duties by, among other things, approving the Merger and omitting purportedly material information from the registration statement on Form S-4 that TRC initially filed with the SEC on November 20, 2014 and most recently amended on January 22, 2015. The lawsuit seeks, among other things, injunctive relief, compensatory and rescissory damages, attorney’s fees, interest and costs. | |||||
All of the above referenced lawsuits, except for the January 2015 lawsuit and the two lawsuits that have been voluntarily dismissed, were settled, subject to court approval, pursuant to memoranda of understanding executed in February 2015, which are conditioned upon, among other things, the execution of an appropriate stipulations of settlement. The stipulations of settlement will be subject to customary conditions, including, among other things, judicial approval of the proposed settlements contemplated by the memoranda of understanding. There can be no assurance that the parties will ultimately enter into stipulations of settlement, that the court will approve the settlements, that the settlements will not be terminated according to their terms or that some unitholders will not opt-out of the settlements. | |||||
Issuances_of_Units
Issuances of Units | 12 Months Ended |
Dec. 31, 2014 | |
Proceeds From Issuance Or Sale Of Equity [Abstract] | |
Issuances of Units | NOTE 15 —ISSUANCES OF UNITS |
The Partnership | |
The Partnership recognizes gains on its subsidiaries’ equity transactions as credits to partners’ capital on its consolidated balance sheets rather than as income on its consolidated statements of operations. These gains represent the Partnership’s portion of the excess net offering price per unit of each of its subsidiaries’ common units over the book carrying amount per unit. | |
Purchase of ARP Preferred Units. | |
In July 2013, in connection with ARP’s EP Energy Acquisition (see Note 4), the Partnership purchased 3,746,986 of ARP’s Class C convertible preferred units, at a negotiated price per unit of $23.10, for proceeds of $86.6 million. The Class C preferred units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act. The Class C preferred units pay cash distributions in an amount equal to the greater of (i) $0.51 per unit and (ii) the distributions payable on each common unit at each declared quarterly distribution date. The initial Class C preferred distribution was paid for the quarter ended September 30, 2013. The Class C preferred units have no voting rights, except as set forth in the certificate of designation for the Class C preferred units, which provides, among other things, that the affirmative vote of 75% of the Class C Preferred Units is required to repeal such certificate of designation. Holders of the Class C preferred units have the right to convert the Class C preferred units on a one-for-one basis, in whole or in part, into common units at any time before July 31, 2016. Unless previously converted, all Class C preferred units will convert into common units on July 31, 2016. Upon issuance of the Class C preferred units, the Partnership, as purchaser of the Class C preferred units, also received 562,497 warrants to purchase ARP’s common units at an exercise price equal to the face value of the Class C preferred units. The warrants were exercisable beginning October 29, 2013 into an equal number of ARP common units at an exercise price of $23.10 per unit, subject to adjustments provided therein. The warrants will expire on July 31, 2016. | |
Atlas Resource Partners | |
Equity Offerings | |
In October 2014, in connection with the Eagle Ford Acquisition (see Note 4), ARP issued 3,200,000 8.625% ARP Class D Preferred Units at a public offering price of $25.00 per Class D ARP Preferred Unit, yielding net proceeds of approximately $77.4 million from the offering, after deducting underwriting discounts and estimated offering expenses. ARP used the net proceeds from the offering to fund a portion of the Eagle Ford Acquisition. On January 15, 2015, ARP paid an initial quarterly distribution of $0.616927 per unit for the extended period from October 2, 2014 through January 14, 2015 to holders of record as of January 2, 2015 (see Note 16). ARP will pay future cumulative distributions on a quarterly basis, at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference. | |
The Class D ARP Preferred Units rank senior to ARP’s common units and Class C ARP convertible preferred units with respect to the payment of distributions and distributions upon a liquidation event and equal with ARP’s Class B convertible preferred units. The Class D ARP Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by ARP or converted into its common units in connection with a change in control. At any time on or after October 15, 2019, ARP may, at its option, redeem the Class D ARP Preferred Units in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, ARP may redeem the Class D ARP Preferred Units following certain changes of control, as described in the Certificate of Designation. If ARP does not exercise this redemption option upon a change of control, then holders of the Class D ARP Preferred Units will have the option to convert the Class D ARP Preferred Units into a number of ARP common units per Class D unit as set forth in the Certificate of Designation. If ARP exercises any of its redemption rights relating to the Class D ARP Preferred Units, the holders of such Class D ARP Preferred Units will not have the conversion right described above with respect to the Class D ARP Preferred Units called for redemption. | |
In August 2014, ARP entered into an equity distribution agreement with Deutsche Bank Securities Inc., as representative of the several banks named therein (the “Agents”). Pursuant to the equity distribution agreement, ARP may sell from time to time through the Agents common units representing limited partner interests of ARP having an aggregate offering price of up to $100.0 million. Sales of common units, if any, may be made in negotiated transactions or transactions that are deemed to be “at-the-market” offerings as defined in Rule 415 of the Securities Act, including sales made directly on the New York Stock Exchange, the existing trading market for the common units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. ARP will pay each of the Agents a commission, which in each case shall not be more than 2.0% of the gross sales price of common units sold through such Agent. Under the terms of the equity distribution agreement, ARP may also sell common units from time to time to any Agent as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to an Agent as principal would be pursuant to the terms of a separate terms agreement between ARP and such Agent. As of December 31, 2014, no units have been sold under this program. | |
In May 2014, in connection with the closing of the Rangely Acquisition (see Note 4), ARP issued 15,525,000 of its common limited partner units (including 2,025,000 units pursuant to an over-allotment option) in a public offering at a price of $19.90 per unit, yielding net proceeds of approximately $297.3 million. The units were registered under the Securities Act, pursuant to a shelf registration statement on Form S-3, which was automatically effective on the filing date of February 3, 2014. | |
In March 2014, in connection with the GeoMet Acquisition (see Note 4), ARP issued 6,325,000 of its common limited partner units (including 825,000 units pursuant to an over-allotment option) in a public offering at a price of $21.18 per unit, yielding net proceeds of approximately $129.0 million. The units were registered under the Securities Act, pursuant to a shelf registration statement on Form S-3, which was automatically effective on the filing date of February 3, 2014. | |
In July 2013, in connection with the closing of the EP Energy Acquisition (see Note 4), ARP issued 3,749,986 of its newly created Class C convertible preferred units to ATLS, at a negotiated price per unit of $23.10, for proceeds of $86.6 million. The Class C preferred units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act. The Class C preferred units pay cash distributions in an amount equal to the greater of (i) $0.51 per unit and (ii) the distributions payable on each common unit at each declared quarterly distribution date. The initial Class C preferred distribution was paid for the quarter ending September 30, 2013. The Class C preferred units have no voting rights, except as set forth in the certificate of designation for the Class C preferred units, which provides, among other things, that the affirmative vote of 75% of the Class C Preferred Units is required to repeal such certificate of designation. Holders of the Class C preferred units have the right to convert the Class C preferred units on a one-for-one basis, in whole or in part, into common units at any time before July 31, 2016. Unless previously converted, all Class C preferred units will convert into common units on July 31, 2016. Upon issuance of the Class C preferred units, ATLS, as purchaser of the Class C preferred units, received 562,497 warrants to purchase ARP‘s common units at an exercise price equal to the face value of the Class C preferred units. The warrants were exercisable beginning October 29, 2013 into an equal number of common units of ARP at an exercise price of $23.10 per unit, subject to adjustments provided therein. The warrants will expire on July 31, 2016. | |
Upon issuance of the Class C preferred units and warrants on July 31, 2013, ARP entered into a registration rights agreement pursuant to which it agreed to file a registration statement with the SEC to register the resale of the common units issuable upon conversion of the Class C preferred units and upon exercise of the warrants. ARP agreed to use commercially reasonable efforts to file such registration statement within 90 days of the conversion of the Class C preferred units into common units or the exercise of the warrants. | |
In June 2013, in connection with the EP Energy Acquisition (see Note 4), ARP sold an aggregate of 14,950,000 of its common limited partner units (including 1,950,000 units pursuant to an over-allotment option) in a public offering at a price of $21.75 per unit, yielding net proceeds of approximately $313.1 million. ARP utilized the net proceeds from the sale to repay the outstanding balance under its revolving credit facility (see Note 9). | |
In May 2013, ARP entered into an equity distribution agreement with Deutsche Bank Securities Inc., as representative of several banks. Pursuant to the equity distribution agreement, ARP could sell, from time to time through the agents, common units having an aggregate offering price of up to $25.0 million. During the year ended December 31, 2013, ARP issued 309,174 common limited partner units under the equity distribution program for net proceeds of $6.9 million, net of $0.4 million in commissions paid. ARP utilized the net proceeds from the sale to repay borrowings outstanding under its revolving credit facility. ARP terminated this equity distribution agreement effective December 27, 2013. | |
In November and December 2012, in connection with entering into a purchase agreement to acquire certain producing wells and net acreage from DTE, ARP sold an aggregate of 7,898,210 of its common limited partner units in a public offering at a price of $23.01 per unit, yielding net proceeds of approximately $174.5 million. ARP utilized the net proceeds from the sale to repay a portion of the outstanding balance under its revolving credit facility and $2.2 million under its then-existing term loan credit facility. | |
In July 2012, ARP completed the acquisition of certain proved reserves and associated assets in the Barnett Shale from Titan in exchange for 3.8 million ARP common units and 3.8 million newly-created convertible ARP Class B preferred units (which had an estimated collective value of $193.2 million, based upon the closing price of ARP’s publicly traded common units as of the acquisition closing date), as well as $15.4 million in cash for closing adjustments (see Note 4). The Class B preferred units are voluntarily convertible to common units on a one-for-one basis within three years of the acquisition closing date at a strike price of $26.03 plus all unpaid preferred distributions per unit, and will be mandatorily converted to common units on the third anniversary of the issuance. While outstanding, the preferred units will receive regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution. | |
ARP entered into a registration rights agreement pursuant to which it agreed to file a registration statement with the SEC by January 25, 2013 to register the resale of the ARP common units issued on the acquisition closing date and those issuable upon conversion of the Class B preferred units. ARP agreed to use its commercially reasonable efforts to have the registration statement declared effective by March 31, 2013, and to cause the registration statement to be continuously effective until the earlier of (i) the date as of which all such common units registered thereunder are sold by the holders and (ii) one year after the date of effectiveness. On September 19, 2012, ARP filed a registration statement with the SEC in satisfaction of the registration requirements of the registration rights agreement, and the registration statement was declared effective by the SEC on October 2, 2012. On December 23, 2014, 3,796,900 of the ARP Class B preferred units were voluntarily converted into common units. | |
In April 2012, ARP completed the acquisition of certain oil and gas assets from Carrizo (see Note 4). To partially fund the acquisition, ARP sold 6.0 million of its common units in a private placement at a negotiated purchase price per unit of $20.00, for net proceeds of $119.5 million, of which $5.0 million was purchased by certain executives of the Partnership. The common units issued by ARP are subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement stipulated that ARP would (a) file a registration statement with the SEC by October 30, 2012 and (b) cause the registration statement to be declared effective by the SEC by December 31, 2012. On July 11, 2012, ARP filed a registration statement with the SEC for the common units subject to the registration rights agreement in satisfaction of one of the requirements of the registration rights agreement noted previously. On August 28, 2012, the registration statement was declared effective by the SEC. | |
At December 31, 2014 and 2013, in connection with the issuance of ARP’s common units, the Partnership recorded gains of $40.5 million and $27.3 million within partners’ capital and a corresponding decrease in non-controlling interests on its consolidated balance sheet and consolidated statement of partners’ capital. | |
ARP Common Unit Distribution | |
In February 2012, the board of directors of ATLS’ general partner approved the distribution of approximately 5.24 million of the Partnership’s common limited partner units which were distributed on March 13, 2012 to ATLS’ unitholders using a ratio of 0.1021 Partnership common limited partner units for each of ATLS’ common units owned on the record date of February 28, 2012. | |
Atlas Pipeline Partners | |
Equity Offerings | |
On May 12, 2014, APL entered into an Equity Distribution Agreement (the “2014 EDA”) with Citigroup, Wells Fargo Securities, LLC and MLV & Co. LLC, as sales agents. Pursuant to this program, APL may offer and sell from time to time through its sales agents, common units having an aggregate value up to $250.0 million. Sales are at market prices prevailing at the time of the sale. However, APL is currently restricted from selling common units by the APL merger agreement (see Note 19). | |
During the year ended December 31, 2014, APL issued 3,558,005 common units, under the 2014 EDA for proceeds of $121.6 million, net of $1.2 million in commissions paid to the sales agents. APL also received capital contributions from the Partnership, as general partner, of $2.5 million during the year ended December 31, 2014 to maintain its 2.0% general partner interest in APL. The net proceeds from the common unit offerings and General Partner contributions were utilized for general partnership purposes. | |
On March 17, 2014, APL issued 5,060,000 of its Class E APL Preferred Units to the public at an offering price of $25.00 per Class E APL Preferred Unit. APL received $122.3 million in net proceeds. The proceeds were used to pay down APL’s revolving credit facility. | |
APL made cumulative cash distributions on the Class E APL Preferred Units from the date of original issue, which were payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year. The initial distribution on the Class E APL Preferred Units was paid on July 15, 2014 in an amount equal to $0.67604 per unit, or approximately $3.4 million, representing the distribution for the period March 17, 2014 through July 14, 2014. Thereafter, APL paid cumulative distributions in cash on the Class E APL Preferred Units on a quarterly basis at a rate of $0.515625 per unit, or 8.25% per year. On October 15, 2014, APL paid a cash distribution of $2.6 million on its outstanding Class E APL Preferred Units, representing the cash distribution for the period from July 15, 2014 through October 14, 2014. On January 15, 2015, APL paid a cash distribution of $2.6 million on its outstanding Class E APL Preferred Units, representing the cash distribution for the period from October 15, 2014 through January 14, 2015. For the year ended December 31, 2014, APL allocated net income of $8.2 million to the Class E APL Preferred Units for the dividends earned during the period, which was recorded within income (loss) from non-controlling interests on the Partnership’s consolidated statements of operations. | |
On May 7, 2013, APL completed a private placement of $400.0 million of its Class D APL Preferred Units to third party investors, at a negotiated price per unit of $29.75, resulting in net proceeds of $397.7 million pursuant to the Class D preferred unit purchase agreement dated April 16, 2013 (the “Commitment Date”). The Partnership contributed $8.2 million to maintain its 2.0% general partnership interest upon the issuance of the Class D APL Preferred Units. APL used the proceeds to fund a portion of the purchase price of the TEAK Acquisition (see Note 4). The Class D APL Preferred Units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act. APL had the right to convert the Class D APL Preferred Units plus any unpaid distributions, in whole but not in part, beginning one year following their issuance, into common units. | |
The fair value of APL’s common units on the Commitment Date was $36.52 per unit, resulting in an embedded beneficial conversion discount (“discount”) on the Class D APL Preferred Units of $91.0 million. APL recognized the fair value of the Class D APL Preferred Units with the offsetting intrinsic value of the discount within non-controlling interests on the Partnership’s consolidated balance sheets as of December 31, 2014 and 2013. The discount is being accreted and recognized as imputed dividends over the term of the Class D APL Preferred Units as a reduction to APL’s net income attributable to the common limited partners and the Partnership, as general partner. APL’s Class D Preferred Units are presented combined with a net $16.0 million and $61.5 million unaccreted discount within non-controlling interests on the Partnership’s consolidated balance sheets as of December 31, 2014 and 2013, respectively. APL recorded $45.5 million and $29.5 million in the years ended December 31, 2014 and 2013, respectively, within income (loss) attributable to non-controlling interests on the Partnership’s consolidated statements of operations to recognize the accretion of the discount. | |
The Class D APL Preferred Units received distributions of additional Class D APL Preferred Units in each of the quarterly periods following their issuance in May 2013. The amount of the distribution was determined based upon the cash distribution per unit paid each quarter on APL’s common limited partner units plus a preferred yield premium. APL recorded Class D APL Preferred Unit distributions in kind of $42.6 million and $23.6 million for the years ended December 31, 2014 and 2013, respectively, within income (loss) attributable to non-controlling interests on the Partnership’s consolidated statements of operations. APL considers preferred unit distributions in kind to be a non-cash financing activity. | |
On January 22, 2015, APL exercised its right under the certificate of designation of the Class D APL Preferred Units (“Class D APL Certificate of Designation”) to convert all outstanding Class D APL Preferred Units and unpaid distributions into common limited partner units, based upon the Execution Date Unit Price of $29.75 per unit, as defined by the Class D APL Certificate of Designation. As a result of the conversion, 15,389,575 common limited partner units were issued. | |
In April 2013, APL sold 11,845,000 of its common units in a public offering at a price of $34.00 per unit, yielding net proceeds of $388.4 million after underwriting commissions and expenses. APL also received a capital contribution from the Partnership of $8.3 million during the year ended December 31, 2013, to maintain its 2.0% general partnership interest in APL. APL used the proceeds from this offering to fund a portion of the purchase price of the TEAK Acquisition (see Note 4). | |
In December 2012, APL sold 10,507,033 common units in a public offering at a price of $31.00 per unit, yielding net proceeds of approximately $319.3 million, including $6.7 million contributed by the Partnership to maintain its 2.0% general partner interest. APL utilized the net proceeds from the common unit offering to partially finance the Cardinal Acquisition (see Note 4). | |
In November 2012, APL entered into an equity distribution program with Citigroup. Pursuant to this program, APL offered and sold through Citigroup, as its sales agent, common units for $150.0 million. Sales were at market prices prevailing at the time of the sale. During the years ended December 31, 2013 and 2012, the Partnership issued 3,895,679 and 275,429 common units, respectively, under the equity distribution program for proceeds of $137.8 million and $8.7 million, respectively, net of $2.8 million and $0.2 million, respectively, in commissions incurred from Citigroup, and other expenses. APL also received capital contributions from the Partnership of $2.9 million and $0.2 million during the years ended December 31, 2013 and 2012, respectively, to maintain its 2.0% general partner interest in APL. The net proceeds from the common unit offering were utilized for general partnership purposes. | |
For the year ended December 31, 2014, in connection with the issuance of APL’s common units, the Partnership recorded a $2.7 million gain within partners’ capital and a corresponding decrease in non-controlling interests on its consolidated balance sheet and consolidated statement of partner’s capital. At December 31, 2013, in connection with the issuance of APL’s common units, the Partnership recorded an $11.9 million gain within partners’ capital and a corresponding decrease in non-controlling interests on its consolidated balance sheet and consolidated statement of partners’ capital. | |
Cash_Distributions
Cash Distributions | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||
Distributions Made To Members Or Limited Partners [Abstract] | |||||||||||||||||||
Cash Distributions | NOTE 16 – CASH DISTRIBUTIONS | ||||||||||||||||||
The Partnership has a cash distribution policy under which it distributes, within 50 days after the end of each quarter, all of its available cash (as defined in the partnership agreement) for that quarter to its common unitholders. Distributions declared by the Partnership for the period from January 1, 2012 through December 31, 2014 were as follows (in thousands, except per unit amounts): | |||||||||||||||||||
Date Cash Distribution Paid | For Quarter | Cash Distribution per | Total Cash Distributions | ||||||||||||||||
Ended | Common Limited | Paid to Common | |||||||||||||||||
Partner Unit | Limited Partners | ||||||||||||||||||
March 31, 2012 | $ | 0.25 | $ | 12,830 | |||||||||||||||
May 18, 2012 | |||||||||||||||||||
August 17, 2012 | 30-Jun-12 | $ | 0.25 | $ | 12,831 | ||||||||||||||
November 19, 2012 | September 30, 2012 | $ | 0.27 | $ | 13,866 | ||||||||||||||
February 19, 2013 | 31-Dec-12 | $ | 0.3 | $ | 15,410 | ||||||||||||||
May 20, 2013 | 31-Mar-13 | $ | 0.31 | $ | 15,928 | ||||||||||||||
August 19, 2013 | 30-Jun-13 | $ | 0.44 | $ | 22,611 | ||||||||||||||
19-Nov-13 | September 30, 2013 | $ | 0.46 | $ | 23,649 | ||||||||||||||
19-Feb-14 | December 31, 2013 | $ | 0.46 | $ | 23,681 | ||||||||||||||
20-May-14 | March 31, 2014 | $ | 0.46 | $ | 23,865 | ||||||||||||||
19-Aug-14 | 30-Jun-14 | $ | 0.49 | $ | 25,435 | ||||||||||||||
20-Nov-14 | 30-Sep-14 | $ | 0.52 | $ | 27,015 | ||||||||||||||
On January 28, 2015, the Partnership declared a cash distribution of $0.52 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2014. The $27.1 million distribution was paid on February 19, 2015 to unitholders of record at the close of business on February 9, 2015. | |||||||||||||||||||
ARP Cash Distributions. In January 2014, ARP’s board of directors approved the modification of its cash distribution payment practice to a monthly cash distribution program whereby it distributes all of its available cash (as defined in the partnership agreement) for that month to its unitholders within 45 days from the month end. Prior to that, ARP paid quarterly cash distributions within 45 days from the end of each calendar quarter. If ARP’s common unit distributions in any quarter exceed specified target levels, the Partnership will receive between 13% and 48% of such distributions in excess of the specified target levels. | |||||||||||||||||||
Distributions declared by ARP for the period from January 1, 2013 through December 31, 2014 were as follows (in thousands, except per unit amounts): | |||||||||||||||||||
Date Cash | For Quarter/Month | Cash | Total Cash | Total Cash | Total Cash | ||||||||||||||
Distribution | Ended | Distribution | Distribution | Distribution | Distribution | ||||||||||||||
Paid | per Common | to Common | To | to the General | |||||||||||||||
Limited | Limited | Preferred | Partner’s | ||||||||||||||||
Partner Unit | Partners | Limited | Class | ||||||||||||||||
Partners | A Units | ||||||||||||||||||
May 15, 2012 | March 31, 2012 | $ | 0.12 | -1 | $ | 3,144 | $ | — | $ | 64 | |||||||||
August 14, 2012 | 30-Jun-12 | $ | 0.4 | $ | 12,891 | $ | — | $ | 263 | ||||||||||
November 14, 2012 | 30-Sep-12 | $ | 0.43 | $ | 15,510 | $ | 1,652 | $ | 350 | ||||||||||
February 14, 2013 | 31-Dec-12 | $ | 0.48 | $ | 21,107 | $ | 1,841 | $ | 618 | ||||||||||
May 15, 2013 | 31-Mar-13 | $ | 0.51 | $ | 22,428 | $ | 1,957 | $ | 946 | ||||||||||
August 14, 2013 | 30-Jun-13 | $ | 0.54 | $ | 32,097 | $ | 2,072 | $ | 1,884 | ||||||||||
November 14, 2013 | September 30, 2013 | $ | 0.56 | $ | 33,291 | $ | 4,248 | $ | 2,443 | ||||||||||
14-Feb-14 | 31-Dec-13 | $ | 0.58 | $ | 34,489 | $ | 4,400 | $ | 2,891 | ||||||||||
17-Mar-14 | 31-Jan-14 | $ | 0.1933 | $ | 12,718 | $ | 1,467 | $ | 1,055 | ||||||||||
14-Apr-14 | 28-Feb-14 | $ | 0.1933 | $ | 12,719 | $ | 1,466 | $ | 1,055 | ||||||||||
15-May-14 | 31-Mar-14 | $ | 0.1933 | $ | 12,719 | $ | 1,466 | $ | 1,054 | ||||||||||
13-Jun-14 | 30-Apr-14 | $ | 0.1933 | $ | 15,752 | $ | 1,466 | $ | 1,279 | ||||||||||
15-Jul-14 | 31-May-14 | $ | 0.1933 | $ | 15,752 | $ | 1,466 | $ | 1,279 | ||||||||||
14-Aug-14 | 30-Jun-14 | $ | 0.1966 | $ | 16,029 | $ | 1,492 | $ | 1,377 | ||||||||||
12-Sep-14 | 31-Jul-14 | $ | 0.1966 | $ | 16,028 | $ | 1,493 | $ | 1,378 | ||||||||||
15-Oct-14 | 31-Aug-14 | $ | 0.1966 | $ | 16,032 | $ | 1,491 | $ | 1,378 | ||||||||||
14-Nov-14 | 30-Sep-14 | $ | 0.1966 | $ | 16,032 | $ | 1,492 | $ | 1,378 | ||||||||||
15-Dec-14 | 31-Oct-14 | $ | 0.1966 | $ | 16,033 | $ | 1,491 | $ | 1,378 | ||||||||||
14-Jan-15 | 30-Nov-14 | $ | 0.1966 | $ | 16,779 | $ | 745 | -2 | $ | 1,378 | |||||||||
-1 | Represents a pro-rated cash distribution of $0.40 per common limited partner unit for the period from March 5, 2012, the date the Partnership’s exploration and production assets were transferred to ARP, to March 31, 2012. | ||||||||||||||||||
-2 | Excludes ARP’s initial Class D preferred unit quarterly distribution (see Note 15). | ||||||||||||||||||
At December 31, 2014, ARP had 3.2 million of its 8.625% Class D ARP Preferred Units outstanding (see Note 15). On January 15, 2015, ARP paid an initial quarterly distribution of $0.616927 per unit for the extended period from October 2, 2014 through January 14, 2015 to holders of record as of January 2, 2015. ARP will pay future cumulative distributions on a quarterly basis, at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference. | |||||||||||||||||||
On January 28, 2015, ARP declared a monthly distribution of $0.1966 per common unit for the month of December 31, 2014. The $18.9 million distribution, including $1.4 million and $0.7 million to the Partnership as general partner and preferred limited partners, respectively, was paid on February 13, 2015 to unitholders of record at the close of business on February 9, 2015. | |||||||||||||||||||
On February 23, 2015, ARP declared a monthly distribution of $0.1083 per common unit for the month of January 2015. The $9.9 million distribution, including $0.2 million and $0.4 million to the Partnership as general partner and preferred limited partners, respectively, will be paid on March 17, 2015 to unitholders of record at the close of business on March 10, 2015. | |||||||||||||||||||
APL Cash Distributions. APL is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter to its common unitholders and the Partnership, as general partner. If APL’s common unit distributions in any quarter exceed specified target levels, the Partnership will receive between 13% and 48% of such distributions in excess of the specified target levels. | |||||||||||||||||||
Common unit and general partner distributions declared by APL for the period from January 1, 2012 through December 31, 2014 were as follows (in thousands, except per unit amounts): | |||||||||||||||||||
Date Cash Distribution Paid | For Quarter | APL Cash | Total APL Cash | Total APL Cash | |||||||||||||||
Ended | Distribution | Distribution to | Distribution to | ||||||||||||||||
per Common | Common | the General | |||||||||||||||||
Limited | Limited | Partner | |||||||||||||||||
Partner Unit | Partners | ||||||||||||||||||
March 31, 2012 | $ | 0.56 | $ | 30,030 | $ | 2,217 | |||||||||||||
May 15, 2012 | |||||||||||||||||||
August 14, 2012 | 30-Jun-12 | $ | 0.56 | $ | 30,085 | $ | 2,221 | ||||||||||||
November 14, 2012 | September 30, 2012 | $ | 0.57 | $ | 30,641 | $ | 2,409 | ||||||||||||
February 14, 2013 | 31-Dec-12 | $ | 0.58 | $ | 37,442 | $ | 3,117 | ||||||||||||
31-Mar-13 | $ | 0.59 | $ | 45,382 | $ | 3,980 | |||||||||||||
May 15, 2013 | |||||||||||||||||||
August 14, 2013 | 30-Jun-13 | $ | 0.62 | $ | 48,165 | $ | 5,875 | ||||||||||||
November 14, 2013 | 30-Sep-13 | $ | 0.62 | $ | 49,298 | $ | 6,013 | ||||||||||||
14-Feb-14 | 31-Dec-13 | $ | 0.62 | $ | 49,969 | $ | 6,095 | ||||||||||||
31-Mar-14 | $ | 0.62 | $ | 49,998 | $ | 6,099 | |||||||||||||
May 15, 2014 | |||||||||||||||||||
August 14, 2014 | 30-Jun-14 | $ | 0.63 | $ | 51,781 | $ | 7,055 | ||||||||||||
November 14, 2014 | 30-Sep-14 | $ | 0.64 | $ | 54,080 | $ | 8,115 | ||||||||||||
On January 9, 2015, APL declared a cash distribution of $0.64 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2013. The $62.2 million distribution, including $8.1 million to the Partnership as general partner, was paid on February 13, 2015 to unitholders of record at the close of business on January 21, 2015. | |||||||||||||||||||
On January 15, 2015, APL paid a cash distribution of $0.515625 per unit, or approximately $2.6 million, on its outstanding Class E APL Preferred Units, representing the cash distribution for the period from October 15, 2014 through January 14, 2015 (see Note 15). |
Benefit_Plans
Benefit Plans | 12 Months Ended | |||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | ||||||||||||||||||||||||
Benefit Plans | NOTE 17 — BENEFIT PLANS | |||||||||||||||||||||||
Partnership Rabbi Trust | ||||||||||||||||||||||||
In 2011, the Partnership established an excess 401(k) plan relating to certain executives. In connection with the plan, the Partnership established a “rabbi” trust for the contributed amounts. At December 31, 2014 and 2013, the Partnership reflected $3.9 million and $3.7 million, respectively, related to the value of the rabbi trust within other assets, net on its consolidated balance sheets (see Note 7), and recorded corresponding liabilities of $3.9 million and $3.7 million, as of the same dates within other long-term liabilities on its consolidated balance sheets. During the year ended December 31, 2014, the Partnership distributed $1.8 million to participants related to the rabbi trust. No amounts were distributed during the year ended December 31, 2013. | ||||||||||||||||||||||||
2010 Long-Term Incentive Plan | ||||||||||||||||||||||||
The Board of Directors of the Partnership’s general partner (the “General Partner”) approved and adopted the Partnership’s 2010 Long-Term Incentive Plan (“2010 LTIP”) effective February 2011. The 2010 LTIP provides equity incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for the Partnership. The 2010 LTIP is administered by a committee consisting of the Board or committee of the Board or board of an affiliate appointed by the Board (the “LTIP Committee”), which is the Compensation Committee of the General Partner’s board of directors. Under the 2010 LTIP, the LTIP Committee may grant awards of phantom units, restricted units or unit options for an aggregate of 5,763,781 common limited partner units. At December 31, 2014, the Partnership had 4,911,209 phantom units and unit options outstanding under the 2010 LTIP, with 283,650 phantom units and unit options available for grant. | ||||||||||||||||||||||||
In the case of awards held by eligible employees, following a “change in control”, as defined in the 2010 LTIP, upon the eligible employee’s termination of employment without “cause”, as defined in the 2010 LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the option. Upon a change in control, all unvested awards held by directors will immediately vest in full. | ||||||||||||||||||||||||
In connection with a change in control, the committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any participant, but subject to the terms of any award agreements and employment agreements to which the Partnership’s general partner (or any affiliate) and any participant are party, may take one or more of the following actions (with discretion to differentiate between individual participants and awards for any reason): | ||||||||||||||||||||||||
— | cause awards to be assumed or substituted by the surviving entity (or affiliate of such surviving entity); | |||||||||||||||||||||||
— | accelerate the vesting of awards as of immediately prior to the consummation of the transaction that constitutes the change in control so that awards will vest (and, with respect to options, become exercisable) as to the Partnership’s common units that otherwise would have been unvested so that participants (as holders of awards granted under the new equity plan) may participate in the transaction; | |||||||||||||||||||||||
— | provide for the payment of cash or other consideration to participants in exchange for the cancellation of outstanding awards (in an amount equal to the fair market value of such cancelled awards); | |||||||||||||||||||||||
— | terminate all or some awards upon the consummation of the change-in-control transaction, but only if the committee provides for full vesting of awards immediately prior to the consummation of such transaction; and | |||||||||||||||||||||||
— | make such other modifications, adjustments or amendments to outstanding awards or the new equity plan as the committee deems necessary or appropriate. | |||||||||||||||||||||||
2010 Phantom Units. A phantom unit entitles a Participant to receive a Partnership common unit upon vesting of the phantom unit. In tandem with phantom unit grants, the LTIP Committee may grant Participant Distribution Equivalent Rights (“DERs”), which are the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions the Partnership makes on a common unit during the period such phantom unit is outstanding. Generally, phantom units granted to employees under the 2010 LTIP will vest over a three or four year period from the date of grant and phantom units granted to non-employee directors generally vest over a four year period, 25% per year. Of the phantom units outstanding under the 2010 LTIP at December 31, 2014, there are 1,601,974 units that will vest within the following twelve months. All phantom units outstanding under the 2010 LTIP at December 31, 2014 include DERs. During the years ended December 31, 2014, 2013 and 2012, the Partnership paid $4.3 million, $3.1 million and $2.0 million, respectively, with respect to the 2010 LTIP DERs. | ||||||||||||||||||||||||
The following table sets forth the 2010 LTIP phantom unit activity for the periods indicated: | ||||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Number | Weighted | Number | Weighted | Number | Weighted | |||||||||||||||||||
of Units | Average | of Units | Average | of Units | Average | |||||||||||||||||||
Grant Date | Grant Date | Grant Date | ||||||||||||||||||||||
Fair Value | Fair Value | Fair Value | ||||||||||||||||||||||
Outstanding, beginning of year | 2,054,534 | $ | 22.58 | 2,044,227 | $ | 20.9 | 1,838,164 | $ | 22.11 | |||||||||||||||
Granted | 961,000 | 44.93 | 112,000 | 50.26 | 133,080 | 29.95 | ||||||||||||||||||
Vested(1) | (486,321 | ) | 20.76 | (25,684 | ) | 19.87 | (19,677 | ) | 20.11 | |||||||||||||||
Forfeited | (32,549 | ) | 32.53 | (76,009 | ) | 20.67 | (72,808 | ) | 20.65 | |||||||||||||||
ARP anti-dilution adjustment(2) | — | — | — | — | 165,468 | — | ||||||||||||||||||
Outstanding, end of year(3) | 2,496,664 | $ | 31.41 | 2,054,534 | $ | 22.58 | 2,044,227 | $ | 20.9 | |||||||||||||||
Non-cash compensation expense recognized | $ | 22,624 | $ | 11,848 | $ | 11,612 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
-1 | The aggregate intrinsic values of phantom unit awards vested were $21.1 million, $1.3 million and $0.7 million, respectively, for the years ended December 31, 2014, 2013 and 2012. | |||||||||||||||||||||||
-2 | The number of 2010 phantom units was adjusted concurrently with the distribution of ARP common units. | |||||||||||||||||||||||
-3 | The aggregate intrinsic value of phantom unit awards outstanding at December 31, 2014 was $77.8 million. | |||||||||||||||||||||||
At December 31, 2014, the Partnership had approximately $35.7 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2010 LTIP based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 2.1 years. | ||||||||||||||||||||||||
2010 Unit Options. A unit option entitles a Participant to receive a common unit of the Partnership upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option is equal to the fair market value of the Partnership’s common unit on the date of grant of the option. The LTIP Committee also determines how the exercise price may be paid by the Participant. The LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Generally, unit options granted under the 2010 LTIP generally will vest over a three or four year period from the date of grant. There are 1,770,877 unit options outstanding under the 2010 LTIP at December 31, 2014 that will vest within the following twelve months. For the years ended December 31, 2014, 2013 and 2012, the Partnership received cash of $0.6 million, $0.1 million and $0.1 million, respectively, from the exercise of options. | ||||||||||||||||||||||||
The following table sets forth the 2010 LTIP unit option activity for the periods indicated: | ||||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Number | Weighted | Number | Weighted | Number | Weighted | |||||||||||||||||||
of Unit | Average | of Unit | Average | of Unit | Average | |||||||||||||||||||
Options | Exercise | Options | Exercise | Options | Exercise | |||||||||||||||||||
Price | Price | Price | ||||||||||||||||||||||
Outstanding, beginning of year | 2,452,412 | $ | 20.52 | 2,504,703 | $ | 20.51 | 2,304,300 | $ | 22.12 | |||||||||||||||
Granted | — | — | — | — | 77,167 | 27.55 | ||||||||||||||||||
Exercised(1) | (28,473 | ) | 20.68 | (3,262 | ) | 20.44 | (5,438 | ) | 18.44 | |||||||||||||||
Forfeited | (9,394 | ) | 18.79 | (49,029 | ) | 20.38 | (79,119 | ) | 20.33 | |||||||||||||||
ARP anti-dilution adjustment(2) | — | — | — | — | 207,793 | — | ||||||||||||||||||
Outstanding, end of year(3)(4) | 2,414,545 | $ | 20.53 | 2,452,412 | $ | 20.52 | 2,504,703 | $ | 20.51 | |||||||||||||||
Options exercisable, end of year(5) | 584,162 | $ | 20.34 | 13,865 | $ | 20.03 | 3,398 | $ | 20.85 | |||||||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 4,535 | $ | 5,768 | $ | 5,966 | ||||||||||||||||||
-1 | The intrinsic values of options exercised during the years ended December 31, 2014, 2013 and 2012 were $0.6 million, $0.1 million and $0.1 million, respectively. | |||||||||||||||||||||||
-2 | The number of 2010 unit options and exercise price was adjusted concurrently with the distribution of ARP common units. | |||||||||||||||||||||||
-3 | The weighted average remaining contractual life for outstanding options at December 31, 2014 was 6.3 years. | |||||||||||||||||||||||
-4 | The options outstanding at December 31, 2014 had an aggregate intrinsic value of $25.7 million. | |||||||||||||||||||||||
-5 | The weighted average remaining contractual lives for exercisable options at December 31, 2014 and 2013 were 6.3 years and 7.6 years, respectively. The intrinsic values of exercisable options at December 31, 2014, 2013 and 2012 were $6.1 million, $0.4 million and approximately $47,000, respectively. | |||||||||||||||||||||||
At December 31, 2014, the Partnership had approximately $1.1 million in unrecognized compensation expense related to unvested unit options outstanding under the 2010 LTIP based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 0.3 years. The Partnership used the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted. | ||||||||||||||||||||||||
The following weighted average assumptions were used for the periods indicated: | ||||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Expected dividend yield | — | % | — | % | 3.7 | % | ||||||||||||||||||
Expected unit price volatility | — | % | — | % | 45 | % | ||||||||||||||||||
Risk-free interest rate | — | % | — | % | 1.4 | % | ||||||||||||||||||
Expected term (in years) | — | — | 6.84 | |||||||||||||||||||||
Fair value of unit options granted | $ | — | $ | — | $ | 8.08 | ||||||||||||||||||
2006 Long-Term Incentive Plan | ||||||||||||||||||||||||
The Board of Directors approved and adopted the Partnership’s 2006 Long-Term Incentive Plan (“2006 LTIP”), which provides equity incentive awards to Participants who perform services for the Partnership. The 2006 LTIP is administered by the LTIP Committee. The LTIP Committee may grant such awards of either phantom units or unit options for an aggregate of 2,261,516 common limited partner units. At December 31, 2014, the Partnership had 1,721,121 phantom units and unit options outstanding under the 2006 LTIP, with 133,951 phantom units and unit options available for grant. Share based payments to non-employees, which have a cash settlement option, are recognized within liabilities in the financial statements based upon their current fair market value. | ||||||||||||||||||||||||
In the case of awards held by eligible employees, following a “change in control”, as defined in the 2006 LTIP, upon the eligible employee’s termination of employment without “cause”, as defined in the 2006 LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the option. Upon a change in control, all unvested awards held by directors will immediately vest in full. | ||||||||||||||||||||||||
2006 Phantom Units. Generally, phantom units granted to employees under the 2006 LTIP will vest over a three or four year period from the date of grant and phantom units granted to non-employee directors generally vest over a four year period, 25% per year. Of the phantom units outstanding under the 2006 LTIP at December 31, 2014, 311,387 units will vest within the following twelve months. All phantom units outstanding under the 2006 LTIP at December 31, 2014 include DERs. During the years ended December 31, 2014, 2013 and 2012, respectively, the Partnership paid approximately $1.1 million, $0.4 million and approximately $42,000 with respect to 2006 LTIP’s DERs. These amounts were recorded as reductions of partners’ capital on the Partnership’s consolidated balance sheets. | ||||||||||||||||||||||||
The following table sets forth the 2006 LTIP phantom unit activity for the periods indicated: | ||||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Number | Weighted | Number | Weighted | Number | Weighted | |||||||||||||||||||
of Units | Average | of Units | Average | of Units | Average | |||||||||||||||||||
Grant Date | Grant Date | Grant Date | ||||||||||||||||||||||
Fair Value | Fair Value | Fair Value | ||||||||||||||||||||||
Outstanding, beginning of year | 234,940 | $ | 35.82 | 50,759 | $ | 21.02 | 32,641 | $ | 15.99 | |||||||||||||||
Granted | 629,525 | 43.76 | 207,363 | 38.05 | 25,248 | 29.7 | ||||||||||||||||||
Vested (1) (2) | (83,283 | ) | 33.86 | (20,182 | ) | 21.34 | (10,107 | ) | 20.26 | |||||||||||||||
Forfeited | — | — | (3,000 | ) | 36.45 | — | — | |||||||||||||||||
ARP anti-dilution adjustment(3) | — | — | — | — | 2,977 | — | ||||||||||||||||||
Outstanding, end of year(4)(5) | 781,182 | $ | 42.43 | 234,940 | $ | 35.82 | 50,759 | $ | 21.02 | |||||||||||||||
Non-cash compensation expense recognized | $ | 16,797 | $ | 5,317 | $ | 660 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
-1 | The intrinsic values for phantom unit awards vested during the years ended December 31, 2014, 2013 and 2012 were $3.8 million, $1.0 million and $0.3 million, respectively. | |||||||||||||||||||||||
-2 | There were 6,380 and 1,146 vested units during the years ended December 31, 2014 and 2013, respectively, that were settled for approximately $0.3 million and $0.1 million cash, respectively. No units were settled in cash during the year ended December 31, 2012. | |||||||||||||||||||||||
-3 | The number of 2006 phantom units was adjusted concurrently with the distribution of ARP common units. | |||||||||||||||||||||||
-4 | The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2014 was $24.3 million. | |||||||||||||||||||||||
-5 | There were $0.8 million and $1.1 million recognized as liabilities on APL’s consolidated balance sheets at December 31, 2014 and 2013, respectively, representing 41,113 and 41,525, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units are $36.94 and $29.67 as of December 31, 2014 and 2013, respectively. | |||||||||||||||||||||||
At December 31, 2014, the Partnership had approximately $14.1 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2006 LTIP based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 1.7 years. | ||||||||||||||||||||||||
2006 Unit Options. The exercise price of the unit option may be equal to or more than the fair market value of the Partnership’s common unit on the date of grant of the option. Unit option awards expire 10 years from the date of grant. Generally, unit options granted under the 2006 LTIP will vest over a three or four year period from the date of grant. There are 2,500 unit options outstanding under the 2006 LTIP at December 31, 2014 that will vest within the following twelve months. For the year ended December 31, 2012, the Partnership received cash of $0.2 million from the exercise of options. No cash was received from the exercise of options for the years ended December 31, 2014 and 2013. | ||||||||||||||||||||||||
The following table sets forth the 2006 LTIP unit option activity for the periods indicated: | ||||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Number | Weighted | Number | Weighted | Number | Weighted | |||||||||||||||||||
of Unit | Average | of Unit | Average | of Unit | Average | |||||||||||||||||||
Options | Exercise | Options | Exercise | Options | Exercise | |||||||||||||||||||
Price | Price | Price | ||||||||||||||||||||||
Outstanding, beginning of year | 939,939 | $ | 20.94 | 929,939 | $ | 20.75 | 903,614 | $ | 21.52 | |||||||||||||||
Granted | — | — | 10,000 | 38.51 | — | — | ||||||||||||||||||
Exercised(1) | — | — | — | — | (51,998 | ) | 3.03 | |||||||||||||||||
Forfeited | — | — | — | — | — | — | ||||||||||||||||||
ARP anti-dilution adjustment(2) | — | — | — | — | 78,323 | — | ||||||||||||||||||
Outstanding, end of year(3)(4) | 939,939 | $ | 20.94 | 939,939 | $ | 20.94 | 929,939 | $ | 20.75 | |||||||||||||||
Options exercisable, end of year(5) | 932,439 | $ | 20.8 | 929,939 | $ | 20.75 | 929,939 | $ | 20.75 | |||||||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 22 | $ | 36 | $ | — | ||||||||||||||||||
-1 | The intrinsic value of options exercised during the year ended December 31, 2012 was $1.5 million. No options were exercised during the years ended December 31, 2014 and 2013. | |||||||||||||||||||||||
-2 | The number of 2006 unit options and exercise price was adjusted concurrently with the distribution of ARP common units. | |||||||||||||||||||||||
-3 | The weighted average remaining contractual life for outstanding options at December 31, 2014 was 1.9 years. | |||||||||||||||||||||||
-4 | The aggregate intrinsic value of options outstanding at December 31, 2014 was approximately $9.7 million. | |||||||||||||||||||||||
-5 | The weighted average remaining contractual lives for exercisable options at December 31, 2014 and 2013 were 1.9 years and 2.9 years, respectively. The aggregate intrinsic values of options exercisable at December 31, 2014, 2013 and 2012 were $9.7 million, $24.3 million and $13.0 million, respectively. | |||||||||||||||||||||||
At December 31, 2014, the Partnership had approximately $17,000 of unrecognized compensation expense related to unvested unit options outstanding under the 2006 LTIP based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 1.6 years. The Partnership uses the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted. | ||||||||||||||||||||||||
The following weighted average assumptions were used for the periods indicated: | ||||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Expected dividend yield | — | % | 3.2 | % | — | % | ||||||||||||||||||
Expected unit price volatility | — | % | 30 | % | — | % | ||||||||||||||||||
Risk-free interest rate | — | % | 0.7 | % | — | % | ||||||||||||||||||
Expected term (in years) | — | 6.25 | — | |||||||||||||||||||||
Fair value of unit options granted | $ | — | $ | 7.54 | $ | — | ||||||||||||||||||
ARP Long-Term Incentive Plan | ||||||||||||||||||||||||
ARP’s 2012 Long-Term Incentive Plan (the “ARP LTIP”), effective March 2012, provides incentive awards to officers, employees and directors as well as employees of the general partner and its affiliates, consultants and joint venture partners who perform services for ARP. The ARP LTIP is administered by the board of the general partner, a committee of the board or the board (or committee of the board) of an affiliate (the “ARP LTIP Committee”). Under ARP’s 2012 LTIP, the ARP LTIP Committee may grant awards of phantom units, restricted units, or unit options for an aggregate of 2,900,000 common limited partner units of ARP. At December 31, 2014, ARP had 2,257,492 phantom units, restricted units and restricted options outstanding under the ARP LTIP with 135,663 phantom units, restricted units and unit options available for grant. Share based payments to non-employee directors, which have a cash settlement option, are recognized within liabilities in the consolidated financial statements based upon their current fair market value. | ||||||||||||||||||||||||
In the case of awards held by eligible employees, following a “change in control”, as defined in the ARP LTIP, upon the eligible employee’s termination of employment without “cause”, as defined in the ARP LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the option. Upon a change in control, all unvested awards held by directors will immediately vest in full. | ||||||||||||||||||||||||
In connection with a change in control, the ARP LTIP Committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any participant, but subject to the terms of any award agreements and employment agreements to which the Partnership, as general partner, (or any affiliate) and any participant are party, may take one or more of the following actions (with discretion to differentiate between individual participants and awards for any reason): | ||||||||||||||||||||||||
— | cause awards to be assumed or substituted by the surviving entity (or affiliate of such surviving entity); | |||||||||||||||||||||||
— | accelerate the vesting of awards as of immediately prior to the consummation of the transaction that constitutes the change in control so that awards will vest (and, with respect to options, become exercisable) as to ARP’s common units that otherwise would have been unvested so that participants (as holders of awards granted under the new equity plan) may participate in the transaction; | |||||||||||||||||||||||
— | provide for the payment of cash or other consideration to participants in exchange for the cancellation of outstanding awards (in an amount equal to the fair market value of such cancelled awards); | |||||||||||||||||||||||
— | terminate all or some awards upon the consummation of the change-in-control transaction, but only if the ARP LTIP Committee provides for full vesting of awards immediately prior to the consummation of such transaction; and | |||||||||||||||||||||||
— | make such other modifications, adjustments or amendments to outstanding awards or the new equity plan as the ARP LTIP Committee deems necessary or appropriate. | |||||||||||||||||||||||
ARP Phantom Units. Phantom units granted under the ARP LTIP generally will vest 25% of the original granted amount on each of the four anniversaries of the date of grant. Of the phantom units outstanding under the ARP LTIP at December 31, 2014, 317,587 units will vest within the following twelve months. All phantom units outstanding under the ARP LTIP at December 31, 2014 include DERs. During the years ended December 31, 2014, 2013, and 2012, ARP paid $2.0 million, $1.9 million, and $0.7 million, respectively, with respect to the ARP LTIP’s DERs. These amounts were recorded as non-controlling interests on the Partnership’s consolidated balance sheets. | ||||||||||||||||||||||||
The following table sets forth the ARP LTIP phantom unit activity for the periods indicated: | ||||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Number | Weighted | Number | Weighted | Number | Weighted | |||||||||||||||||||
of Units | Average | of Units | Average | of Units | Average | |||||||||||||||||||
Grant Date | Grant Date | Grant Date | ||||||||||||||||||||||
Fair Value | Fair Value | Fair Value | ||||||||||||||||||||||
Outstanding, beginning of year | 839,808 | $ | 24.31 | 948,476 | $ | 24.76 | — | $ | — | |||||||||||||||
Granted | 264,173 | 19.43 | 145,813 | 21.87 | 949,476 | 24.76 | ||||||||||||||||||
Vested(1) | (274,414 | ) | 24.46 | (215,981 | ) | 24.73 | — | — | ||||||||||||||||
Forfeited | (30,375 | ) | 22.76 | (38,500 | ) | 23.96 | (1,000 | ) | 24.67 | |||||||||||||||
Outstanding, end of year(2)(3) | 799,192 | $ | 22.7 | 839,808 | $ | 24.31 | 948,476 | $ | 24.76 | |||||||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 6,367 | $ | 9,166 | $ | 7,630 | ||||||||||||||||||
-1 | The intrinsic values of phantom unit awards vested during the years ended December 31, 2014 and 2013 were $5.4 million and $6.1 million, respectively. No phantom unit awards vested during the year ended December 31, 2012. | |||||||||||||||||||||||
-2 | The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2014 was $8.6 million. | |||||||||||||||||||||||
-3 | There was approximately $0.2 million and $0.1 million recognized as liabilities on the Partnership’s consolidated balance sheets at December 31, 2014 and 2013, respectively, representing 26,579 and 16,084 units, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units were $21.16 and $22.15 at December 31, 2014 and 2013, respectively. | |||||||||||||||||||||||
At December 31, 2014, ARP had approximately $6.7 million in unrecognized compensation expense related to unvested phantom units outstanding under the ARP LTIP based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 1.7 years. | ||||||||||||||||||||||||
ARP Unit Options. The exercise price of each ARP unit option is determined by the ARP LTIP Committee and may be equal to or greater than the fair market value of ARP’s common unit on the date of grant of the option. The ARP LTIP Committee will determine the vesting and exercise restrictions applicable to an ARP award of options, if any, and the method by which the exercise price may be paid by the participant. Unit option awards expire 10 years from the date of grant. Unit options granted under the ARP LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. There were 361,325 unit options outstanding under the ARP LTIP at December 31, 2014 that will vest within the following twelve months. No cash was received from the exercise of options for the years ended December 31, 2014, 2013, and 2012. | ||||||||||||||||||||||||
The following table sets forth the ARP LTIP unit option activity for the periods indicated: | ||||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Number | Weighted | Number | Weighted | Number | Weighted | |||||||||||||||||||
of Unit Options | Average | of Unit Options | Average | of Unit Options | Average | |||||||||||||||||||
Exercise Price | Exercise Price | Exercise Price | ||||||||||||||||||||||
Outstanding, beginning of year | 1,482,675 | $ | 24.66 | 1,515,500 | $ | 24.68 | — | $ | — | |||||||||||||||
Granted | — | — | 5,000 | 21.56 | 1,517,500 | 24.68 | ||||||||||||||||||
Exercised (1) | — | — | — | — | — | — | ||||||||||||||||||
Forfeited | (24,375 | ) | 24.52 | (37,825 | ) | 24.8 | (2,000 | ) | 24.67 | |||||||||||||||
Outstanding, end of year(2)(3) | 1,458,300 | $ | 24.66 | 1,482,675 | $ | 24.66 | 1,515,500 | $ | 24.68 | |||||||||||||||
Options exercisable, end of year(4) | 730,775 | $ | 24.67 | 370,700 | $ | 24.67 | — | $ | — | |||||||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 1,700 | $ | 3,514 | $ | 3,198 | ||||||||||||||||||
-1 | No options were exercised during the years ended December 31, 2014, 2013 and 2012. | |||||||||||||||||||||||
-2 | The weighted average remaining contractual life for outstanding options at December 31, 2014 was 7.4 years. | |||||||||||||||||||||||
-3 | There was no aggregate intrinsic value of options outstanding at December 31, 2014. The aggregate intrinsic value of options outstanding at December 31, 2013 was approximately $1,000. | |||||||||||||||||||||||
-4 | The weighted average remaining contractual life for exercisable options at December 31, 2014 and 2013 was 7.4 years and 8.4 years, respectively. There were no intrinsic values for options exercisable at December 31, 2014, 2013, and 2012. | |||||||||||||||||||||||
At December 31, 2014, ARP had approximately $1.0 million in unrecognized compensation expense related to unvested unit options outstanding under the ARP LTIP based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 1.1 years. ARP used the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted. | ||||||||||||||||||||||||
The following weighted average assumptions were used for the periods indicated: | ||||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Expected dividend yield | — | % | 8 | % | 5.9 | % | ||||||||||||||||||
Expected unit price volatility | — | % | 35.5 | % | 47 | % | ||||||||||||||||||
Risk-free interest rate | — | % | 1.4 | % | 1 | % | ||||||||||||||||||
