Document_and_Entity_Informatio
Document and Entity Information | 3 Months Ended | |
Mar. 31, 2014 | 5-May-14 | |
Document Document And Entity Information [Line Items] | ' | ' |
Document Type | '10-Q | ' |
Amendment Flag | 'false | ' |
Document Period End Date | 31-Mar-14 | ' |
Document Fiscal Year Focus | '2014 | ' |
Document Fiscal Period Focus | 'Q1 | ' |
Entity Registrant Name | 'Atlas Energy, L.P. | ' |
Entity Central Index Key | '0001347218 | ' |
Current Fiscal Year End Date | '--12-31 | ' |
Entity Filer Category | 'Large Accelerated Filer | ' |
Entity Common Stock, Shares Outstanding | ' | 51,878,278 |
Trading Symbol | 'ATLS | ' |
CONSOLIDATED_BALANCE_SHEETS
CONSOLIDATED BALANCE SHEETS (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Current assets: | ' | ' |
Cash and cash equivalents | $24,779 | $23,501 |
Accounts receivable | 327,031 | 279,464 |
Current portion of derivative asset | 161 | 2,066 |
Subscriptions receivable | ' | 47,692 |
Prepaid expenses and other | 42,213 | 27,612 |
Total current assets | 394,184 | 380,335 |
Property, plant and equipment, net | 5,024,505 | 4,910,875 |
Intangible assets, net | 655,679 | 697,234 |
Investment in joint ventures | 269,058 | 248,301 |
Goodwill, net | 402,180 | 400,356 |
Long-term derivative asset | 28,325 | 30,868 |
Other assets, net | 124,305 | 124,672 |
Total assets | 6,898,236 | 6,792,641 |
Current liabilities: | ' | ' |
Current portion of long-term debt | 2,794 | 2,924 |
Accounts payable | 187,899 | 149,279 |
Liabilities associated with drilling contracts | ' | 49,377 |
Accrued producer liabilities | 191,066 | 152,309 |
Current portion of derivative liability | 36,929 | 17,630 |
Accrued interest | 21,689 | 47,402 |
Accrued well drilling and completion costs | 72,158 | 40,899 |
Accrued liabilities | 76,475 | 87,435 |
Total current liabilities | 589,010 | 547,255 |
Long-term debt, less current portion | 2,830,337 | 2,886,120 |
Deferred income taxes, net | 32,892 | 33,290 |
Asset retirement obligations | 92,927 | 91,214 |
Other long-term liabilities | 12,702 | 11,886 |
Commitments and contingencies | ' | ' |
Partners’ Capital: | ' | ' |
Common limited partners’ interests | 345,045 | 361,511 |
Accumulated other comprehensive income | 2,140 | 10,338 |
Total common limited partners' interest and accumulated other comprehensive income | 347,185 | 371,849 |
Non-controlling interests | 2,993,183 | 2,851,027 |
Total partners’ capital | 3,340,368 | 3,222,876 |
Total liabilities and partners' capital | $6,898,236 | $6,792,641 |
CONSOLIDATED_STATEMENTS_OF_OPE
CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) | 3 Months Ended | |
In Thousands, except Per Share data, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Revenues: | ' | ' |
Gas and oil production | $100,825 | $46,064 |
Well construction and completion | 49,377 | 56,478 |
Gathering and processing | 710,980 | 420,087 |
Administration and oversight | 1,729 | 1,085 |
Well services | 5,479 | 4,816 |
Loss on mark-to-market derivatives | -8,671 | -12,083 |
Other, net | 543 | 5,655 |
Total revenues | 860,262 | 522,102 |
Costs and expenses: | ' | ' |
Gas and oil production | 38,758 | 15,216 |
Well construction and completion | 42,936 | 49,112 |
Gathering and processing | 604,954 | 351,741 |
Well services | 2,482 | 2,318 |
General and administrative | 48,402 | 40,658 |
Depreciation, depletion and amortization | 101,278 | 51,666 |
Total costs and expenses | 838,810 | 510,711 |
Operating income | 21,452 | 11,391 |
Loss on asset sales and disposal | -1,603 | -702 |
Interest expense | -41,314 | -25,810 |
Loss on early extinguishment of debt | ' | -26,582 |
Net loss before tax | -21,465 | -41,703 |
Income tax benefit | -398 | -9 |
Net loss | -21,067 | -41,694 |
Loss attributable to non-controlling interests | 7,142 | 29,098 |
Net loss attributable to common limited partners | ($13,925) | ($12,596) |
Net loss attributable to common limited partners per unit: | ' | ' |
Basic and Diluted | ($0.27) | ($0.25) |
Weighted average common limited partner units outstanding: | ' | ' |
Basic and Diluted | 51,491 | 51,369 |
CONSOLIDATED_STATEMENTS_OF_COM
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Consolidated Statement of Comprehensive Income (Loss) [Abstract] | ' | ' |
Net loss | ($21,067) | ($41,694) |
Other comprehensive income (loss): | ' | ' |
Changes in fair value of derivative instruments accounted for as cash flow hedges | -36,255 | -24,944 |
Less: reclassification adjustment for realized (gains) losses of cash flow hedges in net loss | 14,569 | -993 |
Total other comprehensive loss | -21,686 | -25,937 |
Comprehensive loss | -42,753 | -67,631 |
Comprehensive loss attributable to non-controlling interests | 20,630 | 43,372 |
Comprehensive loss attributable to common limited partners | ($22,123) | ($24,259) |
CONSOLIDATED_STATEMENTS_OF_PAR
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL (USD $) | Total | Common Limited Partners' Capital | Accumulated Other Comprehensive Income | Non-Controlling Interest | Total Partners Capital |
In Thousands, except Share data | |||||
Balance at Dec. 31, 2013 | $3,222,876 | $361,511 | $10,338 | $2,851,027 | $3,222,876 |
Balance units at Dec. 31, 2013 | ' | 51,413,564 | ' | ' | ' |
Distributions to non-controlling interests | ' | ' | ' | -80,711 | -80,711 |
Contributions from Atlas Pipeline Partners, L.P.’s non-controlling interests | 6,840 | ' | ' | 6,840 | 6,840 |
Unissued common units under incentive plan | ' | 7,601 | ' | 8,645 | 16,246 |
Issuance of units under incentive plans | ' | 454,251 | ' | 87 | 87 |
Distributions paid to common limited partners | ' | -23,681 | ' | ' | -23,681 |
Distribution equivalent rights paid on unissued units under incentive plans | ' | -1,011 | ' | -1,524 | -2,535 |
Distributions payable by Atlas Resource Partners, L.P. | ' | ' | ' | -9,565 | -9,565 |
Gain on sale of subsidiary unit issuances | ' | 14,550 | ' | -14,550 | ' |
Non-controlling interests’ capital contributions | ' | ' | ' | 253,564 | 253,564 |
Other comprehensive loss | -21,686 | ' | -8,198 | -13,488 | -21,686 |
Net loss | ' | -13,925 | ' | -7,142 | -21,067 |
Balance at Mar. 31, 2014 | $3,340,368 | $345,045 | $2,140 | $2,993,183 | $3,340,368 |
Balance units at Mar. 31, 2014 | ' | 51,867,815 | ' | ' | ' |
CONSOLIDATED_STATEMENTS_OF_CAS
CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
CASH FLOWS FROM OPERATING ACTIVITIES: | ' | ' |
Net loss | ($21,067) | ($41,694) |
Adjustments to reconcile net loss to net cash used in operating activities: | ' | ' |
Depreciation, depletion and amortization | 101,278 | 51,666 |
Amortization of deferred financing costs | 4,109 | 6,246 |
Non-cash compensation expense | 16,805 | 14,153 |
Loss on asset sales and disposal | 1,603 | 702 |
Deferred income tax benefit | -398 | -9 |
Loss on early extinguishment of debt | ' | 26,582 |
Distributions paid to non-controlling interests | -82,235 | -47,998 |
Equity (income) loss in unconsolidated companies | 1,683 | -2,039 |
Distributions received from unconsolidated companies | 2,311 | 1,804 |
Changes in operating assets and liabilities: | ' | ' |
Accounts receivable, prepaid expenses and other | -15,501 | 53,580 |
Accounts payable and accrued liabilities | -9,031 | -84,766 |
Net cash used in operating activities | -443 | -21,773 |
CASH FLOWS FROM INVESTING ACTIVITIES: | ' | ' |
Capital expenditures | -172,750 | -167,003 |
Investment in joint venture | -1,903 | ' |
Other | -2,519 | -1,498 |
Net cash used in investing activities | -177,172 | -168,501 |
CASH FLOWS FROM FINANCING ACTIVITIES: | ' | ' |
Borrowings under credit facilities | 484,500 | 400,000 |
Repayments under credit facilities | -540,100 | -743,925 |
Net proceeds from issuance of subsidiary long-term debt | ' | 905,016 |
Repayments of subsidiary long-term debt | ' | -365,822 |
Net proceeds from subsidiary equity offerings | 253,564 | 14,144 |
Distributions paid to unitholders | -23,681 | -15,410 |
Contributions from non-controlling interests | 6,840 | ' |
Premium paid on retirement of Atlas Pipeline Partners, L.P. long-term debt | ' | -25,562 |
Deferred financing costs, distribution equivalent rights and other | -2,230 | -3,539 |
Net cash provided by financing activities | 178,893 | 164,902 |
Net change in cash and cash equivalents | 1,278 | -25,372 |
Cash and cash equivalents, beginning of year | 23,501 | 36,780 |
Cash and cash equivalents, end of period | $24,779 | $11,408 |
Basis_of_Presentation
Basis of Presentation | 3 Months Ended | |
Mar. 31, 2014 | ||
BASIS OF PRESENTATION | ' | |
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 March 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 March 31, 2014, the Partnership owned 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 33.7% 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; 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; and NGL transportation services in the southwestern region of the United States. At March 31, 2014, the Partnership owned a 2.0% general partner interest, all of the incentive distribution rights, and an approximate 5.8% 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 March 31, 2014, the Partnership had an approximate 15.9% general partner interest and 12.0% limited partner interest in Lightfoot (see Note 6); | |
· | Development Subsidiary, a new subsidiary partnership to conduct natural gas and oil operations initially in the mid-continent region of the United States, specifically in the Marble Falls formation in the Fort Worth Basin and Mississippi Lime area of the Anadarko basin in Oklahoma. At March 31, 2014, the Partnership owned an 15.2% limited partner interest in its Development Subsidiary and 83.1% of its outstanding general partner Class A units, which are entitled to receive 1.7% of the cash distributed without any obligation to make further capital contributions; and | |
· | Certain natural gas and oil producing assets. | |
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. | ||
The accompanying consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2013 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2013. Certain amounts in the prior year’s consolidated financial statements have been reclassified to conform to the current year presentation. The results of operations for the three months ended March 31, 2014 may not necessarily be indicative of the results of operations for the full year ending December 31, 2014. |
Summary_of_Significant_Account
Summary of Significant Accounting Policies | 3 Months Ended | ||||||||||||
Mar. 31, 2014 | |||||||||||||
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 March 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. | |||||||||||||
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. | |||||||||||||
The Partnership’s consolidated financial statements include APL’s 95% ownership interest in 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 4). | |||||||||||||
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. | |||||||||||||
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. | |||||||||||||
The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the three months ended March 31, 2014 and 2013 represent actual results in all material respects (see “Revenue Recognition”). | |||||||||||||
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 its customers. At March 31, 2014 and December 31, 2013, the Partnership had recorded no allowance for uncollectible accounts receivable on its consolidated balance sheets. | |||||||||||||
Inventory | |||||||||||||
The Partnership had $32.0 million and $19.7 million of inventory at March 31, 2014 and December 31, 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. | |||||||||||||
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 three months ended March 31, 2014 and 2013. | |||||||||||||
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, 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. There were no impairments of proved gas and oil properties recorded by ARP for the three months ended March 31, 2014 and 2013. | |||||||||||||
The impairments of proved and unproved properties during the year ended December 31, 2013 related to the carrying amounts of these gas and oil properties being in excess of ARP’s estimate of their fair values at December 31, 2013 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 natural gas 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 in the aggregate were 5.6% and 6.1% for the three months ended March 31, 2014 and 2013, respectively. The aggregate amounts of interest capitalized by ARP and APL were $5.5 million and $5.9 million for the three months ended March 31, 2014 and 2013, 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 TEAK acquisition (see Note 3), 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 acquisition of 100% of the equity interests of TEAK Midstream, LLC (“TEAK”) in 2013 (the “TEAK Acquisition”) (see Note 3), 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 March 31, 2014 and December 31, 2013 (in thousands): | |||||||||||||
March 31, | December 31, | Estimated | |||||||||||
2014 | 2013 | Useful Lives | |||||||||||
In Years | |||||||||||||
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 | $ | (216,288 | ) | $ | (194,801 | ) | |||||||
(13,449 | ) | (13,381 | ) | ||||||||||
Partnership management and operating contracts | |||||||||||||
$ | (229,737 | ) | $ | (208,182 | ) | ||||||||
Net Carrying Amount: | |||||||||||||
Customer contracts and relationships | $ | 654,784 | $ | 696,271 | |||||||||
Partnership management and operating contracts | 895 | 963 | |||||||||||
$ | 655,679 | $ | 697,234 | ||||||||||
Amortization expense on intangible assets was $21.6 million and $8.2 million for the three months ended March 31, 2014 and 2013, respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2014 - $80.3 million; 2015 - $74.3 million; 2016 - $74.2 million; 2017 - $68.1 million; and 2018 - $59.6 million. | |||||||||||||
Goodwill | |||||||||||||
The following table reflects the carrying amounts of goodwill by reportable operating segments at March 31, 2014 and December 31, 2013 (in thousands): | |||||||||||||
March 31, | December 31, | ||||||||||||
2014 | 2013 | ||||||||||||
Atlas Resource | $ | 31,784 | $ | 31,784 | |||||||||
Atlas Pipeline | 370,396 | 368,572 | |||||||||||
$ | 402,180 | $ | 400,356 | ||||||||||
At March 31, 2014, the Partnership had $402.2 million of goodwill, which consisted of $31.8 million related to prior ARP consummated acquisitions and $370.4 million related to APL’s Cardinal Acquisition in 2012 and TEAK Acquisition in 2013. The goodwill related to APL’s Cardinal Acquisition is a result of the strategic industry position and potential future synergies. The goodwill related to APL’s TEAK Acquisition is a result of the strategic industry position. The change in APL’s goodwill during the three months ended March 31, 2014 is primarily related to a $1.8 million increase in goodwill related to an adjustment of the fair value of assets acquired and liabilities assumed from the TEAK Acquisition (see Note 3). | |||||||||||||
ARP and APL test goodwill for impairment at each year end by comparing its reporting unit estimated fair values to carrying values. 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. | |||||||||||||
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 three months ended March 31, 2014 and 2013, no impairment indicators arose and no goodwill impairments were recognized for ARP or APL by the Partnership. | |||||||||||||
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 7). 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 March 31, 2014 or December 31, 2013 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 reflect 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 three months ended March 31, 2014 and 2013. | |||||||||||||
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 2010. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of March 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 March 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 11). | |||||||||||||
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 16), 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): | |||||||||||||
Three Months Ended | |||||||||||||
March 31, | |||||||||||||
Continuing Operations: | 2014 | 2013 | |||||||||||
Net loss | $ | (21,067 | ) | $ | (41,694 | ) | |||||||
Loss attributable to non-controlling interests | 7,142 | 29,098 | |||||||||||
Net loss attributable to common limited partners | (13,925 | ) | (12,596 | ) | |||||||||
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 | $ | (13,925 | ) | $ | (12,596 | ) | |||||||
(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 three months ended March 31, 2014 and 2013, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 2,398,000 and 2,216,000 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 16). | |||||||||||||
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): | |||||||||||||
Three Months Ended | |||||||||||||
March 31, | |||||||||||||
2014 | 2013 | ||||||||||||
Weighted average number of common limited partners per unit—basic | 51,491 | 51,369 | |||||||||||
Add effect of dilutive incentive awards(1) | — | — | |||||||||||
Weighted average number of common limited partners per unit—diluted | 51,491 | 51,369 | |||||||||||
(1) | For the three months ended March 31, 2014 and 2013, approximately 4,111,000 units and 3,594,000 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. | ||||||||||||
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, the Drilling Partnerships. ARP contracts with the Drilling Partnerships to drill partnership wells. The contracts require that the Drilling Partnerships pay ARP the full contract price upon execution. The income from a drilling contract is recognized as the services are performed using the percentage of completion method. The contracts are typically completed between 60 and 270 days. On an uncompleted contract, ARP classifies the difference between the contract payments it has received and the revenue earned as a current liability titled “Liabilities Associated with Drilling Contracts” on the Partnership’s consolidated balance sheets. ARP recognizes well services revenues at the time the services are performed. ARP is also entitled to receive management fees according to the respective partnership agreements and recognizes such fees as income when earned, which are included in administration and oversight revenues within the Partnership’s consolidated statements of operations. | |||||||||||||
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, treating and transportation 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, if any, at 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. In connection with its gathering, processing and transportation operations, APL enters into the following types of contractual relationships with its producers and shippers: | |||||||||||||
· | Fee-Based Contracts. These contracts provide a set fee for gathering and/or processing raw natural gas and for transporting NGLs. APL’s revenue is a function of the volume of natural gas that it gathers and processes or the volume of NGLs transported and is not directly dependent on the value of the natural gas or NGLs. However, sustained low commodity prices could result in a decline in volumes and a corresponding decrease in fee revenue. APL is also paid a separate compression fee on many of its gathering systems. The fee is dependent upon the volume of gas flowing through its compressors and the quantity of compression stages utilized to gather the gas. | ||||||||||||
· | 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. POP contracts may include a fee component which is charged to the producer. | ||||||||||||
· | Fixed Recoveries. Fee-based or POP contracts sometimes include fixed recovery terms, which mean that the prices paid or products returned to the producer are calculated using an agreed NGL recovery factor, regardless of the volumes of NGLs actually recovered through processing. | ||||||||||||
· | 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. Therefore, APL bears the economic risk (the “processing margin risk”) that (i) the Btu quantity of residue gas available for redelivery to the producer may be less than APL received from the producer; and/or (ii) aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount that it paid for the unprocessed natural gas. In order to help mitigate the risk associated with Keep-Whole contracts, APL generally imposes a fee to gather the gas that is settled under this arrangement. Also, because the natural gas volumes contracted under some Keep-Whole agreements are lower in Btu content and thus can meet downstream pipeline specifications without being processed, the natural gas can be bypassed around the processing plants on these systems and delivered directly into downstream pipelines during periods when the processing margin is uneconomic. | ||||||||||||
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 at March 31, 2014 and December 31, 2013 of $268.9 million and $191.8 million, respectively, which were included in accounts receivable within its consolidated balance sheets. APL’s accrued purchase costs at March 31, 2014 and December 31, 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 9). The Partnership does not have any other type of transaction which would be included within other comprehensive income (loss). | |||||||||||||
Recently Adopted Accounting Standards | |||||||||||||
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 is 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. |
Acquisitions
Acquisitions | 3 Months Ended | ||||
Mar. 31, 2014 | |||||
ACQUISITIONS | ' | ||||
NOTE 3 – ACQUISITIONS | |||||
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 (see Note 8), 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 14). 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 Partnership’s consolidated financial statements reflected the operating results of the acquired business commencing July 31, 2013. | |||||
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 10). 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 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 | $ | 5,268 | |||
Property, plant and equipment | 723,657 | ||||
Total current assets | $ | 728,925 | |||
Liabilities: | |||||
Accounts payable | 2,562 | ||||
Asset retirement obligation | 16,728 | ||||
Total liabilities assumed | 19,290 | ||||
Net assets acquired | $ | 709,635 | |||
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 includes 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 convertible preferred units (“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 14); | ||||
· | 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 14); and | ||||
· | borrowings under its senior secured revolving credit facility. | ||||
Subsequent to the closing of the TEAK Acquisition, APL issued $400.0 million of its 4.75% unsecured senior notes due November 15, 2021 on May 10, 2013 for net proceeds of $391.2 million to reduce the level of borrowings under its revolving credit facility, including amounts borrowed in connection with the TEAK Acquisition (see Note 8). | |||||
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 10). 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 8), 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. | |||||
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 APL 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 TEAK Acquisition, based on their estimated fair values at 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 | 193,877 | ||||
Intangible assets | 430,000 | ||||
Goodwill | 190,683 | ||||
Equity method investment in joint ventures | 183,801 | ||||
Total assets acquired | $ | 1,019,116 | |||
Liabilities: | |||||
Accounts payable and accrued liabilities | (35,296 | ) | |||
Other long term liabilities | (1,075 | ) | |||
Total liabilities assumed | (36,371 | ) | |||
Net assets acquired | 982,745 | ||||
Less cash received | (8,074 | ) | |||
Net cash paid for acquisition | $ | 974,671 | |||
Other Acquisitions | |||||
On February 13, 2014, ARP entered into a definitive asset purchase and sale agreement to acquire certain assets from GeoMet, Inc. (“GeoMet”) (OTCQB: GMET) for approximately $107.0 million in cash with an effective date of January 1, 2014, subject to certain purchase price adjustments. The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia. On May 5, 2014, closing of the transaction was approved by GeoMet’s shareholder vote, and is expected to occur during the second quarter of 2014, subject to certain customary closing conditions. | |||||
In September 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. | |||||
In July 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 8). The Arkoma Acquisition had an effective date of May 1, 2013. |
APL_Equity_Method_Investments
APL Equity Method Investments | 3 Months Ended | ||||||||
Mar. 31, 2014 | |||||||||
APL EQUITY METHOD INVESTMENTS | ' | ||||||||
NOTE 4 — APL EQUITY METHOD INVESTMENTS | |||||||||
West Texas LPG Pipeline Limited Partnership | |||||||||
APL has a 20% interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”), which owns a common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. WTLPG is operated by Chevron Pipeline Company, an affiliate of Chevron Corporation, a Delaware corporation (NYSE: CVX), which owns the remaining 80% interest. APL accounts for its ownership interest in WTLPG under the equity method of accounting, with recognition of its ownership interest in the income of WTLPG included within other, net on the Partnership’s consolidated statements of operations. In May 2014, APL entered into a definitive agreement to sell its interest in WTLPG to Martin Midstream Partners, L.P. (see Note 18). | |||||||||
T2 Joint Ventures | |||||||||
On May 7, 2013, APL acquired a 75% interest in T2 LaSalle, a 50% interest in T2 Eagle Ford and a 50% interest in T2 EF Co-Gen as part of the TEAK Acquisition (see Note 3). The T2 Joint Ventures are operated by TexStar Midstream Services, L.P. (“TexStar”), which owns the remaining interests. The T2 Joint Ventures were formed to provide services for the benefit of the joint interest owners. The T2 Joint Ventures have capacity lease agreements with the joint interest owners, which cover the costs of operations of the T2 Joint Ventures. APL accounts for its investments in the joint ventures under the equity method of accounting. APL’s proportionate share of the net income (loss) of the T2 Joint Ventures is included within other, net on the Partnership’s consolidated statement of operations for the three months ended March 31, 2014 and 2013. | |||||||||
APL evaluated whether the T2 Joint Ventures should be subject to consolidation. The T2 Joint Ventures do meet the qualifications of a Variable Interest Entity (“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, APL does not have controlling financial interests in these entities. Since APL shares equal management rights with TexStar, and TexStar 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 VIEs 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 March 31, 2014 and December 31, 2013 and equity income (loss) in joint ventures as of March 31, 2014 and 2013 (in thousands): | |||||||||
Investment in Joint Venture | |||||||||
March 31, | December 31, | ||||||||
2014 | 2013 | ||||||||
WTLPG | $ | 85,517 | $ | 85,790 | |||||
T2 LaSalle | 58,731 | 50,534 | |||||||
T2 Eagle Ford | 110,091 | 97,437 | |||||||
T2 Co-Gen | 14,719 | 14,540 | |||||||
Equity method investment in joint ventures | $ | 269,058 | $ | 248,301 | |||||
Three Months Ended | |||||||||
March 31, | |||||||||
2014 | 2013 | ||||||||
Equity income in WTLPG | $ | 1,727 | $ | 2,040 | |||||
Equity loss in T2 LaSalle | (1,113 | ) | — | ||||||
Equity loss in T2 Eagle Ford | (2,045 | ) | — | ||||||
Equity loss in T2 Co-Gen | (447 | ) | — | ||||||
Equity income (loss) in joint ventures | $ | (1,878 | ) | $ | 2,040 | ||||
Property_Plant_and_Equipment
Property, Plant and Equipment | 3 Months Ended | ||||||||||||
Mar. 31, 2014 | |||||||||||||
PROPERTY, PLANT AND EQUIPMENT | ' | ||||||||||||
NOTE 5 — PROPERTY, PLANT AND EQUIPMENT | |||||||||||||
The following is a summary of property, plant and equipment at the dates indicated (in thousands): | |||||||||||||
March 31, | December 31, | Estimated | |||||||||||
Useful Lives | |||||||||||||
2014 | 2013 | in Years | |||||||||||
Natural gas and oil properties: | |||||||||||||
Proved properties: | |||||||||||||
Leasehold interests | $ | 323,698 | $ | 322,217 | |||||||||
Pre-development costs | 4,066 | 4,367 | |||||||||||
Wells and related equipment | 2,280,114 | 2,231,213 | |||||||||||
Total proved properties | 2,607,878 | 2,557,797 | |||||||||||
Unproved properties | 216,691 | 211,851 | |||||||||||
Support equipment | 26,656 | 23,258 | |||||||||||
Total natural gas and oil properties | 2,851,225 | 2,792,906 | |||||||||||
Pipelines, processing and compression facilities | 3,063,750 | 2,926,134 | 2–40 | ||||||||||
Rights of way | 195,518 | 203,966 | 20–40 | ||||||||||
Land, buildings and improvements | 29,735 | 30,216 | 3–40 | ||||||||||
Other | 37,372 | 36,752 | 3–10 | ||||||||||
6,177,600 | 5,989,974 | ||||||||||||
Less – accumulated depreciation, depletion and | (1,153,095 | ) | (1,079,099 | ) | |||||||||
amortization | |||||||||||||
$ | 5,024,505 | $ | 4,910,875 | ||||||||||
During the three months ended March 31, 2014, the Partnership and its subsidiaries recognized $1.6 million of loss on asset disposal, primarily related to ARP’s sale of producing wells in the Niobrara Shale in connection with the settlement of a third party farm out agreement. During the three months ended March 31, 2013, ARP recognized a $0.7 million loss on asset disposal pertaining to its decision not to drill wells on leasehold property that expired during the three months ended March 31, 2013 in Indiana and Tennessee. | |||||||||||||
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. These impairments related to the carrying amounts of gas and oil properties being in excess of ARP’s estimate of their fair values at December 31, 2013, and ARP’s intention not to drill on certain expiring unproved acreage. The estimate of fair values of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement. |
Other_Assets
Other Assets | 3 Months Ended | ||||||||
Mar. 31, 2014 | |||||||||
OTHER ASSETS | ' | ||||||||
NOTE 6 — OTHER ASSETS | |||||||||
The following is a summary of other assets at the dates indicated (in thousands): | |||||||||
March 31, | December 31, | ||||||||
2014 | 2013 | ||||||||
Deferred financing costs, net of accumulated amortization of $47,811 and $43,702 at March 31, 2014 and December 31, 2013, respectively | $ | 83,413 | $ | 86,617 | |||||
Investment in Lightfoot | 21,337 | 21,454 | |||||||
Security deposits | 6,082 | 5,631 | |||||||
ARP notes receivable | 4,012 | 3,978 | |||||||
Long-term derivative asset receivable from Drilling Partnerships | 1,007 | 863 | |||||||
Other | 8,454 | 6,129 | |||||||
$ | 124,305 | $ | 124,672 | ||||||
Deferred financing costs. Deferred financing costs are recorded at cost and amortized over the terms of the respective debt agreements (see Note 8). Amortization expense of the Partnership and its subsidiaries’ deferred financing costs was $4.1 million and $3.0 million for the three months ended March 31, 2014 and 2013, respectively, which was recorded within interest expense on the Partnership’s consolidated statements of operations. During the three months ended March 31, 2013, ARP recognized an additional $3.2 million for accelerated amortization of deferred financing costs associated with the retirement of a portion of its then-existing 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 7.75% senior unsecured notes due 2021 (see Note 8). During the three months ended March 31, 2013, APL recorded an additional $5.3 million of accelerated amortization of deferred financing costs related to the retirement of its 8.75% senior unsecured notes due June 15, 2018 (“8.75% APL Senior Notes”) to loss on early extinguishment of debt on the Partnership’s consolidated statement of operations (see Note 8). There was no accelerated amortization of deferred financing costs for the three months ended March 31, 2014. | |||||||||
ARP notes receivable. At March 31, 2014 and December 31, 2013, ARP had notes receivable with certain investors of its Drilling Partnerships, which were included within other assets 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 the three months ended March 31, 2014, $23,000 of interest income was recognized within other, net on the Partnership’s consolidated statement of operations. There was no interest income recognized for the three months ended March 31, 2013. At March 31, 2014 and December 31, 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 March 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 three months ended March 31, 2014 and 2013, the Partnership recognized equity income of approximately $0.2 million and equity loss of approximately $1,000, respectively, within other, net on the Partnership’s consolidated statements of operations. During the three months ended March 31, 2014 and 2013, the Partnership received net cash distributions of approximately $0.4 million and approximately $4,000, 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 | 3 Months Ended | ||||||||