Expected term (in years) | — | 6.31 | 6.25 | |||||||||||||||||||||
Fair value of unit options granted | $ | — | $ | 2.95 | $ | 6.1 | ||||||||||||||||||
APL Long-Term Incentive Plans | ||||||||||||||||||||||||
APL has a 2004 Long-Term Incentive Plan (“2004 APL LTIP”) and a 2010 Long-Term Incentive Plan (“2010 APL LTIP” and collectively with the 2004 LTIP, the “APL LTIPs”) in which officers, employees, non-employee managing board members of APL’s general partner, employees of APL’s general partner’s affiliates and consultants are eligible to participate. The APL LTIPs are administered by its compensation committee (the “APL LTIP Committee”). Under the APL LTIPs, the APL LTIP Committee may make awards of either phantom units or unit options for an aggregate of 3,435,000 common units. At December 31, 2014, APL had 1,684,289 phantom units outstanding under the APL LTIPs, with 139,218 phantom units and unit options available for grant. APL generally issues new common units for phantom units and unit options that have vested and have been exercised. | ||||||||||||||||||||||||
APL Phantom Units | ||||||||||||||||||||||||
Phantom units granted to employees under the APL LTIPs generally had vesting periods of four years. However, in February 2014, the APL granted 227,000 phantom units with a vesting period of three years. The APL LTIP Committee determines the vesting paid for phantom units. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards to non-employee members of the board automatically vest upon a change of control, as defined in the APL LTIPs. At December 31, 2014, there were 614,415 units outstanding under the APL LTIPs that will vest within the following twelve months. | ||||||||||||||||||||||||
APL is authorized to purchase common units from employees to cover employee-related taxes when certain phantom units have vested. During the years ended December 31, 2014 and 2012, APL purchased and retired 66,321 and 24,052 common units, respectively, for a cost of $2.2 million and $0.7 million, respectively. The purchased and retired units were recorded as a reduction of non-controlling interests on the Partnership’s consolidated balance sheets. There were no phantom units purchased and retired during the year ended December 31, 2013. | ||||||||||||||||||||||||
All phantom units outstanding under the APL LTIPs at December 31, 2014 include DERs granted to the participants by the APL LTIP Committee. The amounts paid with respect to APL LTIP DERs were $4.3 million, $3.1 million and $2.0 million during the years ended December 31, 2014, 2013 and 2012, respectively. These amounts were recorded as reductions of non-controlling interests on the Partnership’s consolidated balance sheets. | ||||||||||||||||||||||||
The following table sets forth the APL LTIPs phantom unit activity for the periods indicated: | ||||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Number | Weighted | Number | Weighted | Number | Weighted | |||||||||||||||||||
of Units | Average | of Units | Average | of Units | Average | |||||||||||||||||||
Grant Date | Grant Date | Grant Date | ||||||||||||||||||||||
Fair Value | Fair Value | Fair Value | ||||||||||||||||||||||
Outstanding, beginning of year | 1,446,553 | $ | 36.32 | 1,053,242 | $ | 33.21 | 394,489 | $ | 21.63 | |||||||||||||||
Granted | 738,727 | 33.03 | 744,997 | 38.96 | 907,637 | 34.94 | ||||||||||||||||||
Forfeited | (37,075 | ) | 37.09 | (61,550 | ) | 36.11 | (67,675 | ) | 29.83 | |||||||||||||||
Vested (1)(2) | (463,916 | ) | 34.71 | (290,136 | ) | 31.88 | (181,209 | ) | 17.88 | |||||||||||||||
Outstanding, end of year(3)(4) | 1,684,289 | $ | 35.3 | 1,446,553 | $ | 36.32 | 1,053,242 | $ | 33.21 | |||||||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 25,116 | $ | 19,344 | $ | 11,635 | ||||||||||||||||||
-1 | The intrinsic values for phantom unit awards vested during the years ended December 31, 2014, 2013 and 2012 were $15.4 million, $10.7 million and $5.5 million, respectively. | |||||||||||||||||||||||
-2 | There were 4,684, 1,677 and 792 vested phantom units, which were settled for approximately $155,000, $58,000 and $28,000 cash during the years ended December 31, 2014, 2013 and 2012, respectively. | |||||||||||||||||||||||
-3 | The aggregate intrinsic values for phantom unit awards outstanding at December 31, 2014 and 2013 were $45.9 million and $50.7 million, respectively. | |||||||||||||||||||||||
-4 | There were 25,778 and 22,539 outstanding phantom unit awards at December 31, 2014 and 2013, respectively, which were classified as liabilities due to a cash option available on the related phantom unit awards. | |||||||||||||||||||||||
At December 31, 2014, APL had approximately $27.9 million of unrecognized compensation expense related to APL’s unvested phantom units outstanding under the APL LTIPs based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 1.9 years. | ||||||||||||||||||||||||
APL Unit Options | ||||||||||||||||||||||||
An APL unit option entitles a grantee to purchase an APL common limited partner unit upon payment of the exercise price for APL’s option after completion of vesting of the APL unit option. The exercise price of APL’s unit option is equal to the fair market value of the APL’s common unit on the date of grant of the option. The APL Compensation Committee determines how the exercise price may be paid by the grantee as well as the vesting and exercise period for APL’s unit options. | ||||||||||||||||||||||||
APL had no unit options outstanding at December 31, 2014, and there were no exercises of APL’s unit options during the years ended December 31, 2014, 2013 and 2012. |
Operating_Segment_Information
Operating Segment Information | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Segment Reporting [Abstract] | ||||||||||||||||
Operating Segment Information | NOTE 18 — OPERATING SEGMENT INFORMATION | |||||||||||||||
The Partnership’s operations include three reportable operating segments. These operating segments reflect the way the Partnership manages its operations and makes business decisions. Operating segment data for the periods indicated were as follows (in thousands): | ||||||||||||||||
Years Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
Atlas Resource: | ||||||||||||||||
Revenues | $ | 685,560 | $ | 467,655 | $ | 267,629 | ||||||||||
Operating costs and expenses | (425,000 | ) | (348,812 | ) | (246,267 | ) | ||||||||||
Depreciation, depletion and amortization expense | (233,731 | ) | (136,763 | ) | (52,582 | ) | ||||||||||
Asset impairment | (573,774 | ) | (38,014 | ) | (9,507 | ) | ||||||||||
Loss on asset sales and disposal | (1,869 | ) | (987 | ) | (6,980 | ) | ||||||||||
Interest expense | (62,144 | ) | (34,324 | ) | (4,195 | ) | ||||||||||
Segment loss | $ | (610,958 | ) | $ | (91,245 | ) | $ | (51,902 | ) | |||||||
Atlas Pipeline: | ||||||||||||||||
Revenues | $ | 2,961,113 | $ | 2,102,113 | $ | 1,252,674 | ||||||||||
Operating costs and expenses | (2,483,160 | ) | (1,863,510 | ) | (1,052,826 | ) | ||||||||||
Depreciation, depletion and amortization expense | (202,543 | ) | (168,617 | ) | (90,029 | ) | ||||||||||
Asset impairment | — | (43,866 | ) | — | ||||||||||||
Gain (loss) on asset sales and disposal | 47,381 | (1,519 | ) | — | ||||||||||||
Interest expense | (93,147 | ) | (89,637 | ) | (41,760 | ) | ||||||||||
Loss on early extinguishment of debt | — | (26,601 | ) | — | ||||||||||||
Segment income (loss) | $ | 229,644 | $ | (91,637 | ) | $ | 68,059 | |||||||||
Corporate and other: | ||||||||||||||||
Revenues | $ | 22,030 | $ | 7,747 | $ | 1,140 | ||||||||||
Operating costs and expenses | (72,822 | ) | (41,690 | ) | (33,613 | ) | ||||||||||
Depreciation, depletion and amortization expense | (8,348 | ) | (3,153 | ) | — | |||||||||||
Asset impairment | (6,880 | ) | — | — | ||||||||||||
Gain on asset sales and disposal | 10 | — | — | |||||||||||||
Interest expense | (18,066 | ) | (8,620 | ) | (565 | ) | ||||||||||
Segment loss | $ | (84,076 | ) | $ | (45,716 | ) | $ | (33,038 | ) | |||||||
Reconciliation of segment income (loss) to net loss: | ||||||||||||||||
Segment income (loss): | ||||||||||||||||
Atlas Resource | $ | (610,958 | ) | $ | (91,245 | ) | $ | (51,902 | ) | |||||||
Atlas Pipeline | 229,644 | (91,637 | ) | 68,059 | ||||||||||||
Corporate and other | (84,076 | ) | (45,716 | ) | (33,038 | ) | ||||||||||
Net loss | $ | (465,390 | ) | $ | (228,598 | ) | $ | (16,881 | ) | |||||||
Reconciliation of segment revenues to total revenues: | ||||||||||||||||
Segment revenues: | ||||||||||||||||
Atlas Resource | $ | 685,560 | $ | 467,655 | $ | 267,629 | ||||||||||
Atlas Pipeline | 2,961,113 | 2,102,113 | 1,252,674 | |||||||||||||
Corporate and other | 22,030 | 7,747 | 1,140 | |||||||||||||
Total revenues | $ | 3,668,703 | $ | 2,577,515 | $ | 1,521,443 | ||||||||||
Capital expenditures: | ||||||||||||||||
Atlas Resource | $ | 212,634 | $ | 263,537 | $ | 127,226 | ||||||||||
Atlas Pipeline | 647,747 | 450,560 | 373,533 | |||||||||||||
Corporate and other | 13,002 | 3,943 | — | |||||||||||||
Total capital expenditures | $ | 873,383 | $ | 718,040 | $ | 500,759 | ||||||||||
December 31, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Balance sheet: | ||||||||||||||||
Goodwill: | ||||||||||||||||
Atlas Resource | $ | 13,639 | $ | 31,784 | ||||||||||||
Atlas Pipeline | 365,763 | 368,572 | ||||||||||||||
Corporate and other | — | — | ||||||||||||||
$ | 379,402 | $ | 400,356 | |||||||||||||
Total assets: | ||||||||||||||||
Atlas Resource | $ | 2,727,575 | $ | 2,343,800 | ||||||||||||
Atlas Pipeline | 4,824,733 | 4,327,845 | ||||||||||||||
Corporate and other | 314,328 | 120,996 | ||||||||||||||
$ | 7,866,636 | $ | 6,792,641 | |||||||||||||
Subsequent_Events
Subsequent Events | 12 Months Ended | |
Dec. 31, 2014 | ||
Subsequent Events [Abstract] | ||
Subsequent Events | NOTE 19 — SUBSEQUENT EVENTS | |
Merger with Targa Resources Corp. On October 13, 2014, the Partnership entered into a definitive merger agreement with Targa Resources Corp. (“TRC”; NYSE: TRGP) (the “Merger Agreement”), pursuant to which TRC agreed to acquire the Partnership through a newly formed, wholly-owned subsidiary of TRC (the “Merger”). Upon completion of the Merger, holders of the Partnership’s common units will have the right to receive, for each Partnership common unit, (i) 0.1809 TRC shares, and (ii) $9.12 in cash. | ||
Concurrently with the execution of the Merger Agreement, APL entered into a definitive merger agreement (the “APL Merger Agreement”) with the Partnership, TRC, Targa Resources Partners LP (“TRP”; NYSE: NGLS), pursuant to which TRP agreed to acquire APL through a newly formed, wholly-owned subsidiary of TRP (the “APL Merger”). Upon completion of the APL Merger, holders of APL’s common units will have the right to receive (i) 0.5846 TRP common units and (ii) $1.26 in cash for each APL common unit. | ||
Concurrent with the execution of the Merger Agreement and the APL Merger Agreement, the Partnership agreed to (i) transfer its assets and liabilities, other than those related to APL, to Atlas Energy Group, which is currently a wholly-owned subsidiary of the Partnership and (ii) immediately prior to the Merger, effect a pro rata distribution to the Partnership’s unitholders of common units of Atlas Energy Group representing a 100% interest in Atlas Energy Group (the “Spin-Off”). Atlas Energy Group’s assets, assuming the Spin-Off had been completed as of December 31, 2014, consist of: | ||
— | 100% of the general partner Class A units, all of the incentive distribution rights, as well as an approximate 27.7% limited partner interest (20,962,485 common and 3,749,986 preferred limited partner units) in ARP; | |
— | 80% of the general partner Class A units, all of the incentive distribution rights, as well as a 1.7% limited partner interest, in the Development Subsidiary; | |
— | 15.9% of the general partner interest and a 12% limited partner interest in Lightfoot, which has a 40% limited partner interest in ARCX; and, | |
— | the Partnership’s direct natural gas development and production assets in the Arkoma Basin, which it acquired in July 2013. | |
The closing of the Merger is subject to approval by holders of a majority of the Partnership’s common units, approval by a majority of the holders of TRC common stock voting at a special meeting held to approve the issuance of TRC shares in the Merger and other closing conditions, including the closing of the APL Merger and the Spin-Off. On February 20, 2015, we and TRC each held special meetings, where holders of a majority of our common units approved the Merger and a majority of the holders of TRC common stock voting at the TRC special meeting approved the issuance of TRC shares in the Merger. In addition, holders of a majority of APL’s common units approved the APL Merger at a special meeting held on the same day. Completion of each of the APL Merger and the Spin-Off are also conditioned on the parties standing ready to complete the Merger. | ||
Following the announcement on October 13, 2014 of the Merger, the Partnership, the Partnership’s general partner, TRC, Trident GP Merger Sub LLC (“GP Merger Sub”) and the members of the General Partner’s board have been named as defendants in two putative unitholder class action lawsuits challenging the Merger. In addition, the Partnership, APL, Atlas Pipeline Partners GP LLC (“APL GP”), TRC, TRP, Targa Resources GP LLC (“TRP GP”), Trident MLP Merger Sub LLC (“MLP Merger Sub”) and the members of the managing board of APL GP have been named as defendants in five putative unitholder class action lawsuits challenging the APL Merger. The lawsuits filed generally allege that the individual defendants breached their fiduciary duties and/or contractual obligations by, among other things, failing to obtain sufficient value for the Partnership’s unitholders in the Merger. The plaintiffs seek, among other things, injunctive relief, unspecified compensatory and/or rescissory damages, attorney’s fees, other expenses and costs. | ||
We have also been named as a defendant in a putative class action and derivative lawsuit brought on January 28, 2015 and amended on February 23, 2015, by a shareholder of TRC against TRC and its directors challenging the disclosures made in connection with the Merger. The lawsuit generally alleges that the individual defendants breached their fiduciary duties by, among other things, approving the Merger and failing to disclose purportedly material information concerning the Merger. The lawsuit seeks, among other things, injunctive relief, compensatory and rescissory damages, attorney’s fees, interest, and costs. | ||
All of the above referenced lawsuits, except for the January 2015 lawsuit and the two lawsuits that have been voluntarily dismissed, were settled, subject to court approval, pursuant to memoranda of understanding executed in February 2015, which are conditioned upon, among other things, the execution of an appropriate stipulations of settlement. The stipulations of settlement will be subject to customary conditions, including, among other things, judicial approval of the proposed settlements contemplated by the memoranda of understanding. There can be no assurance that the parties will ultimately enter into stipulations of settlement, that the court will approve the settlements, that the settlements will not be terminated according to their terms or that some unitholders will not opt-out of the settlements. | ||
At this time, the Partnership cannot reasonably estimate the range of possible loss as a result of the lawsuits. See “Part I. Item 3. Legal Proceedings” for more information regarding these lawsuits. | ||
Cash Distribution. On January 28, 2015, the Partnership declared a cash distribution of $0.52 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2014. The $27.1 million distribution was paid on February 19, 2015 to unitholders of record at the close of business on February 9, 2015. | ||
Atlas Resource | ||
Credit Facility Amendment. On February 23, 2015, ARP entered the Sixth Amendment with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto, which amendment amends the ARP Credit Agreement. Among other things, the Sixth Amendment: | ||
— | reduces the borrowing base under the ARP Credit Agreement from $900.0 million to $750.0 million; | |
— | permits the incurrence of second lien debt in an aggregate principal amount up to $300.0 million; | |
— | if the borrowing base utilization (as defined in the ARP Credit Agreement) is less than 90%, increases the applicable margin on Eurodollar loans and ABR loans by 0.25% from previous levels, | |
— | following the next scheduled redetermination of the borrowing base, upon the issuance of senior notes or the incurrence of second lien debt, reduces the borrowing base by 25% of the stated amount of such senior notes or additional second lien debt; and | |
— | revises the maximum ratio of Total Funded Debt to EBITDA to be (i) 5.25 to 1.0 as of the last day of the quarters ended on March 31, 2015, June 30, 2015, September 30, 2015, December 31, 2015 and March 31, 2016, (ii) 5.00 to 1.0 as of the last day of the quarters ended on June 30, 2016, September 30, 2016 and December 31, 2016, (iii) 4.50 to 1.0 as of the last day of the quarters ended on March 31, 2017 and (iv) 4.00 to 1.0 as of the last day of each quarter thereafter. | |
The Amendment was approved by the lenders and was effective on February 23, 2015. | ||
Second Lien Term Loan Facility. On February 23, 2015, ARP entered into a Second Lien Credit Agreement with Wilmington Trust, National Association, as administrative agent, and the lenders party thereto. The Second Lien Credit Agreement provides for a second lien term loan in an original principal amount of $250.0 million (the “Term Loan Facility”). The Term Loan Facility matures on February 23, 2020. | ||
ARP has the option to prepay the Term Loan Facility at any time, and is required to offer to prepay the Term Loan Facility with 100% of the net cash proceeds from the issuance or incurrence of any debt and 100% of the excess net cash proceeds from certain asset sales and condemnation recoveries. ARP is also required to offer to prepay the Term Loan Facility upon the occurrence of a change of control. All prepayments are subject to the following premiums, plus accrued and unpaid interest: | ||
— | the make-whole premium (plus an additional amount if such prepayment is optional and funded with proceeds from the issuance of equity) for prepayments made during the first 12 months after the closing date; | |
— | 4.5% of the principal amount prepaid for prepayments made between 12 months and 24 months after the closing date; | |
— | 2.25% of the principal amount prepaid for prepayments made between 24 months and 36 months after the closing date; and | |
— | no premium for prepayments made following 36 months after the closing date. | |
ARP’s obligations under the Term Loan Facility are secured on a second priority basis by security interests in all of its assets and those of its restricted subsidiaries (the “Loan Parties”) that guarantee ARP’s existing first lien revolving credit facility. In addition, the obligations under the Term Loan Facility are guaranteed by ARP’s material restricted subsidiaries. Borrowings under the Term Loan Facility bear interest, at ARP’s option, at either (i) LIBOR plus 9.0% or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, each plus 8.0% (an “ABR Loan”). Interest is generally payable at the applicable maturity date for Eurodollar loans and quarterly for ABR loans. | ||
The Second Lien Credit Agreement contains customary covenants that limit ARP’s ability to make restricted payments, take on indebtedness, issue preferred stock, grant liens, conduct sales of assets and subsidiary stock, make distributions from restricted subsidiaries, conduct affiliate transactions and engage in other business activities. In addition, the Second Lien Credit Agreement contains covenants substantially similar to those in ARP’s existing first lien revolving credit facility, including, among others, restrictions on swap agreements, debt of unrestricted subsidiaries, drilling and operating agreements and the sale or discount of receivables. | ||
Under the Second Lien Credit Agreement, ARP may elect to add one or more incremental term loan tranches to the Term Loan Facility so long as the aggregate outstanding principal amount of the Term Loan Facility plus the principal amount of any incremental term loan does not exceed $300.0 million and certain other conditions are adhered to. Any such incremental term loans may not mature on a date earlier than February 23, 2020. | ||
Cash Distributions. On January 28, 2015, ARP declared a cash distribution of $0.1966 per common unit for the month of December 2014. The $18.9 million distribution, including $1.4 million and $0.7 million to the Partnership as general partner and preferred limited partners, respectively, was paid on February 13, 2015 to holders of record as of February 9, 2015. | ||
On February 23, 2015, ARP declared a cash distribution of $0.1083 per common unit for the month of January 2015. The $9.9 million distribution, including $0.2 million and $0.4 million to the Partnership as general partner and preferred limited partners, respectively, will be paid on March 17, 2015 to holders of record as of March 10, 2015. | ||
Atlas Pipeline | ||
Notice of Preferred Unit Redemption. On January 27, 2015, APL delivered notice of its intention to redeem all outstanding shares of its Class E APL Preferred Units. The redemption of the Class E APL Preferred Units will occur immediately prior to the close of the APL Merger. APL expects the APL Merger to close on February 27, 2015 and, accordingly, the redemption would also be on February 27, 2015. The Class E APL Preferred Units will be redeemed at a redemption price of $25.00 per unit, plus an amount equal to all accumulated and unpaid distributions on the Class E APL Preferred Units as of the redemption date. TRP has agreed to deposit the funds for such redemption with APL’s paying agent. | ||
Conversion of Preferred Units. On January 22, 2015, APL exercised its right under the Class D APL Certificate of Designation to convert all outstanding Class D APL Preferred Units and unpaid distributions into common limited partner units, based upon the Execution Date Unit Price of $29.75 per unit, as defined by the Class D APL Certificate of Designation. As a result of the conversion, 15,389,575 common limited partner units were issued. | ||
Redemption of APL Senior Notes. On January 15, 2015, TRP announced cash tender offers to redeem any and all of the outstanding $500.0 million aggregate principal amount of the 6.625% APL Senior Notes; $400.0 million aggregate principal amount of the 4.75% APL Senior Notes; and $650.0 million aggregate principal amount of the 5.875% APL Senior Notes. TRP made the cash tender offers in connection with, and conditioned upon, the consummation of the APL Merger. The APL Merger, however, is not conditioned on the consummation of the tender offers. On February 2, 2015, TRP announced as of January 29, 2015, it had received tenders pursuant to its previously announced cash tender offers on January 15, 2015 from holders representing: | ||
— | less than a majority of the total outstanding $500.0 million of the 6.625% APL Senior Notes; | |
— | approximately 98.3% of the total outstanding $400.0 million of the 4.75% APL Senior Notes; and | |
— | approximately 91.0% of the total outstanding $650.0 million of the 5.875% APL Senior Notes. | |
Also on February 2, 2015, TRP announced a change of control cash tender offer for any and all of the outstanding $500.0 million of the 6.625% APL Senior Notes. TRP made the change of control cash tender offer in connection with, and conditioned upon, the consummation of the Merger with APL. The Merger with APL, however, is not conditioned on the consummation of the change in control cash tender offer. The change in control cash tender offer was made independently of TRP’s January 15, 2015 cash tender offers. | ||
Cash Distributions. On January 15, 2015, APL paid a cash distribution of $0.515625 per unit, or approximately $2.6 million, on its Class E APL Preferred Units, representing the cash distribution for the period October 15, 2014 through January 14, 2015. | ||
On January 9, 2015, APL declared a cash distribution of $0.64 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2014. The $62.2 million distribution, including $8.1 million to us as general partner, was paid on February 13, 2015 to unitholders of record at the close of business on January 21, 2015. | ||
Supplemental_Oil_and_Gas_Infor
Supplemental Oil and Gas Information (Unaudited) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Oil And Gas Exploration And Production Industries Disclosures [Abstract] | |||||||||||||
Supplemental Oil and Gas Information (Unaudited) | NOTE 20—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) | ||||||||||||
Oil, Gas and NGL Reserve Information. The preparation of the Partnership’s and ARP’s natural gas, oil and NGL reserve estimates were completed in accordance with the Partnership’s and ARP’s prescribed internal control procedures by the Partnership’s and ARP’s reserve engineers. The accompanying reserve information included below was derived from the reserve reports prepared for the Partnership’s and ARP’s annual reports on Form 10-K for the year ended December 31, 2014. Other than for ARP’s Rangely assets, for the periods presented, Wright and Company, Inc., an independent third-party reserve engineer, was retained to prepare a report of proved reserves. The reserve information includes natural gas, oil and NGL reserves which are all located throughout the United States. The independent reserves engineer’s evaluation was based on more than 38 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. For ARP’s Rangely assets, Cawley, Gillespie, and Associates, Inc. was retained to prepare a report of proved reserves. The independent reserves engineer’s evaluation was based on more than 32 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions and government regulations. The Partnership’s and ARP’s internal control procedures include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by the Partnership’s and ARP’s Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 16 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by the Partnership’s and ARP’s senior engineering staff and management, with final approval by the Chief Operating Officer and President. | |||||||||||||
The reserve disclosures that follow reflect the Partnership’s and ARP’s estimates of proved reserves, proved developed reserves and proved undeveloped reserves, net of royalty interests, of natural gas, crude oil and NGLs owned at year end and changes in proved reserves during the last three years. Proved oil, gas and NGL reserves are those quantities of oil, gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved developed reserves are those reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for undeveloped reserves cannot be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. The proved reserves quantities and future net cash flows as of December 31, 2014, 2013 and 2012 were estimated using an unweighted 12-month average pricing based on the prices on the first day of each month during the years ended December 31, 2014, 2013 and 2012, including adjustments related to regional price differentials and energy content. | |||||||||||||
There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of oil and gas reserves included within the Partnership and ARP or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil and gas prices and in production and development costs and other factors, for their effects have not been proved. | |||||||||||||
Reserve quantity information and a reconciliation of changes in proved reserve quantities included within the Partnership and ARP are as follows (unaudited): | |||||||||||||
Gas (Mcf) | Oil (Bbls)(1) | NGLs (Bbls)(1) | |||||||||||
Balance, January 1, 2012 | 157,676,431 | 1,646,299 | — | ||||||||||
Extensions, discoveries and other additions(2) | 6,756,817 | 10,688 | — | ||||||||||
Sales of reserves in-place | — | — | — | ||||||||||
Purchase of reserves in-place | 462,504,519 | 7,485,998 | 16,212,356 | ||||||||||
Transfers to limited partnerships | — | — | — | ||||||||||
Revisions(3) | (27,760,192 | ) | (153,413 | ) | 206,091 | ||||||||
Production | (25,403,318 | ) | (120,736 | ) | (356,550 | ) | |||||||
Balance, December 31, 2012(4) | 573,774,257 | 8,868,836 | 16,061,897 | ||||||||||
Extensions, discoveries and other additions(2) | 90,098,219 | 8,255,531 | 8,197,272 | ||||||||||
Sales of reserves in-place | (2,755,155 | ) | — | (4,625 | ) | ||||||||
Purchase of reserves in-place | 493,481,302 | 1,964 | 55,187 | ||||||||||
Transfers to limited partnerships | (2,485,210 | ) | (239,910 | ) | (258,381 | ) | |||||||
Revisions(5) | (88,484,468 | ) | (1,412,371 | ) | (3,826,744 | ) | |||||||
Production | (59,849,442 | ) | (485,226 | ) | (1,267,590 | ) | |||||||
Balance, December 31, 2013 | 1,003,779,503 | 14,988,824 | 18,957,016 | ||||||||||
Extensions, discoveries and other additions(2) | 58,461,204 | 3,372,177 | 3,986,986 | ||||||||||
Sales of reserves in-place | (169,035 | ) | (1,519 | ) | (11,326 | ) | |||||||
Purchase of reserves in-place | 88,635,059 | 51,168,449 | 3,567,531 | ||||||||||
Transfers to limited partnerships | (4,887,095 | ) | (684,613 | ) | 956,810 | ||||||||
Revisions | 5,947,622 | (4,639,546 | ) | (2,689,372 | ) | ||||||||
Production | (86,889,803 | ) | (1,254,247 | ) | (1,387,865 | ) | |||||||
Balance, December 31, 2014 | 1,064,877,455 | 62,949,525 | 23,379,780 | ||||||||||
Proved developed reserves at: | |||||||||||||
January 1, 2012 | 138,403,225 | 1,638,083 | — | ||||||||||
December 31, 2012 | 338,655,324 | 3,400,447 | 7,884,778 | ||||||||||
December 31, 2013 | 766,872,394 | 3,459,260 | 7,676,389 | ||||||||||
December 31, 2014 | 889,073,136 | 31,150,298 | 12,209,825 | ||||||||||
Proved undeveloped reserves at: | |||||||||||||
1-Jan-12 | 19,273,206 | 8,216 | — | ||||||||||
December 31, 2012 | 235,118,932 | 5,468,389 | 8,177,120 | ||||||||||
December 31, 2013 | 236,907,109 | 11,529,564 | 11,280,627 | ||||||||||
December 31, 2014 | 175,804,319 | 31,799,227 | 11,169,954 | ||||||||||
(1) Oil includes NGL information at January 1, 2012, which was less than 500 MBbls. | |||||||||||||
(2) Principally includes increases of proved reserves due to the addition of Marble Falls wells. | |||||||||||||
(3) Represents a downward revision and related impairment charge related to ARP’s shallow natural gas wells in Michigan and Colorado due to declines in the average 1st day of the month price for the year ended December 31, 2012 as compared with the year ended December 31, 2011. | |||||||||||||
(4)Prior to the Arkoma Acquisition on July 31, 2013, Partnership had no oil and gas reserves. At December 31, 2014, there were no proved undeveloped reserves related to Partnership’s oil and gas assets. | |||||||||||||
(5) Represents a downward revision primarily due to a reduction of ARP’s five year drilling plans in the Barnett Shale and pricing scenario revisions. | |||||||||||||
Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized costs related to oil and gas producing activities of Partnership and ARP during the periods indicated were as follows (in thousands): | |||||||||||||
Years Ended December 31, | |||||||||||||
2014 | 2013 | ||||||||||||
Natural gas and oil properties: | |||||||||||||
Proved properties | $3,693,833 | $2,557,797 | |||||||||||
Unproved properties | 217,322 | 211,851 | |||||||||||
Support equipment | 37,359 | 23,258 | |||||||||||
3,894,513 | 2,792,906 | ||||||||||||
Accumulated depreciation, depletion and amortization | -1,518,686 | -649,635 | |||||||||||
Net capitalized costs | $2,375,827 | $2,143,271 | |||||||||||
Results of Operations from Oil and Gas Producing Activities. The results of operations related to Partnership’s and ARP’s oil and gas producing activities during the periods indicated were as follows (in thousands): | |||||||||||||
Years Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Revenues | $475,758 | $273,906 | $92,901 | ||||||||||
Production costs | -184,296 | -100,178 | -26,624 | ||||||||||
Depreciation, depletion and amortization | -231,638 | -132,860 | -47,000 | ||||||||||
Asset impairment(1) | -580,654 | -38,014 | -9,507 | ||||||||||
($520,830) | $2,854 | $9,770 | |||||||||||
(1) During the year ended December 31, 2014, the Partnership recognized $580.7 million of asset impairment consisting of $562.6 million related to oil and gas properties within property, plant, and equipment, net on the Partnership’s consolidated balance sheet primarily for ARP’s Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income, and $18.1 million goodwill impairment resulting from the decline in overall commodity prices. During the year ended December 31, 2013, ARP recognized $38.0 million of impairment primarily related to its shallow natural gas wells in the New Albany shale and unproved acreage in the Chattanooga and New Albany shales. During the year ended December 31, 2012, ARP recognized $9.5 million of impairment related to its shallow natural gas wells in the Antrim and Niobrara shales. | |||||||||||||
Costs Incurred in Oil and Gas Producing Activities. The costs incurred by the Partnership and ARP in their oil and gas activities during the periods indicated are as follows (in thousands): | |||||||||||||
Years Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Property acquisition costs: | |||||||||||||
Proved properties | $754,197 | $863,421 | $528,684 | ||||||||||
Unproved properties | 10,978 | 895 | 213,638 | ||||||||||
Exploration costs(1) | 722 | 1,053 | 1,026 | ||||||||||
Development costs | 177,726 | 214,383 | 83,538 | ||||||||||
Total costs incurred in oil & gas producing activities | $943,623 | $1,079,752 | $826,886 | ||||||||||
(1) There were no exploratory wells drilled during the years ended December 31, 2014, 2013 and 2012. | |||||||||||||
Standardized Measure of Discounted Future Cash Flows. The following schedule presents the standardized measure of estimated discounted future net cash flows relating to the Partnership’s and ARP’s proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2014, 2013 and 2012, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations (in thousands): | |||||||||||||
Years Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Future cash inflows | $10,802,697 | $5,268,148 | $2,930,514 | ||||||||||
Future production costs | -4,561,129 | -2,397,997 | -1,185,084 | ||||||||||
Future development costs | -1,623,218 | -752,369 | -441,423 | ||||||||||
Future net cash flows | 4,618,350 | 2,117,782 | 1,304,007 | ||||||||||
Less 10% annual discount for estimated timing of cash flows | -2,381,586 | -1,038,491 | -680,331 | ||||||||||
Standardized measure of discounted future net cash flows | $2,236,764 | $1,079,291 | $623,676 | ||||||||||
Changes in Standardized Discounted Future Cash Flows. The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved oil, gas and NGL reserves (in thousands), including amounts related to asset retirement obligations. Since the Partnership and ARP allocate taxable income to their owner, no recognition has been given to income taxes: | |||||||||||||
Years Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Balance, beginning of year | $1,079,291 | $623,676 | $219,859 | ||||||||||
Increase (decrease) in discounted future net cash flows: | |||||||||||||
Sales and transfers of oil and gas, net of related costs | -275,789 | -171,409 | -54,969 | ||||||||||
Net changes in prices and production costs | 339,776 | 85,191 | -87 | ||||||||||
Revisions of previous quantity estimates | -33,526 | -1,881 | -6,378 | ||||||||||
Development costs incurred | 52,077 | 27,245 | 575 | ||||||||||
Changes in future development costs | -90,887 | -21,579 | — | ||||||||||
Transfers to limited partnerships | -2,966 | -53,392 | — | ||||||||||
Extensions, discoveries, and improved recovery less related costs | 69,436 | 143,338 | 64 | ||||||||||
Purchases of reserves in-place | 1,018,345 | 516,985 | 510,467 | ||||||||||
Sales of reserves in-place | -332 | -2,053 | — | ||||||||||
Accretion of discount | 107,929 | 62,368 | 21,986 | ||||||||||
Estimated settlement of asset retirement obligations | -16,824 | -18,858 | -2,823 | ||||||||||
Estimated proceeds on disposals of well equipment | -21,896 | 17,052 | 3,806 | ||||||||||
Changes in production rates (timing) and other | 12,130 | -127,392 | -68,824 | ||||||||||
Outstanding, end of year | $2,236,764 | $1,079,291 | $623,676 | ||||||||||
Quarterly_Results
Quarterly Results | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | ||||||||||||||||
Quarterly Results | NOTE 21 — QUARTERLY RESULTS | |||||||||||||||
Fourth | Third | Second | First | |||||||||||||
Quarter(1) | Quarter(1) | Quarter(1) | Quarter(1) | |||||||||||||
(in thousands, except unit data) | ||||||||||||||||
Year ended December 31, 2014: | ||||||||||||||||
Revenues | $ | 992,534 | $ | 963,980 | $ | 851,889 | $ | 860,300 | ||||||||
Net income (loss) | (497,769 | ) | 31,513 | 21,933 | (21,067 | ) | ||||||||||
(Income) loss attributable to non-controlling interests | 338,544 | (40,598 | ) | (31,956 | ) | 7,142 | ||||||||||
Net loss attributable to common limited partners | $ | (159,225 | ) | $ | (9,085 | ) | $ | (10,023 | ) | $ | (13,925 | ) | ||||
Net loss attributable to common limited partners per unit: | ||||||||||||||||
Basic | $ | (3.06 | ) | $ | (0.18 | ) | $ | (0.19 | ) | $ | (0.27 | ) | ||||
Diluted | $ | (3.06 | ) | $ | (0.18 | ) | $ | (0.19 | ) | $ | (0.27 | ) | ||||
-1 | For the first, second, third and fourth quarters of the year ended December 31, 2014, approximately 4,111,000, 4,049,000, 5,082,000 and 4,637,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit because the inclusion of such units would have been anti-dilutive. | |||||||||||||||
Fourth | Third | Second | First | |||||||||||||
Quarter(1) | Quarter(1) | Quarter(1) | Quarter(1) | |||||||||||||
(in thousands, except unit data) | ||||||||||||||||
Year ended December 31, 2013: | ||||||||||||||||
Revenues | $ | 761,629 | $ | 649,989 | $ | 643,795 | $ | 522,102 | ||||||||
Net loss | (102,169 | ) | (79,546 | ) | (5,189 | ) | (41,694 | ) | ||||||||
(Income) loss attributable to non-controlling interests | 75,169 | 52,022 | (3,058 | ) | 29,098 | |||||||||||
Net loss attributable to common limited partners | $ | (27,000 | ) | $ | (27,524 | ) | $ | (8,247 | ) | $ | (12,596 | ) | ||||
Net loss attributable to common limited partners per unit: | ||||||||||||||||
Basic | $ | (0.53 | ) | $ | (0.54 | ) | $ | (0.16 | ) | $ | (0.25 | ) | ||||
Diluted | $ | (0.53 | ) | $ | (0.54 | ) | $ | (0.16 | ) | $ | (0.25 | ) | ||||
-1 | For the first, second, third and fourth quarters of the year ended December 31, 2013, approximately 3,594,000, 4,092,000, 4,196,000 and 4,091,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit because the inclusion of such units would have been anti-dilutive. | |||||||||||||||
Summary_of_Significant_Account1
Summary of Significant Accounting Policies (Policies) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Accounting Policies [Abstract] | |||||||||||||
Principles of Consolidation | Principles of Consolidation | ||||||||||||
The consolidated financial statements include the accounts of the Partnership and its consolidated subsidiaries, all of which are wholly-owned at December 31, 2014, except for ARP, APL and the Development Subsidiary, which are controlled by the Partnership. Due to the structure of the Partnership’s ownership interests in ARP, APL and the Development Subsidiary, the Partnership consolidates the financial statements of ARP, APL and the Development Subsidiary into its consolidated financial statements rather than present its ownership interest as equity investments. As such, the non-controlling interests in ARP, APL and the Development Subsidiary are reflected as (income) loss attributable to non-controlling interests in its consolidated statements of operations and as a component of partners’ capital on its consolidated balance sheets. All material intercompany transactions have been eliminated. Certain amounts in the prior years’ consolidated financial statements have been reclassified to conform to the current year presentation. | |||||||||||||
In accordance with established practice in the oil and gas industry, the Partnership’s consolidated financial statements include its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the Drilling Partnerships in which ARP has an interest. Such interests generally approximate 30%. The Partnership’s consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of ARP’s Drilling Partnerships. Rather, ARP calculates these items specific to its own economics as further explained under the heading “Property, Plant and Equipment” elsewhere within this note. | |||||||||||||
In connection with ARP’s acquisition of certain proved reserves and associated assets from Titan Operating, L.L.C. in July 2012, ARP issued 3.8 million ARP common units and 3.8 million newly-created convertible Class B ARP preferred units (“Class B ARP Preferred Units”). While outstanding, the preferred units will receive regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution. On December 23, 2014, 3,796,900 of Class B ARP preferred units were voluntarily converted into common units. In October 2014, in connection with ARP’s acquisition of assets in the Eagle Ford Shale (see Note 4), ARP issued 3.2 million of its 8.625% Class D cumulative redeemable perpetual preferred units (“Class D ARP Preferred Units”). The initial quarterly distribution on the Class D ARP Preferred Units was $0.616927 per unit, representing the distribution for the period from October 2, 2014 through January 14, 2015. Subsequent to January 14, 2015, ARP will pay a future quarterly distribution at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference. In March 2014, APL issued 5.1 million of its Class E cumulative redeemable perpetual preferred units (“Class E APL Preferred Units”). The initial distribution on the Class E APL Preferred Units was $0.67604 per unit, representing the distribution for the period March 17, 2014 through July 14, 2014. Subsequent to July 14, 2014, APL paid a quarterly distribution of $0.515625 per unit. In May 2013, APL issued Class D convertible preferred units (“Class D APL Preferred Units”), which received distributions of additional Class D APL Preferred Units for the first four full quarterly periods following their issuance in May 2013, and thereafter will receive distributions in Class D APL Preferred Units, or a combination of Class D APL Preferred Units and cash (see Note 15). At December 31, 2014 and 2013, $738.7 million and $547.3 million, respectively, related to ARP’s and APL’s preferred units is included within non-controlling interests on the Partnership’s consolidated statements of partners’ capital. | |||||||||||||
The Partnership’s consolidated financial statements include APL’s 95% ownership interest in certain joint ventures, which individually own a 100% ownership interest in the WestOK natural gas gathering system and processing plants and a 72.8% undivided interest in the WestTX natural gas gathering system and processing plants. These joint ventures have a $1.9 billion note receivable from the holder of the 5% ownership interest in the joint ventures, which was reflected within non-controlling interests on the Partnership’s consolidated balance sheets. | |||||||||||||
The Partnership’s consolidated financial statements also include APL’s 60% interest in Centrahoma Processing LLC (“Centrahoma”), which was acquired on December 20, 2012 as part of the acquisition of assets from Cardinal Midstream, LLC (the “Cardinal Acquisition”). The remaining 40% ownership interest is held by MarkWest Oklahoma Gas Company LLC (“MarkWest”), a wholly-owned subsidiary of MarkWest Energy Partners, L.P. (NYSE: MWE). | |||||||||||||
APL consolidates 100% of these joint ventures and the non-controlling interest in the joint venture is reflected on the Partnership’s consolidated statements of operations. The Partnership also reflects the non-controlling interest in the net assets of the joint venture as a component of partners’ capital on its consolidated balance sheets (see Note 5). | |||||||||||||
The West TX joint venture has a 72.8% undivided joint venture interest in the WestTX system, of which the remaining 27.2% interest is owned by Pioneer Natural Resources Company (NYSE: PXD). Due to the WestTX system’s status as an undivided joint venture, the WestTX joint venture proportionally consolidates its 72.8% ownership interest in the assets and liabilities and operating results of the WestTX system. | |||||||||||||
During the year ended December 31, 2014, the Development Subsidiary issued $81.7 million of its common limited partner units, which was included within non-controlling interests in partners’ capital on the Partnership’s consolidated balance sheet. During the year ended December 31, 2014, the Development Subsidiary paid $1.4 million to unitholders, which was included within distributions paid to non-controlling interests on the Partnership’s consolidated statement of cash flows. For the year ended December 31, 2014, in connection with the issuance of the Development Subsidiary’s common units, the Partnership recorded gains of $4.5 million within partners’ capital and a corresponding decrease in non-controlling interests on its consolidated statement of partners’ capital (see Note 15). | |||||||||||||
Use of Estimates | Use of Estimates | ||||||||||||
The preparation of the Partnership’s consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, asset impairments, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired and liabilities assumed. Actual results could differ from those estimates. | |||||||||||||
Cash Equivalents | Cash Equivalents | ||||||||||||
The Partnership considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. These cash equivalents consist principally of temporary investments of cash in short-term money market instruments. | |||||||||||||
Receivables | Receivables | ||||||||||||
Accounts receivable on the consolidated balance sheets consist primarily of the trade accounts receivable associated with the Partnership and its subsidiaries. In evaluating the realizability of its accounts receivable, management performs ongoing credit evaluations of customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of customers’ credit information. The Partnership and its subsidiaries extend credit on sales on an unsecured basis to many of their customers. At December 31, 2014 and 2013, the Partnership had recorded no allowance for uncollectible accounts receivable on its consolidated balance sheets. | |||||||||||||
Inventory | Inventory | ||||||||||||
The Partnership had $23.7 million and $19.7 million of inventory at December 31, 2014 and 2013, respectively, which were included within prepaid expenses and other current assets on its consolidated balance sheets. The Partnership and its subsidiaries value inventories at the lower of cost or market. ARP’s inventories, which consist of materials, pipes, supplies and other inventories, were principally determined using the average cost method. APL’s crude oil and refined product inventory costs consist of APL’s natural gas liquids line fill, which represents amounts receivable for NGLs delivered to counterparties for which the counterparty will pay at a designated later period at a price determined by the then current market price. | |||||||||||||
Subscriptions Receivable | Subscriptions Receivable | ||||||||||||
The Partnership receives contributions from limited partner investors of its Drilling Partnerships, which are used to fund well drilling activities within the programs. Limited partner investors in the Drilling Partnerships execute an investment agreement with Anthem Securities, Inc. (“Anthem”), a registered broker-dealer and wholly owned subsidiary of ARP, through third-party broker dealers, which is then delivered to Anthem. The investor contributions are then remitted to Anthem at a later date. Limited partner investor contributions are non-refundable upon the execution of an investment agreement. ARP recognizes the contributions associated with the executed investment agreements but for which contributions have not yet been received at the respective balance sheet date as subscriptions receivable. | |||||||||||||
Property, Plant and Equipment | Property, Plant and Equipment | ||||||||||||
Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Maintenance and repairs which generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements which generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the Partnership’s results of operations. APL follows the composite method of depreciation and has determined the composite groups to be the major asset classes of its gathering, processing and treating systems. Under the composite depreciation method, any gain or loss upon disposition or retirement of pipeline, gas gathering, processing and treating components is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the Partnership’s consolidated statements of operations. | |||||||||||||
The Partnership and ARP follow the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs to enhance or evaluate development of proved fields or areas are capitalized. All other geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to 6 Mcf of natural gas. Mcf is defined as one thousand cubic feet. | |||||||||||||
The Partnership and ARP’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves, and depletion rates for well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include ARP’s costs of property interests in proportionately consolidated Drilling Partnerships, joint venture wells, wells drilled solely by ARP for its interests, properties purchased and working interests with other outside operators. | |||||||||||||
Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Partnership’s consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Partnership’s consolidated balance sheets. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Partnership’s consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained. | |||||||||||||
Impairment of Long-Lived Assets | Impairment of Long-Lived Assets | ||||||||||||
The Partnership and its subsidiaries review their long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value. | |||||||||||||
The review of oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Partnership’s and ARP’s plans to continue to produce and develop proved reserves. Expected future cash flows from the sale of production of reserves are calculated based on estimated future prices. The Partnership and ARP estimate prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets. | |||||||||||||
The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, ARP’s reserve estimates for its investment in the Drilling Partnerships are based on its own assumptions rather than its proportionate share of the limited partnerships’ reserves. These assumptions include ARP’s actual capital contributions and a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs. | |||||||||||||
ARP’s lower operating and administrative costs result from the limited partners in the Drilling Partnerships paying to ARP their proportionate share of these expenses plus a profit margin. These assumptions could result in ARP’s calculation of depletion and impairment being different than its proportionate share of the Drilling Partnerships’ calculations for these items. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership and ARP cannot predict what reserve revisions may be required in future periods. | |||||||||||||
ARP’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the Drilling Partnerships, which ARP sponsors and owns an interest in but does not control. ARP’s reserve quantities include reserves in excess of its proportionate share of reserves in Drilling Partnerships, which ARP may be unable to recover due to the Drilling Partnerships’ legal structure. ARP may have to pay additional consideration in the future as a Drilling Partnership’s wells become uneconomic to the Drilling Partnership under the terms of the Drilling Partnership’s drilling and operating agreement in order to recover these excess reserves, in addition to ARP becoming responsible for paying associated future operating, development and plugging costs of the well interests acquired, and to acquire any additional residual interests in the wells held by the Drilling Partnership’s limited partners. The acquisition of any such uneconomic well interest from the Drilling Partnership by ARP is governed under the Drilling Partnership’s limited partner agreement. In general, ARP will seek consent from the Drilling Partnership’s limited partners to acquire the well interests from the Drilling Partnership based upon ARP’s determination of fair market value. | |||||||||||||
Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate that the Partnership and ARP will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. During the year ended December 31, 2013, ARP recognized $13.5 million of asset impairments related to its gas and oil properties within property, plant and equipment, net on the Partnership’s consolidated balance sheet, primarily for its unproved acreage in the Chattanooga and New Albany Shales. There were no impairments of unproved gas and oil properties recorded by ARP for the year ended December 31, 2014 and 2012. | |||||||||||||
Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. During the year ended December 31, 2014, the Partnership recognized $562.6 million of asset impairment related to oil and gas properties within property, plant and equipment, net on its consolidated balance sheet primarily for ARP’s Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. Asset impairments for the year ended December 31, 2014 principally resulted from the decline in forward commodity prices during the fourth quarter of 2014 through the impairment testing date in January 2015. During the year ended December 31, 2013, ARP recognized $24.5 million of asset impairments related to its gas and oil properties within property, plant and equipment, net on the Partnership’s consolidated balance sheet for its shallow natural gas wells in the New Albany Shale. During the year ended December 31, 2012, ARP recognized $9.5 million of asset impairments related to gas and oil properties within property, plant and equipment, net on its consolidated balance sheet for its shallow natural gas wells in the Antrim and Niobrara Shales. | |||||||||||||
These impairments related to the carrying amounts of these gas and oil properties being in excess of the Development Subsidiary’s and ARP’s estimates of their fair values at December 31, 2014, 2013, and 2012 and ARP’s intention not to drill on certain expiring unproved acreage. The estimate of the fair values of these gas and oil properties was impacted by, among other factors, the deterioration of commodity prices at the date of measurement. | |||||||||||||
Capitalized Interest | Capitalized Interest | ||||||||||||
ARP and APL capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rates used to capitalize interest on combined borrowed funds by ARP and APL were 5.6%, 5.9% and 5.8% for the years ended December 31, 2014, 2013 and 2012, respectively. The aggregate amounts of interest capitalized by ARP and APL were $25.7 million, $21.7 million and $10.8 million for the years ended December 31, 2014, 2013 and 2012, respectively. | |||||||||||||
Intangible Assets | Intangible Assets | ||||||||||||
Customer contracts and relationships. APL amortizes intangible assets with finite lives in connection with natural gas gathering contracts and customer relationships assumed in certain consummated acquisitions, including the acquisitions of assets from TEAK Midstream, LLC (“TEAK”) in 2013 (the “TEAK Acquisition”) (see Note 4), over their estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset must be amortized over the best estimate of its useful life. At a minimum, APL will assess the useful lives of all intangible assets on an annual basis to determine if adjustments are required. The estimated useful life for APL’s customer contract intangible assets is based upon the approximate average length of customer contracts in existence and expected renewals at the date of acquisition. The estimated useful life for APL’s customer relationship intangible assets is based upon the estimated average length of non-contracted customer relationships in existence at the date of acquisition, adjusted for APL’s management’s estimate of whether the individual relationships will continue in excess of or less than the average length. As part of the TEAK Acquisition, APL recognized $450.0 million of customer relationships with an estimated useful life of 13 years. | |||||||||||||
Partnership management and operating contracts. ARP has recorded intangible assets with finite lives in connection with partnership management and operating contracts acquired through prior consummated acquisitions. ARP amortizes contracts acquired on a declining balance method over their respective estimated useful lives. | |||||||||||||
The following table reflects the components of intangible assets being amortized at December 31, 2014 and 2013 (in thousands): | |||||||||||||
December 31, | Estimated | ||||||||||||
Useful Lives | |||||||||||||
In Years | |||||||||||||
2014 | 2013 | ||||||||||||
Gross Carrying Amount: | |||||||||||||
Customer contracts and relationships | $ | 871,072 | $ | 891,072 | 2–15 | ||||||||
Partnership management and operating contracts | 14,344 | 14,344 | 13 | ||||||||||
$ | 885,416 | $ | 905,416 | ||||||||||
Accumulated Amortization: | |||||||||||||
Customer contracts and relationships | $ | (274,811 | ) | $ | (194,801 | ) | |||||||
Partnership management and operating contracts | (13,653 | ) | (13,381 | ) | |||||||||
$ | (288,464 | ) | $ | (208,182 | ) | ||||||||
Net Carrying Amount: | |||||||||||||
Customer contracts and relationships | $ | 596,261 | $ | 696,271 | |||||||||
Partnership management and operating contracts | 691 | 963 | |||||||||||
$ | 596,952 | $ | 697,234 | ||||||||||
Amortization expense on intangible assets was $80.3 million, $69.3 million and $24.0 million for the years ended December 31, 2014, 2013 and 2012 respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2015 - $74.3 million; 2016 - $74.2 million; 2017 - $68.1 million; 2018 - $59.6 million; and 2019 - $59.6 million. | |||||||||||||
Goodwill | Goodwill | ||||||||||||
The following table reflects the carrying amounts of goodwill by reportable operating segments at December 31, 2014 and December 31, 2013 (in thousands): | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | ||||||||||||
Atlas Resource | $ | 13,639 | $ | 31,784 | |||||||||
Atlas Pipeline | 365,763 | 368,572 | |||||||||||
$ | 379,402 | $ | 400,356 | ||||||||||
At December 31, 2014, the Partnership had $379.4 million of goodwill, which consisted of $13.6 million related to acquisitions previously consummated by ARP and $365.8 million related to acquisitions previously consummated by APL. The change in ARP’s goodwill during the year end December 31, 2014 is related to goodwill impairment related to its gas and oil production reporting unit as a result of a decline in commodity prices. The change in APL’s goodwill during the year ended December 31, 2014 is primarily related to a $2.8 million decrease in goodwill related to an adjustment of the fair value of assets acquired and liabilities assumed from the TEAK Acquisition (see Note 4). | |||||||||||||
ARP and APL test goodwill for impairment at each year end by comparing their respective reporting unit estimated fair values to carrying values, with the exception of APL’s SouthTX reporting unit which is tested as of April 30, 2014. Because quoted market prices for the reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units. ARP’s and APL’s management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets and the available market data of the respective industry group. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to market capitalization. The observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity on a stand-alone basis. In most industries, including ARP’s and APL’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, ARP and APL also consider the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in ARP’s and APL’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in ARP’s and APL’s industry to determine whether those valuations appear reasonable in management’s judgment. ARP’s and APL’s management will continue to evaluate goodwill at least annually or when impairment indicators arise. | |||||||||||||