Mar. 31, 2014 | |||||||||
ASSET RETIREMENT OBLIGATIONS | ' | ||||||||
NOTE 7 — 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 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. | |||||||||
The estimated liability for asset retirement obligations was based on historical experience in plugging and abandoning wells, 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 March 31, 2014, the Drilling Partnerships had $57.9 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. During the three months ended March 31, 2014, ARP withheld approximately $0.6 million of limited partner distributions related to the asset retirement obligations of certain Drilling Partnerships. No amounts were withheld during the three months ended March 31, 2013. 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): | |||||||||
Three Months Ended | |||||||||
March 31, | |||||||||
2014 | 2013 | ||||||||
Asset retirement obligations, beginning of | $ | 91,214 | $ | 64,794 | |||||
year | |||||||||
Liabilities incurred | 602 | 645 | |||||||
Liabilities settled | (217 | ) | (7 | ) | |||||
Accretion expense | 1,328 | 954 | |||||||
Asset retirement obligations, end of period | $ | 92,927 | $ | 66,386 | |||||
The above accretion expense was included in depreciation, depletion and amortization in the Partnership’s consolidated statements of operations and the asset retirement obligation liabilities were included within asset retirement obligations in the Partnership’s consolidated balance sheets. During the year ended December 31, 2013, the Partnership incurred $1.3 million of future plugging and abandonment costs related to the Arkoma Acquisition it consummated during the period. During the year ended December 31, 2013, ARP incurred $16.7 million of future plugging and abandonment costs related to the EP Energy Acquisition it consummated during the period. |
Debt
Debt | 3 Months Ended | ||||||||
Mar. 31, 2014 | |||||||||
DEBT | ' | ||||||||
NOTE 8 — DEBT | |||||||||
Total debt consists of the following at the dates indicated (in thousands): | |||||||||
March 31, | December 31, | ||||||||
2014 | 2013 | ||||||||
Term loan facility | $ | 238,800 | $ | 239,400 | |||||
Revolving credit facility | — | — | |||||||
ARP revolving credit facility | 366,000 | 419,000 | |||||||
ARP 7.75% Senior Notes – due 2021 | 275,000 | 275,000 | |||||||
ARP 9.25% Senior Notes – due 2021 | 248,388 | 248,334 | |||||||
APL revolving credit facility | 150,000 | 152,000 | |||||||
APL 6.625% Senior Notes – due 2020 | 504,387 | 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 | 556 | 754 | |||||||
Total debt | 2,833,131 | 2,889,044 | |||||||
Less current maturities | (2,794 | ) | (2,924 | ) | |||||
Total long-term debt | $ | 2,830,337 | $ | 2,886,120 | |||||
Partnership’s Term Loan Facility. | |||||||||
On July 31, 2013, in connection with the Arkoma Acquisition (see Note 3), the Partnership entered into a $240.0 million secured term facility with a group of outside investors (the “Term Facility”). At March 31, 2014, $238.8 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 March 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 (i) 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, and (ii) the entry into swap agreements with respect to the assets acquired in the EP Energy and Arkoma acquisitions (see Note 3). At March 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 3), 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 March 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 (i) the required ratio of Total Funded Debt (as defined in the credit facility) to EBITDA (as defined in the credit facility), and (ii) entry into swap agreements. At March 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 2.3 to 1.0. | |||||||||
The credit facility is subject to an intercreditor agreement as described above under the “Partnership’s Term Loan Facility”. | |||||||||
At March 31, 2014, the Partnership has not guaranteed any of ARP’s or APL’s debt obligations. | |||||||||
ARP’s Credit Facility | |||||||||
At March 31, 2014, ARP has a credit agreement with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (the “ARP Credit Agreement”) that provides for a senior secured revolving credit facility with a maximum facility amount of $1.5 billion scheduled to mature in July 2018. ARP’s borrowing base under the credit facility, which was $735.0 million at March 31, 2014, is scheduled for semi-annual redeterminations on May 1 and November 1 of each year. At March 31, 2014, $366.0 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 $3.7 million was outstanding at March 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 1.75% 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 0.75% 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 0.5% per annum if 50% or more of the borrowing base is utilized and 0.375% per annum if less than 50% of the borrowing base is utilized, which is included within interest expense on the Partnership’s consolidated statements of operations. At March 31, 2014, the weighted average interest rate on outstanding borrowings under the credit facility was 2.3%. | |||||||||
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 March 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 four quarters of 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 March 31, 2014 and June 30, 2014, 4.25 to 1.0 as of the last day of the quarter ended September 30, 2014 and 4.0 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 ARP’s credit agreement, at March 31, 2014, ARP’s ratio of current assets to current liabilities was 2.1 to 1.0, and its ratio of Total Funded Debt to EBITDA was 3.9 to 1.0. | |||||||||
ARP Senior Notes | |||||||||
On March 31, 2014, ARP had $275.0 million principal outstanding of 7.75% senior notes due 2021 (“7.75% ARP Senior Notes”) and $250.0 million principal outstanding of 9.25% senior notes due 2021 (“9.25% ARP Senior Notes”). On July 30, 2013, ARP issued $250.0 million of its 9.25% ARP Senior Notes in a private placement transaction at an offering price of 99.297% of par value, yielding net proceeds of approximately $242.8 million, net of underwriting fees and other offering costs of $5.5 million. The net proceeds were used to partially fund the EP Energy Acquisition (see Note 3). The 9.25% ARP Senior Notes were presented net of a $1.6 million unamortized discount as of March 31, 2014. Interest on the 9.25% ARP Senior Notes accrued from July 30, 2013, and is payable semi-annually on February 15 and August 15, with the first interest payment date on February 15, 2014. 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 109.25%. 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 9.25% ARP Senior Notes due 2021, ARP entered into a registration rights agreement, whereby it agreed to (a) file an exchange offer registration statement with the Securities and Exchange Commission (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. | |||||||||
On January 23, 2013, ARP issued $275.0 million of its 7.75% ARP Senior Notes and used the net proceeds of approximately $267.6 million to repay all of the indebtedness and accrued interest outstanding under its then-existing term loan credit facility and a portion of the amounts outstanding under its revolving credit facility. In connection with the retirement of ARP’s term loan credit facility and the reduction in its revolving credit facility borrowing base, ARP accelerated $3.2 million of amortization expense related to deferred financing costs during the three months ended March 31, 2013 (see Note 6). 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 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. On July 1, 2013, ARP filed a registration statement relating to the exchange offer for the 7.75% ARP Senior Notes and the exchange offer was completed on January 2, 2014. | |||||||||
The 9.25% ARP Senior Notes and 7.75% ARP Senior Notes are guaranteed by certain of ARP’s material subsidiaries. The guarantees under the 9.25% ARP Senior Notes and 7.75% 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 9.25% ARP Senior Notes and 7.75% 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 March 31, 2014. | |||||||||
APL Credit Facility | |||||||||
At March 31, 2014, APL had a $600.0 million senior secured revolving credit facility with a syndicate of banks, which matures in May 2017, of which $150.0 million was outstanding. Borrowings under APL’s credit facility bear interest, at APL’s option, at either (i) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) three-month LIBOR plus 1.0%, or (ii) the LIBOR rate for the applicable period (each plus the applicable margin). The weighted average interest rate on APL’s outstanding revolving credit facility borrowings at March 31, 2014 was 3.2%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $0.1 million was outstanding at March 31, 2014. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated balance sheet at March 31, 2014. At March 31, 2014, APL had $449.9 million of remaining committed capacity under its credit facility, subject to covenant limitations. The Partnership has not guaranteed any of the obligations under APL’s senior secured revolving credit facility. | |||||||||
Borrowings under APL’s credit facility are secured by (i) a lien on and security interest in all of APL’s property and that of its subsidiaries, except for the assets owned by the West OK, West TX and Centrahoma joint ventures and their respective subsidiaries; and (ii) the guarantee 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 its ability to (i) incur additional indebtedness, (ii) make certain acquisitions, loans or investments, (iii) make distribution payments to its unitholders if an event of default exists, or (iv) enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. APL is also unable to borrow under its 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 which constitute an event of default under 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 APL’s general partner. | |||||||||
On March 11, 2014, APL entered into an amendment to the credit agreement governing its revolving credit facility which, among other changes: | |||||||||
· | adjusted the duration of, and maximum ratios allowed during, the Acquisition Period, as defined in the credit agreement, for the Consolidated Funded Debt Ratio, as defined in the credit agreement; and | ||||||||
· | permitted the payment of cash distributions, if any, on the Class E Preferred Units so long as APL has a pro forma Minimum Liquidity, as defined in the credit agreement, of greater than or equal to $50 million. | ||||||||
APL was in compliance with these covenants as of March 31, 2014. | |||||||||
APL Senior Notes | |||||||||
At March 31, 2014, APL had $400.0 million of 4.75% Senior Notes due 2021 (“4.75% APL Senior Notes”), $650.0 million principal outstanding of 5.875% unsecured senior notes due August 1, 2023 (“5.875% APL Senior Notes”) and $500.0 million principal outstanding of 6.625% unsecured senior notes due October 1, 2020 (“6.625% APL Senior Notes”) (collectively, the “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. 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 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. APL commenced an exchange offer for the 4.75% APL Senior Notes on December 10, 2013 and the exchange offer was completed on January 9, 2014. | |||||||||
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 transaction costs and utilized the proceeds to redeem APL’s previously outstanding 8.75% unsecured senior notes due June 15, 2018 (“8.75% APL Senior Notes”) and repay a portion of the outstanding indebtedness under its revolving credit agreement. 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 redeemable any time after February 1, 2018, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. APL commenced an exchange offer for the 5.875% APL Senior Notes on December 10, 2013 and the exchange offer was completed on January 9, 2014. | |||||||||
The 6.625% APL Senior Notes are presented combined with a net $4.4 million unamortized premium as of March 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 redeemable at any time after October 1, 2016, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. | |||||||||
On January 28, 2013, APL commenced a cash tender offer for any and all of its outstanding $365.8 million 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 8.75% APL Senior Notes not purchased in connection with the 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 three months ended March 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 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 its obligations under its revolving credit facility. | |||||||||
Indentures governing the APL Senior Notes contain covenants, including limitations on 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. APL was in compliance with these covenants as of March 31, 2014. | |||||||||
APL Capital Leases | |||||||||
The following is a summary of the leased property under capital leases as of March 31, 2014 and December 31, 2013, which are included within property, plant and equipment, net (see Note 5) (in thousands): | |||||||||
March 31, | December 31, | ||||||||
2014 | 2013 | ||||||||
Pipelines, processing and compression facilities | $ | 1,142 | $ | 2,281 | |||||
Less – accumulated depreciation | (144 | ) | (330 | ) | |||||
$ | 998 | $ | 1,951 | ||||||
In March 2014, APL took ownership of $1.1 million of facilities in connection with the conclusion of a capital lease. During the year ended December 31, 2013, APL accelerated payment on certain leases and purchased the leased property by paying approximately $7.5 million in accordance with the lease agreements. These leases were to mature in August 2013. | |||||||||
Depreciation expense for leased properties was approximately $32,000 and $0.2 million for the three months ended March 31, 2014 and 2013, respectively. Depreciation expense for leased properties is included within depreciation, depletion and amortization expense on the Partnership’s consolidated statements of operations. | |||||||||
Cash payments for interest by the Partnership and its subsidiaries were $38.8 million and $26.7 million for the three months ended March 31, 2014 and 2013, respectively. | |||||||||
Derivative_Instruments
Derivative Instruments | 3 Months Ended | |||||||||||||||||||||||||||||||||||||||||
Mar. 31, 2014 | ||||||||||||||||||||||||||||||||||||||||||
DERIVATIVE INSTRUMENTS | ' | |||||||||||||||||||||||||||||||||||||||||
NOTE 9 — 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 liabilities on its consolidated balance sheets of $8.5 million and net derivative assets of $14.9 million at March 31, 2014 and December 31, 2013, respectively. Of the $2.1 million of net gain in accumulated other comprehensive income within partners’ capital on the Partnership’s consolidated balance sheet related to derivatives at March 31, 2014, if the fair values of the instruments remain at current market values, the Partnership will reclassify $7.8 million of losses 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 $9.9 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. No amounts were reclassified from other comprehensive income related to derivative instruments entered into during the three months ended March 31, 2014 and 2013. | ||||||||||||||||||||||||||||||||||||||||||
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): | ||||||||||||||||||||||||||||||||||||||||||
Three Months Ended | ||||||||||||||||||||||||||||||||||||||||||
March 31, | ||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||||||||
(Gain) loss reclassified from accumulated other comprehensive income (loss): | ||||||||||||||||||||||||||||||||||||||||||
Gas and oil production revenue | $ | 14,569 | $ | (993 | ) | |||||||||||||||||||||||||||||||||||||
Total | $ | 14,569 | $ | (993 | ) | |||||||||||||||||||||||||||||||||||||
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 March 31, 2014 | ||||||||||||||||||||||||||||||||||||||||||
Long-term portion of derivative assets | $ | 1,367 | $ | — | $ | 1,367 | ||||||||||||||||||||||||||||||||||||
Total derivative assets | $ | 1,367 | $ | — | $ | 1,367 | ||||||||||||||||||||||||||||||||||||
As of December 31, 2013 | ||||||||||||||||||||||||||||||||||||||||||
Current portion of derivative | $ | 24 | $ | (23 | ) | $ | 1 | |||||||||||||||||||||||||||||||||||
assets | ||||||||||||||||||||||||||||||||||||||||||
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 March 31, 2014 | ||||||||||||||||||||||||||||||||||||||||||
Current portion of derivative liabilities | $ | (770 | ) | $ | — | $ | (770 | ) | ||||||||||||||||||||||||||||||||||
Total derivative liabilities | $ | (770 | ) | $ | — | $ | (770 | ) | ||||||||||||||||||||||||||||||||||
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 three months ended March 31, 2014, the Partnership recorded losses of $0.5 million on settled derivative contracts within its consolidated statements of operations. These losses were included within gas and oil production revenue in the Partnership’s consolidated statement of operations. No gains or losses were recorded on settled derivative contracts within the Partnership’s consolidated statements of operations for the three months ended March 31, 2013 as the Partnership had no derivative contracts in those months. 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 three months ended March 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. | ||||||||||||||||||||||||||||||||||||||||||
At March 31, 2014, the Partnership had the following commodity derivatives: | ||||||||||||||||||||||||||||||||||||||||||
Natural Gas Fixed Price Swaps | ||||||||||||||||||||||||||||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||||||||||||||||||||||||||||
Period Ending | Fixed Price | Asset/(Liability) | ||||||||||||||||||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||||||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | ||||||||||||||||||||||||||||||||||||||||
2014 | 2,070,000 | $ | 4.177 | $ | (593 | ) | ||||||||||||||||||||||||||||||||||||
2015 | 2,280,000 | $ | 4.302 | 228 | ||||||||||||||||||||||||||||||||||||||
2016 | 1,440,000 | $ | 4.433 | 399 | ||||||||||||||||||||||||||||||||||||||
2017 | 1,200,000 | $ | 4.59 | 393 | ||||||||||||||||||||||||||||||||||||||
2018 | 420,000 | $ | 4.797 | 170 | ||||||||||||||||||||||||||||||||||||||
The Partnership’s net asset | $ | 597 | ||||||||||||||||||||||||||||||||||||||||
(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): | ||||||||||||||||||||||||||||||||||||||||||
Gross | Gross | Net Amount of | ||||||||||||||||||||||||||||||||||||||||
Amounts of | Amounts | Assets Presented | ||||||||||||||||||||||||||||||||||||||||
Recognized | Offset in the | in the Consolidated | ||||||||||||||||||||||||||||||||||||||||
Assets | Consolidated | Balance Sheets | ||||||||||||||||||||||||||||||||||||||||
Balance Sheets | ||||||||||||||||||||||||||||||||||||||||||
Offsetting Derivative Assets | ||||||||||||||||||||||||||||||||||||||||||
As of March 31, 2014 | ||||||||||||||||||||||||||||||||||||||||||
Current portion of derivative | $ | 161 | $ | — | $ | 161 | ||||||||||||||||||||||||||||||||||||
assets | ||||||||||||||||||||||||||||||||||||||||||
Long-term portion of derivative | 25,859 | (2,110 | ) | 23,749 | ||||||||||||||||||||||||||||||||||||||
assets | ||||||||||||||||||||||||||||||||||||||||||
Current portion of derivative | 4,382 | (4,382 | ) | — | ||||||||||||||||||||||||||||||||||||||
liabilities | ||||||||||||||||||||||||||||||||||||||||||
Long-term portion of derivative liabilities | 114 | (114 | ) | — | ||||||||||||||||||||||||||||||||||||||
Total derivative assets | $ | 30,516 | $ | (6,606 | ) | $ | 23,910 | |||||||||||||||||||||||||||||||||||
As of December 31, 2013 | ||||||||||||||||||||||||||||||||||||||||||
Current portion of derivative assets | $ | 2,664 | $ | (773 | ) | $ | 1,891 | |||||||||||||||||||||||||||||||||||
Long-term portion of derivative | 31,146 | (4,062 | ) | 27,084 | ||||||||||||||||||||||||||||||||||||||
assets | ||||||||||||||||||||||||||||||||||||||||||
Current portion of derivative | 4,341 | (4,341 | ) | — | ||||||||||||||||||||||||||||||||||||||
liabilities | ||||||||||||||||||||||||||||||||||||||||||
Long-term portion of derivative liabilities | 122 | (122 | ) | — | ||||||||||||||||||||||||||||||||||||||
Total derivative assets | $ | 38,273 | $ | (9,298 | ) | $ | 28,975 | |||||||||||||||||||||||||||||||||||
Gross | Gross | Net Amount of | ||||||||||||||||||||||||||||||||||||||||
Amounts of | Amounts | Liabilities Presented | ||||||||||||||||||||||||||||||||||||||||
Recognized | Offset in the | in the Consolidated | ||||||||||||||||||||||||||||||||||||||||
Liabilities | Consolidated | Balance Sheets | ||||||||||||||||||||||||||||||||||||||||
Balance Sheets | ||||||||||||||||||||||||||||||||||||||||||
Offsetting Derivative Liabilities | ||||||||||||||||||||||||||||||||||||||||||
As of March 31, 2014 | ||||||||||||||||||||||||||||||||||||||||||
Current portion of derivative | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||
assets | ||||||||||||||||||||||||||||||||||||||||||
Long-term portion of derivative | (2,110 | ) | 2,110 | — | ||||||||||||||||||||||||||||||||||||||
assets | ||||||||||||||||||||||||||||||||||||||||||
Current portion of derivative | (26,754 | ) | 4,382 | (22,372 | ) | |||||||||||||||||||||||||||||||||||||
liabilities | ||||||||||||||||||||||||||||||||||||||||||
Long-term portion of derivative | (127 | ) | 114 | (13 | ) | |||||||||||||||||||||||||||||||||||||
liabilities | ||||||||||||||||||||||||||||||||||||||||||
Total derivative liabilities | $ | (28,991 | ) | $ | 6,606 | $ | (22,385 | ) | ||||||||||||||||||||||||||||||||||
As of December 31, 2013 | ||||||||||||||||||||||||||||||||||||||||||
Current portion of derivative | $ | (773 | ) | $ | 773 | $ | — | |||||||||||||||||||||||||||||||||||
assets | ||||||||||||||||||||||||||||||||||||||||||
Long-term portion of derivative | (4,062 | ) | 4,062 | — | ||||||||||||||||||||||||||||||||||||||
assets | ||||||||||||||||||||||||||||||||||||||||||
Current portion of derivative | (10,694 | ) | 4,341 | (6,353 | ) | |||||||||||||||||||||||||||||||||||||
liabilities | ||||||||||||||||||||||||||||||||||||||||||
Long-term portion of derivative liabilities | (189 | ) | 122 | (67 | ) | |||||||||||||||||||||||||||||||||||||
Total derivative liabilities | $ | (15,718 | ) | $ | 9,298 | $ | (6,420 | ) | ||||||||||||||||||||||||||||||||||
ARP recognized losses of $14.0 million and gains of $1.0 million for the three months ended March 31, 2014, and 2013, respectively, on settled contracts covering commodity production. These gains and losses 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 three months ended March 31, 2014 and 2013, respectively for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges. | ||||||||||||||||||||||||||||||||||||||||||
At March 31, 2014, ARP had the following commodity derivatives: | ||||||||||||||||||||||||||||||||||||||||||
Natural Gas Fixed Price Swaps | ||||||||||||||||||||||||||||||||||||||||||
Production Period Ending | Volumes | Average | Fair Value | |||||||||||||||||||||||||||||||||||||||
December 31, | Fixed Price | Asset/(Liability) | ||||||||||||||||||||||||||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | ||||||||||||||||||||||||||||||||||||||||
2014 | 45,114,700 | $ | 4.152 | $ | (14,068 | ) | ||||||||||||||||||||||||||||||||||||
2015 | 51,924,500 | $ | 4.239 | 1,799 | ||||||||||||||||||||||||||||||||||||||
2016 | 45,746,300 | $ | 4.311 | 7,193 | ||||||||||||||||||||||||||||||||||||||
2017 | 24,840,000 | $ | 4.532 | 6,734 | ||||||||||||||||||||||||||||||||||||||
2018 | 3,960,000 | $ | 4.716 | 1,306 | ||||||||||||||||||||||||||||||||||||||
$ | 2,964 | |||||||||||||||||||||||||||||||||||||||||
Natural Gas Costless Collars | ||||||||||||||||||||||||||||||||||||||||||
Production | Option Type | Volumes | Average Floor | Fair Value | ||||||||||||||||||||||||||||||||||||||
Period Ending | and Cap | Asset/(Liability) | ||||||||||||||||||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||||||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | ||||||||||||||||||||||||||||||||||||||||
2014 | Puts purchased | 2,880,000 | $ | 4.221 | $ | 642 | ||||||||||||||||||||||||||||||||||||
2014 | Calls sold | 2,880,000 | $ | 5.12 | (418 | ) | ||||||||||||||||||||||||||||||||||||
2015 | Puts purchased | 3,480,000 | $ | 4.234 | 1,636 | |||||||||||||||||||||||||||||||||||||
2015 | Calls sold | 3,480,000 | $ | 5.129 | (721 | ) | ||||||||||||||||||||||||||||||||||||
$ | 1,139 | |||||||||||||||||||||||||||||||||||||||||
Natural Gas Put Options – Drilling Partnerships | ||||||||||||||||||||||||||||||||||||||||||
Production | Option Type | Volumes | Average Fixed | Fair Value | ||||||||||||||||||||||||||||||||||||||
Period Ending | Price | Asset | ||||||||||||||||||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||||||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | ||||||||||||||||||||||||||||||||||||||||
2014 | Puts purchased | 1,350,000 | $ | 3.8 | $ | 84 | ||||||||||||||||||||||||||||||||||||
2015 | Puts purchased | 1,440,000 | $ | 4 | 447 | |||||||||||||||||||||||||||||||||||||
2016 | Puts purchased | 1,440,000 | $ | 4.15 | 613 | |||||||||||||||||||||||||||||||||||||
$ | 1,144 | |||||||||||||||||||||||||||||||||||||||||
WAHA Basis Swaps | ||||||||||||||||||||||||||||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||||||||||||||||||||||||||||
Period Ending | Fixed Price | Liability | ||||||||||||||||||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||||||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | ||||||||||||||||||||||||||||||||||||||||
2014 | 8,100,000 | $ | (0.110 | ) | $ | (42 | ) | |||||||||||||||||||||||||||||||||||
$ | (42 | ) | ||||||||||||||||||||||||||||||||||||||||
Natural Gas Liquids Fixed Price Swaps | ||||||||||||||||||||||||||||||||||||||||||
Production | Volumes | Average Fixed | Fair Value | |||||||||||||||||||||||||||||||||||||||
Period Ending | Price | Asset/(Liability) | ||||||||||||||||||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||||||||||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | ||||||||||||||||||||||||||||||||||||||||
2014 | 79,500 | $ | 91.568 | $ | (486 | ) | ||||||||||||||||||||||||||||||||||||
2015 | 96,000 | $ | 88.55 | (129 | ) | |||||||||||||||||||||||||||||||||||||
2016 | 84,000 | $ | 85.651 | 92 | ||||||||||||||||||||||||||||||||||||||
2017 | 60,000 | $ | 83.78 | 127 | ||||||||||||||||||||||||||||||||||||||
$ | (396 | ) | ||||||||||||||||||||||||||||||||||||||||
Natural Gas Liquids Ethane Fixed Price Swaps | ||||||||||||||||||||||||||||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||||||||||||||||||||||||||||
Period Ending | Fixed Price | Asset | ||||||||||||||||||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||||||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(4) | ||||||||||||||||||||||||||||||||||||||||
2014 | 1,890,000 | $ | 0.303 | $ | 25 | |||||||||||||||||||||||||||||||||||||
$ | 25 | |||||||||||||||||||||||||||||||||||||||||
Natural Gas Liquids Propane Fixed Price Swaps | ||||||||||||||||||||||||||||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||||||||||||||||||||||||||||
Period Ending | Fixed Price | Liability | ||||||||||||||||||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||||||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(5) | ||||||||||||||||||||||||||||||||||||||||
2014 | 9,261,000 | $ | 1 | $ | (727 | ) | ||||||||||||||||||||||||||||||||||||
2015 | 8,064,000 | $ | 1.016 | (149 | ) | |||||||||||||||||||||||||||||||||||||
$ | (876 | ) | ||||||||||||||||||||||||||||||||||||||||
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)(6) | ||||||||||||||||||||||||||||||||||||||||
2014 | 1,134,000 | $ | 1.308 | $ | 35 | |||||||||||||||||||||||||||||||||||||
2015 | 1,512,000 | $ | 1.248 | 28 | ||||||||||||||||||||||||||||||||||||||
$ | 63 | |||||||||||||||||||||||||||||||||||||||||
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)(7) | ||||||||||||||||||||||||||||||||||||||||
2014 | 1,134,000 | $ | 1.323 | $ | 33 | |||||||||||||||||||||||||||||||||||||
2015 | 1,512,000 | $ | 1.263 | 24 | ||||||||||||||||||||||||||||||||||||||
$ | 57 | |||||||||||||||||||||||||||||||||||||||||
Crude Oil Fixed Price Swaps | ||||||||||||||||||||||||||||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||||||||||||||||||||||||||||
Period Ending | Fixed Price | Asset/ | ||||||||||||||||||||||||||||||||||||||||
December 31, | (Liability) | |||||||||||||||||||||||||||||||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | ||||||||||||||||||||||||||||||||||||||||
2014 | 409,500 | $ | 92.692 | $ | (2,091 | ) | ||||||||||||||||||||||||||||||||||||
2015 | 567,000 | $ | 88.144 | (969 | ) | |||||||||||||||||||||||||||||||||||||
2016 | 225,000 | $ | 85.523 | 218 | ||||||||||||||||||||||||||||||||||||||
2017 | 132,000 | $ | 83.305 | 220 | ||||||||||||||||||||||||||||||||||||||
$ | (2,622 | ) | ||||||||||||||||||||||||||||||||||||||||
Crude Oil Costless Collars | ||||||||||||||||||||||||||||||||||||||||||
Production | Option Type | Volumes | Average | Fair Value | ||||||||||||||||||||||||||||||||||||||
Period Ending | Floor and Cap | Asset/(Liability) | ||||||||||||||||||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||||||||||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | ||||||||||||||||||||||||||||||||||||||||
2014 | Puts purchased | 30,870 | $ | 84.169 | $ | 38 | ||||||||||||||||||||||||||||||||||||
2014 | Calls sold | 30,870 | $ | 113.308 | (33 | ) | ||||||||||||||||||||||||||||||||||||
2015 | Puts purchased | 29,250 | $ | 83.846 | 125 | |||||||||||||||||||||||||||||||||||||
2015 | Calls sold | 29,250 | $ | 110.654 | (61 | ) | ||||||||||||||||||||||||||||||||||||
$ | 69 | |||||||||||||||||||||||||||||||||||||||||
ARP’s net asset | $ | 1,525 | ||||||||||||||||||||||||||||||||||||||||
(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 ethane 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. | |||||||||||||||||||||||||||||||||||||||||
At March 31, 2014, ARP had net cash proceeds of $1.9 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. The Partnership reflected the remaining hedge monetization proceeds within current and long-term portion of derivative payable to Drilling Partnerships on its consolidated balance sheets as of March 31, 2014 and December 31, 2013. | ||||||||||||||||||||||||||||||||||||||||||
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 March 31, 2014, net unrealized derivative assets of $1.1 million were payable to the limited partners in the Drilling Partnerships related to these natural gas put option contracts. | ||||||||||||||||||||||||||||||||||||||||||
At March 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 8), 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): | ||||||||||||||||||||||||||||||||||||||||||
Gross | Gross | Net Amounts of Assets | ||||||||||||||||||||||||||||||||||||||||
Amounts of | Amounts | Presented in the | ||||||||||||||||||||||||||||||||||||||||
Recognized | Offset in the | Consolidated | ||||||||||||||||||||||||||||||||||||||||
Assets | Consolidated | Balance Sheets | ||||||||||||||||||||||||||||||||||||||||
Balance Sheets | ||||||||||||||||||||||||||||||||||||||||||
Offsetting Derivative Assets | ||||||||||||||||||||||||||||||||||||||||||
As of March 31, 2014 | ||||||||||||||||||||||||||||||||||||||||||
Long-term portion of derivative assets | $ | 5,336 | $ | (2,127 | ) | $ | 3,209 | |||||||||||||||||||||||||||||||||||
Current portion of derivative liabilities | 2,082 | (2,082 | ) | — | ||||||||||||||||||||||||||||||||||||||
Total derivative assets | $ | 7,418 | $ | (4,209 | ) | $ | 3,209 | |||||||||||||||||||||||||||||||||||
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 | 949 | (949 | ) | — | ||||||||||||||||||||||||||||||||||||||
liabilities | ||||||||||||||||||||||||||||||||||||||||||
Total derivative assets | $ | 8,953 | $ | (6,509 | ) | $ | 2,444 | |||||||||||||||||||||||||||||||||||
Gross | Gross | Net Amounts of | ||||||||||||||||||||||||||||||||||||||||
Amounts of | Amounts | Liabilities Presented | ||||||||||||||||||||||||||||||||||||||||
Recognized | Offset in the | in the Consolidated | ||||||||||||||||||||||||||||||||||||||||
Liabilities | Consolidated | Balance Sheets | ||||||||||||||||||||||||||||||||||||||||
Balance Sheets | ||||||||||||||||||||||||||||||||||||||||||
Offsetting Derivative Liabilities | ||||||||||||||||||||||||||||||||||||||||||
As of March 31, 2014 | ||||||||||||||||||||||||||||||||||||||||||
Long-term portion of derivative assets | $ | (2,127 | ) | $ | 2,127 | $ | — | |||||||||||||||||||||||||||||||||||
Current portion of derivative liabilities | (15,869 | ) | 2,082 | (13,787 | ) | |||||||||||||||||||||||||||||||||||||
Total derivative liabilities | $ | (17,996 | ) | $ | 4,209 | $ | (13,787 | ) | ||||||||||||||||||||||||||||||||||
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 | (1,269 | ) | 949 | (320 | ) | |||||||||||||||||||||||||||||||||||||
liabilities | ||||||||||||||||||||||||||||||||||||||||||
Total derivative liabilities | $ | (18,073 | ) | $ | 6,509 | $ | (11,564 | ) | ||||||||||||||||||||||||||||||||||
As of March 31, 2014, APL had the following commodity derivatives: | ||||||||||||||||||||||||||||||||||||||||||
Fixed Price Swaps | ||||||||||||||||||||||||||||||||||||||||||
Production Period | Purchased/ | Commodity | Volumes(1) | Average | Fair Value | |||||||||||||||||||||||||||||||||||||
Sold | Fixed | Asset/(Liability) | ||||||||||||||||||||||||||||||||||||||||
Price | (in thousands)(2) | |||||||||||||||||||||||||||||||||||||||||
Natural Gas | ||||||||||||||||||||||||||||||||||||||||||
2014 | Sold | Natural Gas | 12,690,000 | $ | 4.029 | $ | (5,555 | ) | ||||||||||||||||||||||||||||||||||
2015 | Sold | Natural Gas | 18,610,000 | $ | 4.244 | 592 | ||||||||||||||||||||||||||||||||||||
2016 | Sold | Natural Gas | 7,950,000 | $ | 4.277 | 779 | ||||||||||||||||||||||||||||||||||||
2017 | Sold | Natural Gas | 600,000 | $ | 4.455 | 23 | ||||||||||||||||||||||||||||||||||||
Natural Gas Liquids | ||||||||||||||||||||||||||||||||||||||||||
2014 | Sold | Natural Gas Liquids | 60,354,000 | $ | 1.198 | (5,123 | ) | |||||||||||||||||||||||||||||||||||
2015 | Sold | Natural Gas Liquids | 41,076,000 | $ | 1.079 | (1,993 | ) | |||||||||||||||||||||||||||||||||||
2016 | Sold | Natural Gas Liquids | 6,300,000 | $ | 1.034 | (85 | ) | |||||||||||||||||||||||||||||||||||
Crude Oil | ||||||||||||||||||||||||||||||||||||||||||
2014 | Sold | Crude Oil | 219,000 | $ | 91.062 | (1,672 | ) | |||||||||||||||||||||||||||||||||||
2015 | Sold | Crude Oil | 60,000 | $ | 85.13 | (298 | ) | |||||||||||||||||||||||||||||||||||
Total Fixed Price Swaps | $ | (13,332 | ) | |||||||||||||||||||||||||||||||||||||||
Options | ||||||||||||||||||||||||||||||||||||||||||
Production Period | Purchased/ | Type | Commodity | Volumes(1) | Average | Fair Value | ||||||||||||||||||||||||||||||||||||
Sold | Strike | Asset/(Liability) (in | ||||||||||||||||||||||||||||||||||||||||
Price | thousands) (2) | |||||||||||||||||||||||||||||||||||||||||
Natural Gas | ||||||||||||||||||||||||||||||||||||||||||
2014 | Purchased | Put | Natural Gas | 500,000 | $ | 4.13 | $ | 60 | ||||||||||||||||||||||||||||||||||
Natural Gas | ||||||||||||||||||||||||||||||||||||||||||
Liquids | ||||||||||||||||||||||||||||||||||||||||||
2014 | Purchased | Put | Natural Gas Liquids | 6,930,000 | $ | 0.96 | 135 | |||||||||||||||||||||||||||||||||||
2014 | Sold | Call | Natural Gas Liquids | 3,780,000 | $ | 1.318 | (27 | ) | ||||||||||||||||||||||||||||||||||
2015 | Purchased | Put | Natural Gas Liquids | 3,150,000 | $ | 0.941 | 155 | |||||||||||||||||||||||||||||||||||
2015 | Sold | Call | Natural Gas Liquids | 1,260,000 | $ | 1.275 | (46 | ) | ||||||||||||||||||||||||||||||||||
Crude Oil | ||||||||||||||||||||||||||||||||||||||||||
2014 | Purchased | Put | Crude Oil | 267,000 | $ | 90.413 | 657 | |||||||||||||||||||||||||||||||||||
2015 | Purchased | Put | Crude Oil | 270,000 | $ | 89.175 | 1,820 | |||||||||||||||||||||||||||||||||||
Total Options | $ | 2,754 | ||||||||||||||||||||||||||||||||||||||||
APL’s net liability | $ | (10,578 | ) | |||||||||||||||||||||||||||||||||||||||
(1) | Volumes for natural gas are stated in MMBtu’s. Volumes for NGLs are stated in gallons. Volumes for crude oil are stated in barrels. | |||||||||||||||||||||||||||||||||||||||||
(2) | See Note 10 for discussion on fair value methodology. | |||||||||||||||||||||||||||||||||||||||||
The following tables summarize APL’s derivatives not designated as hedges, which are included within gain on mark-to market derivatives on the Partnerships consolidated statements of operations: | ||||||||||||||||||||||||||||||||||||||||||
Three Months Ended | ||||||||||||||||||||||||||||||||||||||||||
March 31, | ||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||||||||
Gain (loss) recognized in loss on mark-to-market derivatives: | ||||||||||||||||||||||||||||||||||||||||||
Commodity contract—realized(1) | $ | (9,835 | ) | $ | 1,636 | |||||||||||||||||||||||||||||||||||||
Commodity contract – unrealized(2) | 1,164 | (13,719 | ) | |||||||||||||||||||||||||||||||||||||||
Loss on mark-to-market derivatives | $ | (8,671 | ) | $ | (12,083 | ) | ||||||||||||||||||||||||||||||||||||
(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): | ||||||||||||||||||||||||||||||||||||||||||
March 31, | December 31, | |||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||||||||
Current portion of derivative asset | $ | 161 | $ | 2,066 | ||||||||||||||||||||||||||||||||||||||
Long-term derivative asset | 28,325 | 30,868 | ||||||||||||||||||||||||||||||||||||||||
Current portion of derivative liability | (36,929 | ) | (17,630 | ) | ||||||||||||||||||||||||||||||||||||||
Long-term derivative liability | (13 | ) | (387 | ) | ||||||||||||||||||||||||||||||||||||||
Total Partnership net asset (liability) | $ | (8,456 | ) | $ | 14,917 | |||||||||||||||||||||||||||||||||||||
Fair_Value_of_Financial_Instru
Fair Value of Financial Instruments | 3 Months Ended | ||||||||||||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||||||||||||
FAIR VALUE OF FINANCIAL INSTRUMENTS | ' | ||||||||||||||||||||||||||||
NOTE 10 — 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 9). 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. | |||||||||||||||||||||||||||||
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 for propane, iso butane, normal butane and natural gasoline 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. 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 ARP’s and APL’s assets and liabilities measured at fair value at March 31, 2014 and December 31, 2013 was as follows (in thousands): | |||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||
As of March 31, 2014 | |||||||||||||||||||||||||||||
Derivative assets, gross | |||||||||||||||||||||||||||||
Commodity swaps | $ | — | $ | 1,367 | $ | — | $ | 1,367 | |||||||||||||||||||||
ARP Commodity swaps | — | 26,771 | — | 26,771 | |||||||||||||||||||||||||
ARP Commodity basis swaps | — | 159 | — | 159 | |||||||||||||||||||||||||
ARP Commodity puts | — | 1,144 | — | 1,144 | |||||||||||||||||||||||||
ARP Commodity options | — | 2,442 | — | 2,442 | |||||||||||||||||||||||||
APL Commodity swaps | — | 3,189 | 1,402 | 4,591 | |||||||||||||||||||||||||
APL Commodity options | — | 2,537 | 290 | 2,827 | |||||||||||||||||||||||||
Total derivative assets, gross | — | 37,609 | 1,692 | 39,301 | |||||||||||||||||||||||||
Derivative liabilities, gross | |||||||||||||||||||||||||||||
Commodity swaps | — | (770 | ) | — | (770 | ) | |||||||||||||||||||||||
ARP Commodity swaps | — | (27,556 | ) | — | (27,556 | ) | |||||||||||||||||||||||
ARP Commodity basis swaps | — | (201 | ) | — | (201 | ) | |||||||||||||||||||||||
ARP Commodity options | — | (1,234 | ) | — | (1,234 | ) | |||||||||||||||||||||||
APL Commodity swaps | — | (9,320 | ) | (8,603 | ) | (17,923 | ) | ||||||||||||||||||||||
APL Commodity options | — | — | (73 | ) | (73 | ) | |||||||||||||||||||||||
Total derivative liabilities, gross | — | (39,081 | ) | (8,676 | ) | (47,757 | ) | ||||||||||||||||||||||
Total derivatives, fair value, net | $ | — | $ | (1,472 | ) | $ | (6,984 | ) | $ | (8,456 | ) | ||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||||||||
Derivative assets, gross | |||||||||||||||||||||||||||||
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 derivative assets, gross | — | 47,238 | 1,622 | 48,860 | |||||||||||||||||||||||||
Derivative 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 | $ | — | $ | 26,673 | $ | (11,756 | ) | $ | 14,917 | ||||||||||||||||||||
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, 2014 | 130,158 | $ | (11,966 | ) | 6,300 | $ | 210 | — | — | $ | (11,756 | ) | |||||||||||||||||
New contracts(1) | — | — | 5,040 | 200 | 5,040 | (200 | ) | — | |||||||||||||||||||||
Cash settlements from unrealized gain (loss)(2)(3) | (22,428 | ) | 5,873 | (1,260 | ) | 137 | — | — | 6,010 | ||||||||||||||||||||
Net change in unrealized gain (loss)(2) | — | (1,108 | ) | — | (120 | ) | — | 127 | (1,101 | ) | |||||||||||||||||||
Option premium recognition(3) | — | — | — | (137 | ) | — | — | (137 | ) | ||||||||||||||||||||
Balance – March 31, 2014 | 107,730 | (7,201 | ) | 10,080 | 290 | 5,040 | (73 | ) | (6,984 | ) | |||||||||||||||||||
(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 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 March 31, 2014 and December 31, 2013 (in thousands): | |||||||||||||||||||||||||||||
Gallons | Third Party | Adjustments(2) | Total | ||||||||||||||||||||||||||
Quotes(1) | Amount | ||||||||||||||||||||||||||||
As of March 31, 2014 | |||||||||||||||||||||||||||||
Propane swaps | 83,538 | $ | (6,059 | ) | $ | — | $ | (6,059 | ) | ||||||||||||||||||||
Iso butane swaps | 5,040 | (1,405 | ) | 651 | (754 | ) | |||||||||||||||||||||||
Normal butane swaps | 5,040 | 483 | 192 | 675 | |||||||||||||||||||||||||
Natural gasoline swaps | 14,112 | (276 | ) | (787 | ) | (1,063 | ) | ||||||||||||||||||||||
Total NGL swaps — March 31, 2014 | 107,730 | $ | (7,257 | ) | $ | 56 | $ | (7,201 | ) | ||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||||||||
Propane swaps | 100,296 | $ | (10,260 | ) | $ | — | $ | (10,260 | ) | ||||||||||||||||||||
Iso butane 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): | |||||||||||||||||||||||||||||
Adjustment Based upon | |||||||||||||||||||||||||||||
Regression Coefficient | |||||||||||||||||||||||||||||
Level 3 Fair | Lower | Upper | Average | ||||||||||||||||||||||||||
Value | 95% | 95% | Coefficient | ||||||||||||||||||||||||||
Adjustments | |||||||||||||||||||||||||||||
As of March 31, 2014 | |||||||||||||||||||||||||||||
Iso butane swaps | $ | 651 | $ | 1.1168 | $ | 1.1271 | $ | 1.1219 | |||||||||||||||||||||
Normal butane swaps | 192 | 1.0341 | 1.0382 | 1.0361 | |||||||||||||||||||||||||
Natural gasoline swaps | (787 | ) | 0.9685 | 0.9716 | 0.9701 | ||||||||||||||||||||||||
Total NGL swaps – March 31, 2014 | $ | 56 | |||||||||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||||||||
Iso butane swaps | $ | 955 | 1.1184 | 1.1284 | 1.1234 | ||||||||||||||||||||||||
Normal butane swaps | 322 | 1.0341 | 1.0386 | 1.0364 | |||||||||||||||||||||||||
Natural gasoline swaps | (813 | ) | 0.9727 | 0.9751 | 0.9739 | ||||||||||||||||||||||||
Total NGL swaps – December 31, 2013 | $ | 464 | |||||||||||||||||||||||||||
APL had $21.7 million and $14.5 million of NGL linefill at March 31, 2014 and December 31, 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 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 a reduction of $0.4 million and $0.4 million as of March 31, 2014 and December 31, 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. | |||||||||||||||||||||||||||||
The following table provides a summary of changes in fair value of APL’s NGL linefill for the three months ended March 31, 2014 (in thousands): | |||||||||||||||||||||||||||||
Linefill Valued at | Linefill Valued on | Total NGL Linefill | |||||||||||||||||||||||||||
Market | FIFO | ||||||||||||||||||||||||||||
Gallons | Amount | Gallons | Amount | Gallons | Amount | ||||||||||||||||||||||||
Balance – January 1, 2014 | 5,788 | $ | 4,739 | 11,538 | $ | 9,778 | 17,326 | $ | 14,517 | ||||||||||||||||||||
Deliveries into NGL linefill | 1,050 | 1,013 | 25,600 | 16,875 | 26,650 | 17,888 | |||||||||||||||||||||||
NGL linefill sales | — | — | (20,622 | ) | (10,847 | ) | (20,622 | ) | (10,847 | ) | |||||||||||||||||||
Net change in NGL linefill valuation(1) | — | 143 | — | — | — | 143 | |||||||||||||||||||||||
Balance – March 31, 2014 | 6,838 | $ | 5,895 | 16,516 | $ | 15,806 | 23,354 | $ | 21,701 | ||||||||||||||||||||
(1) | Included within gathering and processing revenues on the Partnership’s consolidated statements of operations. | ||||||||||||||||||||||||||||
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 March 31, 2014 and December 31, 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 $2,875.0 million and $2,841.7 million, respectively, compared with the carrying amounts of $2,833.1 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 a Level 3 value. | |||||||||||||||||||||||||||||
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 three months ended March 31, 2014 and 2013 was as follows (in thousands): | |||||||||||||||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||||||||
Level 3 | Total | Level 3 | Total | ||||||||||||||||||||||||||
Asset retirement obligations | $ | 602 | $ | 602 | $ | 645 | $ | 645 | |||||||||||||||||||||
Total | $ | 602 | $ | 602 | $ | 645 | $ | 645 | |||||||||||||||||||||
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 year ended December 31, 2013, ARP recognized $38.0 million of impairment of long-lived assets which were defined as a Level 3 fair value measurements (see Note 2 – Impairment of Long-Lived Assets). No impairments were recognized during the three months ended March 31, 2014 and 2013. | |||||||||||||||||||||||||||||
During the year ended December 31, 2013, the Partnership completed the Arkoma Acquisition and ARP completed the EP Energy Acquisition. During the year ended December 31, 2013, APL completed the TEAK Acquisition. 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 estimates of fair value of the EP Energy and TEAK acquisitions as of their respective acquisition dates, which are reflected in the Partnership’s consolidated balance sheet as of March 31, 2014, are subject to change as the final valuations 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 7). These inputs require significant judgments and estimates by the Partnership’s and ARP’s management at the time of the valuation 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 March 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 amounts APL could pay related to the remaining contingent payment is up to $6.0 million. | |||||||||||||||||||||||||||||
Income_Taxes
Income Taxes | 3 Months Ended | ||||||||
Mar. 31, 2014 | |||||||||
INCOME TAXES | ' | ||||||||
NOTE 11 – 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 three months ended March 31, 2014 and 2013 are as follows (in thousands): | |||||||||
Three Months Ended | |||||||||
March 31, | |||||||||
2014 | 2013 | ||||||||
Income tax benefit: | |||||||||
Federal | $ | (357 | ) | $ | (8 | ) | |||
State | (41 | ) | (1 | ) | |||||
Total income tax benefit | $ | (398 | ) | $ | (9 | ) | |||
As of March 31, 2014 and December 31, 2013, APL had non-current net deferred income tax liabilities of $32.9 million and $33.3 million, respectively. The components of net deferred tax liabilities as of March 31, 2014 and December 31, 2013 consist of the following (in thousands): | |||||||||
March 31, | December 31, | ||||||||
2014 | 2013 | ||||||||
Deferred tax assets: | |||||||||
Net operating loss tax carryforwards and alternative minimum tax credits | $ | 15,499 | $ | 14,900 | |||||
Deferred tax liabilities: | |||||||||
Excess of asset carrying value over tax basis | (48,391 | ) | (48,190 | ) | |||||
Net deferred tax liabilities | $ | (32,892 | ) | $ | (33,290 | ) | |||
As of March 31, 2014, APL had net operating loss carry forwards for federal income tax purposes of approximately $40.1 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 | 3 Months Ended |
Mar. 31, 2014 | |
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS | ' |
NOTE 12 — 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 Partnership’s revenue 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 three month periods ended March 31, 2014 and 2013, $0.1 million and $0.1 million, respectively, of gathering fees paid by ARP to APL were eliminated in consolidation. | |
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 | 3 Months Ended |
Mar. 31, 2014 | |
COMMITMENTS AND CONTINGENCIES | ' |
NOTE 13 — COMMITMENTS AND CONTINGENCIES | |
General Commitments | |
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. Subject to certain conditions, investor partners in certain Drilling Partnerships have the right to present their interests for purchase by ARP, as managing general partner. ARP is not obligated to purchase more than 5% to 10% of the units in any calendar year. Based on its historical experience, as of March 31, 2014, the management of ARP believes that any such liability incurred would not be material. Also, ARP has agreed to subordinate a portion of its share of net partnership revenues from certain of the Drilling Partnerships to the benefit of the investor partners until they have received specified returns, typically 10% per year determined on a cumulative basis, over a specific period, typically the first five to eight years, in accordance with the terms of the partnership agreements. For the three months ended March 31, 2014 and 2013, $3.5 million and $2.1, respectively, of ARP’s revenues, net of corresponding production costs, were subordinated, which reduced its cash distributions received from the Drilling Partnerships. | |
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 ARP’s EP Energy Acquisition (see Note 3), ARP acquired certain long-term annual firm transportation obligations. Estimated fixed and determinable portions of ARP’s firm transportation obligations as of March 31, 2014 were as follows: 2014—$6.6 million; 2015—$8.6 million; 2016—$2.1 million; and 2017 to 2018—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 $7.3 million and $3.0 million for the three months ended March 31, 2014 and 2013, respectively. The future fixed and determinable portions of APL’s obligations as of March 31, 2014 were as follows: remainder of 2014—$6.3 million; 2015 to 2017—$3.5 million per year; and 2018—$2.7 million. | |
As of March 31, 2014, the Partnership and its subsidiaries are committed to expend approximately $84.5 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades. | |
Legal Proceedings | |
The Partnership and its subsidiaries are parties to various routine legal proceedings arising out of the ordinary course of its business. Management of the Partnership and its subsidiaries believe that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations. |
Issuances_of_Units
Issuances of Units | 3 Months Ended |
Mar. 31, 2014 | |
ISSUANCES OF UNITS | ' |
NOTE 14 —ISSUANCES OF UNITS | |
The Partnership | |
The Partnership recognizes gains on ARP’s and APL’s 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 ARP’s and APL’s 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 3), the Partnership purchased 3,746,986 of ARP’s newly created 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 March 2014, 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 of 1933, as amended (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 3), ARP issued 3,749,986 newly created Class C convertible preferred units to the Partnership at a negotiated price per unit of $23.10, for proceeds of $86.6 million. The Class C preferred units were issued with 562,497 warrants to purchase ARP common units at an exercise price of $23.10 at the Partnership’s option beginning on October 29, 2013. The warrants will expire on July 31, 2016. The Class C preferred units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act (see “Purchase of ARP Preferred Units”). | |
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 3), 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 8). | |
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 the equity distribution agreement effective December 27, 2013. | |
At March 31, 2014 and December 31, 2013, in connection with the issuance of ARP’s common units, the Partnership recorded gains of $14.6 million and $27.3 million within partners’ capital and a corresponding decrease in non-controlling interests on its consolidated balance sheets and consolidated statement of partners’ capital. | |
Atlas Pipeline Partners | |
Equity Offerings | |
In March 2014, APL issued 5,060,000 of its Class E Preferred Units to the public at an offering price of $25.00 per Class E Preferred Unit. APL received $122.4 million in net proceeds. The proceeds were used to pay down APL’s revolving credit facility. | |
APL will make cumulative cash distributions on the Class E Preferred Units from the date of original issue. The cash distributions will be payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year, when, and if, declared by the board of directors. The initial distribution on the Class E Preferred Units will be payable on July 15, 2014 in an amount equal to $0.67604 per unit, or approximately $3.4 million. Thereafter, APL will pay cumulative distributions in cash on the Class E Preferred Units on a quarterly basis at a rate of $0.515625 per unit, or 8.25% per year. | |
At any time on or after March 17, 2019, or in the event of a liquidation or certain changes of control, APL may redeem the Class E 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 on the date of redemption, whether or not declared. If APL does not exercise this redemption right upon a change of control, then the holders of the Class E Preferred Units will have the option to convert their Class E Preferred Units into a number of APL’s common units, as set forth in the Certificate of Designation relating to the Class E Preferred Units. | |
In May 2013, APL issued Class D Preferred Units in a private placement transaction to third party investors which are presented combined with a net $50.2 million unaccreted beneficial conversion discount within non-controlling interests on the Partnership’s consolidated balance sheet at March 31, 2014. The discount will be accreted and recognized by APL as imputed dividends over the term of the Class D Preferred Units as a reduction to APL’s net income attributable to the common limited partners and the Partnership, as general partner. For the three months ended March 31, 2014, APL recorded $11.4 million within income (loss) attributable to non-controlling interests for the preferred unit imputed dividend effect on the Partnership’s consolidated statements of operations to recognize the accretion of the beneficial conversion discount. | |
The Class D Preferred Units will receive distributions of additional Class D Preferred Units for the first four full quarterly periods following their issuance in May 2013, and thereafter will receive distributions in Class D Preferred Units, or cash, or a combination of Class D Preferred Units and cash, at the discretion of the Partnership, as general partner. For the three months ended March 31, 2014, APL recorded Class D Preferred Unit distributions in kind of $9.7 million within income (loss) attributable to non-controlling interests on the Partnership’s consolidated statements of operations. During the three months ended March 31, 2014, APL distributed 274,785 Class D Preferred Units to the holders of the Class D Preferred Units as a distribution in kind. APL’s Class D Preferred Unit distributions paid in kind represented non-cash transactions during the three months ended March 31, 2014. | |
APL had an equity distribution program with Citigroup Global Markets, Inc. (“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 three year period ended December 31, 2013, APL issued 3,895,679 common units under the equity distribution program for net proceeds of $137.8 million, net of $2.8 million in sales commissions incurred and other offering costs. APL also received capital contributions from the Partnership of $2.9 million during the year ended December 31, 2013 to maintain its 2.0% general partner interest in APL. APL utilized the net proceeds from the common unit offering for general partnership purposes. As of December 31, 2013, APL had used the full capacity under the equity distribution program. | |
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 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 3). | |
At December 31, 2013, in connection with the issuance of APL’s common units, the Partnership recorded an $11.9 million gain, respectively, within partner’s capital and a corresponding decrease in non-controlling interests on its consolidated balance sheets and consolidated statement of partners’ capital. No gain or loss was recorded within partners’ capital for the three months ended March 31, 2014. |
Cash_Distributions
Cash Distributions | 3 Months Ended | ||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||
CASH DISTRIBUTIONS | ' | ||||||||||||||||||
NOTE 15 — 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, 2013 through March 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 | ||||||||||||||||||
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 | ||||||||||||||
On April 23, 2014, the Partnership declared a cash distribution of $0.46 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2014. The $23.9 million distribution will be paid on May 20, 2014 to unitholders of record at the close of business on May 7, 2014. | |||||||||||||||||||
ARP Cash Distributions. ARP has a cash distribution policy under which it distributes, within 45 days following the end of each calendar quarter, all of its available cash (as defined in the partnership agreement) for that quarter to its common unitholders and general partner. In January 2014, ARP’s board of directors approved the modification of its cash distribution payment practice to a monthly cash distribution program beginning for the month of January 2014, whereby the monthly cash distribution will be paid within 45 days from the month end. 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 March 31, 2014 were as follows (in thousands, except per unit amounts): | |||||||||||||||||||
Date Cash Distribution Paid | For Quarter/ | Cash | Total Cash | Total Cash | Total Cash | ||||||||||||||
Month Ended | Distribution | Distribution | Distribution | Distribution to the | |||||||||||||||
per Common | to Common | To Preferred | General Partner | ||||||||||||||||
Limited | Limited | Limited | |||||||||||||||||
Partner Unit | Partners | Partners | |||||||||||||||||
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 | December 31, 2013 | $ | 0.58 | $ | 34,489 | $ | 4,400 | $ | 2,891 | ||||||||||
March 17, 2014 | 31-Jan-14 | $ | 0.1933 | $ | 12,718 | $ | 1,467 | $ | 1,055 | ||||||||||
April 14, 2014 | 28-Feb-14 | $ | 0.1933 | $ | 12,719 | $ | 1,466 | $ | 1,055 | ||||||||||
On April 23, 2014, ARP declared its monthly distribution of $0.1933 per common unit for the month of March 2014. The $15.3 million distribution, including $1.1 million and $1.5 million to the general partner and preferred limited partners, respectively, will be paid on May 15, 2014 to holders of record as of May 7, 2014. | |||||||||||||||||||
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, 2013 through March 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 | ||||||||||||||||||
May 15, 2013 | 31-Mar-13 | $ | 0.59 | $ | 45,382 | $ | 3,980 | ||||||||||||
August 14, 2013 | 30-Jun-13 | $ | 0.62 | $ | 48,165 | $ | 5,875 | ||||||||||||
November 14, 2013 | September 30, 2013 | $ | 0.62 | $ | 49,298 | $ | 6,013 | ||||||||||||
February 14, 2014 | 31-Dec-13 | $ | 0.62 | $ | 49,969 | $ | 6,095 | ||||||||||||
On April 22, 2014, APL declared a cash distribution of $0.62 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2014. The $56.1 million distribution, including $6.1 million to the Partnership as general partner, will be paid on May 15, 2014 to unitholders of record at the close of business on May 8, 2014. Based on this declaration, APL will issue approximately 317,000 Class D Preferred Units to the holders of the Class D Preferred Units as a preferred unit distribution in kind for the quarter ended March 31, 2014 (see Note 18). | |||||||||||||||||||
Benefit_Plans
Benefit Plans | 3 Months Ended | ||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||
BENEFIT PLANS | ' | ||||||||||||||||
NOTE 16 — BENEFIT PLANS | |||||||||||||||||
2010 Long-Term Incentive Plan | |||||||||||||||||
The Board of Directors of 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 March 31, 2014, the Partnership had 4,454,130 phantom units and unit options outstanding under the 2010 LTIP, with 1,217,255 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 March 31, 2014, there are 1,243,877 units that will vest within the following twelve months. All phantom units outstanding under the 2010 LTIP at March 31, 2014 include DERs. During the three months ended March 31, 2014 and 2013, the Partnership paid $0.9 million and $0.6 million, respectively, with respect to the 2010 LTIP DERs. | |||||||||||||||||
The following table sets forth the 2010 LTIP phantom unit activity for the periods indicated: | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Number | Weighted | Number | Weighted | ||||||||||||||
of Units | Average | of Units | Average | ||||||||||||||
Grant Date | Grant Date | ||||||||||||||||
Fair Value | Fair Value | ||||||||||||||||
Outstanding, beginning of year | 2,054,534 | $ | 22.56 | 2,044,227 | $ | 20.88 | |||||||||||
Granted | — | — | — | — | |||||||||||||
Vested and issued(1) | (38,335 | ) | 20.29 | (2,936 | ) | 17.47 | |||||||||||
Forfeited | (11,768 | ) | 27.25 | — | — | ||||||||||||
Outstanding, end of period(2) | 2,004,431 | $ | 22.57 | 2,041,291 | $ | 20.88 | |||||||||||
Vested and not yet issued(3) | 344,553 | $ | 20.6 | — | $ | — | |||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 2,928 | $ | 3,108 | |||||||||||||
(1) | The aggregate intrinsic values of phantom unit awards vested and issued were $1.7 million and $0.1 million, respectively, for the three months ended March 31, 2014 and 2013, respectively. | ||||||||||||||||
(2) | The aggregate intrinsic value of phantom unit awards outstanding at March 31, 2014 was $86.3 million. | ||||||||||||||||
(3) | The intrinsic value of phantom unit awards vested, but not yet issued at March 31, 2014 was $15.0 million. No phantom unit awards had vested, but had not yet been issued at March 31, 2013. | ||||||||||||||||
At March 31, 2014, the Partnership had approximately $13.3 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2010 LTIP based upon the fair value of the awards. | |||||||||||||||||
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 1,723,698 unit options outstanding under the 2010 LTIP at March 31, 2014 that will vest within the following twelve months. No cash was received from the exercise of options for the three months ended March 31, 2014 and 2013, respectively. | |||||||||||||||||
The following table sets forth the 2010 LTIP unit option activity for the periods indicated: | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Number | Weighted | Number | Weighted | ||||||||||||||
of Unit | Average | of Unit | Average | ||||||||||||||
Options | Exercise | Options | Exercise | ||||||||||||||
Price | Price | ||||||||||||||||
Outstanding, beginning of year | 2,452,412 | $ | 20.52 | 2,504,703 | $ | 20.51 | |||||||||||
Granted | — | — | — | — | |||||||||||||
Exercised(1) | — | — | — | — | |||||||||||||
Forfeited | (2,713 | ) | 17.47 | (2,604 | ) | 17.47 | |||||||||||
Outstanding, end of period(2)(3) | 2,449,699 | $ | 20.52 | 2,502,099 | $ | 20.52 | |||||||||||
Options exercisable, end of period(4) | 569,368 | $ | 20.43 | 3,398 | $ | 20.85 | |||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 1,438 | $ | 1,515 | |||||||||||||
(1) | No options were exercised during the three months ended March 31, 2014 and 2013. | ||||||||||||||||
(2) | The weighted average remaining contractual life for outstanding options at March 31, 2014 was 7.0 years. | ||||||||||||||||
(3) | The options outstanding at March 31, 2014 had an aggregate intrinsic value of $55.2 million. | ||||||||||||||||
(4) | The weighted average remaining contractual lives for exercisable options at March 31, 2014 and 2013 were 7.0 years and 8.4 years, respectively. The intrinsic values of exercisable options at March 31, 2014 and 2013 were $12.9 million and $0.1 million, respectively. | ||||||||||||||||
At March 31, 2014, the Partnership had approximately $4.2 million in unrecognized compensation expense related to unvested unit options outstanding under the 2010 LTIP based upon the fair value of the awards. 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. | |||||||||||||||||
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 March 31, 2014, the Partnership had 1,534,966 phantom units and unit options outstanding under the 2006 LTIP, with 339,639 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 March 31, 2014, 264,859 units will vest within the following twelve months. All phantom units outstanding under the 2006 LTIP at March 31, 2014 include DERs. During the three months ended March 31, 2014 and 2013, the Partnership paid $0.1 million 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: | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Number | Weighted | Number | Weighted | ||||||||||||||
of Units | Average | of Units | Average | ||||||||||||||
Grant Date | Grant Date | ||||||||||||||||
Fair Value | Fair Value | ||||||||||||||||
Outstanding, beginning of year | 234,940 | $ | 35.82 | 50,759 | $ | 21.02 | |||||||||||
Granted | 423,837 | 43.23 | 204,777 | 37.92 | |||||||||||||
Vested and issued(1) (2) | (63,750 | ) | 35.33 | (5,500 | ) | 18.16 | |||||||||||
Forfeited | — | — | — | — | |||||||||||||