As a result of its impairment evaluation at December 31, 2014, ARP recognized an $18.1 million goodwill impairment charge within asset impairments on the Partnership’s consolidated statement of operations for the year ended December 31, 2014. The goodwill impairment resulted from the reduction in ARP’s estimated fair value of its gas and oil production reporting unit in comparison to its carrying amount at December 31, 2014. ARP’s estimated fair value of its gas and oil production reporting unit was impacted by a decline in overall commodity prices during the fourth quarter of 2014. During the years ended December 31, 2013 and 2012, no impairment indicators arose and no goodwill impairments were recognized for ARP by the Partnership. | |||||||||||||
Subsequent to recording the final estimated fair values of the assets acquired and liabilities assumed in the Cardinal Acquisition, APL determined that a portion of goodwill recorded in connection with the acquisition was impaired. APL performed a qualitative assessment for goodwill impairment of APL’s gas treating reporting unit. The assessment indicated the potential for goodwill to be impaired due to lower forecasted cash flows as compared to original forecasts. Using a combination of discounted cash flow models and market multiples for similar businesses, APL measured the amount of goodwill impairment to be $43.9 million, which was recorded within asset impairment on the Partnership’s consolidated statement of operations for the year ended December 31, 2013. | |||||||||||||
During the years ended December 31, 2014 and 2012, no impairment indicators arose and no goodwill impairments were recognized for APL by the Partnership. | |||||||||||||
Equity Method Investments Policy | Equity Method Investments | ||||||||||||
The Partnership’s consolidated financial statements include APL’s previous interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”) which was sold in May 2014 (see Note 5); and APL’s interests in T2 LaSalle Gathering Company L.L.C. (“T2 LaSalle”), T2 Eagle Ford Gathering Company L.L.C. (“T2 Eagle Ford”), and T2 EF Cogeneration Holdings L.L.C. (“T2 Co-Gen”) (the “T2 Joint Ventures”), which were acquired as part of APL’s acquisition of 100% of the equity interests of TEAK Midstream, LLC (“TEAK”) for $974.7 million in cash, including final purchase price adjustments, less cash received (the “TEAK Acquisition”) (see Notes 4 and 5). APL accounts for its investments in these joint ventures under the equity method of accounting. Under this method, APL records its proportionate share of the joint ventures’ net income (loss) as equity income on the Partnership’s consolidated statements of operations. Investments in excess of the underlying net assets of equity method investees identifiable to property, plant and equipment or finite lived intangible assets are amortized over the useful life of the related assets and recorded as a reduction to equity investment on the Partnership’s consolidated balance sheet with an offsetting reduction to equity income on the Partnership’s consolidated statements of operations. Equity method investments are subject to impairment evaluation as necessary when events and circumstances indicate the carrying value of an equity investment may be less than its fair value. APL noted no indicators of impairment for its equity method investments, and thus no impairment charges were recognized for the years ended as of December 31, 2014, 2013 and 2012. | |||||||||||||
The Partnership’s consolidated financial statements also include its interest in Lightfoot which is accounted for under the equity method of accounting (see Note 7). | |||||||||||||
Capital Leases | Capital Leases | ||||||||||||
Leased property and equipment meeting capital lease criteria are capitalized based on the minimum payments required under the lease and are included within property, plant and equipment on the Partnership’s consolidated balance sheets. Obligations under capital leases are accounted for as current and noncurrent liabilities and are included within debt on the Partnership’s consolidated balance sheets. Amortization is calculated on a straight-line method based upon the estimated useful lives of the assets (see Note 9). | |||||||||||||
Derivative Instruments | Derivative Instruments | ||||||||||||
The Partnership enters into certain financial contracts to manage its exposure to movement in commodity prices and interest rates (see Note 10). The derivative instruments recorded in the consolidated balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in the Partnership’s consolidated statements of operations unless specific hedge accounting criteria are met. | |||||||||||||
Asset Retirement Obligations | Asset Retirement Obligations | ||||||||||||
The Partnership and ARP recognize an estimated liability for the plugging and abandonment of their respective gas and oil wells and related facilities (see Note 8). The Partnership and ARP also recognize a liability for their respective future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership and its subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization. | |||||||||||||
APL performs ongoing analysis of asset removal and site restoration costs that it may be required to perform under law or contract once an asset has been permanently taken out of service. APL has property, plant and equipment at locations it owns and at sites leased or under right of way agreements. APL is under no contractual obligation to remove the assets at locations it owns. In evaluating its asset retirement obligation, APL reviews its lease agreements, right of way agreements, easements and permits to determine which agreements, if any, require an asset removal and restoration obligation. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including expected settlement dates, future retirement costs, future inflation rates and the credit-adjusted-risk-free interest rates. However, APL was not able to reasonably measure the fair value of the asset retirement obligation as of December 31, 2014 because the settlement dates were indeterminable. Any cost incurred in the future to remove assets and restore sites will be expensed as incurred. | |||||||||||||
Income Taxes | Income Taxes | ||||||||||||
The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income (loss) reported in the accompanying consolidated financial statements. | |||||||||||||
The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its consolidated financial statements that would not meet this threshold. The Partnership’s policy is to record interest and penalties related to uncertain tax positions, when and if they become applicable. The Partnership has not recognized any potential interest or penalties in its consolidated financial statements for the years ended December 31, 2014, 2013 and 2012. | |||||||||||||
The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2011. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2014, except for an ongoing examination by the Texas Comptroller of Public Accounts related to APL’s Texas Franchise Tax for franchise report years 2008 through 2011. | |||||||||||||
Certain corporate subsidiaries of the Partnership are subject to federal and state income tax. With the exception of a corporate subsidiary acquired by APL through the Cardinal acquisition in 2012, the federal and state income taxes related to the Partnership and these corporate subsidiaries were immaterial to the consolidated financial statements as of December 31, 2014 and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for these corporate subsidiaries in the accompanying consolidated financial statements. APL’s corporate subsidiary accounts for income taxes under the asset and liability method. Deferred income taxes are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realization of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value. The effective tax rate differs from the statutory rate due primarily to APL earnings that are generally not subject to federal and state income taxes at the APL level (see Note 12). | |||||||||||||
Stock-Based Compensation | Stock-Based Compensation | ||||||||||||
The Partnership recognizes all share-based payments to employees, including grants of employee stock options, in the consolidated financial statements based on their fair values (see Note 17). | |||||||||||||
Net Income (Loss) Per Common Unit | Net Income (Loss) Per Common Unit | ||||||||||||
Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners, which is determined after the deduction of net income attributable to participating securities, if applicable, by the weighted average number of common limited partner units outstanding during the period. | |||||||||||||
Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit pursuant to the two-class method. The Partnership’s phantom unit awards, which consist of common units issuable under the terms of its long-term incentive plans and incentive compensation agreements (see Note 17), contain non-forfeitable rights to distribution equivalents of the Partnership. The participation rights result in a non-contingent transfer of value each time the Partnership declares a distribution or distribution equivalent right during the award’s vesting period. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. As such, the net income utilized in the calculation of net income (loss) per unit must be after the allocation of only net income to the phantom units on a pro-rata basis. | |||||||||||||
The following is a reconciliation of net income (loss) allocated to the common limited partners for purposes of calculating net income (loss) attributable to common limited partners per unit (in thousands, except unit data): | |||||||||||||
Years Ended December 31, | |||||||||||||
Continuing Operations: | 2014 | 2013 | 2012 | ||||||||||
Net loss | $ | (465,390 | ) | $ | (228,598 | ) | $ | (16,881 | ) | ||||
Loss (income) attributable to non-controlling interests | 273,132 | 153,231 | (35,532 | ) | |||||||||
Net loss attributable to common limited partners | (192,258 | ) | (75,367 | ) | (52,413 | ) | |||||||
Less: Net income attributable to participating securities – phantom units(1) | — | — | — | ||||||||||
Net loss utilized in the calculation of net loss attributable to common limited partners per unit | $ | (192,258 | ) | $ | (75,367 | ) | $ | (52,413 | ) | ||||
(1) | Net income attributable to common limited partners’ ownership interests is allocated to the phantom units on a pro-rata basis (weighted average phantom units outstanding as a percentage of the sum of the weighted average phantom units and common limited partner units outstanding). For the years ended December 31, 2014, 2013 and 2012, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 2,827,000, 2,278,000 and 2,058,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. | ||||||||||||
Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners, less income allocable to participating securities, by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of unit option awards, as calculated by the treasury stock method. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of the Partnership’s long-term incentive plans (see Note 17). | |||||||||||||
The following table sets forth the reconciliation of the Partnership’s weighted average number of common limited partner units used to compute basic net income (loss) attributable to common limited partners per unit with those used to compute diluted net income (loss) attributable to common limited partners per unit (in thousands): | |||||||||||||
Years Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Weighted average number of common limited partners per unit—basic | 51,810 | 51,387 | 51,327 | ||||||||||
Add effect of dilutive incentive awards(1) | — | — | — | ||||||||||
Weighted average number of common limited partners per unit—diluted | 51,810 | 51,387 | 51,327 | ||||||||||
(1) | For the years ended December 31, 2014, 2013 and 2012, approximately 4,473,000, 3,995,000 and 2,867,000 units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. | ||||||||||||
Environmental Matters | Environmental Matters | ||||||||||||
The Partnership and its subsidiaries are subject to various federal, state and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of the Partnership’s and its subsidiaries’ operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. The Partnership and its subsidiaries maintain insurance which may cover in whole or in part certain environmental expenditures. The Partnership and its subsidiaries had no environmental matters requiring specific disclosure or requiring the recognition of a liability for the years ended December 31, 2014 and 2013. During the year ended December 31, 2012, one of the Partnership’s subsidiaries entered into two agreements with the United States Environmental Protection Agency (the “EPA”) to settle alleged violations in connection with a fire that occurred at a natural gas well and associated well pad site in Washington County, Pennsylvania in 2010. The EPA alleged non-compliance with the Clean Air Act, including with respect to the storage and handling of the natural gas condensate, as well as non-compliance with the Emergency Planning and Community Right-to-Know Act of 1986. The subsidiary agreed to a civil penalty of $84,506 under a consent agreement and agreed to upgrade its facility pursuant to an administrative settlement agreement. | |||||||||||||
Concentration of Credit Risk | Concentration of Credit Risk | ||||||||||||
Financial instruments, which potentially subject the Partnership to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. The Partnership and its subsidiaries place their temporary cash investments in high-quality short-term money market instruments and deposits with high-quality financial institutions and brokerage firms. At December 31, 2014 and 2013, the Partnership had $86.5 million and $51.4 million, respectively, in deposits at various banks, of which $81.6 million and $48.8 million, respectively, were over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments to date. Cash on deposit at various banks may differ from the balance of cash and cash equivalents at period end due to certain reconciling items, including any outstanding checks as of period end. | |||||||||||||
The Partnership and its subsidiaries sell natural gas, crude oil and NGLs under contracts to various purchasers in the normal course of business. For the year ended December 31, 2014, ARP had four customers within its gas and oil production segment that individually accounted for approximately 25%, 15%, 14% and 13%, respectively, of its natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2013, ARP had three customers within its gas and oil production segment that individually accounted for approximately 19%, 11% and 10%, respectively, of its natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2012, ARP had two customers within its gas and oil production segment that individually accounted for approximately 43% and 11% of its natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. | |||||||||||||
For the year ended December 31, 2014, APL had three customers that individually accounted for approximately 26%, 13% and 11%, respectively, of its consolidated total third party revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2013, APL had three customers that individually accounted for approximately 29%, 17% and 14%, respectively, of its consolidated total third party revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2012, APL had two customers that individually accounted for approximately 48% and 15%, respectively, of its consolidated total third party revenues, excluding the impact of all financial derivative activity. | |||||||||||||
Accrued Producer Liabilities | Accrued Producer Liabilities | ||||||||||||
Accrued producer liabilities on the Partnership’s consolidated balance sheets represent APL’s accrued purchase commitments payable to producers related to the natural gas gathered and processed through its system under its Percentage of Proceeds (“POP”) and Keep-Whole contracts (see “Revenue Recognition”). | |||||||||||||
Revenue Recognition | Revenue Recognition | ||||||||||||
Natural gas and oil production. The Partnership and ARP generally sell natural gas, crude oil and NGLs at prevailing market prices. Typically, sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil and NGLs, in which the Partnership or ARP has an interest with other producers, are recognized on the basis of the entity’s percentage ownership of the working interest and/or overriding royalty. | |||||||||||||
ARP’s Drilling Partnerships. Certain energy activities are conducted by ARP through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. Drilling Partnership investor capital raised by ARP is deployed to drill and complete wells included within the partnership. As ARP deploys Drilling Partnership investor capital, it recognizes certain management fees it is entitled to receive, including well construction and completion revenue and a portion of administration and oversight revenue. At each period end, if ARP has Drilling Partnership investor capital that has not yet been deployed, it will recognize a current liability titled “Liabilities Associated with Drilling Contracts” on the Partnership’s consolidated balance sheets. After the Drilling Partnership well is completed and turned in line, ARP is entitled to receive additional operating and management fees, which are included within well services and administration and oversight revenue, respectively, on a monthly basis while the well is operating. In addition to the management fees it is entitled to receive for services provided, ARP is also entitled to its pro-rata share of Drilling Partnership gas and oil production revenue, which generally approximates 30%. ARP recognizes its Drilling Partnership management fees in the following manner: | |||||||||||||
— | Well construction and completion. For each well that is drilled by a Drilling Partnership, ARP receives a 15% mark-up on those costs incurred to drill and complete wells included within the partnership. Such fees are earned, in accordance with the partnership agreement, and recognized as the services are performed, typically between 60 and 270 days, using the percentage of completion method. | ||||||||||||
— | Administration and oversight. For each well drilled by a Drilling Partnership, ARP receives a fixed fee between $100,000 and $500,000, depending on the type of well drilled, which is earned in accordance with the partnership agreement and recognized at the initiation of the well. Additionally, the Drilling Partnership pays ARP a monthly per well administrative fee of $75 for the life of the well. The well administrative fee is earned on a monthly basis as the services are performed. | ||||||||||||
— | Well services. Each Drilling Partnership pays ARP a monthly per well operating fee, currently $1,000 to $2,000, depending on the type of well, for the life of the well. Such fees are earned on a monthly basis as the services are performed. | ||||||||||||
While its historical structure has varied, ARP has generally agreed to subordinate a portion of its share of Drilling Partnership gas and oil production revenue, net of corresponding production costs and up to a maximum of 50% of unhedged revenue, from certain Drilling Partnerships for the benefit of the limited partner investors until they have received specified returns, typically 10% to 12% per year determined on a cumulative basis, over a specified period, typically the first five to eight years, in accordance with the terms of the partnership agreements. ARP periodically compares the projected return on investment for limited partners in a Drilling Partnership during the subordination period, based upon historical and projected cumulative gas and oil production revenue and expenses, with the return on investment subject to subordination agreed upon within the Drilling Partnership agreement. If the projected return on investment falls below the agreed upon rate, ARP recognizes subordination as an estimated reduction of its pro-rata share of gas and oil production revenue, net of corresponding production costs, during the current period in an amount that will achieve the agreed upon investment return, subject to the limitation of 50% of unhedged cumulative net production revenues over the subordination period. For Drilling Partnerships for which ARP has recognized subordination in a historical period, if projected investment returns subsequently reflect that the agreed upon limited partner investment return will be achieved during the subordination period, ARP will recognize an estimated increase in its portion of historical cumulative gas and oil net production, subject to a limitation of the cumulative subordination previously recognized. | |||||||||||||
ARP’s Gathering and processing revenue. Gathering and processing revenue includes gathering fees ARP charges to the Drilling Partnership wells for ARP’s processing plants in the New Albany and the Chattanooga Shales. Generally, ARP charges a gathering fee to the Drilling Partnership wells equivalent to the fees ARP remits. In Appalachia, a majority of the Drilling Partnership wells are subject to a gathering agreement, whereby ARP remits a gathering fee of 16%. However, based on the respective Drilling Partnership agreements, ARP charges the Drilling Partnership wells a 13% gathering fee. As a result, some of ARP’s gathering expenses, specifically those in the Appalachian Basin, will generally exceed the revenues collected from the Drilling Partnerships by approximately 3%. | |||||||||||||
Atlas Pipeline. APL’s revenue primarily consists of the sale of natural gas and NGLs, along with the fees earned from its gathering, processing and treating operations. Under certain agreements, APL purchases natural gas from producers, moves it into receipt points on its pipeline systems and then sells the natural gas, or produced NGLs and condensate, if any, off delivery points on its systems. Under other agreements, APL gathers natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with the physical sale of natural gas and NGLs is recognized upon physical delivery. Revenue related to fees for providing natural gas gathering, processing and treating services is recognized based on throughput volumes during the period, with throughput volumes generally measured at the wellhead. In connection with its gathering, processing and treating operations, APL enters into the following types of contractual relationships with its producers and shippers: | |||||||||||||
POP Contracts. These contracts provide for APL to retain a negotiated percentage of the sale proceeds from residue gas and NGLs it gathers and processes, with the remainder being remitted to the producer. In this contract-type, APL and the producer are directly dependent on the volume of the commodity and its value; APL effectively owns a percentage of the commodity and revenues are directly correlated to its market value. | |||||||||||||
Keep-Whole Contracts. These contracts require APL, as the processor and gatherer, to gather or purchase raw natural gas at current market rates per MMBtu. The volume and energy content of gas gathered or purchased is based on the measurement at an agreed upon location (generally at the wellhead). The Btu quantity of gas redelivered or sold at the tailgate of APL’s processing facility may be lower than the Btu quantity purchased at the wellhead primarily due to the NGLs extracted from the natural gas when processed through a plant. APL must make up or “keep the producer whole” for this loss in Btu quantity. To offset the make-up obligation, APL retains the NGLs which are extracted and sells them for its own account. During 2014, APL renegotiated most of its Keep-Whole contracts and converted them into POP contracts. | |||||||||||||
Fee-based or POP contracts sometimes include fixed recovery terms, which mean products returned to the producer are calculated using an agreed NGL recovery factor, regardless of the volumes of NGLs actually recovered through processing. | |||||||||||||
The Partnership and its subsidiaries accrue unbilled revenue and APL accrues the related purchase costs due to timing differences between the delivery of natural gas, NGLs, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “Use of Estimates” for further description). The Partnership and its subsidiaries had unbilled revenues of $260.7 million and $191.8 million at December 31, 2014 and 2013, respectively, which were included in accounts receivable within its consolidated balance sheets. APL’s accrued purchase costs at December 31, 2014 and 2013 are included within accrued producer liabilities within the Partnership’s consolidated balance sheets. | |||||||||||||
Comprehensive Income (Loss) | Comprehensive Income (Loss) | ||||||||||||
Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on the Partnership’s consolidated financial statements, and for all periods presented, only include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges (see Note 10). The Partnership does not have any other type of transaction which would be included within other comprehensive income (loss). | |||||||||||||
Recently Adopted Accounting Standards | Recently Adopted Accounting Standards | ||||||||||||
In November 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-17, Business Combinations (Topic 805) – Pushdown Accounting (“Update 2014-17”). The amendments in Update 2014-17 provide an acquired entity with an option to apply pushdown accounting in its separate financial statements upon occurrence of an event in which an acquirer obtains control of the acquired entity. The amendments in Update 2014-17 also provide U.S. GAAP guidance on whether and at what threshold an acquired entity that is a business can apply pushdown accounting in its separate financial statements. The amendments in Update 2014-17 became effective on November 18, 2014. After the effective date, an acquired entity can make an election to apply the guidance to future change-in-control events or to its most recent change-in-control event. However, if the financial statements for the period in which the most recent change-in-control event occurred already have been issued or made available to be issued, the application of this guidance would be a change in accounting principle. The Partnership adopted the requirements of Update 2014-17 upon its effective date of November 18, 2014, and it had no material impact on its financial position, results of operations or related disclosures. | |||||||||||||
In July 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-11, Income Taxes (Topic 740) – Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (“Update 2013-11”), which, among other changes, requires an entity to present an unrecognized tax benefit as a liability and not net with deferred tax assets when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date to settle any additional income taxes under the tax law of the applicable jurisdiction that would result from the disallowance of a tax position or when the tax law of the applicable tax jurisdiction does not require, and the entity does not intend to, use the deferred tax asset for such purpose. These requirements are effective for interim and annual reporting periods beginning after December 15, 2013. Early adoption was permitted. These amendments should be applied prospectively to all unrecognized tax benefits that exist at the effective date. Retrospective application was permitted. The Partnership adopted the requirements of Update 2013-11 upon its effective date of January 1, 2014, and it had no material impact on its financial position, results of operations or related disclosures. | |||||||||||||
In February 2013, the FASB issued ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements, for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements, for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership adopted the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it had no material impact on its financial position, results of operations or related disclosures. | |||||||||||||
Recently Issued Accounting Standards | Recently Issued Accounting Standards | ||||||||||||
In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“Update 2015-02”). The amendments in Update 2015-02 are intended to improve targeted areas of consolidation guidance for legal entities such as limited partnerships, limited liability corporations and securitization structures. The amendments simplify the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. The amendments in Update 2015-02 are effective for periods beginning after December 31, 2015. Early adoption is permitted, including adoption in an interim period. The Partnership will adopt the requirements of Update 2015-02 upon its effective date of January 1, 2016, and is evaluating the impact of adoption on its financial position, results of operations or related disclosures. | |||||||||||||
In January 2015, the FASB issued ASU 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items (“Update 2015-01”). The amendments in Update 2015-01 simplify the income statement presentation requirements in Subtopic 225-20 by eliminating the concept of extraordinary items. Extraordinary items are events and transactions that are distinguished by their unusual nature and by the infrequency of their occurrence. Eliminating the extraordinary classification simplifies income statement presentation by altogether removing the concept of extraordinary items from consideration. The amendments in Update 2015-01 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. A reporting entity may apply the amendments prospectively. A reporting entity may also apply the amendments retrospectively to all prior periods presented in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal year of adoption. The Partnership will adopt the requirements of Update 2015-01 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures. | |||||||||||||
In November 2014, the FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815) – Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share is More Akin to Debt or to Equity (“Update 2014-16”). Certain classes of shares include features that entitle the holders to preferences and rights (such as conversion rights, redemption rights, voting powers, and liquidation and dividend payment preferences) over the other shareholders. Shares that include embedded derivative features are referred to as hybrid financial instruments, which must be separated from the host contract and accounted for as a derivative if certain criteria are met under Subtopic 815-10. One criterion requires evaluating whether the nature of the host contract is more akin to debt or to equity and whether the economic characteristics and risks of the embedded derivative feature are “clearly and closely related” to the host contract. In making that evaluation, an issuer or investor may consider all terms and features in a hybrid financial instrument including the embedded derivative feature that is being evaluated for separate accounting or may consider all terms and features in the hybrid financial instrument except for the embedded derivative feature that is being evaluated for separate accounting. The use of different methods can result in different accounting outcomes for economically similar hybrid financial instruments. Additionally, there is diversity in practice with respect to the consideration of redemption features in relation to other features when determining whether the nature of a host contract is more akin to debt or to equity. The amendments in Update 2014-16 clarify how current GAAP should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. The effects of initially adopting the amendments in Update 2014-16 should be applied on a modified retrospective basis to existing hybrid financial instruments issued in the form of a share as of the beginning of the fiscal year for which the amendments are effective. Retrospective application is permitted to all relevant prior periods. The amendments in Update 2014-16 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption, including adoption in an interim period, is permitted. The Partnership will adopt the requirements of Update 2014-16 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures. | |||||||||||||
In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) (“Update 2014-15”). The amendments in Update 2014-15 provide U.S. GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management will be required to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. The Partnership will adopt the requirements of Update 2014-15 upon its effective date of January 1, 2017, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures. | |||||||||||||
In June 2014, the FASB issued ASU 2014-12, Compensation – Stock Compensation (Topic 718) (“Update 2014-12”). The amendments in Update 2014-12 require that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. As such, the performance target should not be reflected in estimating the grant date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved. The amendments in Update 2014-12 are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Earlier adoption is permitted. Entities may apply the amendments in Update 2014-12 either (a) prospectively to all awards granted or modified after the effective date, or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. The Partnership will adopt the requirements of Update 2014-12 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures. | |||||||||||||
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles – Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. The Partnership will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2017, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures. | |||||||||||||
Derivative_Instruments_Policie
Derivative Instruments (Policies) | 12 Months Ended |
Dec. 31, 2014 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Derivatives, Methods of Accounting, Derivative Types | The Partnership and its subsidiaries use a number of different derivative instruments, principally swaps, collars, and options, in connection with their commodity and interest rate price risk management activities. The Partnership and its subsidiaries enter into financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold or interest payments on the underlying debt instrument are due. Under commodity-based swap agreements, the Partnership and its subsidiaries receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. To manage the risk of regional commodity price differences, the Partnership and its subsidiaries occasionally enter into basis swaps. Basis swaps are contractual arrangements that guarantee a price differential for a commodity from a specified delivery point price and the comparable national exchange price. For natural gas basis swaps, which have negative differentials to NYMEX, the Partnership and its subsidiaries receive or pay a payment from the counterparty if the price differential to NYMEX is greater or less than the stated terms of the contract. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike, price and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged. |
Derivatives, Methods of Accounting, Hedge Effectiveness | The Partnership and ARP apply the principles of hedge accounting for derivatives qualifying as hedges. Accordingly, the Partnership and ARP formally document all relationships between hedging instruments and the items being hedged, including their risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity and interest derivative contracts to the forecasted transactions. The Partnership and ARP assess, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the Partnership and ARP will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which are determined by management through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated statements of operations. For derivatives qualifying as hedges, the Partnership and ARP recognize the effective portion of changes in fair value of derivative instruments in partners’ capital as accumulated other comprehensive income (loss) and reclassify the portion relating to the Partnership and ARP’s commodity derivatives within gas and oil production revenues and the portion relating to interest rate derivatives to interest expense within the Partnership’s consolidated statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, changes in fair value are recognized within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated statements of operations as they occur. |
Derivatives, Basis and Use of Derivatives, Use of Derivatives | The Partnership and its subsidiaries enter into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s consolidated balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s consolidated balance sheets as the initial value of the options. |
Summary_of_Significant_Account2
Summary of Significant Accounting Policies (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Accounting Policies [Abstract] | |||||||||||||
Schedule of the Components of Intangible Assets Being Amortized | The following table reflects the components of intangible assets being amortized at December 31, 2014 and 2013 (in thousands): | ||||||||||||
December 31, | Estimated | ||||||||||||
Useful Lives | |||||||||||||
In Years | |||||||||||||
2014 | 2013 | ||||||||||||
Gross Carrying Amount: | |||||||||||||
Customer contracts and relationships | $ | 871,072 | $ | 891,072 | 2–15 | ||||||||
Partnership management and operating contracts | 14,344 | 14,344 | 13 | ||||||||||
$ | 885,416 | $ | 905,416 | ||||||||||
Accumulated Amortization: | |||||||||||||
Customer contracts and relationships | $ | (274,811 | ) | $ | (194,801 | ) | |||||||
Partnership management and operating contracts | (13,653 | ) | (13,381 | ) | |||||||||
$ | (288,464 | ) | $ | (208,182 | ) | ||||||||
Net Carrying Amount: | |||||||||||||
Customer contracts and relationships | $ | 596,261 | $ | 696,271 | |||||||||
Partnership management and operating contracts | 691 | 963 | |||||||||||
$ | 596,952 | $ | 697,234 | ||||||||||
Summary of Carrying Amounts of Goodwill by Reportable Operating Segments | The following table reflects the carrying amounts of goodwill by reportable operating segments at December 31, 2014 and December 31, 2013 (in thousands): | ||||||||||||
December 31, | |||||||||||||
2014 | 2013 | ||||||||||||
Atlas Resource | $ | 13,639 | $ | 31,784 | |||||||||
Atlas Pipeline | 365,763 | 368,572 | |||||||||||
$ | 379,402 | $ | 400,356 | ||||||||||
Reconciliation of Net Income (Loss) | The following is a reconciliation of net income (loss) allocated to the common limited partners for purposes of calculating net income (loss) attributable to common limited partners per unit (in thousands, except unit data): | ||||||||||||
Years Ended December 31, | |||||||||||||
Continuing Operations: | 2014 | 2013 | 2012 | ||||||||||
Net loss | $ | (465,390 | ) | $ | (228,598 | ) | $ | (16,881 | ) | ||||
Loss (income) attributable to non-controlling interests | 273,132 | 153,231 | (35,532 | ) | |||||||||
Net loss attributable to common limited partners | (192,258 | ) | (75,367 | ) | (52,413 | ) | |||||||
Less: Net income attributable to participating securities – phantom units(1) | — | — | — | ||||||||||
Net loss utilized in the calculation of net loss attributable to common limited partners per unit | $ | (192,258 | ) | $ | (75,367 | ) | $ | (52,413 | ) | ||||
(1) | Net income attributable to common limited partners’ ownership interests is allocated to the phantom units on a pro-rata basis (weighted average phantom units outstanding as a percentage of the sum of the weighted average phantom units and common limited partner units outstanding). For the years ended December 31, 2014, 2013 and 2012, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 2,827,000, 2,278,000 and 2,058,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. | ||||||||||||
Reconciliation of the Partnership's Weighted Average Number of Common Limited Partner Units | The following table sets forth the reconciliation of the Partnership’s weighted average number of common limited partner units used to compute basic net income (loss) attributable to common limited partners per unit with those used to compute diluted net income (loss) attributable to common limited partners per unit (in thousands): | ||||||||||||
Years Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Weighted average number of common limited partners per unit—basic | 51,810 | 51,387 | 51,327 | ||||||||||
Add effect of dilutive incentive awards(1) | — | — | — | ||||||||||
Weighted average number of common limited partners per unit—diluted | 51,810 | 51,387 | 51,327 | ||||||||||
(1) | For the years ended December 31, 2014, 2013 and 2012, approximately 4,473,000, 3,995,000 and 2,867,000 units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. |
Acquisitions_from_Atlas_Energy
Acquisitions from Atlas Energy, Inc. (Tables) (Transferred Business AEI) | 12 Months Ended | |||
Dec. 31, 2014 | ||||
Transferred Business AEI | ||||
Assets Acquired and Liabilities Assumed in Acquisition | ||||
Cash | $ | 153,350 | ||
Accounts receivable | 18,090 | |||
Accounts receivable – affiliate | 45,682 | |||
Prepaid expenses and other | 6,955 | |||
Total current assets | 224,077 | |||
Property, plant and equipment, net | 516,625 | |||
Goodwill | 31,784 | |||
Intangible assets, net | 2,107 | |||
Other assets, net | 20,416 | |||
Total long-term assets | 570,932 | |||
Total assets acquired | $ | 795,009 | ||
Accounts payable | $ | 59,202 | ||
Net liabilities associated with drilling contracts | 47,929 | |||
Accrued well completion costs | 39,552 | |||
Current portion of derivative payable to Drilling Partnerships | 25,659 | |||
Accrued liabilities | 25,283 | |||
Total current liabilities | 197,625 | |||
Long-term derivative payable to Drilling Partnerships | 31,719 | |||
Asset retirement obligations | 42,791 | |||
Total long-term liabilities | 74,510 | |||
Total liabilities assumed | $ | 272,135 | ||
Historical carrying value of net assets acquired | $ | 522,874 | ||
Acquisitions_Tables
Acquisitions (Tables) | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Business Acquisition, Pro Forma Information | ||||||||||
Years Ended December 31, | ||||||||||
2014 | 2013 | |||||||||
Total revenues and other | $ | 3,714,704 | $ | 2,793,098 | ||||||
Net loss | (427,351 | ) | (141,776 | ) | ||||||
Net loss attributable to common limited partners | (181,455 | ) | (51,653 | ) | ||||||
Net loss attributable to common limited partners per unit: | ||||||||||
Basic and Diluted | $ | (3.50 | ) | $ | (1.01 | ) | ||||
Rangely Acquisition | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Assets Acquired and Liabilities Assumed in Acquisition | The following table presents the preliminary values assigned to the assets acquired and liabilities assumed in the acquisition, based on their estimated fair values at the date of the acquisition (in thousands): | |||||||||
Assets: | ||||||||||
Prepaid expenses and other | 4,041 | |||||||||
Property, plant and equipment | 405,876 | |||||||||
Other assets, net | 2,888 | |||||||||
Total assets acquired | $ | 412,805 | ||||||||
Liabilities: | ||||||||||
Accrued liabilities | 2,117 | |||||||||
Asset retirement obligation | 1,305 | |||||||||
Total liabilities assumed | 3,422 | |||||||||
Net assets acquired | $ | 409,383 | ||||||||
EP Energy Acquisition | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Assets Acquired and Liabilities Assumed in Acquisition | The following table presents the values assigned to the assets acquired and liabilities assumed in the EP Energy Acquisition, based on their estimated fair values at the date of the acquisition (in thousands): | |||||||||
Assets: | ||||||||||
Prepaid expenses and other | $5,268 | |||||||||
Property, plant and equipment | 723,842 | |||||||||
Total current assets | $729,110 | |||||||||
Liabilities: | ||||||||||
Accounts payable | 2,747 | |||||||||
Asset retirement obligation | 16,728 | |||||||||
Total liabilities assumed | 19,475 | |||||||||
Net assets acquired | $709,635 | |||||||||
DTE Gas Resources, LLC | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Assets Acquired and Liabilities Assumed in Acquisition | The following table presents the values assigned to the assets acquired and liabilities assumed in the DTE Acquisition, based on their estimated fair values at the date of the acquisition (in thousands): | |||||||||
Assets: | ||||||||||
Accounts receivable | $10,721 | |||||||||
Prepaid expenses and other | 2,100 | |||||||||
Total current assets | 12,821 | |||||||||
Property, plant and equipment | 263,194 | |||||||||
Other assets, net | 273 | |||||||||
Total assets acquired | $276,288 | |||||||||
Liabilities: | ||||||||||
Accounts payable | $7,760 | |||||||||
Accrued liabilities | 2,910 | |||||||||
Total current liabilities | 10,670 | |||||||||
Asset retirement obligation and other | 8,169 | |||||||||
Total liabilities assumed | 18,839 | |||||||||
Net assets acquired | $257,449 | |||||||||
Titan Operating, L.L.C | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Assets Acquired and Liabilities Assumed in Acquisition | The following table presents the values assigned to the assets acquired and liabilities assumed in the acquisition of Titan, based on their estimated fair values at the date of the acquisition (in thousands): | |||||||||
Assets: | ||||||||||
Cash and cash equivalents | $372 | |||||||||
Accounts receivable | 5,253 | |||||||||
Prepaid expenses and other | 131 | |||||||||
Total current assets | 5,756 | |||||||||
Property, plant and equipment | 208,491 | |||||||||
Other assets, net | 2,344 | |||||||||
Total assets acquired | $216,591 | |||||||||
Liabilities: | ||||||||||
Accounts payable | $676 | |||||||||
Revenue distribution payable | 3,091 | |||||||||
Accrued liabilities | 1,816 | |||||||||
Total current liabilities | 5,583 | |||||||||
Asset retirement obligation and other | 2,418 | |||||||||
Total liabilities assumed | 8,001 | |||||||||
Net assets acquired | $208,590 | |||||||||
Carrizo Oil and Gas, Inc. | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Assets Acquired and Liabilities Assumed in Acquisition | The following table presents the values assigned to the assets acquired and liabilities assumed in the Carrizo Acquisition, based on their estimated fair values at the date of the acquisition (in thousands): | |||||||||
Assets: | ||||||||||
Property, plant and equipment | $190,946 | |||||||||
Liabilities: | ||||||||||
Asset retirement obligation | 3,903 | |||||||||
Net assets acquired | $187,043 | |||||||||
TEAK Acquisition | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Assets Acquired and Liabilities Assumed in Acquisition | The following table presents the final values assigned to the assets acquired and liabilities assumed in the TEAK Acquisition, based on their fair values as the date of the acquisition (in thousands): | |||||||||
Assets: | ||||||||||
Cash | $ | 8,074 | ||||||||
Accounts receivable | 11,055 | |||||||||
Prepaid expenses and other | 1,626 | |||||||||
Total current assets | 20,755 | |||||||||
Property, plant and equipment | 197,683 | |||||||||
Intangible assets | 430,000 | |||||||||
Goodwill | 186,050 | |||||||||
Equity method investment in joint ventures | 184,327 | |||||||||
Total assets acquired | $ | 1,018,815 | ||||||||
Liabilities: | ||||||||||
Accounts payable and accrued liabilities | 34,995 | |||||||||
Other long term liabilities | 1,075 | |||||||||
Total liabilities assumed | 36,070 | |||||||||
Net assets acquired | 982,745 | |||||||||
Less cash received | (8,074 | ) | ||||||||
Net cash paid for acquisition | $ | 974,671 | ||||||||
Cardinal Acquisition | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Assets Acquired and Liabilities Assumed in Acquisition | The following table presents the values assigned to the assets acquired and liabilities assumed in the Cardinal Acquisition, based on their estimated fair values at the date of the acquisition, including the 40% non-controlling interest of Centrahoma held by MarkWest (in thousands): | |||||||||
Assets: | ||||||||||
Cash | $ | 1,184 | ||||||||
Accounts receivable | 13,783 | |||||||||
Prepaid expenses and other | 1,289 | |||||||||
Property, plant and equipment | 246,787 | |||||||||
Intangible assets | 232,740 | |||||||||
Goodwill | 214,090 | |||||||||
Total assets acquired | 709,873 | |||||||||
Liabilities: | ||||||||||
Current portion of long-term debt | 341 | |||||||||
Accounts payable and accrued liabilities | 14,596 | |||||||||
Deferred tax liability, net | 35,353 | |||||||||
Long-term debt, less current portion | 604 | |||||||||
Total liabilities acquired | 50,894 | |||||||||
Non-controlling interest | 58,905 | |||||||||
Net assets acquired | 600,074 | |||||||||
Less cash received | (1,184 | ) | ||||||||
Net cash paid for acquisition | $ | 598,890 | ||||||||
APL_Equity_Method_Investments_
APL Equity Method Investments (Tables) | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
Equity Method Investments And Joint Ventures [Abstract] | ||||||||||
Schedule of Equity Method Investments | The following tables present the values of APL’s equity method investments as of December 31, 2014 and 2013 and equity income (loss) in joint ventures for the years ended December 31, 2014 and 2013 (in thousands): | |||||||||
December 31, | December 31, | |||||||||
2014 | 2013 | |||||||||
WTLPG | $ | - | $ | 85,790 | ||||||
T2 LaSalle | 55,911 | 50,534 | ||||||||
T2 Eagle Ford | 109,517 | 97,437 | ||||||||
T2 EF Co-Gen | 11,784 | 14,540 | ||||||||
Equity method investment in joint ventures | $ | 177,212 | $ | 248,301 | ||||||
Years Ended December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
WTLPG | 2,611 | 4,988 | 6,323 | |||||||
T2 LaSalle | (4,271 | ) | (3,127 | ) | - | |||||
T2 Eagle Ford | (8,754 | ) | (4,408 | ) | - | |||||
T2 EF Co-Gen | (3,593 | ) | (2,189 | ) | - | |||||
Equity income (loss) in joint ventures | $ | (14,007 | ) | $ | (4,736 | ) | $ | 6,323 | ||
Property_Plant_and_Equipment_T
Property, Plant and Equipment (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Property Plant And Equipment [Abstract] | |||||||||||||
Summary of Property, Plant and Equipment | The following is a summary of property, plant and equipment at the dates indicated (in thousands): | ||||||||||||
Estimated | |||||||||||||
December 31, | Useful Lives | ||||||||||||
2014 | 2013 | in Years | |||||||||||
Natural gas and oil properties: | |||||||||||||
Proved properties: | |||||||||||||
Leasehold interests | $ | 535,893 | $ | 322,217 | |||||||||
Pre-development costs | 7,378 | 4,367 | |||||||||||
Wells and related equipment | 3,096,562 | 2,231,213 | |||||||||||
Total proved properties | 3,639,833 | 2,557,797 | |||||||||||
Unproved properties | 217,321 | 211,851 | |||||||||||
Support equipment | 37,359 | 23,258 | |||||||||||
Total natural gas and oil properties | 3,894,513 | 2,792,906 | |||||||||||
Pipelines, processing and compression facilities | 3,576,551 | 2,926,134 | 2–40 | ||||||||||
Rights of way | 209,140 | 203,966 | 20–40 | ||||||||||
Land, buildings and improvements | 19,607 | 30,216 | 3–40 | ||||||||||
Other | 47,846 | 36,752 | 3–10 | ||||||||||
7,747,657 | 5,989,974 | ||||||||||||
Less – accumulated depreciation, depletion and | (2,078,395 | ) | (1,079,099 | ) | |||||||||
amortization | |||||||||||||
$ | 5,669,262 | $ | 4,910,875 | ||||||||||
Other_Assets_Tables
Other Assets (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Other Assets Noncurrent Disclosure [Abstract] | |||||||||
Summary of Other Assets | The following is a summary of other assets at the dates indicated (in thousands): | ||||||||
December 31, | |||||||||
2014 | 2013 | ||||||||
Deferred financing costs, net of accumulated amortization of $62,008 and $43,702 at December 31, 2014 and 2013, respectively | $ | 86,692 | $ | 86,617 | |||||
Investment in Lightfoot | 21,123 | 21,454 | |||||||
Rabbi trust | 3,925 | 3,705 | |||||||
Security deposits | 2,467 | 5,631 | |||||||
ARP notes receivable | 3,866 | 3,978 | |||||||
Other | 9,848 | 3,287 | |||||||
$ | 127,921 | $ | 124,672 | ||||||
Asset_Retirement_Obligations_T
Asset Retirement Obligations (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Asset Retirement Obligation Disclosure [Abstract] | |||||||||||||
Reconciliation of Liability for Well Plugging and Abandonment Costs | A reconciliation of the Partnership and ARP’s liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands): | ||||||||||||
Years Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Asset retirement obligations, beginning of | $ | 91,214 | $ | 64,794 | $ | 45,779 | |||||||
year | |||||||||||||
Liabilities incurred | 10,674 | 23,129 | 16,568 | ||||||||||
Liabilities settled | (1,664 | ) | (1,188 | ) | (546 | ) | |||||||
Accretion expense | 5,759 | 4,479 | 2,993 | ||||||||||
Revisions | 2,118 | - | - | ||||||||||
Asset retirement obligations, end of year | $ | 108,101 | $ | 91,214 | $ | 64,794 | |||||||
Debt_Tables
Debt (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Debt Disclosure [Abstract] | |||||||||
Schedule of Long-term Debt Instruments | Total debt consists of the following at the dates indicated (in thousands): | ||||||||
December 31, | |||||||||
2014 | 2013 | ||||||||
Term loan facility | $ | 237,000 | $ | 239,400 | |||||
Revolving credit facility | — | — | |||||||
ARP revolving credit facility | 696,000 | 419,000 | |||||||
ARP 7.75% Senior Notes – due 2021 | 374,544 | 275,000 | |||||||
ARP 9.25% Senior Notes – due 2021 | 323,916 | 248,334 | |||||||
APL revolving credit facility | 385,000 | 152,000 | |||||||
APL 6.625% Senior Notes – due 2020 | 503,881 | 504,556 | |||||||
APL 5.875% Senior Notes – due 2023 | 650,000 | 650,000 | |||||||
APL 4.750% Senior Notes – due 2021 | 400,000 | 400,000 | |||||||
APL capital leases | 229 | 754 | |||||||
Total debt | 3,570,570 | 2,889,044 | |||||||
Less current maturities | (2,624 | ) | (2,924 | ) | |||||
Total long-term debt | $ | 3,567,946 | $ | 2,886,120 | |||||
Schedule of Maturities of Long-term Debt | The aggregate amount of the Partnership’s, ARP’s and APL’s debt maturities is as follows (in thousands): | ||||||||
Years Ended December 31: | |||||||||
2015 | $ | 2,624 | |||||||
2016 | 2,405 | ||||||||
2017 | 232,200 | ||||||||
2018 | 696,000 | ||||||||
2019 | 385,000 | ||||||||
Thereafter | 2,250,000 | ||||||||
Total principle maturities | 3,568,229 | ||||||||
Unamortized premiums | 4,245 | ||||||||
Unamortized discounts | (1,904 | ) | |||||||
Total debt | $ | 3,570,570 | |||||||
Derivative_Instruments_Tables
Derivative Instruments (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Derivatives Fair Value [Line Items] | |||||||||||||||||
Summary of Gain or Losses Derivative Instruments Recognized in Statements of Operations | The following table summarizes the Partnership’s and ARP’s gains or losses recognized in the Partnership’s consolidated statements of operations for effective derivative instruments, excluding the effect of non-controlling interest, for the periods indicated (in thousands): | ||||||||||||||||
Years Ended December 31, | |||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
(Gain) loss reclassified from accumulated other comprehensive income: | |||||||||||||||||
Gas and oil production revenue | $ | 7,739 | $ | (10,216 | ) | $ | (19,281 | ) | |||||||||
Gathering and processing revenue | — | — | 4,390 | ||||||||||||||
Total | $ | 7,739 | $ | (10,216 | ) | $ | (14,891 | ) | |||||||||
Fair Value of Derivative Instruments Table | The fair value of the derivatives included in the Partnership’s consolidated balance sheets for the periods indicated was as follows (in thousands): | ||||||||||||||||
31-Dec | December 31, | ||||||||||||||||
2014 | 2013 | ||||||||||||||||
Current portion of derivative asset | $ | 232,266 | $ | 2,066 | |||||||||||||
Long-term derivative asset | 168,000 | 30,868 | |||||||||||||||
Current portion of derivative liability | — | (17,630 | ) | ||||||||||||||
Long-term derivative liability | — | (387 | ) | ||||||||||||||
Total Partnership net asset | $ | 400,266 | $ | 14,917 | |||||||||||||
ATLS Partnership | |||||||||||||||||
Derivatives Fair Value [Line Items] | |||||||||||||||||
Fair Value of Derivative Instruments Table | The following table summarizes the gross fair values of the Partnership’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Partnership’s consolidated balance sheets as of the dates indicated (in thousands): | ||||||||||||||||
Gross | Gross | Net Amount of | |||||||||||||||
Amounts of | Amounts | Assets | |||||||||||||||
Recognized | Offset in the | Presented in the | |||||||||||||||
Assets | Consolidated | Consolidated | |||||||||||||||
Balance Sheets | Balance Sheets | ||||||||||||||||
Offsetting Derivative Assets | |||||||||||||||||
As of December 31, 2014 | |||||||||||||||||
Current portion of derivative assets | $ | 2,893 | $ | — | $ | 2,893 | |||||||||||
Long-term portion of derivative assets | 2,669 | — | 2,669 | ||||||||||||||
Total derivative assets | $ | 5,562 | $ | — | $ | 5,562 | |||||||||||
As of December 31, 2013 | |||||||||||||||||
Current portion of derivative assets | $ | 24 | $ | (23 | ) | $ | 1 | ||||||||||
Long-term portion of derivative assets | 1,547 | (33 | ) | 1,514 | |||||||||||||
Current portion of derivative liabilities | 63 | (63 | ) | — | |||||||||||||
Total derivative assets | $ | 1,634 | $ | (119 | ) | $ | 1,515 | ||||||||||
Gross | Gross | Net Amount of | |||||||||||||||
Amounts of | Amounts | Liabilities | |||||||||||||||
Recognized | Offset in the | Presented in the | |||||||||||||||
Liabilities | Consolidated | Consolidated | |||||||||||||||
Balance Sheets | Balance Sheets | ||||||||||||||||
Offsetting Derivative Liabilities | |||||||||||||||||
As of December 31, 2014 | |||||||||||||||||
Long-term portion of derivative assets | $ | — | $ | — | $ | — | |||||||||||
Long-term portion of derivative assets | — | — | — | ||||||||||||||
Total derivative liabilities | $ | — | $ | — | $ | — | |||||||||||
As of December 31, 2013 | |||||||||||||||||
Current portion of derivative assets | $ | (23 | ) | $ | 23 | $ | — | ||||||||||
Long-term portion of derivative assets | (33 | ) | 33 | — | |||||||||||||
Current portion of derivative liabilities | (96 | ) | 63 | (33 | ) | ||||||||||||
Total derivative liabilities | $ | (152 | ) | $ | 119 | $ | (33 | ) | |||||||||
Commodity Derivative Instruments by Type Table | At December 31, 2014, the Partnership had the following commodity derivatives: | ||||||||||||||||
Natural Gas – Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | |||||||||||||||
2015 | 2,280,000 | $ | 4.302 | $ | 2,893 | ||||||||||||
2016 | 1,440,000 | $ | 4.433 | 1,374 | |||||||||||||
2017 | 1,200,000 | $ | 4.59 | 960 | |||||||||||||
2018 | 420,000 | $ | 4.797 | 335 | |||||||||||||
The Partnership’s net asset | $ | 5,562 | |||||||||||||||
(1) | “MMBtu” represents million British Thermal Units. | ||||||||||||||||
(2) | Fair value based on forward NYMEX natural gas prices, as applicable. | ||||||||||||||||
Atlas Resource Partners, L.P. | |||||||||||||||||
Derivatives Fair Value [Line Items] | |||||||||||||||||
Fair Value of Derivative Instruments Table | The following table summarizes the gross fair values of ARP’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Partnership’s consolidated balance sheets as of the dates indicated (in thousands): | ||||||||||||||||
Offsetting Derivative Assets | Gross | Gross | Net Amount of | ||||||||||||||
Amounts of | Amounts | Assets | |||||||||||||||
Recognized | Offset in the | Presented in the | |||||||||||||||
Assets | Consolidated | Consolidated | |||||||||||||||
Balance Sheets | Balance Sheets | ||||||||||||||||
As of December 31, 2014 | |||||||||||||||||
Current portion of derivative assets | $ | 141,464 | $ | (98 | ) | $ | 141,366 | ||||||||||