Outstanding, end of period(3)(4) | 595,027 | $ | 41.15 | 250,036 | $ | 34.92 | |||||||||||
Vested and not yet issued(5) | 11,497 | $ | 37.68 | — | $ | — | |||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 2,988 | $ | 1,147 | |||||||||||||
-1 | The intrinsic value for phantom unit awards vested and issued during the three months ended March 31, 2014 and 2013 were $3.0 million and $0.2 million, respectively. | ||||||||||||||||
-2 | There were 3,884 and 522 vested units during the three months ended March 31, 2014 and 2013, respectively, that settled for cash consideration of approximately $185,000 and approximately $20,000, respectively. | ||||||||||||||||
-3 | The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2014 was $25.6 million. | ||||||||||||||||
-4 | There was $0.7 million and $1.1 million recognized as liabilities on the Partnership’s consolidated balance sheets at March 31, 2014 and December 31, 2013, respectively, representing 41,067 and 41,525 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 are $36.53 and $29.67 as of March 31, 2014 and December 31, 2013, respectively. | ||||||||||||||||
-5 | The intrinsic value of phantom unit awards vested, but not yet issued at March 31, 2014 was $0.5 million. No phantom units were vested, but not yet issued at March 31, 2013. | ||||||||||||||||
At March 31, 2014, the Partnership had approximately $19.4 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2006 LTIP based upon the fair value of the awards. | |||||||||||||||||
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 March 31, 2014 that will vest within the following twelve months. No cash was received from the exercise of options for the three months ended March 31, 2014 and 2013. | |||||||||||||||||
The following table sets forth the 2006 LTIP unit option activity for the periods indicated: | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Number | Weighted | Number | Weighted | ||||||||||||||
of Unit | Average | of Unit | Average | ||||||||||||||
Options | Exercise | Options | Exercise | ||||||||||||||
Price | Price | ||||||||||||||||
Outstanding, beginning of year | 939,939 | $ | 20.94 | 929,939 | $ | 20.75 | |||||||||||
Granted | — | — | 10,000 | 38.51 | |||||||||||||
Exercised(1) | — | — | — | — | |||||||||||||
Forfeited | — | — | — | — | |||||||||||||
Outstanding, end of year(2)(3) | 939,939 | $ | 20.94 | 939,939 | $ | 20.94 | |||||||||||
Options exercisable, end of period(4)(5) | 932,439 | $ | 20.8 | 929,939 | $ | 20.75 | |||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 7 | $ | 7 | |||||||||||||
-1 | No options were exercised during the three months ended March 31, 2014 and 2013. | ||||||||||||||||
-2 | The weighted average remaining contractual life for outstanding options at March 31, 2014 was 2.7 years. | ||||||||||||||||
-3 | The aggregate intrinsic value of options outstanding at March 31, 2014 was approximately $20.8 million. | ||||||||||||||||
-4 | The weighted average remaining contractual lives for exercisable options at March 31, 2014 and 2013 were 2.6 years and 3.6 years, respectively. | ||||||||||||||||
-5 | The aggregate intrinsic values of options exercisable at March 31, 2014 and 2013 were $20.7 million and $21.7 million, respectively. | ||||||||||||||||
At March 31, 2014, the Partnership had approximately $33,000 of unrecognized compensation expense related to unvested unit options outstanding under the 2006 LTIP based upon the fair value of the awards. 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: | |||||||||||||||||
Three Months Ended | |||||||||||||||||
March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
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 has a 2012 Long-Term Incentive Plan effective March 2012 (the “ARP LTIP”). Awards of options to purchase units, restricted units and phantom units may be granted to officers, employees and directors of ARP’s general partner under the ARP LTIP, and such awards may be subject to vesting terms and conditions in the discretion of the administrator of the ARP LTIP. Up to 2,900,0000 common units of ARP, subject to adjustment as provided for under the ARP LTIP, may be issued pursuant to awards granted under the ARP LTIP. The ARP LTIP is administered by the Compensation Committee of the board (the “ARP LTIP Committee”). At March 31, 2014, ARP had 2,284,983 phantom units, restricted units and unit options outstanding under the ARP LTIP, with 372,711 phantom units, restricted 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 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 March 31, 2014, 275,545 units will vest within the following twelve months. All phantom units outstanding under the ARP LTIP at March 31, 2014 include DERs. During the three months ended March 31, 2014 and 2013, ARP paid $0.6 million and $0.5 million, respectively, with respect to the ARP LTIP’s DERs. These amounts were recorded as reductions of non-controlling interest on the Partnership’s consolidated balance sheets. | |||||||||||||||||
The following table sets forth the ARP LTIP phantom unit activity for the periods indicated: | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Number | Weighted | Number | Weighted | ||||||||||||||
of Units | Average | of Units | Average | ||||||||||||||
Grant Date | Grant Date | ||||||||||||||||
Fair Value | Fair Value | ||||||||||||||||
Outstanding, beginning of year | 839,808 | $ | 24.31 | 948,476 | $ | 24.76 | |||||||||||
Granted | 3,500 | 20.99 | 83,250 | 21.96 | |||||||||||||
Vested and issued(1) | (15,500 | ) | 22.69 | (2,465 | ) | 24.67 | |||||||||||
Forfeited | (15,500 | ) | 22.63 | (4,000 | ) | 25.14 | |||||||||||
Outstanding, end of period(2)(3) | 812,308 | $ | 24.35 | 1,025,261 | $ | 24.53 | |||||||||||
Vested and not yet issued(4) | 6,875 | $ | 22.76 | — | $ | — | |||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 1,731 | $ | 3,053 | |||||||||||||
-1 | The intrinsic value of phantom unit awards vested and issued during the three months ended March 31, 2014 and 2013 was $0.3 million and $0.1 million, respectively. | ||||||||||||||||
-2 | The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2014 was $17.0 million. | ||||||||||||||||
-3 | There was $0.1 million recognized as liabilities on the Partnership’s consolidated balance sheets at the periods ended March 31, 2014 and December 31, 2013, representing 16,084 units for the periods ending March 31, 2014 and December 31, 2013 due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair value for these units was $22.15 for the periods ending March 31, 2014 and December 31, 2013, respectively. There was approximately $44,000 recognized as liabilities on the Partnership’s consolidated balance sheet at March 31, 2013, representing 3,476 units, due to the option of the participants to settle in cash instead of units. The weighted average grant date fair value for these units was $28.75 at March 31, 2013. | ||||||||||||||||
-4 | The intrinsic value of phantom unit awards vested, but not yet issued at March 31, 2014 was $0.1 million. No phantom unit awards had vested, but had not yet been issued at March 31, 2013. | ||||||||||||||||
At March 31, 2014, ARP had approximately $6.9 million in unrecognized compensation expense related to unvested phantom units outstanding under the ARP LTIP based upon the fair value of the awards. | |||||||||||||||||
ARP Unit Options. The exercise price of the unit option may be equal to or more than the fair market value of ARP’s common unit on the date of grant of the option. 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 367,575 unit options outstanding under the ARP LTIP at March 31, 2014 that will vest within the following twelve months. No cash was received from the exercise of options for the three months ended March 31, 2014 and 2013. | |||||||||||||||||
The following table sets forth the ARP LTIP unit option activity for the periods indicated: | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Number | Weighted | Number | Weighted | ||||||||||||||
of Units | Average | of Units | Average | ||||||||||||||
Exercise | Exercise | ||||||||||||||||
Price | Price | ||||||||||||||||
Outstanding, beginning of year | 1,482,675 | $ | 24.66 | 1,515,500 | $ | 24.68 | |||||||||||
Granted | — | — | 2,000 | 22.27 | |||||||||||||
Exercised (1) | — | — | — | — | |||||||||||||
Forfeited | (10,000 | ) | 23.4 | (4,000 | ) | 25.14 | |||||||||||
Outstanding, end of period(2)(3) | 1,472,675 | $ | 24.66 | 1,513,500 | $ | 24.67 | |||||||||||
Options exercisable, end of period(4) | 368,825 | $ | 24.67 | — | $ | — | |||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 612 | $ | 1,194 | |||||||||||||
-1 | No options were exercised during the three months ended March 31, 2014, and 2013. | ||||||||||||||||
-2 | The weighted average remaining contractual life for outstanding options at March 31, 2014 was 8.1 years. | ||||||||||||||||
-3 | The aggregate intrinsic value of options outstanding at March 31, 2014 was approximately $2,000. | ||||||||||||||||
-4 | The weighted average remaining contractual life for exercisable options at March 31, 2014 was 8.1 years. There were no intrinsic values for options exercisable at March 31, 2014 and 2013. | ||||||||||||||||
At March 31, 2014, ARP had approximately $2.2 million in unrecognized compensation expense related to unvested unit options outstanding under the ARP LTIP based upon the fair value of the awards. 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: | |||||||||||||||||
Three Months Ended | |||||||||||||||||
March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Expected dividend yield | — | % | 6.6 | % | |||||||||||||
Expected unit price volatility | — | % | 44 | % | |||||||||||||
Risk-free interest rate | — | % | 1.1 | % | |||||||||||||
Expected term (in years) | — | 6.25 | |||||||||||||||
Fair value of unit options granted | $ | — | $ | 4.85 | |||||||||||||
APL Long-Term Incentive Plans | |||||||||||||||||
APL has a 2004 Long-Term Incentive Plan (“APL 2004 LTIP”), and a 2010 Long-Term Incentive Plan, which was modified on April 26, 2011 (“APL 2010 LTIP” and collectively with the APL 2004 LTIP, the “APL LTIPs”), in which officers, employees and non-employee managing board members of APL’s general partner and employees of APL’s general partner’s affiliates and consultants are eligible to participate. The APL LTIPs are administered by APL’s 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 March 31, 2014, APL had 1,664,642 phantom units outstanding under the APL LTIPs, with 608,369 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. Share based payments to non-employees that have a cash settlement option are recognized within liabilities in the consolidated financial statements based upon their current fair market value. There were no unit options outstanding as of March 31, 2014. | |||||||||||||||||
APL Phantom Units. Through March 31, 2014, phantom units granted under the APL LTIPs generally had vesting periods of four years. However, in February 2014, APL granted 227,000 phantom units which had a vesting period of three years. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards to non-employee members of APL’s board automatically vest upon a change of control, as defined in the APL LTIPs. Of the units outstanding under the APL LTIPs at March 31, 2014, 531,244 phantom units 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. | |||||||||||||||||
All phantom units outstanding under the APL LTIPs at March 31, 2014 include DERs. The amounts paid with respect to APL LTIP DERs were $0.9 million and $0.6 million, respectively, for the three months ended March 31, 2014 and 2013, respectively. These amounts were recorded as reductions of non-controlling interest on the Partnership’s consolidated balance sheet. | |||||||||||||||||
The following table sets forth the APL LTIP phantom unit activity for the periods indicated: | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Number | Weighted | Number | Weighted | ||||||||||||||
of Units | Average | of Units | Average | ||||||||||||||
Grant Date | Grant Date | ||||||||||||||||
Fair Value | Fair Value | ||||||||||||||||
Outstanding, beginning of year | 1,446,553 | $ | 36.32 | 1,053,242 | $ | 33.21 | |||||||||||
Granted | 234,701 | 31.03 | 6,804 | 33.06 | |||||||||||||
Vested and issued(1) | (14,412 | ) | 34.03 | (2,963 | ) | 28.94 | |||||||||||
Forfeited | (2,200 | ) | 39.51 | — | — | ||||||||||||
Outstanding, end of period(2)(3) | 1,664,642 | $ | 35.59 | 1,057,083 | $ | 33.22 | |||||||||||
Non-cash compensation expense recognized | $ | 6,439 | $ | 4,384 | |||||||||||||
(in thousands) | |||||||||||||||||
(1) | The intrinsic values for phantom unit awards vested and issued were $0.5 million and $0.1 million, respectively, during the three months ended March 31, 2014 and 2013, respectively. | ||||||||||||||||
(2) | There were 25,228 and 22,539 outstanding phantom unit awards at March 31, 2014 and December 31, 2013, respectively, which were classified as liabilities due to a cash option available on the related phantom unit awards. | ||||||||||||||||
(3) | The aggregate intrinsic values for phantom unit awards outstanding at ended March 31, 2014 and December 31, 2013 were $53.5 million and $50.7 million, respectively. | ||||||||||||||||
At March 31 2014, APL had approximately $31.5 million of unrecognized compensation expense related to 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 2.0 years. |
Operating_Segment_Information
Operating Segment Information | 3 Months Ended | ||||||||
Mar. 31, 2014 | |||||||||
OPERATING SEGMENT INFORMATION | ' | ||||||||
NOTE 17 — 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): | |||||||||
Three Months Ended | |||||||||
March 31, | |||||||||
2014 | 2013 | ||||||||
Atlas Resource: | |||||||||
Revenues | $ | 157,345 | $ | 112,048 | |||||
Operating costs and expenses | (103,078 | ) | (88,626 | ) | |||||
Depreciation, depletion and amortization expense | (50,237 | ) | (21,208 | ) | |||||
Loss on asset sales and disposal | (1,603 | ) | (702 | ) | |||||
Interest expense | (13,188 | ) | (6,889 | ) | |||||
Segment loss | $ | (10,761 | ) | $ | (5,377 | ) | |||
Atlas Pipeline: | |||||||||
Revenues | $ | 698,089 | $ | 409,952 | |||||
Operating costs and expenses | (618,138 | ) | (361,718 | ) | |||||
Depreciation, depletion and amortization expense | (49,239 | ) | (30,458 | ) | |||||
Loss on asset sales and disposal | — | — | |||||||
Interest expense | (23,663 | ) | (18,686 | ) | |||||
Loss on early extinguishment of debt | — | (26,582 | ) | ||||||
Segment income (loss) | $ | 7,049 | $ | (27,492 | ) | ||||
Corporate and other: | |||||||||
Revenues | $ | 4,828 | $ | 102 | |||||
Operating costs and expenses | (15,918 | ) | (8,692 | ) | |||||
Depreciation, depletion and amortization expense | (1,802 | ) | — | ||||||
Loss on asset sales and disposal | — | — | |||||||
Interest expense | (4,463 | ) | (235 | ) | |||||
Segment loss | $ | (17,355 | ) | $ | (8,825 | ) | |||
Reconciliation of segment income (loss) to net loss: | |||||||||
Segment income (loss): | |||||||||
Atlas Resource | $ | (10,761 | ) | $ | (5,377 | ) | |||
Atlas Pipeline | 7,049 | (27,492 | ) | ||||||
Corporate and other | (17,355 | ) | (8,825 | ) | |||||
Net loss | $ | (21,067 | ) | $ | (41,694 | ) | |||
Capital expenditures: | |||||||||
Atlas Resource | $ | 39,897 | $ | 58,487 | |||||
Atlas Pipeline | 128,331 | 108,516 | |||||||
Corporate and other | 4,522 | — | |||||||
Total capital expenditures | $ | 172,750 | $ | 167,003 | |||||
March 31, | December 31, | ||||||||
2014 | 2013 | ||||||||
Balance sheet: | |||||||||
Goodwill: | |||||||||
Atlas Resource | $ | 31,784 | $ | 31,784 | |||||
Atlas Pipeline | 370,396 | 368,572 | |||||||
Corporate and other | — | — | |||||||
$ | 402,180 | $ | 400,356 | ||||||
Total assets: | |||||||||
Atlas Resource | $ | 2,321,905 | $ | 2,343,800 | |||||
Atlas Pipeline | 4,446,958 | 4,327,845 | |||||||
Corporate and other | 129,373 | 120,996 | |||||||
$ | 6,898,236 | $ | 6,792,641 | ||||||
Subsequent_Events
Subsequent Events | 3 Months Ended |
Mar. 31, 2014 | |
SUBSEQUENT EVENTS | ' |
NOTE 18 — SUBSEQUENT EVENTS | |
Cash Distribution. On April 23, 2014, the Partnership declared a cash distribution of $0.46 per unit on its outstanding common units, representing the cash distribution for the quarter ended March 31, 2014. The $23.9 million distribution will be paid on May 20, 2014 to unitholders of record at the close of business on May 7, 2014. | |
Atlas Resource | |
Cash Distribution. On April 23, 2014, ARP declared a cash distribution of $0.1933 per common unit for the month of March 2014. The $15.3 million distribution, including $1.1 million and $1.5 million to the general partner and preferred limited partners, respectively, will be paid on May 15, 2014 to holders of record as of May 7, 2014. | |
Merit Acquisition. On May 7, 2014, ARP entered into a definitive purchase and sale agreement to acquire Merit Energy Company’s (“Merit”) non-operated producing oil wells in the Rangely field of northwest Colorado for $420 million in cash, subject to customary closing adjustments. The transaction is expected to close during the second quarter of 2014 and has an effective date of April 1, 2014. In connection with the transaction, on May 8, 2014, ARP issued 13,500,000 of its common limited partner units in a public offering at a price of $19.18 per unit, yielding net proceeds of approximately $258.7 million. | |
Atlas Pipeline | |
Sale of WTLPG. On May 5, 2014, APL entered into a definitive agreement to sell its 20% interest in WTLPG to Martin Midstream Partners, L.P. for $135.0 million in cash, subject to certain customary closing adjustments. The proceeds from the sale will be used to repay borrowings outstanding on APL’s credit facility. | |
Distribution. On April 22, 2014, APL declared a cash distribution of $0.62 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2014. The $56.1 million distribution, including $6.1 million to the Partnership as general partner, will be paid on May 15, 2014 to unitholders of record at the close of business on May 8, 2014. Based on this declaration, APL will also issue approximately 317,000 Class D Preferred Units to the holders of the Class D Preferred Units as a preferred unit distribution in kind for the quarter ended March 31, 2014. |
Summary_of_Significant_Account1
Summary of Significant Accounting Policies (Policies) | 3 Months Ended | ||||||||||||
Mar. 31, 2014 | |||||||||||||
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 March 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. | |||||||||||||
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. | |||||||||||||
The Partnership’s consolidated financial statements include APL’s 95% ownership interest in 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 4). | |||||||||||||
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. | |||||||||||||
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. | |||||||||||||
The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the three months ended March 31, 2014 and 2013 represent actual results in all material respects (see “Revenue Recognition”). | |||||||||||||
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 its customers. At March 31, 2014 and December 31, 2013, the Partnership had recorded no allowance for uncollectible accounts receivable on its consolidated balance sheets. | |||||||||||||
Inventory | ' | ||||||||||||
Inventory | |||||||||||||
The Partnership had $32.0 million and $19.7 million of inventory at March 31, 2014 and December 31, 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. | |||||||||||||
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 three months ended March 31, 2014 and 2013. | |||||||||||||
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, 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. There were no impairments of proved gas and oil properties recorded by ARP for the three months ended March 31, 2014 and 2013. | |||||||||||||
The impairments of proved and unproved properties during the year ended December 31, 2013 related to the carrying amounts of these gas and oil properties being in excess of ARP’s estimate of their fair values at December 31, 2013 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 natural gas 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 in the aggregate were 5.6% and 6.1% for the three months ended March 31, 2014 and 2013, respectively. The aggregate amounts of interest capitalized by ARP and APL were $5.5 million and $5.9 million for the three months ended March 31, 2014 and 2013, 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 TEAK acquisition (see Note 3), 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 acquisition of 100% of the equity interests of TEAK Midstream, LLC (“TEAK”) in 2013 (the “TEAK Acquisition”) (see Note 3), 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 March 31, 2014 and December 31, 2013 (in thousands): | |||||||||||||
March 31, | December 31, | Estimated | |||||||||||
2014 | 2013 | Useful Lives | |||||||||||
In Years | |||||||||||||
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 | $ | (216,288 | ) | $ | (194,801 | ) | |||||||
(13,449 | ) | (13,381 | ) | ||||||||||
Partnership management and operating contracts | |||||||||||||
$ | (229,737 | ) | $ | (208,182 | ) | ||||||||
Net Carrying Amount: | |||||||||||||
Customer contracts and relationships | $ | 654,784 | $ | 696,271 | |||||||||
Partnership management and operating contracts | 895 | 963 | |||||||||||
$ | 655,679 | $ | 697,234 | ||||||||||
Amortization expense on intangible assets was $21.6 million and $8.2 million for the three months ended March 31, 2014 and 2013, respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2014 - $80.3 million; 2015 - $74.3 million; 2016 - $74.2 million; 2017 - $68.1 million; and 2018 - $59.6 million. | |||||||||||||
Goodwill | ' | ||||||||||||
Goodwill | |||||||||||||
The following table reflects the carrying amounts of goodwill by reportable operating segments at March 31, 2014 and December 31, 2013 (in thousands): | |||||||||||||
March 31, | December 31, | ||||||||||||
2014 | 2013 | ||||||||||||
Atlas Resource | $ | 31,784 | $ | 31,784 | |||||||||
Atlas Pipeline | 370,396 | 368,572 | |||||||||||
$ | 402,180 | $ | 400,356 | ||||||||||
At March 31, 2014, the Partnership had $402.2 million of goodwill, which consisted of $31.8 million related to prior ARP consummated acquisitions and $370.4 million related to APL’s Cardinal Acquisition in 2012 and TEAK Acquisition in 2013. The goodwill related to APL’s Cardinal Acquisition is a result of the strategic industry position and potential future synergies. The goodwill related to APL’s TEAK Acquisition is a result of the strategic industry position. The change in APL’s goodwill during the three months ended March 31, 2014 is primarily related to a $1.8 million increase in goodwill related to an adjustment of the fair value of assets acquired and liabilities assumed from the TEAK Acquisition (see Note 3). | |||||||||||||
ARP and APL test goodwill for impairment at each year end by comparing its reporting unit estimated fair values to carrying values. 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. | |||||||||||||
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 three months ended March 31, 2014 and 2013, no impairment indicators arose and no goodwill impairments were recognized for ARP or APL by the Partnership. | |||||||||||||
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 7). 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 March 31, 2014 or December 31, 2013 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 reflect 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 three months ended March 31, 2014 and 2013. | |||||||||||||
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 2010. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of March 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 March 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 11). | |||||||||||||
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 16), 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): | |||||||||||||
Three Months Ended | |||||||||||||
March 31, | |||||||||||||
Continuing Operations: | 2014 | 2013 | |||||||||||
Net loss | $ | (21,067 | ) | $ | (41,694 | ) | |||||||
Loss attributable to non-controlling interests | 7,142 | 29,098 | |||||||||||
Net loss attributable to common limited partners | (13,925 | ) | (12,596 | ) | |||||||||
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 | $ | (13,925 | ) | $ | (12,596 | ) | |||||||
(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 three months ended March 31, 2014 and 2013, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 2,398,000 and 2,216,000 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 16). | |||||||||||||
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): | |||||||||||||
Three Months Ended | |||||||||||||
March 31, | |||||||||||||
2014 | 2013 | ||||||||||||
Weighted average number of common limited partners per unit—basic | 51,491 | 51,369 | |||||||||||
Add effect of dilutive incentive awards(1) | — | — | |||||||||||
Weighted average number of common limited partners per unit—diluted | 51,491 | 51,369 | |||||||||||
(1) | For the three months ended March 31, 2014 and 2013, approximately 4,111,000 units and 3,594,000 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. | ||||||||||||
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, the Drilling Partnerships. ARP contracts with the Drilling Partnerships to drill partnership wells. The contracts require that the Drilling Partnerships pay ARP the full contract price upon execution. The income from a drilling contract is recognized as the services are performed using the percentage of completion method. The contracts are typically completed between 60 and 270 days. On an uncompleted contract, ARP classifies the difference between the contract payments it has received and the revenue earned as a current liability titled “Liabilities Associated with Drilling Contracts” on the Partnership’s consolidated balance sheets. ARP recognizes well services revenues at the time the services are performed. ARP is also entitled to receive management fees according to the respective partnership agreements and recognizes such fees as income when earned, which are included in administration and oversight revenues within the Partnership’s consolidated statements of operations. | |||||||||||||
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, treating and transportation 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, if any, at 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. In connection with its gathering, processing and transportation operations, APL enters into the following types of contractual relationships with its producers and shippers: | |||||||||||||
· | Fee-Based Contracts. These contracts provide a set fee for gathering and/or processing raw natural gas and for transporting NGLs. APL’s revenue is a function of the volume of natural gas that it gathers and processes or the volume of NGLs transported and is not directly dependent on the value of the natural gas or NGLs. However, sustained low commodity prices could result in a decline in volumes and a corresponding decrease in fee revenue. APL is also paid a separate compression fee on many of its gathering systems. The fee is dependent upon the volume of gas flowing through its compressors and the quantity of compression stages utilized to gather the gas. | ||||||||||||
· | 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. POP contracts may include a fee component which is charged to the producer. | ||||||||||||
· | Fixed Recoveries. Fee-based or POP contracts sometimes include fixed recovery terms, which mean that the prices paid or products returned to the producer are calculated using an agreed NGL recovery factor, regardless of the volumes of NGLs actually recovered through processing. | ||||||||||||
· | 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. Therefore, APL bears the economic risk (the “processing margin risk”) that (i) the Btu quantity of residue gas available for redelivery to the producer may be less than APL received from the producer; and/or (ii) aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount that it paid for the unprocessed natural gas. In order to help mitigate the risk associated with Keep-Whole contracts, APL generally imposes a fee to gather the gas that is settled under this arrangement. Also, because the natural gas volumes contracted under some Keep-Whole agreements are lower in Btu content and thus can meet downstream pipeline specifications without being processed, the natural gas can be bypassed around the processing plants on these systems and delivered directly into downstream pipelines during periods when the processing margin is uneconomic. | ||||||||||||
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 at March 31, 2014 and December 31, 2013 of $268.9 million and $191.8 million, respectively, which were included in accounts receivable within its consolidated balance sheets. APL’s accrued purchase costs at March 31, 2014 and December 31, 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 9). 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 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 is 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. |
Derivative_Instruments_Policie
Derivative Instruments (Policies) | 3 Months Ended |
Mar. 31, 2014 | |
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. | |
Fair_Value_of_Financial_Instru1
Fair Value of Financial Instruments (Policies) | 3 Months Ended |
Mar. 31, 2014 | |
Fair Value of Financial Instruments, Policy | ' |
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. | |
Summary_of_Significant_Account2
Summary of Significant Accounting Policies (Tables) | 3 Months Ended | ||||||||||||
Mar. 31, 2014 | |||||||||||||
Schedule of the Components of Intangible Assets Being Amortized | ' | ||||||||||||
The following table reflects the components of intangible assets being amortized at March 31, 2014 and December 31, 2013 (in thousands): | |||||||||||||
March 31, | December 31, | Estimated | |||||||||||
2014 | 2013 | Useful Lives | |||||||||||
In Years | |||||||||||||
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 | $ | (216,288 | ) | $ | (194,801 | ) | |||||||
(13,449 | ) | (13,381 | ) | ||||||||||
Partnership management and operating contracts | |||||||||||||
$ | (229,737 | ) | $ | (208,182 | ) | ||||||||
Net Carrying Amount: | |||||||||||||
Customer contracts and relationships | $ | 654,784 | $ | 696,271 | |||||||||
Partnership management and operating contracts | 895 | 963 | |||||||||||
$ | 655,679 | $ | 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 March 31, 2014 and December 31, 2013 (in thousands): | |||||||||||||
March 31, | December 31, | ||||||||||||
2014 | 2013 | ||||||||||||
Atlas Resource | $ | 31,784 | $ | 31,784 | |||||||||
Atlas Pipeline | 370,396 | 368,572 | |||||||||||
$ | 402,180 | $ | 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): | |||||||||||||
Three Months Ended | |||||||||||||
March 31, | |||||||||||||
Continuing Operations: | 2014 | 2013 | |||||||||||
Net loss | $ | (21,067 | ) | $ | (41,694 | ) | |||||||
Loss attributable to non-controlling interests | 7,142 | 29,098 | |||||||||||
Net loss attributable to common limited partners | (13,925 | ) | (12,596 | ) | |||||||||
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 | $ | (13,925 | ) | $ | (12,596 | ) | |||||||
(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 three months ended March 31, 2014 and 2013, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 2,398,000 and 2,216,000 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): | |||||||||||||
Three Months Ended | |||||||||||||
March 31, | |||||||||||||
2014 | 2013 | ||||||||||||
Weighted average number of common limited partners per unit—basic | 51,491 | 51,369 | |||||||||||
Add effect of dilutive incentive awards(1) | — | — | |||||||||||
Weighted average number of common limited partners per unit—diluted | 51,491 | 51,369 | |||||||||||
(1) | For the three months ended March 31, 2014 and 2013, approximately 4,111,000 units and 3,594,000 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_Tables
Acquisitions (Tables) | 3 Months Ended | ||||
Mar. 31, 2014 | |||||
Ep Energy | ' | ||||
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 | $ | 5,268 | |||
Property, plant and equipment | 723,657 | ||||
Total current assets | $ | 728,925 | |||
Liabilities: | |||||
Accounts payable | 2,562 | ||||
Asset retirement obligation | 16,728 | ||||
Total liabilities assumed | 19,290 | ||||
Net assets acquired | $ | 709,635 | |||
TEAK Acquisition | ' | ||||
Assets Acquired and Liabilities Assumed in Acquisition | ' | ||||
The following table presents the preliminary values assigned to the assets acquired and liabilities assumed in the TEAK Acquisition, based on their estimated fair values at 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 | 193,877 | ||||
Intangible assets | 430,000 | ||||
Goodwill | 190,683 | ||||
Equity method investment in joint ventures | 183,801 | ||||
Total assets acquired | $ | 1,019,116 | |||
Liabilities: | |||||
Accounts payable and accrued liabilities | (35,296 | ) | |||
Other long term liabilities | (1,075 | ) | |||
Total liabilities assumed | (36,371 | ) | |||
Net assets acquired | 982,745 | ||||
Less cash received | (8,074 | ) | |||
Net cash paid for acquisition | $ | 974,671 | |||
APL_Equity_Method_Investments_
APL Equity Method Investments (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2014 | |||||||||
Schedule of Equity Method Investments | ' | ||||||||
The following tables present the values of APL’s equity method investments as of March 31, 2014 and December 31, 2013 and equity income (loss) in joint ventures as of March 31, 2014 and 2013 (in thousands): | |||||||||
Investment in Joint Venture | |||||||||
March 31, | December 31, | ||||||||
2014 | 2013 | ||||||||
WTLPG | $ | 85,517 | $ | 85,790 | |||||
T2 LaSalle | 58,731 | 50,534 | |||||||
T2 Eagle Ford | 110,091 | 97,437 | |||||||
T2 Co-Gen | 14,719 | 14,540 | |||||||
Equity method investment in joint ventures | $ | 269,058 | $ | 248,301 | |||||
Equity Income from Joint Ventures | ' | ||||||||
Three Months Ended | |||||||||
March 31, | |||||||||
2014 | 2013 | ||||||||
Equity income in WTLPG | $ | 1,727 | $ | 2,040 | |||||
Equity loss in T2 LaSalle | (1,113 | ) | — | ||||||
Equity loss in T2 Eagle Ford | (2,045 | ) | — | ||||||
Equity loss in T2 Co-Gen | (447 | ) | — | ||||||
Equity income (loss) in joint ventures | $ | (1,878 | ) | $ | 2,040 | ||||
Property_Plant_and_Equipment_T
Property, Plant and Equipment (Tables) | 3 Months Ended | ||||||||||||
Mar. 31, 2014 | |||||||||||||
Summary of Property, Plant and Equipment | ' | ||||||||||||
The following is a summary of property, plant and equipment at the dates indicated (in thousands): | |||||||||||||
March 31, | December 31, | Estimated | |||||||||||
Useful Lives | |||||||||||||
2014 | 2013 | in Years | |||||||||||
Natural gas and oil properties: | |||||||||||||
Proved properties: | |||||||||||||
Leasehold interests | $ | 323,698 | $ | 322,217 | |||||||||
Pre-development costs | 4,066 | 4,367 | |||||||||||
Wells and related equipment | 2,280,114 | 2,231,213 | |||||||||||
Total proved properties | 2,607,878 | 2,557,797 | |||||||||||
Unproved properties | 216,691 | 211,851 | |||||||||||
Support equipment | 26,656 | 23,258 | |||||||||||
Total natural gas and oil properties | 2,851,225 | 2,792,906 | |||||||||||
Pipelines, processing and compression facilities | 3,063,750 | 2,926,134 | 2–40 | ||||||||||
Rights of way | 195,518 | 203,966 | 20–40 | ||||||||||
Land, buildings and improvements | 29,735 | 30,216 | 3–40 | ||||||||||
Other | 37,372 | 36,752 | 3–10 | ||||||||||
6,177,600 | 5,989,974 | ||||||||||||
Less – accumulated depreciation, depletion and | (1,153,095 | ) | (1,079,099 | ) | |||||||||
amortization | |||||||||||||
$ | 5,024,505 | $ | 4,910,875 | ||||||||||
Other_Assets_Tables
Other Assets (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2014 | |||||||||
Summary of Other Assets | ' | ||||||||
The following is a summary of other assets at the dates indicated (in thousands): | |||||||||
March 31, | December 31, | ||||||||
2014 | 2013 | ||||||||
Deferred financing costs, net of accumulated amortization of $47,811 and $43,702 at March 31, 2014 and December 31, 2013, respectively | $ | 83,413 | $ | 86,617 | |||||
Investment in Lightfoot | 21,337 | 21,454 | |||||||
Security deposits | 6,082 | 5,631 | |||||||
ARP notes receivable | 4,012 | 3,978 | |||||||
Long-term derivative asset receivable from Drilling Partnerships | 1,007 | 863 | |||||||
Other | 8,454 | 6,129 | |||||||
$ | 124,305 | $ | 124,672 | ||||||
Asset_Retirement_Obligations_T
Asset Retirement Obligations (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2014 | |||||||||
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): | |||||||||
Three Months Ended | |||||||||
March 31, | |||||||||
2014 | 2013 | ||||||||
Asset retirement obligations, beginning of | $ | 91,214 | $ | 64,794 | |||||
year | |||||||||
Liabilities incurred | 602 | 645 | |||||||
Liabilities settled | (217 | ) | (7 | ) | |||||
Accretion expense | 1,328 | 954 | |||||||
Asset retirement obligations, end of period | $ | 92,927 | $ | 66,386 | |||||
Debt_Tables
Debt (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2014 | |||||||||
Total Debt | ' | ||||||||
Total debt consists of the following at the dates indicated (in thousands): | |||||||||
March 31, | December 31, | ||||||||
2014 | 2013 | ||||||||
Term loan facility | $ | 238,800 | $ | 239,400 | |||||
Revolving credit facility | — | — | |||||||
ARP revolving credit facility | 366,000 | 419,000 | |||||||
ARP 7.75% Senior Notes – due 2021 | 275,000 | 275,000 | |||||||
ARP 9.25% Senior Notes – due 2021 | 248,388 | 248,334 | |||||||
APL revolving credit facility | 150,000 | 152,000 | |||||||
APL 6.625% Senior Notes – due 2020 | 504,387 | 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 | 556 | 754 | |||||||
Total debt | 2,833,131 | 2,889,044 | |||||||
Less current maturities | (2,794 | ) | (2,924 | ) | |||||
Total long-term debt | $ | 2,830,337 | $ | 2,886,120 | |||||
Summary of Leased Property under Capital Leases | ' | ||||||||
The following is a summary of the leased property under capital leases as of March 31, 2014 and December 31, 2013, which are included within property, plant and equipment, net (see Note 5) (in thousands): | |||||||||
March 31, | December 31, | ||||||||
2014 | 2013 | ||||||||
Pipelines, processing and compression facilities | $ | 1,142 | $ | 2,281 | |||||
Less – accumulated depreciation | (144 | ) | (330 | ) | |||||
$ | 998 | $ | 1,951 | ||||||
Derivative_Instruments_Tables
Derivative Instruments (Tables) | 3 Months Ended | |||||||||||||||||||||||||||||||||||||||||
Mar. 31, 2014 | ||||||||||||||||||||||||||||||||||||||||||
Summary of Gain or Loss 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): | ||||||||||||||||||||||||||||||||||||||||||
Three Months Ended | ||||||||||||||||||||||||||||||||||||||||||
March 31, | ||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||||||||
(Gain) loss reclassified from accumulated other comprehensive income (loss): | ||||||||||||||||||||||||||||||||||||||||||
Gas and oil production revenue | $ | 14,569 | $ | (993 | ) | |||||||||||||||||||||||||||||||||||||
Total | $ | 14,569 | $ | (993 | ) | |||||||||||||||||||||||||||||||||||||
Fair Value of Derivative Instruments | ' | |||||||||||||||||||||||||||||||||||||||||
The fair value of the derivatives included in the Partnership’s consolidated balance sheets for the periods indicated was as follows (in thousands): | ||||||||||||||||||||||||||||||||||||||||||
March 31, | December 31, | |||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||||||||
Current portion of derivative asset | $ | 161 | $ | 2,066 | ||||||||||||||||||||||||||||||||||||||
Long-term derivative asset | 28,325 | 30,868 | ||||||||||||||||||||||||||||||||||||||||
Current portion of derivative liability | (36,929 | ) | (17,630 | ) | ||||||||||||||||||||||||||||||||||||||
Long-term derivative liability | (13 | ) | (387 | ) | ||||||||||||||||||||||||||||||||||||||
Total Partnership net asset (liability) | $ | (8,456 | ) | $ | 14,917 | |||||||||||||||||||||||||||||||||||||
ATLS Partnership | ' | |||||||||||||||||||||||||||||||||||||||||
Fair Value of Derivative Instruments | ' | |||||||||||||||||||||||||||||||||||||||||
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 March 31, 2014 | ||||||||||||||||||||||||||||||||||||||||||
Long-term portion of derivative assets | $ | 1,367 | $ | — | $ | 1,367 | ||||||||||||||||||||||||||||||||||||
Total derivative assets | $ | 1,367 | $ | — | $ | 1,367 | ||||||||||||||||||||||||||||||||||||
As of December 31, 2013 | ||||||||||||||||||||||||||||||||||||||||||
Current portion of derivative | $ | 24 | $ | (23 | ) | $ | 1 | |||||||||||||||||||||||||||||||||||
assets | ||||||||||||||||||||||||||||||||||||||||||
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 March 31, 2014 | ||||||||||||||||||||||||||||||||||||||||||
Current portion of derivative liabilities | $ | (770 | ) | $ | — | $ | (770 | ) | ||||||||||||||||||||||||||||||||||
Total derivative liabilities | $ | (770 | ) | $ | — | $ | (770 | ) | ||||||||||||||||||||||||||||||||||
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 | ' | |||||||||||||||||||||||||||||||||||||||||
At March 31, 2014, the Partnership had the following commodity derivatives: | ||||||||||||||||||||||||||||||||||||||||||
Natural Gas Fixed Price Swaps | ||||||||||||||||||||||||||||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||||||||||||||||||||||||||||
Period Ending | Fixed Price | Asset/(Liability) | ||||||||||||||||||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||||||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | ||||||||||||||||||||||||||||||||||||||||
2014 | 2,070,000 | $ | 4.177 | $ | (593 | ) | ||||||||||||||||||||||||||||||||||||
2015 | 2,280,000 | $ | 4.302 | 228 | ||||||||||||||||||||||||||||||||||||||
2016 | 1,440,000 | $ | 4.433 | 399 | ||||||||||||||||||||||||||||||||||||||
2017 | 1,200,000 | $ | 4.59 | 393 | ||||||||||||||||||||||||||||||||||||||
2018 | 420,000 | $ | 4.797 | 170 | ||||||||||||||||||||||||||||||||||||||
The Partnership’s net asset | $ | 597 | ||||||||||||||||||||||||||||||||||||||||
(1) | “MMBtu” represents million British Thermal Units. | |||||||||||||||||||||||||||||||||||||||||
(2) | Fair value based on forward NYMEX natural gas prices, as applicable. | |||||||||||||||||||||||||||||||||||||||||
Atlas Resource Partners, L.P. | ' | |||||||||||||||||||||||||||||||||||||||||
Fair Value of Derivative Instruments | ' | |||||||||||||||||||||||||||||||||||||||||
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): | ||||||||||||||||||||||||||||||||||||||||||
Gross | Gross | Net Amount of | ||||||||||||||||||||||||||||||||||||||||
Amounts of | Amounts | Assets Presented | ||||||||||||||||||||||||||||||||||||||||
Recognized | Offset in the | in the Consolidated | ||||||||||||||||||||||||||||||||||||||||
Assets | Consolidated | Balance Sheets | ||||||||||||||||||||||||||||||||||||||||
Balance Sheets | ||||||||||||||||||||||||||||||||||||||||||
Offsetting Derivative Assets | ||||||||||||||||||||||||||||||||||||||||||
As of March 31, 2014 | ||||||||||||||||||||||||||||||||||||||||||
Current portion of derivative | $ | 161 | $ | — | $ | 161 | ||||||||||||||||||||||||||||||||||||
assets | ||||||||||||||||||||||||||||||||||||||||||
Long-term portion of derivative | 25,859 | (2,110 | ) | 23,749 | ||||||||||||||||||||||||||||||||||||||
assets | ||||||||||||||||||||||||||||||||||||||||||
Current portion of derivative | 4,382 | (4,382 | ) | — | ||||||||||||||||||||||||||||||||||||||
liabilities | ||||||||||||||||||||||||||||||||||||||||||
Long-term portion of derivative liabilities | 114 | (114 | ) | — | ||||||||||||||||||||||||||||||||||||||
Total derivative assets | $ | 30,516 | $ | (6,606 | ) | $ | 23,910 | |||||||||||||||||||||||||||||||||||
As of December 31, 2013 | ||||||||||||||||||||||||||||||||||||||||||
Current portion of derivative assets | $ | 2,664 | $ | (773 | ) | $ | 1,891 | |||||||||||||||||||||||||||||||||||
Long-term portion of derivative | 31,146 | (4,062 | ) | 27,084 | ||||||||||||||||||||||||||||||||||||||
assets | ||||||||||||||||||||||||||||||||||||||||||
Current portion of derivative | 4,341 | (4,341 | ) | — | ||||||||||||||||||||||||||||||||||||||
liabilities | ||||||||||||||||||||||||||||||||||||||||||
Long-term portion of derivative liabilities | 122 | (122 | ) | — | ||||||||||||||||||||||||||||||||||||||
Total derivative assets | $ | 38,273 | $ | (9,298 | ) | $ | 28,975 | |||||||||||||||||||||||||||||||||||
Gross | Gross | Net Amount of | ||||||||||||||||||||||||||||||||||||||||
Amounts of | Amounts | Liabilities Presented | ||||||||||||||||||||||||||||||||||||||||
Recognized | Offset in the | in the Consolidated | ||||||||||||||||||||||||||||||||||||||||
Liabilities | Consolidated | Balance Sheets | ||||||||||||||||||||||||||||||||||||||||
Balance Sheets | ||||||||||||||||||||||||||||||||||||||||||
Offsetting Derivative Liabilities | ||||||||||||||||||||||||||||||||||||||||||
As of March 31, 2014 | ||||||||||||||||||||||||||||||||||||||||||
Current portion of derivative | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||
assets | ||||||||||||||||||||||||||||||||||||||||||
Long-term portion of derivative | (2,110 | ) | 2,110 | — | ||||||||||||||||||||||||||||||||||||||
assets | ||||||||||||||||||||||||||||||||||||||||||
Current portion of derivative | (26,754 | ) | 4,382 | (22,372 | ) | |||||||||||||||||||||||||||||||||||||
liabilities | ||||||||||||||||||||||||||||||||||||||||||
Long-term portion of derivative | (127 | ) | 114 | (13 | ) | |||||||||||||||||||||||||||||||||||||
liabilities | ||||||||||||||||||||||||||||||||||||||||||
Total derivative liabilities | $ | (28,991 | ) | $ | 6,606 | $ | (22,385 | ) | ||||||||||||||||||||||||||||||||||
As of December 31, 2013 | ||||||||||||||||||||||||||||||||||||||||||
Current portion of derivative | $ | (773 | ) | $ | 773 | $ | — | |||||||||||||||||||||||||||||||||||
assets | ||||||||||||||||||||||||||||||||||||||||||
Long-term portion of derivative | (4,062 | ) | 4,062 | — | ||||||||||||||||||||||||||||||||||||||
assets | ||||||||||||||||||||||||||||||||||||||||||
Current portion of derivative | (10,694 | ) | 4,341 | (6,353 | ) | |||||||||||||||||||||||||||||||||||||
liabilities | ||||||||||||||||||||||||||||||||||||||||||
Long-term portion of derivative liabilities | (189 | ) | 122 | (67 | ) | |||||||||||||||||||||||||||||||||||||
Total derivative liabilities | $ | (15,718 | ) | $ | 9,298 | $ | (6,420 | ) | ||||||||||||||||||||||||||||||||||
Commodity Derivative Instruments by Type | ' | |||||||||||||||||||||||||||||||||||||||||
At March 31, 2014, ARP had the following commodity derivatives: | ||||||||||||||||||||||||||||||||||||||||||
Natural Gas Fixed Price Swaps | ||||||||||||||||||||||||||||||||||||||||||
Production Period Ending | Volumes | Average | Fair Value | |||||||||||||||||||||||||||||||||||||||
December 31, | Fixed Price | Asset/(Liability) | ||||||||||||||||||||||||||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | ||||||||||||||||||||||||||||||||||||||||
2014 | 45,114,700 | $ | 4.152 | $ | (14,068 | ) | ||||||||||||||||||||||||||||||||||||
2015 | 51,924,500 | $ | 4.239 | 1,799 | ||||||||||||||||||||||||||||||||||||||
2016 | 45,746,300 | $ | 4.311 | 7,193 | ||||||||||||||||||||||||||||||||||||||
2017 | 24,840,000 | $ | 4.532 | 6,734 | ||||||||||||||||||||||||||||||||||||||
2018 | 3,960,000 | $ | 4.716 | 1,306 | ||||||||||||||||||||||||||||||||||||||
$ | 2,964 | |||||||||||||||||||||||||||||||||||||||||
Natural Gas Costless Collars | ||||||||||||||||||||||||||||||||||||||||||
Production | Option Type | Volumes | Average Floor | Fair Value | ||||||||||||||||||||||||||||||||||||||
Period Ending | and Cap | Asset/(Liability) | ||||||||||||||||||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||||||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | ||||||||||||||||||||||||||||||||||||||||
2014 | Puts purchased | 2,880,000 | $ | 4.221 | $ | 642 | ||||||||||||||||||||||||||||||||||||
2014 | Calls sold | 2,880,000 | $ | 5.12 | (418 | ) | ||||||||||||||||||||||||||||||||||||
2015 | Puts purchased | 3,480,000 | $ | 4.234 | 1,636 | |||||||||||||||||||||||||||||||||||||
2015 | Calls sold | 3,480,000 | $ | 5.129 | (721 | ) | ||||||||||||||||||||||||||||||||||||
$ | 1,139 | |||||||||||||||||||||||||||||||||||||||||
Natural Gas Put Options – Drilling Partnerships | ||||||||||||||||||||||||||||||||||||||||||
Production | Option Type | Volumes | Average Fixed | Fair Value | ||||||||||||||||||||||||||||||||||||||
Period Ending | Price | Asset | ||||||||||||||||||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||||||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | ||||||||||||||||||||||||||||||||||||||||
2014 | Puts purchased | 1,350,000 | $ | 3.8 | $ | 84 | ||||||||||||||||||||||||||||||||||||
2015 | Puts purchased | 1,440,000 | $ | 4 | 447 | |||||||||||||||||||||||||||||||||||||
2016 | Puts purchased | 1,440,000 | $ | 4.15 | 613 | |||||||||||||||||||||||||||||||||||||
$ | 1,144 | |||||||||||||||||||||||||||||||||||||||||
WAHA Basis Swaps | ||||||||||||||||||||||||||||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||||||||||||||||||||||||||||
Period Ending | Fixed Price | Liability | ||||||||||||||||||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||||||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | ||||||||||||||||||||||||||||||||||||||||
2014 | 8,100,000 | $ | (0.110 | ) | $ | (42 | ) | |||||||||||||||||||||||||||||||||||
$ | (42 | ) | ||||||||||||||||||||||||||||||||||||||||
Natural Gas Liquids Fixed Price Swaps | ||||||||||||||||||||||||||||||||||||||||||
Production | Volumes | Average Fixed | Fair Value | |||||||||||||||||||||||||||||||||||||||
Period Ending | Price | Asset/(Liability) | ||||||||||||||||||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||||||||||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | ||||||||||||||||||||||||||||||||||||||||
2014 | 79,500 | $ | 91.568 | $ | (486 | ) | ||||||||||||||||||||||||||||||||||||
2015 | 96,000 | $ | 88.55 | (129 | ) | |||||||||||||||||||||||||||||||||||||
2016 | 84,000 | $ | 85.651 | 92 | ||||||||||||||||||||||||||||||||||||||
2017 | 60,000 | $ | 83.78 | 127 | ||||||||||||||||||||||||||||||||||||||
$ | (396 | ) | ||||||||||||||||||||||||||||||||||||||||
Natural Gas Liquids Ethane Fixed Price Swaps | ||||||||||||||||||||||||||||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||||||||||||||||||||||||||||
Period Ending | Fixed Price | Asset | ||||||||||||||||||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||||||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(4) | ||||||||||||||||||||||||||||||||||||||||
2014 | 1,890,000 | $ | 0.303 | $ | 25 | |||||||||||||||||||||||||||||||||||||
$ | 25 | |||||||||||||||||||||||||||||||||||||||||
Natural Gas Liquids Propane Fixed Price Swaps | ||||||||||||||||||||||||||||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||||||||||||||||||||||||||||
Period Ending | Fixed Price | Liability | ||||||||||||||||||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||||||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(5) | ||||||||||||||||||||||||||||||||||||||||
2014 | 9,261,000 | $ | 1 | $ | (727 | ) | ||||||||||||||||||||||||||||||||||||
2015 | 8,064,000 | $ | 1.016 | (149 | ) | |||||||||||||||||||||||||||||||||||||
$ | (876 | ) | ||||||||||||||||||||||||||||||||||||||||
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)(6) | ||||||||||||||||||||||||||||||||||||||||
2014 | 1,134,000 | $ | 1.308 | $ | 35 | |||||||||||||||||||||||||||||||||||||
2015 | 1,512,000 | $ | 1.248 | 28 | ||||||||||||||||||||||||||||||||||||||
$ | 63 | |||||||||||||||||||||||||||||||||||||||||
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)(7) | ||||||||||||||||||||||||||||||||||||||||
2014 | 1,134,000 | $ | 1.323 | $ | 33 | |||||||||||||||||||||||||||||||||||||
2015 | 1,512,000 | $ | 1.263 | 24 | ||||||||||||||||||||||||||||||||||||||
$ | 57 | |||||||||||||||||||||||||||||||||||||||||
Crude Oil Fixed Price Swaps | ||||||||||||||||||||||||||||||||||||||||||
Production | Volumes | Average | Fair Value | |||||||||||||||||||||||||||||||||||||||
Period Ending | Fixed Price | Asset/ | ||||||||||||||||||||||||||||||||||||||||
December 31, | (Liability) | |||||||||||||||||||||||||||||||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | ||||||||||||||||||||||||||||||||||||||||
2014 | 409,500 | $ | 92.692 | $ | (2,091 | ) | ||||||||||||||||||||||||||||||||||||
2015 | 567,000 | $ | 88.144 | (969 | ) | |||||||||||||||||||||||||||||||||||||
2016 | 225,000 | $ | 85.523 | 218 | ||||||||||||||||||||||||||||||||||||||
2017 | 132,000 | $ | 83.305 | 220 | ||||||||||||||||||||||||||||||||||||||
$ | (2,622 | ) | ||||||||||||||||||||||||||||||||||||||||
Crude Oil Costless Collars | ||||||||||||||||||||||||||||||||||||||||||
Production | Option Type | Volumes | Average | Fair Value | ||||||||||||||||||||||||||||||||||||||
Period Ending | Floor and Cap | Asset/(Liability) | ||||||||||||||||||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||||||||||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | ||||||||||||||||||||||||||||||||||||||||
2014 | Puts purchased | 30,870 | $ | 84.169 | $ | 38 | ||||||||||||||||||||||||||||||||||||
2014 | Calls sold | 30,870 | $ | 113.308 | (33 | ) | ||||||||||||||||||||||||||||||||||||
2015 | Puts purchased | 29,250 | $ | 83.846 | 125 | |||||||||||||||||||||||||||||||||||||
2015 | Calls sold | 29,250 | $ | 110.654 | (61 | ) | ||||||||||||||||||||||||||||||||||||
$ | 69 | |||||||||||||||||||||||||||||||||||||||||
ARP’s net asset | $ | 1,525 | ||||||||||||||||||||||||||||||||||||||||
(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 ethane 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. | |||||||||||||||||||||||||||||||||||||||||
Atlas Pipeline "APL" | ' | |||||||||||||||||||||||||||||||||||||||||
Fair Value of Derivative Instruments | ' | |||||||||||||||||||||||||||||||||||||||||
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): | ||||||||||||||||||||||||||||||||||||||||||
Gross | Gross | Net Amounts of Assets | ||||||||||||||||||||||||||||||||||||||||
Amounts of | Amounts | Presented in the | ||||||||||||||||||||||||||||||||||||||||
Recognized | Offset in the | Consolidated | ||||||||||||||||||||||||||||||||||||||||
Assets | Consolidated | Balance Sheets | ||||||||||||||||||||||||||||||||||||||||
Balance Sheets | ||||||||||||||||||||||||||||||||||||||||||
Offsetting Derivative Assets | ||||||||||||||||||||||||||||||||||||||||||
As of March 31, 2014 | ||||||||||||||||||||||||||||||||||||||||||
Long-term portion of derivative assets | $ | 5,336 | $ | (2,127 | ) | $ | 3,209 | |||||||||||||||||||||||||||||||||||
Current portion of derivative liabilities | 2,082 | (2,082 | ) | — | ||||||||||||||||||||||||||||||||||||||
Total derivative assets | $ | 7,418 | $ | (4,209 | ) | $ | 3,209 | |||||||||||||||||||||||||||||||||||
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 | 949 | (949 | ) | — | ||||||||||||||||||||||||||||||||||||||
liabilities | ||||||||||||||||||||||||||||||||||||||||||
Total derivative assets | $ | 8,953 | $ | (6,509 | ) | $ | 2,444 | |||||||||||||||||||||||||||||||||||
Gross | Gross | Net Amounts of | ||||||||||||||||||||||||||||||||||||||||
Amounts of | Amounts | Liabilities Presented | ||||||||||||||||||||||||||||||||||||||||
Recognized | Offset in the | in the Consolidated | ||||||||||||||||||||||||||||||||||||||||
Liabilities | Consolidated | Balance Sheets | ||||||||||||||||||||||||||||||||||||||||
Balance Sheets | ||||||||||||||||||||||||||||||||||||||||||
Offsetting Derivative Liabilities | ||||||||||||||||||||||||||||||||||||||||||
As of March 31, 2014 | ||||||||||||||||||||||||||||||||||||||||||
Long-term portion of derivative assets | $ | (2,127 | ) | $ | 2,127 | $ | — | |||||||||||||||||||||||||||||||||||
Current portion of derivative liabilities | (15,869 | ) | 2,082 | (13,787 | ) | |||||||||||||||||||||||||||||||||||||
Total derivative liabilities | $ | (17,996 | ) | $ | 4,209 | $ | (13,787 | ) | ||||||||||||||||||||||||||||||||||
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 | (1,269 | ) | 949 | (320 | ) | |||||||||||||||||||||||||||||||||||||
liabilities | ||||||||||||||||||||||||||||||||||||||||||
Total derivative liabilities | $ | (18,073 | ) | $ | 6,509 | $ | (11,564 | ) | ||||||||||||||||||||||||||||||||||
Commodity Derivative Instruments by Type | ' | |||||||||||||||||||||||||||||||||||||||||
As of March 31, 2014, APL had the following commodity derivatives: | ||||||||||||||||||||||||||||||||||||||||||
Fixed Price Swaps | ||||||||||||||||||||||||||||||||||||||||||
Production Period | Purchased/ | Commodity | Volumes(1) | Average | Fair Value | |||||||||||||||||||||||||||||||||||||
Sold | Fixed | Asset/(Liability) | ||||||||||||||||||||||||||||||||||||||||
Price | (in thousands)(2) | |||||||||||||||||||||||||||||||||||||||||
Natural Gas | ||||||||||||||||||||||||||||||||||||||||||
2014 | Sold | Natural Gas | 12,690,000 | $ | 4.029 | $ | (5,555 | ) | ||||||||||||||||||||||||||||||||||
2015 | Sold | Natural Gas | 18,610,000 | $ | 4.244 | 592 | ||||||||||||||||||||||||||||||||||||
2016 | Sold | Natural Gas | 7,950,000 | $ | 4.277 | 779 | ||||||||||||||||||||||||||||||||||||
2017 | Sold | Natural Gas | 600,000 | $ | 4.455 | 23 | ||||||||||||||||||||||||||||||||||||
Natural Gas Liquids | ||||||||||||||||||||||||||||||||||||||||||
2014 | Sold | Natural Gas Liquids | 60,354,000 | $ | 1.198 | (5,123 | ) | |||||||||||||||||||||||||||||||||||
2015 | Sold | Natural Gas Liquids | 41,076,000 | $ | 1.079 | (1,993 | ) | |||||||||||||||||||||||||||||||||||
2016 | Sold | Natural Gas Liquids | 6,300,000 | $ | 1.034 | (85 | ) | |||||||||||||||||||||||||||||||||||
Crude Oil | ||||||||||||||||||||||||||||||||||||||||||
2014 | Sold | Crude Oil | 219,000 | $ | 91.062 | (1,672 | ) | |||||||||||||||||||||||||||||||||||
2015 | Sold | Crude Oil | 60,000 | $ | 85.13 | (298 | ) | |||||||||||||||||||||||||||||||||||
Total Fixed Price Swaps | $ | (13,332 | ) | |||||||||||||||||||||||||||||||||||||||
Options | ||||||||||||||||||||||||||||||||||||||||||
Production Period | Purchased/ | Type | Commodity | Volumes(1) | Average | Fair Value | ||||||||||||||||||||||||||||||||||||
Sold | Strike | Asset/(Liability) (in | ||||||||||||||||||||||||||||||||||||||||
Price | thousands) (2) | |||||||||||||||||||||||||||||||||||||||||
Natural Gas | ||||||||||||||||||||||||||||||||||||||||||
2014 | Purchased | Put | Natural Gas | 500,000 | $ | 4.13 | $ | 60 | ||||||||||||||||||||||||||||||||||
Natural Gas | ||||||||||||||||||||||||||||||||||||||||||
Liquids | ||||||||||||||||||||||||||||||||||||||||||
2014 | Purchased | Put | Natural Gas Liquids | 6,930,000 | $ | 0.96 | 135 | |||||||||||||||||||||||||||||||||||
2014 | Sold | Call | Natural Gas Liquids | 3,780,000 | $ | 1.318 | (27 | ) | ||||||||||||||||||||||||||||||||||
2015 | Purchased | Put | Natural Gas Liquids | 3,150,000 | $ | 0.941 | 155 | |||||||||||||||||||||||||||||||||||
2015 | Sold | Call | Natural Gas Liquids | 1,260,000 | $ | 1.275 | (46 | ) | ||||||||||||||||||||||||||||||||||
Crude Oil | ||||||||||||||||||||||||||||||||||||||||||
2014 | Purchased | Put | Crude Oil | 267,000 | $ | 90.413 | 657 | |||||||||||||||||||||||||||||||||||
2015 | Purchased | Put | Crude Oil | 270,000 | $ | 89.175 | 1,820 | |||||||||||||||||||||||||||||||||||
Total Options | $ | 2,754 | ||||||||||||||||||||||||||||||||||||||||
APL’s net liability | $ | (10,578 | ) | |||||||||||||||||||||||||||||||||||||||
(1) | Volumes for natural gas are stated in MMBtu’s. Volumes for NGLs are stated in gallons. Volumes for crude oil are stated in barrels. | |||||||||||||||||||||||||||||||||||||||||
(2) | See Note 10 for discussion on fair value methodology. | |||||||||||||||||||||||||||||||||||||||||
Gain (Loss) Recognized on Derivative Instruments | ' | |||||||||||||||||||||||||||||||||||||||||
The following tables summarize APL’s derivatives not designated as hedges, which are included within gain on mark-to market derivatives on the Partnerships consolidated statements of operations: | ||||||||||||||||||||||||||||||||||||||||||
Three Months Ended | ||||||||||||||||||||||||||||||||||||||||||
March 31, | ||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||||||||
Gain (loss) recognized in loss on mark-to-market derivatives: | ||||||||||||||||||||||||||||||||||||||||||
Commodity contract—realized(1) | $ | (9,835 | ) | $ | 1,636 | |||||||||||||||||||||||||||||||||||||
Commodity contract – unrealized(2) | 1,164 | (13,719 | ) | |||||||||||||||||||||||||||||||||||||||
Loss on mark-to-market derivatives | $ | (8,671 | ) | $ | (12,083 | ) | ||||||||||||||||||||||||||||||||||||
(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_Instru2
Fair Value of Financial Instruments (Tables) | 3 Months Ended | ||||||||||||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||||||||||||
Partnership, ARP and ATLS Assets and Liabilities Measured at Fair Value | ' | ||||||||||||||||||||||||||||
Information for ARP’s and APL’s assets and liabilities measured at fair value at March 31, 2014 and December 31, 2013 was as follows (in thousands): | |||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||
As of March 31, 2014 | |||||||||||||||||||||||||||||
Derivative assets, gross | |||||||||||||||||||||||||||||
Commodity swaps | $ | — | $ | 1,367 | $ | — | $ | 1,367 | |||||||||||||||||||||
ARP Commodity swaps | — | 26,771 | — | 26,771 | |||||||||||||||||||||||||
ARP Commodity basis swaps | — | 159 | — | 159 | |||||||||||||||||||||||||
ARP Commodity puts | — | 1,144 | — | 1,144 | |||||||||||||||||||||||||
ARP Commodity options | — | 2,442 | — | 2,442 | |||||||||||||||||||||||||
APL Commodity swaps | — | 3,189 | 1,402 | 4,591 | |||||||||||||||||||||||||
APL Commodity options | — | 2,537 | 290 | 2,827 | |||||||||||||||||||||||||
Total derivative assets, gross | — | 37,609 | 1,692 | 39,301 | |||||||||||||||||||||||||
Derivative liabilities, gross | |||||||||||||||||||||||||||||
Commodity swaps | — | (770 | ) | — | (770 | ) | |||||||||||||||||||||||
ARP Commodity swaps | — | (27,556 | ) | — | (27,556 | ) | |||||||||||||||||||||||
ARP Commodity basis swaps | — | (201 | ) | — | (201 | ) | |||||||||||||||||||||||
ARP Commodity options | — | (1,234 | ) | — | (1,234 | ) | |||||||||||||||||||||||
APL Commodity swaps | — | (9,320 | ) | (8,603 | ) | (17,923 | ) | ||||||||||||||||||||||
APL Commodity options | — | — | (73 | ) | (73 | ) | |||||||||||||||||||||||
Total derivative liabilities, gross | — | (39,081 | ) | (8,676 | ) | (47,757 | ) | ||||||||||||||||||||||
Total derivatives, fair value, net | $ | — | $ | (1,472 | ) | $ | (6,984 | ) | $ | (8,456 | ) | ||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||||||||
Derivative assets, gross | |||||||||||||||||||||||||||||
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 derivative assets, gross | — | 47,238 | 1,622 | 48,860 | |||||||||||||||||||||||||
Derivative 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 | $ | — | $ | 26,673 | $ | (11,756 | ) | $ | 14,917 | ||||||||||||||||||||
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, 2014 | 130,158 | $ | (11,966 | ) | 6,300 | $ | 210 | — | — | $ | (11,756 | ) | |||||||||||||||||
New contracts(1) | — | — | 5,040 | 200 | 5,040 | (200 | ) | — | |||||||||||||||||||||
Cash settlements from unrealized gain (loss)(2)(3) | (22,428 | ) | 5,873 | (1,260 | ) | 137 | — | — | 6,010 | ||||||||||||||||||||
Net change in unrealized gain (loss)(2) | — | (1,108 | ) | — | (120 | ) | — | 127 | (1,101 | ) | |||||||||||||||||||
Option premium recognition(3) | — | — | — | (137 | ) | — | — | (137 | ) | ||||||||||||||||||||
Balance – March 31, 2014 | 107,730 | (7,201 | ) | 10,080 | 290 | 5,040 | (73 | ) | (6,984 | ) | |||||||||||||||||||
(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 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 March 31, 2014 and December 31, 2013 (in thousands): | |||||||||||||||||||||||||||||
Gallons | Third Party | Adjustments(2) | Total | ||||||||||||||||||||||||||
Quotes(1) | Amount | ||||||||||||||||||||||||||||
As of March 31, 2014 | |||||||||||||||||||||||||||||
Propane swaps | 83,538 | $ | (6,059 | ) | $ | — | $ | (6,059 | ) | ||||||||||||||||||||
Iso butane swaps | 5,040 | (1,405 | ) | 651 | (754 | ) | |||||||||||||||||||||||
Normal butane swaps | 5,040 | 483 | 192 | 675 | |||||||||||||||||||||||||
Natural gasoline swaps | 14,112 | (276 | ) | (787 | ) | (1,063 | ) | ||||||||||||||||||||||
Total NGL swaps — March 31, 2014 | 107,730 | $ | (7,257 | ) | $ | 56 | $ | (7,201 | ) | ||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||||||||
Propane swaps | 100,296 | $ | (10,260 | ) | $ | — | $ | (10,260 | ) | ||||||||||||||||||||
Iso butane 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): | |||||||||||||||||||||||||||||
Adjustment Based upon | |||||||||||||||||||||||||||||
Regression Coefficient | |||||||||||||||||||||||||||||
Level 3 Fair | Lower | Upper | Average | ||||||||||||||||||||||||||
Value | 95% | 95% | Coefficient | ||||||||||||||||||||||||||
Adjustments | |||||||||||||||||||||||||||||
As of March 31, 2014 | |||||||||||||||||||||||||||||
Iso butane swaps | $ | 651 | $ | 1.1168 | $ | 1.1271 | $ | 1.1219 | |||||||||||||||||||||
Normal butane swaps | 192 | 1.0341 | 1.0382 | 1.0361 | |||||||||||||||||||||||||
Natural gasoline swaps | (787 | ) | 0.9685 | 0.9716 | 0.9701 | ||||||||||||||||||||||||
Total NGL swaps – March 31, 2014 | $ | 56 | |||||||||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||||||||
Iso butane swaps | $ | 955 | 1.1184 | 1.1284 | 1.1234 | ||||||||||||||||||||||||
Normal butane swaps | 322 | 1.0341 | 1.0386 | 1.0364 | |||||||||||||||||||||||||
Natural gasoline swaps | (813 | ) | 0.9727 | 0.9751 | 0.9739 | ||||||||||||||||||||||||
Total NGL swaps – 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 three months ended March 31, 2014 (in thousands): | |||||||||||||||||||||||||||||
Linefill Valued at | Linefill Valued on | Total NGL Linefill | |||||||||||||||||||||||||||
Market | FIFO | ||||||||||||||||||||||||||||