Long-term portion of derivative assets | 128,303 | (370 | ) | 127,933 | |||||||||||||
Total derivative assets | $ | 269,767 | $ | (468 | ) | $ | 269,299 | ||||||||||
As of December 31, 2013 | |||||||||||||||||
Current portion of derivative assets | $ | 2,664 | $ | (773 | ) | $ | 1,891 | ||||||||||
Long-term portion of derivative assets | 31,146 | (4,062 | ) | 27,084 | |||||||||||||
Current portion of derivative liabilities | 4,341 | (4,341 | ) | — | |||||||||||||
Long-term portion of derivative liabilities | 122 | (122 | ) | — | |||||||||||||
Total derivative assets | $ | 38,273 | $ | (9,298 | ) | $ | 28,975 | ||||||||||
Offsetting Derivative Liabilities | Gross | Gross | Net Amount of | ||||||||||||||
Amounts of | Amounts | Liabilities | |||||||||||||||
Recognized | Offset in the | Presented in the | |||||||||||||||
Liabilities | Consolidated | Consolidated | |||||||||||||||
Balance Sheets | Balance Sheets | ||||||||||||||||
As of December 31, 2014 | |||||||||||||||||
Current portion of derivative liabilities | $ | (98 | ) | $ | 98 | $ | — | ||||||||||
Long-term portion of derivative liabilities | (370 | ) | 370 | — | |||||||||||||
Total derivative liabilities | $ | (468 | ) | $ | 468 | $ | — | ||||||||||
As of December 31, 2013 | |||||||||||||||||
Current portion of derivative assets | $ | (773 | ) | $ | 773 | $ | — | ||||||||||
Long-term portion of derivative assets | (4,062 | ) | 4,062 | — | |||||||||||||
Current portion of derivative liabilities | (10,694 | ) | 4,341 | (6,353 | ) | ||||||||||||
Long-term portion of derivative liabilities | (189 | ) | 122 | (67 | ) | ||||||||||||
Total derivative liabilities | $ | (15,718 | ) | $ | 9,298 | $ | (6,420 | ) | |||||||||
Commodity Derivative Instruments by Type Table | At December 31, 2014, ARP had the following commodity derivatives: | ||||||||||||||||
Natural Gas – Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | |||||||||||||||
2015 | 54,834,500 | $ | 4.226 | $ | 65,393 | ||||||||||||
2016 | 53,546,300 | $ | 4.229 | 40,428 | |||||||||||||
2017 | 46,320,000 | $ | 4.276 | 22,999 | |||||||||||||
2018 | 35,760,000 | $ | 4.25 | 9,881 | |||||||||||||
2019 | 9,720,000 | $ | 4.234 | 1,023 | |||||||||||||
$ | 139,724 | ||||||||||||||||
Natural Gas – Costless Collars | |||||||||||||||||
Production | Option Type | Volumes | Average Floor | Fair Value | |||||||||||||
Period Ending | and Cap | Asset/ | |||||||||||||||
December 31, | (Liability) | ||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | |||||||||||||||
2015 | Puts purchased | 3,480,000 | $ | 4.234 | $ | 4,478 | |||||||||||
2015 | Calls sold | 3,480,000 | $ | 5.129 | (59 | ) | |||||||||||
$ | 4,419 | ||||||||||||||||
Natural Gas – Put Options – Drilling Partnerships | |||||||||||||||||
Production | Option Type | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | |||||||||||||||
2015 | Puts purchased | 1,440,000 | $ | 4 | $ | 1,506 | |||||||||||
2016 | Puts purchased | 1,440,000 | $ | 4.15 | 1,261 | ||||||||||||
$ | 2,767 | ||||||||||||||||
Natural Gas – WAHA Basis Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(7) | |||||||||||||||
2015 | 5,250,000 | $ | (0.082 | ) | $ | 153 | |||||||||||
$ | 153 | ||||||||||||||||
Natural Gas Liquids – Natural Gasoline Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(8) | |||||||||||||||
2015 | 5,040,000 | $ | 1.983 | $ | 4,630 | ||||||||||||
$ | 4,630 | ||||||||||||||||
Natural Gas Liquids – Propane Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(4) | |||||||||||||||
2015 | 8,064,000 | $ | 1.016 | $ | 4,011 | ||||||||||||
$ | 4,011 | ||||||||||||||||
Natural Gas Liquids – Butane Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(5) | |||||||||||||||
2015 | 1,512,000 | $ | 1.248 | $ | 829 | ||||||||||||
$ | 829 | ||||||||||||||||
Natural Gas Liquids – Iso Butane Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(6) | |||||||||||||||
2015 | 1,512,000 | $ | 1.263 | $ | 826 | ||||||||||||
$ | 826 | ||||||||||||||||
Natural Gas Liquids – Crude Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | |||||||||||||||
2016 | 84,000 | $ | 85.651 | $ | 1,851 | ||||||||||||
2017 | 60,000 | $ | 83.78 | 984 | |||||||||||||
$ | 2,835 | ||||||||||||||||
Crude Oil – Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | |||||||||||||||
2015 | 1,743,000 | $ | 90.645 | $ | 58,765 | ||||||||||||
2016 | 1,209,000 | $ | 87.36 | 28,663 | |||||||||||||
2017 | 672,000 | $ | 85.669 | 12,248 | |||||||||||||
2018 | 540,000 | $ | 85.466 | 8,595 | |||||||||||||
$ | 108,271 | ||||||||||||||||
Crude Oil – Costless Collars | |||||||||||||||||
Production | Option Type | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Floor | Asset/ | |||||||||||||||
December 31, | and Cap | (Liability) | |||||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | |||||||||||||||
2015 | Puts purchased | 29,250 | $ | 83.846 | $ | 842 | |||||||||||
2015 | Calls sold | 29,250 | $ | 110.654 | (8 | ) | |||||||||||
$ | 834 | ||||||||||||||||
Total net assets | $ | 269,299 | |||||||||||||||
-1 | “MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons. | ||||||||||||||||
(2) | Fair value based on forward NYMEX natural gas prices, as applicable. | ||||||||||||||||
-3 | Fair value based on forward WTI crude oil prices, as applicable. | ||||||||||||||||
-4 | Fair value based on forward Mt. Belvieu propane prices, as applicable. | ||||||||||||||||
-5 | Fair value based on forward Mt. Belvieu butane prices, as applicable. | ||||||||||||||||
(6) | Fair value based on forward Mt. Belvieu iso butane prices, as applicable. | ||||||||||||||||
(7) | Fair value based on forward WAHA natural gas prices, as applicable | ||||||||||||||||
(8) | Fair value based on forward Mt. Belvieu natural gasoline prices, as applicable. | ||||||||||||||||
Atlas Pipeline "APL" | |||||||||||||||||
Derivatives Fair Value [Line Items] | |||||||||||||||||
Fair Value of Derivative Instruments Table | The following table summarizes APL’s gross fair values of its derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Partnership’s consolidated balance sheets as of the dates indicated (in thousands): | ||||||||||||||||
Offsetting Derivative Assets | Gross Amounts of Recognized Assets | Gross Amounts Offset in the Consolidated Balance Sheets | Net Amounts of Assets Presented in the Consolidated Balance Sheets | ||||||||||||||
As of December 31, 2014: | |||||||||||||||||
Current portion of derivative assets | $ | 88,007 | $ | - | $ | 88,007 | |||||||||||
Long-term portion of derivative assets | 37,398 | - | 37,398 | ||||||||||||||
Total derivative assets, net | $ | 125,405 | $ | - | $ | 125,405 | |||||||||||
As of December 31, 2013: | |||||||||||||||||
Current portion of derivative assets | $ | 1,310 | $ | (1,136 | ) | $ | 174 | ||||||||||
Long-term portion of derivative assets | 5,082 | (2,812 | ) | 2,270 | |||||||||||||
Current portion of derivative liabilities | 1,612 | (1,612 | ) | - | |||||||||||||
Long-term portion of derivative liabilities | 949 | (949 | ) | - | |||||||||||||
Total derivative assets, net | $ | 8,953 | $ | (6,509 | ) | $ | 2,444 | ||||||||||
Offsetting Derivative Liabilities | Gross Amounts of Recognized Liabilities | Gross Amounts Offset in the Consolidated Balance Sheets | Net Amounts of Liabilities Presented in the Consolidated Balance Sheets | ||||||||||||||
As of December 31, 2014: | |||||||||||||||||
Current portion of derivative assets | $ | - | $ | - | $ | - | |||||||||||
Long-term portion of derivative assets | - | - | - | ||||||||||||||
Total derivative liabilities, net | $ | - | $ | - | $ | - | |||||||||||
As of December 31, 2013: | |||||||||||||||||
Current portion of derivative assets | $ | (1,136 | ) | $ | 1,136 | $ | - | ||||||||||
Long-term portion of derivative assets | (2,812 | ) | 2,812 | - | |||||||||||||
Current portion of derivative liabilities | (12,856 | ) | 1,612 | (11,244 | ) | ||||||||||||
Long-term portion of derivative liabilities | (1,269 | ) | 949 | (320 | ) | ||||||||||||
Total derivative liabilities, net | $ | (18,073 | ) | $ | 6,509 | $ | (11,564 | ) | |||||||||
Commodity Derivative Instruments by Type Table | As of December 31, 2014, APL had the following commodity derivatives: | ||||||||||||||||
Production | Average Fixed Price | ||||||||||||||||
Period | Commodity | Volumes(1) | ($/Volume) | Fair Value(2) Asset | |||||||||||||
Sold fixed price swaps | (in thousands) | ||||||||||||||||
2015 | Natural gas | 27,010,000 | 4.18 | $ | 30,945 | ||||||||||||
2016 | Natural gas | 13,800,000 | 4.15 | 9,381 | |||||||||||||
2017 | Natural gas | 6,600,000 | 4.11 | 2,137 | |||||||||||||
2015 | NGLs | 71,442,000 | 1.22 | 43,094 | |||||||||||||
2016 | NGLs | 34,650,000 | 1.03 | 16,822 | |||||||||||||
2017 | NGLs | 10,080,000 | 1.04 | 4,777 | |||||||||||||
2015 | Crude oil | 210,000 | 90.26 | 7,274 | |||||||||||||
2016 | Crude oil | 30,000 | 90 | 848 | |||||||||||||
Total fixed price swaps | 115,278 | ||||||||||||||||
Purchased put options | |||||||||||||||||
2015 | NGLs | 3,150,000 | 0.94 | 1,353 | |||||||||||||
2015 | Crude oil | 270,000 | 89.18 | 8,774 | |||||||||||||
Sold call options | |||||||||||||||||
2015 | NGLs | 1,260,000 | 1.28 | - | |||||||||||||
Total options | 10,127 | ||||||||||||||||
APL’s net asset | $ | 125,405 | |||||||||||||||
— | NGL volumes are stated in gallons. Crude oil volumes are stated in barrels. Natural gas volumes are stated in MMBTUs. | ||||||||||||||||
— | See Note 2 for discussion on fair value methodology. | ||||||||||||||||
Gain (Loss) Recognized on Derivative Instruments | The following table summarizes APL’s derivatives not designated as hedges, which are included within gain (loss) on mark-to market derivatives on the Partnerships consolidated statements of operations: | ||||||||||||||||
Years Ended December 31, | |||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
Gain (loss) recognized in gain (loss) on mark-to-market derivatives: | |||||||||||||||||
Commodity contract—realized(1) | $ | (9,960 | ) | $ | (324 | ) | $ | 10,993 | |||||||||
Commodity contract – unrealized(2) | 141,024 | (28,440 | ) | 20,947 | |||||||||||||
Gain (loss) on mark-to-market derivatives | $ | 131,064 | $ | (28,764 | ) | $ | 31,940 | ||||||||||
(1) | Realized gain (loss) represents the gain (loss) incurred when the derivative contract expires and/or is cash settled. | ||||||||||||||||
(2) | Unrealized gain (loss) represents the mark-to-market gain (loss) recognized on open derivative contracts, which have not yet settled. |
Fair_Value_of_Financial_Instru1
Fair Value of Financial Instruments (Tables) | 12 Months Ended | |||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||
Fair Value Disclosures [Abstract] | ||||||||||||||||||||||||||||
Partnership, ARP and ATLS Assets and Liabilities Measured at Fair Value | Information for the Partnership’s, ARP’s and APL’s assets and liabilities measured at fair value at December 31, 2014 and 2013 was as follows (in thousands): | |||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||
As of December 31, 2014 | ||||||||||||||||||||||||||||
Assets, gross | ||||||||||||||||||||||||||||
Rabbi trust | $ | 3,925 | $ | — | $ | — | $ | 3,925 | ||||||||||||||||||||
Commodity swaps | — | 5,562 | — | 5,562 | ||||||||||||||||||||||||
ARP Commodity swaps | — | 261,680 | — | 261,680 | ||||||||||||||||||||||||
ARP Commodity puts | — | 2,767 | — | 2,767 | ||||||||||||||||||||||||
ARP Commodity options | — | 5,320 | — | 5,320 | ||||||||||||||||||||||||
APL Commodity swaps | — | 50,585 | 64,693 | 115,278 | ||||||||||||||||||||||||
APL Commodity options | — | 8,774 | 1,353 | 10,127 | ||||||||||||||||||||||||
Total assets, gross | 3,925 | 334,688 | 66,046 | 404,659 | ||||||||||||||||||||||||
Liabilities, gross | ||||||||||||||||||||||||||||
Commodity swaps | — | — | — | — | ||||||||||||||||||||||||
ARP Commodity swaps | — | (401 | ) | — | (401 | ) | ||||||||||||||||||||||
ARP Commodity options | — | (67 | ) | — | (67 | ) | ||||||||||||||||||||||
APL Commodity swaps | — | — | — | — | ||||||||||||||||||||||||
APL Commodity options | — | — | — | — | ||||||||||||||||||||||||
Total liabilities, gross | — | (468 | ) | — | (468 | ) | ||||||||||||||||||||||
Total assets, fair value, net | $ | 3,925 | $ | 334,220 | $ | 66,046 | $ | 404,191 | ||||||||||||||||||||
As of December 31, 2013 | ||||||||||||||||||||||||||||
Assets, gross | ||||||||||||||||||||||||||||
Rabbi trust | $ | 3,705 | $ | — | $ | — | $ | 3,705 | ||||||||||||||||||||
Commodity swaps | — | 1,634 | $ | — | 1,634 | |||||||||||||||||||||||
ARP Commodity swaps | — | 33,594 | — | 33,594 | ||||||||||||||||||||||||
ARP Commodity puts | — | 1,374 | — | 1,374 | ||||||||||||||||||||||||
ARP Commodity options | — | 3,305 | — | 3,305 | ||||||||||||||||||||||||
APL Commodity swaps | — | 2,994 | 1,412 | 4,406 | ||||||||||||||||||||||||
APL Commodity options | — | 4,337 | 210 | 4,547 | ||||||||||||||||||||||||
Total assets, gross | 3,705 | 47,238 | 1,622 | 52,565 | ||||||||||||||||||||||||
Liabilities, gross | ||||||||||||||||||||||||||||
Commodity swaps | — | (152 | ) | — | (152 | ) | ||||||||||||||||||||||
ARP Commodity swaps | — | (14,624 | ) | — | (14,624 | ) | ||||||||||||||||||||||
ARP Commodity options | — | (1,094 | ) | — | (1,094 | ) | ||||||||||||||||||||||
APL Commodity swaps | — | (4,695 | ) | (13,378 | ) | (18,073 | ) | |||||||||||||||||||||
Total derivative liabilities, gross | — | (20,565 | ) | (13,378 | ) | (33,943 | ) | |||||||||||||||||||||
Total derivatives, fair value, net | $ | 3,705 | $ | 26,673 | $ | (11,756 | ) | $ | 18,622 | |||||||||||||||||||
Summary of Changes in Fair Value of APL's Level 3 Derivative Instruments | APL’s Level 3 fair value amounts relate to its derivative contracts on NGL fixed price swaps and NGL options. The following table provides a summary of changes in fair value of APL’s Level 3 derivative instruments for the periods indicated (in thousands): | |||||||||||||||||||||||||||
NGL Fixed Price Swaps | NGL Put Options | NGL Call Options | Total | |||||||||||||||||||||||||
Gallons | Amount | Gallons | Amount | Gallons | Amount | Amount | ||||||||||||||||||||||
Balance – January 1, 2013 | 87,066 | $ | 16,814 | 38,556 | $ | 6,269 | — | — | $ | 23,083 | ||||||||||||||||||
New contracts(1) | 104,328 | — | 7,560 | 816 | — | — | 816 | |||||||||||||||||||||
Cash settlements from unrealized (gain) loss(2)(3) | (61,236 | ) | (11,496 | ) | (39,816 | ) | 8,545 | — | — | (2,951 | ) | |||||||||||||||||
Net change in unrealized loss(2) | — | (17,284 | ) | — | (2,367 | ) | — | — | (19,651 | ) | ||||||||||||||||||
Deferred option premium recognition(3) | — | — | — | (13,053 | ) | — | — | (13,053 | ) | |||||||||||||||||||
Balance – December 31, 2013 | 130,158 | $ | (11,966 | ) | 6,300 | $ | 210 | — | — | $ | (11,756 | ) | ||||||||||||||||
New contracts(1) | 70,560 | — | 5,040 | 200 | 5,040 | (200 | ) | — | ||||||||||||||||||||
Cash settlements from unrealized (gain) loss(2)(3) | (84,546 | ) | 3,406 | (8,190 | ) | 100 | (3,780 | ) | (121 | ) | 3,385 | |||||||||||||||||
Net change in unrealized gain (loss)(2) | — | 73,253 | — | 1,448 | — | 200 | 74,901 | |||||||||||||||||||||
Deferred option premium recognition(3) | — | — | — | (605 | ) | — | 121 | (484 | ) | |||||||||||||||||||
Balance – December 31, 2014 | 116,172 | $ | 64,693 | 3,150 | $ | 1,353 | 1,260 | — | $ | 66,046 | ||||||||||||||||||
(1) | Swaps are entered into with no value on the date of trade. Options include premiums paid, which are included in the value of the derivatives on the date of trade. | |||||||||||||||||||||||||||
(2) | Included within gain (loss) on mark-to-market derivatives on the Partnership’s consolidated statements of operations. | |||||||||||||||||||||||||||
(3) | Includes option premium cost reclassified from unrealized gain (loss) to realized gain (loss) at time of option expiration. | |||||||||||||||||||||||||||
Fair Value APL's NGL Fixed Price Swaps Measured on Nonrecurring Basis Unobservable Inputs | The following table provides a summary of the unobservable inputs used in the fair value measurement of APL’s NGL fixed price swaps at December 31, 2014 and December 31, 2013 (in thousands): | |||||||||||||||||||||||||||
Gallons | Third Party Quotes(1) | Adjustments(2) | Total Amount | |||||||||||||||||||||||||
As of December 31, 2014 | ||||||||||||||||||||||||||||
Propane swaps | 101,556 | $ | 50,201 | $ | — | $ | 50,201 | |||||||||||||||||||||
Natural gasoline swaps | 14,616 | 14,859 | (367 | ) | 14,492 | |||||||||||||||||||||||
Total NGL swaps – December 31, 2014 | 116,172 | $ | 65,060 | $ | (367 | ) | $ | 64,693 | ||||||||||||||||||||
As of December 31, 2013 | ||||||||||||||||||||||||||||
Propane swaps | 100,296 | $ | (10,260 | ) | $ | — | $ | (10,260 | ) | |||||||||||||||||||
Isobutane swaps | 6,300 | (2,342 | ) | 955 | (1,387 | ) | ||||||||||||||||||||||
Normal butane swaps | 7,560 | 40 | 322 | 362 | ||||||||||||||||||||||||
Natural gasoline swaps | 16,002 | 132 | (813 | ) | (681 | ) | ||||||||||||||||||||||
Total NGL swaps – December 31, 2013 | 130,158 | $ | (12,430 | ) | $ | 464 | $ | (11,966 | ) | |||||||||||||||||||
(1) | Based upon the difference between the quoted market price provided by the third party and the fixed price of the swap. | |||||||||||||||||||||||||||
(2) | Product and location basis differentials calculated through the use of a regression model, which compares the difference between the settlement prices for the products and locations quoted by the third party and the settlement prices for the actual products and locations underlying the derivatives, using a three-year historical period. | |||||||||||||||||||||||||||
Summary of the Regression Coefficient Utilized in the Calculation of the Unobservable Inputs for the Level 3 Fair Value Measurements for APL's NGL Swaps | The following table provides a summary of the regression coefficient utilized in the calculation of the unobservable inputs for the Level 3 fair value measurements for APL’s NGL fixed price swaps for the periods indicated (in thousands): | |||||||||||||||||||||||||||
Level 3 NGL Swap Fair | Adjustment based upon Regression Coefficient | |||||||||||||||||||||||||||
Value Adjustments | Lower 95% | Upper 95% | Average | |||||||||||||||||||||||||
As of December 31, 2014: | ||||||||||||||||||||||||||||
Natural gasoline | $ | (367 | ) | 0.9714 | 0.9748 | 0.9731 | ||||||||||||||||||||||
Total Level 3 adjustments – December 31, 2014 | $ | (367 | ) | |||||||||||||||||||||||||
As of December 31, 2013: | ||||||||||||||||||||||||||||
Isobutane | $ | 955 | 1.1184 | 1.1284 | 1.1234 | |||||||||||||||||||||||
Normal butane | 322 | 1.0341 | 1.0386 | 1.0364 | ||||||||||||||||||||||||
Natural gasoline | (813 | ) | 0.9727 | 0.9751 | 0.9739 | |||||||||||||||||||||||
Total Level 3 adjustments – December 31, 2013 | $ | 464 | ||||||||||||||||||||||||||
Summary of the Changes in Fair Value of APL's NGL Linefill | The following table provides a summary of changes in fair value of APL’s NGL linefill for the years ended December 31, 2014 and 2013 (in thousands): | |||||||||||||||||||||||||||
Linefill Valued at Market | Linefill Valued on FIFO | Total NGL Linefill | ||||||||||||||||||||||||||
Gallons | Amount | Gallons | Amount | Gallons | Amount | |||||||||||||||||||||||
Balance –January 1, 2013 | 9,148 | $ | 7,783 | - | $ | - | 9,148 | $ | 7,783 | |||||||||||||||||||
Deliveries into NGL linefill | - | - | 80,758 | 60,565 | 80,758 | 60,565 | ||||||||||||||||||||||
NGL linefill sales | -3,360 | -2,795 | -71,433 | -52,155 | -74,793 | -54,950 | ||||||||||||||||||||||
Net change in NGL linefill valuation(1) | - | -249 | - | - | - | -249 | ||||||||||||||||||||||
Acquired NGL linefill(2) | - | - | 2,213 | 1,368 | 2,213 | 1,368 | ||||||||||||||||||||||
Balance – December 31, 2013 | 5,788 | $ | 4,739 | 11,538 | $ | 9,778 | 17,326 | $ | 14,517 | |||||||||||||||||||
Deliveries into NGL linefill | 4,385 | 2,919 | 59,273 | 38,451 | 63,658 | 41,370 | ||||||||||||||||||||||
NGL linefill sales | -4,629 | -3,917 | -49,335 | -31,470 | -53,964 | -35,387 | ||||||||||||||||||||||
Adjustments for linefill contract revision | 11,982 | 9,846 | -11,982 | -9,846 | - | - | ||||||||||||||||||||||
Net change in NGL linefill valuation(1) | - | -5,888 | - | - | - | -5,888 | ||||||||||||||||||||||
Balance – December 31, 2014 | 17,526 | $ | 7,699 | 9,494 | $ | 6,913 | 27,020 | $ | 14,612 | |||||||||||||||||||
-1 | Included within gathering and processing revenues on the Partnership’s consolidated statements of operations. | |||||||||||||||||||||||||||
-2 | NGL linefill acquired as part of APL’s TEAK and Cardinal acquisitions (see Note 4). | |||||||||||||||||||||||||||
Schedule of Assets and Liabilities Measured on Non Recurring Basis | Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the years ended December 31, 2014 and 2013 was as follows (in thousands): | |||||||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||
Level 3 | Total | Level 3 | Total | |||||||||||||||||||||||||
Asset retirement obligations | $ | 10,674 | $ | 10,674 | $ | 23,129 | $ | 23,129 | ||||||||||||||||||||
Total | $ | 10,674 | $ | 10,674 | $ | 23,129 | $ | 23,129 | ||||||||||||||||||||
Income_Taxes_Tables
Income Taxes (Tables) | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
Income Tax Disclosure [Abstract] | ||||||||||
Schedule of Components of Income Tax Expense (Benefit) | APL owns a taxable subsidiary. The components of the federal and state income tax expense (benefit) for APL’s taxable subsidiary for the years ended December 31, 2014, 2013 and 2012 are as follows (in thousands): | |||||||||
Years Ended December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
Income tax expense (benefit) : | ||||||||||
Federal | $ | -2,128 | $ | -2,024 | $ | 158 | ||||
State | -248 | -236 | 18 | |||||||
Total income tax expense (benefit) | $ | -2,376 | $ | -2,260 | $ | 176 | ||||
Schedule of Deferred Tax Assets and Liabilities | As of December 31, 2014 and 2013, APL had non-current net deferred income tax liabilities of $30.9 million and $33.3 million, respectively. The components of net deferred tax liabilities as of December 31, 2014 and 2013 consist of the following (in thousands): | |||||||||
December 31, | December 31, | |||||||||
2014 | 2013 | |||||||||
Deferred tax assets: | ||||||||||
Net operating loss tax carryforwards and alternative minimum tax credits | $ | 17,269 | $ | 14,900 | ||||||
Deferred tax liabilities: | ||||||||||
Excess of asset carrying value over tax basis | -48,183 | -48,190 | ||||||||
Net deferred tax liabilities | $ | -30,914 | $ | -33,290 | ||||||
Commitments_and_Contingencies_
Commitments and Contingencies (Tables) | 12 Months Ended | ||||
Dec. 31, 2014 | |||||
Commitments And Contingencies Disclosure [Abstract] | |||||
Schedule of Future Minimum Rental Payments | Future minimum rental commitments for the next five years are as follows (in thousands): | ||||
Years Ended December 31, | |||||
2015 | $ | 16,524 | |||
2016 | 11,917 | ||||
2017 | 8,216 | ||||
2018 | 7,314 | ||||
2019 | 1,951 | ||||
Thereafter | 3,415 | ||||
$ | 49,337 | ||||
Cash_Distribution_Distribution
Cash Distribution (Distributions Declared) (Tables) | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||
ATLS | |||||||||||||||||||
Schedule of Distributions Made by Partnership | The Partnership has a cash distribution policy under which it distributes, within 50 days after the end of each quarter, all of its available cash (as defined in the partnership agreement) for that quarter to its common unitholders. Distributions declared by the Partnership for the period from January 1, 2012 through December 31, 2014 were as follows (in thousands, except per unit amounts): | ||||||||||||||||||
Date Cash Distribution Paid | For Quarter | Cash Distribution per | Total Cash Distributions | ||||||||||||||||
Ended | Common Limited | Paid to Common | |||||||||||||||||
Partner Unit | Limited Partners | ||||||||||||||||||
March 31, 2012 | $ | 0.25 | $ | 12,830 | |||||||||||||||
May 18, 2012 | |||||||||||||||||||
August 17, 2012 | 30-Jun-12 | $ | 0.25 | $ | 12,831 | ||||||||||||||
November 19, 2012 | September 30, 2012 | $ | 0.27 | $ | 13,866 | ||||||||||||||
February 19, 2013 | 31-Dec-12 | $ | 0.3 | $ | 15,410 | ||||||||||||||
May 20, 2013 | 31-Mar-13 | $ | 0.31 | $ | 15,928 | ||||||||||||||
August 19, 2013 | 30-Jun-13 | $ | 0.44 | $ | 22,611 | ||||||||||||||
19-Nov-13 | September 30, 2013 | $ | 0.46 | $ | 23,649 | ||||||||||||||
19-Feb-14 | December 31, 2013 | $ | 0.46 | $ | 23,681 | ||||||||||||||
20-May-14 | March 31, 2014 | $ | 0.46 | $ | 23,865 | ||||||||||||||
19-Aug-14 | 30-Jun-14 | $ | 0.49 | $ | 25,435 | ||||||||||||||
20-Nov-14 | 30-Sep-14 | $ | 0.52 | $ | 27,015 | ||||||||||||||
Atlas Resource Partners, L.P. | |||||||||||||||||||
Schedule of Distributions Made by Partnership | Distributions declared by ARP for the period from January 1, 2013 through December 31, 2014 were as follows (in thousands, except per unit amounts): | ||||||||||||||||||
Date Cash | For Quarter/Month | Cash | Total Cash | Total Cash | Total Cash | ||||||||||||||
Distribution | Ended | Distribution | Distribution | Distribution | Distribution | ||||||||||||||
Paid | per Common | to Common | To | to the General | |||||||||||||||
Limited | Limited | Preferred | Partner’s | ||||||||||||||||
Partner Unit | Partners | Limited | Class | ||||||||||||||||
Partners | A Units | ||||||||||||||||||
May 15, 2012 | March 31, 2012 | $ | 0.12 | -1 | $ | 3,144 | $ | — | $ | 64 | |||||||||
August 14, 2012 | 30-Jun-12 | $ | 0.4 | $ | 12,891 | $ | — | $ | 263 | ||||||||||
November 14, 2012 | 30-Sep-12 | $ | 0.43 | $ | 15,510 | $ | 1,652 | $ | 350 | ||||||||||
February 14, 2013 | 31-Dec-12 | $ | 0.48 | $ | 21,107 | $ | 1,841 | $ | 618 | ||||||||||
May 15, 2013 | 31-Mar-13 | $ | 0.51 | $ | 22,428 | $ | 1,957 | $ | 946 | ||||||||||
August 14, 2013 | 30-Jun-13 | $ | 0.54 | $ | 32,097 | $ | 2,072 | $ | 1,884 | ||||||||||
November 14, 2013 | September 30, 2013 | $ | 0.56 | $ | 33,291 | $ | 4,248 | $ | 2,443 | ||||||||||
14-Feb-14 | 31-Dec-13 | $ | 0.58 | $ | 34,489 | $ | 4,400 | $ | 2,891 | ||||||||||
17-Mar-14 | 31-Jan-14 | $ | 0.1933 | $ | 12,718 | $ | 1,467 | $ | 1,055 | ||||||||||
14-Apr-14 | 28-Feb-14 | $ | 0.1933 | $ | 12,719 | $ | 1,466 | $ | 1,055 | ||||||||||
15-May-14 | 31-Mar-14 | $ | 0.1933 | $ | 12,719 | $ | 1,466 | $ | 1,054 | ||||||||||
13-Jun-14 | 30-Apr-14 | $ | 0.1933 | $ | 15,752 | $ | 1,466 | $ | 1,279 | ||||||||||
15-Jul-14 | 31-May-14 | $ | 0.1933 | $ | 15,752 | $ | 1,466 | $ | 1,279 | ||||||||||
14-Aug-14 | 30-Jun-14 | $ | 0.1966 | $ | 16,029 | $ | 1,492 | $ | 1,377 | ||||||||||
12-Sep-14 | 31-Jul-14 | $ | 0.1966 | $ | 16,028 | $ | 1,493 | $ | 1,378 | ||||||||||
15-Oct-14 | 31-Aug-14 | $ | 0.1966 | $ | 16,032 | $ | 1,491 | $ | 1,378 | ||||||||||
14-Nov-14 | 30-Sep-14 | $ | 0.1966 | $ | 16,032 | $ | 1,492 | $ | 1,378 | ||||||||||
15-Dec-14 | 31-Oct-14 | $ | 0.1966 | $ | 16,033 | $ | 1,491 | $ | 1,378 | ||||||||||
14-Jan-15 | 30-Nov-14 | $ | 0.1966 | $ | 16,779 | $ | 745 | -2 | $ | 1,378 | |||||||||
Atlas Pipeline "APL" | |||||||||||||||||||
Schedule of Distributions Made by Partnership | Common unit and general partner distributions declared by APL for the period from January 1, 2012 through December 31, 2014 were as follows (in thousands, except per unit amounts): | ||||||||||||||||||
Date Cash Distribution Paid | For Quarter | APL Cash | Total APL Cash | Total APL Cash | |||||||||||||||
Ended | Distribution | Distribution to | Distribution to | ||||||||||||||||
per Common | Common | the General | |||||||||||||||||
Limited | Limited | Partner | |||||||||||||||||
Partner Unit | Partners | ||||||||||||||||||
March 31, 2012 | $ | 0.56 | $ | 30,030 | $ | 2,217 | |||||||||||||
May 15, 2012 | |||||||||||||||||||
August 14, 2012 | 30-Jun-12 | $ | 0.56 | $ | 30,085 | $ | 2,221 | ||||||||||||
November 14, 2012 | September 30, 2012 | $ | 0.57 | $ | 30,641 | $ | 2,409 | ||||||||||||
February 14, 2013 | 31-Dec-12 | $ | 0.58 | $ | 37,442 | $ | 3,117 | ||||||||||||
31-Mar-13 | $ | 0.59 | $ | 45,382 | $ | 3,980 | |||||||||||||
May 15, 2013 | |||||||||||||||||||
August 14, 2013 | 30-Jun-13 | $ | 0.62 | $ | 48,165 | $ | 5,875 | ||||||||||||
November 14, 2013 | 30-Sep-13 | $ | 0.62 | $ | 49,298 | $ | 6,013 | ||||||||||||
14-Feb-14 | 31-Dec-13 | $ | 0.62 | $ | 49,969 | $ | 6,095 | ||||||||||||
31-Mar-14 | $ | 0.62 | $ | 49,998 | $ | 6,099 | |||||||||||||
May 15, 2014 | |||||||||||||||||||
August 14, 2014 | 30-Jun-14 | $ | 0.63 | $ | 51,781 | $ | 7,055 | ||||||||||||
November 14, 2014 | 30-Sep-14 | $ | 0.64 | $ | 54,080 | $ | 8,115 | ||||||||||||
Benefit_Plans_Tables
Benefit Plans (Tables) | 12 Months Ended | |||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||
Partnership 2010 Long Term Incentive Plan | ||||||||||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||||||||||||||||||
Phantom Unit Activity | The following table sets forth the 2010 LTIP phantom unit activity for the periods indicated: | |||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Number | Weighted | Number | Weighted | Number | Weighted | |||||||||||||||||||
of Units | Average | of Units | Average | of Units | Average | |||||||||||||||||||
Grant Date | Grant Date | Grant Date | ||||||||||||||||||||||
Fair Value | Fair Value | Fair Value | ||||||||||||||||||||||
Outstanding, beginning of year | 2,054,534 | $ | 22.58 | 2,044,227 | $ | 20.9 | 1,838,164 | $ | 22.11 | |||||||||||||||
Granted | 961,000 | 44.93 | 112,000 | 50.26 | 133,080 | 29.95 | ||||||||||||||||||
Vested(1) | (486,321 | ) | 20.76 | (25,684 | ) | 19.87 | (19,677 | ) | 20.11 | |||||||||||||||
Forfeited | (32,549 | ) | 32.53 | (76,009 | ) | 20.67 | (72,808 | ) | 20.65 | |||||||||||||||
ARP anti-dilution adjustment(2) | — | — | — | — | 165,468 | — | ||||||||||||||||||
Outstanding, end of year(3) | 2,496,664 | $ | 31.41 | 2,054,534 | $ | 22.58 | 2,044,227 | $ | 20.9 | |||||||||||||||
Non-cash compensation expense recognized | $ | 22,624 | $ | 11,848 | $ | 11,612 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
-1 | The aggregate intrinsic values of phantom unit awards vested were $21.1 million, $1.3 million and $0.7 million, respectively, for the years ended December 31, 2014, 2013 and 2012. | |||||||||||||||||||||||
-2 | The number of 2010 phantom units was adjusted concurrently with the distribution of ARP common units. | |||||||||||||||||||||||
-3 | The aggregate intrinsic value of phantom unit awards outstanding at December 31, 2014 was $77.8 million. | |||||||||||||||||||||||
Unit Option Activity | The following table sets forth the 2010 LTIP unit option activity for the periods indicated: | |||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Number | Weighted | Number | Weighted | Number | Weighted | |||||||||||||||||||
of Unit | Average | of Unit | Average | of Unit | Average | |||||||||||||||||||
Options | Exercise | Options | Exercise | Options | Exercise | |||||||||||||||||||
Price | Price | Price | ||||||||||||||||||||||
Outstanding, beginning of year | 2,452,412 | $ | 20.52 | 2,504,703 | $ | 20.51 | 2,304,300 | $ | 22.12 | |||||||||||||||
Granted | — | — | — | — | 77,167 | 27.55 | ||||||||||||||||||
Exercised(1) | (28,473 | ) | 20.68 | (3,262 | ) | 20.44 | (5,438 | ) | 18.44 | |||||||||||||||
Forfeited | (9,394 | ) | 18.79 | (49,029 | ) | 20.38 | (79,119 | ) | 20.33 | |||||||||||||||
ARP anti-dilution adjustment(2) | — | — | — | — | 207,793 | — | ||||||||||||||||||
Outstanding, end of year(3)(4) | 2,414,545 | $ | 20.53 | 2,452,412 | $ | 20.52 | 2,504,703 | $ | 20.51 | |||||||||||||||
Options exercisable, end of year(5) | 584,162 | $ | 20.34 | 13,865 | $ | 20.03 | 3,398 | $ | 20.85 | |||||||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 4,535 | $ | 5,768 | $ | 5,966 | ||||||||||||||||||
-1 | The intrinsic values of options exercised during the years ended December 31, 2014, 2013 and 2012 were $0.6 million, $0.1 million and $0.1 million, respectively. | |||||||||||||||||||||||
-2 | The number of 2010 unit options and exercise price was adjusted concurrently with the distribution of ARP common units. | |||||||||||||||||||||||
-3 | The weighted average remaining contractual life for outstanding options at December 31, 2014 was 6.3 years. | |||||||||||||||||||||||
-4 | The options outstanding at December 31, 2014 had an aggregate intrinsic value of $25.7 million. | |||||||||||||||||||||||
-5 | The weighted average remaining contractual lives for exercisable options at December 31, 2014 and 2013 were 6.3 years and 7.6 years, respectively. The intrinsic values of exercisable options at December 31, 2014, 2013 and 2012 were $6.1 million, $0.4 million and approximately $47,000, respectively. | |||||||||||||||||||||||
Weighted Average Assumptions | The following weighted average assumptions were used for the periods indicated: | |||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Expected dividend yield | — | % | — | % | 3.7 | % | ||||||||||||||||||
Expected unit price volatility | — | % | — | % | 45 | % | ||||||||||||||||||
Risk-free interest rate | — | % | — | % | 1.4 | % | ||||||||||||||||||
Expected term (in years) | — | — | 6.84 | |||||||||||||||||||||
Fair value of unit options granted | $ | — | $ | — | $ | 8.08 | ||||||||||||||||||
Partnership 2006 Long Term Incentive Plan | ||||||||||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||||||||||||||||||
Phantom Unit Activity | The following table sets forth the 2006 LTIP phantom unit activity for the periods indicated: | |||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Number | Weighted | Number | Weighted | Number | Weighted | |||||||||||||||||||
of Units | Average | of Units | Average | of Units | Average | |||||||||||||||||||
Grant Date | Grant Date | Grant Date | ||||||||||||||||||||||
Fair Value | Fair Value | Fair Value | ||||||||||||||||||||||
Outstanding, beginning of year | 234,940 | $ | 35.82 | 50,759 | $ | 21.02 | 32,641 | $ | 15.99 | |||||||||||||||
Granted | 629,525 | 43.76 | 207,363 | 38.05 | 25,248 | 29.7 | ||||||||||||||||||
Vested (1) (2) | (83,283 | ) | 33.86 | (20,182 | ) | 21.34 | (10,107 | ) | 20.26 | |||||||||||||||
Forfeited | — | — | (3,000 | ) | 36.45 | — | — | |||||||||||||||||
ARP anti-dilution adjustment(3) | — | — | — | — | 2,977 | — | ||||||||||||||||||
Outstanding, end of year(4)(5) | 781,182 | $ | 42.43 | 234,940 | $ | 35.82 | 50,759 | $ | 21.02 | |||||||||||||||
Non-cash compensation expense recognized | $ | 16,797 | $ | 5,317 | $ | 660 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
-1 | The intrinsic values for phantom unit awards vested during the years ended December 31, 2014, 2013 and 2012 were $3.8 million, $1.0 million and $0.3 million, respectively. | |||||||||||||||||||||||
-2 | There were 6,380 and 1,146 vested units during the years ended December 31, 2014 and 2013, respectively, that were settled for approximately $0.3 million and $0.1 million cash, respectively. No units were settled in cash during the year ended December 31, 2012. | |||||||||||||||||||||||
-3 | The number of 2006 phantom units was adjusted concurrently with the distribution of ARP common units. | |||||||||||||||||||||||
-4 | The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2014 was $24.3 million. | |||||||||||||||||||||||
-5 | There were $0.8 million and $1.1 million recognized as liabilities on APL’s consolidated balance sheets at December 31, 2014 and 2013, respectively, representing 41,113 and 41,525, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units are $36.94 and $29.67 as of December 31, 2014 and 2013, respectively. | |||||||||||||||||||||||
Unit Option Activity | The following table sets forth the 2006 LTIP unit option activity for the periods indicated: | |||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Number | Weighted | Number | Weighted | Number | Weighted | |||||||||||||||||||
of Unit | Average | of Unit | Average | of Unit | Average | |||||||||||||||||||
Options | Exercise | Options | Exercise | Options | Exercise | |||||||||||||||||||
Price | Price | Price | ||||||||||||||||||||||
Outstanding, beginning of year | 939,939 | $ | 20.94 | 929,939 | $ | 20.75 | 903,614 | $ | 21.52 | |||||||||||||||
Granted | — | — | 10,000 | 38.51 | — | — | ||||||||||||||||||
Exercised(1) | — | — | — | — | (51,998 | ) | 3.03 | |||||||||||||||||
Forfeited | — | — | — | — | — | — | ||||||||||||||||||
ARP anti-dilution adjustment(2) | — | — | — | — | 78,323 | — | ||||||||||||||||||
Outstanding, end of year(3)(4) | 939,939 | $ | 20.94 | 939,939 | $ | 20.94 | 929,939 | $ | 20.75 | |||||||||||||||
Options exercisable, end of year(5) | 932,439 | $ | 20.8 | 929,939 | $ | 20.75 | 929,939 | $ | 20.75 | |||||||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 22 | $ | 36 | $ | — | ||||||||||||||||||
-1 | The intrinsic value of options exercised during the year ended December 31, 2012 was $1.5 million. No options were exercised during the years ended December 31, 2014 and 2013. | |||||||||||||||||||||||
-2 | The number of 2006 unit options and exercise price was adjusted concurrently with the distribution of ARP common units. | |||||||||||||||||||||||
-3 | The weighted average remaining contractual life for outstanding options at December 31, 2014 was 1.9 years. | |||||||||||||||||||||||
-4 | The aggregate intrinsic value of options outstanding at December 31, 2014 was approximately $9.7 million. | |||||||||||||||||||||||
-5 | The weighted average remaining contractual lives for exercisable options at December 31, 2014 and 2013 were 1.9 years and 2.9 years, respectively. The aggregate intrinsic values of options exercisable at December 31, 2014, 2013 and 2012 were $9.7 million, $24.3 million and $13.0 million, respectively. | |||||||||||||||||||||||
Weighted Average Assumptions | The following weighted average assumptions were used for the periods indicated: | |||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Expected dividend yield | — | % | 3.2 | % | — | % | ||||||||||||||||||
Expected unit price volatility | — | % | 30 | % | — | % | ||||||||||||||||||
Risk-free interest rate | — | % | 0.7 | % | — | % | ||||||||||||||||||
Expected term (in years) | — | 6.25 | — | |||||||||||||||||||||
Fair value of unit options granted | $ | — | $ | 7.54 | $ | — | ||||||||||||||||||
ARP Long Term Incentive Plan | ||||||||||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||||||||||||||||||
Phantom Unit Activity | The following table sets forth the ARP LTIP phantom unit activity for the periods indicated: | |||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Number | Weighted | Number | Weighted | Number | Weighted | |||||||||||||||||||
of Units | Average | of Units | Average | of Units | Average | |||||||||||||||||||
Grant Date | Grant Date | Grant Date | ||||||||||||||||||||||
Fair Value | Fair Value | Fair Value | ||||||||||||||||||||||
Outstanding, beginning of year | 839,808 | $ | 24.31 | 948,476 | $ | 24.76 | — | $ | — | |||||||||||||||
Granted | 264,173 | 19.43 | 145,813 | 21.87 | 949,476 | 24.76 | ||||||||||||||||||
Vested(1) | (274,414 | ) | 24.46 | (215,981 | ) | 24.73 | — | — | ||||||||||||||||
Forfeited | (30,375 | ) | 22.76 | (38,500 | ) | 23.96 | (1,000 | ) | 24.67 | |||||||||||||||
Outstanding, end of year(2)(3) | 799,192 | $ | 22.7 | 839,808 | $ | 24.31 | 948,476 | $ | 24.76 | |||||||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 6,367 | $ | 9,166 | $ | 7,630 | ||||||||||||||||||
-1 | The intrinsic values of phantom unit awards vested during the years ended December 31, 2014 and 2013 were $5.4 million and $6.1 million, respectively. No phantom unit awards vested during the year ended December 31, 2012. | |||||||||||||||||||||||
-2 | The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2014 was $8.6 million. | |||||||||||||||||||||||
-3 | There was approximately $0.2 million and $0.1 million recognized as liabilities on the Partnership’s consolidated balance sheets at December 31, 2014 and 2013, respectively, representing 26,579 and 16,084 units, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units were $21.16 and $22.15 at December 31, 2014 and 2013, respectively. | |||||||||||||||||||||||
Unit Option Activity | The following table sets forth the ARP LTIP unit option activity for the periods indicated: | |||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Number | Weighted | Number | Weighted | Number | Weighted | |||||||||||||||||||
of Unit Options | Average | of Unit Options | Average | of Unit Options | Average | |||||||||||||||||||
Exercise Price | Exercise Price | Exercise Price | ||||||||||||||||||||||
Outstanding, beginning of year | 1,482,675 | $ | 24.66 | 1,515,500 | $ | 24.68 | — | $ | — | |||||||||||||||
Granted | — | — | 5,000 | 21.56 | 1,517,500 | 24.68 | ||||||||||||||||||
Exercised (1) | — | — | — | — | — | — | ||||||||||||||||||
Forfeited | (24,375 | ) | 24.52 | (37,825 | ) | 24.8 | (2,000 | ) | 24.67 | |||||||||||||||
Outstanding, end of year(2)(3) | 1,458,300 | $ | 24.66 | 1,482,675 | $ | 24.66 | 1,515,500 | $ | 24.68 | |||||||||||||||
Options exercisable, end of year(4) | 730,775 | $ | 24.67 | 370,700 | $ | 24.67 | — | $ | — | |||||||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 1,700 | $ | 3,514 | $ | 3,198 | ||||||||||||||||||
-1 | No options were exercised during the years ended December 31, 2014, 2013 and 2012. | |||||||||||||||||||||||
-2 | The weighted average remaining contractual life for outstanding options at December 31, 2014 was 7.4 years. | |||||||||||||||||||||||
-3 | There was no aggregate intrinsic value of options outstanding at December 31, 2014. The aggregate intrinsic value of options outstanding at December 31, 2013 was approximately $1,000. | |||||||||||||||||||||||
-4 | The weighted average remaining contractual life for exercisable options at December 31, 2014 and 2013 was 7.4 years and 8.4 years, respectively. There were no intrinsic values for options exercisable at December 31, 2014, 2013, and 2012. | |||||||||||||||||||||||
Weighted Average Assumptions | The following weighted average assumptions were used for the periods indicated: | |||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Expected dividend yield | — | % | 8 | % | 5.9 | % | ||||||||||||||||||
Expected unit price volatility | — | % | 35.5 | % | 47 | % | ||||||||||||||||||
Risk-free interest rate | — | % | 1.4 | % | 1 | % | ||||||||||||||||||
Expected term (in years) | — | 6.31 | 6.25 | |||||||||||||||||||||
Fair value of unit options granted | $ | — | $ | 2.95 | $ | 6.1 | ||||||||||||||||||
APL Long Term Incentive Plans | ||||||||||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||||||||||||||||||
Phantom Unit Activity | The following table sets forth the APL LTIPs phantom unit activity for the periods indicated: | |||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Number | Weighted | Number | Weighted | Number | Weighted | |||||||||||||||||||
of Units | Average | of Units | Average | of Units | Average | |||||||||||||||||||
Grant Date | Grant Date | Grant Date | ||||||||||||||||||||||
Fair Value | Fair Value | Fair Value | ||||||||||||||||||||||
Outstanding, beginning of year | 1,446,553 | $ | 36.32 | 1,053,242 | $ | 33.21 | 394,489 | $ | 21.63 | |||||||||||||||
Granted | 738,727 | 33.03 | 744,997 | 38.96 | 907,637 | 34.94 | ||||||||||||||||||
Forfeited | (37,075 | ) | 37.09 | (61,550 | ) | 36.11 | (67,675 | ) | 29.83 | |||||||||||||||
Vested (1)(2) | (463,916 | ) | 34.71 | (290,136 | ) | 31.88 | (181,209 | ) | 17.88 | |||||||||||||||
Outstanding, end of year(3)(4) | 1,684,289 | $ | 35.3 | 1,446,553 | $ | 36.32 | 1,053,242 | $ | 33.21 | |||||||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 25,116 | $ | 19,344 | $ | 11,635 | ||||||||||||||||||
Operating_Segment_Information_
Operating Segment Information (Tables) | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Segment Reporting [Abstract] | ||||||||||||||||
Operating Segment Data | The Partnership’s operations include three reportable operating segments. These operating segments reflect the way the Partnership manages its operations and makes business decisions. Operating segment data for the periods indicated were as follows (in thousands): | |||||||||||||||
Years Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
Atlas Resource: | ||||||||||||||||
Revenues | $ | 685,560 | $ | 467,655 | $ | 267,629 | ||||||||||
Operating costs and expenses | (425,000 | ) | (348,812 | ) | (246,267 | ) | ||||||||||
Depreciation, depletion and amortization expense | (233,731 | ) | (136,763 | ) | (52,582 | ) | ||||||||||
Asset impairment | (573,774 | ) | (38,014 | ) | (9,507 | ) | ||||||||||
Loss on asset sales and disposal | (1,869 | ) | (987 | ) | (6,980 | ) | ||||||||||
Interest expense | (62,144 | ) | (34,324 | ) | (4,195 | ) | ||||||||||
Segment loss | $ | (610,958 | ) | $ | (91,245 | ) | $ | (51,902 | ) | |||||||
Atlas Pipeline: | ||||||||||||||||
Revenues | $ | 2,961,113 | $ | 2,102,113 | $ | 1,252,674 | ||||||||||
Operating costs and expenses | (2,483,160 | ) | (1,863,510 | ) | (1,052,826 | ) | ||||||||||
Depreciation, depletion and amortization expense | (202,543 | ) | (168,617 | ) | (90,029 | ) | ||||||||||
Asset impairment | — | (43,866 | ) | — | ||||||||||||
Gain (loss) on asset sales and disposal | 47,381 | (1,519 | ) | — | ||||||||||||
Interest expense | (93,147 | ) | (89,637 | ) | (41,760 | ) | ||||||||||
Loss on early extinguishment of debt | — | (26,601 | ) | — | ||||||||||||
Segment income (loss) | $ | 229,644 | $ | (91,637 | ) | $ | 68,059 | |||||||||
Corporate and other: | ||||||||||||||||
Revenues | $ | 22,030 | $ | 7,747 | $ | 1,140 | ||||||||||
Operating costs and expenses | (72,822 | ) | (41,690 | ) | (33,613 | ) | ||||||||||
Depreciation, depletion and amortization expense | (8,348 | ) | (3,153 | ) | — | |||||||||||
Asset impairment | (6,880 | ) | — | — | ||||||||||||
Gain on asset sales and disposal | 10 | — | — | |||||||||||||
Interest expense | (18,066 | ) | (8,620 | ) | (565 | ) | ||||||||||
Segment loss | $ | (84,076 | ) | $ | (45,716 | ) | $ | (33,038 | ) | |||||||
Reconciliation of segment income (loss) to net loss: | ||||||||||||||||
Segment income (loss): | ||||||||||||||||
Atlas Resource | $ | (610,958 | ) | $ | (91,245 | ) | $ | (51,902 | ) | |||||||
Atlas Pipeline | 229,644 | (91,637 | ) | 68,059 | ||||||||||||
Corporate and other | (84,076 | ) | (45,716 | ) | (33,038 | ) | ||||||||||
Net loss | $ | (465,390 | ) | $ | (228,598 | ) | $ | (16,881 | ) | |||||||
Reconciliation of segment revenues to total revenues: | ||||||||||||||||
Segment revenues: | ||||||||||||||||
Atlas Resource | $ | 685,560 | $ | 467,655 | $ | 267,629 | ||||||||||
Atlas Pipeline | 2,961,113 | 2,102,113 | 1,252,674 | |||||||||||||
Corporate and other | 22,030 | 7,747 | 1,140 | |||||||||||||
Total revenues | $ | 3,668,703 | $ | 2,577,515 | $ | 1,521,443 | ||||||||||
Capital expenditures: | ||||||||||||||||
Atlas Resource | $ | 212,634 | $ | 263,537 | $ | 127,226 | ||||||||||
Atlas Pipeline | 647,747 | 450,560 | 373,533 | |||||||||||||
Corporate and other | 13,002 | 3,943 | — | |||||||||||||
Total capital expenditures | $ | 873,383 | $ | 718,040 | $ | 500,759 | ||||||||||
December 31, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Balance sheet: | ||||||||||||||||
Goodwill: | ||||||||||||||||
Atlas Resource | $ | 13,639 | $ | 31,784 | ||||||||||||
Atlas Pipeline | 365,763 | 368,572 | ||||||||||||||
Corporate and other | — | — | ||||||||||||||
$ | 379,402 | $ | 400,356 | |||||||||||||
Total assets: | ||||||||||||||||
Atlas Resource | $ | 2,727,575 | $ | 2,343,800 | ||||||||||||
Atlas Pipeline | 4,824,733 | 4,327,845 | ||||||||||||||
Corporate and other | 314,328 | 120,996 | ||||||||||||||
$ | 7,866,636 | $ | 6,792,641 | |||||||||||||
Supplemental_Oil_and_Gas_Infor1
Supplemental Oil and Gas Information (Unaudited) (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Oil And Gas Exploration And Production Industries Disclosures [Abstract] | |||||||||||||
Reserve Quantity Information | Reserve quantity information and a reconciliation of changes in proved reserve quantities included within the Partnership and ARP are as follows (unaudited): | ||||||||||||
Gas (Mcf) | Oil (Bbls)(1) | NGLs (Bbls)(1) | |||||||||||
Balance, January 1, 2012 | 157,676,431 | 1,646,299 | — | ||||||||||
Extensions, discoveries and other additions(2) | 6,756,817 | 10,688 | — | ||||||||||
Sales of reserves in-place | — | — | — | ||||||||||
Purchase of reserves in-place | 462,504,519 | 7,485,998 | 16,212,356 | ||||||||||
Transfers to limited partnerships | — | — | — | ||||||||||
Revisions(3) | (27,760,192 | ) | (153,413 | ) | 206,091 | ||||||||
Production | (25,403,318 | ) | (120,736 | ) | (356,550 | ) | |||||||
Balance, December 31, 2012(4) | 573,774,257 | 8,868,836 | 16,061,897 | ||||||||||
Extensions, discoveries and other additions(2) | 90,098,219 | 8,255,531 | 8,197,272 | ||||||||||
Sales of reserves in-place | (2,755,155 | ) | — | (4,625 | ) | ||||||||
Purchase of reserves in-place | 493,481,302 | 1,964 | 55,187 | ||||||||||
Transfers to limited partnerships | (2,485,210 | ) | (239,910 | ) | (258,381 | ) | |||||||
Revisions(5) | (88,484,468 | ) | (1,412,371 | ) | (3,826,744 | ) | |||||||
Production | (59,849,442 | ) | (485,226 | ) | (1,267,590 | ) | |||||||
Balance, December 31, 2013 | 1,003,779,503 | 14,988,824 | 18,957,016 | ||||||||||
Extensions, discoveries and other additions(2) | 58,461,204 | 3,372,177 | 3,986,986 | ||||||||||
Sales of reserves in-place | (169,035 | ) | (1,519 | ) | (11,326 | ) | |||||||
Purchase of reserves in-place | 88,635,059 | 51,168,449 | 3,567,531 | ||||||||||
Transfers to limited partnerships | (4,887,095 | ) | (684,613 | ) | 956,810 | ||||||||
Revisions | 5,947,622 | (4,639,546 | ) | (2,689,372 | ) | ||||||||
Production | (86,889,803 | ) | (1,254,247 | ) | (1,387,865 | ) | |||||||
Balance, December 31, 2014 | 1,064,877,455 | 62,949,525 | 23,379,780 | ||||||||||
Proved developed reserves at: | |||||||||||||
January 1, 2012 | 138,403,225 | 1,638,083 | — | ||||||||||
December 31, 2012 | 338,655,324 | 3,400,447 | 7,884,778 | ||||||||||
December 31, 2013 | 766,872,394 | 3,459,260 | 7,676,389 | ||||||||||
December 31, 2014 | 889,073,136 | 31,150,298 | 12,209,825 | ||||||||||
Proved undeveloped reserves at: | |||||||||||||
1-Jan-12 | 19,273,206 | 8,216 | — | ||||||||||
December 31, 2012 | 235,118,932 | 5,468,389 | 8,177,120 | ||||||||||
December 31, 2013 | 236,907,109 | 11,529,564 | 11,280,627 | ||||||||||
December 31, 2014 | 175,804,319 | 31,799,227 | 11,169,954 | ||||||||||
(1) Oil includes NGL information at January 1, 2012, which was less than 500 MBbls. | |||||||||||||
(2) Principally includes increases of proved reserves due to the addition of Marble Falls wells. | |||||||||||||
(3) Represents a downward revision and related impairment charge related to ARP’s shallow natural gas wells in Michigan and Colorado due to declines in the average 1st day of the month price for the year ended December 31, 2012 as compared with the year ended December 31, 2011. | |||||||||||||
(4)Prior to the Arkoma Acquisition on July 31, 2013, Partnership had no oil and gas reserves. At December 31, 2014, there were no proved undeveloped reserves related to Partnership’s oil and gas assets. | |||||||||||||
(5) Represents a downward revision primarily due to a reduction of ARP’s five year drilling plans in the Barnett Shale and pricing scenario revisions. | |||||||||||||
Schedule of Capitalized Costs Related to Oil and Gas Producing Activities | Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized costs related to oil and gas producing activities of Partnership and ARP during the periods indicated were as follows (in thousands): | ||||||||||||
Years Ended December 31, | |||||||||||||
2014 | 2013 | ||||||||||||
Natural gas and oil properties: | |||||||||||||
Proved properties | $3,693,833 | $2,557,797 | |||||||||||
Unproved properties | 217,322 | 211,851 | |||||||||||
Support equipment | 37,359 | 23,258 | |||||||||||
3,894,513 | 2,792,906 | ||||||||||||
Accumulated depreciation, depletion and amortization | -1,518,686 | -649,635 | |||||||||||
Net capitalized costs | $2,375,827 | $2,143,271 | |||||||||||
Schedule of Results of Operations from Oil and gas Producing Activities | Results of Operations from Oil and Gas Producing Activities. The results of operations related to Partnership’s and ARP’s oil and gas producing activities during the periods indicated were as follows (in thousands): | ||||||||||||
Years Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Revenues | $475,758 | $273,906 | $92,901 | ||||||||||
Production costs | -184,296 | -100,178 | -26,624 | ||||||||||
Depreciation, depletion and amortization | -231,638 | -132,860 | -47,000 | ||||||||||
Asset impairment(1) | -580,654 | -38,014 | -9,507 | ||||||||||
($520,830) | $2,854 | $9,770 | |||||||||||
(1) During the year ended December 31, 2014, the Partnership recognized $580.7 million of asset impairment consisting of $562.6 million related to oil and gas properties within property, plant, and equipment, net on the Partnership’s consolidated balance sheet primarily for ARP’s Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income, and $18.1 million goodwill impairment resulting from the decline in overall commodity prices. During the year ended December 31, 2013, ARP recognized $38.0 million of impairment primarily related to its shallow natural gas wells in the New Albany shale and unproved acreage in the Chattanooga and New Albany shales. During the year ended December 31, 2012, ARP recognized $9.5 million of impairment related to its shallow natural gas wells in the Antrim and Niobrara shales. | |||||||||||||
Schedule of Costs Incurred in Oil and gas Producing Activities | Costs Incurred in Oil and Gas Producing Activities. The costs incurred by the Partnership and ARP in their oil and gas activities during the periods indicated are as follows (in thousands): | ||||||||||||
Years Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Property acquisition costs: | |||||||||||||
Proved properties | $754,197 | $863,421 | $528,684 | ||||||||||
Unproved properties | 10,978 | 895 | 213,638 | ||||||||||
Exploration costs(1) | 722 | 1,053 | 1,026 | ||||||||||
Development costs | 177,726 | 214,383 | 83,538 | ||||||||||
Total costs incurred in oil & gas producing activities | $943,623 | $1,079,752 | $826,886 | ||||||||||
(1) There were no exploratory wells drilled during the years ended December 31, 2014, 2013 and 2012. | |||||||||||||
Schedule of Standardized Measure of Estimated Discounted Future Net Cash Flows | Standardized Measure of Discounted Future Cash Flows. The following schedule presents the standardized measure of estimated discounted future net cash flows relating to the Partnership’s and ARP’s proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2014, 2013 and 2012, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations (in thousands): | ||||||||||||
Years Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Future cash inflows | $10,802,697 | $5,268,148 | $2,930,514 | ||||||||||
Future production costs | -4,561,129 | -2,397,997 | -1,185,084 | ||||||||||
Future development costs | -1,623,218 | -752,369 | -441,423 | ||||||||||
Future net cash flows | 4,618,350 | 2,117,782 | 1,304,007 | ||||||||||
Less 10% annual discount for estimated timing of cash flows | -2,381,586 | -1,038,491 | -680,331 | ||||||||||
Standardized measure of discounted future net cash flows | $2,236,764 | $1,079,291 | $623,676 | ||||||||||
Schedule of Changes in Discounted Future Net Cash Flows | Changes in Standardized Discounted Future Cash Flows. The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved oil, gas and NGL reserves (in thousands), including amounts related to asset retirement obligations. Since the Partnership and ARP allocate taxable income to their owner, no recognition has been given to income taxes: | ||||||||||||
Years Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Balance, beginning of year | $1,079,291 | $623,676 | $219,859 | ||||||||||
Increase (decrease) in discounted future net cash flows: | |||||||||||||
Sales and transfers of oil and gas, net of related costs | -275,789 | -171,409 | -54,969 | ||||||||||
Net changes in prices and production costs | 339,776 | 85,191 | -87 | ||||||||||
Revisions of previous quantity estimates | -33,526 | -1,881 | -6,378 | ||||||||||
Development costs incurred | 52,077 | 27,245 | 575 | ||||||||||
Changes in future development costs | -90,887 | -21,579 | — | ||||||||||
Transfers to limited partnerships | -2,966 | -53,392 | — | ||||||||||
Extensions, discoveries, and improved recovery less related costs | 69,436 | 143,338 | 64 | ||||||||||
Purchases of reserves in-place | 1,018,345 | 516,985 | 510,467 | ||||||||||
Sales of reserves in-place | -332 | -2,053 | — | ||||||||||
Accretion of discount | 107,929 | 62,368 | 21,986 | ||||||||||
Estimated settlement of asset retirement obligations | -16,824 | -18,858 | -2,823 | ||||||||||
Estimated proceeds on disposals of well equipment | -21,896 | 17,052 | 3,806 | ||||||||||
Changes in production rates (timing) and other | 12,130 | -127,392 | -68,824 | ||||||||||
Outstanding, end of year | $2,236,764 | $1,079,291 | $623,676 | ||||||||||
Quarterly_Results_Tables
Quarterly Results (Tables) | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | ||||||||||||||||
Schedule of Quarterly Financial Information | ||||||||||||||||
Fourth | Third | Second | First | |||||||||||||
Quarter(1) | Quarter(1) | Quarter(1) | Quarter(1) | |||||||||||||
(in thousands, except unit data) | ||||||||||||||||
Year ended December 31, 2014: | ||||||||||||||||
Revenues | $ | 992,534 | $ | 963,980 | $ | 851,889 | $ | 860,300 | ||||||||
Net income (loss) | (497,769 | ) | 31,513 | 21,933 | (21,067 | ) | ||||||||||
(Income) loss attributable to non-controlling interests | 338,544 | (40,598 | ) | (31,956 | ) | 7,142 | ||||||||||
Net loss attributable to common limited partners | $ | (159,225 | ) | $ | (9,085 | ) | $ | (10,023 | ) | $ | (13,925 | ) | ||||
Net loss attributable to common limited partners per unit: | ||||||||||||||||
Basic | $ | (3.06 | ) | $ | (0.18 | ) | $ | (0.19 | ) | $ | (0.27 | ) | ||||
Diluted | $ | (3.06 | ) | $ | (0.18 | ) | $ | (0.19 | ) | $ | (0.27 | ) | ||||
-1 | For the first, second, third and fourth quarters of the year ended December 31, 2014, approximately 4,111,000, 4,049,000, 5,082,000 and 4,637,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit because the inclusion of such units would have been anti-dilutive. | |||||||||||||||
Fourth | Third | Second | First | |||||||||||||
Quarter(1) | Quarter(1) | Quarter(1) | Quarter(1) | |||||||||||||
(in thousands, except unit data) | ||||||||||||||||
Year ended December 31, 2013: | ||||||||||||||||
Revenues | $ | 761,629 | $ | 649,989 | $ | 643,795 | $ | 522,102 | ||||||||
Net loss | (102,169 | ) | (79,546 | ) | (5,189 | ) | (41,694 | ) | ||||||||
(Income) loss attributable to non-controlling interests | 75,169 | 52,022 | (3,058 | ) | 29,098 | |||||||||||
Net loss attributable to common limited partners | $ | (27,000 | ) | $ | (27,524 | ) | $ | (8,247 | ) | $ | (12,596 | ) | ||||
Net loss attributable to common limited partners per unit: | ||||||||||||||||
Basic | $ | (0.53 | ) | $ | (0.54 | ) | $ | (0.16 | ) | $ | (0.25 | ) | ||||
Diluted | $ | (0.53 | ) | $ | (0.54 | ) | $ | (0.16 | ) | $ | (0.25 | ) | ||||
-1 | For the first, second, third and fourth quarters of the year ended December 31, 2013, approximately 3,594,000, 4,092,000, 4,196,000 and 4,091,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit because the inclusion of such units would have been anti-dilutive. | |||||||||||||||
Basis_of_Presentation_Narrativ
Basis of Presentation (Narrative) (Details) | 1 Months Ended | 12 Months Ended | 1 Months Ended |
Feb. 29, 2012 | Dec. 31, 2014 | Dec. 31, 2012 | |
Limited Partner Interest | |||
Basis Of Presentation [Line Items] | |||
Board Approval Date For Issuance of Common Units | 2012-02 | ||
Exploration And Production Assets Transferred | 5-Mar-12 | ||
Distribution Made to Member or Limited Partner, Share Distribution | 5,240,000 | ||
Distribution Made to Member or Limited Partner, Distribution Date | 13-Mar-12 | ||
Ratio Of ARP Limited Partner Units | 0.1021 | ||
Distribution Made to Member or Limited Partner, Date of Record | 28-Feb-12 | ||
Lightfoot Capital Partners, LP | |||
Basis Of Presentation [Line Items] | |||
General partner ownership interest | 15.90% | ||
Common limited partner ownership interest | 12.00% | ||
Development Subsidiary | |||
Basis Of Presentation [Line Items] | |||
Common limited partner ownership interest | 1.70% | ||
Outstanding general partner ownership interest | 80.00% | ||
Percentage of cash distribution | 2.00% | ||
Atlas Resource Partners, L.P. | |||
Basis Of Presentation [Line Items] | |||