Gallons | Amount | Gallons | Amount | Gallons | Amount | ||||||||||||||||||||||||
Balance – January 1, 2014 | 5,788 | $ | 4,739 | 11,538 | $ | 9,778 | 17,326 | $ | 14,517 | ||||||||||||||||||||
Deliveries into NGL linefill | 1,050 | 1,013 | 25,600 | 16,875 | 26,650 | 17,888 | |||||||||||||||||||||||
NGL linefill sales | — | — | (20,622 | ) | (10,847 | ) | (20,622 | ) | (10,847 | ) | |||||||||||||||||||
Net change in NGL linefill valuation(1) | — | 143 | — | — | — | 143 | |||||||||||||||||||||||
Balance – March 31, 2014 | 6,838 | $ | 5,895 | 16,516 | $ | 15,806 | 23,354 | $ | 21,701 | ||||||||||||||||||||
Summary of Information for Assets that were Measured at Fair Value on a Nonrecurring Basis | ' | ||||||||||||||||||||||||||||
Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the three months ended March 31, 2014 and 2013 was as follows (in thousands): | |||||||||||||||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||||||||
Level 3 | Total | Level 3 | Total | ||||||||||||||||||||||||||
Asset retirement obligations | $ | 602 | $ | 602 | $ | 645 | $ | 645 | |||||||||||||||||||||
Total | $ | 602 | $ | 602 | $ | 645 | $ | 645 | |||||||||||||||||||||
Income_Taxes_Tables
Income Taxes (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2014 | |||||||||
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 three months ended March 31, 2014 and 2013 are as follows (in thousands): | |||||||||
Three Months Ended | |||||||||
March 31, | |||||||||
2014 | 2013 | ||||||||
Income tax benefit: | |||||||||
Federal | $ | (357 | ) | $ | (8 | ) | |||
State | (41 | ) | (1 | ) | |||||
Total income tax benefit | $ | (398 | ) | $ | (9 | ) | |||
Schedule of Deferred Tax Assets and Liabilities | ' | ||||||||
As of March 31, 2014 and December 31, 2013, APL had non-current net deferred income tax liabilities of $32.9 million and $33.3 million, respectively. The components of net deferred tax liabilities as of March 31, 2014 and December 31, 2013 consist of the following (in thousands): | |||||||||
March 31, | December 31, | ||||||||
2014 | 2013 | ||||||||
Deferred tax assets: | |||||||||
Net operating loss tax carryforwards and alternative minimum tax credits | $ | 15,499 | $ | 14,900 | |||||
Deferred tax liabilities: | |||||||||
Excess of asset carrying value over tax basis | (48,391 | ) | (48,190 | ) | |||||
Net deferred tax liabilities | $ | (32,892 | ) | $ | (33,290 | ) | |||
Cash_Distribution_Distribution
Cash Distribution (Distributions Declared) (Table) | 3 Months Ended | ||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||
ATLS | ' | ||||||||||||||||||
Schedule of Distributions Declared 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, 2013 through March 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 | ||||||||||||||||||
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 | ||||||||||||||
Atlas Resource Partners, L.P. | ' | ||||||||||||||||||
Schedule of Distributions Declared by Partnership | ' | ||||||||||||||||||
Distributions declared by ARP for the period from January 1, 2013 through March 31, 2014 were as follows (in thousands, except per unit amounts): | |||||||||||||||||||
Date Cash Distribution Paid | For Quarter/ | Cash | Total Cash | Total Cash | Total Cash | ||||||||||||||
Month Ended | Distribution | Distribution | Distribution | Distribution to the | |||||||||||||||
per Common | to Common | To Preferred | General Partner | ||||||||||||||||
Limited | Limited | Limited | |||||||||||||||||
Partner Unit | Partners | Partners | |||||||||||||||||
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 | December 31, 2013 | $ | 0.58 | $ | 34,489 | $ | 4,400 | $ | 2,891 | ||||||||||
March 17, 2014 | 31-Jan-14 | $ | 0.1933 | $ | 12,718 | $ | 1,467 | $ | 1,055 | ||||||||||
April 14, 2014 | 28-Feb-14 | $ | 0.1933 | $ | 12,719 | $ | 1,466 | $ | 1,055 | ||||||||||
Atlas Pipeline "APL" | ' | ||||||||||||||||||
Schedule of Distributions Declared by Partnership | ' | ||||||||||||||||||
Common unit and general partner distributions declared by APL for the period from January 1, 2013 through March 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 | ||||||||||||||||||
May 15, 2013 | 31-Mar-13 | $ | 0.59 | $ | 45,382 | $ | 3,980 | ||||||||||||
August 14, 2013 | 30-Jun-13 | $ | 0.62 | $ | 48,165 | $ | 5,875 | ||||||||||||
November 14, 2013 | September 30, 2013 | $ | 0.62 | $ | 49,298 | $ | 6,013 | ||||||||||||
February 14, 2014 | 31-Dec-13 | $ | 0.62 | $ | 49,969 | $ | 6,095 | ||||||||||||
Benefit_Plans_Tables
Benefit Plans (Tables) | 3 Months Ended | ||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||
Partnership 2010 Long Term Incentive Plan | ' | ||||||||||||||||
Phantom Unit Activity | ' | ||||||||||||||||
The following table sets forth the 2010 LTIP phantom unit activity for the periods indicated: | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Number | Weighted | Number | Weighted | ||||||||||||||
of Units | Average | of Units | Average | ||||||||||||||
Grant Date | Grant Date | ||||||||||||||||
Fair Value | Fair Value | ||||||||||||||||
Outstanding, beginning of year | 2,054,534 | $ | 22.56 | 2,044,227 | $ | 20.88 | |||||||||||
Granted | — | — | — | — | |||||||||||||
Vested and issued(1) | (38,335 | ) | 20.29 | (2,936 | ) | 17.47 | |||||||||||
Forfeited | (11,768 | ) | 27.25 | — | — | ||||||||||||
Outstanding, end of period(2) | 2,004,431 | $ | 22.57 | 2,041,291 | $ | 20.88 | |||||||||||
Vested and not yet issued(3) | 344,553 | $ | 20.6 | — | $ | — | |||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 2,928 | $ | 3,108 | |||||||||||||
(1) | The aggregate intrinsic values of phantom unit awards vested and issued were $1.7 million and $0.1 million, respectively, for the three months ended March 31, 2014 and 2013, respectively. | ||||||||||||||||
(2) | The aggregate intrinsic value of phantom unit awards outstanding at March 31, 2014 was $86.3 million. | ||||||||||||||||
(3) | The intrinsic value of phantom unit awards vested, but not yet issued at March 31, 2014 was $15.0 million. No phantom unit awards had vested, but had not yet been issued at March 31, 2013. | ||||||||||||||||
Unit Option Activity | ' | ||||||||||||||||
The following table sets forth the 2010 LTIP unit option activity for the periods indicated: | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Number | Weighted | Number | Weighted | ||||||||||||||
of Unit | Average | of Unit | Average | ||||||||||||||
Options | Exercise | Options | Exercise | ||||||||||||||
Price | Price | ||||||||||||||||
Outstanding, beginning of year | 2,452,412 | $ | 20.52 | 2,504,703 | $ | 20.51 | |||||||||||
Granted | — | — | — | — | |||||||||||||
Exercised(1) | — | — | — | — | |||||||||||||
Forfeited | (2,713 | ) | 17.47 | (2,604 | ) | 17.47 | |||||||||||
Outstanding, end of period(2)(3) | 2,449,699 | $ | 20.52 | 2,502,099 | $ | 20.52 | |||||||||||
Options exercisable, end of period(4) | 569,368 | $ | 20.43 | 3,398 | $ | 20.85 | |||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 1,438 | $ | 1,515 | |||||||||||||
(1) | No options were exercised during the three months ended March 31, 2014 and 2013. | ||||||||||||||||
(2) | The weighted average remaining contractual life for outstanding options at March 31, 2014 was 7.0 years. | ||||||||||||||||
(3) | The options outstanding at March 31, 2014 had an aggregate intrinsic value of $55.2 million. | ||||||||||||||||
(4) | The weighted average remaining contractual lives for exercisable options at March 31, 2014 and 2013 were 7.0 years and 8.4 years, respectively. The intrinsic values of exercisable options at March 31, 2014 and 2013 were $12.9 million and $0.1 million, respectively. | ||||||||||||||||
Partnership 2006 Long Term Incentive Plan | ' | ||||||||||||||||
Phantom Unit Activity | ' | ||||||||||||||||
The following table sets forth the 2006 LTIP phantom unit activity for the periods indicated: | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Number | Weighted | Number | Weighted | ||||||||||||||
of Units | Average | of Units | Average | ||||||||||||||
Grant Date | Grant Date | ||||||||||||||||
Fair Value | Fair Value | ||||||||||||||||
Outstanding, beginning of year | 234,940 | $ | 35.82 | 50,759 | $ | 21.02 | |||||||||||
Granted | 423,837 | 43.23 | 204,777 | 37.92 | |||||||||||||
Vested and issued(1) (2) | (63,750 | ) | 35.33 | (5,500 | ) | 18.16 | |||||||||||
Forfeited | — | — | — | — | |||||||||||||
Outstanding, end of period(3)(4) | 595,027 | $ | 41.15 | 250,036 | $ | 34.92 | |||||||||||
Vested and not yet issued(5) | 11,497 | $ | 37.68 | — | $ | — | |||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 2,988 | $ | 1,147 | |||||||||||||
-1 | The intrinsic value for phantom unit awards vested and issued during the three months ended March 31, 2014 and 2013 were $3.0 million and $0.2 million, respectively. | ||||||||||||||||
-2 | There were 3,884 and 522 vested units during the three months ended March 31, 2014 and 2013, respectively, that settled for cash consideration of approximately $185,000 and approximately $20,000, respectively. | ||||||||||||||||
-3 | The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2014 was $25.6 million. | ||||||||||||||||
-4 | There was $0.7 million and $1.1 million recognized as liabilities on the Partnership’s consolidated balance sheets at March 31, 2014 and December 31, 2013, respectively, representing 41,067 and 41,525 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 are $36.53 and $29.67 as of March 31, 2014 and December 31, 2013, respectively. | ||||||||||||||||
-5 | The intrinsic value of phantom unit awards vested, but not yet issued at March 31, 2014 was $0.5 million. No phantom units were vested, but not yet issued at March 31, 2013. | ||||||||||||||||
Unit Option Activity | ' | ||||||||||||||||
The following table sets forth the 2006 LTIP unit option activity for the periods indicated: | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Number | Weighted | Number | Weighted | ||||||||||||||
of Unit | Average | of Unit | Average | ||||||||||||||
Options | Exercise | Options | Exercise | ||||||||||||||
Price | Price | ||||||||||||||||
Outstanding, beginning of year | 939,939 | $ | 20.94 | 929,939 | $ | 20.75 | |||||||||||
Granted | — | — | 10,000 | 38.51 | |||||||||||||
Exercised(1) | — | — | — | — | |||||||||||||
Forfeited | — | — | — | — | |||||||||||||
Outstanding, end of year(2)(3) | 939,939 | $ | 20.94 | 939,939 | $ | 20.94 | |||||||||||
Options exercisable, end of period(4)(5) | 932,439 | $ | 20.8 | 929,939 | $ | 20.75 | |||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 7 | $ | 7 | |||||||||||||
-1 | No options were exercised during the three months ended March 31, 2014 and 2013. | ||||||||||||||||
-2 | The weighted average remaining contractual life for outstanding options at March 31, 2014 was 2.7 years. | ||||||||||||||||
-3 | The aggregate intrinsic value of options outstanding at March 31, 2014 was approximately $20.8 million. | ||||||||||||||||
-4 | The weighted average remaining contractual lives for exercisable options at March 31, 2014 and 2013 were 2.6 years and 3.6 years, respectively. | ||||||||||||||||
-5 | The aggregate intrinsic values of options exercisable at March 31, 2014 and 2013 were $20.7 million and $21.7 million, respectively. | ||||||||||||||||
Weighted Average Assumptions | ' | ||||||||||||||||
The following weighted average assumptions were used for the periods indicated: | |||||||||||||||||
Three Months Ended | |||||||||||||||||
March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
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 | ' | ||||||||||||||||
Phantom Unit Activity | ' | ||||||||||||||||
The following table sets forth the ARP LTIP phantom unit activity for the periods indicated: | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Number | Weighted | Number | Weighted | ||||||||||||||
of Units | Average | of Units | Average | ||||||||||||||
Grant Date | Grant Date | ||||||||||||||||
Fair Value | Fair Value | ||||||||||||||||
Outstanding, beginning of year | 839,808 | $ | 24.31 | 948,476 | $ | 24.76 | |||||||||||
Granted | 3,500 | 20.99 | 83,250 | 21.96 | |||||||||||||
Vested and issued(1) | (15,500 | ) | 22.69 | (2,465 | ) | 24.67 | |||||||||||
Forfeited | (15,500 | ) | 22.63 | (4,000 | ) | 25.14 | |||||||||||
Outstanding, end of period(2)(3) | 812,308 | $ | 24.35 | 1,025,261 | $ | 24.53 | |||||||||||
Vested and not yet issued(4) | 6,875 | $ | 22.76 | — | $ | — | |||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 1,731 | $ | 3,053 | |||||||||||||
-1 | The intrinsic value of phantom unit awards vested and issued during the three months ended March 31, 2014 and 2013 was $0.3 million and $0.1 million, respectively. | ||||||||||||||||
-2 | The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2014 was $17.0 million. | ||||||||||||||||
-3 | There was $0.1 million recognized as liabilities on the Partnership’s consolidated balance sheets at the periods ended March 31, 2014 and December 31, 2013, representing 16,084 units for the periods ending March 31, 2014 and December 31, 2013 due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair value for these units was $22.15 for the periods ending March 31, 2014 and December 31, 2013, respectively. There was approximately $44,000 recognized as liabilities on the Partnership’s consolidated balance sheet at March 31, 2013, representing 3,476 units, due to the option of the participants to settle in cash instead of units. The weighted average grant date fair value for these units was $28.75 at March 31, 2013. | ||||||||||||||||
-4 | The intrinsic value of phantom unit awards vested, but not yet issued at March 31, 2014 was $0.1 million. No phantom unit awards had vested, but had not yet been issued at March 31, 2013. | ||||||||||||||||
Unit Option Activity | ' | ||||||||||||||||
The following table sets forth the ARP LTIP unit option activity for the periods indicated: | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Number | Weighted | Number | Weighted | ||||||||||||||
of Units | Average | of Units | Average | ||||||||||||||
Exercise | Exercise | ||||||||||||||||
Price | Price | ||||||||||||||||
Outstanding, beginning of year | 1,482,675 | $ | 24.66 | 1,515,500 | $ | 24.68 | |||||||||||
Granted | — | — | 2,000 | 22.27 | |||||||||||||
Exercised (1) | — | — | — | — | |||||||||||||
Forfeited | (10,000 | ) | 23.4 | (4,000 | ) | 25.14 | |||||||||||
Outstanding, end of period(2)(3) | 1,472,675 | $ | 24.66 | 1,513,500 | $ | 24.67 | |||||||||||
Options exercisable, end of period(4) | 368,825 | $ | 24.67 | — | $ | — | |||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 612 | $ | 1,194 | |||||||||||||
-1 | No options were exercised during the three months ended March 31, 2014, and 2013. | ||||||||||||||||
-2 | The weighted average remaining contractual life for outstanding options at March 31, 2014 was 8.1 years. | ||||||||||||||||
-3 | The aggregate intrinsic value of options outstanding at March 31, 2014 was approximately $2,000. | ||||||||||||||||
-4 | The weighted average remaining contractual life for exercisable options at March 31, 2014 was 8.1 years. There were no intrinsic values for options exercisable at March 31, 2014 and 2013. | ||||||||||||||||
Weighted Average Assumptions | ' | ||||||||||||||||
The following weighted average assumptions were used for the periods indicated: | |||||||||||||||||
Three Months Ended | |||||||||||||||||
March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Expected dividend yield | — | % | 6.6 | % | |||||||||||||
Expected unit price volatility | — | % | 44 | % | |||||||||||||
Risk-free interest rate | — | % | 1.1 | % | |||||||||||||
Expected term (in years) | — | 6.25 | |||||||||||||||
Fair value of unit options granted | $ | — | $ | 4.85 | |||||||||||||
APL Long Term Incentive Plans | ' | ||||||||||||||||
Phantom Unit Activity | ' | ||||||||||||||||
The following table sets forth the APL LTIP phantom unit activity for the periods indicated: | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Number | Weighted | Number | Weighted | ||||||||||||||
of Units | Average | of Units | Average | ||||||||||||||
Grant Date | Grant Date | ||||||||||||||||
Fair Value | Fair Value | ||||||||||||||||
Outstanding, beginning of year | 1,446,553 | $ | 36.32 | 1,053,242 | $ | 33.21 | |||||||||||
Granted | 234,701 | 31.03 | 6,804 | 33.06 | |||||||||||||
Vested and issued(1) | (14,412 | ) | 34.03 | (2,963 | ) | 28.94 | |||||||||||
Forfeited | (2,200 | ) | 39.51 | — | — | ||||||||||||
Outstanding, end of period(2)(3) | 1,664,642 | $ | 35.59 | 1,057,083 | $ | 33.22 | |||||||||||
Non-cash compensation expense recognized | $ | 6,439 | $ | 4,384 | |||||||||||||
(in thousands) | |||||||||||||||||
(1) | The intrinsic values for phantom unit awards vested and issued were $0.5 million and $0.1 million, respectively, during the three months ended March 31, 2014 and 2013, respectively. | ||||||||||||||||
(2) | There were 25,228 and 22,539 outstanding phantom unit awards at March 31, 2014 and December 31, 2013, respectively, which were classified as liabilities due to a cash option available on the related phantom unit awards. | ||||||||||||||||
(3) | The aggregate intrinsic values for phantom unit awards outstanding at ended March 31, 2014 and December 31, 2013 were $53.5 million and $50.7 million, respectively. |
Operating_Segment_Information_
Operating Segment Information (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2014 | |||||||||
Summary of 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): | |||||||||
Three Months Ended | |||||||||
March 31, | |||||||||
2014 | 2013 | ||||||||
Atlas Resource: | |||||||||
Revenues | $ | 157,345 | $ | 112,048 | |||||
Operating costs and expenses | (103,078 | ) | (88,626 | ) | |||||
Depreciation, depletion and amortization expense | (50,237 | ) | (21,208 | ) | |||||
Loss on asset sales and disposal | (1,603 | ) | (702 | ) | |||||
Interest expense | (13,188 | ) | (6,889 | ) | |||||
Segment loss | $ | (10,761 | ) | $ | (5,377 | ) | |||
Atlas Pipeline: | |||||||||
Revenues | $ | 698,089 | $ | 409,952 | |||||
Operating costs and expenses | (618,138 | ) | (361,718 | ) | |||||
Depreciation, depletion and amortization expense | (49,239 | ) | (30,458 | ) | |||||
Loss on asset sales and disposal | — | — | |||||||
Interest expense | (23,663 | ) | (18,686 | ) | |||||
Loss on early extinguishment of debt | — | (26,582 | ) | ||||||
Segment income (loss) | $ | 7,049 | $ | (27,492 | ) | ||||
Corporate and other: | |||||||||
Revenues | $ | 4,828 | $ | 102 | |||||
Operating costs and expenses | (15,918 | ) | (8,692 | ) | |||||
Depreciation, depletion and amortization expense | (1,802 | ) | — | ||||||
Loss on asset sales and disposal | — | — | |||||||
Interest expense | (4,463 | ) | (235 | ) | |||||
Segment loss | $ | (17,355 | ) | $ | (8,825 | ) | |||
Reconciliation of segment income (loss) to net loss: | |||||||||
Segment income (loss): | |||||||||
Atlas Resource | $ | (10,761 | ) | $ | (5,377 | ) | |||
Atlas Pipeline | 7,049 | (27,492 | ) | ||||||
Corporate and other | (17,355 | ) | (8,825 | ) | |||||
Net loss | $ | (21,067 | ) | $ | (41,694 | ) | |||
Capital expenditures: | |||||||||
Atlas Resource | $ | 39,897 | $ | 58,487 | |||||
Atlas Pipeline | 128,331 | 108,516 | |||||||
Corporate and other | 4,522 | — | |||||||
Total capital expenditures | $ | 172,750 | $ | 167,003 | |||||
March 31, | December 31, | ||||||||
2014 | 2013 | ||||||||
Balance sheet: | |||||||||
Goodwill: | |||||||||
Atlas Resource | $ | 31,784 | $ | 31,784 | |||||
Atlas Pipeline | 370,396 | 368,572 | |||||||
Corporate and other | — | — | |||||||
$ | 402,180 | $ | 400,356 | ||||||
Total assets: | |||||||||
Atlas Resource | $ | 2,321,905 | $ | 2,343,800 | |||||
Atlas Pipeline | 4,446,958 | 4,327,845 | |||||||
Corporate and other | 129,373 | 120,996 | |||||||
$ | 6,898,236 | $ | 6,792,641 | ||||||
Basis_of_Presentation_Narrativ
Basis of Presentation (Narrative) (Details) | 1 Months Ended | 3 Months Ended | 12 Months Ended | 3 Months Ended | |||||||||||||||
Feb. 29, 2012 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Mar. 31, 2012 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2012 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | |
Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Development Subsidiary | General Partner Interest | General Partner Interest | General Partner Interest | General Partner Interest | Limited Partner Interest | Limited Partner Interest | Limited Partner Interest | Limited Partner Interest | Limited Partner Interest | ||||||||
Class C Preferred Limited Partner Units | Atlas Resource Partners, L.P. | Atlas Pipeline Partners, L.P. | Lightfoot Capital Partners, LP | Development Subsidiary | Atlas Resource Partners, L.P. | Atlas Pipeline Partners, L.P. | Lightfoot Capital Partners, LP | Development Subsidiary | |||||||||||
General partner ownership interest | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 100.00% | 2.00% | 15.90% | ' | ' | ' | ' | ' | ' |
Common limited partner ownership interest | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 33.70% | 5.80% | 12.00% | 15.20% |
Common limited partner interest in ARP, units | ' | ' | ' | ' | ' | ' | ' | 20,962,485 | 3,749,986 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Outstanding general partner ownership interest | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 83.10% | ' | ' | ' | ' | ' |
Percentage of cash distribution | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1.70% | ' | ' | ' | ' | ' | ' | ' | ' | ' |
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 | 19-Feb-14 | 19-Nov-13 | 19-Aug-13 | 20-May-13 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Ratio Of ARP Limited Partner Units | 0.1021 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Date of Record | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 28-Feb-12 | ' | ' | ' | ' |
Summary_of_Significant_Account3
Summary of Significant Accounting Policies (Narrative) (Details) (USD $) | 3 Months Ended | 3 Months Ended | 3 Months Ended | 12 Months Ended | 3 Months Ended | 1 Months Ended | 12 Months Ended | 3 Months Ended | 3 Months Ended | ||||||||||||||||
Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2013 | 7-May-13 | 7-May-13 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | |
TEAK Acquisition | ARP Acquisitions | ARP Acquisitions | APL Acquisitions | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Ownership Interest West OK Natural Gas Gathering System And Processing Plants | Undivided Interest In West TX Natural Gas System And Processing Plants | Pioneer Natural Resource's Ownership Interest in West TX | ARP And APL Carrying Amount Changes, Goodwill | ARP And APL Carrying Amount Changes, Goodwill | Corporate Subsidiaries of the Partnership | ||||
Gathering Fee Remits | Gathering Fee Charges | Revenues Collected | TEAK Acquisition | TEAK Acquisition | Cardinal Acquisition | Centrahoma Processing LLC | |||||||||||||||||||
Customer Relationships | |||||||||||||||||||||||||
Pro-rata share in Drilling Partnerships | ' | ' | ' | ' | ' | ' | ' | 30.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity Method Investment, Ownership Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 95.00% | ' | ' | ' | ' | 60.00% | ' | ' | ' | ' | ' | ' |
Percentage Individually Owned By Joint Ventures | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 100.00% | 72.80% | ' | ' | ' | ' |
Non-controlling ownership interest in joint ventures | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5.00% | ' | ' | ' | ' | 40.00% | ' | ' | 27.20% | ' | ' | ' |
Note Receivable From Joint Ventures | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $1,900,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Business Acquisition, Effective Date of Acquisition | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20-Dec-12 | ' | ' | ' | ' | ' | ' |
Percentage Of Joint Ventures Consolidated | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 100.00% | ' | ' | ' | ' | ' | ' |
Allowance for Doubtful Accounts Receivable | 0 | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Materials, supplies and other inventory | 32,000,000 | ' | 19,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Impairments Of Unproved Gas And Oil Properties | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 13,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Impairments Of Proved Gas And Oil Properties | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 24,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Weighted average interest rate used to capitalize interest | 5.60% | 6.10% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Aggregate amount of interest capitalized | 5,500,000 | 5,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Business Acquisition, Percentage of Voting Interests Acquired | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 100.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Intangible assets | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 430,000,000 | 450,000,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Estimated Useful Lives In Years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '13 years | ' | ' | ' | ' | ' | ' | ' | ' |
Amortization of Intangible Assets | 21,600,000 | 8,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Future Amortization Expense, 2014 | ' | ' | 80,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Goodwill | 402,180,000 | ' | 400,356,000 | ' | 31,800,000 | 31,800,000 | 370,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Goodwill, Period Increase (Decrease) | ' | ' | ' | 1,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Goodwill, Impairment Loss | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 43,900,000 | ' | ' | ' | ' | 0 | 0 | ' |
Goodwill Impairment Indicators | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
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 2010. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of March 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 | -398,000 | -9,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -398,000 | -9,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 |
Related party transaction, percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16.00% | 13.00% | 3.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Unbilled Contracts Receivable | $268,900,000 | ' | $191,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Summary_of_Significant_Account4
Summary of Significant Accounting Policies (Schedule of the Components of Intangible Assets Being Amortized) (Details) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2014 | Dec. 31, 2013 |
Finite Lived Intangible Assets [Line Items] | ' | ' |
Gross Carrying Amount | $885,416 | $905,416 |
Accumulated Amortization | -229,737 | -208,182 |
Net Carrying Amount | 655,679 | 697,234 |
Customer contracts and relationships | ' | ' |
Finite Lived Intangible Assets [Line Items] | ' | ' |
Gross Carrying Amount | 871,072 | 891,072 |
Accumulated Amortization | -216,288 | -194,801 |
Net Carrying Amount | 654,784 | 696,271 |
Customer contracts and relationships | Minimum | ' | ' |
Finite Lived Intangible Assets [Line Items] | ' | ' |
Estimated Useful Lives In Years | '2 years | ' |
Customer contracts and relationships | 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 | -13,449 | -13,381 |
Net Carrying Amount | $895 | $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 $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Goodwill [Line Items] | ' | ' |
Goodwill | $402,180 | $400,356 |
Atlas Resource Partners, L.P. | ' | ' |
Goodwill [Line Items] | ' | ' |
Goodwill | 31,784 | 31,784 |
Atlas Pipeline Partners, L.P. | ' | ' |
Goodwill [Line Items] | ' | ' |
Goodwill | $370,396 | $368,572 |
Summary_of_Significant_Account6
Summary of Significant Accounting Policies (Schedule of Net Income Reconciliation) (Details) (USD $) | 3 Months Ended | |||
In Thousands, except Share data, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | ||
Net loss | ($21,067) | ($41,694) | ||
Loss attributable to non-controlling interests | 7,142 | 29,098 | ||
Net loss attributable to common limited partners | -13,925 | -12,596 | ||
Phantom units not attributable to net loss | 2,398,000 | 2,216,000 | ||
Segment, Continuing Operations | ' | ' | ||
Net loss | -21,067 | -41,694 | ||
Loss attributable to non-controlling interests | 7,142 | 29,098 | ||
Net loss attributable to common limited partners | -13,925 | -12,596 | ||
Less: Net income attributable to participating securities – phantom units | ' | [1] | ' | [1] |
Net loss utilized in the calculation of net loss attributable to common limited partners per unit | ($13,925) | ($12,596) | ||
[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 three months ended March 31, 2014 and 2013, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 2,398,000 and 2,216,000 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. |
Summary_of_Significant_Account7
Summary of Significant Accounting Policies (Reconciliation of Weighted Average Number of Common Limited Partner Units) (Details) | 3 Months Ended | |||
Mar. 31, 2014 | Mar. 31, 2013 | |||
Accounting Policies [Abstract] | ' | ' | ||
Weighted average number of common limited partners per unit—basic | 51,491,000 | 51,369,000 | ||
Add effect of dilutive incentive awards | ' | [1] | ' | [1] |
Weighted average number of common limited partners per unit—diluted | 51,491,000 | 51,369,000 | ||
Antidilutive Securities Excluded From Computation Of Diluted Earnings Attributable To Common Limited Partners Outstanding Units | 4,111,000 | 3,594,000 | ||
[1] | For the three months ended March 31, 2014 and 2013, approximately 4,111,000 units and 3,594,000 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_EP_Energy_Acquisi
Acquisitions (EP Energy Acquisition ) (Narrative) (Details) (Atlas Resource Partners, L.P., USD $) | 1 Months Ended | 1 Months Ended | |||
In Millions, except Share data, unless otherwise specified | Mar. 31, 2014 | Jul. 31, 2013 | Jun. 30, 2013 | Dec. 31, 2013 | Jul. 31, 2013 |
Ep Energy | Ep Energy | Ep Energy | Ep Energy | ||
Preferred Class C | |||||
Business Acquisition [Line Items] | ' | ' | ' | ' | ' |
Cash Consideration | ' | $709.60 | ' | ' | ' |
Debt Instrument, Interest Rate, Stated Percentage | ' | 9.25% | ' | ' | ' |
Debt Instrument, Maturity Date | ' | 15-Aug-21 | ' | ' | ' |
Business Acquisition, Effective Date of Acquisition | ' | 1-May-13 | ' | ' | ' |
Partners' Capital Account, Units, Sale of units | 6,325,000 | 14,950,000 | 14,950,000 | ' | 3,749,986 |
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 10). | ' | ' | ' |
Business Acquisition, Purchase Price Allocation, Status | ' | '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 | ' | ' | ' | $12.10 | ' |
Acquisitions_EP_Energy_Acquisi1
Acquisitions (EP Energy Acquisition Schedule of Assets Acquired and Liabilities Assumed) (Details) (Atlas Resource Partners, L.P., Ep Energy, USD $) | Jul. 31, 2013 |
In Thousands, unless otherwise specified | |
Atlas Resource Partners, L.P. | Ep Energy | ' |
Business Acquisition [Line Items] | ' |
Prepaid expenses and other | $5,268 |
Property, plant and equipment | 723,657 |
Total current assets | 728,925 |
Accounts payable | 2,562 |
Asset retirement obligation | 16,728 |
Total liabilities assumed | 19,290 |
Net assets acquired | $709,635 |
Acquisitions_TEAK_Acquisition_
Acquisitions (TEAK Acquisition) (Narrative) (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | 10-May-13 | 7-May-13 | Apr. 17, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | 7-May-13 | 10-May-13 | Mar. 31, 2014 | 7-May-13 | Apr. 17, 2013 | 7-May-13 |
APL 4.750 % Senior Notes | TEAK Acquisition | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | |||
APL 4.750 % Senior Notes | APL 4.750 % Senior Notes | APL 4.750 % Senior Notes | APL 4.750 % Senior Notes | TEAK Acquisition | TEAK Acquisition | TEAK Acquisition | TEAK Acquisition | TEAK Acquisition | TEAK Acquisition | TEAK Acquisition | TEAK Acquisition | TEAK Acquisition | TEAK Acquisition | ||||
Class D Preferred Units | APL 4.750 % Senior Notes | APL 4.750 % Senior Notes | APL 4.750 % Senior Notes | Common Units To Maintain General Partner Interest | Common Units To Maintain General Partner Interest | ||||||||||||
Class D Preferred Units | |||||||||||||||||
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 includes 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€). | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Partners' Capital Account, Private Placement of Units | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 400,000,000 | ' | ' | ' | ' | ' |
Proceeds from Issuance of Preferred Limited Partners Units | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 397,700,000 | ' | ' | ' | 8,300,000 | 8,200,000 |
General partner ownership interest | ' | ' | ' | ' | ' | ' | ' | ' | 2.00% | ' | ' | 2.00% | ' | ' | ' | ' | ' |
Partners' Capital Account, Units, Sale of units | ' | ' | ' | ' | ' | ' | ' | ' | 11,845,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Negotiated Purchase Price Per Unit | ' | ' | ' | ' | ' | ' | ' | ' | $34 | ' | ' | ' | ' | ' | ' | ' | ' |
Proceeds from Issuance of Common Limited Partners Units | ' | ' | ' | ' | ' | ' | ' | ' | 388,400,000 | ' | ' | ' | ' | ' | ' | 8,300,000 | ' |
Debt Instrument, Face Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 400,000,000 | ' | 400,000,000 | ' | ' |
Debt Instrument, Interest Rate, Stated Percentage | ' | ' | ' | 4.75% | 4.75% | 4.75% | 4.75% | ' | ' | ' | ' | ' | ' | ' | 4.75% | ' | ' |
Debt Instrument, Maturity Date | ' | ' | 1-Jan-21 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15-Nov-21 | ' | ' | ' |
Proceeds from Debt, Net of Issuance Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 391,200,000 | ' | ' | ' | ' |
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 10). | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Deferred Finance Costs, Noncurrent, Net | $83,413,000 | $86,617,000 | ' | ' | ' | ' | ' | ' | ' | ' | $9,700,000 | ' | ' | ' | ' | ' | ' |
Business Acquisition, Purchase Price Allocation, Status | ' | ' | ' | ' | ' | ' | ' | '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 APL continues to evaluate the facts and circumstances that existed as of the acquisition date. | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Acquisitions_TEAK_Acquisition_1
Acquisitions (TEAK Acquisition Schedule of Assets Acquired and Liabilities Assumed) (Details) (Atlas Pipeline "APL", TEAK Acquisition, USD $) | 7-May-13 |
In Thousands, unless otherwise specified | |
Atlas Pipeline "APL" | TEAK Acquisition | ' |
Business Acquisition [Line Items] | ' |
Cash | $8,074 |
Accounts receivable | 11,055 |
Prepaid expenses and other | 1,626 |
Total current assets | 20,755 |
Property, plant and equipment | 193,877 |
Intangible assets | 430,000 |
Goodwill | 190,683 |
Equity method investment in joint ventures | 183,801 |
Total assets acquired | 1,019,116 |
Accounts payable and accrued liabilities | -35,296 |
Other long term liabilities | -1,075 |
Total liabilities assumed | -36,371 |
Net assets acquired | 982,745 |
Less cash received | -8,074 |
Net cash paid for acquisition | $974,671 |
Acquisitions_Other_Acquisition
Acquisitions (Other Acquisitions) (Narrative) (Details) (USD $) | 1 Months Ended | ||
In Thousands, unless otherwise specified | Jul. 31, 2013 | Feb. 13, 2014 | Sep. 20, 2013 |
Arkoma Acquisition | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | |
GeoMet, Inc. | Norwood Acquisition | ||
Business Acquisition [Line Items] | ' | ' | ' |
Net cash paid for acquisition | ' | $107,000 | ' |
Business Acquisition, Effective Date of Acquisition | 1-May-13 | 1-Jan-14 | 1-Jun-13 |
Businnes acquisition approved closing date of transaction | ' | 5-May-14 | ' |
Expected closing date of transaction | ' | 30-Jun-14 | ' |
Net assets acquired | $64,500 | ' | $5,400 |
APL_Equity_Method_Investments_1
APL Equity Method Investments (West Texas LPG Pipeline) (Narrative) (Details) (Atlas Pipeline "APL") | Mar. 31, 2014 |
Schedule Of Equity Method Investments [Line Items] | ' |
Equity Method Investment, Ownership Percentage | 95.00% |
Equity Method Investment in West Texas LPG Pipeline L.P. | ' |
Schedule Of Equity Method Investments [Line Items] | ' |
Equity Method Investment, Ownership Percentage | 20.00% |
Chevron Pipeline's Equity Method Investment in WTLPG | ' |
Schedule Of Equity Method Investments [Line Items] | ' |
Equity Method Investment, Ownership Percentage | 80.00% |
APL_Equity_Method_Investments_2
APL Equity Method Investments (Joint Ventures) (Narrative) (Details) (Atlas Pipeline "APL") | Mar. 31, 2014 |
Schedule Of Equity Method Investments [Line Items] | ' |
Equity Method Investment, Ownership Percentage | 95.00% |
Equity Method Investment in T2 LaSalle | TEAK Acquisition | ' |
Schedule Of Equity Method Investments [Line Items] | ' |
Equity Method Investment, Ownership Percentage | 75.00% |
Equity Method Investment in T2 Eagle Ford | TEAK Acquisition | ' |
Schedule Of Equity Method Investments [Line Items] | ' |
Equity Method Investment, Ownership Percentage | 50.00% |
Equity Method Investment in T2 EF C0-Gen | TEAK Acquisition | ' |
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 $) | 3 Months Ended | ||
Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | |
Schedule Of Equity Method Investments [Line Items] | ' | ' | ' |
Equity method investment in joint ventures | $269,058,000 | ' | $248,301,000 |
Equity income (loss) in joint ventures | -1,878,000 | 2,040,000 | ' |
Equity Method Investment in West Texas LPG Pipeline L.P. | ' | ' | ' |
Schedule Of Equity Method Investments [Line Items] | ' | ' | ' |
Equity method investment in joint ventures | 85,517,000 | ' | 85,790,000 |
Equity income (loss) in joint ventures | 1,727,000 | 2,040,000 | ' |
Equity Method Investment in T2 EF C0-Gen | ' | ' | ' |
Schedule Of Equity Method Investments [Line Items] | ' | ' | ' |
Equity method investment in joint ventures | 14,719,000 | ' | 14,540,000 |
Equity income (loss) in joint ventures | -447,000 | ' | ' |
TEAK Acquisition | Equity Method Investment in T2 LaSalle | ' | ' | ' |
Schedule Of Equity Method Investments [Line Items] | ' | ' | ' |
Equity method investment in joint ventures | 58,731,000 | ' | 50,534,000 |
Equity income (loss) in joint ventures | -1,113,000 | ' | ' |
TEAK Acquisition | Equity Method Investment in T2 Eagle Ford | ' | ' | ' |
Schedule Of Equity Method Investments [Line Items] | ' | ' | ' |
Equity method investment in joint ventures | 110,091,000 | ' | 97,437,000 |
Equity income (loss) in joint ventures | ($2,045,000) | ' | ' |
Property_Plant_and_Equipment_S
Property, Plant and Equipment (Summary of Property, Plant and Equipment) (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Property Plant And Equipment [Line Items] | ' | ' |
Proved properties: Leasehold interest | $323,698 | $322,217 |
Proved Properties: Pre-development costs | 4,066 | 4,367 |
Proved Properties: Wells and related equipment | 2,280,114 | 2,231,213 |
Total proved properties | 2,607,878 | 2,557,797 |
Unproved properties | 216,691 | 211,851 |
Support equipment | 26,656 | 23,258 |
Total natural gas and oil properties | 2,851,225 | 2,792,906 |
Pipelines, processing and compression facilities | 3,063,750 | 2,926,134 |
Rights of way | 195,518 | 203,966 |
Land, buildings and improvements | 29,735 | 30,216 |
Other | 37,372 | 36,752 |
Total gross property, plant and equipment | 6,177,600 | 5,989,974 |
Less – accumulated depreciation, depletion and amortization | -1,153,095 | -1,079,099 |
Property, plant and equipment, Net, Total | $5,024,505 | $4,910,875 |
Property_Plant_and_Equipment_U
Property, Plant and Equipment (Useful Life Narrative) (Details) | 3 Months Ended |
Mar. 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 $) | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | |
Property Plant And Equipment [Line Items] | ' | ' | ' |
Loss on asset sales and disposal | ($1,603,000) | ($702,000) | ' |
Asset impairment | ' | ' | 38,000,000 |
Atlas Resource Partners, L.P. | ' | ' | ' |
Property Plant And Equipment [Line Items] | ' | ' | ' |
Loss on asset sales and disposal | ' | 700,000 | ' |
Asset impairment | ' | ' | $38,000,000 |
Other_Assets_Summary_of_Other_
Other Assets (Summary of Other Assets) (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Schedule Of Equity Method Investments [Line Items] | ' | ' |
Deferred financing costs, net of accumulated amortization of $47,811 and $43,702 at March 31, 2014 and December 31, 2013, respectively | $83,413 | $86,617 |
Security deposits | 6,082 | 5,631 |
Long-term derivative asset receivable from Drilling Partnerships | 1,007 | 863 |
Other | 8,454 | 6,129 |
Total Other Assets | 124,305 | 124,672 |
Accumulated amortization of deferred financing costs | 47,811 | 43,702 |
Equity Method Investment In Lightfoot | ' | ' |
Schedule Of Equity Method Investments [Line Items] | ' | ' |
Investment in Lightfoot | 21,337 | 21,454 |
Atlas Resource Partners, L.P. | ' | ' |
Schedule Of Equity Method Investments [Line Items] | ' | ' |
ARP notes receivable | $4,012 | $3,978 |
Other_Assets_Narrative_Details
Other Assets (Narrative) (Details) (USD $) | 3 Months Ended | |
Mar. 31, 2014 | Mar. 31, 2013 | |
Schedule Of Equity Method Investments [Line Items] | ' | ' |
Amortization of deferred financing costs | $4,109,000 | $6,246,000 |
Distributions received from unconsolidated companies | 2,311,000 | 1,804,000 |
Equity Method Investment in Lightfoot LP | ' | ' |
Schedule Of Equity Method Investments [Line Items] | ' | ' |
Equity Method Investment, Ownership Percentage | 12.00% | ' |
Distributions received from unconsolidated companies | 400,000 | 4,000 |
Equity Method Investment In Lightfoot GP | ' | ' |
Schedule Of Equity Method Investments [Line Items] | ' | ' |
Equity Method Investment, Ownership Percentage | 15.90% | ' |
Equity Method Investment In Lightfoot | ' | ' |
Schedule Of Equity Method Investments [Line Items] | ' | ' |
Equity income (loss) in joint ventures | 200,000 | 1,000 |
Atlas Pipeline "APL" | ' | ' |
Schedule Of Equity Method Investments [Line Items] | ' | ' |
Amortization of deferred financing costs | 4,100,000 | 3,000,000 |
Accelerated amortization of deferred financing costs | 0 | 5,300,000 |
Senior Notes Retirement Percent | ' | 8.75% |
Debt Instrument, Maturity Date | ' | 15-Jun-18 |
Atlas Resource Partners, L.P. | ' | ' |
Schedule Of Equity Method Investments [Line Items] | ' | ' |
Accelerated amortization of deferred financing costs | ' | 3,200,000 |
Atlas Resource Partners, L.P. | Notes Receivable | ' | ' |
Schedule Of Equity Method Investments [Line Items] | ' | ' |
Note Agreement, Maturity Date | 31-Mar-22 | ' |
Note Agreement Interest Rate Per Annum | 2.25% | ' |
Other Interest and Dividend Income | $23,000 | $0 |
Atlas Resource Partners, L.P. | Note Agreement, Option to Extend Maturity Date | ' | ' |
Schedule Of Equity Method Investments [Line Items] | ' | ' |
Note Agreement, 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) (Details) (USD $) | 3 Months Ended | 12 Months Ended | 3 Months Ended | 12 Months Ended | |||
Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | |
Arkoma Acquisition | Relationship With Drilling Partnerships | Relationship With Drilling Partnerships | Relationship With Drilling Partnerships | Atlas Resource Partners, L.P. | |||
Limited Partner Interest | Ep Energy | ||||||
Asset retirement obligations, beginning of year | $91,214,000 | $64,794,000 | ' | ' | ' | $57,900,000 | ' |
Liabilities incurred | 602,000 | 645,000 | ' | ' | ' | ' | ' |
Liabilities settled | -217,000 | -7,000 | ' | ' | ' | ' | ' |
Accretion expense | 1,328,000 | 954,000 | ' | ' | ' | ' | ' |
Asset retirement obligations, end of period | 92,927,000 | 66,386,000 | ' | ' | ' | 57,900,000 | ' |
Limited partner distributions withheld related to the asset retirement obligations of certain Drilling Partnerships | ' | ' | ' | 600,000 | 0 | ' | ' |
Future plugging and abandonment costs related to acquisitions | ' | ' | $1,300,000 | ' | ' | ' | $16,700,000 |
Debt_Total_Debt_Details
Debt (Total Debt) (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Jan. 23, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Jul. 30, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Feb. 11, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | 10-May-13 |
In Thousands, unless otherwise specified | APL 5.875% Senior Notes | APL 4.750 % Senior Notes | Parent Company | Parent Company | Parent Company | Parent Company | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | ||
Term Loan | Term Loan | ARP 7.75% Senior Notes | ARP 7.75% Senior Notes | ARP 7.75% Senior Notes | ARP 9.25% Senior Notes | ARP 9.25% Senior Notes | ARP 9.25% Senior Notes | APL 6.625% Senior Notes | APL 6.625% Senior Notes | APL 5.875% Senior Notes | APL 5.875% Senior Notes | APL 5.875% Senior Notes | APL 4.750 % Senior Notes | APL 4.750 % Senior Notes | APL 4.750 % Senior Notes | |||||||||||
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Term loan facility | ' | ' | ' | ' | ' | ' | $238,800 | $239,400 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Revolving credit facility | ' | ' | ' | ' | ' | ' | ' | ' | 366,000 | 419,000 | ' | ' | ' | ' | ' | ' | 150,000 | 152,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Senior Notes | ' | ' | 650,000 | 400,000 | ' | ' | ' | ' | ' | ' | 275,000 | 275,000 | ' | 248,388 | 248,334 | ' | ' | ' | 504,387 | 504,556 | 650,000 | 650,000 | 650,000 | 400,000 | 400,000 | ' |
Capital leases | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 556 | 754 | ' | ' | ' | ' | ' | ' | ' | ' |
Total debt | 2,833,131 | 2,889,044 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Less current maturities | -2,794 | -2,924 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Total long-term debt | $2,830,337 | $2,886,120 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Interest Rate, Stated Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7.75% | 7.75% | 7.75% | 9.25% | 9.25% | 9.25% | ' | ' | 6.63% | 6.63% | 5.88% | 5.88% | 5.88% | 4.75% | 4.75% | 4.75% |
Debt_Partnerships_Term_Loan_Fa
Debt (Partnership's Term Loan Facility) (Details) (ATLS Partnership, USD $) | 3 Months Ended | |
Mar. 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 (i) 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, and (ii) the entry into swap agreements with respect to the assets acquired in the EP Energy and Arkoma acquisitions (see Note 3). At March 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. | ' |
Secured Term Facility | Arkoma Acquisition | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Revolving Credit Facility | ' | $240,000,000 |
Term loan facility | 238,800,000 | ' |
Line of Credit Facility, Expiration Date | 31-Jul-19 | ' |
Debt Instrument, Interest Terms and Due Dates | '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 $) | 3 Months Ended | |
Mar. 31, 2014 | Dec. 31, 2013 | |
ATLS Partnership | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Line of Credit Facility, Amount Outstanding | ' | ' |
ATLS Partnership | Credit Facility | Arkoma Acquisition | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Line of Credit Facility, Expiration Date | 31-Jul-18 | ' |
Line of Credit Facility, Maximum Borrowing Capacity | 50,000,000 | ' |
Line of Credit Facility, Amount Outstanding | ' | ' |
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. | ' |
Fee Range per annum on unused portion of the commitments under the credit agreement | '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. | ' |
ATLS Partnership | Standby Letters of Credit | Arkoma Acquisition | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Line of Credit Facility, Maximum Borrowing Capacity | 5,000,000 | ' |
Line of Credit Facility, Amount Outstanding | ' | ' |
ATLS | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Line of Credit Facility, Amount Outstanding | ' | ' |
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 2.3 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 (i) the required ratio of Total Funded Debt (as defined in the credit facility) to EBITDA (as defined in the credit facility), and (ii) entry into swap agreements. At March 31, 2014, the Partnership was in compliance with these covenants. | ' |
Line Of Credit Facility Total Funded Debt To Ebitda Actual Ratio | '2.3 to 1.0 | ' |
ATLS | Minimum | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Line of Credit Facility, Amount Outstanding | ' | ' |
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.50% | ' |
ATLS | Maximum | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Line of Credit Facility, Amount Outstanding | ' | ' |
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.63% | ' |
Debt_ARPs_Credit_Facility_Deta
Debt (ARP's Credit Facility) (Details) (Atlas Resource Partners, L.P., USD $) | 3 Months Ended | |
Mar. 31, 2014 | Dec. 31, 2013 | |
Debt Instrument [Line Items] | ' | ' |
Line of Credit Facility, Expiration Date | 1-Jul-18 | ' |
Line of Credit Facility, Current Borrowing Capacity | $735,000,000 | ' |
Line of Credit Facility, Maximum Borrowing Capacity | 1,500,000,000 | ' |
Line of Credit Facility, Amount Outstanding | 366,000,000 | 419,000,000 |
Line of Credit Facility, Interest Rate Description | 'Borrowings under the credit facility bear interest, at ARP’s election, at either an adjusted LIBOR rate plus an applicable margin between 1.75% 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 0.75% 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 0.5% per annum if 50% or more of the borrowing base is utilized and 0.375% per annum if less than 50% of the borrowing base is utilized, which is included within interest expense on the Partnership’s consolidated statements of operations. | ' |
Outstanding Term Facility, Weighted Average Interest Rate | 2.30% | ' |
Line Of Credit Facility, Total Funded Debt to EBITDA, Required Ratio | '4.0 to 1.0 | '4.50 to 1.0 |
Line Of Credit Facility, Current Assets to Current Liabilities, Required Ratio | '1.0 to 1.0 | ' |
Line Of Credit Facility, Current Assets to Current Liabilities, Actual Ratio | '2.1 to 1.0 | ' |
Line Of Credit Facility, EBITDA to Consolidated Interest Expense, Actual Ratio | '3.9 to 1.0 | ' |
The last day of quarter ended March 31, 2014 | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Line Of Credit Facility, Total Funded Debt to EBITDA, Required Ratio | '4.50 to 1.0 | ' |
The last day of quarter ended June 30, 2014 | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Line Of Credit Facility, Total Funded Debt to EBITDA, Required Ratio | '4.50 to 1.0 | ' |
The last day of quarter ended September 30, 2014 | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Line Of Credit Facility, Total Funded Debt to EBITDA, Required Ratio | '4.25 to 1.0 | ' |
Minimum | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Line of Credit Facility, Additional Margin Rates In Excess of LIBOR | 1.75% | ' |
Line of Credit Facility, Borrowing Base Additional Rate | 0.75% | ' |
Maximum | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Line of Credit Facility, Additional Margin Rates In Excess of LIBOR | 2.75% | ' |
Line of Credit Facility, Borrowing Base Additional Rate | 1.75% | ' |
50% or more of the borrowing base is utilized | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.50% | ' |
Less than 50% of the borrowing base is utilized | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.38% | ' |
Letter of Credit | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Line of Credit Facility, Maximum Borrowing Capacity | 20,000,000 | ' |
Line of Credit Facility, Amount Outstanding | $3,700,000 | ' |
Revolving Credit Facility | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Obligations under the facility, description | 'Additionally, obligations under the facility are guaranteed by certain of ARP’s material subsidiaries | ' |
Debt Instrument, Covenant Compliance | 'ARP was in compliance with these covenants as of March 31, 2014. | ' |
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. | ' |
Credit Agreement | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Business Acquisition, Date of Acquisition Agreement | 31-Jul-13 | ' |
Debt_ARP_Senior_Notes_Details
Debt (ARP Senior Notes) (Details) (Atlas Resource Partners, L.P., USD $) | 3 Months Ended | 0 Months Ended | 3 Months Ended | |||
In Millions, except Per Share data, unless otherwise specified | Mar. 31, 2014 | Dec. 31, 2013 | Jul. 30, 2013 | Jan. 23, 2013 | Mar. 31, 2014 | Dec. 31, 2013 |
ARP 9.25% Senior Notes | ARP 9.25% Senior Notes | ARP 9.25% Senior Notes | ARP 7.75% Senior Notes | ARP 7.75% Senior Notes | ARP 7.75% Senior Notes | |
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' |
Debt Instrument, Issuance Date | 30-Jul-13 | ' | ' | ' | 23-Jan-13 | ' |
Debt Instrument, Face Amount | ' | ' | $250 | $275 | $275 | ' |
Debt Instrument, Interest Rate, Stated Percentage | 9.25% | 9.25% | 9.25% | 7.75% | 7.75% | 7.75% |
Debt Instrument, Maturity Date | 15-Aug-21 | ' | ' | ' | 1-Jan-21 | ' |
Offering price as a percentage of par value | ' | ' | 99.30% | ' | ' | ' |
Debt Instruments, Underwriting Fees and Other Offering Costs | ' | ' | 5.5 | ' | ' | ' |
Unamortized discounts | 1.6 | ' | ' | ' | ' | ' |
Proceeds from Debt, Net of Issuance Costs | 242.8 | ' | ' | 267.6 | ' | ' |
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 109.25%. 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. | ' | ' | ' | ' | ' |
Line Of Credit Facility, Borrowing Base Reduction Rate | ' | ' | ' | 15.00% | ' | ' |
Debt Instrument, Interest Terms and Due Dates | ' | ' | ' | 'Interest on the 7.75% ARP Senior Notes is payable semi-annually on January 15 and July 15. | ' | ' |
Amortization of Financing Costs | ' | ' | ' | ' | $3.20 | ' |
Debt Instrument, Redemption Date | ' | ' | ' | ' | 15-Jan-16 | ' |
Senior Notes, Partial Redemption, Percent | ' | ' | ' | 35.00% | ' | ' |
Debt instrument, redemption price | ' | ' | ' | $108 | ' | ' |
Senior Notes Repurchase Price | ' | ' | ' | '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. | ' | ' |
Debt Instrument, Restrictive Covenants | ' | ' | ' | 'The indentures governing the 9.25% ARP Senior Notes and 7.75% 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. | ' | ' |
Debt Instrument, Covenant Compliance | ' | ' | ' | ' | 'ARP was in compliance with these covenants as of March 31, 2014. | ' |
Debt_APL_Credit_Facility_Detai
Debt (APL Credit Facility) (Details) (Atlas Pipeline "APL", USD $) | 3 Months Ended | |
Mar. 31, 2014 | Dec. 31, 2013 | |
Debt Instrument [Line Items] | ' | ' |
Line of Credit Facility, Maximum Borrowing Capacity | $600,000,000 | ' |
Line of Credit Facility, Expiration Date | 1-May-17 | ' |
Line of Credit Facility, Amount Outstanding | 150,000,000 | 152,000,000 |
Line of Credit Facility, Interest Rate Description | 'Borrowings under APL’s credit facility bear interest, at APL’s option, at either (i) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) three-month LIBOR plus 1.0%, or (ii) the LIBOR rate for the applicable period (each plus the applicable margin). | ' |
Outstanding Term Facility, Weighted Average Interest Rate | 3.20% | ' |
Line of Credit Facility, Remaining Borrowing Capacity | 449,900,000 | ' |
Guaranty Liabilities | 0 | ' |
Line of Credit Facility, Collateral | 'Borrowings under APL’s credit facility are secured by (i) a lien on and security interest in all of APL’s property and that of its subsidiaries, except for the assets owned by the West OK, West TX and Centrahoma joint ventures and their respective subsidiaries; and (ii) the guarantee of each of APL’s consolidated subsidiaries other than the joint venture companies. | ' |
Letter of Credit | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Line of Credit Facility, Maximum Borrowing Capacity | 50,000,000 | ' |
Line of Credit Facility, Amount Outstanding | 100,000 | ' |
Revolving Credit Facility | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Debt Instrument, Restrictive Covenants | 'The revolving credit facility contains customary covenants, including requirements that APL maintain certain financial thresholds and restrictions on its ability to (i) incur additional indebtedness, (ii) make certain acquisitions, loans or investments, (iii) make distribution payments to its unitholders if an event of default exists, or (iv) enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. APL is also unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings†pursuant to its partnership agreement. | ' |
Debt Instrument, Covenant Compliance | 'APL was in compliance with these covenants as of March 31, 2014. | ' |
Revolving Credit Facility | Minimum | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Line of Credit Facility, Current Borrowing Capacity | $50,000,000 | ' |
Debt_APL_Senior_Notes_Issuance
Debt (APL Senior Notes Issuances) (Details) (USD $) | 3 Months Ended | 3 Months Ended | 1 Months Ended | 3 Months Ended | 1 Months Ended | 3 Months Ended | 1 Months Ended | 3 Months Ended | 0 Months Ended | 1 Months Ended | 3 Months Ended | |||||||||||
Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Feb. 11, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | 10-May-13 | Mar. 31, 2014 | Dec. 31, 2013 | 10-May-13 | Mar. 31, 2014 | 7-May-13 | Feb. 11, 2013 | Mar. 12, 2013 | Jan. 28, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | |
APL 6.625% Senior Notes | APL 5.875% Senior Notes | APL 4.750 % Senior Notes | APL 4.750 % Senior Notes | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | ||
TEAK Acquisition | APL 6.625% Senior Notes | APL 5.875% Senior Notes | APL 5.875% Senior Notes | APL 5.875% Senior Notes | APL 4.750 % Senior Notes | APL 4.750 % Senior Notes | APL 4.750 % Senior Notes | APL 4.750 % Senior Notes | APL 4.750 % Senior Notes | APL 4.750 % Senior Notes | APL 8.75% Senior Notes Remaining Redemption | Senior Notes | Senior Notes | Senior Notes | A P L Senior Notes | |||||||
TEAK Acquisition | TEAK Acquisition | TEAK Acquisition | ||||||||||||||||||||
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Senior Notes | ' | ' | $650,000,000 | $400,000,000 | ' | ' | ' | $500,000,000 | $650,000,000 | $650,000,000 | $650,000,000 | ' | $400,000,000 | $400,000,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Interest Rate, Stated Percentage | ' | ' | ' | ' | 4.75% | ' | ' | 6.63% | 5.88% | 5.88% | 5.88% | 4.75% | 4.75% | 4.75% | ' | ' | 4.75% | 8.75% | ' | ' | ' | ' |
Debt Instrument, Maturity Date | ' | 1-Oct-20 | 1-Aug-23 | 1-Jan-21 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15-Nov-21 | ' | ' | ' | ' | ' | ' |
Debt Instrument, Face Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 400,000,000 | ' | 400,000,000 | ' | ' | ' | ' | ' |
Debt Instrument, Interest Terms and Due Dates | ' | '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 redeemable at any time after October 1, 2016, at certain redemption prices, together with accrued and unpaid interest to the date of redemption | ' | ' | ' | ' | ' | ' | 'Interest on the 5.875% APL Senior Notes is payable semi-annually in arrears on February 1 and August 1 | ' | ' | 'Interest on the 4.75% APL Senior Notes is payable semi-annually in arrears on May 15 and November 15 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Redemption Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1-Feb-18 | ' | ' | 15-Mar-16 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Exchange Offer Registration Statement Agreement Description | ' | ' | ' | ' | ' | ' | ' | ' | ' | 'APL commenced an exchange offer for the 5.875% APL Senior Notes on December 10, 2013 and the exchange offer was completed on January 9, 2014 | ' | ' | 'APL commenced an exchange offer for the 4.75% APL Senior Notes on December 10, 2013 and the exchange offer was completed on January 9, 2014 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Proceeds from Debt, Net of Issuance Costs | ' | ' | ' | ' | ' | ' | ' | ' | 637,300,000 | ' | ' | ' | ' | ' | 391,200,000 | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Unamortized Premium | ' | 4,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,200,000 | ' | ' | ' |
Debt Instrument, Repurchased Face Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 97,300,000 | 365,800,000 | ' | ' |
Debt Instrument, Repurchase Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 105,600,000 | 291,400,000 | ' | ' |
Premium Paid On Redeemed Debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 17,500,000 | 11,200,000 | ' | ' |
Consent Payment on Debt Repurchase | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8,000,000 | 8,000,000 | ' | ' |
Cash Tender Offer Aggregate Principal Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 268,400,000 | ' | ' |
Cash Paid On Accrued Interest On Debt | ' | ' | ' | ' | ' | 38,800,000 | 26,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,700,000 | ' | ' |
Debt instrument. redemption premium | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6,300,000 | ' |
Debt instrument redemption, accrued interest | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | ' |
Loss on early extinguishment of debt | -26,582,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 26,600,000 | ' | ' | ' |
Accelerated amortization of deferred financing costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $5,300,000 | ' | ' | ' |
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 its obligations under its revolving credit facility. |
Debt Instrument, Restrictive Covenants | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 'Indentures governing the APL Senior Notes contain covenants, including limitations on 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. |
Debt Instrument, Covenant Compliance | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 'APL was in compliance with these covenants as of March 31, 2014. |
Debt_APL_Capital_Leases_Detail
Debt (APL Capital Leases) (Details) (Atlas Pipeline "APL", USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Atlas Pipeline "APL" | ' | ' |
Debt Instrument [Line Items] | ' | ' |
Pipelines, processing and compression facilities | $1,142 | $2,281 |
Less – accumulated depreciation | -144 | -330 |
Capital Leases, Net | $998 | $1,951 |
Debt_APL_Capital_Leases_Narrat
Debt (APL Capital Leases) (Narrative) (Details) (Atlas Pipeline "APL", USD $) | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | |
Capital lease obligations | $1,100,000 | ' | ' |
Accelerated payment on certain leases and purchase of leased property | ' | ' | 7,500,000 |
Depreciation Expense for Leased Properties | 32,000 | 200,000 | ' |
Cash Paid On Accrued Interest On Debt | $38,800,000 | $26,700,000 | ' |
Accelerated Payment Original Lease Maturity Date | ' | ' | ' |
Lease Expiration Date | ' | ' | 1-Aug-13 |
Derivative_Instruments_Narrati
Derivative Instruments (Narrative) (Details) (USD $) | 3 Months Ended | 3 Months Ended | ||||||
Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | |
Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Aggregate Gains To Be Reclassified In Later Periods | ATLS Partnership | ATLS Partnership | ATLS Partnership | |||
Contract | Contract | Ep Energy | ||||||
Derivative Instruments Gain Loss [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' |
Total Partnership net derivative liabilities | $8,500,000 | ' | ' | ' | ' | ' | ' | ' |
Total Partnership net derivative assets | ' | 14,900,000 | ' | ' | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss), Net of Tax | 2,140,000 | 10,338,000 | ' | ' | ' | ' | ' | ' |
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months | 7,800,000 | ' | ' | ' | ' | ' | ' | ' |
Cash Flow Hedge Gain (Loss) To Be Reclassified In Later Periods | ' | ' | ' | ' | 9,900,000 | ' | ' | ' |
Amounts reclassified from other comprehensive income (loss) related to derivative instruments entered into during the period | ' | ' | ' | ' | ' | 0 | ' | ' |
Recognized Loss On Settled Contracts Covering Commodity Production | ' | ' | 14,000,000 | ' | ' | 500,000 | ' | ' |
Gain Loss Recognized For Hedge Ineffectiveness Or As Result Of Discontinuance Of Cash Flow Hedges | ' | ' | 0 | 0 | ' | 0 | 0 | ' |
Number of Derivative Contracts | ' | ' | ' | ' | ' | 0 | 0 | ' |
Premiums Paid On Swaption Contracts | ' | ' | ' | ' | ' | ' | ' | 2,300,000 |
Recognized Gain On Settled Contracts Covering Commodity Production | ' | ' | ' | 1,000,000 | ' | ' | ' | ' |
Hedge Monetization Cash Proceeds | ' | ' | 1,900,000 | ' | ' | ' | ' | ' |
Net Unrealized Derivative Assets Payable To Limited Partners | ' | ' | $1,100,000 | ' | ' | ' | ' | ' |
Derivative_Instruments_Gain_Lo
Derivative Instruments (Gain Loss Reclassified from Accumulated Other Comprehensive Loss into Revenue Table) (Details) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Derivative Instruments Gain Loss [Line Items] | ' | ' |
(Gain) loss reclassified from accumulated other comprehensive income (loss) | $14,569 | ($993) |
Gas And Oil Production Revenue | ' | ' |
Derivative Instruments Gain Loss [Line Items] | ' | ' |
(Gain) loss reclassified from accumulated other comprehensive income (loss) | $14,569 | ($993) |
Derivative_Instruments_Fair_Va
Derivative Instruments (Fair Value of the Partnership's Derivative Instruments Table) (Details) (ATLS Partnership, USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Long-term portion of derivative assets | ' | ' |
Derivatives Fair Value [Line Items] | ' | ' |
Gross Amounts of Recognized Assets | $1,367 | $1,547 |
Gross Amounts Offset in the Consolidated Balance Sheets | ' | -33 |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 1,367 | 1,514 |
Gross Amounts of Recognized Liabilities | ' | -33 |
Gross Amounts Offset in the Consolidated Balance Sheets | ' | 33 |
Total derivative assets | ' | ' |
Derivatives Fair Value [Line Items] | ' | ' |
Gross Amounts of Recognized Assets | 1,367 | 1,634 |
Gross Amounts Offset in the Consolidated Balance Sheets | ' | -119 |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 1,367 | 1,515 |
Current portion of derivative assets | ' | ' |
Derivatives Fair Value [Line Items] | ' | ' |
Gross Amounts of Recognized Assets | ' | 24 |
Gross Amounts Offset in the Consolidated Balance Sheets | ' | -23 |
Net Amount of Assets Presented in the Consolidated Balance Sheets | ' | 1 |
Gross Amounts of Recognized Liabilities | ' | -23 |
Gross Amounts Offset in the Consolidated Balance Sheets | ' | 23 |
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 | -770 | -96 |
Gross Amounts Offset in the Consolidated Balance Sheets | ' | 63 |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | -770 | -33 |
Total derivative liabilities | ' | ' |