General partner ownership interest | 100.00% | ||
Common limited partner ownership interest | 27.70% | ||
Common limited partner interest in ARP, units | 20,962,485 | ||
Atlas Resource Partners, L.P. | Class C Preferred Limited Partner Units | |||
Basis Of Presentation [Line Items] | |||
Common limited partner interest in ARP, units | 3,749,986 | ||
Atlas Pipeline "APL" | |||
Basis Of Presentation [Line Items] | |||
General partner ownership interest | 2.00% | 2.00% | |
Common limited partner ownership interest | 5.50% |
Summary_of_Significant_Account3
Summary of Significant Accounting Policies (Narrative) (Details) (USD $) | 2 Months Ended | 12 Months Ended | 0 Months Ended | 1 Months Ended | 0 Months Ended | 1 Months Ended | 0 Months Ended | ||||
Dec. 31, 2012 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 23, 2014 | Oct. 31, 2014 | Jan. 14, 2015 | Dec. 31, 2012 | Apr. 17, 2013 | 7-May-13 | 14-May-14 | |
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Pro-rata share in Drilling Partnerships | 30.00% | ||||||||||
Partners unit, issued | 7,898,210 | 0 | |||||||||
Conversion of Class B preferred units (units) | 3,796,900 | ||||||||||
Non-controlling interests | $3,152,464,000 | $2,851,027,000 | |||||||||
Distributions paid to unitholders | 99,996,000 | 77,598,000 | 51,837,000 | ||||||||
Allowance for Doubtful Accounts Receivable | 0 | 0 | |||||||||
Materials, supplies and other inventory | 23,700,000 | 19,700,000 | |||||||||
Asset impairment | 580,654,000 | 81,880,000 | 9,507,000 | ||||||||
Future Hedge Gains | 82,300,000 | ||||||||||
Weighted Average Interest Rate Used To Capitalize Interest | 5.60% | 5.90% | 5.80% | ||||||||
Interest Costs Capitalized | 25,700,000 | 21,700,000 | 10,800,000 | ||||||||
Amortization of Intangible Assets | 80,300,000 | 69,300,000 | 24,000,000 | ||||||||
Future Amortization Expense, 2015 | 74,300,000 | ||||||||||
Future Amortization Expense, 2016 | 74,200,000 | ||||||||||
Future Amortization Expense, 2017 | 68,100,000 | ||||||||||
Future Amortization Expense, 2018 | 59,600,000 | ||||||||||
Future Amortization Expense, 2019 | 59,600,000 | ||||||||||
Goodwill, Impairment Loss | 18,100,000 | ||||||||||
Equity Method Investment Ownership Percentage | 100.00% | ||||||||||
Equity Method Impairment Loss | 0 | 0 | 0 | ||||||||
Entity Not Subject to Income Taxes, Policy | The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income (loss) reported in the accompanying consolidated financial statements. | ||||||||||
Income Tax Examination, Penalties and Interest Expense | 0 | 0 | 0 | ||||||||
Income Tax Examination, Description | The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2011. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2014, except for an ongoing examination by the Texas Comptroller of Public Accounts related to APL’s Texas Franchise Tax for franchise report years 2008 through 2011. | ||||||||||
Deferred income tax (benefit) expense | -2,376,000 | -2,260,000 | 176,000 | ||||||||
Environmental Remediation Costs Recognized Disclosure | During the year ended December 31, 2012, one of the Partnership’s subsidiaries entered into two agreements with the United States Environmental Protection Agency (the “EPAâ€) to settle alleged violations in connection with a fire that occurred at a natural gas well and associated well pad site in Washington County, Pennsylvania in 2010. The EPA alleged non-compliance with the Clean Air Act, including with respect to the storage and handling of the natural gas condensate, as well as non-compliance with the Emergency Planning and Community Right-to-Know Act of 1986. The subsidiary agreed to a civil penalty of $84,506 under a consent agreement and agreed to upgrade its facility pursuant to an administrative settlement agreement. | ||||||||||
Penalty Under Administrative Settlement Agreement | 84,506 | ||||||||||
Concentration Risk, Credit Risk, Uninsured Deposits | Financial instruments, which potentially subject the Partnership to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. The Partnership and its subsidiaries place their temporary cash investments in high-quality short-term money market instruments and deposits with high-quality financial institutions and brokerage firms. At December 31, 2014 and 2013, the Partnership had $86.5 million and $51.4 million, respectively, in deposits at various banks, of which $81.6 million and $48.8 million, respectively, were over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments to date. Cash on deposit at various banks may differ from the balance of cash and cash equivalents at period end due to certain reconciling items, including any outstanding checks as of period end. | ||||||||||
Cash Equivalents, at Carrying Value | 86,500,000 | 51,400,000 | |||||||||
Cash, Uninsured Amount | 81,600,000 | 48,800,000 | |||||||||
Concentration Risk, Customer | The Partnership and its subsidiaries sell natural gas, crude oil and NGLs under contracts to various purchasers in the normal course of business. For the year ended December 31, 2014, ARP had four customers within its gas and oil production segment that individually accounted for approximately 25%, 15%, 14% and 13%, respectively, of its natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2013, ARP had three customers within its gas and oil production segment that individually accounted for approximately 19%, 11% and 10%, respectively, of its natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2012, ARP had two customers within its gas and oil production segment that individually accounted for approximately 43% and 11% of its natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. | ||||||||||
Proportion of amount received on cost incurred to drill | 15.00% | ||||||||||
Monthly administrative fee per well | 75 | ||||||||||
Gathering Fee Percentage | 16.00% | ||||||||||
Gathering Fee Percentage Net Margin | 3.00% | ||||||||||
Unbilled Contracts Receivable | 260,700,000 | 191,800,000 | |||||||||
Customer Concentration Risk Customer 1 | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Concentration Risk, Percentage | 25.00% | 19.00% | 43.00% | ||||||||
Customer Concentration Risk Customer 2 | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Concentration Risk, Percentage | 15.00% | 11.00% | 11.00% | ||||||||
Customer Concentration Risk Customer 3 | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Concentration Risk, Percentage | 14.00% | 10.00% | |||||||||
Customer Concentration Risk Customer 4 | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Concentration Risk, Percentage | 13.00% | ||||||||||
Minimum | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Recognition period to receive fees | 60 days | ||||||||||
Amount of fixed fees received by each well drilled | 100,000 | ||||||||||
Monthly operating fee paid per well | 1,000 | ||||||||||
Return on unhedged revenue percentage | 10.00% | ||||||||||
Period of return on unhedged revenue | 5 years | ||||||||||
Maximum | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Recognition period to receive fees | 270 days | ||||||||||
Amount of fixed fees received by each well drilled | 500,000 | ||||||||||
Monthly operating fee paid per well | 2,000 | ||||||||||
Percentage on unhedged revenue | 50.00% | ||||||||||
Return on unhedged revenue percentage | 12.00% | ||||||||||
Period of return on unhedged revenue | 8 years | ||||||||||
ARP Acquisitions | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Goodwill, Impairment Loss | 18,100,000 | ||||||||||
Goodwill Impairment Indicators | 0 | 0 | |||||||||
ARP Acquisitions | Class B Preferred Units | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Conversion of Class B preferred units (units) | 3,796,900 | ||||||||||
ARP Acquisitions | Preferred class D | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Partners unit, issued | 3,200,000 | ||||||||||
Partners' Capital Account, Units, Percentage | 8.63% | ||||||||||
ARP Acquisitions | Preferred class D | Subsequent Event | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $0.62 | ||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit there after | $2.16 | ||||||||||
Percentage of Preferred Unit Regular Quarterly Cash Distributions | 8.63% | ||||||||||
Atlas Resource Partners, L.P. | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Gain on sale of subsidiary unit issuances | 40,500,000 | 27,300,000 | |||||||||
Impairments of Unproved Gas and Oil Properties | 0 | 13,500,000 | 0 | ||||||||
Asset impairment | 562,600,000 | 38,000,000 | 9,507,000 | ||||||||
Impairments of Proved Gas And Oil Properties | 24,500,000 | ||||||||||
Atlas Resource Partners, L.P. | Titan Acquisition | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Preferred stock participation rights | While outstanding, the preferred units will receive regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution. | ||||||||||
Atlas Resource Partners, L.P. | Titan Acquisition | Common Units | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Partners unit, issued | 3,800,000 | ||||||||||
Atlas Resource Partners, L.P. | Titan Acquisition | Class B Preferred Units | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Partners unit, issued | 3,800,000 | ||||||||||
Atlas Resource Partners, L.P. | Titan Acquisition | Class B Preferred Units | Minimum | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Distribution Made to Limited Partner, Distributions Declared, Per Unit | $0.40 | ||||||||||
Atlas Pipeline "APL" | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Partners unit, issued | 10,507,033 | ||||||||||
Percentage of ownership interest in joint ventures | 95.00% | ||||||||||
Non-controlling ownership interest in joint ventures | 5.00% | ||||||||||
Equity Method Investment Ownership Percentage | 20.00% | ||||||||||
Deferred income tax (benefit) expense | -2,376,000 | -2,260,000 | 176,000 | ||||||||
Atlas Pipeline "APL" | Centrahoma Processing Llc | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Percentage of ownership interest in joint ventures | 60.00% | ||||||||||
Non-controlling ownership interest in joint ventures | 40.00% | ||||||||||
Business Acquisition, Effective Date of Acquisition | 20-Dec-12 | ||||||||||
Percentage Of Joint Ventures Consolidated | 100.00% | ||||||||||
Atlas Pipeline "APL" | Class E Preferred Units | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $0.68 | ||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit there after | $0.52 | ||||||||||
Atlas Pipeline "APL" | TEAK Acquisition | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Partners unit, issued | 11,845,000 | ||||||||||
Intangible assets | 430,000,000 | ||||||||||
Atlas Pipeline "APL" | TEAK Acquisition | Customer Relationships | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Intangible assets | 450,000,000 | ||||||||||
Estimated Useful Lives In Years | 13 years | ||||||||||
ARP and APL Combined | Preferred Units | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Non-controlling interests | 738,700,000 | 547,300,000 | |||||||||
Ownership Interest West Ok Natural Gas Gathering System And Processing Plants | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Percentage of ownership interest in joint ventures | 100.00% | ||||||||||
Undivided Interest In West Tx Natural Gas System And Processing Plants | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Percentage of ownership interest in joint ventures | 72.80% | ||||||||||
West O K And West T X Joint Venture | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Note receivable from interest holder in joint ventures | 1,900,000,000 | ||||||||||
Pioneer Natural Resources Ownership Interest In West Tx | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Non-controlling ownership interest in joint ventures | 27.20% | ||||||||||
Development Subsidiary | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Stock Issued During Period, Value, New Issues | 81,700,000 | ||||||||||
Distributions paid to unitholders | 1,400,000 | ||||||||||
Gain on sale of subsidiary unit issuances | 4,500,000 | ||||||||||
APL | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Deferred income tax (benefit) expense | $0 | ||||||||||
Atlas Pipeline "APL" | Customer Concentration Risk Customer 1 | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Concentration Risk, Percentage | 26.00% | 29.00% | 48.00% | ||||||||
Atlas Pipeline "APL" | Customer Concentration Risk Customer 2 | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Concentration Risk, Percentage | 13.00% | 17.00% | 15.00% | ||||||||
Atlas Pipeline "APL" | Customer Concentration Risk Customer 3 | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Concentration Risk, Percentage | 11.00% | 14.00% | |||||||||
Drilling Partnership wells | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Gathering Fee Percentage | 13.00% |
Summary_of_Significant_Account4
Summary of Significant Accounting Policies (Schedule of the Components of Intangible Assets Being Amortized) (Details) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Finite Lived Intangible Assets [Line Items] | ||
Gross Carrying Amount | $885,416 | $905,416 |
Accumulated Amortization | -288,464 | -208,182 |
Net Carrying Amount | 596,952 | 697,234 |
Customer-Related Intangible Assets | ||
Finite Lived Intangible Assets [Line Items] | ||
Gross Carrying Amount | 871,072 | 891,072 |
Accumulated Amortization | -274,811 | -194,801 |
Net Carrying Amount | 596,261 | 696,271 |
Customer-Related Intangible Assets | Minimum | ||
Finite Lived Intangible Assets [Line Items] | ||
Estimated Useful Lives In Years | 2 years | |
Customer-Related Intangible Assets | Maximum | ||
Finite Lived Intangible Assets [Line Items] | ||
Estimated Useful Lives In Years | 15 years | |
Partnership Management And Operating Contracts | ||
Finite Lived Intangible Assets [Line Items] | ||
Gross Carrying Amount | 14,344 | 14,344 |
Accumulated Amortization | -13,653 | -13,381 |
Net Carrying Amount | $691 | $963 |
Estimated Useful Lives In Years | 13 years |
Summary_of_Significant_Account5
Summary of Significant Accounting Policies (Summary of Carrying Amounts of Goodwill by Reportable Operating Segments) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Goodwill [Line Items] | ||
Goodwill | $379,402 | $400,356 |
Atlas Resource Partners, L.P. | Operating Segments | ||
Goodwill [Line Items] | ||
Goodwill | 13,639 | 31,784 |
Atlas Pipeline "APL" | Operating Segments | ||
Goodwill [Line Items] | ||
Goodwill | $365,763 | $368,572 |
Summary_of_Significant_Account6
Summary of Significant Accounting Policies (Schedule of Net Income Reconciliation) (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||||||
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||||||
Reconciliation Of Net Income [Line Items] | |||||||||||||||||||
Net loss | ($497,769) | [1] | $31,513 | [1] | $21,933 | [1] | ($21,067) | [1] | ($102,169) | [2] | ($79,546) | [2] | ($5,189) | [2] | ($41,694) | [2] | ($465,390) | ($228,598) | ($16,881) |
Loss (income) attributable to non-controlling interests | -338,544 | [1] | 40,598 | [1] | 31,956 | [1] | -7,142 | [1] | -75,169 | [2] | -52,022 | [2] | 3,058 | [2] | -29,098 | [2] | 273,132 | 153,231 | -35,532 |
Net loss attributable to common limited partners | -159,225 | [1] | -9,085 | [1] | -10,023 | [1] | -13,925 | [1] | -27,000 | [2] | -27,524 | [2] | -8,247 | [2] | -12,596 | [2] | -192,258 | -75,367 | -52,413 |
Antidilutive Securities Excluded From Computation Of Diluted Earnings Attributable To Common Limited Partners Outstanding Units | 2,827,000 | 2,278,000 | 2,058,000 | ||||||||||||||||
Continuing Operations | |||||||||||||||||||
Reconciliation Of Net Income [Line Items] | |||||||||||||||||||
Loss (income) attributable to non-controlling interests | 273,132 | 153,231 | -35,532 | ||||||||||||||||
Net loss attributable to common limited partners | -192,258 | -75,367 | -52,413 | ||||||||||||||||
Net loss utilized in the calculation of net loss attributable to common limited partners per unit | ($192,258) | ($75,367) | ($52,413) | ||||||||||||||||
[1] | For the first, second, third and fourth quarters of the year ended December 31, 2014, approximately 4,111,000, 4,049,000, 5,082,000 and 4,637,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit because the inclusion of such units would have been anti-dilutive. | ||||||||||||||||||
[2] | For the first, second, third and fourth quarters of the year ended December 31, 2013, approximately 3,594,000, 4,092,000, 4,196,000 and 4,091,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit because the inclusion of such units would have been anti-dilutive. |
Summary_of_Significant_Account7
Summary of Significant Accounting Policies (Reconciliation of Weighted Average Number of Common Limited Partner Units) (Details) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Accounting Policies [Abstract] | |||
Weighted average number of common limited partners per unit—basic | 51,810,000 | 51,387,000 | 51,327,000 |
Weighted average number of common limited partners per unit—diluted | 51,810,000 | 51,387,000 | 51,327,000 |
Antidilutive Securities Excluded From Computation Of Diluted Earnings Attributable To Common Limited Partners Outstanding Units | 4,473,000 | 3,995,000 | 2,867,000 |
Acquisition_from_Atlas_Energy_1
Acquisition from Atlas Energy, Inc. (Narrative) (Details) (USD $) | 0 Months Ended | 12 Months Ended | ||
Feb. 17, 2011 | Dec. 31, 2014 | Dec. 31, 2012 | Dec. 31, 2011 | |
Business Acquisition [Line Items] | ||||
Subsidiary of Limited Liability Company or Limited Partnership, Date | 5-Mar-12 | |||
APL's Equity Method Investment in Laurel Mountain | ||||
Business Acquisition [Line Items] | ||||
Percentage Of Non Controlling Interest Sold In Laurel Mountain Joint Venture | 49.00% | |||
Equity Method Investment, Net Sales Proceeds | $409,500,000 | |||
Chevron | ||||
Business Acquisition [Line Items] | ||||
Chevron transaction expense | 7,670,000 | |||
Transferred Business AEI | ||||
Business Acquisition [Line Items] | ||||
Business Acquisition, Effective Date of Acquisition | 17-Feb-11 | |||
Business Acquisition, Purchase Price Allocation, Status | For the assets acquired and liabilities assumed, the Partnership issued approximately 23.4 million of its common limited partner units and paid $30.0 million in cash consideration. Based on the Partnership’s February 17, 2011 common unit closing price of $15.92, the common units issued to AEI were valued at approximately $372.2 million. Concurrent with the Partnership’s acquisition of the Transferred Business, AEI was sold to Chevron Corporation (NYSE: CVX) (“Chevronâ€). In connection with the transaction, the Partnership received $118.7 million with respect to a contractual cash transaction adjustment from AEI related to certain exploration and production liabilities assumed by the Partnership. Including the cash transaction adjustment, the net book value of the Transferred Business was approximately $522.9 million. Certain amounts included within the contractual cash transaction adjustment were subject to a reconciliation period with Chevron following the consummation of the transaction. Liabilities related to the cash transaction adjustment were assumed by ARP on March 5, 2012, as certain amounts included within the contractual cash transaction adjustment remained in dispute between the parties. During the year ended December 31, 2012, ARP recognized a $7.7 million charge on the Partnership’s consolidated combined statement of operations regarding its reconciliation process with Chevron, which was settled in October 2012 | |||
Cash Consideration | 30,000,000 | |||
Unit closing price | 15.92 | |||
Partners' Capital Account, Acquisitions | 372,200,000 | |||
Contractual cash transaction adjustment from AEI related to certain exploration and production liabilities assumed | 118,700,000 | |||
Historical carrying value of net assets acquired | 522,874,000 | |||
Business Acquisition, Date Transaction Adjustment Assumed | 5-Mar-12 | |||
Net transaction adjustment related to the acquisition of the Transferred Business (see Note 3) | $261,000,000 |
Acquisition_from_Atlas_Energy_2
Acquisition from Atlas Energy, Inc. (Schedule of Acquired Assets And Liabilities) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Feb. 17, 2011 |
In Thousands, unless otherwise specified | |||||
Business Acquisition [Line Items] | |||||
Cash and cash equivalents | $83,210 | $23,501 | $36,780 | $77,376 | |
Accounts receivable | 355,817 | 279,464 | |||
Total current assets | 747,887 | 380,335 | |||
Property, plant and equipment, net | 5,669,262 | 4,910,875 | |||
Goodwill | 379,402 | 400,356 | |||
Intangible assets, net | 596,952 | 697,234 | |||
Other assets, net | 127,921 | 124,672 | |||
Total assets | 7,866,636 | 6,792,641 | |||
Accounts payable | 210,746 | 149,279 | |||
Accrued liabilities | 224,251 | 87,435 | |||
Total current liabilities | 785,769 | 547,255 | |||
Asset retirement obligations | 108,101 | 91,214 | |||
Transferred Business AEI | |||||
Business Acquisition [Line Items] | |||||
Cash and cash equivalents | 153,350 | ||||
Accounts receivable | 18,090 | ||||
Accounts receivable – affiliate | 45,682 | ||||
Prepaid expenses and other | 6,955 | ||||
Total current assets | 224,077 | ||||
Property, plant and equipment, net | 516,625 | ||||
Goodwill | 31,784 | ||||
Intangible assets, net | 2,107 | ||||
Other assets, net | 20,416 | ||||
Total long-term assets | 570,932 | ||||
Total assets | 795,009 | ||||
Accounts payable | 59,202 | ||||
Net liabilities associated with drilling contracts | 47,929 | ||||
Accrued well completion costs | 39,552 | ||||
Current portion of derivative payable to Drilling Partnerships | 25,659 | ||||
Accrued liabilities | 25,283 | ||||
Total current liabilities | 197,625 | ||||
Long-term derivative payable to Drilling Partnerships | 31,719 | ||||
Asset retirement obligations | 42,791 | ||||
Total long-term liabilities | 74,510 | ||||
Total liabilities assumed | 272,135 | ||||
Historical carrying value of net assets acquired | $522,874 |
Acquisitions_Rangely_Acquisiti
Acquisitions (Rangely Acquisition) (Narrative) (Details) (USD $) | 2 Months Ended | 12 Months Ended | 1 Months Ended | |||||
In Millions, except Share data, unless otherwise specified | Dec. 31, 2012 | Dec. 31, 2014 | 31-May-14 | Jun. 30, 2014 | Apr. 30, 2012 | Jun. 02, 2014 | Dec. 31, 2013 | Jan. 23, 2013 |
Business Acquisition [Line Items] | ||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 50.00% | |||||||
Partners unit, issued | 7,898,210 | 0 | ||||||
Rangely Acquisition | ||||||||
Business Acquisition [Line Items] | ||||||||
Partners unit, issued | 15,525,000 | |||||||
Atlas Resource Partners, L.P. | 7.75% Senior Notes | ||||||||
Business Acquisition [Line Items] | ||||||||
Debt Instrument, Interest Rate, Stated Percentage | 7.75% | 7.75% | 7.75% | 7.75% | ||||
Atlas Resource Partners, L.P. | Rangely Acquisition | ||||||||
Business Acquisition [Line Items] | ||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 25.00% | |||||||
Business Acquisition, Cost of Acquired Entity, Cash Paid | $409.40 | |||||||
Debt Instrument, Maturity Date | 15-Aug-21 | |||||||
Business Acquisition, Effective Date of Acquisition | 1-Apr-14 | |||||||
Business Acquisition, Purchase Price Allocation, Methodology | ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). | |||||||
Business Acquisition, Purchase Price Allocation, Status | In conjunction with the issuance of ARP’s common limited partner units associated with the acquisition, ARP recorded $11.6 million of transaction fees which were included within non-controlling interests at December 31, 2014 on the Partnership’s consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred. Due to the recent date of the acquisition, the accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as ARP continues to evaluate the facts and circumstances that existed as of the acquisition date. | |||||||
Business Acquisition, Cost of Acquired Entity, Transaction Costs | 11.6 | |||||||
Atlas Resource Partners, L.P. | Rangely Acquisition | 7.75% Senior Notes | ||||||||
Business Acquisition [Line Items] | ||||||||
Proceed from additional senior notes | $100 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 7.75% | |||||||
Partners unit, issued | 15,525,000 |
Acquisitions_Rangely_Acquisiti1
Acquisitions (Rangely Acquisition Schedule of Assets Acquired and Liabilities Assumed) (Details) (Rangely Acquisition, USD $) | Jun. 30, 2014 |
In Thousands, unless otherwise specified | |
Rangely Acquisition | |
Business Acquisition [Line Items] | |
Prepaid expenses and other | $4,041 |
Property, plant and equipment | 405,876 |
Other assets, net | 2,888 |
Total assets acquired | 412,805 |
Accrued liabilities | 2,117 |
Asset retirement obligation | 1,305 |
Total liabilities assumed | 3,422 |
Historical carrying value of net assets acquired | $409,383 |
Acquisitions_Rangely_Acquisiti2
Acquisitions (Rangely Acquisition Revenues and Net Income Loss) (Narrative) (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Revenues | $992,534 | [1] | $963,980 | [1] | $851,889 | [1] | $860,300 | [1] | $761,629 | [2] | $649,989 | [2] | $643,795 | [2] | $522,102 | [2] | $3,668,703 | $2,577,515 | $1,521,443 |
Net loss | -497,769 | [1] | 31,513 | [1] | 21,933 | [1] | -21,067 | [1] | -102,169 | [2] | -79,546 | [2] | -5,189 | [2] | -41,694 | [2] | -465,390 | -228,598 | -16,881 |
Atlas Pipeline "APL" | Rangely Acquisition | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Revenues | 41,500 | ||||||||||||||||||
Net loss | $18,800 | ||||||||||||||||||
[1] | For the first, second, third and fourth quarters of the year ended December 31, 2014, approximately 4,111,000, 4,049,000, 5,082,000 and 4,637,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit because the inclusion of such units would have been anti-dilutive. | ||||||||||||||||||
[2] | For the first, second, third and fourth quarters of the year ended December 31, 2013, approximately 3,594,000, 4,092,000, 4,196,000 and 4,091,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit because the inclusion of such units would have been anti-dilutive. |
Acquisitions_EP_Energy_Acquisi
Acquisitions (EP Energy Acquisition ) (Narrative) (Details) (USD $) | 2 Months Ended | 12 Months Ended | 1 Months Ended | ||
In Millions, except Share data, unless otherwise specified | Dec. 31, 2012 | Dec. 31, 2014 | Jun. 30, 2014 | Jul. 31, 2013 | Dec. 31, 2013 |
Business Acquisition [Line Items] | |||||
Partners unit, issued | 7,898,210 | 0 | |||
EP Energy Acquisition | |||||
Business Acquisition [Line Items] | |||||
Partners unit, issued | 14,950,000 | ||||
9.25% Senior Notes | |||||
Business Acquisition [Line Items] | |||||
Debt Instrument, Interest Rate, Stated Percentage | 9.25% | ||||
Atlas Resource Partners, L.P. | EP Energy Acquisition | |||||
Business Acquisition [Line Items] | |||||
Business Acquisition, Cost of Acquired Entity, Cash Paid | $709.60 | ||||
Business Acquisition, Effective Date of Acquisition | 1-May-13 | ||||
Partners unit, issued | 14,950,000 | ||||
Business Acquisition, Purchase Price Allocation, Methodology | ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). | ||||
Business Acquisition, Cost of Acquired Entity, Transaction Costs | $12.10 | ||||
Business Acquisition, Purchase Price Allocation, Status | All other costs associated with the acquisition of assets were expensed as incurred. | ||||
Atlas Resource Partners, L.P. | EP Energy Acquisition | Class C Convertible Preferred Units | |||||
Business Acquisition [Line Items] | |||||
Partners unit, issued | 3,749,986 | ||||
Atlas Resource Partners, L.P. | 9.25% Senior Notes | |||||
Business Acquisition [Line Items] | |||||
Debt Instrument, Interest Rate, Stated Percentage | 9.25% | 9.25% | |||
Atlas Resource Partners, L.P. | 9.25% Senior Notes | EP Energy Acquisition | |||||
Business Acquisition [Line Items] | |||||
Debt Instrument, Interest Rate, Stated Percentage | 9.25% | ||||
Debt Instrument, Maturity Date | 15-Aug-21 |
Acquisitions_EP_Energy_Acquisi1
Acquisitions (EP Energy Acquisition Schedule of Assets Acquired and Liabilities Assumed) (Details) (EP Energy Acquisition, USD $) | Jul. 31, 2013 |
In Thousands, unless otherwise specified | |
EP Energy Acquisition | |
Business Acquisition [Line Items] | |
Prepaid expenses and other | $5,268 |
Property, plant and equipment | 723,842 |
Total current assets | 729,110 |
Accounts payable | 2,747 |
Asset retirement obligation | 16,728 |
Total liabilities assumed | 19,475 |
Historical carrying value of net assets acquired | $709,635 |
Acquisitions_DTE_Acquisition_N
Acquisitions (DTE Acquisition) (Narrative) (Details) (USD $) | 2 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended |
In Millions, except Share data, unless otherwise specified | Dec. 31, 2012 | Dec. 31, 2014 | Dec. 20, 2012 | Dec. 31, 2013 |
Business Acquisition [Line Items] | ||||
Business Acquisition, Date of Acquisition Agreement | 1-Apr-12 | |||
Partners unit, issued | 7,898,210 | 0 | ||
Net proceeds from issuance of common limited partner units | $174.50 | |||
Atlas Resource Partners, L.P. | DTE Gas Resources, LLC | ||||
Business Acquisition [Line Items] | ||||
Business Acquisition, Date of Acquisition Agreement | 20-Dec-12 | |||
Business Acquisition, Name of Acquired Entity | DTE Gas Resources, L.L.C. | |||
Partners unit, issued | 7,900,000 | |||
Net proceeds from issuance of common limited partner units | 174.5 | |||
Cash Consideration | 257.4 | |||
Business Acquisition, Purchase Price Allocation, Methodology | ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). | |||
Business Acquisition, Cost of Acquired Entity, Transaction Costs | 0.2 | |||
Atlas Resource Partners, L.P. | DTE Gas Resources, LLC | Line of Credit | ||||
Business Acquisition [Line Items] | ||||
Debt Instrument, Increase, Additional Borrowings | 179.8 | |||
Atlas Resource Partners, L.P. | DTE Gas Resources, LLC | Term Loan Credit Facility | ||||
Business Acquisition [Line Items] | ||||
Debt Instrument, Increase, Additional Borrowings | $77.60 |
Acquisitions_DTE_Acquisition_S
Acquisitions (DTE Acquisition Schedule of Assets Acquired and Liabilities Assumed) (Details) (DTE Gas Resources, LLC, USD $) | Dec. 20, 2012 |
In Thousands, unless otherwise specified | |
DTE Gas Resources, LLC | |
Business Acquisition [Line Items] | |
Accounts receivable | $10,721 |
Prepaid expenses and other | 2,100 |
Total current assets | 12,821 |
Property, plant and equipment | 263,194 |
Other assets, net | 273 |
Total assets acquired | 276,288 |
Accounts payable | 7,760 |
Accrued liabilities | 2,910 |
Total current liabilities | 10,670 |
Asset retirement obligation and other | 8,169 |
Total liabilities assumed | 18,839 |
Historical carrying value of net assets acquired | $257,449 |
Acquisitions_Titan_Acquisition
Acquisitions (Titan Acquisition) (Narrative) (Details) (USD $) | 2 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | |
In Millions, except Share data, unless otherwise specified | Dec. 31, 2012 | Dec. 31, 2014 | Jul. 31, 2012 | Jul. 25, 2012 | Dec. 31, 2012 |
Business Acquisition [Line Items] | |||||
Business Acquisition, Date of Acquisition Agreement | 1-Apr-12 | ||||
Partners unit, issued | 7,898,210 | 0 | |||
Titan Operating, L.L.C | |||||
Business Acquisition [Line Items] | |||||
Business Acquisition, Cost of Acquired Entity, Equity Interests Issued and Issuable | $193.20 | ||||
Cash Consideration | 15.4 | ||||
Atlas Resource Partners, L.P. | Titan Operating, L.L.C | |||||
Business Acquisition [Line Items] | |||||
Business Acquisition, Date of Acquisition Agreement | 25-Jul-12 | ||||
Business Acquisition, Name of Acquired Entity | Titan Operating, L.L.C. | ||||
Business Acquisition, Cost of Acquired Entity, Equity Interests Issued and Issuable | 193.2 | ||||
Cash Consideration | 15.4 | ||||
Business Acquisition, Purchase Price Allocation, Methodology | ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). | ||||
Business Acquisition, Cost of Acquired Entity, Transaction Costs | 3.5 | 3.5 | |||
Atlas Resource Partners, L.P. | Titan Operating, L.L.C | Common Units | |||||
Business Acquisition [Line Items] | |||||
Partners unit, issued | 3.8 | 3.8 | |||
Atlas Resource Partners, L.P. | Titan Operating, L.L.C | Preferred Class B | |||||
Business Acquisition [Line Items] | |||||
Partners unit, issued | 3.8 | 3.8 |
Acquisitions_Titan_Acquisition1
Acquisitions (Titan Acquisition Schedule of Assets Acquired and Liabilities Assumed) (Details) (Titan Operating, L.L.C, USD $) | Jul. 25, 2012 |
Titan Operating, L.L.C | |
Business Acquisition [Line Items] | |
Cash and cash equivalents | $372,000 |
Accounts receivable | 5,253,000 |
Prepaid expenses and other | 131,000 |
Total current assets | 5,756,000 |
Property, plant and equipment | 208,491,000 |
Other assets, net | 2,344,000 |
Total assets acquired | 216,591,000 |
Accounts payable | 676,000 |
Revenue distribution payable | 3,091,000 |
Accrued liabilities | 1,816,000 |
Total current liabilities | 5,583,000 |
Asset retirement obligation | 2,418,000 |
Total liabilities assumed | 8,001,000 |
Historical carrying value of net assets acquired | $208,590,000 |
Acquisitions_Carrizo_Acquisiti
Acquisitions (Carrizo Acquisition) (Narrative) (Details) (USD $) | 2 Months Ended | 12 Months Ended | 1 Months Ended | |
In Millions, except Share data, unless otherwise specified | Dec. 31, 2012 | Dec. 31, 2014 | Apr. 30, 2012 | Dec. 20, 2012 |
Business Acquisition [Line Items] | ||||
Business Acquisition, Date of Acquisition Agreement | 1-Apr-12 | |||
Net proceeds from issuance of common limited partner units | $174.50 | |||
Partners unit, issued | 7,898,210 | 0 | ||
Subsidiary or Equity Method Investee, Price-Per-Share | $23.01 | |||
Carrizo Oil and Gas, Inc. | ||||
Business Acquisition [Line Items] | ||||
Business Acquisition, Date of Acquisition Agreement | 30-Apr-12 | |||
Net proceeds from issuance of common limited partner units | 119.5 | |||
Partners unit, issued | 6,000,000 | |||
Subsidiary or Equity Method Investee, Price-Per-Share | $20 | |||
Atlas Resource Partners, L.P. | Carrizo Oil and Gas, Inc. | ||||
Business Acquisition [Line Items] | ||||
Business Acquisition, Date of Acquisition Agreement | 30-Apr-12 | |||
Business Acquisition, Name of Acquired Entity | Carrizo Oil and Gas, Inc. | |||
Cash Consideration | 187 | |||
Net proceeds from issuance of common limited partner units | 119.5 | |||
Partners unit, issued | 6,000,000 | |||
Subsidiary or Equity Method Investee, Price-Per-Share | $20 | |||
Business Acquisition, Cost of Acquired Entity, Transaction Costs | 1.2 | |||
Business Acquisition, Purchase Price Allocation, Methodology | ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). | |||
Atlas Resource Partners, L.P. | Carrizo Oil and Gas, Inc. | Units Purchased By Executives Amount | ||||
Business Acquisition [Line Items] | ||||
Net proceeds from issuance of common limited partner units | $5 |
Acquisitions_Carrizo_Acquisiti1
Acquisitions (Carrizo Acquisition Schedule of Assets Acquired and Liabilities Assumed) (Details) (Carrizo Oil and Gas, Inc., USD $) | Apr. 30, 2012 |
In Thousands, unless otherwise specified | |
Carrizo Oil and Gas, Inc. | |
Business Acquisition [Line Items] | |
Property, plant and equipment | $190,946 |
Asset retirement obligation | 3,903 |
Historical carrying value of net assets acquired | $187,043 |
Acquisitions_TEAK_Acquisition_
Acquisitions (TEAK Acquisition) (Narrative) (Details) (USD $) | 1 Months Ended | 12 Months Ended | 0 Months Ended | ||
Apr. 30, 2012 | Dec. 31, 2014 | 10-May-13 | 7-May-13 | Dec. 31, 2013 | |
Business Acquisition [Line Items] | |||||
Business Acquisition, Date of Acquisition Agreement | 1-Apr-12 | ||||
Business Acquisition, Description of Acquired Entity | In April 2012, ARP acquired a 50% interest in approximately 14,500 net undeveloped acres in the oil and NGL area of the Mississippi Lime play in northwestern Oklahoma for $18.0 million from subsidiaries of Equal Energy, Ltd. (NYSE: EQU; TSX: EQU; “Equalâ€). The transaction was funded through borrowings under ARP’s revolving credit facility. Concurrent with the purchase of acreage, ARP and Equal entered into a participation and development agreement for future drilling in the Mississippi Lime play. ARP served as the drilling and completion operator, while Equal undertook production operations, including water disposal. In September 2012, ARP acquired Equal’s remaining 50% interest in the undeveloped acres, as well as approximately 8 MMcfed of net production in the Mississippi Lime region and salt water disposal infrastructure for $41.3 million, including $1.3 million related to certain post-closing adjustments. | ||||
Deferred Finance Costs, Noncurrent, Net | $86,692,000 | $86,617,000 | |||
Senior Notes Four Point Seven Five Percent | |||||
Business Acquisition [Line Items] | |||||
Debt Instrument, Interest Rate, Stated Percentage | 4.75% | ||||
Atlas Pipeline "APL" | Senior Notes Four Point Seven Five Percent | |||||
Business Acquisition [Line Items] | |||||
Debt Instrument, Face Amount | 400,000,000 | ||||
Debt Instrument, Interest Rate, Stated Percentage | 4.75% | 4.75% | 4.75% | ||
Debt Instrument, Maturity Date | 15-Nov-21 | ||||
Proceeds from Debt, Net of Issuance Costs | 391,200,000 | ||||
Atlas Pipeline "APL" | TEAK Acquisition | |||||
Business Acquisition [Line Items] | |||||
Business Acquisition, Date of Acquisition Agreement | 7-May-13 | ||||
Business Acquisition, Name of Acquired Entity | TEAK | ||||
Cash Consideration | 974,700,000 | ||||
Business Acquisition, Description of Acquired Entity | Through the TEAK Acquisition, APL acquired natural gas gathering and processing facilities in Texas, which included a 75% interest in T2 LaSalle Gathering Company L.L.C. (“T2 LaSalleâ€), a 50% interest in T2 Eagle Ford Gathering Company L.L.C. (“T2 Eagle Fordâ€), and a 50% interest in T2 EF Cogeneration Holdings L.L.C. (“T2 Co-Genâ€) (collectively, the “T2 Joint Venturesâ€). | ||||
Payments of Stock Issuance Costs | 16,600,000 | ||||
Business Acquisition, Purchase Price Allocation, Methodology | APL accounted for this transaction under the acquisition method of accounting. Accordingly, APL evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). | ||||
Deferred Finance Costs, Noncurrent, Net | 9,700,000 | ||||
Atlas Pipeline "APL" | TEAK Acquisition | A P L4750 Senior Notes | |||||
Business Acquisition [Line Items] | |||||
Debt Instrument, Face Amount | 400,000,000 | ||||
Debt Instrument, Interest Rate, Stated Percentage | 4.75% | ||||
Debt Instrument, Maturity Date | 15-Nov-21 | ||||
Proceeds from Debt, Net of Issuance Costs | $391,200,000 |
Acquisitions_TEAK_Acquisition_1
Acquisitions (TEAK Acquisition Final Values Assigned to Assets Acquired and Liabilities Assumed ) (Details) (Atlas Pipeline "APL", USD $) | Dec. 31, 2014 | 7-May-13 |
Business Acquisition [Line Items] | ||
Cash | $1.26 | |
TEAK Acquisition | ||
Business Acquisition [Line Items] | ||
Cash | 8,074,000 | |
Accounts receivable | 11,055,000 | |
Prepaid expenses and other | 1,626,000 | |
Total current assets | 20,755,000 | |
Property, plant and equipment | 197,683,000 | |
Intangible assets | 430,000,000 | |
Goodwill | 186,050,000 | |
Equity method investment in joint ventures | 184,327,000 | |
Total assets acquired | 1,018,815,000 | |
Accounts payable and accrued liabilities | 34,995,000 | |
Other long term liabilities | 1,075,000 | |
Total liabilities assumed | 36,070,000 | |
Historical carrying value of net assets acquired | 982,745,000 | |
Less cash received | -8,074,000 | |
Net cash paid for acquisition | $974,671,000 |
Acquisitions_Cardinal_Acquisit
Acquisitions (Cardinal Acquisition) (Narrative) (Details) (USD $) | 1 Months Ended | 2 Months Ended | 12 Months Ended | 0 Months Ended | 1 Months Ended | |
In Millions, except Share data, unless otherwise specified | Apr. 30, 2012 | Dec. 31, 2012 | Dec. 31, 2014 | Dec. 20, 2012 | Dec. 20, 2012 | Dec. 31, 2012 |
Business Acquisition [Line Items] | ||||||
Business Acquisition, Date of Acquisition Agreement | 1-Apr-12 | |||||
Business Acquisition, Description of Acquired Entity | In April 2012, ARP acquired a 50% interest in approximately 14,500 net undeveloped acres in the oil and NGL area of the Mississippi Lime play in northwestern Oklahoma for $18.0 million from subsidiaries of Equal Energy, Ltd. (NYSE: EQU; TSX: EQU; “Equalâ€). The transaction was funded through borrowings under ARP’s revolving credit facility. Concurrent with the purchase of acreage, ARP and Equal entered into a participation and development agreement for future drilling in the Mississippi Lime play. ARP served as the drilling and completion operator, while Equal undertook production operations, including water disposal. In September 2012, ARP acquired Equal’s remaining 50% interest in the undeveloped acres, as well as approximately 8 MMcfed of net production in the Mississippi Lime region and salt water disposal infrastructure for $41.3 million, including $1.3 million related to certain post-closing adjustments. | |||||
Business Acquisition, Percentage of Voting Interests Acquired | 50.00% | |||||
Partners unit, issued | 7,898,210 | 0 | ||||
Subsidiary or Equity Method Investee, Price-Per-Share | $23.01 | $23.01 | ||||
Net proceeds from issuance of common limited partner units | $174.50 | |||||
Atlas Pipeline "APL" | Cardinal Acquisition | ||||||
Business Acquisition [Line Items] | ||||||
Business Acquisition, Date of Acquisition Agreement | 20-Dec-12 | |||||
Cash Consideration | 598.9 | |||||
Business Acquisition, Description of Acquired Entity | The assets from this acquisition (the “APL Arkoma assetsâ€) include gas gathering, processing and treating facilities in Arkansas, Louisiana, Oklahoma and Texas | |||||
Business Acquisition, Percentage of Voting Interests Acquired | 40.00% | 40.00% | ||||
Proceeds from Debt, Net of Issuance Costs | 176.5 | |||||
Partners unit, issued | 10,507,033 | |||||
Subsidiary or Equity Method Investee, Price-Per-Share | $31 | $31 | ||||
Net proceeds from issuance of common limited partner units | 6.7 | |||||
General partner ownership interest | 2.00% | |||||
Atlas Pipeline "APL" | Cardinal Acquisition | Senior Notes Eight Point Seven Five Percentage | ||||||
Business Acquisition [Line Items] | ||||||
Debt Instrument, Face Amount | 175 | 175 | ||||
Debt Instrument, Interest Rate, Stated Percentage | 6.63% | 6.63% | ||||
Debt Instrument, Maturity Date | 1-Oct-20 | |||||
Debt Instrument, Premium | 3.00% | 3.00% | ||||
Atlas Pipeline "APL" | Cardinal Acquisition | General Partner | ||||||
Business Acquisition [Line Items] | ||||||
Business Acquisition, Percentage of Voting Interests Acquired | 60.00% | 60.00% | ||||
Net proceeds from issuance of common limited partner units | $319.30 | |||||
Atlas Pipeline "APL" | Cardinal Acquisition | Mark West Non Controlling Interest | ||||||
Business Acquisition [Line Items] | ||||||
Business Acquisition, Name of Acquired Entity | Cardinal | |||||
Business Acquisition, Percentage of Voting Interests Acquired | 40.00% | 40.00% |
Acquisitions_Cardinal_Acquisit1
Acquisitions (Cardinal Acquisition Schedule of Assets Acquired and Liabilities Assumed) (Details) (Atlas Pipeline "APL", Cardinal Acquisition, Adjusted, USD $) | Dec. 20, 2012 |
Atlas Pipeline "APL" | Cardinal Acquisition | Adjusted | |
Business Acquisition [Line Items] | |
Cash | $1,184,000 |
Accounts receivable | 13,783,000 |
Prepaid expenses and other | 1,289,000 |
Property, plant and equipment | 246,787,000 |
Intangible assets | 232,740,000 |
Goodwill | 214,090,000 |
Total assets acquired | 709,873,000 |
Current portion of long-term debt | 341,000 |
Accounts payable and accrued liabilities | 14,596,000 |
Deferred tax liability, net | 35,353,000 |
Asset retirement obligation and other | 604,000 |
Total liabilities acquired | 50,894,000 |
Non-controlling interest | 58,905,000 |
Historical carrying value of net assets acquired | 600,074,000 |
Less cash received | -1,184,000 |
Net cash paid for acquisition | $598,890,000 |
Acquisitions_Cardinal_Acquisit2
Acquisitions (Cardinal Acquisition Schedule of Assets Acquired and Liabilities Assumed) (Narrative) (Details) | Apr. 30, 2012 | Dec. 20, 2012 |
Business Acquisition [Line Items] | ||
Business Acquisition, Percentage of Voting Interests Acquired | 50.00% | |
Atlas Pipeline "APL" | Cardinal Acquisition | ||
Business Acquisition [Line Items] | ||
Business Acquisition, Percentage of Voting Interests Acquired | 40.00% | |
Atlas Pipeline "APL" | Cardinal Acquisition | General Partner | ||
Business Acquisition [Line Items] | ||
Business Acquisition, Percentage of Voting Interests Acquired | 60.00% | |
Mark West Non Controlling Interest | Atlas Pipeline "APL" | Cardinal Acquisition | ||
Business Acquisition [Line Items] | ||
Business Acquisition, Percentage of Voting Interests Acquired | 40.00% | |
Adjustment for lack of control that market participants would consider when measuring its fair value | 5.00% |
Acquisitions_Pro_Forma_Financi
Acquisitions (Pro Forma Financial Information) (Narrative) (Details) | 12 Months Ended |
Dec. 31, 2014 | |
Business Combinations [Abstract] | |
Business Acquisition, Pro Forma Information, Description | The following data presents pro forma revenues, net loss and basic and diluted net loss per unit for the Partnership as if the Rangely, EP Energy and TEAK acquisitions, including the related borrowings, net proceeds from the issuances of debt and issuances of common and preferred limited partner units had occurred on January 1, 2013. The Partnership prepared these pro forma unaudited financial results for comparative purposes only; they may not be indicative of the results that would have occurred if the Rangely, EP Energy and TEAK acquisitions and related offerings had occurred on January 1, 2013 or the results that will be attained in future periods |
Acquisitions_TEAK_Acquisition_2
Acquisitions (TEAK Acquisition Pro Forma Information) (Details) (Atlas Pipeline "APL", TEAK Acquisition, USD $) | 12 Months Ended | |
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Atlas Pipeline "APL" | TEAK Acquisition | ||
Business Acquisition [Line Items] | ||
Total revenues and other | $3,714,704 | $2,793,098 |
Net loss | -427,351 | -141,776 |
Net loss attributable to common limited partners | ($181,455) | ($51,653) |
Net loss attributable to common limited partners per unit: Basic and diluted | ($3.50) | ($1.01) |
Acquisitions_Other_Acquisition
Acquisitions (Other Acquisition) (Narrative) (Details) (USD $) | 1 Months Ended | 12 Months Ended | 0 Months Ended | 1 Months Ended | |||||
Apr. 30, 2012 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Nov. 05, 2014 | 12-May-14 | Sep. 20, 2013 | Jul. 31, 2013 | Sep. 30, 2012 | |
acre | Mcf | ||||||||
Business Acquisition [Line Items] | |||||||||
Business Acquisition, Date of Acquisition Agreement | 1-Apr-12 | ||||||||
Gains on mark to market derivatives | $131,064,000 | ($28,764,000) | $31,940,000 | ||||||
Business Acquisition, Description of Acquired Entity | In April 2012, ARP acquired a 50% interest in approximately 14,500 net undeveloped acres in the oil and NGL area of the Mississippi Lime play in northwestern Oklahoma for $18.0 million from subsidiaries of Equal Energy, Ltd. (NYSE: EQU; TSX: EQU; “Equalâ€). The transaction was funded through borrowings under ARP’s revolving credit facility. Concurrent with the purchase of acreage, ARP and Equal entered into a participation and development agreement for future drilling in the Mississippi Lime play. ARP served as the drilling and completion operator, while Equal undertook production operations, including water disposal. In September 2012, ARP acquired Equal’s remaining 50% interest in the undeveloped acres, as well as approximately 8 MMcfed of net production in the Mississippi Lime region and salt water disposal infrastructure for $41.3 million, including $1.3 million related to certain post-closing adjustments. | ||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 50.00% | ||||||||
Number Of Net Undeveloped Acres Acquired | 14,500 | ||||||||
Eagle Ford Acquisition | |||||||||
Business Acquisition [Line Items] | |||||||||
Business Acquisition, Date of Acquisition Agreement | 5-Nov-14 | ||||||||
Cash Consideration | 179,500,000 | ||||||||
Deferred portion of purchase price | 140,000,000 | ||||||||
Dividend percentage | 8.63% | ||||||||
Business Acquisition, Effective Date of Acquisition | 1-Jul-14 | ||||||||
Gains on mark to market derivatives | 2,800,000 | ||||||||
Eagle Ford Acquisition | Atlas Resource Partners, L.P. | |||||||||
Business Acquisition [Line Items] | |||||||||
Deferred portion of purchase price | 24,000,000 | ||||||||
Deferred portion of purchase price payable in quarterly installments, beginning date | 31-Mar-15 | ||||||||
Increase in borrowing base under revolving credit facility | 900,000,000 | ||||||||
Eagle Ford Acquisition | Atlas Resource Partners, L.P. | Class D Preferred Units | |||||||||
Business Acquisition [Line Items] | |||||||||
Business Acquisition, Cost of Acquired Entity, Equity Interests Issued and Issuable | 20,000,000 | ||||||||
Public offer price per share | $25 | ||||||||
Eagle Ford Acquisition | Development Subsidiary | |||||||||
Business Acquisition [Line Items] | |||||||||
Deferred portion of purchase price | 116,000,000 | ||||||||
GeoMet Acquisition | |||||||||
Business Acquisition [Line Items] | |||||||||
Cash Consideration | 97,900,000 | ||||||||
Business Acquisition, Effective Date of Acquisition | 1-Jan-14 | ||||||||
Business Acquisition, Description of Acquired Entity | The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia. | ||||||||
Norwood Natural Resources | |||||||||
Business Acquisition [Line Items] | |||||||||
Cash Consideration | 5,400,000 | ||||||||
Business Acquisition, Effective Date of Acquisition | 1-Jun-13 | ||||||||
Business Acquisition, Description of Acquired Entity | The assets acquired included Norwood’s non-operating working interest in certain producing wells in the Barnett Shale | ||||||||
Arkoma Acquisition | |||||||||
Business Acquisition [Line Items] | |||||||||
Business Acquisition, Effective Date of Acquisition | 1-May-13 | ||||||||
Historical carrying value of net assets acquired | 64,500,000 | ||||||||
Equal Energy Ltd | |||||||||
Business Acquisition [Line Items] | |||||||||
Cash Consideration | 18,000,000 | ||||||||
Equal Energy Ltd Additional Acquisition | |||||||||
Business Acquisition [Line Items] | |||||||||
Business Acquisition, Date of Acquisition Agreement | 1-Sep-12 | ||||||||
Cash Consideration | 41,300,000 | ||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 50.00% | ||||||||
Net Production Acquired, Mcf | 8,000 | ||||||||
Business Acquisition, Post-Closing Adjustments | $1,300,000 |
APL_Equity_Method_Investments_1
APL Equity Method Investments (West Texas LPG Pipeline) (Narrative) (Details) (USD $) | 0 Months Ended | 12 Months Ended |
In Millions, unless otherwise specified | 14-May-14 | Dec. 31, 2014 |
Subsidiary | ||
Schedule Of Equity Method Investments [Line Items] | ||
Sale of subsidiaries | 2 | |
Equity Method Investment Ownership Percentage | 100.00% | |
Sale of Interest, Cash | $131 | |
Gain (loss) on disposition of assets | $47.80 | |
Atlas Pipeline "APL" | ||
Schedule Of Equity Method Investments [Line Items] | ||
Equity Method Investment Ownership Percentage | 20.00% |
APL_Equity_Method_Investments_2
APL Equity Method Investments (Joint Ventures) (Narrative) (Details) | 14-May-14 | Dec. 31, 2014 |
Schedule Of Equity Method Investments [Line Items] | ||
Equity Method Investment Ownership Percentage | 100.00% | |
Equity Method Investment T2 Joint Ventures | ||
Schedule Of Equity Method Investments [Line Items] | ||
Equity Method Investment Ownership Percentage | 50.00% |
APL_Equity_Method_Investments_3
APL Equity Method Investments (Schedule of Equity Method Investments Tables) (Details) (Atlas Pipeline "APL", USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Schedule Of Equity Method Investments [Line Items] | |||
Equity method investment in joint ventures | $177,212 | $248,301 | |
Equity income (loss) in joint ventures | -14,007 | -4,736 | 6,323 |
Equity Method Investment in West Texas LPG Pipeline L.P. | |||
Schedule Of Equity Method Investments [Line Items] | |||
Equity method investment in joint ventures | 85,790 | ||
Equity income (loss) in joint ventures | 2,611 | 4,988 | 6,323 |
Equity Method Investment in T2 LaSalle | |||
Schedule Of Equity Method Investments [Line Items] | |||
Equity method investment in joint ventures | 55,911 | 50,534 | |
Equity income (loss) in joint ventures | -4,271 | -3,127 | |
Equity Method Investment in T2 Eagle Ford | |||
Schedule Of Equity Method Investments [Line Items] | |||
Equity method investment in joint ventures | 109,517 | 97,437 | |
Equity income (loss) in joint ventures | -8,754 | -4,408 | |
Equity Method Investment in T2 EF C0-Gen | |||
Schedule Of Equity Method Investments [Line Items] | |||
Equity method investment in joint ventures | 11,784 | 14,540 | |
Equity income (loss) in joint ventures | ($3,593) | ($2,189) |
Property_Plant_and_Equipment_S
Property, Plant and Equipment (Summary of Property, Plant and Equipment) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Property Plant And Equipment [Abstract] | ||
Proved properties: Leasehold interests | $535,893 | $322,217 |
Proved Properties: Pre-development costs | 7,378 | 4,367 |
Proved Properties: Wells and related equipment | 3,096,562 | 2,231,213 |
Total proved properties | 3,639,833 | 2,557,797 |
Unproved properties | 217,321 | 211,851 |
Support equipment | 37,359 | 23,258 |
Total natural gas and oil properties | 3,894,513 | 2,792,906 |
Pipelines, processing and compression facilities | 3,576,551 | 2,926,134 |
Rights of way | 209,140 | 203,966 |
Land, buildings and improvements | 19,607 | 30,216 |
Other | 47,846 | 36,752 |
Total gross property, plant and equipment | 7,747,657 | 5,989,974 |
Less – accumulated depreciation, depletion and amortization | -2,078,395 | -1,079,099 |
Property, plant and equipment, Net, Total | $5,669,262 | $4,910,875 |
Property_Plant_and_Equipment_U
Property, Plant and Equipment (Useful Life Narrative) (Details) | 12 Months Ended |
Dec. 31, 2014 | |
Pipelines, processing and compression facilities | Minimum | |
Property Plant And Equipment [Line Items] | |
Property, Plant And Equipment Useful Life | 2 years |
Pipelines, processing and compression facilities | Maximum | |
Property Plant And Equipment [Line Items] | |
Property, Plant And Equipment Useful Life | 40 years |
Rights of way | Minimum | |
Property Plant And Equipment [Line Items] | |
Property, Plant And Equipment Useful Life | 20 years |
Rights of way | Maximum | |
Property Plant And Equipment [Line Items] | |
Property, Plant And Equipment Useful Life | 40 years |
Land, buildings and improvements | Minimum | |
Property Plant And Equipment [Line Items] | |
Property, Plant And Equipment Useful Life | 3 years |
Land, buildings and improvements | Maximum | |
Property Plant And Equipment [Line Items] | |
Property, Plant And Equipment Useful Life | 40 years |
Other | Minimum | |
Property Plant And Equipment [Line Items] | |
Property, Plant And Equipment Useful Life | 3 years |
Other | Maximum | |
Property Plant And Equipment [Line Items] | |
Property, Plant And Equipment Useful Life | 10 years |
Property_Plant_and_Equipment_N
Property, Plant and Equipment (Narrative) (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Property Plant And Equipment [Line Items] | |||
Gain (loss) on asset sales and disposal | $45,522,000 | ($2,506,000) | ($6,980,000) |
Asset impairment | 580,654,000 | 81,880,000 | 9,507,000 |
Future Hedge Gains | 82,300,000 | ||
Non-cash property, plant and equipment additions | 39,700,000 | 8,700,000 | |
Atlas Resource Partners, L.P. | |||
Property Plant And Equipment [Line Items] | |||
Gain (loss) on asset sales and disposal | 1,000,000 | ||
Asset impairment | 562,600,000 | 38,000,000 | 9,507,000 |
Atlas Pipeline "APL" | |||
Property Plant And Equipment [Line Items] | |||
Gain (loss) on asset sales and disposal | $1,500,000 |
Other_Assets_Summary_of_Other_
Other Assets (Summary of Other Assets) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Other Assets [Line Items] | ||
Deferred financing costs, net of accumulated amortization of $62,008 and $43,702 at December 31, 2014 and 2013, respectively | $86,692 | $86,617 |
Rabbi trust | 3,925 | 3,705 |
Security deposits | 2,467 | 5,631 |
Other | 9,848 | 3,287 |
Total Other Assets | 127,921 | 124,672 |
Atlas Resource Partners, L.P. | ||
Other Assets [Line Items] | ||
ARP notes receivable | 3,866 | 3,978 |
Lightfoot | ||
Other Assets [Line Items] | ||
Investment in Lightfoot | $21,123 | $21,454 |
Other_Assets_Narrative_Details
Other Assets (Narrative) (Details) (USD $) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | 14-May-14 | |
Other Assets [Line Items] | ||||
Accumulated amortization | $62,008,000 | $43,702,000 | ||
Amortization of financing costs | 17,700,000 | 14,400,000 | 6,700,000 | |
Equity Method Investment Ownership Percentage | 100.00% | |||
Distributions received from unconsolidated companies | 6,959,000 | 8,422,000 | 8,131,000 | |
Lightfoot LP | ||||
Other Assets [Line Items] | ||||
Equity Method Investment Ownership Percentage | 12.00% | |||
Distributions received from unconsolidated companies | 1,700,000 | 1,000,000 | 900,000 | |
Lightfoot GP | ||||
Other Assets [Line Items] | ||||
Equity Method Investment Ownership Percentage | 15.90% | |||
Lightfoot | ||||
Other Assets [Line Items] | ||||
Equity income (loss) in joint ventures | 1,100,000 | 2,600,000 | 1,500,000 | |
Atlas Pipeline "APL" | ||||
Other Assets [Line Items] | ||||
Accelerated amortization of deferred financing costs | 0 | 5,300,000 | 0 | |
Atlas Pipeline "APL" | Apl 8.75 Senior Notes | ||||
Other Assets [Line Items] | ||||
Senior Notes Retirement Percent | 8.75% | |||
Atlas Resource Partners, L.P. | ||||
Other Assets [Line Items] | ||||
Accelerated amortization of deferred financing costs | 600,000 | 3,200,000 | 0 | |
Allowance for credit loss | 0 | 0 | ||
Atlas Resource Partners, L.P. | Notes Receivable | ||||
Other Assets [Line Items] | ||||
Senior notes, maturity date | 31-Mar-22 | |||
Note Agreement Interest Rate Per Annum | 2.25% | |||
Other Interest and Dividend Income | $100,000 | $100,000 | $0 | |
Atlas Resource Partners, L.P. | Note Agreement, Option to Extend Maturity Date | ||||
Other Assets [Line Items] | ||||
Senior notes, maturity date | 31-Mar-27 | |||
Note Agreement Extension Fee Percent | 1.00% |
Asset_Retirement_Obligations_R
Asset Retirement Obligations (Reconciliation of Liability for Well Plugging and Abandonment Costs) (Narrative) (Details) (USD $) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Asset Retirement Obligations [Line Items] | ||||
Asset retirement obligations | $108,101,000 | $91,214,000 | $64,794,000 | $45,779,000 |
Limited Partner Interest | Series of Individually Immaterial Business Acquisitions | ||||
Asset Retirement Obligations [Line Items] | ||||
Oil and gas reclamation liabilities noncurrent | 100,000 | 1,300,000 | 0 | |
Relationship With Drilling Partnerships | ||||
Asset Retirement Obligations [Line Items] | ||||
Limited partner distributions withheld related to the asset retirement obligations of certain Drilling Partnerships | 1,600,000 | |||
Relationship With Drilling Partnerships | Limited Partner Interest | ||||
Asset Retirement Obligations [Line Items] | ||||
Asset retirement obligations | 47,600,000 | |||
Atlas Resource Partners, L.P. | Series of Individually Immaterial Business Acquisitions | ||||
Asset Retirement Obligations [Line Items] | ||||
Oil and gas reclamation liabilities noncurrent | $7,000,000 | $16,700,000 | $15,600,000 |
Asset_Retirement_Obligations_R1
Asset Retirement Obligations (Reconciliation of Liability for Well Plugging and Abandonment Costs) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Asset Retirement Obligation Roll Forward Analysis Roll Forward | |||
Asset retirement obligations, beginning of year | $91,214 | $64,794 | $45,779 |
Liabilities incurred | 10,674 | 23,129 | 16,568 |
Liabilities settled | -1,664 | -1,188 | -546 |
Accretion expense | 5,759 | 4,479 | 2,993 |
Revisions | 2,118 | ||
Asset retirement obligations, end of year | $108,101 | $91,214 | $64,794 |
Debt_Schedule_of_Total_Debt_Ou
Debt (Schedule of Total Debt Outstanding) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Jun. 02, 2014 | Jan. 23, 2013 | 10-May-13 |
In Thousands, unless otherwise specified | |||||
Debt Instrument [Line Items] | |||||
Total debt | $3,570,570 | $2,889,044 | |||
Less current maturities | -2,624 | -2,924 | |||
Total long-term debt | 3,567,946 | 2,886,120 | |||
9.25% Senior Notes | |||||
Debt Instrument [Line Items] | |||||
Debt Instrument, Interest Rate, Stated Percentage | 9.25% | ||||
Senior Notes Four Point Seven Five Percent | |||||
Debt Instrument [Line Items] | |||||
Debt Instrument, Interest Rate, Stated Percentage | 4.75% | ||||
ATLS | Term Loan | |||||
Debt Instrument [Line Items] | |||||
Term loan facility | 237,000 | 239,400 | |||
Atlas Resource Partners, L.P. | |||||
Debt Instrument [Line Items] | |||||
Revolving credit facility | 696,000 | 419,000 | |||
Atlas Resource Partners, L.P. | 7.75% Senior Notes | |||||
Debt Instrument [Line Items] | |||||
Senior Notes | 374,544 | 275,000 | |||
Debt Instrument, Interest Rate, Stated Percentage | 7.75% | 7.75% | 7.75% | 7.75% | |
Atlas Resource Partners, L.P. | 9.25% Senior Notes | |||||
Debt Instrument [Line Items] | |||||
Senior Notes | 323,916 | 248,334 | |||
Debt Instrument, Interest Rate, Stated Percentage | 9.25% | 9.25% | |||
Atlas Pipeline "APL" | |||||
Debt Instrument [Line Items] | |||||
Revolving credit facility | 385,000 | 152,000 | |||
Capital leases | 229 | 754 | |||
Atlas Pipeline "APL" | 6.625% Senior Notes | |||||
Debt Instrument [Line Items] | |||||
Senior Notes | 503,881 | 504,556 | |||
Debt Instrument, Interest Rate, Stated Percentage | 6.63% | 6.63% | |||
Atlas Pipeline "APL" | 5.875% Senior Notes | |||||
Debt Instrument [Line Items] | |||||
Senior Notes | 650,000 | 650,000 | |||
Debt Instrument, Interest Rate, Stated Percentage | 5.88% | 5.88% | |||
Atlas Pipeline "APL" | Senior Notes Four Point Seven Five Percent | |||||
Debt Instrument [Line Items] | |||||
Senior Notes | $400,000 | $400,000 | |||
Debt Instrument, Interest Rate, Stated Percentage | 4.75% | 4.75% | 4.75% |
Debt_Partnerships_Term_Loan_Fa
Debt (Partnership's Term Loan Facility) (Details) (ATLS Partnership, USD $) | 12 Months Ended | |
Dec. 31, 2014 | Jul. 31, 2013 | |
Arkoma Acquisition | ||
Debt Instrument [Line Items] | ||
Line of Credit Facility, Initiation Date | 31-Jul-13 | |
Secured Term Facility | ||
Debt Instrument [Line Items] | ||
Line of Credit Facility, Covenant Terms | The Term Facility contains customary covenants, similar to those in the Partnership’s credit facility, that limit the Partnership’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of the Partnership’s assets. The Term Facility also contains covenants that require the Partnership to maintain a ratio of Total Funded Debt (as defined in the Term Facility) to EBITDA (as defined in the Term Facility), calculated over a period of four consecutive fiscal quarters, of not greater than 4.5 to 1.0 as of the last day of each of the quarters ending on or before September 30, 2014; 4.0 to 1.0 as of the last day of each of the quarters ending on or before September 30, 2015; and 3.5 to 1.0 for the last day of each of the quarters thereafter. At December 31, 2014, the Partnership was in compliance with these covenants. The events which constitute events of default are also customary for credit facilities of this nature, including payment defaults, breaches of representations, warranties or covenants, defaults in the payment of other indebtedness over a specified threshold, insolvency and change of control. | |
Secured Term Facility | Arkoma Acquisition | ||
Debt Instrument [Line Items] | ||
Revolving Credit Facility | $240,000,000 | |
Line of Credit Facility, Expiration Date | 31-Jul-19 | |
Senior Notes Interest Payment Dates and Terms | Borrowings under the Term Facility bear interest, at the Partnership’s election at either an adjusted LIBOR rate plus an applicable margin of 5.50% per annum or the alternate base rate (as defined in the Term Facility) (“ABRâ€) plus an applicable margin of 4.50% per annum. Interest is generally payable quarterly for ABR loans and, for LIBOR loans at the interest periods selected by the Partnership. The Partnership is required to repay principal at the rate of $0.6 million per quarter commencing December 31, 2013 and continuing until the maturity date when the remaining balance is due. | |
Line of Credit Facility, Additional Margin Rates In Excess of LIBOR | 5.50% | |
Line of Credit Facility, Borrowing Base Additional Rate | 4.50% | |
Line of Credit Facility, principal repayment rate per quarter | $600,000 | |
Outstanding Term Facility, Weighted Average Interest Rate | 6.50% |
Debt_Partnerships_Revolving_Cr
Debt (Partnership's Revolving Credit Facility) (Details) (USD $) | 12 Months Ended |
Dec. 31, 2014 | |
Maximum | |
Debt Instrument [Line Items] | |
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.63% |
ATLS Partnership | Standby Letters of Credit | Arkoma Acquisition | |
Debt Instrument [Line Items] | |
Increase in borrowing base under revolving credit facility | 5,000,000 |
ATLS Partnership | Credit Facility | Arkoma Acquisition | |
Debt Instrument [Line Items] | |
Line of Credit Facility, Expiration Date | 31-Jul-18 |
Increase in borrowing base under revolving credit facility | 50,000,000 |
Line of Credit Facility, Interest Rate Description | At the Partnership’s election, interest on borrowings under the credit agreement is determined by reference to either an adjusted LIBOR rate plus an applicable margin of 5.50% per year or the ABR plus an applicable margin of 4.50% per year. Interest is generally payable quarterly for ABR loans and at the interest payment periods selected by the Partnership for LIBOR loans. |
ATLS | |
Debt Instrument [Line Items] | |
Line of Credit Facility, Additional Margin Rates In Excess of LIBOR | 5.50% |
Line of Credit Facility, Borrowing Base Additional Rate | 4.50% |
Line of Credit Facility, Interest Rate Description | Based on the definition in the Partnership’s Term Facility and credit facility, the Partnership’s ratio of Total Funded Debt to EBITDA was 2.0 to 1.0. |
Line of Credit Facility, Covenant Terms | The credit facility contains customary covenants that limit the Partnership’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of the Partnership’s assets. The credit facility also contains covenants the same as those in the Partnership’s Term Facility with respect to the required ratio of Total Funded Debt (as defined in the credit facility) to EBITDA (as defined in the credit facility). At December 31, 2014, the Partnership was in compliance with these covenants. |
Total Funded Debt to Ebitda Ratio | 2.00% |
ATLS | Minimum | |
Debt Instrument [Line Items] | |
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.50% |
Debt_Credit_Facility_Details
Debt (Credit Facility) (Details) (Revolving Credit Facility, USD $) | 6 Months Ended | 12 Months Ended | ||
Jun. 30, 2014 | Dec. 31, 2014 | Nov. 24, 2014 | Sep. 24, 2014 | |
Line Of Credit Facility [Line Items] | ||||
Line of Credit Facility, Current Borrowing Capacity | $825,000,000 | $900,000,000 | $900,000,000 | $825,000,000 |
Revolving Credit Facility | 1,500,000 | |||
Line of Credit Facility, Expiration Date | 1-Jul-18 | |||
Line of Credit Facility, Interest Rate Description | If the borrowing base utilization is less than 25%, ARP will incur the applicable margin on Eurodollar loans of 1.50%, the applicable margin on alternative base rate loans of 0.50% and a commitment fee rate of 0.375%; | at either an adjusted LIBOR rate plus an applicable margin between 1.50% and 2.75% per annum or the base rate (which is the higher of the bank’s prime rate, the Federal funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 0.50% and 1.75% per annum. ARP is also required to pay a fee on the unused portion of the borrowing base at a rate of 0.375% per annum if less than 50% of the borrowing base is utilized and 0.5% if 50% or more of the borrowing base is utilized, which is included within interest expense on the Partnership’s consolidated statements of operations. At December 31, 2014, the weighted average interest rate on outstanding borrowings under the credit facility was 2.9%. | ||
Required Total Funded Debt To EBITDA Ratio | 4.50% | |||
Revolving credit facility | 696,000,000 | |||
Letters Of Credit Outstanding Maximum | 20,000,000 | |||
Letters Of Credit Outstanding Amount | $4,400,000 | |||
Line Of Credit Facility Collateral | ARP’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by certain of ARP’s material subsidiaries, and any non-guarantor subsidiaries of ARP are minor. | |||
Line of Credit Facility, Weighted Average Interest Rate | 2.90% | |||
Line of Credit Facility, Covenant Terms | The ARP Credit Agreement contains customary covenants that limit ARP’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. ARP was in compliance with these covenants as of December 31, 2014. The ARP Credit Agreement also requires ARP to maintain a ratio of Total Funded Debt (as defined in the ARP Credit Agreement) to EBITDA (as defined in the ARP Credit Agreement) (actual or annualized, as applicable), calculated over a period of four consecutive fiscal quarters, of not greater than 4.50 to 1.0 as of the last day of the quarters ended on June 30, 2014, September 30, 2014 and December 31, 2014, 4.25 to 1.0 as of the last day of the quarter ending March 31, 2015, and 4.00 to 1.0 as of the last day of fiscal quarters ending thereafter, and a ratio of current assets (as defined in the ARP Credit Agreement) to current liabilities (as defined in the ARP Credit Agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter. | |||
Line of Credit Facility, Covenant Compliance | ARP was in compliance with these covenants as of December 31, 2014. | |||
Required Current Assets To Current Liabilities Ratio | 1.00% | |||
Total Funded Debt to Ebitda Ratio | 3.60% | |||
Current Assets To Current Liabilities Ratio | 1.20% | |||
Scenario One | ||||
Line Of Credit Facility [Line Items] | ||||
Percentage of borrowing base utilized | 25.00% | |||
Line of credit facility, commitment fee percentage | 0.38% | |||
Scenario One | Eurodollar | ||||
Line Of Credit Facility [Line Items] | ||||
Debt instrument, basis spread on variable rate | 1.50% | |||
Scenario One | Base Rate | ||||
Line Of Credit Facility [Line Items] | ||||
Debt instrument, basis spread on variable rate | 0.50% | |||
Quarter ended June 30, 2014 | ||||
Line Of Credit Facility [Line Items] | ||||
Required Total Funded Debt To EBITDA Ratio | 4.50% | 4.50% | ||
Quarter ended September 30, 2014 | ||||
Line Of Credit Facility [Line Items] | ||||
Required Total Funded Debt To EBITDA Ratio | 4.50% | 4.50% | ||
Quarter ended December 31, 2014 | ||||
Line Of Credit Facility [Line Items] | ||||
Required Total Funded Debt To EBITDA Ratio | 4.50% | 4.50% | ||
Quarter ended March 31, 2015 | ||||
Line Of Credit Facility [Line Items] | ||||
Required Total Funded Debt To EBITDA Ratio | 4.25% | 4.25% | ||
Fiscal quarters ending thereafter | ||||
Line Of Credit Facility [Line Items] | ||||
Required Total Funded Debt To EBITDA Ratio | 4.00% | 4.00% |
Debt_ARP_Senior_Notes_Details
Debt (ARP Senior Notes) (Details) (USD $) | 0 Months Ended | 12 Months Ended | 0 Months Ended | |||
Oct. 14, 2014 | Dec. 31, 2014 | Jun. 02, 2014 | Jan. 23, 2013 | Jul. 30, 2014 | Dec. 31, 2013 | |
Debt Instrument [Line Items] | ||||||
Debt Instrument, Unamortized Discount | $1,904,000 | |||||
Debt Instrument, Unamortized Premium | 4,245,000 | |||||
9.25% Senior Notes | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, issuance date | 14-Oct-14 | |||||
Debt Instrument, Face Amount | 75,000,000 | 323,900,000 | 250,000,000 | |||
Senior notes, maturity | 2021 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 9.25% | |||||
Offering price as a percentage of par value | 100.50% | |||||
Proceeds from Debt, Net of Issuance Costs | 73,600,000 | |||||
Debt Instrument, Unamortized Discount | 1,500,000 | |||||
Senior Notes Interest Payment Dates and Terms | Interest on the 9.25% ARP Senior Notes is payable semi-annually on February 15 and August 15 | |||||
Debt Instrument, Unamortized Premium | 400,000 | |||||
Debt Instrument, Call Feature | At any time on or after August 15, 2017, ARP may redeem some or all of the 9.25% ARP Senior Notes at a redemption price of 104.625%. On or after August 15, 2018, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 102.313% and on or after August 15, 2019, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 100.0%. In addition, at any time prior to August 15, 2016, ARP may redeem up to 35% of the 9.25% ARP Senior Notes with the proceeds received from certain equity offerings at a redemption price of 109.250%. Under certain conditions, including if ARP sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, ARP must offer to repurchase the 9.25% ARP Senior Notes. | |||||
9.25% Senior Notes | Maximum | ||||||
Debt Instrument [Line Items] | ||||||
Completion of exchange offer period | 270 days | |||||
Atlas Resource Partners, L.P. | 7.75% Senior Notes | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, issuance date | 2-Jun-14 | 23-Jan-13 | ||||
Debt Instrument, Face Amount | 374,500,000 | 100,000,000 | 275,000,000 | |||
Senior notes, maturity | 2021 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 7.75% | 7.75% | 7.75% | 7.75% | ||
Offering price as a percentage of par value | 99.50% | |||||
Proceeds from Debt, Net of Issuance Costs | 97,400,000 | |||||
Debt Instrument, Unamortized Discount | $500,000 | |||||
Senior Notes Interest Payment Dates and Terms | Interest on the 7.75% ARP Senior Notes is payable semi-annually on January 15 and July 15. | |||||
Repurchase, Make Whole and Redemption Terms And Description | At any time prior to January 15, 2016, the 7.75% ARP Senior Notes are redeemable for up to 35% of the outstanding principal amount with the net cash proceeds of equity offerings at the redemption price of 107.75%. The 7.75% ARP Senior Notes are also subject to repurchase at a price equal to 101% of the principal amount, plus accrued and unpaid interest, upon a change of control. At any time prior to January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price as defined in the governing indenture, plus accrued and unpaid interest and additional interest, if any. On and after January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price of 103.875%, decreasing to 101.938% on January 15, 2018 and 100% on January 15, 2019. | |||||
Atlas Resource Partners, L.P. | 7.75% Senior Notes | Maximum | ||||||
Debt Instrument [Line Items] | ||||||
Completion of exchange offer period | 270 days | 365 days | ||||
Atlas Resource Partners, L.P. | 9.25% Senior Notes | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 9.25% | 9.25% |
Debt_APL_Credit_Facility_Detai
Debt (APL Credit Facility) (Details) (USD $) | 12 Months Ended | 6 Months Ended | |
Dec. 31, 2014 | Jun. 30, 2014 | Dec. 31, 2013 | |
Atlas Pipeline "APL" | |||
Line Of Credit Facility [Line Items] | |||
Line of Credit Facility, Expiration Date | 28-Aug-19 | ||
Line of Credit Facility, Interest Rate Description | changed the per annum interest rate on borrowings to (i) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) the LIBOR rate plus 1.0%, or (ii) the LIBOR rate for the applicable period, in each case plus the applicable margin | ||
Revolving credit facility | $385,000,000 | $152,000,000 | |
Line Of Credit Facility Borrowing Base Reduction Rate | 0.25% | ||
Incremental Term Loan | |||
Line Of Credit Facility [Line Items] | |||
Increase in borrowing base under revolving credit facility | 1,050,000,000 | ||
Revolving Credit Facility | |||
Line Of Credit Facility [Line Items] | |||
Increase in borrowing base under revolving credit facility | 1,500,000 | ||
Line of Credit Facility, Expiration Date | 1-Jul-18 | ||
Line of Credit Facility, Interest Rate Description | at either an adjusted LIBOR rate plus an applicable margin between 1.50% and 2.75% per annum or the base rate (which is the higher of the bank’s prime rate, the Federal funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 0.50% and 1.75% per annum. ARP is also required to pay a fee on the unused portion of the borrowing base at a rate of 0.375% per annum if less than 50% of the borrowing base is utilized and 0.5% if 50% or more of the borrowing base is utilized, which is included within interest expense on the Partnership’s consolidated statements of operations. At December 31, 2014, the weighted average interest rate on outstanding borrowings under the credit facility was 2.9%. | If the borrowing base utilization is less than 25%, ARP will incur the applicable margin on Eurodollar loans of 1.50%, the applicable margin on alternative base rate loans of 0.50% and a commitment fee rate of 0.375%; | |
Revolving credit facility | 696,000,000 | ||
Line Of Credit Facility Collateral | ARP’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by certain of ARP’s material subsidiaries, and any non-guarantor subsidiaries of ARP are minor. | ||
Revolving Credit Facility | Atlas Pipeline "APL" | |||
Line Of Credit Facility [Line Items] | |||
Increase in borrowing base under revolving credit facility | 800,000,000 | ||
Line of Credit Facility, Expiration Date | 31-Dec-19 | ||
Line of Credit Facility, Interest Rate Description | Borrowings under the revolving credit facility bear interest, at APL’s option, at either (1) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) the LIBOR rate plus 1.0%, or (2) the LIBOR rate for the applicable period (each plus the applicable margin). | ||
Outstanding Term Facility, Weighted Average Interest Rate | 2.70% | ||
Line Of Credit Facility Collateral | Borrowings under the revolving credit facility are secured by (i) a lien on and security interest in all the Partnership’s property and that of its subsidiaries, except for the assets owned by Atlas Pipeline Mid-Continent WestOk, LLC (“WestOK LLCâ€) and Atlas Pipeline Mid-Continent WestTex, LLC (“WestTX LLCâ€), entities in which APL has 95% interests, and Centrahoma, in which APL has a 60% interest; and their respective subsidiaries; and (ii) by the guaranty of each of APL’s consolidated subsidiaries other than the joint venture companies | ||
Senior notes, Restrictive Covenants | The revolving credit facility contains customary covenants, including requirements that APL maintain certain financial thresholds and restrictions on APL’s ability to (1) incur additional indebtedness, (2) make certain acquisitions, loans or investments, (3) make distribution payments to its unitholders if an event of default exists, or (4) enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries, without approval of the lenders. APL is unable to borrow under its revolving credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings†pursuant to its partnership agreement. | ||
Line of credit facility, initial borrowing capacity | 600,000,000 | ||
Line of credit facility, initial increments in borrowing capacity | 200,000,000 | ||
Line of credit facility, increments in borrowing capacity | 250,000,000 | ||
Revolving Credit Facility | Letter of Credit | Atlas Pipeline "APL" | |||
Line Of Credit Facility [Line Items] | |||
Increase in borrowing base under revolving credit facility | 50,000,000 | ||
Line of Credit Facility, Remaining Borrowing Capacity | 410,800,000 | ||
Revolving credit facility | $4,200,000 |
Debt_APL_Senior_Notes_Issuance
Debt (APL Senior Notes Issuances) (Details) (USD $) | 12 Months Ended | 0 Months Ended | 1 Months Ended | 0 Months Ended | |||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Sep. 28, 2012 | Dec. 20, 2012 | Feb. 11, 2013 | 10-May-13 | Mar. 12, 2014 | Jan. 28, 2014 | |
Debt Instrument [Line Items] | |||||||||
Debt Instrument, Unamortized Premium | $4,245,000 | ||||||||
Cash paid on accrued interest on debt | 170,700,000 | 96,600,000 | 38,800,000 | ||||||
Loss on early extinguishment of debt | -26,601,000 | ||||||||
Senior Notes Additional | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt Instrument, Maturity Date | 1-Oct-20 | ||||||||
Debt Instrument, Unamortized Premium | 3,900,000 | ||||||||
Senior Notes Interest Payment Dates and Terms | Interest on the 6.625% APL Senior Notes is payable semi-annually in arrears on April 1 and October 1 | ||||||||
Debt Instrument, Face Amount | 325,000,000 | ||||||||
Proceeds from Debt, Net of Issuance Costs | 318,900,000 | ||||||||
Senior Notes Additional | Atlas Pipeline "APL" | |||||||||
Debt Instrument [Line Items] | |||||||||
Senior Notes | 500,000,000 | ||||||||
Debt Instrument, Interest Rate, Stated Percentage | 6.63% | ||||||||
A P L5875 Senior Notes | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt Instrument, Maturity Date | 1-Aug-23 | ||||||||
A P L5875 Senior Notes | Atlas Pipeline "APL" | |||||||||
Debt Instrument [Line Items] | |||||||||
Senior Notes | 650,000,000 | ||||||||
A P L4750 Senior Notes | |||||||||
Debt Instrument [Line Items] | |||||||||
Senior Notes | 400,000,000 | ||||||||
A P L4750 Senior Notes | Atlas Pipeline "APL" | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.75% | ||||||||
A P L Senior Notes | Atlas Pipeline "APL" | |||||||||
Debt Instrument [Line Items] | |||||||||
Senior Notes Repurchase Price | The APL Senior Notes are subject to repurchase by APL at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if APL does not reinvest the net proceeds within 360 days. The APL Senior Notes are junior in right of payment to APL’s secured debt, including APL’s obligations under its revolving credit facility. | ||||||||
Senior notes, Restrictive Covenants | Indentures governing the APL Senior Notes contain covenants, including limitations of APL’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all its assets, without consent. | ||||||||
Senior notes, Covenant Compliance | APL is in compliance with these covenants as of December 31, 2014. | ||||||||
6.625% Senior Notes | Atlas Pipeline "APL" | |||||||||
Debt Instrument [Line Items] | |||||||||
Senior Notes | 503,881,000 | 504,556,000 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 6.63% | 6.63% | |||||||
Debt Instrument, Face Amount | 175,000,000 | ||||||||
Proceeds from Debt, Net of Issuance Costs | 176,500,000 | 176,100,000 | |||||||
Premium on issuance of senior notes | 103.00% | ||||||||
Yield on senior notes issued | 6.00% | ||||||||
Debt issuance cost | 400,000 | ||||||||
5.875% Senior Notes | Atlas Pipeline "APL" | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.88% | ||||||||
Debt Instrument, Maturity Date | 1-Aug-23 | ||||||||
Senior Notes Interest Payment Dates and Terms | Interest on the 5.875% APL Senior Notes is payable semi-annually in arrears on February 1 and August 1. | ||||||||
Debt Instrument, Face Amount | 650,000,000 | ||||||||
Proceeds from Debt, Net of Issuance Costs | 637,300,000 | ||||||||
Debt instrument, redemption period, start date | 1-Feb-18 | ||||||||
Apl 8.75 Senior Notes | Atlas Pipeline "APL" | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt Instrument, Interest Rate, Stated Percentage | 8.75% | ||||||||
Senior Notes Four Point Seven Five Percent | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.75% | ||||||||
Senior Notes Four Point Seven Five Percent | Atlas Pipeline "APL" | |||||||||
Debt Instrument [Line Items] | |||||||||
Senior Notes | 400,000,000 | 400,000,000 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.75% | 4.75% | 4.75% | ||||||
Debt Instrument, Maturity Date | 15-Nov-21 | ||||||||
Senior Notes Interest Payment Dates and Terms | Interest on the 4.75% APL Senior Notes is payable semi-annually in arrears on May 15 and November 15. | ||||||||
Debt Instrument, Face Amount | 400,000,000 | ||||||||
Proceeds from Debt, Net of Issuance Costs | 391,200,000 | ||||||||
Debt instrument, redemption period, start date | 15-Mar-16 | ||||||||
Senior Notes Eight Point Seven Five Percentage | Atlas Pipeline "APL" | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt Instrument, Interest Rate, Stated Percentage | 8.75% | ||||||||
Debt Instrument, Unamortized Premium | 4,200,000 | ||||||||
Cash tender offer aggregate principal amount | 268,400,000 | ||||||||
Debt instrument, repurchase amount | 105,600,000 | 291,400,000 | |||||||
Premium paid on redeemed debt | 17,500,000 | 11,200,000 | |||||||
Cash paid on accrued interest on debt | 3,700,000 | ||||||||
Consent payment on debt repurchase | 8,000,000 | 8,000,000 | |||||||
Debt instrument repurchased face amount | 97,300,000 | ||||||||
Debt instrument redemption premium | 6,300,000 | ||||||||
Debt instrument redemption accrued interest | 2,000,000 | ||||||||
Loss on early extinguishment of debt | 26,600,000 | ||||||||
Accelerated amortization of deferred financing costs | $5,300,000 |
Debt_Aggregate_Amount_of_the_P
Debt (Aggregate Amount of the Partnership's, ARP's and APL's Debt Maturities Table) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Debt Disclosure [Abstract] | ||
2015 | $2,624 | |
2016 | 2,405 | |
2017 | 232,200 | |
2018 | 696,000 | |
2019 | 385,000 | |
Thereafter | 2,250,000 | |
Total principle maturities | 3,568,229 | |
Debt Instrument, Unamortized Premium | 4,245 | |
Unamortized discounts | -1,904 | |
Total debt | $3,570,570 | $2,889,000 |
Derivative_Instruments_Narrati
Derivative Instruments (Narrative) (Details) (USD $) | 12 Months Ended | 1 Months Ended | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Jun. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | |
Derivative Instruments Gain Loss [Line Items] | |||||
Cash Flow Hedges Derivative Assets at Fair Value, Net | $400,300,000 | $14,900,000 | |||
Net gain in accumulated other comprehensive income | 54,000,000 | ||||
Cash Flow Hedge Gain (Losses) to be Reclassified within Twelve Months | 27,200,000 | ||||
Cash Flow Hedge Gain (Loss) To Be Reclassified In Later Periods | 26,800,000 | ||||
Derivative Instruments, Gains Reclassified from Accumulated OCI into Income, Effective Portion | 2,500,000 | 3,900,000 | |||
Atlas Resource Partners, L.P. | |||||
Derivative Instruments Gain Loss [Line Items] | |||||
Premiums Paid On Swaption Contracts | 200,000 | ||||
Net Proceeds From Early Termination Of Natural Gas And Oil Derivative Positions | 3,900,000 | ||||
Net Unrealized Derivative Assets Payable To Limited Partners | 2,800,000 | 1,400,000 | |||
Carrizo Acquisition | Atlas Resource Partners, L.P. | |||||
Derivative Instruments Gain Loss [Line Items] | |||||
Amortization Expense On Swaption Contracts | 4,600,000 | ||||
Premiums Paid On Swaption Contracts | 4,600,000 | ||||
Gas And Oil Production Revenue | Atlas Resource Partners, L.P. | |||||
Derivative Instruments Gain Loss [Line Items] | |||||
Gains recognized on settled contracts covering commodity production | 9,700,000 | 19,300,000 | |||
Losses recognized on settled contracts covering commodity production | 7,100,000 | ||||
Gain (Loss) Recognized for Hedge Ineffectiveness or as a Result of Discontinuance of Cash Flow Hedges | 0 | 0 | 0 | ||
Gas And Oil Production Revenue | EP Energy Acquisition | |||||
Derivative Instruments Gain Loss [Line Items] | |||||
Amortization Expense On Swaption Contracts | 14,500,000 | ||||
Premiums Paid On Swaption Contracts | 14,500,000 | ||||
ATLS Partnership | EP Energy Acquisition | |||||
Derivative Instruments Gain Loss [Line Items] | |||||
Premiums Paid On Swaption Contracts | 2,300,000 | ||||
Amortization Expense On Swaption Contracts | 2,300,000 | ||||
ATLS Partnership | Gas And Oil Production Revenue | |||||
Derivative Instruments Gain Loss [Line Items] | |||||
Gains recognized on settled contracts covering commodity production | 700,000 | 500,000 | |||
Number of Derivative Contracts | 0 | ||||
Gain (Loss) Recognized for Hedge Ineffectiveness or as a Result of Discontinuance of Cash Flow Hedges | $0 | $0 |
Derivative_Instruments_Summary
Derivative Instruments (Summary of Gains or Losses Derivative Instruments Recognized In Statements of Operations) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Derivative Instruments Gain Loss [Line Items] | |||
(Gain) loss reclassified from accumulated other comprehensive income (loss) | $7,739 | ($10,216) | ($14,891) |
Gas And Oil Production Revenue | |||
Derivative Instruments Gain Loss [Line Items] | |||
(Gain) loss reclassified from accumulated other comprehensive income (loss) | 7,739 | -10,216 | -19,281 |
Gathering And Processing Revenue | |||
Derivative Instruments Gain Loss [Line Items] | |||
(Gain) loss reclassified from accumulated other comprehensive income (loss) | $4,390 |
Derivative_Instruments_Fair_Va
Derivative Instruments (Fair Values of the Partnership's Derivative Instruments Table) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | $404,659 | $52,565 |
Gross Amounts of Recognized Liabilities | -468 | -33,943 |
ATLS Partnership | Current portion of derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 2,893 | 24 |
Gross Amounts Offset in the Consolidated Balance Sheets | -23 | |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 2,893 | 1 |
Gross Amounts of Recognized Liabilities | -23 | |
Gross Amounts Offset in the Consolidated Balance Sheets | 23 | |
ATLS Partnership | Long-term portion of derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 2,669 | 1,547 |
Gross Amounts Offset in the Consolidated Balance Sheets | -33 | |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 2,669 | 1,514 |
Gross Amounts of Recognized Liabilities | -33 | |
Gross Amounts Offset in the Consolidated Balance Sheets | 33 | |
ATLS Partnership | Total derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 5,562 | 1,634 |
Gross Amounts Offset in the Consolidated Balance Sheets | -119 | |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 5,562 | 1,515 |
ATLS Partnership | Current portion of derivative liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 63 | |
Gross Amounts Offset in the Consolidated Balance Sheets | -63 | |
Gross Amounts of Recognized Liabilities | -96 | |
Gross Amounts Offset in the Consolidated Balance Sheets | 63 | |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | -33 | |
ATLS Partnership | Total derivative liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Liabilities | -152 | |
Gross Amounts Offset in the Consolidated Balance Sheets | 119 | |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | ($33) |
Derivative_Instruments_The_Par
Derivative Instruments (The Partnership's Commodity Derivative Instruments by Type Table) (Details) (ATLS Partnership, Natural Gas - Fixed Price Swaps, USD $) | Dec. 31, 2014 | |
In Thousands, unless otherwise specified | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset / (Liability) | $5,562 | [1] |
Production Period Ending December 31 2015 | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 2,280,000 | [2] |
Derivative, Swap Type, Average Fixed Price | 4.302 | [2] |
Fair Value Asset / (Liability) | 2,893 | [1] |
Production Period Ending December 31 2016 | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 1,440,000 | [2] |
Derivative, Swap Type, Average Fixed Price | 4.433 | [2] |
Fair Value Asset / (Liability) | 1,374 | [1] |
Production Period Ending December 31 2017 | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 1,200,000 | [2] |
Derivative, Swap Type, Average Fixed Price | 4.59 | [2] |
Fair Value Asset / (Liability) | 960 | [1] |
Production Period Ending December 31 2018 | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 420,000 | [2] |
Derivative, Swap Type, Average Fixed Price | 4.797 | [2] |
Fair Value Asset / (Liability) | $335 | [1] |
[1] | Fair value based on forward NYMEX natural gas prices, as applicable. | |
[2] | “MMBtu†represents million British Thermal Units. |
Derivative_Instruments_Fair_Va1
Derivative Instruments (Fair Value of ARP's Derivative Instruments Table) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | $404,659 | $52,565 |
Gross Amounts of Recognized Liabilities | -468 | -33,943 |
Atlas Resource Partners, L.P. | Current portion of derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 141,464 | 2,664 |
Gross Amounts Offset in the Consolidated Balance Sheets | -98 | -773 |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 141,366 | 1,891 |
Gross Amounts of Recognized Liabilities | -98 | -773 |
Gross Amounts Offset in the Consolidated Balance Sheets | 98 | 773 |
Atlas Resource Partners, L.P. | Long-term portion of derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 128,303 | 31,146 |
Gross Amounts Offset in the Consolidated Balance Sheets | -370 | -4,062 |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 127,933 | 27,084 |
Gross Amounts of Recognized Liabilities | -370 | -4,062 |
Gross Amounts Offset in the Consolidated Balance Sheets | 370 | 4,062 |
Atlas Resource Partners, L.P. | Total derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 269,767 | 38,273 |
Gross Amounts Offset in the Consolidated Balance Sheets | -468 | -9,298 |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 269,299 | 28,975 |
Atlas Resource Partners, L.P. | Current portion of derivative liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 4,341 | |
Gross Amounts Offset in the Consolidated Balance Sheets | -4,341 | |
Gross Amounts of Recognized Liabilities | -10,694 | |
Gross Amounts Offset in the Consolidated Balance Sheets | 4,341 | |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | -6,353 | |
Atlas Resource Partners, L.P. | Long-term portion of derivative liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 122 | |
Gross Amounts Offset in the Consolidated Balance Sheets | -122 | |
Gross Amounts of Recognized Liabilities | -189 | |
Gross Amounts Offset in the Consolidated Balance Sheets | 122 | |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | -67 | |
Atlas Resource Partners, L.P. | Total derivative liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Liabilities | -468 | -15,718 |
Gross Amounts Offset in the Consolidated Balance Sheets | 468 | 9,298 |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | ($6,420) |
Derivative_Instruments_ARPs_Co
Derivative Instruments (ARP's Commodity Derivative Instruments by Type Table) (Details) (Atlas Resource Partners, L.P., USD $) | Dec. 31, 2014 | |
In Thousands, unless otherwise specified | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset / (Liability) | $269,299 | [1] |
Natural Gas - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset / (Liability) | 139,724 | [2] |
Natural Gas - Costless Collars | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset / (Liability) | 4,419 | [2] |
Natural Gas - Put Options - Drilling Partnerships | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset / (Liability) | 2,767 | [2] |
Natural Gas - WAHA Basis Swaps | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset / (Liability) | 153 | [3] |
Natural Gas Liquids - Natural Gasoline Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset / (Liability) | 4,630 | [4] |
Natural Gas Liquids - Propane Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset / (Liability) | 4,011 | [5] |
Natural Gas Liquids - Butane Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset / (Liability) | 829 | [6] |
Natural Gas Liquids – Iso Butane Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset / (Liability) | 826 | [7] |
Natural Gas Liquids – Crude Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset / (Liability) | 2,835 | [1] |
Crude Oil - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset / (Liability) | 108,271 | [1] |
Crude Oil - Costless Collars | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset / (Liability) | 834 | [1] |
Production Period Ending December 31 2015 | Natural Gas - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 54,834,500 | [8] |
Derivative, Swap Type, Average Fixed Price | 4.226 | [8] |
Fair Value Asset / (Liability) | 65,393 | [2] |
Production Period Ending December 31 2015 | Natural Gas - Costless Collars | Puts Purchased | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 3,480,000 | [8] |
Fair Value Asset / (Liability) | 4,478 | [2] |
Average Floor and Cap | 4.234 | [8] |
Production Period Ending December 31 2015 | Natural Gas - Costless Collars | Calls Sold | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 3,480,000 | [8] |
Fair Value Asset / (Liability) | -59 | [2] |
Average Floor and Cap | 5.129 | [8] |
Production Period Ending December 31 2015 | Natural Gas - Put Options - Drilling Partnerships | Puts Purchased | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 1,440,000 | [8] |
Derivative, Swap Type, Average Fixed Price | 4 | [8] |
Fair Value Asset / (Liability) | 1,506 | [2] |
Production Period Ending December 31 2015 | Natural Gas - WAHA Basis Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 5,250,000 | [8] |
Derivative, Swap Type, Average Fixed Price | -0.082 | [8] |
Fair Value Asset / (Liability) | 153 | [3] |
Production Period Ending December 31 2015 | Natural Gas Liquids - Natural Gasoline Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 5,040,000 | [8] |
Derivative, Swap Type, Average Fixed Price | 1.983 | [8] |
Fair Value Asset / (Liability) | 4,630 | [4] |
Production Period Ending December 31 2015 | Natural Gas Liquids - Propane Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 8,064,000 | [8] |
Derivative, Swap Type, Average Fixed Price | 1.016 | [8] |
Fair Value Asset / (Liability) | 4,011 | [5] |
Production Period Ending December 31 2015 | Natural Gas Liquids - Butane Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 1,512,000 | [8] |
Derivative, Swap Type, Average Fixed Price | 1.248 | [8] |
Fair Value Asset / (Liability) | 829 | [6] |
Production Period Ending December 31 2015 | Natural Gas Liquids – Iso Butane Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 1,512,000 | [8] |
Derivative, Swap Type, Average Fixed Price | 1.263 | [8] |
Fair Value Asset / (Liability) | 826 | [7] |
Production Period Ending December 31 2015 | Crude Oil - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 1,743,000 | [8] |
Derivative, Swap Type, Average Fixed Price | 90.645 | [8] |
Fair Value Asset / (Liability) | 58,765 | [1] |
Production Period Ending December 31 2015 | Crude Oil - Costless Collars | Puts Purchased | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 29,250 | [8] |
Fair Value Asset / (Liability) | 842 | [1] |
Average Floor and Cap | 83.846 | [8] |
Production Period Ending December 31 2015 | Crude Oil - Costless Collars | Calls Sold | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 29,250 | [8] |
Fair Value Asset / (Liability) | -8 | [1] |
Average Floor and Cap | 110.654 | [8] |
Production Period Ending December 31 2016 | Natural Gas - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 53,546,300 | [8] |
Derivative, Swap Type, Average Fixed Price | 4.229 | [8] |
Fair Value Asset / (Liability) | 40,428 | [2] |
Production Period Ending December 31 2016 | Natural Gas - Put Options - Drilling Partnerships | Puts Purchased | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 1,440,000 | [8] |
Derivative, Swap Type, Average Fixed Price | 4.15 | [8] |
Fair Value Asset / (Liability) | 1,261 | [2] |
Production Period Ending December 31 2016 | Natural Gas Liquids – Crude Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 84,000 | [8] |
Derivative, Swap Type, Average Fixed Price | 85.651 | [8] |
Fair Value Asset / (Liability) | 1,851 | [1] |
Production Period Ending December 31 2016 | Crude Oil - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 1,209,000 | [8] |
Derivative, Swap Type, Average Fixed Price | 87.36 | [8] |
Fair Value Asset / (Liability) | 28,663 | [1] |
Production Period Ending December 31 2017 | Natural Gas - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 46,320,000 | [8] |
Derivative, Swap Type, Average Fixed Price | 4.276 | [8] |
Fair Value Asset / (Liability) | 22,999 | [2] |
Production Period Ending December 31 2017 | Natural Gas Liquids – Crude Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 60,000 | [8] |
Derivative, Swap Type, Average Fixed Price | 83.78 | [8] |
Fair Value Asset / (Liability) | 984 | [1] |
Production Period Ending December 31 2017 | Crude Oil - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 672,000 | [8] |
Derivative, Swap Type, Average Fixed Price | 85.669 | [8] |
Fair Value Asset / (Liability) | 12,248 | [1] |
Production Period Ending December 31 2018 | Natural Gas - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 35,760,000 | [8] |
Derivative, Swap Type, Average Fixed Price | 4.25 | [8] |
Fair Value Asset / (Liability) | 9,881 | [2] |
Production Period Ending December 31 2018 | Crude Oil - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 540,000 | [8] |
Derivative, Swap Type, Average Fixed Price | 85.466 | [8] |
Fair Value Asset / (Liability) | 8,595 | [1] |
Production Period Ending December 31 2019 | Natural Gas - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 9,720,000 | [8] |
Derivative, Swap Type, Average Fixed Price | 4.234 | [8] |
Fair Value Asset / (Liability) | $1,023 | [2] |
[1] | Fair value based on forward WTI crude oil prices, as applicable. | |
[2] | Fair value based on forward NYMEX natural gas prices, as applicable. | |
[3] | Fair value based on forward WAHA natural gas prices, as applicable | |
[4] | Fair value based on forward Mt. Belvieu natural gasoline prices, as applicable. | |
[5] | Fair value based on forward Mt. Belvieu propane prices, as applicable. | |
[6] | Fair value based on forward Mt. Belvieu butane prices, as applicable. | |
[7] | Fair value based on forward Mt. Belvieu iso butane prices, as applicable. | |
[8] | “MMBtu†represents million British Thermal Units; “Bbl†represents barrels; “Gal†represents gallons. |
Derivative_Instruments_APLs_Gr
Derivative Instruments (APL's Gross Fair Values of Derivative Instruments Table) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | $404,659 | $52,565 |
Gross Amounts of Recognized Liabilities | -468 | -33,943 |
Atlas Pipeline "APL" | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 88,007 | 4,547 |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 88,007 | |
Atlas Pipeline "APL" | Long-term portion of derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 37,398 | 5,082 |
Gross Amounts Offset in the Consolidated Balance Sheets | -2,812 | |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 37,398 | 2,270 |
Gross Amounts of Recognized Liabilities | -2,812 | |
Gross Amounts Offset in the Consolidated Balance Sheets | 2,812 | |
Atlas Pipeline "APL" | Total derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 125,405 | 8,953 |
Gross Amounts Offset in the Consolidated Balance Sheets | -6,509 | |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 125,405 | 2,444 |
Atlas Pipeline "APL" | Current portion of derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 1,310 | |
Gross Amounts Offset in the Consolidated Balance Sheets | -1,136 | |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 174 | |
Gross Amounts of Recognized Liabilities | -1,136 | |
Gross Amounts Offset in the Consolidated Balance Sheets | 1,136 | |
Atlas Pipeline "APL" | Current portion of derivative liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 1,612 | |
Gross Amounts Offset in the Consolidated Balance Sheets | -1,612 | |
Gross Amounts of Recognized Liabilities | -12,856 | |
Gross Amounts Offset in the Consolidated Balance Sheets | 1,612 | |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | -11,244 | |
Atlas Pipeline "APL" | Long-term portion of derivative liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 949 | |
Gross Amounts Offset in the Consolidated Balance Sheets | -949 | |
Gross Amounts of Recognized Liabilities | -1,269 | |
Gross Amounts Offset in the Consolidated Balance Sheets | 949 | |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | -320 | |
Atlas Pipeline "APL" | Total derivative liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Liabilities | -18,073 | |
Gross Amounts Offset in the Consolidated Balance Sheets | 6,509 | |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | ($11,564) |
Derivative_Instruments_APL_Com
Derivative Instruments (APL Commodity Derivative Instruments by Type Table) (Details) (Atlas Pipeline "APL", USD $) | Dec. 31, 2014 | |
In Thousands, unless otherwise specified | ||
Derivatives Fair Value [Line Items] | ||
APL’s net asset | $125,405 | [1] |
APL Fixed Price Swaps | Sold | ||
Derivatives Fair Value [Line Items] | ||
Total fixed price swaps | 115,278 | [1] |
APL Fixed Price Swaps | Sold | Production Period Ending December 31 2015 | Natural Gas | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 27,010,000 | [2] |
Derivative Instruments Not Designated As Hedges Average Fixed Price | 4.18 | |
Fair Value Asset | 30,945 | [1] |
APL Fixed Price Swaps | Sold | Production Period Ending December 31 2015 | Natural Gas Liquids | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Gallons Of Natural Gas Liquids | 71,442,000 | [2] |
Derivative Instruments Not Designated As Hedges Average Fixed Price | 1.22 | |
Fair Value Asset | 43,094 | [1] |
APL Fixed Price Swaps | Sold | Production Period Ending December 31 2015 | APL Crude Oil | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Barrels Of Oil | 210,000 | [2] |
Derivative Instruments Not Designated As Hedges Average Fixed Price | 90.26 | |
Fair Value Asset | 7,274 | [1] |
APL Fixed Price Swaps | Sold | Production Period Ending December 31 2016 | Natural Gas | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 13,800,000 | [2] |
Derivative Instruments Not Designated As Hedges Average Fixed Price | 4.15 | |
Fair Value Asset | 9,381 | [1] |
APL Fixed Price Swaps | Sold | Production Period Ending December 31 2016 | Natural Gas Liquids | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Gallons Of Natural Gas Liquids | 34,650,000 | [2] |
Derivative Instruments Not Designated As Hedges Average Fixed Price | 1.03 | |
Fair Value Asset | 16,822 | [1] |
APL Fixed Price Swaps | Sold | Production Period Ending December 31 2016 | APL Crude Oil | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Barrels Of Oil | 30,000 | [2] |
Derivative Instruments Not Designated As Hedges Average Fixed Price | 90 | |
Fair Value Asset | 848 | [1] |
APL Fixed Price Swaps | Sold | Production Period Ending December 31 2017 | Natural Gas | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 6,600,000 | [2] |
Derivative Instruments Not Designated As Hedges Average Fixed Price | 4.11 | |
Fair Value Asset | 2,137 | [1] |
APL Fixed Price Swaps | Sold | Production Period Ending December 31 2017 | Natural Gas Liquids | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Gallons Of Natural Gas Liquids | 10,080,000 | [2] |
Derivative Instruments Not Designated As Hedges Average Fixed Price | 1.04 | |
Fair Value Asset | 4,777 | [1] |
APL Options | Sold | ||
Derivatives Fair Value [Line Items] | ||
Total options | 10,127 | [1] |
APL Options | Sold | Production Period Ending December 31 2015 | Natural Gas Liquids | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Gallons Of Natural Gas Liquids | 1,260,000 | [2] |
Derivative Instruments Not Designated As Hedges Average Fixed Price | 1.28 | |
APL Options | Puts Purchased | Production Period Ending December 31 2015 | Natural Gas Liquids | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Gallons Of Natural Gas Liquids | 3,150,000 | [2] |
Derivative Instruments Not Designated As Hedges Average Fixed Price | 0.94 | |
Fair Value Asset | 1,353 | [1] |
APL Options | Puts Purchased | Production Period Ending December 31 2015 | APL Crude Oil | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Barrels Of Oil | 270,000 | [2] |
Derivative Instruments Not Designated As Hedges Average Fixed Price | 89.18 | |
Fair Value Asset | $8,774 | [1] |
[1] | See Note 2 for discussion on fair value methodology | |
[2] | NGL volumes are stated in gallons. Crude oil volumes are stated in barrels. Natural gas volumes are stated in MMBTUs |
Derivative_Instruments_APLs_Ga
Derivative Instruments (APL's Gain Loss Recognized in Gain Loss on Mark to Market Derivatives Table) (Details) (USD $) | 12 Months Ended | |||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Derivative Instruments Gain Loss [Line Items] | ||||||
Gains on mark to market derivatives | $131,064 | ($28,764) | $31,940 | |||
Atlas Pipeline "APL" | Derivatives Not Designated As Hedges | Realized Gain Loss | Commodity Contract | ||||||
Derivative Instruments Gain Loss [Line Items] | ||||||
Gain (loss) recognized in gain (loss) on mark-to-market derivatives - Realized | -9,960 | [1] | -324 | [1] | 10,993 | [1] |
Atlas Pipeline "APL" | Derivatives Not Designated As Hedges | Unrealized Gain Loss | Commodity Contract | ||||||
Derivative Instruments Gain Loss [Line Items] | ||||||
Gain (loss) recognized in gain (loss) on mark-to-market derivatives - Unrealized | $141,024 | [2] | ($28,440) | [2] | $20,947 | [2] |
[1] | Realized gain (loss) represents the gain (loss) incurred when the derivative contract expires and/or is cash settled. | |||||
[2] | Unrealized gain (loss) represents the mark-to-market gain (loss) recognized on open derivative contracts, which have not yet settled. |
Derivative_Instruments_Fair_Va2
Derivative Instruments (Fair Value of Derivative Instruments by Balance Sheet Location Table) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Derivative Instruments And Hedging Activities Disclosure [Abstract] | ||
Current portion of derivative asset | $232,266 | $2,066 |
Long-term derivative asset | 168,000 | 30,868 |
Current portion of derivative liability | -17,630 | |
Long-term derivative liability | -387 | |
Total Partnership net asset | $400,266 | $14,917 |
Fair_Value_of_Financial_Instru2
Fair Value of Financial Instruments (Schedule of Assets/Liabilities at Fair Value) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | $404,659 | $52,565 |
Gross Amounts of Recognized Liabilities | -468 | -33,943 |
Total assets, fair value, net | 404,191 | 18,622 |
Rabbi trust | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Rabbi trust | 3,925 | 3,705 |
Swap | Commodity Contract | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 5,562 | 1,634 |
Gross Amounts of Recognized Liabilities | -152 | |
Atlas Resource Partners, L.P. | Puts | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 2,767 | 1,374 |
Atlas Resource Partners, L.P. | Swap | Commodity Contract | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 261,680 | 33,594 |
Gross Amounts of Recognized Liabilities | -401 | -14,624 |
Atlas Resource Partners, L.P. | Commodity Options | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 5,320 | 3,305 |
Gross Amounts of Recognized Liabilities | -67 | -1,094 |
Atlas Pipeline "APL" | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 88,007 | 4,547 |
Atlas Pipeline "APL" | Swap | Commodity Contract | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 115,278 | 4,406 |
Gross Amounts of Recognized Liabilities | -18,073 | |
Atlas Pipeline "APL" | Commodity Options | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 10,127 | |
Level 1 | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 3,925 | 3,705 |
Total assets, fair value, net | 3,925 | 3,705 |
Level 1 | Rabbi trust | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Rabbi trust | 3,925 | 3,705 |
Level 2 | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 334,688 | 47,238 |
Gross Amounts of Recognized Liabilities | -468 | -20,565 |
Total assets, fair value, net | 334,220 | 26,673 |
Level 2 | Swap | Commodity Contract | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 5,562 | 1,634 |
Gross Amounts of Recognized Liabilities | -152 | |
Level 2 | Atlas Resource Partners, L.P. | Puts | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 2,767 | 1,374 |
Level 2 | Atlas Resource Partners, L.P. | Swap | Commodity Contract | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 261,680 | 33,594 |
Gross Amounts of Recognized Liabilities | -401 | -14,624 |
Level 2 | Atlas Resource Partners, L.P. | Commodity Options | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 5,320 | 3,305 |
Gross Amounts of Recognized Liabilities | -67 | -1,094 |
Level 2 | Atlas Pipeline "APL" | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 4,337 | |
Level 2 | Atlas Pipeline "APL" | Swap | Commodity Contract | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 50,585 | 2,994 |
Gross Amounts of Recognized Liabilities | -4,695 | |
Level 2 | Atlas Pipeline "APL" | Commodity Options | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 8,774 | |
Level 3 | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 66,046 | 1,622 |
Gross Amounts of Recognized Liabilities | -13,378 | |
Total assets, fair value, net | 66,046 | -11,756 |
Level 3 | Atlas Pipeline "APL" | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 210 | |
Level 3 | Atlas Pipeline "APL" | Swap | Commodity Contract | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 64,693 | 1,412 |
Gross Amounts of Recognized Liabilities | -13,378 | |
Level 3 | Atlas Pipeline "APL" | Commodity Options | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | $1,353 |
Fair_Value_of_Financial_Instru3
Fair Value of Financial Instruments (Schedule of Level 3 Derivative Contract Fair Value) (Details) (USD $) | 12 Months Ended | ||||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2012 | ||
gal | |||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||
Balance - Beginning (Amount) | ($11,756) | 66,046 | $23,083 | ||
NGL Fixed Price Swaps | |||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||
Balance - Beginning (Volume) | 130,158,000 | 116,172,000 | 87,066,000 | ||
Balance - Beginning (Amount) | -11,966 | 64,693 | 16,814 | ||
NGL Put Option | |||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||
Balance - Beginning (Volume) | 6,300,000 | 3,150,000 | 38,556,000 | ||
Balance - Beginning (Amount) | 210 | 1,353 | 6,269 | ||
NGL Call Option | |||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||
Balance - Beginning (Volume) | 1,260,000 | ||||
New Contracts | |||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||
New contracts | 816 | [1] | |||
New Contracts | NGL Fixed Price Swaps | |||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||
New contracts | 104,328,000 | [1] | 70,560,000 | [1] | |
New Contracts | NGL Put Option | |||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||
New contracts | 7,560,000 | [1] | 5,040,000 | [1] | |
New contracts | 816 | [1] | 200 | [1] | |
New Contracts | NGL Call Option | |||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||
New contracts | 5,040,000 | [1] | |||
New contracts | -200 | [1] | |||
Cash Settlement From Unrealized Gain (loss) | |||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||
Cash settlements from unrealized (gain) loss | -2,951 | [2],[3] | 3,385 | [2],[3] | |
Cash Settlement From Unrealized Gain (loss) | NGL Fixed Price Swaps | |||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||
Cash settlements from unrealized (gain) loss | -61,236,000 | [2],[3] | -84,546,000 | [2],[3] | |
Cash settlements from unrealized (gain) loss | -11,496 | [2],[3] | 3,406 | [2],[3] | |
Cash Settlement From Unrealized Gain (loss) | NGL Put Option | |||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||
Cash settlements from unrealized (gain) loss | -39,816,000 | [2],[3] | -8,190,000 | [2],[3] | |
Cash settlements from unrealized (gain) loss | 8,545 | [2],[3] | 100 | [2],[3] | |
Cash Settlement From Unrealized Gain (loss) | NGL Call Option | |||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||
Cash settlements from unrealized (gain) loss | -3,780,000 | [2],[3] | |||
Cash settlements from unrealized (gain) loss | -121 | [2],[3] | |||
Net Change In Unrealized Loss | |||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||
Net change in unrealized loss | -19,651 | [2] | 74,901 | [2] | |
Net Change In Unrealized Loss | NGL Fixed Price Swaps | |||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||
Net change in unrealized loss | -17,284 | [2] | 73,253 | [2] | |
Net Change In Unrealized Loss | NGL Put Option | |||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||
Net change in unrealized loss | -2,367 | [2] | 1,448 | [2] | |
Net Change In Unrealized Loss | NGL Call Option | |||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||
Net change in unrealized loss | 200 | [2] | |||
Option Premium | |||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||
Deferred option premium recognition | -13,053 | [3] | -484 | [3] | |
Option Premium | NGL Put Option | |||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||
Deferred option premium recognition | -13,053 | [3] | -605 | [3] | |
Option Premium | NGL Call Option | |||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||
Deferred option premium recognition | 121 | [3] | |||
[1] | Swaps are entered into with no value on the date of trade. Options include premiums paid, which are included in the value of the derivatives on the date of trade. | ||||
[2] | Included within gain (loss) on mark-to-market derivatives on the Partnership’s consolidated statements of operations. | ||||
[3] | Includes option premium cost reclassified from unrealized gain (loss) to realized gain (loss) at time of option expiration. |
Fair_Value_of_Financial_Instru4
Fair Value of Financial Instruments (Summary of Unobservable Inputs) (Details) (USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | ||
gal | gal | |||
Propane Swaps | ||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||||
Balance - Beginning (Volume) | 101,556,000 | 100,296,000 | ||
Third Party Quotes | $50,201 | [1] | ($10,260) | [1] |
Total Amount | 50,201 | -10,260 | ||
Natural Gasoline Swaps | ||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||||
Balance - Beginning (Volume) | 14,616,000 | 16,002,000 | ||
Third Party Quotes | 14,859 | [1] | 132 | [1] |
Adjustments | -367 | [2] | -813 | [2] |
Total Amount | 14,492 | -681 | ||
Total NGL Swaps | ||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||||
Balance - Beginning (Volume) | 116,172,000 | 130,158,000 | ||
Third Party Quotes | 65,060 | [1] | -12,430 | [1] |
Adjustments | -367 | [2] | 464 | [2] |
Total Amount | 64,693 | -11,966 | ||
Iso butane Swaps | ||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||||
Balance - Beginning (Volume) | 6,300,000 | |||
Third Party Quotes | -2,342 | [1] | ||
Adjustments | 955 | [2] | ||
Total Amount | -1,387 | |||
Normal Butane Swaps | ||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||||
Balance - Beginning (Volume) | 7,560,000 | |||
Third Party Quotes | 40 | [1] | ||
Adjustments | 322 | [2] | ||
Total Amount | $362 | |||
[1] | Based upon the difference between the quoted market price provided by the third party and the fixed price of the swap. | |||
[2] | Product and location basis differentials calculated through the use of a regression model, which compares the difference between the settlement prices for the products and locations quoted by the third party and the settlement prices for the actual products and locations underlying the derivatives, using a three-year historical period. |
Recovered_Sheet1
Fair Value Of Financial Instruments (Summary Of Regression Coefficient Utilized In The Calculation Of Unobservable Inputs For Level 3 Fair Value Measurements) (Details) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Natural Gasoline Swaps | Level 3 Fair Value Adjustments | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Adjustments | ($367) | ($813) |
Natural Gasoline Swaps | Lower 95% | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Adjustment based upon Regression Coefficient | 0.9714 | 0.9727 |
Natural Gasoline Swaps | Upper 95% | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Adjustment based upon Regression Coefficient | 0.9748 | 0.9751 |
Natural Gasoline Swaps | Average Coefficient | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Adjustment based upon Regression Coefficient | 0.9731 | 0.9739 |
Total NGL Swaps | Level 3 Fair Value Adjustments | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Adjustments | -367 | |
Iso butane Swaps | Level 3 Fair Value Adjustments | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Adjustments | 955 | |
Iso butane Swaps | Lower 95% | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Adjustment based upon Regression Coefficient | 1.1184 | |
Iso butane Swaps | Upper 95% | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Adjustment based upon Regression Coefficient | 1.1284 | |
Iso butane Swaps | Average Coefficient | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Adjustment based upon Regression Coefficient | 1.1234 | |
Normal Butane Swaps | Level 3 Fair Value Adjustments | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Adjustments | 322 | |
Normal Butane Swaps | Lower 95% | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Adjustment based upon Regression Coefficient | 1.0341 | |
Normal Butane Swaps | Upper 95% | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Adjustment based upon Regression Coefficient | 1.0386 | |
Normal Butane Swaps | Average Coefficient | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Adjustment based upon Regression Coefficient | 1.0364 | |
Total NGL Swaps | Level 3 Fair Value Adjustments | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Adjustments | $464 |
Fair_Value_of_Financial_Instru5
Fair Value of Financial Instruments (Summary of Regression Coefficient Utilized in the Calculation of Unobservable Inputs for Level 3 Fair Value Measurements) (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Product/Location Adjustment, Based Upon Multiple Regression Analysis, Reduction | $100,000 | $400,000 | |
Ngl Linefill | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Prepaid expenses and other | $14,612,000 | $14,517,000 | $7,783,000 |
Fair_Value_of_Financial_Instru6
Fair Value of Financial Instruments (Summary of Changes in NGL Linefill) (Details) (Ngl Linefill, USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | ||
gal | gal | |||
Beginning balance, Gallons | 17,326,000 | 9,148,000 | ||
Deliveries into NGL | 63,658,000 | 80,758,000 | ||
NGL linefill | -53,964,000 | -74,793,000 | ||
Acquired NGL linefill | 2,213,000 | [1] | ||
Ending balance, Gallons | 27,020,000 | 17,326,000 | ||
Beginning balance, Gallons | $14,517 | $7,783 | ||
Deliveries into NGL linefill | 41,370 | 60,565 | ||
NGL linefill sales | -35,387 | -54,950 | ||
Net change in NGL linefill valuation | -5,888 | [2] | -249 | [2] |
Acquired NGL linefill | 1,368 | [1] | ||
Ending balance, Gallons | 14,612 | 14,517 | ||
Linefill Valued at Market | ||||
Beginning balance, Gallons | 5,788,000 | 9,148,000 | ||
Deliveries into NGL | 4,385,000 | |||
NGL linefill | -4,629,000 | -3,360,000 | ||
Ending balance, Gallons | 17,526,000 | 5,788,000 | ||
Adjustments for linefill contract revision | 11,982,000 | |||
Beginning balance, Gallons | 4,739 | 7,783 | ||
Deliveries into NGL linefill | 2,919 | |||
NGL linefill sales | -3,917 | -2,795 | ||
Net change in NGL linefill valuation | -5,888 | [2] | -249 | [2] |
Ending balance, Gallons | 7,699 | 4,739 | ||
Adjustments for linefill contract revision | 9,846 | |||
Linefill Valued on FIFO | ||||
Beginning balance, Gallons | 11,538,000 | |||
Deliveries into NGL | 59,273,000 | 80,758,000 | ||
NGL linefill | -49,335,000 | -71,433,000 | ||
Acquired NGL linefill | 2,213,000 | [1] | ||
Ending balance, Gallons | 9,494,000 | 11,538,000 | ||
Adjustments for linefill contract revision | -11,982,000 | |||
Beginning balance, Gallons | 9,778 | |||
Deliveries into NGL linefill | 38,451 | 60,565 | ||
NGL linefill sales | -31,470 | -52,155 | ||
Acquired NGL linefill | 1,368 | [1] | ||
Ending balance, Gallons | 6,913 | 9,778 | ||
Adjustments for linefill contract revision | ($9,846) | |||
[1] | NGL linefill acquired as part of APL’s TEAK and Cardinal acquisitions (see Note 4). | |||
[2] | Included within gathering and processing revenues on the Partnership’s consolidated statements of operations. |
Fair_Value_of_Financial_Instru7
Fair Value of Financial Instruments - Additional Information (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
Fair Value Disclosures [Abstract] | ||
Long-term Debt, Fair Value | $3,382,900,000 | $2,841,700,000 |
Long-term debt | $3,570,570,000 | $2,889,000,000 |
Fair_Value_of_Financial_Instru8
Fair Value of Financial Instruments (Schedule of Assets and Liabilities Measured on Non Recurring Basis) (Details) (USD $) | 12 Months Ended | 0 Months Ended | 1 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | 7-May-13 | Feb. 29, 2012 | Jan. 31, 2013 | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||||||
Liabilities incurred | $10,674,000 | $23,129,000 | $16,568,000 | |||
Asset impairment | 580,654,000 | 81,880,000 | 9,507,000 | |||
Maximum | ||||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||||||
Range Of Undiscounted Amounts Possible Related to Trigger Payments, Low End | 6,000,000 | |||||
Atlas Pipeline "APL" | TEAK Acquisition | ||||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||||||
Cash Consideration | 974,700,000 | |||||
Atlas Pipeline "APL" | Gas Gathering System And Related Assets | ||||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||||||
Business Acquisition, Effective Date of Acquisition | 1-Feb-12 | |||||
Cash Consideration | 19,000,000 | |||||
Trigger Payments | 12,000,000 | |||||
Trigger Payments, Liabilities Recorded Upon Acquisition at Fair Value | 6,000,000 | |||||
Atlas Pipeline "APL" | Gas Gathering System And Related Assets | Trigger Payments | ||||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||||||
Trigger Payments, Payments Made | 6,000,000 | |||||
Level 3 | ||||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||||||
Liabilities incurred | 10,674,000 | 23,129,000 | ||||
Asset impairment | 580,700,000 | 38,000,000 | 9,500,000 | |||
Level 3 | Atlas Pipeline "APL" | TEAK Acquisition | ||||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||||||
Business Acquisition, Purchase Price Allocation, Status | During the year ended December 31, 2014, ARP completed the Eagle Ford, Rangely and GeoMet acquisitions (see Note 4). During the year ended December 31, 2013, the Partnership completed the Arkoma Acquisition, ARP completed the EP Energy Acquisition and APL completed the TEAK Acquisition. During the year ended December 31, 2012, ARP completed the acquisitions of certain oil and gas assets from Carrizo, certain proved reserves and associated assets from Titan, Equal and DTE, while APL completed the Cardinal Acquisition (see Note 4). The fair value measurements of assets acquired and liabilities assumed for each of these acquisitions are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The estimated fair values of the assets acquired and liabilities assumed in the Eagle Ford, Rangely and GeoMet acquisitions as of the respective acquisition dates, which are reflected in the Partnership’s consolidated balance sheet as of December 31, 2014, are subject to change as the final valuations for these transactions have not yet been completed, and such changes may be material. The fair values of natural gas and oil properties were measured using a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, as well as the respective natural gas, oil and natural gas liquids forward price curves. The fair values of the asset retirement obligations were measured under the Partnership’s and ARP’s existing methodology for recognizing an estimated liability for the plugging and abandonment of its gas and oil wells (see Note 8). These inputs require significant judgments and estimates by the Partnership’s and ARP’s management at the time of the valuations and are subject to change. | |||||
Asset Retirement Obligations | ||||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||||||
Liabilities incurred | 10,674,000 | 23,129,000 | ||||
Asset Retirement Obligations | Level 3 | ||||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||||||
Liabilities incurred | $10,674,000 | $23,129,000 |
Income_Taxes_Components_Of_Fed
Income Taxes (Components Of Federal And State Income Tax Expense (Benefit) of APL's Taxable Subsidiary Table) (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Total income tax expense (benefit) | ($2,376,000) | ($2,260,000) | $176,000 |
Atlas Pipeline "APL" | |||
Federal | -2,128,000 | -2,024,000 | 158,000 |
State | -248,000 | -236,000 | 18,000 |
Total income tax expense (benefit) | ($2,376,000) | ($2,260,000) | $176,000 |
Income_Taxes_Narrative_Details
Income Taxes (Narrative) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
Deferred income taxes, net | ($30,914,000) | ($33,290,000) |
Net operating loss carry forwards for federal income tax | 44,700,000 | |
Atlas Pipeline "APL" | ||
Deferred income taxes, net | ($30,914,000) | ($33,290,000) |
Income_Taxes_Components_Of_APL
Income Taxes (Components Of APL's Net Deferred Tax Liabilities Table) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Net deferred tax liabilities | ($30,914) | ($33,290) |
Atlas Pipeline "APL" | ||
Net operating loss tax carryforwards and alternative minimum tax credits | 17,269 | 14,900 |
Deferred Tax Liabilities - Excess of asset carrying value over tax basis | -48,183 | -48,190 |
Net deferred tax liabilities | ($30,914) | ($33,290) |
Certain_Relationships_and_Rela1
Certain Relationships and Related Party Transactions (Narrative) (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Relationship With Drilling Partnerships | |||
Related Party Transaction [Line Items] | |||
Related Party Transaction, Description of Transaction | ARP conducts certain activities through, and a portion of its revenues are attributable to, the Drilling Partnerships. ARP serves as general partner and operator of the Drilling Partnerships and assumes customary rights and obligations for the Drilling Partnerships. As the general partner, ARP is liable for the Drilling Partnerships’ liabilities and can be liable to limited partners of the Drilling Partnerships if it breaches its responsibilities with respect to the operations of the Drilling Partnerships. ARP is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Drilling Partnerships’ revenues and costs and expenses according to the respective partnership agreements. | ||
Relationship With APL | |||
Related Party Transaction [Line Items] | |||
Related Party Transaction, Description of Transaction | In the Chattanooga Shale, a portion of the natural gas produced by ARP is gathered and processed by APL. For the years ended December 31, 2014, 2013 and 2012, $0.3 million, $0.3 million and $0.4 million of gathering fees paid by ARP to APL were eliminated in consolidation. | ||
Relationship With APL | Design And Construction Management Assistance Services For ARP | |||
Related Party Transaction [Line Items] | |||
Related Party Transaction, Description of Transaction | In addition, in Lycoming County, Pennsylvania, APL agreed to provide assistance in the design and construction management services for ARP with respect to a pipeline. ARP reimbursed approximately $1.8 million to APL for the year ended December 31, 2013. | ||
Incurred price for Lycoming County pipeline project | $1.80 | ||
Atlas Resource Partners, L.P. | |||
Related Party Transaction [Line Items] | |||
Related Party Transaction, Amounts of Transaction | 0.3 | 0.3 | 0.4 |
Relationship With Resource America Inc | Issuance Of Term Facility With CVC Credits Partners LLC | |||
Related Party Transaction [Line Items] | |||
Related Party Transaction, Description of Transaction | In connection with the issuance of the Term Facility, CVC Credit Partners, LLC (“CVCâ€), which is a joint-venture between Resource America, Inc. and an unrelated third party private equity firm, was allocated an aggregate of $12.5 million of the Term Facility. The Partnership’s Chief Executive Officer and President is Chairman of the board of directors of Resource America, Inc., and the Partnership’s Executive Chairman of the General Partner’s board of directors is Chief Executive Officer and President and Resource America, Inc. | ||
Related Party Transaction, Amounts of Transaction | $12.50 |
Commitments_and_Contingencies_1
Commitments and Contingencies (General Commitments) (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Lawsuits | |||
Operating leases, rent expense, net | $32.60 | $24.40 | $9.60 |
Percentage of present value of future cash flows | 10.00% | ||
Net partnership revenues subordinated | 5.3 | 9.6 | 6.3 |
Voluntarily settled and dismissed, lawsuits | 2 | ||
Atlas Pipeline "APL" | |||
Contractual obligation, due in next twelve months | 20.7 | ||
Contractual obligation, due in second year | 23.9 | ||
Contractual obligation, due in third year | 23.9 | ||
Contractual obligation, due in fourth year | 21.8 | ||
Contractual obligation, due in fifth year | 16.9 | ||
Transportation Contracts Fees | 28.3 | 34.8 | 10.5 |
ARP and APL Combined | |||
Commitment to expend | 198 | ||
GeoMet Acquisition | |||
Contractual obligation, due in next twelve months | 2.5 | ||
Contractual obligation, due in second year | 2.4 | ||
Contractual obligation, due in third year | 2 | ||
Contractual obligation, due in fourth year | 1.8 | ||
Contractual obligation, due in fifth year | 1.8 | ||
Contractual obligation, due in thereafter | 6.9 | ||
EP Energy Acquisition | |||
Contractual obligation, due in next twelve months | 8.3 | ||
Contractual obligation, due in second year | 2.1 | ||
Contractual obligation, due in third year | 0 | ||
Contractual obligation, due in fourth year | 0 | ||
Contractual obligation, due in fifth year | $0 | ||
Minimum | |||
Partnership obligations to purchase units from investor partners | 5.00% | ||
Investor partners return on investment | 10.00% | ||
Maximum | |||
Partnership obligations to purchase units from investor partners | 10.00% | ||
Percentage on unhedged revenue | 50.00% | ||
Investor partners return on investment | 12.00% |
Commitments_and_Contingencies_2
Commitments and Contingencies (Schedule of Future Minimum Lease Payments) (Details) (USD $) | Dec. 31, 2014 |
In Thousands, unless otherwise specified | |
Commitments And Contingencies Disclosure [Abstract] | |
2015 | $16,524 |
2016 | 11,917 |
2017 | 8,216 |
2018 | 7,314 |
2019 | 1,951 |
Thereafter | 3,415 |
Operating leases, future minimum payments due, total | $49,337 |
Issuances_of_Units_EP_Energy_A
Issuances of Units (EP Energy Acquisition And Equity Distribution Program) (Details) (USD $) | 1 Months Ended | 2 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 1 Months Ended | 0 Months Ended | 1 Months Ended | 0 Months Ended | 3 Months Ended | 1 Months Ended | ||||||||
Aug. 31, 2014 | Dec. 31, 2012 | Dec. 31, 2014 | Dec. 31, 2014 | Dec. 23, 2014 | Jan. 15, 2015 | Dec. 31, 2013 | Jul. 31, 2012 | Feb. 29, 2012 | Jun. 30, 2014 | Jul. 31, 2013 | Nov. 05, 2014 | Oct. 31, 2014 | 31-May-14 | 12-May-14 | Mar. 31, 2014 | Jul. 25, 2012 | Apr. 30, 2012 | Dec. 20, 2012 | |
Capital Unit [Line Items] | |||||||||||||||||||
Partners unit, issued | 7,898,210 | 0 | |||||||||||||||||
Subsidiary or Equity Method Investee, Price-Per-Share | $23.01 | ||||||||||||||||||
Partners Capital Account Units Date Of Sale | November and December 2012 | ||||||||||||||||||
Aggregate Offering Price Of Common Units (Maximum) | $100,000,000 | ||||||||||||||||||
Agent commission, maximum percentage, of the gross sales price of common limited partner units sold. | 2.00% | ||||||||||||||||||
Net proceeds from issuance of common limited partner units | 174,500,000 | ||||||||||||||||||
Net Proceeds From Unit Issuance Applied To Repay Term Loan Credit Facility | 2,200,000 | 2,200,000 | |||||||||||||||||
Registration Rights Agreement Date | 19-Sep-12 | ||||||||||||||||||
Conversion of Class B preferred units (units) | 3,796,900 | ||||||||||||||||||
Business Acquisition, Date of Acquisition Agreement | 1-Apr-12 | ||||||||||||||||||
Preferred class D | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Partners unit, issued | 3,200,000 | ||||||||||||||||||
Partners' Capital Account, Units, Percentage | 8.63% | ||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit there after | $2.16 | $2.16 | |||||||||||||||||
Percentage of Preferred Unit Regular Quarterly Cash Distributions | 8.63% | ||||||||||||||||||
Redemption price per unit | $25 | $25 | |||||||||||||||||
Subsequent Event | Preferred class D | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $0.62 | ||||||||||||||||||
Equity Distribution Agreement with Deutsche Bank Securities Inc. | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Partners unit, issued | 309,174 | ||||||||||||||||||
Aggregate Offering Price Of Common Units (Maximum) | 25,000,000 | ||||||||||||||||||
Equity Distribution Agreement Commencement Date | 1-May-13 | ||||||||||||||||||
Net proceeds from issuance of common limited partner units | 6,900,000 | ||||||||||||||||||
Payments For Commissions | 400,000 | ||||||||||||||||||
Equity Distribution Agreement Effective Date | 27-Dec-13 | ||||||||||||||||||
Convertible Class B Preferred Units | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Partners unit, issued | 3,800,000 | ||||||||||||||||||
ATLS | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Share Distribution | 5,240,000 | ||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 13-Mar-12 | ||||||||||||||||||
Distribution Made to Member or Limited Partner, Date of Record | 28-Feb-12 | ||||||||||||||||||
Ratio Of Atls Limited Partner Units | $0.10 | ||||||||||||||||||
Registration Rights Agreement Date Agreed To File With Sec | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Registration Rights Agreement Date | 25-Jan-13 | ||||||||||||||||||
Registration Statement Declared Effective By Date | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Registration Rights Agreement Date | 31-Mar-13 | ||||||||||||||||||
Registration Statement Declared Effective On Date | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Registration Rights Agreement Date | 2-Oct-12 | ||||||||||||||||||
Atlas Resource Partners, L.P. | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Gain on sale of subsidiary unit issuances | 40,500,000 | 27,300,000 | |||||||||||||||||
EP Energy Acquisition | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Partners unit, issued | 14,950,000 | ||||||||||||||||||
Subsidiary or Equity Method Investee, Price-Per-Share | $21.75 | ||||||||||||||||||
Partners Capital Account Units Date Of Sale | Jun-13 | ||||||||||||||||||
Partners Capital Account Sale Of Units | 313,100,000 | ||||||||||||||||||
EP Energy Acquisition | Over Allotment Units Issued | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Partners unit, issued | 1,950,000 | ||||||||||||||||||
EP Energy Acquisition | ARP Acquisitions | Class C Convertible Preferred Units | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Partners unit, issued | 3,746,986 | ||||||||||||||||||
Subsidiary or Equity Method Investee, Price-Per-Share | $23.10 | ||||||||||||||||||
Partners' Capital Account, Private Placement of Units | 86,600,000 | ||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $0.51 | ||||||||||||||||||
Preferred Stock, Voting Rights | The Class C preferred units have no voting rights, except as set forth in the certificate of designation for the Class C preferred units, which provides, among other things, that the affirmative vote of 75% of the Class C Preferred Units is required to repeal such certificate of designation. | ||||||||||||||||||
Warrants Received | 562,497 | ||||||||||||||||||
Warrants Exercisable Date | 29-Oct-13 | ||||||||||||||||||
Warrants Expiration Date | 31-Jul-16 | ||||||||||||||||||
Preferred Units, Description | The Class C preferred units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act. The Class C preferred units pay cash distributions in an amount equal to the greater of (i) $0.51 per unit and (ii) the distributions payable on each common unit at each declared quarterly distribution date. The initial Class C preferred distribution was paid for the quarter ended September 30, 2013. The Class C preferred units have no voting rights, except as set forth in the certificate of designation for the Class C preferred units, which provides, among other things, that the affirmative vote of 75% of the Class C Preferred Units is required to repeal such certificate of designation. Holders of the Class C preferred units have the right to convert the Class C preferred units on a one-for-one basis, in whole or in part, into common units at any time before July 31, 2016. Unless previously converted, all Class C preferred units will convert into common units on July 31, 2016. | ||||||||||||||||||
EP Energy Acquisition | ATLS | Class C Convertible Preferred Units | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Partners unit, issued | 3,749,986 | ||||||||||||||||||
Subsidiary or Equity Method Investee, Price-Per-Share | $23.10 | ||||||||||||||||||
Partners' Capital Account, Private Placement of Units | 86,600,000 | ||||||||||||||||||
Warrants Received | 562,497 | ||||||||||||||||||
Preferred Units, Description | The Class C preferred units pay cash distributions in an amount equal to the greater of (i) $0.51 per unit and (ii) the distributions payable on each common unit at each declared quarterly distribution date. The initial Class C preferred distribution was paid for the quarter ending September 30, 2013. The Class C preferred units have no voting rights, except as set forth in the certificate of designation for the Class C preferred units, which provides, among other things, that the affirmative vote of 75% of the Class C Preferred Units is required to repeal such certificate of designation. Holders of the Class C preferred units have the right to convert the Class C preferred units on a one-for-one basis, in whole or in part, into common units at any time before July 31, 2016 | ||||||||||||||||||
Registration Rights Agreement, Description And Terms | Upon issuance of the Class C preferred units and warrants on July 31, 2013, ARP entered into a registration rights agreement pursuant to which it agreed to file a registration statement with the SEC to register the resale of the common units issuable upon conversion of the Class C preferred units and upon exercise of the warrants. ARP agreed to use commercially reasonable efforts to file such registration statement within 90 days of the conversion of the Class C preferred units into common units or the exercise of the warrants. | ||||||||||||||||||
EP Energy Acquisition | Atlas Resource Partners, L.P. | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Partners unit, issued | 14,950,000 | ||||||||||||||||||
EP Energy Acquisition | Atlas Resource Partners, L.P. | Class C Convertible Preferred Units | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Partners unit, issued | 3,749,986 | ||||||||||||||||||
Eagle Ford Acquisition | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Cash Consideration | 179,500,000 | ||||||||||||||||||
Business Acquisition, Date of Acquisition Agreement | 5-Nov-14 | ||||||||||||||||||
Eagle Ford Acquisition | Class D Preferred Units | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Partners unit, issued | 3,200,000 | ||||||||||||||||||
Subsidiary or Equity Method Investee, Price-Per-Share | $25 | ||||||||||||||||||
Partners Capital Account Units Date Of Sale | Oct-14 | ||||||||||||||||||
Partners' Capital Account, Units, Percentage | 8.63% | ||||||||||||||||||
Partners Capital Account Sale Of Units | 77,400,000 | ||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit there after | $2.16 | ||||||||||||||||||
Percentage of Preferred Unit Regular Quarterly Cash Distributions | 8.63% | ||||||||||||||||||
Eagle Ford Acquisition | Class D Preferred Units | Subsequent Event | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $0.62 | ||||||||||||||||||
Eagle Ford Acquisition | Atlas Resource Partners, L.P. | Class D Preferred Units | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Business Acquisition, Cost of Acquired Entity, Equity Interests Issued and Issuable | 20,000,000 | ||||||||||||||||||
Rangely Acquisition | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Partners unit, issued | 15,525,000 | ||||||||||||||||||
Subsidiary or Equity Method Investee, Price-Per-Share | $19.90 | ||||||||||||||||||
Partners Capital Account Units Date Of Sale | May-14 | ||||||||||||||||||
Partners Capital Account Sale Of Units | 297,300,000 | ||||||||||||||||||
Rangely Acquisition | Over Allotment Units Issued | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Partners unit, issued | 2,025,000 | ||||||||||||||||||
GeoMet Acquisition | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Partners unit, issued | 6,325,000 | ||||||||||||||||||
Subsidiary or Equity Method Investee, Price-Per-Share | $21.18 | ||||||||||||||||||
Partners Capital Account Units Date Of Sale | Mar-14 | ||||||||||||||||||
Partners Capital Account Sale Of Units | 129,000,000 | ||||||||||||||||||
Cash Consideration | 97,900,000 | ||||||||||||||||||
GeoMet Acquisition | Over Allotment Units Issued | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Partners unit, issued | 825,000 | ||||||||||||||||||
Titan Operating, L.L.C | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | 0.4 | ||||||||||||||||||
Business Acquisition, Cost of Acquired Entity, Equity Interests Issued and Issuable | 193,200,000 | ||||||||||||||||||
Cash Consideration | 15,400,000 | ||||||||||||||||||
Strike Price Of Preferred Units Voluntarily Convertible To Common Units | 26.03 | ||||||||||||||||||
Titan Operating, L.L.C | Common Units | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Partners unit, issued | 3,800,000 | ||||||||||||||||||
Titan Operating, L.L.C | Atlas Resource Partners, L.P. | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Business Acquisition, Cost of Acquired Entity, Equity Interests Issued and Issuable | 193,200,000 | ||||||||||||||||||
Cash Consideration | 15,400,000 | ||||||||||||||||||
Business Acquisition, Date of Acquisition Agreement | 25-Jul-12 | ||||||||||||||||||
Carrizo Oil and Gas, Inc. | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Partners unit, issued | 6,000,000 | ||||||||||||||||||
Subsidiary or Equity Method Investee, Price-Per-Share | $20 | ||||||||||||||||||
Net proceeds from issuance of common limited partner units | 119,500,000 | ||||||||||||||||||
Registration Rights Agreement Date | 11-Jul-12 | ||||||||||||||||||
Business Acquisition, Date of Acquisition Agreement | 30-Apr-12 | ||||||||||||||||||
Carrizo Oil and Gas, Inc. | Units Purchased By Executives Amount | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Partners Capital Account Sale Of Units | 5,000,000 | ||||||||||||||||||
Carrizo Oil and Gas, Inc. | Registration Statement Declared Effective By Date | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Registration Rights Agreement Date | 30-Oct-12 | ||||||||||||||||||
Carrizo Oil and Gas, Inc. | Registration Statement Declared Effective On Date | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Registration Rights Agreement Date | 28-Aug-12 | ||||||||||||||||||
Carrizo Oil and Gas, Inc. | Registration Statement Declared Effective By SEC Date | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Registration Rights Agreement Date | 31-Dec-12 | ||||||||||||||||||
Carrizo Oil and Gas, Inc. | Atlas Resource Partners, L.P. | |||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||
Partners unit, issued | 6,000,000 | ||||||||||||||||||
Subsidiary or Equity Method Investee, Price-Per-Share | $20 | ||||||||||||||||||
Net proceeds from issuance of common limited partner units | 119,500,000 | ||||||||||||||||||
Cash Consideration | $187,000,000 | ||||||||||||||||||
Business Acquisition, Date of Acquisition Agreement | 30-Apr-12 |
Issuances_of_Units_Atlas_Pipel
Issuances of Units (Atlas Pipeline Partners) (Details) (USD $) | 2 Months Ended | 3 Months Ended | 12 Months Ended | 1 Months Ended | 0 Months Ended | 1 Months Ended | 0 Months Ended | ||||||||||||||||||||||||||||
Dec. 31, 2012 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Apr. 17, 2013 | 12-May-14 | Nov. 30, 2012 | Oct. 15, 2014 | Mar. 17, 2014 | Jan. 15, 2015 | Jan. 22, 2015 | 7-May-13 | Dec. 20, 2012 | Apr. 16, 2013 | |||||||||
Capital Unit [Line Items] | |||||||||||||||||||||||||||||||||||
Partners unit, issued | 7,898,210 | 0 | |||||||||||||||||||||||||||||||||
Net proceeds from issuance of common limited partner units | $174,500,000 | ||||||||||||||||||||||||||||||||||
Subsidiary or Equity Method Investee, Price-Per-Share | $23.01 | ||||||||||||||||||||||||||||||||||
Cash Distributions Paid | 27,015,000 | 25,435,000 | 23,865,000 | 23,681,000 | 23,649,000 | 22,611,000 | 15,928,000 | 15,410,000 | 13,866,000 | 12,831,000 | 12,830,000 | ||||||||||||||||||||||||
Net loss attributable to common limited partners | -159,225,000 | [1] | -9,085,000 | [1] | -10,023,000 | [1] | -13,925,000 | [1] | -27,000,000 | [2] | -27,524,000 | [2] | -8,247,000 | [2] | -12,596,000 | [2] | -192,258,000 | -75,367,000 | -52,413,000 | ||||||||||||||||
Partners Capital Account Units Date Of Sale | November and December 2012 | ||||||||||||||||||||||||||||||||||
Citigroup Equity Distribution Program | Common Units To Maintain General Partner Interest | |||||||||||||||||||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||||||||||||||||||
Net proceeds from issuance of common limited partner units | 2,800,000 | 200,000 | |||||||||||||||||||||||||||||||||
Class D Preferred Units | TEAK Acquisition | |||||||||||||||||||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||||||||||||||||||
Fair Value Of Common Units | $36.52 | ||||||||||||||||||||||||||||||||||
Embedded beneficial conversion discount | 91,000,000 | ||||||||||||||||||||||||||||||||||
Accretion of the beneficial conversion discount | 45,500,000 | 29,500,000 | |||||||||||||||||||||||||||||||||
Class D Preferred Units | TEAK Acquisition | Net Unaccreted Beneficial Conversion Discount | |||||||||||||||||||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||||||||||||||||||
Embedded beneficial conversion discount | 16,000,000 | 61,500,000 | 16,000,000 | 61,500,000 | |||||||||||||||||||||||||||||||
Atlas Pipeline "APL" | |||||||||||||||||||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||||||||||||||||||
Partners unit, issued | 10,507,033 | ||||||||||||||||||||||||||||||||||
Net proceeds from issuance of common limited partner units | 319,300,000 | ||||||||||||||||||||||||||||||||||
General partner ownership interest | 2.00% | 2.00% | |||||||||||||||||||||||||||||||||
Subsidiary or Equity Method Investee, Price-Per-Share | $31 | $31 | $31 | $31 | |||||||||||||||||||||||||||||||
Capital contribution from partnership | 8,300,000 | ||||||||||||||||||||||||||||||||||
Atlas Pipeline "APL" | TEAK Acquisition | |||||||||||||||||||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||||||||||||||||||
Partners unit, issued | 11,845,000 | ||||||||||||||||||||||||||||||||||
Net proceeds from issuance of common limited partner units | 388,400,000 | ||||||||||||||||||||||||||||||||||
General partner ownership interest | 2.00% | ||||||||||||||||||||||||||||||||||
Subsidiary or Equity Method Investee, Price-Per-Share | $34 | ||||||||||||||||||||||||||||||||||
Capital contribution from partnership | 6,700,000 | ||||||||||||||||||||||||||||||||||
Atlas Pipeline "APL" | Sales Agents Equity Distribution | |||||||||||||||||||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||||||||||||||||||
Equity distribution agreement, value of common units | 250,000,000 | ||||||||||||||||||||||||||||||||||
Atlas Pipeline "APL" | Citigroup Equity Distribution Program | |||||||||||||||||||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||||||||||||||||||
Equity distribution agreement, value of common units | 150,000,000 | ||||||||||||||||||||||||||||||||||
Partners unit, issued | 3,558,005 | 3,895,679 | 275,429 | ||||||||||||||||||||||||||||||||
Net proceeds from issuance of common limited partner units | 121,600,000 | 137,800,000 | 8,700,000 | ||||||||||||||||||||||||||||||||
Payments For Commissions | 1,200,000 | 2,900,000 | 200,000 | ||||||||||||||||||||||||||||||||
Proceeds From Issuance Of Preferred Limited Partners Units | 2,500,000 | ||||||||||||||||||||||||||||||||||
General partner ownership interest | 2.00% | 2.00% | 2.00% | ||||||||||||||||||||||||||||||||
Gain on sale of subsidiary unit issuances | 2,700,000 | 11,900,000 | |||||||||||||||||||||||||||||||||
Atlas Pipeline "APL" | Class E Preferred Units | |||||||||||||||||||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||||||||||||||||||
Partners unit, issued | 5,060,000 | ||||||||||||||||||||||||||||||||||
Subsidiary or Equity Method Investee, Price-Per-Share | $25 | ||||||||||||||||||||||||||||||||||
Proceeds from Issuance cost | 122,300,000 | ||||||||||||||||||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $0.68 | ||||||||||||||||||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions | 3,400,000 | ||||||||||||||||||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit there after | $0.52 | ||||||||||||||||||||||||||||||||||
Percentage of Preferred Unit Regular Quarterly Cash Distributions | 8.25% | ||||||||||||||||||||||||||||||||||
Cash Distributions Paid | 2,600,000 | ||||||||||||||||||||||||||||||||||
Net loss attributable to common limited partners | 8,200,000 | ||||||||||||||||||||||||||||||||||
Atlas Pipeline "APL" | Class E Preferred Units | Subsequent Event | |||||||||||||||||||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||||||||||||||||||
Cash Distributions Paid | 2,600,000 | ||||||||||||||||||||||||||||||||||
Atlas Pipeline "APL" | Class D Preferred Units | TEAK Acquisition | |||||||||||||||||||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||||||||||||||||||
Partners Capital Account Units Date Of Sale | 5/31/13 | ||||||||||||||||||||||||||||||||||
Preferred stock distribution related to income statement | 42,600,000 | 23,600,000 | |||||||||||||||||||||||||||||||||
Atlas Pipeline "APL" | Class D Preferred Units | Subsequent Event | |||||||||||||||||||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||||||||||||||||||
Partners unit, issued | 15,389,575 | ||||||||||||||||||||||||||||||||||
Subsidiary or Equity Method Investee, Price-Per-Share | $29.75 | ||||||||||||||||||||||||||||||||||
Atlas Pipeline "APL" | Class D Preferred Units | TEAK Acquisition | |||||||||||||||||||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||||||||||||||||||
Proceeds From Issuance Of Preferred Limited Partners Units | 397,700,000 | ||||||||||||||||||||||||||||||||||
General partner ownership interest | 2.00% | ||||||||||||||||||||||||||||||||||
Subsidiary or Equity Method Investee, Price-Per-Share | $29.75 | ||||||||||||||||||||||||||||||||||
Partners Capital Account Units Date Of Sale | 5/7/13 | ||||||||||||||||||||||||||||||||||
Partners' Capital Account, Private Placement of Units | 400,000,000 | ||||||||||||||||||||||||||||||||||
Commitment Date | 16-Apr-13 | ||||||||||||||||||||||||||||||||||
Atlas Pipeline "APL" | Class D Preferred Units | TEAK Acquisition | Common Units To Maintain General Partner Interest | |||||||||||||||||||||||||||||||||||
Capital Unit [Line Items] | |||||||||||||||||||||||||||||||||||
Proceeds From Issuance Of Preferred Limited Partners Units | $8,200,000 | ||||||||||||||||||||||||||||||||||
[1] | For the first, second, third and fourth quarters of the year ended December 31, 2014, approximately 4,111,000, 4,049,000, 5,082,000 and 4,637,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit because the inclusion of such units would have been anti-dilutive. | ||||||||||||||||||||||||||||||||||
[2] | For the first, second, third and fourth quarters of the year ended December 31, 2013, approximately 3,594,000, 4,092,000, 4,196,000 and 4,091,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit because the inclusion of such units would have been anti-dilutive. |
Cash_Distributions_Additional_
Cash Distributions - Additional Information (Details) (USD $) | 1 Months Ended | 2 Months Ended | 3 Months Ended | 12 Months Ended | 0 Months Ended | 1 Months Ended | 0 Months Ended | |||||||||||||||||||||||
In Thousands, except Share data, unless otherwise specified | Mar. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | 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, 2014 | Dec. 31, 2014 | Dec. 23, 2014 | Jan. 15, 2015 | Feb. 23, 2015 | Jan. 28, 2015 | Nov. 30, 2014 | Oct. 31, 2014 | Aug. 31, 2014 | Jul. 31, 2014 | 31-May-14 | Apr. 30, 2014 | Feb. 28, 2014 | Jan. 31, 2014 | Dec. 31, 2012 | Jan. 09, 2015 | |
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $0.40 | $0.52 | $0.49 | $0.46 | $0.46 | $0.46 | $0.44 | $0.31 | $0.30 | $0.27 | $0.25 | $0.25 | ||||||||||||||||||
Partners unit, issued | 7,898,210 | 0 | ||||||||||||||||||||||||||||
Preferred class D | ||||||||||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||||||||||||
Partners unit, issued | 3,200,000 | |||||||||||||||||||||||||||||
Partners' Capital Account, Units, Percentage | 8.63% | |||||||||||||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit there after | 2.15625 | $2.16 | ||||||||||||||||||||||||||||
Percentage of Preferred Unit Regular Quarterly Cash Distributions | 8.63% | |||||||||||||||||||||||||||||
Subsequent Event | Class E APL Preferred Units | ||||||||||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $2,600 | |||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $0.52 | |||||||||||||||||||||||||||||
Subsequent Event | Cash Distribution Declared | ||||||||||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $0.11 | $0.20 | ||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Declaration Date | 23-Feb-15 | 28-Jan-15 | ||||||||||||||||||||||||||||
Subsequent Event | Cash Distribution Paid | ||||||||||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | 9,900 | 18,900 | ||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 17-Mar-15 | 13-Feb-15 | ||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Date of Record | 10-Mar-15 | 9-Feb-15 | ||||||||||||||||||||||||||||
Subsequent Event | Cash Distribution Paid | General Partner | ||||||||||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | 200 | 1,400 | ||||||||||||||||||||||||||||
Subsequent Event | Cash Distribution Paid | Preferred Limited Partners' Interest | ||||||||||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | 400 | 700 | ||||||||||||||||||||||||||||
Subsequent Event | Preferred class D | ||||||||||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $0.62 | |||||||||||||||||||||||||||||
ATLS | ||||||||||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||||||||||||
Distribution Policy, Members or Limited Partners, Description | The Partnership has a cash distribution policy under which it distributes, within 50 days after the end of each quarter, all of its available cash (as defined in the partnership agreement) for that quarter to its common unitholders. | |||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 13-Mar-12 | |||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Date of Record | 28-Feb-12 | |||||||||||||||||||||||||||||
ATLS | Subsequent Event | Cash Distribution Declared | ||||||||||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $0.52 | |||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Declaration Date | 28-Jan-15 | |||||||||||||||||||||||||||||
ATLS | Subsequent Event | Cash Distribution Paid | ||||||||||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | 27,100 | |||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 19-Feb-15 | |||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Date of Record | 9-Feb-15 | |||||||||||||||||||||||||||||
Atlas Resource Partners, L.P. | ||||||||||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||||||||||||
Distribution Policy, Members or Limited Partners, Description | ARP Cash Distributions. In January 2014, ARP’s board of directors approved the modification of its cash distribution payment practice to a monthly cash distribution program whereby it distributes all of its available cash (as defined in the partnership agreement) for that month to its unitholders within 45 days from the month end. Prior to that, ARP paid quarterly cash distributions within 45 days from the end of each calendar quarter. | |||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $0.20 | $0.20 | $0.19 | $0.58 | $0.56 | $0.54 | $0.51 | $0.48 | $0.43 | $0.40 | $0.12 | [1] | $0.20 | $0.20 | $0.20 | $0.20 | $0.19 | $0.19 | $0.19 | $0.19 | ||||||||||
Atlas Resource Partners, L.P. | Subsequent Event | Cash Distribution Declared | ||||||||||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Declaration Date | 23-Feb-15 | 28-Jan-15 | ||||||||||||||||||||||||||||
Atlas Resource Partners, L.P. | Subsequent Event | Cash Distribution Paid | ||||||||||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 17-Mar-15 | 13-Feb-15 | ||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Date of Record | 10-Mar-15 | 9-Feb-15 | ||||||||||||||||||||||||||||
Atlas Resource Partners, L.P. | Minimum | ||||||||||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||||||||||||
Percentage of Distributions in Excess of Targets | 13.00% | |||||||||||||||||||||||||||||
Atlas Resource Partners, L.P. | Maximum | ||||||||||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||||||||||||
Percentage of Distributions in Excess of Targets | 48.00% | |||||||||||||||||||||||||||||
Atlas Pipeline "APL" | ||||||||||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||||||||||||
Distribution Policy, Members or Limited Partners, Description | APL Cash Distributions. APL is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter to its common unitholders and the Partnership, as general partner. If APL’s common unit distributions in any quarter exceed specified target levels, the Partnership will receive between 13% and 48% of such distributions in excess of the specified target levels | |||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $0.64 | $0.63 | $0.62 | $0.62 | $0.62 | $0.62 | $0.59 | $0.58 | $0.57 | $0.56 | $0.56 | |||||||||||||||||||
Partners unit, issued | 10,507,033 | |||||||||||||||||||||||||||||
Atlas Pipeline "APL" | General Partner | ||||||||||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | 8,115 | 7,055 | 6,099 | 6,095 | 6,013 | 5,875 | 3,980 | 3,117 | 2,409 | 2,221 | 2,217 | |||||||||||||||||||
Atlas Pipeline "APL" | Cash Distribution Declared | ||||||||||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Declaration Date | 9-Jan-15 | |||||||||||||||||||||||||||||
Atlas Pipeline "APL" | Cash Distribution Paid | ||||||||||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | 62,200 | |||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 13-Feb-15 | |||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Date of Record | 21-Jan-15 | |||||||||||||||||||||||||||||
Atlas Pipeline "APL" | Cash Distribution Paid | General Partner | ||||||||||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | 8,100 | |||||||||||||||||||||||||||||
Atlas Pipeline "APL" | Subsequent Event | Cash Distribution Declared | ||||||||||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $0.64 | |||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Declaration Date | 9-Jan-15 | |||||||||||||||||||||||||||||
Atlas Pipeline "APL" | Subsequent Event | Cash Distribution Paid | ||||||||||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 13-Feb-15 | |||||||||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Date of Record | 21-Jan-15 | |||||||||||||||||||||||||||||
APL Cash Distributions | Minimum | ||||||||||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||||||||||||
Percentage of Distributions in Excess of Targets | 13.00% | |||||||||||||||||||||||||||||
APL Cash Distributions | Maximum | ||||||||||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||||||||||||
Percentage of Distributions in Excess of Targets | 48.00% | |||||||||||||||||||||||||||||
[1] | Represents a pro-rated cash distribution of $0.40 per common limited partner unit for the period from March 5, 2012, the date the Partnership’s exploration and production assets were transferred to ARP, to March 31, 2012 |
Cash_Distributions_Distributio
Cash Distributions (Distributions Declared by ARP) (Details) (USD $) | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||||||||
In Thousands, except Per Share data, unless otherwise specified | Mar. 31, 2012 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | 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, 2014 |
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $0.40 | $0.52 | $0.49 | $0.46 | $0.46 | $0.46 | $0.44 | $0.31 | $0.30 | $0.27 | $0.25 | $0.25 | |
Cash Distributions Paid | $27,015 | $25,435 | $23,865 | $23,681 | $23,649 | $22,611 | $15,928 | $15,410 | $13,866 | $12,831 | $12,830 | ||
Quarter Ended March 31, 2012 | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 18-May-12 | ||||||||||||
Quarter Ended June 30, 2012 | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 17-Aug-12 | ||||||||||||
Quarter Ended September 30, 2012 | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 19-Nov-12 | ||||||||||||
Quarter ended December 31, 2014 | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 19-Feb-13 | ||||||||||||
Quarter Ended March 31, 2013 | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 20-May-13 | ||||||||||||
Quarter Ended June 30, 2013 | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 19-Aug-13 | ||||||||||||
Quarter Ended September 30, 2013 | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 19-Nov-13 | ||||||||||||
Quarter Ended December 31, 2013 | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 19-Feb-14 | ||||||||||||
Quarter Ended March 31, 2014 | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 20-May-14 | ||||||||||||
Quarter ended June 30, 2014 | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 19-Aug-14 | ||||||||||||
Quarter ended September 30, 2014 | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 20-Nov-14 |
Cash_Distributions_Schedule_of
Cash Distributions (Schedule of Distributions Declared by Partnership) (Details) (USD $) | 1 Months Ended | 3 Months Ended | 12 Months Ended | 1 Months Ended | |||||||||||||||||||
In Thousands, except Per Share data, unless otherwise specified | Mar. 31, 2012 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | 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, 2014 | Nov. 30, 2014 | Oct. 31, 2014 | Aug. 31, 2014 | Jul. 31, 2014 | 31-May-14 | Apr. 30, 2014 | Feb. 28, 2014 | Jan. 31, 2014 | ||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $0.40 | $0.52 | $0.49 | $0.46 | $0.46 | $0.46 | $0.44 | $0.31 | $0.30 | $0.27 | $0.25 | $0.25 | |||||||||||
Cash Distributions Paid | $27,015 | $25,435 | $23,865 | $23,681 | $23,649 | $22,611 | $15,928 | $15,410 | $13,866 | $12,831 | $12,830 | ||||||||||||
Limited Partner Interest | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 13-Mar-12 | ||||||||||||||||||||||
Atlas Resource Partners, L.P. | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $0.20 | $0.20 | $0.19 | $0.58 | $0.56 | $0.54 | $0.51 | $0.48 | $0.43 | $0.40 | $0.12 | [1] | $0.20 | $0.20 | $0.20 | $0.20 | $0.19 | $0.19 | $0.19 | $0.19 | |||
Atlas Resource Partners, L.P. | Limited Partner Interest | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Cash Distributions Paid | 16,032 | 16,029 | 12,719 | 34,489 | 33,291 | 32,097 | 22,428 | 21,107 | 15,510 | 12,891 | 3,144 | 16,779 | 16,033 | 16,032 | 16,028 | 15,752 | 15,752 | 12,719 | 12,718 | ||||
Atlas Resource Partners, L.P. | Preferred Limited Partners' Interest | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Cash Distributions Paid | 1,492 | 1,492 | 1,466 | 4,400 | 4,248 | 2,072 | 1,957 | 1,841 | 1,652 | 745 | [2] | 1,491 | 1,491 | 1,493 | 1,466 | 1,466 | 1,466 | 1,467 | |||||
Atlas Resource Partners, L.P. | General Partner | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Cash Distributions Paid | $1,378 | $1,377 | $1,054 | $2,891 | $2,443 | $1,884 | $946 | $618 | $350 | $263 | $64 | $1,378 | $1,378 | $1,378 | $1,378 | $1,279 | $1,279 | $1,055 | $1,055 | ||||
Quarter Ended March 31, 2012 | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 18-May-12 | ||||||||||||||||||||||
Quarter Ended June 30, 2012 | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 17-Aug-12 | ||||||||||||||||||||||
Quarter Ended September 30, 2012 | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 19-Nov-12 | ||||||||||||||||||||||
Quarter ended December 31, 2014 | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 19-Feb-13 | ||||||||||||||||||||||
Quarter Ended March 31, 2013 | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 20-May-13 | ||||||||||||||||||||||
Quarter Ended June 30, 2013 | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 19-Aug-13 | ||||||||||||||||||||||
Quarter Ended September 30, 2013 | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 19-Nov-13 | ||||||||||||||||||||||
Quarter Ended December 31, 2013 | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 19-Feb-14 | ||||||||||||||||||||||
Quarter Ended March 31, 2014 | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 20-May-14 | ||||||||||||||||||||||
Quarter ended June 30, 2014 | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 19-Aug-14 | ||||||||||||||||||||||
Quarter ended September 30, 2014 | |||||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 20-Nov-14 | ||||||||||||||||||||||
[1] | Represents a pro-rated cash distribution of $0.40 per common limited partner unit for the period from March 5, 2012, the date the Partnership’s exploration and production assets were transferred to ARP, to March 31, 2012 | ||||||||||||||||||||||
[2] | (1) Excludes ARP’s initial Class D preferred unit quarterly distribution (see Note 15). |
Cash_Distributions_Common_Unit
Cash Distributions (Common Unit and General Partner Distributions Declared by APL) (Details) (USD $) | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||||||||
In Thousands, except Per Share data, unless otherwise specified | Mar. 31, 2012 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | 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, 2014 |
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $0.40 | $0.52 | $0.49 | $0.46 | $0.46 | $0.46 | $0.44 | $0.31 | $0.30 | $0.27 | $0.25 | $0.25 | |
Atlas Pipeline "APL" | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $0.64 | $0.63 | $0.62 | $0.62 | $0.62 | $0.62 | $0.59 | $0.58 | $0.57 | $0.56 | $0.56 | ||
Atlas Pipeline "APL" | Limited Partner Interest | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $54,080 | $51,781 | $49,998 | $49,969 | $49,298 | $48,165 | $45,382 | $37,442 | $30,641 | $30,085 | $30,030 | ||
Atlas Pipeline "APL" | General Partner | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $8,115 | $7,055 | $6,099 | $6,095 | $6,013 | $5,875 | $3,980 | $3,117 | $2,409 | $2,221 | $2,217 | ||
Quarter Ended March 31, 2012 | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 18-May-12 | ||||||||||||
Quarter Ended March 31, 2012 | Atlas Pipeline "APL" | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 15-May-12 | ||||||||||||
Quarter Ended June 30, 2012 | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 17-Aug-12 | ||||||||||||
Quarter Ended June 30, 2012 | Atlas Pipeline "APL" | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 14-Aug-12 | ||||||||||||
Quarter Ended September 30, 2012 | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 19-Nov-12 | ||||||||||||
Quarter Ended September 30, 2012 | Atlas Pipeline "APL" | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 14-Nov-12 | ||||||||||||
Quarter Ended December 31, 2012 | Atlas Pipeline "APL" | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 14-Feb-13 | ||||||||||||
Quarter Ended March 31, 2013 | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 20-May-13 | ||||||||||||
Quarter Ended March 31, 2013 | Atlas Pipeline "APL" | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 15-May-13 | ||||||||||||
Quarter Ended June 30, 2013 | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 19-Aug-13 | ||||||||||||
Quarter Ended June 30, 2013 | Atlas Pipeline "APL" | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 14-Aug-13 | ||||||||||||
Quarter Ended September 30, 2013 | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 19-Nov-13 | ||||||||||||
Quarter Ended September 30, 2013 | Atlas Pipeline "APL" | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 14-Nov-13 | ||||||||||||
Quarter Ended December 31, 2013 | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 19-Feb-14 | ||||||||||||
Quarter Ended December 31, 2013 | Atlas Pipeline "APL" | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 14-Feb-14 | ||||||||||||
Quarter Ended March 31, 2014 | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 20-May-14 | ||||||||||||
Quarter Ended March 31, 2014 | Atlas Pipeline "APL" | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 15-May-14 | ||||||||||||
Quarter ended June 30, 2014 | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 19-Aug-14 | ||||||||||||
Quarter ended June 30, 2014 | Atlas Pipeline "APL" | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 14-Aug-14 | ||||||||||||
Quarter ended September 30, 2014 | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 20-Nov-14 | ||||||||||||
Quarter ended September 30, 2014 | Atlas Pipeline "APL" | |||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 14-Nov-14 |
Benefit_Plans_Rabbi_Trust_Narr
Benefit Plans (Rabbi Trust Narrative) (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Rabbi trust | $3,925,000 | $3,705,000 | |
Rabbi trust liabilities recorded | 3,900,000 | 3,700,000 | |
Partnership distributed to participants | 99,996,000 | 77,598,000 | 51,837,000 |
Rabbi trust | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Partnership distributed to participants | $1,800,000 | $0 |
Benefit_Plans_2010_Long_Term_I
Benefit Plans (2010 Long Term Incentive Plan Narrative) (Details) (Partnership 2010 Long Term Incentive Plan) | 12 Months Ended |
Dec. 31, 2014 | |
Partnership 2010 Long Term Incentive Plan | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |
Share-based Compensation Arrangement by Share-based Payment Award, Description | The Board of Directors of the Partnership’s general partner (the “General Partnerâ€) approved and adopted the Partnership’s 2010 Long-Term Incentive Plan (“2010 LTIPâ€) effective February 2011. The 2010 LTIP provides equity incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners (collectively, the “Participantsâ€) who perform services for the Partnership. The 2010 LTIP is administered by a committee consisting of the Board or committee of the Board or board of an affiliate appointed by the Board (the “LTIP Committeeâ€), which is the Compensation Committee of the General Partner’s board of directors. |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 5,763,781 |
Phantom Units, Restricted Units and Unit Options Outstanding | 4,911,209 |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 283,650 |
Benefit_Plans_2010_LTIP_Phanto
Benefit Plans (2010 LTIP Phantom Unit Activity) (Details) (USD $) | 12 Months Ended | |||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Distribution equivalent rights paid on unissued units under incentive plans | $11,839,000 | $8,504,000 | $4,785,000 | |||
Partnership 2010 Phantom Units | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights | Generally, phantom units granted to employees under the 2010 LTIP will vest over a three or four year period from the date of grant | |||||
Share Based Compensation Arrangement By Share Based Payment Award Award Other Than Options Vesting Period Percentage | 25.00% | |||||
Share Based Compensation Arrangement By Share Based Payment Award Number Of Outstanding Units To Vest Within Next Twelve Months | 1,601,974 | |||||
Distribution equivalent rights paid on unissued units under incentive plans | 4,300,000 | 3,100,000 | 2,000,000 | |||
Outstanding, beginning of year (Units) | 2,054,534 | [1] | 2,044,227 | [1] | 1,838,164 | |
Granted (Units) | 961,000 | 112,000 | 133,080 | |||
Vested (Units) | -486,321 | [2] | -25,684 | [2] | -19,677 | [2] |
Forfeited (Units) | -32,549 | -76,009 | -72,808 | |||
ARP anti-dilution adjustment (Units) | 165,468 | [3] | ||||
Outstanding, end of year (Units) | 2,496,664 | [1] | 2,054,534 | [1] | 2,044,227 | [1] |
Non-cash compensation expense recognized | 22,624,000 | 11,848,000 | 11,612,000 | |||
Outstanding, beginning of year | $22.58 | [1] | $20.90 | [1] | $22.11 | |
Granted | $44.93 | $50.26 | $29.95 | |||
Vested | $20.76 | [2] | $19.87 | [2] | $20.11 | [2] |
Forfeited | $32.53 | $20.67 | $20.65 | |||
Outstanding, end of year | $31.41 | [1] | $22.58 | [1] | $20.90 | [1] |
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested In Period Intrinsic Value | 21,100,000 | 1,300,000 | 700,000 | |||
Share Based Compensation Arrangement By Share Based Payment Award Other Than Options Outstanding Intrinsic Value | 77,800,000 | |||||
Unrecognized compensation expense related to unvested phantom units | $35,700,000 | |||||
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition | 2 years 1 month 6 days | |||||
Minimum | Partnership 2010 Phantom Units | Employees | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period | 3 years | |||||
Maximum | Partnership 2010 Phantom Units | Employees | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period | 4 years | |||||
[1] | The aggregate intrinsic value of phantom unit awards outstanding at December 31, 2014 was $77.8 million. | |||||
[2] | The aggregate intrinsic values of phantom unit awards vested were $21.1 million, $1.3 million and $0.7 million, respectively, for the years ended December 31, 2014, 2013 and 2012. | |||||
[3] | The number of 2010 unit options and exercise price was adjusted concurrently with the distribution of ARP common units. |
Benefit_Plans_2010_Unit_Option
Benefit Plans (2010 Unit Option Activity) (Details) (Partnership2010 Unit Options, USD $) | 12 Months Ended | |||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights | The LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Generally, unit options granted under the 2010 LTIP generally will vest over a three or four year period from the date of grant. | |||||
Years From Date Of Grant Unit Option Awards Expire | 10 years | |||||
Share Based Compensation Arrangement By Share Based Payment Award Number Of Outstanding Units To Vest Within Next Twelve Months | 1,770,877 | |||||
Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options | $600,000 | $100,000 | $100,000 | |||
Outstanding, beginning of year (Units) | 2,452,412 | [1],[2] | 2,504,703 | [1],[2] | 2,304,300 | |
Granted (Units) | 77,167 | |||||
Exercised (Units) | -28,473 | [3] | -3,262 | [3] | -5,438 | [3] |
Forfeited (Units) | -9,394 | -49,029 | -79,119 | |||
ARP anti-dilution adjustment (Units) | 207,793 | [4] | ||||
Outstanding, end of year (Units) | 2,414,545 | [1],[2] | 2,452,412 | [1],[2] | 2,504,703 | [1],[2] |
Options exercisable (Units) | 584,162 | [5] | 13,865 | [5] | 3,398 | [5] |
Outstanding, beginning of year | $20.52 | [1],[2] | $20.51 | [1],[2] | $22.12 | |
Granted | $27.55 | |||||
Exercised | $20.68 | [3] | $20.44 | [3] | $18.44 | [3] |
Forfeited | $18.79 | $20.38 | $20.33 | |||
Outstanding, end of year | $20.53 | [1],[2] | $20.52 | [1],[2] | $20.51 | [1],[2] |
Options exercisable, end of year | $20.34 | [5] | $20.03 | [5] | $20.85 | [5] |
Non-cash compensation expense recognized | 4,535,000 | 5,768,000 | 5,966,000 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Term | 6 years 3 months 18 days | |||||
Aggregate Intrinsic Value Of Options Outstanding | 25,700,000 | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term | 6 years 3 months 18 days | 7 years 7 months 6 days | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value | 6,100,000 | 400,000 | 47,000 | |||
Unrecognized compensation expense related to unvested unit options | $1,100,000 | |||||
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition | 3 months 18 days | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Method Used | The Partnership used the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted. | |||||
Expected dividend yield | 3.70% | |||||
Expected unit price volatility | 45.00% | |||||
Risk-free interest rate | 1.40% | |||||
Expected term (in years) | 0 years | 0 years | 6 years 10 months 2 days | |||
Fair value of unit options granted | $8.08 | |||||
Maximum | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period | 4 years | |||||
Minimum | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period | 3 years | |||||
[1] | The weighted average remaining contractual life for outstanding options at December 31, 2014 was 6.3 years. | |||||
[2] | The options outstanding at December 31, 2014 had an aggregate intrinsic value of $25.7 million. | |||||
[3] | The intrinsic values of options exercised during the years ended December 31, 2014, 2013 and 2012 were $0.6 million, $0.1 million and $0.1 million, respectively. | |||||
[4] | The number of 2010 unit options and exercise price was adjusted concurrently with the distribution of ARP common units. | |||||
[5] | The weighted average remaining contractual lives for exercisable options at December 31, 2014 and 2013 were 6.3 years and 7.6 years, respectively. The intrinsic values of exercisable options at December 31, 2014, 2013 and 2012 were $6.1 million, $0.4 million and approximately $47,000, respectively. |
Benefit_Plans_2006_Long_Term_I
Benefit Plans (2006 Long Term Incentive Plan Narrative) (Details) (Partnership 2006 Long Term Incentive Plan) | 12 Months Ended |
Dec. 31, 2014 | |
Partnership 2006 Long Term Incentive Plan | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |
Share-based Compensation Arrangement by Share-based Payment Award, Description | The Board of Directors approved and adopted the Partnership’s 2006 Long-Term Incentive Plan (“2006 LTIPâ€), which provides equity incentive awards to Participants who perform services for the Partnership. The 2006 LTIP is administered by the LTIP Committee. |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 2,261,516 |
Phantom Units, Restricted Units and Unit Options Outstanding | 1,721,121 |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 133,951 |
Benefit_Plans_2006_LTIP_Phanto
Benefit Plans (2006 LTIP Phantom Unit Activity) (Details) (USD $) | 12 Months Ended | |||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Distribution equivalent rights paid on unissued units under incentive plans | $11,839,000 | $8,504,000 | $4,785,000 | |||
Partnership 2006 Phantom Units | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights | Generally, phantom units granted to employees under the 2006 LTIP will vest over a three or four year period from the date of grant and phantom units granted to non-employee directors generally vest over a four year period, 25% per year. | |||||
Share Based Compensation Arrangement By Share Based Payment Award Number Of Outstanding Units To Vest Within Next Twelve Months | 311,387 | |||||
Distribution equivalent rights paid on unissued units under incentive plans | 1,100,000 | 400,000 | 42,000 | |||
Outstanding, beginning of year (Units) | 234,940 | [1],[2] | 50,759 | [1],[2] | 32,641 | |
Granted (Units) | 629,525 | 207,363 | 25,248 | |||
Vested (Units) | -83,283 | [3],[4] | -20,182 | [3],[4] | -10,107 | [3],[4] |
Forfeited (Units) | -3,000 | |||||
ARP anti-dilution adjustment (Units) | 2,977 | [5] | ||||
Outstanding, end of year (Units) | 781,182 | [1],[2] | 234,940 | [1],[2] | 50,759 | [1],[2] |
Outstanding, beginning of year | $35.82 | [1],[2] | $21.02 | [1],[2] | $15.99 | |
Granted | $43.76 | $38.05 | $29.70 | |||
Vested | $33.86 | [3],[4] | $21.34 | [3],[4] | $20.26 | [3],[4] |
Forfeited | $36.45 | |||||
Outstanding, end of year | $42.43 | [1],[2] | $35.82 | [1],[2] | $21.02 | [1],[2] |
Non-cash compensation expense recognized | 16,797,000 | 5,317,000 | 660,000 | |||
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested In Period Intrinsic Value | 3,800,000 | 1,000,000 | 300,000 | |||
Share Based Compensation Arrangement By Share Based Payment Award Other Than Options Outstanding Intrinsic Value | 24,300,000 | |||||
Liabilities Related to Outstanding Phantom Units | 800,000 | 1,100,000 | ||||
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Nonvested Number Classified As Liabilities | 41,113 | 41,525 | ||||
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Weighted Average Grant Date Fair Value Units Classified Within Liabilities | $36.94 | $29.67 | ||||
Unrecognized compensation expense related to unvested phantom units | 14,100,000 | |||||
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition | 1 year 8 months 12 days | |||||
Partnership 2006 Phantom Units | Vested Units Settled In Cash | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Vested (Units) | -6,380 | -1,146 | ||||
Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options | $300,000 | $100,000 | $0 | |||
Partnership 2006 Phantom Units | Non Employee Directors | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Share Based Compensation Arrangement By Share Based Payment Award Award Other Than Options Vesting Period Percentage | 25.00% | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period | 4 years | |||||
Partnership 2006 Phantom Units | Minimum | Employees | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period | 3 years | |||||
Partnership 2006 Phantom Units | Maximum | Employees | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period | 4 years | |||||
[1] | The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2014 was $24.3 million. | |||||
[2] | There were $0.8 million and $1.1 million recognized as liabilities on APL’s consolidated balance sheets at December 31, 2014 and 2013, respectively, representing 41,113 and 41,525, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units are $36.94 and $29.67 as of December 31, 2014 and 2013, respectively. | |||||
[3] | The intrinsic values for phantom unit awards vested during the years ended December 31, 2014, 2013 and 2012 were $3.8 million, $1.0 million and $0.3 million, respectively. | |||||
[4] | There were 6,380 and 1,146 vested units during the years ended December 31, 2014 and 2013, respectively, that were settled for approximately $0.3 million and $0.1 million cash, respectively. No units were settled in cash during the year ended December 31, 2012. | |||||
[5] | The number of 2006 phantom units was adjusted concurrently with the distribution of ARP common units. |
Benefit_Plans_2006_Unit_Option
Benefit Plans (2006 Unit Option Activity) (Details) (Partnership 2006 Unit Options, USD $) | 12 Months Ended | |||||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 20, 2012 | |||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||||
Years From Date Of Grant Unit Option Awards Expire | 10 years | |||||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights | Generally, unit options granted under the 2006 LTIP will vest over a three or four year period from the date of grant. | |||||||
Share Based Compensation Arrangement By Share Based Payment Award Number Of Outstanding Units To Vest Within Next Twelve Months | 2,500 | |||||||
Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options | $0 | $0 | $200,000 | |||||
Outstanding, beginning of year (Units) | 939,939 | [1],[2] | 929,939 | [1],[2] | 903,614 | |||
Granted (Units) | 10,000 | |||||||
Exercised (Units) | -51,998 | [3] | ||||||
ARP anti-dilution adjustment (Units) | 78,323 | [4] | ||||||
Outstanding, end of year (Units) | 939,939 | [1],[2] | 939,939 | [1],[2] | 929,939 | [1],[2] | ||
Options exercisable (Units) | 932,439 | [5] | 929,939 | [5] | 929,939 | [5] | ||
Outstanding, beginning of year | $20.94 | [1],[2] | $20.75 | $21.52 | $20.75 | [1],[2] | ||
Granted | $38.51 | |||||||
Exercised | $3.03 | [3] | ||||||
Outstanding, end of year | $20.94 | [1],[2] | $20.94 | [1],[2] | $20.75 | $20.75 | [1],[2] | |
Options exercisable, end of year | $20.80 | [5] | $20.75 | [5] | $20.75 | [5] | ||
Non-cash compensation expense recognized | 22,000 | 36,000 | ||||||
Share Based Compensation Arrangement By Share Based Payment Award Options Exercises In Period Total Intrinsic Value | 0 | 0 | 1,500,000 | |||||
Share Based Compensation Arrangement By Share Based Payment Award Other Than Options Outstanding Intrinsic Value | 9,700,000 | |||||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term | 1 year 10 months 24 days | 2 years 10 months 24 days | ||||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value | 9,700,000 | 24,300,000 | 13,000,000 | |||||
Unrecognized compensation expense related to unvested unit options | $17,000 | |||||||
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition | 1 year 7 months 6 days | |||||||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Method Used | The Partnership uses the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted. | |||||||
Expected dividend yield | 3.20% | |||||||
Expected unit price volatility | 30.00% | |||||||
Risk-free interest rate | 0.70% | |||||||
Expected term (in years) | 0 years | 6 years 3 months | 0 years | |||||
Fair value of unit options granted | $7.54 | |||||||
Minimum | ||||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period | 3 years | |||||||
Maximum | ||||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period | 4 years | |||||||
[1] | The weighted average remaining contractual life for outstanding options at December 31, 2014 was 1.9 years. | |||||||
[2] | The aggregate intrinsic value of options outstanding at December 31, 2014 was approximately $9.7 million. | |||||||
[3] | (1)The intrinsic value of options exercised during the year ended December 31, 2012 was $1.5 million. No options were exercised during the years ended December 31, 2014 and 2013. | |||||||
[4] | The number of 2006 unit options and exercise price was adjusted concurrently with the distribution of ARP common units. | |||||||
[5] | The weighted average remaining contractual lives for exercisable options at December 31, 2014 and 2013 were 1.9 years and 2.9 years, respectively. The aggregate intrinsic values of options exercisable at December 31, 2014, 2013 and 2012 were $9.7 million, $24.3 million and $13.0 million, respectively. |
Benefit_Plans_ARP_Long_Term_In
Benefit Plans (ARP Long Term Incentive Plan Narrative) (Details) (ARP Long Term Incentive Plan) | 12 Months Ended |
Dec. 31, 2014 | |
ARP Long Term Incentive Plan | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |
Share-based Compensation Arrangement by Share-based Payment Award, Description | ARP’s 2012 Long-Term Incentive Plan (the “ARP LTIPâ€), effective March 2012, provides incentive awards to officers, employees and directors as well as employees of the general partner and its affiliates, consultants and joint venture partners who perform services for ARP. The ARP LTIP is administered by the board of the general partner, a committee of the board or the board (or committee of the board) of an affiliate (the “ARP LTIP Committeeâ€). |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 2,900,000 |
Phantom Units, Restricted Units and Unit Options Outstanding | 2,257,492 |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 135,663 |
Benefit_Plans_ARP_LTIP_Phantom
Benefit Plans (ARP LTIP Phantom Unit Activity) (Details) (USD $) | 12 Months Ended | |||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Distribution equivalent rights paid on unissued units under incentive plans | $11,839,000 | $8,504,000 | $4,785,000 | |||
ARP Phantom Units | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Outstanding, beginning of year (Units) | 839,808 | [1],[2] | 948,476 | [1],[2] | ||
Granted (Units) | 264,173 | 145,813 | 949,476 | |||
Vested (Units) | -274,414 | [3] | -215,981 | [3] | ||
Forfeited (Units) | -30,375 | -38,500 | -1,000 | |||
Outstanding, end of year (Units) | 799,192 | [1],[2] | 839,808 | [1],[2] | 948,476 | [1],[2] |
Outstanding, beginning of year | $24.31 | [1],[2] | $24.76 | [1],[2] | ||
Granted | $19.43 | $21.87 | $24.76 | |||
Vested | $24.46 | [3] | $24.73 | [3] | ||
Forfeited | $22.76 | $23.96 | $24.67 | |||
Outstanding, end of year | $22.70 | [1],[2] | $24.31 | [1],[2] | $24.76 | [1],[2] |
Non-cash compensation expense recognized | 6,367 | 9,166 | 7,630 | |||
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested In Period Intrinsic Value | 5,400,000 | 6,100,000 | 0 | |||
Share Based Compensation Arrangement By Share Based Payment Award Other Than Options Outstanding Intrinsic Value | 8,600,000 | |||||
Liabilities Related to Outstanding Phantom Units | 200,000 | 100,000 | ||||
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Units Classified Within Liabilities | 26,579 | 16,084 | ||||
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Weighted Average Grant Date Fair Value Units Classified Within Liabilities | $21.16 | $22.15 | ||||
Unrecognized compensation expense related to unvested phantom units | 6,700,000 | |||||
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition | 1 year 8 months 12 days | |||||
Atlas Resource Partners, L.P. | ARP Phantom Units | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights | Phantom units granted under the ARP LTIP generally will vest 25% of the original granted amount on each of the four anniversaries of the date of grant. | |||||
Share Based Compensation Arrangement By Share Based Payment Award Number Of Outstanding Units To Vest Within Next Twelve Months | 317,587 | |||||
Distribution equivalent rights paid on unissued units under incentive plans | $2,000,000 | $1,900,000 | $700,000 | |||
Atlas Resource Partners, L.P. | ARP Phantom Units | Vesting Percentage On Each Of Next Four Anniversaries Of Date Of Grant | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Share Based Compensation Arrangement By Share Based Payment Award Award Other Than Options Vesting Period Percentage | 25.00% | |||||
[1] | The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2014 was $8.6 million. | |||||
[2] | There was approximately $0.2 million and $0.1 million recognized as liabilities on the Partnership’s consolidated balance sheets at December 31, 2014 and 2013, respectively, representing 26,579 and 16,084 units, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units were $21.16 and $22.15 at December 31, 2014 and 2013, respectively. | |||||
[3] | The intrinsic values of phantom unit awards vested during the years ended December 31, 2014 and 2013 were $5.4 million and $6.1 million, respectively. No phantom unit awards vested during the year ended December 31, 2012. |
Benefit_Plans_ARP_Unit_Options
Benefit Plans (ARP Unit Options Activity) (Details) (Partnership 2012 Long Term Incentive Plans - Phantom Units, USD $) | 12 Months Ended | ||||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Apr. 30, 2012 | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights | The ARP LTIP Committee will determine the vesting and exercise restrictions applicable to an ARP award of options, if any, and the method by which the exercise price may be paid by the participant. Unit option awards expire 10 years from the date of grant. Unit options granted under the ARP LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. | ||||||
Years From Date Of Grant Unit Option Awards Expire | 10 years | ||||||
Share Based Compensation Arrangement By Share Based Payment Award Fair Value Assumptions Outstanding Options To Vest Within Next Twelve Months | 361,325 | ||||||
Proceeds from Stock Options Exercised | $0 | $0 | $0 | ||||
Outstanding, beginning of year (Units) | 1,482,675 | [1],[2] | 1,515,500 | [1],[2] | 1,515,500 | ||
Granted (Units) | 5,000 | 1,517,500 | |||||
Forfeited (Units) | -24,375 | -37,825 | -2,000 | ||||
Outstanding, end of year (Units) | 1,458,300 | [1],[2] | 1,482,675 | [1],[2] | 1,515,500 | [1],[2] | 1,515,500 |
Options exercisable (Units) | 730,775 | [3] | 370,700 | [3] | |||
Non-cash compensation expense recognized | 1,700,000 | 3,514,000 | 3,198,000 | ||||
Outstanding, beginning of year | $24.66 | [1],[2] | $24.68 | [1],[2] | |||
Granted | $21.56 | $24.68 | |||||
Forfeited | $24.52 | $24.80 | $24.67 | ||||
Outstanding, end of year | $24.66 | [1],[2] | $24.66 | [1],[2] | $24.68 | [1],[2] | |
Options exercisable, end of year | $24.67 | [3] | $24.67 | [3] | |||
Share Based Compensation Arrangement By Share Based Payment Award Options Exercises In Period Total Intrinsic Value | 0 | 0 | 0 | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term | 7 years 4 months 24 days | ||||||
Aggregate Intrinsic Value Of Options Outstanding | 1,000 | ||||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term | 7 years 4 months 24 days | 8 years 4 months 24 days | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value | 0 | 0 | 0 | ||||
Unrecognized compensation expense related to unvested unit options | $1,000,000 | ||||||
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition | 1 year 1 month 6 days | ||||||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Method Used | ARP used the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted. | ||||||
Expected dividend yield | 800.00% | 590.00% | |||||
Expected unit price volatility | 3550.00% | 4700.00% | |||||
Risk-free interest rate | 140.00% | 100.00% | |||||
Expected term (in years) | 0 years | 6 years 3 months 22 days | 6 years 3 months | ||||
Fair value of unit options granted | $2.95 | $6.10 | |||||
Vesting Percentage On Each Of Next Four Anniversaries Of Date Of Grant | |||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||||
Share Based Compensation Arrangement By Share Based Payment Award Options Vesting Period Percentage | 25.00% | ||||||
[1] | The weighted average remaining contractual life for outstanding options at December 31, 2014 was 7.4 years. | ||||||
[2] | There was no aggregate intrinsic value of options outstanding at December 31, 2014. The aggregate intrinsic value of options outstanding at December 31, 2013 was approximately $1,000. | ||||||
[3] | The weighted average remaining contractual life for exercisable options at December 31, 2014 and 2013 was 7.4 years and 8.4 years, respectively. There were no intrinsic values for options exercisable at December 31, 2014, 2013, and 2012. |
Benefit_Plans_APL_Long_Term_In
Benefit Plans (APL Long Term Incentive Plans Narrative) (Details) (APL Long Term Incentive Plans) | 12 Months Ended |
Dec. 31, 2014 | |
APL Long Term Incentive Plans | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |
Share-based Compensation Arrangement by Share-based Payment Award, Description | APL has a 2004 Long-Term Incentive Plan (“2004 APL LTIPâ€) and a 2010 Long-Term Incentive Plan (“2010 APL LTIP†and collectively with the 2004 LTIP, the “APL LTIPsâ€) in which officers, employees, non-employee managing board members of APL’s general partner, employees of APL’s general partner’s affiliates and consultants are eligible to participate. The APL LTIPs are administered by its compensation committee (the “APL LTIP Committeeâ€). |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 139,218 |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 3,435,000 |
Phantom Units, Restricted Units and Unit Options Outstanding | 1,684,289 |
Benefit_Plans_APL_Phantom_Unit
Benefit Plans (APL Phantom Unit Activity) (Details) (USD $) | 12 Months Ended | ||||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Feb. 28, 2014 | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||||
Distribution equivalent rights paid on unissued units under incentive plans | $11,839,000 | $8,504,000 | $4,785,000 | ||||
ARP Phantom Units | |||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||||
Outstanding, beginning of year | $24.31 | [1],[2] | $24.76 | [1],[2] | |||
Granted | $19.43 | $21.87 | $24.76 | ||||
Forfeited | $22.76 | $23.96 | $24.67 | ||||
Vested | $24.46 | [3] | $24.73 | [3] | |||
Outstanding, end of year | $22.70 | [1],[2] | $24.31 | [1],[2] | $24.76 | [1],[2] | |
Non-cash compensation expense recognized | 6,367 | 9,166 | 7,630 | ||||
Outstanding, beginning of year (Units) | 839,808 | [1],[2] | 948,476 | [1],[2] | |||
Granted (Units) | 264,173 | 145,813 | 949,476 | ||||
Forfeited (Units) | -30,375 | -38,500 | -1,000 | ||||
Vested (Units) | -274,414 | [3] | -215,981 | [3] | |||
Outstanding, end of year (Units) | 799,192 | [1],[2] | 839,808 | [1],[2] | 948,476 | [1],[2] | |
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested In Period Intrinsic Value | 5,400,000 | 6,100,000 | 0 | ||||
Share Based Compensation Arrangement By Share Based Payment Award Other Than Options Outstanding Intrinsic Value | 8,600,000 | ||||||
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Units Classified Within Liabilities | 26,579 | 16,084 | |||||
Unrecognized compensation expense related to unvested phantom units | 6,700,000 | ||||||
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition | 1 year 8 months 12 days | ||||||
Atlas Pipeline "APL" | ARP Phantom Units | |||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights | Phantom units granted to employees under the APL LTIPs generally had vesting periods of four years. | ||||||
Share Based Compensation Arrangement By Share Based Payment Award Unit Options To Vest In Three Years | 227,000 | ||||||
Share Based Compensation Arrangement By Share Based Payment Award Number Of Outstanding Units To Vest Within Next Twelve Months | 614,415 | ||||||
Share Based Compensation Arrangement By Share Based Payment Award Number Of Common Units Purchased And Retired From Employees To Cover Employee Related Taxes | 66,321 | 0 | 24,052 | ||||
Share Based Compensation Arrangement By Share Based Payment Award Cost Of Common Units Purchased And Retired From Employees To Cover Employee Related Taxes | 2,200,000 | 700,000 | |||||
Distribution equivalent rights paid on unissued units under incentive plans | 4,300,000 | 3,100,000 | 2,000,000 | ||||
Outstanding, beginning of year | $36.32 | [4],[5] | $33.21 | [4],[5] | $21.63 | ||
Granted | $33.03 | $38.96 | $34.94 | ||||
Forfeited | $37.09 | $36.11 | $29.83 | ||||
Vested | $34.71 | [6],[7] | $31.88 | [6],[7] | $17.88 | [6],[7] | |
Outstanding, end of year | $35.30 | [4],[5] | $36.32 | [4],[5] | $33.21 | [4],[5] | |
Non-cash compensation expense recognized | 25,116,000 | 19,344,000 | 11,635,000 | ||||
Outstanding, beginning of year (Units) | 1,446,553 | [4],[5] | 1,053,242 | [4],[5] | 394,489 | ||
Granted (Units) | 738,727 | 744,997 | 907,637 | ||||
Forfeited (Units) | -37,075 | -61,550 | -67,675 | ||||
Vested (Units) | -463,916 | [6],[7] | -290,136 | [6],[7] | -181,209 | [6],[7] | |
Outstanding, end of year (Units) | 1,684,289 | [4],[5] | 1,446,553 | [4],[5] | 1,053,242 | [4],[5] | |
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested In Period Intrinsic Value | 15,400,000 | 10,700,000 | 5,500,000 | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Maturities | 4,684 | 1,677 | 792 | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Total Share-based Liabilities Paid | 155,000 | 58,000 | 28,000 | ||||
Share Based Compensation Arrangement By Share Based Payment Award Other Than Options Outstanding Intrinsic Value | 45,900,000 | 50,700,000 | |||||
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Units Classified Within Liabilities | 25,778 | 22,539 | |||||
Unrecognized compensation expense related to unvested phantom units | $27,900,000 | ||||||
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition | 1 year 10 months 24 days | ||||||
[1] | The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2014 was $8.6 million. | ||||||
[2] | There was approximately $0.2 million and $0.1 million recognized as liabilities on the Partnership’s consolidated balance sheets at December 31, 2014 and 2013, respectively, representing 26,579 and 16,084 units, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units were $21.16 and $22.15 at December 31, 2014 and 2013, respectively. | ||||||
[3] | The intrinsic values of phantom unit awards vested during the years ended December 31, 2014 and 2013 were $5.4 million and $6.1 million, respectively. No phantom unit awards vested during the year ended December 31, 2012. | ||||||
[4] | (3)The aggregate intrinsic values for phantom unit awards outstanding at December 31, 2014 and 2013 were $45.9 million and $50.7 million, respectively. | ||||||
[5] | (4)There were 25,778 and 22,539 outstanding phantom unit awards at December 31, 2014 and 2013, respectively, which were classified as liabilities due to a cash option available on the related phantom unit awards. | ||||||
[6] | (1)The intrinsic values for phantom unit awards vested during the years ended December 31, 2014, 2013 and 2012 were $15.4 million, $10.7 million and $5.5 million, respectively. | ||||||
[7] | (2)There were 4,684, 1,677 and 792 vested phantom units, which were settled for approximately $155,000, $58,000 and $28,000 cash during the years ended December 31, 2014, 2013 and 2012, respectively. |
Benefit_Plans_APL_Unit_Option_
Benefit Plans (APL Unit Option Activity) (Details) (APL Unit Options, USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
APL Unit Options | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Phantom Units, Restricted Units and Unit Options Outstanding | 0 | ||
Share Based Compensation Arrangement By Share Based Payment Award Options Exercises In Period Total Intrinsic Value | $0 | $0 | $0 |
Operating_Segment_Information_1
Operating Segment Information (Narrative) (Details) | 12 Months Ended |
Dec. 31, 2014 | |
Segment | |
Segment Reporting [Abstract] | |
Number of reportable operating segments | 3 |
Operating_Segment_Information_2
Operating Segment Information (Operating Segment Data) (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | $992,534 | [1] | $963,980 | [1] | $851,889 | [1] | $860,300 | [1] | $761,629 | [2] | $649,989 | [2] | $643,795 | [2] | $522,102 | [2] | $3,668,703 | $2,577,515 | $1,521,443 |
Depreciation, depletion and amortization expense | -444,622 | -308,533 | -142,611 | ||||||||||||||||
Asset impairment | -580,654 | -81,880 | -9,507 | ||||||||||||||||
Gain (loss) on asset sales and disposal | 45,522 | -2,506 | -6,980 | ||||||||||||||||
Interest expense | -173,357 | -132,581 | -46,520 | ||||||||||||||||
Loss on early extinguishment of debt | -26,601 | ||||||||||||||||||
Atlas Resource Partners, L.P. | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Asset impairment | -562,600 | -38,000 | -9,507 | ||||||||||||||||
Gain (loss) on asset sales and disposal | 1,000 | ||||||||||||||||||
Atlas Pipeline "APL" | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Gain (loss) on asset sales and disposal | 1,500 | ||||||||||||||||||
Reportable Legal Entities | Atlas Resource Partners, L.P. | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | 685,560 | 467,655 | 267,629 | ||||||||||||||||
Operating costs and expenses | -425,000 | -348,812 | -246,267 | ||||||||||||||||
Depreciation, depletion and amortization expense | -233,731 | -136,763 | -52,582 | ||||||||||||||||
Asset impairment | -573,774 | -38,014 | -9,507 | ||||||||||||||||
Gain (loss) on asset sales and disposal | -1,869 | -987 | -6,980 | ||||||||||||||||
Interest expense | -62,144 | -34,324 | -4,195 | ||||||||||||||||
Segment loss | -610,958 | -91,245 | -51,902 | ||||||||||||||||
Reportable Legal Entities | Atlas Pipeline "APL" | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | 2,961,113 | 2,102,113 | 1,252,674 | ||||||||||||||||
Operating costs and expenses | -2,483,160 | -1,863,510 | -1,052,826 | ||||||||||||||||
Depreciation, depletion and amortization expense | -202,543 | -168,617 | -90,029 | ||||||||||||||||
Asset impairment | -43,866 | ||||||||||||||||||
Gain (loss) on asset sales and disposal | 47,381 | -1,519 | |||||||||||||||||
Interest expense | -93,147 | -89,637 | -41,760 | ||||||||||||||||
Segment loss | 229,644 | -91,637 | 68,059 | ||||||||||||||||
Loss on early extinguishment of debt | -26,601 | ||||||||||||||||||
Operating Segments | Corporate and Other | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | 22,030 | 7,747 | 1,140 | ||||||||||||||||
Operating costs and expenses | -72,822 | -41,690 | -33,613 | ||||||||||||||||
Depreciation, depletion and amortization expense | -8,348 | -3,153 | |||||||||||||||||
Asset impairment | -6,880 | ||||||||||||||||||
Gain (loss) on asset sales and disposal | 10 | ||||||||||||||||||
Interest expense | -18,066 | -8,620 | -565 | ||||||||||||||||
Segment loss | ($84,076) | ($45,716) | ($33,038) | ||||||||||||||||
[1] | For the first, second, third and fourth quarters of the year ended December 31, 2014, approximately 4,111,000, 4,049,000, 5,082,000 and 4,637,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit because the inclusion of such units would have been anti-dilutive. | ||||||||||||||||||
[2] | For the first, second, third and fourth quarters of the year ended December 31, 2013, approximately 3,594,000, 4,092,000, 4,196,000 and 4,091,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit because the inclusion of such units would have been anti-dilutive. |
Operating_Segment_Information_3
Operating Segment Information (Reconciliation of Segment Income (Loss) to Net Loss) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Segment Reporting Information [Line Items] | |||
Net loss | ($465,390) | ($228,598) | ($16,881) |
Reportable Legal Entities | Atlas Resource Partners, L.P. | |||
Segment Reporting Information [Line Items] | |||
Net loss | -610,958 | -91,245 | -51,902 |
Reportable Legal Entities | Atlas Pipeline "APL" | |||
Segment Reporting Information [Line Items] | |||
Net loss | 229,644 | -91,637 | 68,059 |
Operating Segments | Corporate and Other | |||
Segment Reporting Information [Line Items] | |||
Net loss | ($84,076) | ($45,716) | ($33,038) |
Operating_Segment_Information_4
Operating Segment Information (Reconciliation of Segment Revenues to Total Revenues) (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Total revenues | $992,534 | [1] | $963,980 | [1] | $851,889 | [1] | $860,300 | [1] | $761,629 | [2] | $649,989 | [2] | $643,795 | [2] | $522,102 | [2] | $3,668,703 | $2,577,515 | $1,521,443 |
Reportable Legal Entities | Atlas Resource Partners, L.P. | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Total revenues | 685,560 | 467,655 | 267,629 | ||||||||||||||||
Reportable Legal Entities | Atlas Pipeline "APL" | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Total revenues | 2,961,113 | 2,102,113 | 1,252,674 | ||||||||||||||||
Operating Segments | Corporate and Other | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Total revenues | $22,030 | $7,747 | $1,140 | ||||||||||||||||
[1] | For the first, second, third and fourth quarters of the year ended December 31, 2014, approximately 4,111,000, 4,049,000, 5,082,000 and 4,637,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit because the inclusion of such units would have been anti-dilutive. | ||||||||||||||||||
[2] | For the first, second, third and fourth quarters of the year ended December 31, 2013, approximately 3,594,000, 4,092,000, 4,196,000 and 4,091,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit because the inclusion of such units would have been anti-dilutive. |
Operating_Segment_Information_5
Operating Segment Information (Balance Sheet) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Segment Reporting Information [Line Items] | ||
Goodwill | $379,402 | $400,356 |
Total assets | 7,866,636 | 6,792,641 |
Reportable Legal Entities | Atlas Resource Partners, L.P. | ||
Segment Reporting Information [Line Items] | ||
Goodwill | 13,639 | 31,784 |
Total assets | 2,727,575 | 2,343,800 |
Reportable Legal Entities | Atlas Pipeline "APL" | ||
Segment Reporting Information [Line Items] | ||
Goodwill | 365,763 | 368,572 |
Total assets | 4,824,733 | 4,327,845 |
Operating Segments | Corporate and Other | ||
Segment Reporting Information [Line Items] | ||
Total assets | 314,328 | 120,996 |
Operating Segments | Atlas Resource Partners, L.P. | ||
Segment Reporting Information [Line Items] | ||
Goodwill | 13,639 | 31,784 |
Operating Segments | Atlas Pipeline "APL" | ||
Segment Reporting Information [Line Items] | ||
Goodwill | $365,763 | $368,572 |
Operating_Segment_Information_6
Operating Segment Information (Capital Expenditures) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Segment Reporting Information [Line Items] | |||
Capital expenditures | $873,383 | $718,040 | $500,759 |
Reportable Legal Entities | Atlas Resource Partners, L.P. | |||
Segment Reporting Information [Line Items] | |||
Capital expenditures | 212,634 | 263,537 | 127,226 |
Reportable Legal Entities | Atlas Pipeline "APL" | |||
Segment Reporting Information [Line Items] | |||
Capital expenditures | 647,747 | 450,560 | 373,533 |
Operating Segments | Corporate and Other | |||
Segment Reporting Information [Line Items] | |||
Capital expenditures | $13,002 | $3,943 |
Subsequent_Events_Targa_Resour
Subsequent Events (Targa Resources Corp) (Details) (USD $) | 12 Months Ended | 1 Months Ended | 0 Months Ended | |
Dec. 31, 2014 | Feb. 28, 2015 | Dec. 31, 2012 | Oct. 13, 2014 | |
Lawsuits | Lawsuits | |||
Subsequent Event [Line Items] | ||||
Business Acquisition, Date of Acquisition Agreement | 1-Apr-12 | |||
Voluntarily settled and dismissed, lawsuits | 2 | |||
Subsequent Event | ||||
Subsequent Event [Line Items] | ||||
Voluntarily settled and dismissed, lawsuits | 2 | |||
Development Subsidiary | ||||
Subsequent Event [Line Items] | ||||
Common limited partner ownership interest | 1.70% | |||
Lightfoot Capital Partners, LP | ||||
Subsequent Event [Line Items] | ||||
General partner ownership interest | 15.90% | |||
Common limited partner ownership interest | 12.00% | |||
Atlas Pipeline "APL" | ||||
Subsequent Event [Line Items] | ||||
Consideration received on merger transaction, per share | 0.5846 | |||
Consideration received on merger transaction, per share | 1.26 | |||
General partner ownership interest | 2.00% | 2.00% | ||
Common limited partner ownership interest | 5.50% | |||
Atlas Resource Partners, L.P. | ||||
Subsequent Event [Line Items] | ||||
General partner ownership interest | 100.00% | |||
Common limited partner ownership interest | 27.70% | |||
Common limited partner interest in ARP, units | 20,962,485 | |||
Targa Resources Corp | ||||
Subsequent Event [Line Items] | ||||
Consideration received on merger transaction, per share | 0.1809 | |||
Consideration received on merger transaction, per share | $9.12 | |||
Targa Resources Corp | Merger Agreement | ||||
Subsequent Event [Line Items] | ||||
Business Acquisition, Date of Acquisition Agreement | 13-Oct-14 | |||
Targa Resources Corp | Spin-Off Agreement | Lightfoot Capital Partners, LP | ||||
Subsequent Event [Line Items] | ||||
General partner ownership interest | 15.90% | |||
Common limited partner ownership interest | 12.00% | |||
Targa Resources Corp | Spin-Off Agreement | Arc Logistics Partners, L.P. | ||||
Subsequent Event [Line Items] | ||||
Common limited partner ownership interest | 40.00% | |||
Targa Resources Corp | Spin-Off Agreement | General Partner | Development Subsidiary | ||||
Subsequent Event [Line Items] | ||||
General partner ownership interest | 80.00% | |||
Targa Resources Corp | Spin-Off Agreement | Preferred Limited Partner Units | Development Subsidiary | ||||
Subsequent Event [Line Items] | ||||
Common limited partner ownership interest | 1.70% | |||
Targa Resources Corp | Spin-Off Agreement | Atlas Resource Partners, L.P. | General Partner | ||||
Subsequent Event [Line Items] | ||||
General partner ownership interest | 100.00% | |||
Common limited partner interest in ARP, units | 20,962,485 | |||
Targa Resources Corp | Spin-Off Agreement | Atlas Resource Partners, L.P. | Preferred Limited Partner Units | ||||
Subsequent Event [Line Items] | ||||
Common limited partner ownership interest | 27.70% | |||
Common limited partner interest in ARP, units | 3,749,986 |
Subsequent_Events_Cash_Distrib
Subsequent Events (Cash Distributions) (Details) (USD $) | 1 Months Ended | 3 Months Ended | 0 Months Ended | 12 Months Ended | |||||||||||
In Thousands, except Per Share data, unless otherwise specified | Mar. 31, 2012 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Feb. 23, 2015 | Jan. 28, 2015 | Dec. 31, 2014 |
Subsequent Event [Line Items] | |||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $0.40 | $0.52 | $0.49 | $0.46 | $0.46 | $0.46 | $0.44 | $0.31 | $0.30 | $0.27 | $0.25 | $0.25 | |||
Subsequent Event | Cash Distribution Declared | |||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||
Distribution Made to Member or Limited Partner, Declaration Date | 23-Feb-15 | 28-Jan-15 | |||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $0.11 | $0.20 | |||||||||||||
Subsequent Event | Cash Distribution Paid | |||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $9,900 | $18,900 | |||||||||||||
Distribution Made to Member or Limited Partner, Date of Record | 10-Mar-15 | 9-Feb-15 | |||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 17-Mar-15 | 13-Feb-15 | |||||||||||||
ATLS | |||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||
Distribution Made to Member or Limited Partner, Date of Record | 28-Feb-12 | ||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 13-Mar-12 | ||||||||||||||
ATLS | Subsequent Event | Cash Distribution Declared | |||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||
Distribution Made to Member or Limited Partner, Declaration Date | 28-Jan-15 | ||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $0.52 | ||||||||||||||
ATLS | Subsequent Event | Cash Distribution Paid | |||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $27,100 | ||||||||||||||
Distribution Made to Member or Limited Partner, Date of Record | 9-Feb-15 | ||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 19-Feb-15 |
Subsequent_Events_Credit_Facil
Subsequent Events (Credit Facility Amendment) (Details) (Revolving Credit Facility, USD $) | 12 Months Ended | 6 Months Ended | 0 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Jun. 30, 2014 | Feb. 23, 2015 | Nov. 24, 2014 | Sep. 24, 2014 |
Subsequent Event [Line Items] | |||||
Line of Credit Facility, Current Borrowing Capacity | $900 | 825 | $900 | $825 | |
Required Total Funded Debt To EBITDA Ratio | 4.50% | ||||
Quarter ended March 31, 2015 | |||||
Subsequent Event [Line Items] | |||||
Required Total Funded Debt To EBITDA Ratio | 4.25% | 4.25% | |||
Fiscal quarters ending thereafter | |||||
Subsequent Event [Line Items] | |||||
Required Total Funded Debt To EBITDA Ratio | 4.00% | 4.00% | |||
Atlas Resource Partners, L.P. | |||||
Subsequent Event [Line Items] | |||||
Line of Credit Facility, Current Borrowing Capacity | 900 | ||||
Subsequent Event | Atlas Resource Partners, L.P. | |||||
Subsequent Event [Line Items] | |||||
Line of Credit Facility, Current Borrowing Capacity | 750 | ||||
Aggregate Principal Amount of Second Lien Debt | $300 | ||||
Percentage of stated amount of senior notes or additional second lien debt that borrowing base reduced | 25.00% | ||||
Subsequent Event | Atlas Resource Partners, L.P. | Borrowing base utilization is less than 90% | |||||
Subsequent Event [Line Items] | |||||
Percentage of borrowing base utilized | 90.00% | ||||
Subsequent Event | Atlas Resource Partners, L.P. | Borrowing base utilization is less than 90% | Eurodollar | |||||
Subsequent Event [Line Items] | |||||
Increase in applicable margin | 0.25% | ||||
Subsequent Event | Atlas Resource Partners, L.P. | Borrowing base utilization is less than 90% | Alternate Base Rate | |||||
Subsequent Event [Line Items] | |||||
Increase in applicable margin | 0.25% | ||||
Subsequent Event | Atlas Resource Partners, L.P. | Quarter ended March 31, 2015 | |||||
Subsequent Event [Line Items] | |||||
Required Total Funded Debt To EBITDA Ratio | 5.25% | ||||
Subsequent Event | Atlas Resource Partners, L.P. | Quarter Ended June Thirty Two Thousand And Fifteen | |||||
Subsequent Event [Line Items] | |||||
Required Total Funded Debt To EBITDA Ratio | 5.25% | ||||
Subsequent Event | Atlas Resource Partners, L.P. | Quarter Ended September Thirty Two Thousand And Fifteen | |||||
Subsequent Event [Line Items] | |||||
Required Total Funded Debt To EBITDA Ratio | 5.25% | ||||
Subsequent Event | Atlas Resource Partners, L.P. | Quarter Ended December Thirty First Two Thousand And Fifteen | |||||
Subsequent Event [Line Items] | |||||
Required Total Funded Debt To EBITDA Ratio | 5.25% | ||||
Subsequent Event | Atlas Resource Partners, L.P. | Quarter Ended March Thirty First Two Thousand And Sixteen | |||||
Subsequent Event [Line Items] | |||||
Required Total Funded Debt To EBITDA Ratio | 5.25% | ||||
Subsequent Event | Atlas Resource Partners, L.P. | Quarter Ended June Thirty Two Thousand And Sixteen | |||||
Subsequent Event [Line Items] | |||||
Required Total Funded Debt To EBITDA Ratio | 5.00% | ||||
Subsequent Event | Atlas Resource Partners, L.P. | Quarter Ended September Thirty Two Thousand And Sixteen | |||||
Subsequent Event [Line Items] | |||||
Required Total Funded Debt To EBITDA Ratio | 5.00% | ||||
Subsequent Event | Atlas Resource Partners, L.P. | Quarter Ended December Thirty First Two Thousand And Sixteen | |||||
Subsequent Event [Line Items] | |||||
Required Total Funded Debt To EBITDA Ratio | 5.00% | ||||
Subsequent Event | Atlas Resource Partners, L.P. | Quarter Ended March Thirty First Two Thousand And Seventeen | |||||
Subsequent Event [Line Items] | |||||
Required Total Funded Debt To EBITDA Ratio | 4.50% | ||||
Subsequent Event | Atlas Resource Partners, L.P. | Fiscal quarters ending thereafter | |||||
Subsequent Event [Line Items] | |||||
Required Total Funded Debt To EBITDA Ratio | 4.00% |
Subsequent_Events_Second_Lien_
Subsequent Events (Second Lien Term Loan Facility) (Details) (Second Lien Term Loan Facility, USD $) | 12 Months Ended | 0 Months Ended |
Dec. 31, 2014 | Feb. 23, 2015 | |
Subsequent Event [Line Items] | ||
Line of Credit Facility, Interest Rate Description | Borrowings under the Term Loan Facility bear interest, at ARP’s option, at either (i) LIBOR plus 9.0% or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, each plus 8.0% (an “ABR Loanâ€). Interest is generally payable at the applicable maturity date for Eurodollar loans and quarterly for ABR loans. | |
Incremental Term Loan | ||
Subsequent Event [Line Items] | ||
Line of Credit Facility, Expiration Date | 23-Feb-20 | |
Subsequent Event | ||
Subsequent Event [Line Items] | ||
Principal amount of term loan facility | $300,000,000 | |
Subsequent Event | London Interbank Offered Rate (LIBOR) | ||
Subsequent Event [Line Items] | ||
Debt instrument, basis spread on variable rate | 9.00% | |
Subsequent Event | Federal Funds Effective Swap Rate | ||
Subsequent Event [Line Items] | ||
Debt instrument, basis spread on variable rate | 0.50% | |
Subsequent Event | One Month L I B O R | ||
Subsequent Event [Line Items] | ||
Debt instrument, basis spread on variable rate | 1.00% | |
Subsequent Event | Base Rate | ||
Subsequent Event [Line Items] | ||
Debt instrument, basis spread on variable rate | 2.00% | |
Subsequent Event | Alternate Base Rate | ||
Subsequent Event [Line Items] | ||
Debt instrument, basis spread on variable rate | 8.00% | |
Subsequent Event | Debt Instrument, Redemption, Period Four | ||
Subsequent Event [Line Items] | ||
Principal amount prepaid for repayments | 0.00% | |
Subsequent Event | Atlas Resource Partners, L.P. | ||
Subsequent Event [Line Items] | ||
Revolving Credit Facility | $250,000,000 | |
Line of Credit Facility, Expiration Date | 23-Feb-20 | |
Net cash proceeds from the issuance or incurrence of debt | 100.00% | |
Excess net cash proceeds from certain asset sales and condemnation recoveries | 100.00% | |
Subsequent Event | Atlas Resource Partners, L.P. | Debt Instrument, Redemption, Period Two | ||
Subsequent Event [Line Items] | ||
Principal amount prepaid for repayments | 4.50% | |
Subsequent Event | Atlas Resource Partners, L.P. | Debt Instrument, Redemption, Period Three | ||
Subsequent Event [Line Items] | ||
Principal amount prepaid for repayments | 2.25% |
Subsequent_Events_Atlas_Resour
Subsequent Events (Atlas Resource Cash Distribution) (Details) (USD $) | 3 Months Ended | 0 Months Ended | 1 Months Ended | ||||||||||||||||||
In Thousands, except Per Share data, unless otherwise specified | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Feb. 23, 2015 | Jan. 28, 2015 | Nov. 30, 2014 | Oct. 31, 2014 | Aug. 31, 2014 | Jul. 31, 2014 | 31-May-14 | Apr. 30, 2014 | Feb. 28, 2014 | Jan. 31, 2014 |
Subsequent Event [Line Items] | |||||||||||||||||||||
Cash Distributions Paid | $27,015 | $25,435 | $23,865 | $23,681 | $23,649 | $22,611 | $15,928 | $15,410 | $13,866 | $12,831 | $12,830 | ||||||||||
Subsequent Event | Cash Distribution Declared | |||||||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||||||
Distribution Made to Member or Limited Partner, Declaration Date | 23-Feb-15 | 28-Jan-15 | |||||||||||||||||||
Subsequent Event | Cash Distribution Paid | |||||||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 17-Mar-15 | 13-Feb-15 | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Date of Record | 10-Mar-15 | 9-Feb-15 | |||||||||||||||||||
Atlas Resource Partners, L.P. | General Partner | |||||||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||||||
Cash Distributions Paid | 1,378 | 1,377 | 1,054 | 2,891 | 2,443 | 1,884 | 946 | 618 | 350 | 263 | 64 | 1,378 | 1,378 | 1,378 | 1,378 | 1,279 | 1,279 | 1,055 | 1,055 | ||
Atlas Resource Partners, L.P. | Subsequent Event | Cash Distribution Declared | |||||||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||||||
Distribution Made to Member or Limited Partner, Declaration Date | 23-Feb-15 | 28-Jan-15 | |||||||||||||||||||
Distribution Made to Limited Partner, Distributions Declared, Per Unit | 0.1083 | 0.1966 | |||||||||||||||||||
Atlas Resource Partners, L.P. | Subsequent Event | Cash Distribution Paid | |||||||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||||||
Cash Distributions Paid | 9,900 | 18,900 | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 17-Mar-15 | 13-Feb-15 | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Date of Record | 10-Mar-15 | 9-Feb-15 | |||||||||||||||||||
Atlas Resource Partners, L.P. | Subsequent Event | Cash Distribution Paid | General Partner | |||||||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||||||
Cash Distributions Paid | 200 | 1,400 | |||||||||||||||||||
Atlas Resource Partners, L.P. | Subsequent Event | Cash Distribution Paid | Preferred Limited Partner Units | |||||||||||||||||||||
Subsequent Event [Line Items] | |||||||||||||||||||||
Cash Distributions Paid | 400 | 700 |
Subsequent_Events_Atlas_Pipeli
Subsequent Events (Atlas Pipeline Notice of Preferred Unit Redemption) (Details) (Subsequent Event, Class E APL Preferred Units, USD $) | Jan. 27, 2015 |
Subsequent Event | Class E APL Preferred Units | |
Subsequent Event [Line Items] | |
Preferred Stock, redemption price Per Share | $25 |
Subsequent_Events_Atlas_Pipeli1
Subsequent Events (Atlas Pipeline Conversion of Preferred Units) (Details) (Subsequent Event, Class D APL Preferred Units, USD $) | 0 Months Ended |
Jan. 22, 2015 | |
Subsequent Event | Class D APL Preferred Units | |
Subsequent Event [Line Items] | |
Conversion price per unit | $29.75 |
Issued common limited partner | 15,389,575 |
Subsequent_Events_Atlas_Pipeli2
Subsequent Events (Atlas Pipeline Redemption of APL Senior Notes) (Details) (Subsequent Event, USD $) | 0 Months Ended | 1 Months Ended |
In Millions, unless otherwise specified | Jan. 15, 2015 | Jan. 29, 2015 |
6.625% APL Senior Notes | ||
Subsequent Event [Line Items] | ||
Aggregate principal amount | $500 | |
4.75% APL Senior Notes | ||
Subsequent Event [Line Items] | ||
Aggregate principal amount | 400 | |
4.75% APL Senior Notes | Targa Resource Partners L P | ||
Subsequent Event [Line Items] | ||
Debt instrument outstanding percentage | 98.30% | |
5.875% APL Senior Notes | ||
Subsequent Event [Line Items] | ||
Aggregate principal amount | $650 | |
5.875% APL Senior Notes | Targa Resources Partners L P | ||
Subsequent Event [Line Items] | ||
Debt instrument outstanding percentage | 91.00% |
Subsequent_Events_Distribution
Subsequent Events (Distribution) (Details) (USD $) | 3 Months Ended | 12 Months Ended | 0 Months Ended | |||||||||||||
In Thousands, except Per Share data, unless otherwise specified | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | 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, 2014 | Feb. 23, 2015 | Jan. 28, 2015 | Jan. 09, 2015 | Jan. 15, 2015 |
Subsequent Event [Line Items] | ||||||||||||||||
Cash Distributions Paid | $27,015 | $25,435 | $23,865 | $23,681 | $23,649 | $22,611 | $15,928 | $15,410 | $13,866 | $12,831 | $12,830 | |||||
Cash Distribution Declared | Atlas Pipeline "APL" | ||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||
Distribution Made to Member or Limited Partner, Declaration Date | 9-Jan-15 | |||||||||||||||
Cash Distribution Paid | Atlas Pipeline "APL" | ||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 13-Feb-15 | |||||||||||||||
Distribution Made to Member or Limited Partner, Date of Record | 21-Jan-15 | |||||||||||||||
Class E Preferred Units | ||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||
Distribution Made to Limited Partner, Distribution Date | 15-Jan-15 | |||||||||||||||
Subsequent Event | Cash Distribution Declared | ||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||
Distribution Made to Member or Limited Partner, Declaration Date | 23-Feb-15 | 28-Jan-15 | ||||||||||||||
Subsequent Event | Cash Distribution Declared | Atlas Pipeline "APL" | ||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||
Distribution Made to Member or Limited Partner, Declaration Date | 9-Jan-15 | |||||||||||||||
Distribution Made to Limited Partner, Distributions Declared, Per Unit | $0.64 | |||||||||||||||
Subsequent Event | Cash Distribution Paid | ||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 17-Mar-15 | 13-Feb-15 | ||||||||||||||
Distribution Made to Member or Limited Partner, Date of Record | 10-Mar-15 | 9-Feb-15 | ||||||||||||||
Subsequent Event | Cash Distribution Paid | Atlas Pipeline "APL" | ||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||
Cash Distributions Paid | 62,200 | |||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 13-Feb-15 | |||||||||||||||
Distribution Made to Member or Limited Partner, Date of Record | 21-Jan-15 | |||||||||||||||
Subsequent Event | Cash Distribution Paid | Atlas Pipeline "APL" | General Partner | ||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||
Cash Distributions Paid | 8,100 | |||||||||||||||
Subsequent Event | Class E Preferred Units | ||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit there after | $0.52 | |||||||||||||||
Cash Distributions Paid | $2,600 |
Supplemental_Oil_and_Gas_Infor2
Supplemental Oil and Gas Information (Reserve Quantity Information) (Details) | 12 Months Ended | |||||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||||
Mcf | Mcf | Mcf | Mcf | |||||
Natural Gas | ||||||||
Reserve Quantities [Line Items] | ||||||||
Balance | 1,003,779,503 | 573,774,257 | [1] | 157,676,431 | ||||
Extensions, discoveries and other additions | 58,461,204 | [2] | 90,098,219 | [2] | 6,756,817 | [2] | ||
Sales of reserves in-place | -169,035 | -2,755,155 | ||||||
Purchase of reserves in-place | 88,635,059 | 493,481,302 | 462,504,519 | |||||
Transfers to limited partnerships | -4,887,095 | -2,485,210 | ||||||
Revisions | 5,947,622 | -88,484,468 | [3] | -27,760,192 | [4] | |||
Production | -86,889,803 | -59,849,442 | -25,403,318 | |||||
Balance | 1,064,877,455 | 1,003,779,503 | 573,774,257 | [1] | ||||
Proved developed reserves | 889,073,136 | 766,872,394 | 338,655,324 | 138,403,225 | ||||
Proved undeveloped reserves | 175,804,319 | 236,907,109 | 235,118,932 | 19,273,206 | ||||
Oil | ||||||||
Reserve Quantities [Line Items] | ||||||||
Balance | 14,988,824 | [5] | 8,868,836 | [1],[5] | 1,646,299 | [5] | ||
Extensions, discoveries and other additions | 3,372,177 | [2],[5] | 8,255,531 | [2],[5] | 10,688 | [2],[5] | ||
Sales of reserves in-place | -1,519 | [5] | ||||||
Purchase of reserves in-place | 51,168,449 | [5] | 1,964 | [5] | 7,485,998 | [5] | ||
Transfers to limited partnerships | -684,613 | [5] | -239,910 | [5] | ||||
Revisions | -4,639,546 | [5] | -1,412,371 | [3],[5] | -153,413 | [4],[5] | ||
Production | -1,254,247 | [5] | -485,226 | [5] | -120,736 | [5] | ||
Balance | 62,949,525 | [5] | 14,988,824 | [5] | 8,868,836 | [1],[5] | ||
Proved developed reserves | 31,150,298 | [5] | 3,459,260 | [5] | 3,400,447 | [5] | 1,638,083 | [5] |
Proved undeveloped reserves | 31,799,227 | [5] | 11,529,564 | [5] | 5,468,389 | [5] | 8,216 | [5] |
Natural Gas Liquids | ||||||||
Reserve Quantities [Line Items] | ||||||||
Balance | 18,957,016 | [5] | 16,061,897 | [1],[5] | ||||
Extensions, discoveries and other additions | 3,986,986 | [2],[5] | 8,197,272 | [2],[5] | ||||
Sales of reserves in-place | -11,326 | [5] | -4,625 | [5] | ||||
Purchase of reserves in-place | 3,567,531 | [5] | 55,187 | [5] | 16,212,356 | [5] | ||
Transfers to limited partnerships | 956,810 | [5] | -258,381 | [5] | ||||
Revisions | -2,689,372 | [5] | -3,826,744 | [3],[5] | 206,091 | [4],[5] | ||
Production | -1,387,865 | [5] | -1,267,590 | [5] | -356,550 | [5] | ||
Balance | 23,379,780 | [5] | 18,957,016 | [5] | 16,061,897 | [1],[5] | ||
Proved developed reserves | 12,209,825 | [5] | 7,676,389 | [5] | 7,884,778 | [5] | ||
Proved undeveloped reserves | 11,169,954 | [5] | 11,280,627 | [5] | 8,177,120 | [5] | ||
[1] | Prior to the Arkoma Acquisition on July 31, 2013, Partnership had no oil and gas reserves. At December 31, 2014, there were no proved undeveloped reserves related to Partnership’s oil and gas assets. | |||||||
[2] | Principally includes increases of proved reserves due to the addition of Marble Falls wells. | |||||||
[3] | Represents a downward revision primarily due to a reduction of ARP’s five year drilling plans in the Barnett Shale and pricing scenario revisions. | |||||||
[4] | Represents a downward revision and related impairment charge related to ARP’s shallow natural gas wells in Michigan and Colorado due to declines in the average 1st day of the month price for the year ended December 31, 2012 as compared with the year ended December 31, 2011. | |||||||
[5] | Oil includes NGL information at January 1, 2012, which was less than 500 MBbls. |
Supplemental_Oil_and_Gas_Infor3
Supplemental Oil and Gas Information (Schedule of Capitalized Costs Related to Oil and Gas Producing Activities) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items] | ||
Proved properties | $3,639,833 | $2,557,797 |
Unproved properties | 217,321 | 211,851 |
Support equipment | 37,359 | 23,258 |
Capitalized Costs Related To Oil And Gas Producing Activities | ||
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items] | ||
Proved properties | 3,693,833 | 2,557,797 |
Unproved properties | 217,322 | 211,851 |
Support equipment | 37,359 | 23,258 |
Total natural gas and oil properties | 3,894,513 | 2,792,906 |
Accumulated depreciation, depletion and amortization | -1,518,686 | -649,635 |
Net capitalized costs | $2,375,827 | $2,143,271 |
Supplemental_Oil_and_Gas_Infor4
Supplemental Oil and Gas Information (Schedule of Results of Operations from Oil and gas Producing Activities) (Details) (USD $) | 12 Months Ended | |||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||
Supplemental Oil and Gas Information (Unaudited) [Abstract] | ||||||
Revenues | $475,758,000 | $273,906,000 | $92,901,000 | |||
Production costs | -184,296,000 | -100,178,000 | -26,624,000 | |||
Depreciation, depletion and amortization | -231,638,000 | -132,860,000 | -47,000,000 | |||
Long-lived asset impairment | -580,654,000 | [1] | -38,014,000 | [1] | -9,507,000 | [1] |
Results of Operations, Income before Income Taxes, Total | -520,830,000 | 2,854,000 | 9,770,000 | |||
Asset Impairment With In Property Plant And Equipment Net | 562,600,000 | |||||
Asset impairment of future hedge gains | 82,300,000 | |||||
Goodwill, Impairment Loss | 18,100,000 | |||||
Chattanooga and New Albany Shales | ||||||
Supplemental Oil and Gas Information (Unaudited) [Abstract] | ||||||
Long-lived asset impairment | 38,000,000 | |||||
Antrim And Niobrara Shales | ||||||
Supplemental Oil and Gas Information (Unaudited) [Abstract] | ||||||
Long-lived asset impairment | $9,500,000 | |||||
[1] | During the year ended December 31, 2014, the Partnership recognized $580.7 million of asset impairment consisting of $562.6 million related to oil and gas properties within property, plant, and equipment, net on the Partnership’s consolidated balance sheet primarily for ARP’s Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income, and $18.1 million goodwill impairment resulting from the decline in overall commodity prices. During the year ended December 31, 2013, ARP recognized $38.0 million of impairment primarily related to its shallow natural gas wells in the New Albany shale and unproved acreage in the Chattanooga and New Albany shales. During the year ended December 31, 2012, ARP recognized $9.5 million of impairment related to its shallow natural gas wells in the Antrim and Niobrara shales. |
Supplemental_Oil_and_Gas_Infor5
Supplemental Oil and Gas Information (Schedule of Costs Incurred in Oil and gas Producing Activities) (Details) (USD $) | 12 Months Ended | |||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Supplemental Oil and Gas Information (Unaudited) [Abstract] | ||||||
Proved properties | $754,197 | $863,421 | $528,684 | |||
Unproved properties | 10,978 | 895 | 213,638 | |||
Exploration costs | 722 | [1] | 1,053 | [1] | 1,026 | [1] |
Development costs | 177,726 | 214,383 | 83,538 | |||
Total costs incurred in oil & gas producing activities | $943,623 | $1,079,752 | $826,886 | |||
[1] | There were no exploratory wells drilled during the years ended December 31, 2014, 2013 and 2012. |
Supplemental_Oil_and_Gas_Infor6
Supplemental Oil and Gas Information (Schedule of Standardized Measure of Estimated Discounted Future Net Cash Flows) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Supplemental Oil and Gas Information (Unaudited) [Abstract] | |||
Future cash inflows | $10,802,697 | $5,268,148 | $2,930,514 |
Future production costs | -4,561,129 | -2,397,997 | -1,185,084 |
Future development costs | -1,623,218 | -752,369 | -441,423 |
Future net cash flows | 4,618,350 | 2,117,782 | 1,304,007 |
Less 10% annual discount for estimated timing of cash flows | -2,381,586 | -1,038,491 | -680,331 |
Standardized measure of discounted future net cash flows | $2,236,764 | $1,079,291 | $623,676 |
Supplemental_Oil_and_Gas_Infor7
Supplemental Oil and Gas Information (Schedule of Changes in Discounted Future Net Cash Flows) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Supplemental Oil and Gas Information (Unaudited) [Abstract] | |||
Balance, beginning of year | $1,079,291 | $623,676 | $219,859 |
Sales and transfers of oil and gas, net of related costs | -275,789 | -171,409 | -54,969 |
Net changes in prices and production costs | 339,776 | 85,191 | -87 |
Revisions of previous quantity estimates | -33,526 | -1,881 | -6,378 |
Development costs incurred | 52,077 | 27,245 | 575 |
Changes in future development costs | -90,887 | -21,579 | |
Transfers to limited partnerships | -2,966 | -53,392 | |
Extensions, discoveries, and improved recovery less related costs | 69,436 | 143,338 | 64 |
Purchases of reserves in-place | 1,018,345 | 516,985 | 510,467 |
Sales of reserves in-place | -332 | -2,053 | |
Accretion of discount | 107,929 | 62,368 | 21,986 |
Estimated settlement of asset retirement obligations | -16,824 | -18,858 | -2,823 |
Estimated proceeds on disposals of well equipment | -21,896 | 17,052 | 3,806 |
Changes in production rates timing and other | 12,130 | -127,392 | -68,824 |
Outstanding, end of year | $2,236,764 | $1,079,291 | $623,676 |
Quarterly_Results_Schedule_of_
Quarterly Results - Schedule of Quarterly Financial Information (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||||||
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||||||
Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||||
Revenues | $992,534 | [1] | $963,980 | [1] | $851,889 | [1] | $860,300 | [1] | $761,629 | [2] | $649,989 | [2] | $643,795 | [2] | $522,102 | [2] | $3,668,703 | $2,577,515 | $1,521,443 |
Net income (loss) | -497,769 | [1] | 31,513 | [1] | 21,933 | [1] | -21,067 | [1] | -102,169 | [2] | -79,546 | [2] | -5,189 | [2] | -41,694 | [2] | -465,390 | -228,598 | -16,881 |
(Income) loss attributable to non-controlling interests | 338,544 | [1] | -40,598 | [1] | -31,956 | [1] | 7,142 | [1] | 75,169 | [2] | 52,022 | [2] | -3,058 | [2] | 29,098 | [2] | -273,132 | -153,231 | 35,532 |
Net loss attributable to common limited partners | ($159,225) | [1] | ($9,085) | [1] | ($10,023) | [1] | ($13,925) | [1] | ($27,000) | [2] | ($27,524) | [2] | ($8,247) | [2] | ($12,596) | [2] | ($192,258) | ($75,367) | ($52,413) |
Net loss attributable to common limited partners per unit: | |||||||||||||||||||
Basic | ($3.06) | [1] | ($0.18) | [1] | ($0.19) | [1] | ($0.27) | [1] | ($0.53) | [2] | ($0.54) | [2] | ($0.16) | [2] | ($0.25) | [2] | |||
Diluted | ($3.06) | [1] | ($0.18) | [1] | ($0.19) | [1] | ($0.27) | [1] | ($0.53) | [2] | ($0.54) | [2] | ($0.16) | [2] | ($0.25) | [2] | |||
Antidilutive Securities Excluded From Computation Of Diluted Earnings Attributable To Common Limited Partners Outstanding Units | 4,637,000 | 5,082,000 | 4,049,000 | 4,111,000 | 4,091,000 | 4,196,000 | 4,092,000 | 3,594,000 | |||||||||||
[1] | For the first, second, third and fourth quarters of the year ended December 31, 2014, approximately 4,111,000, 4,049,000, 5,082,000 and 4,637,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit because the inclusion of such units would have been anti-dilutive. | ||||||||||||||||||
[2] | For the first, second, third and fourth quarters of the year ended December 31, 2013, approximately 3,594,000, 4,092,000, 4,196,000 and 4,091,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit because the inclusion of such units would have been anti-dilutive. |