Derivatives Fair Value [Line Items] | ' | ' |
Gross Amounts of Recognized Liabilities | -770 | -152 |
Gross Amounts Offset in the Consolidated Balance Sheets | ' | 119 |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | ($770) | ($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 $) | Mar. 31, 2014 | |
In Thousands, unless otherwise specified | ||
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset / (Liability) | $597 | [1] |
Production Period Ending December 31 2014 | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 2,070,000 | [2] |
Average Fixed Price | 4.177 | [2] |
Fair Value Asset / (Liability) | -593 | [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] |
Average Fixed Price | 4.302 | [2] |
Fair Value Asset / (Liability) | 228 | [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] |
Average Fixed Price | 4.433 | [2] |
Fair Value Asset / (Liability) | 399 | [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] |
Average Fixed Price | 4.59 | [2] |
Fair Value Asset / (Liability) | 393 | [1] |
Production Period Ending December 31 2018 | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 420,000 | [2] |
Average Fixed Price | 4.797 | [2] |
Fair Value Asset / (Liability) | $170 | [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 $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Derivatives Fair Value [Line Items] | ' | ' |
Current portion of derivative asset | $161 | $2,066 |
Long-term derivative asset | 28,325 | 30,868 |
Current portion of derivative liabilities | -36,929 | -17,630 |
Long-term portion of derivative liabilities | -13 | -387 |
Atlas Resource Partners, L.P. | Gross Amounts Of Recognized Assets | ' | ' |
Derivatives Fair Value [Line Items] | ' | ' |
Current portion of derivative asset | 161 | 2,664 |
Long-term derivative asset | 25,859 | 31,146 |
Current portion of derivative liabilities | 4,382 | 4,341 |
Long-term portion of derivative liabilities | 114 | 122 |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 30,516 | 38,273 |
Atlas Resource Partners, L.P. | Gross Amounts Offset In Consolidated Combined Balance Sheets Assets | ' | ' |
Derivatives Fair Value [Line Items] | ' | ' |
Current portion of derivative asset | ' | -773 |
Long-term derivative asset | -2,110 | -4,062 |
Current portion of derivative liabilities | -4,382 | -4,341 |
Long-term portion of derivative liabilities | -114 | -122 |
Net Amount of Assets Presented in the Consolidated Balance Sheets | -6,606 | -9,298 |
Atlas Resource Partners, L.P. | Net Amount Of Assets Presented In Consolidated Combined Balance Sheets | ' | ' |
Derivatives Fair Value [Line Items] | ' | ' |
Current portion of derivative asset | 161 | 1,891 |
Long-term derivative asset | 23,749 | 27,084 |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 23,910 | 28,975 |
Atlas Resource Partners, L.P. | Gross Amounts Of Recognized Liabilities | ' | ' |
Derivatives Fair Value [Line Items] | ' | ' |
Current portion of derivative asset | ' | -773 |
Long-term derivative asset | -2,110 | -4,062 |
Current portion of derivative liabilities | -26,754 | -10,694 |
Long-term portion of derivative liabilities | -127 | -189 |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | -28,991 | -15,718 |
Atlas Resource Partners, L.P. | Gross Amounts Offset in the Consolidated Balance Sheets Liabilities | ' | ' |
Derivatives Fair Value [Line Items] | ' | ' |
Current portion of derivative asset | ' | 773 |
Long-term derivative asset | 2,110 | 4,062 |
Current portion of derivative liabilities | 4,382 | 4,341 |
Long-term portion of derivative liabilities | 114 | 122 |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | 6,606 | 9,298 |
Atlas Resource Partners, L.P. | Net Amount of Liabilities Presented in Consolidated Combined Balance Sheets | ' | ' |
Derivatives Fair Value [Line Items] | ' | ' |
Current portion of derivative asset | ' | ' |
Current portion of derivative liabilities | -22,372 | -6,353 |
Long-term portion of derivative liabilities | -13 | -67 |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | ($22,385) | ($6,420) |
Derivative_Instruments_ARPs_Co
Derivative Instruments (ARP's Commodity Derivative Instruments by Type Table) (Details) (Atlas Resource Partners, L.P., USD $) | Mar. 31, 2014 | |
In Thousands, unless otherwise specified | ||
Natural Gas Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset / (Liability) | $2,964 | [1] |
Natural Gas Costless Collars | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset / (Liability) | 1,139 | [1] |
Natural Gas Put Options - Drilling Partnership | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset / (Liability) | 1,144 | [1] |
WAHA Basis Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset / (Liability) | -42 | [1] |
Natural Gas Liquids Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset / (Liability) | -396 | [2] |
Natural Gas Liquids Ethane Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset / (Liability) | 25 | [3] |
Natural Gas Liquids Propane Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset / (Liability) | -876 | [4] |
Natural Gas Liquids Butane Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset / (Liability) | 63 | [5] |
Natural Gas Liquids Iso Butane Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset / (Liability) | 57 | [6] |
Crude Oil Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset / (Liability) | -2,622 | [2] |
Crude Oil Costless Collars | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset / (Liability) | 69 | [2] |
Total ARP Net Asset | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset / (Liability) | 1,525 | [2] |
Production Period Ending December 31 2014 | Natural Gas Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 45,114,700 | [7] |
Average Fixed Price | 4.152 | [7] |
Fair Value Asset / (Liability) | -14,068 | [1] |
Production Period Ending December 31 2014 | Natural Gas Costless Collars | Puts Purchased | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 2,880,000 | [7] |
Fair Value Asset / (Liability) | 642 | [1] |
Average Floor and Cap | 4.221 | [7] |
Production Period Ending December 31 2014 | Natural Gas Costless Collars | Calls Sold | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 2,880,000 | [7] |
Fair Value Asset / (Liability) | -418 | [1] |
Average Floor and Cap | 5.12 | [7] |
Production Period Ending December 31 2014 | Natural Gas Put Options - Drilling Partnership | Puts Purchased | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 1,350,000 | [7] |
Average Fixed Price | 3.8 | [7] |
Fair Value Asset / (Liability) | 84 | [1] |
Production Period Ending December 31 2014 | WAHA Basis Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 8,100,000 | [7] |
Average Fixed Price | -0.11 | [7] |
Fair Value Asset / (Liability) | -42 | [1] |
Production Period Ending December 31 2014 | Natural Gas Liquids Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Average Fixed Price | 91.568 | [7] |
Fair Value Asset / (Liability) | -486 | [2] |
Derivatives Nonmonetary Volume Notional Amount Barrels | 79,500 | [7] |
Production Period Ending December 31 2014 | Natural Gas Liquids Ethane Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Average Fixed Price | 0.303 | [7] |
Fair Value Asset / (Liability) | 25 | [3] |
Derivatives Nonmonetary Notional Amount Gallons | 1,890,000 | [7] |
Production Period Ending December 31 2014 | Natural Gas Liquids Propane Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Average Fixed Price | 1 | [7] |
Fair Value Asset / (Liability) | -727 | [4] |
Derivatives Nonmonetary Notional Amount Gallons | 9,261,000 | [7] |
Production Period Ending December 31 2014 | Natural Gas Liquids Butane Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Average Fixed Price | 1.308 | [7] |
Fair Value Asset / (Liability) | 35 | [5] |
Derivatives Nonmonetary Notional Amount Gallons | 1,134,000 | [7] |
Production Period Ending December 31 2014 | Natural Gas Liquids Iso Butane Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Average Fixed Price | 1.323 | [7] |
Fair Value Asset / (Liability) | 33 | [6] |
Derivatives Nonmonetary Notional Amount Gallons | 1,134,000 | [7] |
Production Period Ending December 31 2014 | Crude Oil Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Average Fixed Price | 92.692 | [7] |
Fair Value Asset / (Liability) | -2,091 | [2] |
Derivatives Nonmonetary Volume Notional Amount Barrels | 409,500 | [7] |
Production Period Ending December 31 2014 | Crude Oil Costless Collars | Puts Purchased | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset / (Liability) | 38 | [2] |
Average Floor and Cap | 84.169 | [7] |
Derivatives Nonmonetary Volume Notional Amount Barrels | 30,870 | [7] |
Production Period Ending December 31 2014 | Crude Oil Costless Collars | Calls Sold | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset / (Liability) | -33 | [2] |
Average Floor and Cap | 113.308 | [7] |
Derivatives Nonmonetary Volume Notional Amount Barrels | 30,870 | [7] |
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 | 51,924,500 | [7] |
Average Fixed Price | 4.239 | [7] |
Fair Value Asset / (Liability) | 1,799 | [1] |
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 | [7] |
Fair Value Asset / (Liability) | 1,636 | [1] |
Average Floor and Cap | 4.234 | [7] |
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 | [7] |
Fair Value Asset / (Liability) | -721 | [1] |
Average Floor and Cap | 5.129 | [7] |
Production Period Ending December 31 2015 | Natural Gas Put Options - Drilling Partnership | Puts Purchased | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 1,440,000 | [7] |
Average Fixed Price | 4 | [7] |
Fair Value Asset / (Liability) | 447 | [1] |
Production Period Ending December 31 2015 | Natural Gas Liquids Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Average Fixed Price | 88.55 | [7] |
Fair Value Asset / (Liability) | -129 | [2] |
Derivatives Nonmonetary Volume Notional Amount Barrels | 96,000 | [7] |
Production Period Ending December 31 2015 | Natural Gas Liquids Propane Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Average Fixed Price | 1.016 | [7] |
Fair Value Asset / (Liability) | -149 | [4] |
Derivatives Nonmonetary Notional Amount Gallons | 8,064,000 | [7] |
Production Period Ending December 31 2015 | Natural Gas Liquids Butane Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Average Fixed Price | 1.248 | [7] |
Fair Value Asset / (Liability) | 28 | [5] |
Derivatives Nonmonetary Notional Amount Gallons | 1,512,000 | [7] |
Production Period Ending December 31 2015 | Natural Gas Liquids Iso Butane Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Average Fixed Price | 1.263 | [7] |
Fair Value Asset / (Liability) | 24 | [6] |
Derivatives Nonmonetary Notional Amount Gallons | 1,512,000 | [7] |
Production Period Ending December 31 2015 | Crude Oil Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Average Fixed Price | 88.144 | [7] |
Fair Value Asset / (Liability) | -969 | [2] |
Derivatives Nonmonetary Volume Notional Amount Barrels | 567,000 | [7] |
Production Period Ending December 31 2015 | Crude Oil Costless Collars | Puts Purchased | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset / (Liability) | 125 | [2] |
Average Floor and Cap | 83.846 | [7] |
Derivatives Nonmonetary Volume Notional Amount Barrels | 29,250 | [7] |
Production Period Ending December 31 2015 | Crude Oil Costless Collars | Calls Sold | ' | |
Derivatives Fair Value [Line Items] | ' | |
Fair Value Asset / (Liability) | -61 | [2] |
Average Floor and Cap | 110.654 | [7] |
Derivatives Nonmonetary Volume Notional Amount Barrels | 29,250 | [7] |
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 | 45,746,300 | [7] |
Average Fixed Price | 4.311 | [7] |
Fair Value Asset / (Liability) | 7,193 | [1] |
Production Period Ending December 31 2016 | Natural Gas Put Options - Drilling Partnership | Puts Purchased | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 1,440,000 | [7] |
Average Fixed Price | 4.15 | [7] |
Fair Value Asset / (Liability) | 613 | [1] |
Production Period Ending December 31 2016 | Natural Gas Liquids Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Average Fixed Price | 85.651 | [7] |
Fair Value Asset / (Liability) | 92 | [2] |
Derivatives Nonmonetary Volume Notional Amount Barrels | 84,000 | [7] |
Production Period Ending December 31 2016 | Crude Oil Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Average Fixed Price | 85.523 | [7] |
Fair Value Asset / (Liability) | 218 | [2] |
Derivatives Nonmonetary Volume Notional Amount Barrels | 225,000 | [7] |
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 | 24,840,000 | [7] |
Average Fixed Price | 4.532 | [7] |
Fair Value Asset / (Liability) | 6,734 | [1] |
Production Period Ending December 31 2017 | Natural Gas Liquids Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Average Fixed Price | 83.78 | [7] |
Fair Value Asset / (Liability) | 127 | [2] |
Derivatives Nonmonetary Volume Notional Amount Barrels | 60,000 | [7] |
Production Period Ending December 31 2017 | Crude Oil Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Average Fixed Price | 83.305 | [7] |
Fair Value Asset / (Liability) | 220 | [2] |
Derivatives Nonmonetary Volume Notional Amount Barrels | 132,000 | [7] |
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 | 3,960,000 | [7] |
Average Fixed Price | 4.716 | [7] |
Fair Value Asset / (Liability) | $1,306 | [1] |
[1] | Fair value based on forward NYMEX natural gas prices, as applicable. | |
[2] | Fair value based on forward WTI crude oil prices, as applicable. | |
[3] | Fair value based on forward Mt. Belvieu ethane 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] | “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 $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Derivatives Fair Value [Line Items] | ' | ' |
Long-term derivative asset | $28,325 | $30,868 |
Current portion of derivative liabilities | -36,929 | -17,630 |
Current portion of derivative asset | 161 | 2,066 |
Long-term portion of derivative liabilities | -13 | -387 |
Atlas Pipeline "APL" | Gross Amounts Of Recognized Assets | ' | ' |
Derivatives Fair Value [Line Items] | ' | ' |
Long-term derivative asset | 5,336 | 5,082 |
Current portion of derivative liabilities | 2,082 | 1,612 |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 7,418 | 8,953 |
Current portion of derivative asset | ' | 1,310 |
Long-term portion of derivative liabilities | ' | 949 |
Atlas Pipeline "APL" | Gross Amounts Offset In Consolidated Combined Balance Sheets Assets | ' | ' |
Derivatives Fair Value [Line Items] | ' | ' |
Long-term derivative asset | -2,127 | -2,812 |
Current portion of derivative liabilities | -2,082 | -1,612 |
Net Amount of Assets Presented in the Consolidated Balance Sheets | -4,209 | -6,509 |
Current portion of derivative asset | ' | -1,136 |
Long-term portion of derivative liabilities | ' | -949 |
Atlas Pipeline "APL" | Net Amount Of Assets Presented In Consolidated Combined Balance Sheets | ' | ' |
Derivatives Fair Value [Line Items] | ' | ' |
Long-term derivative asset | 3,209 | 2,270 |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 3,209 | 2,444 |
Current portion of derivative asset | ' | 174 |
Atlas Pipeline "APL" | Gross Amounts Of Recognized Liabilities | ' | ' |
Derivatives Fair Value [Line Items] | ' | ' |
Long-term derivative asset | -2,127 | -2,812 |
Current portion of derivative liabilities | -15,869 | -12,856 |
Current portion of derivative asset | ' | -1,136 |
Long-term portion of derivative liabilities | ' | -1,269 |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | -17,996 | -18,073 |
Atlas Pipeline "APL" | Gross Amounts Offset In Consolidated Combined Balance Sheets Liabilities | ' | ' |
Derivatives Fair Value [Line Items] | ' | ' |
Long-term derivative asset | 2,127 | 2,812 |
Current portion of derivative liabilities | 2,082 | 1,612 |
Current portion of derivative asset | ' | 1,136 |
Long-term portion of derivative liabilities | ' | 949 |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | 4,209 | 6,509 |
Atlas Pipeline "APL" | Net Amount of Liabilities Presented in Consolidated Combined Balance Sheets | ' | ' |
Derivatives Fair Value [Line Items] | ' | ' |
Current portion of derivative liabilities | -13,787 | -11,244 |
Long-term portion of derivative liabilities | ' | -320 |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | ($13,787) | ($11,564) |
Derivative_Instruments_APL_Com
Derivative Instruments (APL Commodity Derivative Instruments by Type Table) (Details) (Atlas Pipeline "APL", USD $) | Mar. 31, 2014 | |
In Thousands, unless otherwise specified | ||
APL Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Total Fixed Price Swaps | ($13,332) | [1] |
APL Options | ' | |
Derivatives Fair Value [Line Items] | ' | |
Total Options | 2,754 | [1],[2] |
Total APL net asset | -10,578 | [1],[2] |
Sold | Production Period Ending December 31 2014 | Natural Gas | APL Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 12,690,000 | [2] |
Derivative Instruments Not Designated As Hedges Average Fixed Price | 4.029 | |
Fair Value Asset / (Liability) | -5,555 | [1] |
Sold | Production Period Ending December 31 2014 | Natural Gas Liquids | APL Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount Gallons Of Natural Gas Liquids | 60,354,000 | [2] |
Derivative Instruments Not Designated As Hedges Average Fixed Price | 1.198 | |
Fair Value Asset / (Liability) | -5,123 | [1] |
Sold | Production Period Ending December 31 2014 | Natural Gas Liquids | APL Options | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount Gallons Of Natural Gas Liquids | 3,780,000 | [1] |
Fair Value Asset / (Liability) | -27 | [1],[2] |
Derivative Instruments Not Designated As Hedges Average Strike Price | 1.318 | |
Sold | Production Period Ending December 31 2014 | APL Crude Oil | APL Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount Barrels | 219,000 | [2] |
Derivative Instruments Not Designated As Hedges Average Fixed Price | 91.062 | |
Fair Value Asset / (Liability) | -1,672 | [1] |
Sold | Production Period Ending December 31 2015 | Natural Gas | APL Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 18,610,000 | [2] |
Derivative Instruments Not Designated As Hedges Average Fixed Price | 4.244 | |
Fair Value Asset / (Liability) | 592 | [1] |
Sold | Production Period Ending December 31 2015 | Natural Gas Liquids | APL Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount Gallons Of Natural Gas Liquids | 41,076,000 | [2] |
Derivative Instruments Not Designated As Hedges Average Fixed Price | 1.079 | |
Fair Value Asset / (Liability) | -1,993 | [1] |
Sold | Production Period Ending December 31 2015 | Natural Gas Liquids | APL Options | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount Gallons Of Natural Gas Liquids | 1,260,000 | [1] |
Fair Value Asset / (Liability) | -46 | [1],[2] |
Derivative Instruments Not Designated As Hedges Average Strike Price | 1.275 | |
Sold | Production Period Ending December 31 2015 | APL Crude Oil | APL Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount Barrels | 60,000 | [2] |
Derivative Instruments Not Designated As Hedges Average Fixed Price | 85.13 | |
Fair Value Asset / (Liability) | -298 | [1] |
Sold | Production Period Ending December 31 2016 | Natural Gas | APL Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 7,950,000 | [2] |
Derivative Instruments Not Designated As Hedges Average Fixed Price | 4.277 | |
Fair Value Asset / (Liability) | 779 | [1] |
Sold | Production Period Ending December 31 2016 | Natural Gas Liquids | APL Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount Gallons Of Natural Gas Liquids | 6,300,000 | [2] |
Derivative Instruments Not Designated As Hedges Average Fixed Price | 1.034 | |
Fair Value Asset / (Liability) | -85 | [1] |
Sold | Production Period Ending December 31 2017 | Natural Gas | APL Fixed Price Swaps | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 600,000 | [2] |
Derivative Instruments Not Designated As Hedges Average Fixed Price | 4.455 | |
Fair Value Asset / (Liability) | 23 | [1] |
Puts Purchased | Production Period Ending December 31 2014 | Natural Gas | APL Options | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 500,000 | [1] |
Fair Value Asset / (Liability) | 60 | [1],[2] |
Derivative Instruments Not Designated As Hedges Average Strike Price | 4.13 | |
Puts Purchased | Production Period Ending December 31 2014 | Natural Gas Liquids | APL Options | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount Gallons Of Natural Gas Liquids | 6,930,000 | [1] |
Fair Value Asset / (Liability) | 135 | [1],[2] |
Derivative Instruments Not Designated As Hedges Average Strike Price | 0.96 | |
Puts Purchased | Production Period Ending December 31 2014 | APL Crude Oil | APL Options | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount Barrels | 267,000 | [1] |
Fair Value Asset / (Liability) | 657 | [1],[2] |
Derivative Instruments Not Designated As Hedges Average Strike Price | 90.413 | |
Puts Purchased | Production Period Ending December 31 2015 | Natural Gas Liquids | APL Options | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount Gallons Of Natural Gas Liquids | 3,150,000 | [1] |
Fair Value Asset / (Liability) | 155 | [1],[2] |
Derivative Instruments Not Designated As Hedges Average Strike Price | 0.941 | |
Puts Purchased | Production Period Ending December 31 2015 | APL Crude Oil | APL Options | ' | |
Derivatives Fair Value [Line Items] | ' | |
Derivatives Nonmonetary Volume Notional Amount Barrels | 270,000 | [1] |
Fair Value Asset / (Liability) | $1,820 | [1],[2] |
Derivative Instruments Not Designated As Hedges Average Strike Price | 89.175 | |
[1] | See Note 10 for discussion on fair value methodology. | |
[2] | Volumes for natural gas are stated in MMBtu’s. Volumes for NGLs are stated in gallons. Volumes for crude oil are stated in barrels. |
Derivative_Instruments_APLs_Ga
Derivative Instruments (APL's Gain Loss Recognized in Gain Loss on Mark to Market Derivatives Table) (Details) (Atlas Pipeline "APL", Derivatives Not Designated As Hedges, USD $) | 3 Months Ended | |||
In Thousands, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | ||
Derivative Instruments Gain Loss [Line Items] | ' | ' | ||
Gain (loss) recognized in loss on mark-to-market derivatives | ($8,671) | ($12,083) | ||
Realized Gain Loss | Commodity Contract | ' | ' | ||
Derivative Instruments Gain Loss [Line Items] | ' | ' | ||
Gain (loss) recognized in loss on mark-to-market derivatives | -9,835 | [1] | 1,636 | [1] |
Unrealized Gain Loss | Commodity Contract | ' | ' | ||
Derivative Instruments Gain Loss [Line Items] | ' | ' | ||
Gain (loss) recognized in loss on mark-to-market derivatives | $1,164 | [2] | ($13,719) | [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 $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Derivatives Fair Value [Line Items] | ' | ' |
Current portion of derivative asset | $161 | $2,066 |
Long-term derivative asset | 28,325 | 30,868 |
Current portion of derivative liabilities | -36,929 | -17,630 |
Long-term portion of derivative liabilities | -13 | -387 |
Total Partnership net asset (liability) | ($8,456) | $14,917 |
Fair_Value_of_Financial_Instru3
Fair Value of Financial Instruments (Schedule of Assets/Liabilities at Fair Value) (Details) (Fair Value, Gross of Master Netting Arrangements, USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Gross Amounts of Recognized Assets | $39,301 | $48,860 |
Gross Amounts of Recognized Liabilities | -47,757 | -33,943 |
Total derivatives | -8,456 | 14,917 |
Commodity Swaps | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 1,367 | 1,634 |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | -770 | -152 |
Level 2 | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Gross Amounts of Recognized Assets | 37,609 | 47,238 |
Gross Amounts of Recognized Liabilities | -39,081 | -20,565 |
Total derivatives | -1,472 | 26,673 |
Level 2 | Commodity Swaps | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 1,367 | 1,634 |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | -770 | -152 |
Level 3 | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Gross Amounts of Recognized Assets | 1,692 | 1,622 |
Gross Amounts of Recognized Liabilities | -8,676 | -13,378 |
Total derivatives | -6,984 | -11,756 |
Atlas Resource Partners, L.P. | Commodity Swaps | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 26,771 | 33,594 |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | -27,556 | -14,624 |
Atlas Resource Partners, L.P. | ARP Commodity basis swaps. | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 159 | ' |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | -201 | ' |
Atlas Resource Partners, L.P. | Commodity Puts | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 1,144 | 1,374 |
Atlas Resource Partners, L.P. | Commodity Options | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 2,442 | 3,305 |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | -1,234 | -1,094 |
Atlas Resource Partners, L.P. | Level 2 | Commodity Swaps | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 26,771 | 33,594 |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | -27,556 | -14,624 |
Atlas Resource Partners, L.P. | Level 2 | ARP Commodity basis swaps. | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 159 | ' |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | -201 | ' |
Atlas Resource Partners, L.P. | Level 2 | Commodity Puts | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 1,144 | 1,374 |
Atlas Resource Partners, L.P. | Level 2 | Commodity Options | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 2,442 | 3,305 |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | -1,234 | -1,094 |
Atlas Pipeline "APL" | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Net Amount of Assets Presented in the Consolidated Balance Sheets | ' | 4,547 |
Atlas Pipeline "APL" | Commodity Swaps | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 4,591 | 4,406 |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | -17,923 | -18,073 |
Atlas Pipeline "APL" | Commodity Options | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 2,827 | ' |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | -73 | ' |
Atlas Pipeline "APL" | Level 2 | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Net Amount of Assets Presented in the Consolidated Balance Sheets | ' | 4,337 |
Atlas Pipeline "APL" | Level 2 | Commodity Swaps | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 3,189 | 2,994 |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | -9,320 | -4,695 |
Atlas Pipeline "APL" | Level 2 | Commodity Options | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 2,537 | ' |
Atlas Pipeline "APL" | Level 3 | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Net Amount of Assets Presented in the Consolidated Balance Sheets | ' | 210 |
Atlas Pipeline "APL" | Level 3 | Commodity Swaps | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 1,402 | 1,412 |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | -8,603 | -13,378 |
Atlas Pipeline "APL" | Level 3 | Commodity Options | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Net Amount of Assets Presented in the Consolidated Balance Sheets | 290 | ' |
Net Amount of Liabilities Presented in the Consolidated Balance Sheets | ($73) | ' |
Fair_Value_of_Financial_Instru4
Fair Value of Financial Instruments (Schedule of Level 3 Derivative Contract Fair Value) (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | |||||||||||||
In Thousands, unless otherwise specified | NGL Fixed Price Swaps | NGL Fixed Price Swaps | NGL Put Option | NGL Put Option | NGL Call Option | NGL Call Option | New Contracts | New Contracts | Cash Settlement From Unrealized Gain (loss) | Cash Settlement From Unrealized Gain (loss) | Cash Settlement From Unrealized Gain (loss) | Cash Settlement From Unrealized Gain (loss) | Net Change In Unrealized Loss | Net Change In Unrealized Loss | Net Change In Unrealized Loss | Net Change In Unrealized Loss | Option Premium | Option Premium | Option Premium | |||||||||||||||
gal | gal | gal | gal | gal | gal | NGL Put Option | NGL Call Option | NGL Fixed Price Swaps | NGL Put Option | NGL Call Option | NGL Fixed Price Swaps | NGL Put Option | NGL Call Option | NGL Put Option | NGL Call Option | |||||||||||||||||||
gal | gal | gal | gal | gal | ||||||||||||||||||||||||||||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Balance - Beginning (Volume) | ' | ' | 107,730,000 | 130,158,000 | 10,080,000 | 6,300,000 | 5,040,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
New contracts (Volume) | ' | ' | ' | ' | ' | ' | ' | ' | 5,040,000 | [1] | 5,040,000 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||
Cash settlements from unrealized gain (loss) (Volume) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -22,428,000 | [2],[3] | -1,260,000 | [2],[3] | ' | [2],[3] | ' | ' | ' | ' | ' | ' | ' | ||||||||||
Balance - Ending (Volume) | ' | ' | 107,730,000 | 130,158,000 | 10,080,000 | 6,300,000 | 5,040,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Balance - Beginning (Amount) | ($6,984) | ($11,756) | ($7,201) | ($11,966) | $290 | $210 | ($73) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
New contracts (Amount) | ' | ' | ' | ' | ' | ' | ' | ' | 200 | [1] | -200 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||
Cash settlements from unrealized gain (loss) (Amount) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6,010 | [2],[3] | 5,873 | [2],[3] | 137 | [2],[3] | ' | [2],[3] | ' | ' | ' | ' | ' | ' | ' | |||||||||
Net change in unrealized loss (Amount) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -1,101 | [2] | -1,108 | [2] | -120 | [2] | 127 | [2] | ' | ' | ' | |||||||||
Option premium recognition (Amount) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -137 | [3] | -137 | [3] | ' | [3] | ||||||||||
Balance - Ending (Amount) | ($6,984) | ($11,756) | ($7,201) | ($11,966) | $290 | $210 | ($73) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
[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 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_Instru5
Fair Value of Financial Instruments (Summary of Unobservable Inputs) (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 | ||
In Thousands, unless otherwise specified | gal | gal | ||
Propane Swaps | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' | ||
Gallons | 83,538,000 | 100,296,000 | ||
Third PartyQuotes | ($6,059) | [1] | ($10,260) | [1] |
NGL Fixed Price Swaps, Fair Value | -6,059 | -10,260 | ||
Iso butane Swaps | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' | ||
Gallons | 5,040,000 | 6,300,000 | ||
Third PartyQuotes | -1,405 | [1] | -2,342 | [1] |
Adjustments | 651 | [2] | 955 | [2] |
NGL Fixed Price Swaps, Fair Value | -754 | -1,387 | ||
Normal Butane Swaps | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' | ||
Gallons | 5,040,000 | 7,560,000 | ||
Third PartyQuotes | 483 | [1] | 40 | [1] |
Adjustments | 192 | [2] | 322 | [2] |
NGL Fixed Price Swaps, Fair Value | 675 | 362 | ||
Natural Gasoline Swaps | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' | ||
Gallons | 14,112,000 | 16,002,000 | ||
Third PartyQuotes | -276 | [1] | 132 | [1] |
Adjustments | -787 | [2] | -813 | [2] |
NGL Fixed Price Swaps, Fair Value | -1,063 | -681 | ||
Total NGL Swaps | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' | ||
Gallons | 107,730,000 | 130,158,000 | ||
Third PartyQuotes | -7,257 | [1] | -12,430 | [1] |
Adjustments | 56 | [2] | 464 | [2] |
NGL Fixed Price Swaps, Fair Value | ($7,201) | ($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. |
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 $) | Mar. 31, 2014 | Dec. 31, 2013 |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Prepaid expenses and other | $42,213,000 | $27,612,000 |
Product/Location Adjustment, Based Upon Multiple Regression Analysis, Reduction | 400,000 | 400,000 |
Iso butane Swaps | Level 3 Fair Value Adjustments | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Adjustments | 651,000 | 955,000 |
Iso butane Swaps | Lower 95% | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Adjustment based on Regression Coefficient | '$1.1168 | '1.1184 |
Iso butane Swaps | Upper 95% | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Adjustment based on Regression Coefficient | '$1.1271 | '1.1284 |
Iso butane Swaps | Average Coefficient | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Adjustment based on Regression Coefficient | '$1.1219 | '1.1234 |
Normal Butane Swaps | Level 3 Fair Value Adjustments | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Adjustments | 192,000 | 322,000 |
Normal Butane Swaps | Lower 95% | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Adjustment based on Regression Coefficient | '1.0341 | '1.0341 |
Normal Butane Swaps | Upper 95% | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Adjustment based on Regression Coefficient | '1.0382 | '1.0386 |
Normal Butane Swaps | Average Coefficient | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Adjustment based on Regression Coefficient | '1.0361 | '1.0364 |
Natural Gasoline Swaps | Level 3 Fair Value Adjustments | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Adjustments | -787,000 | -813,000 |
Natural Gasoline Swaps | Lower 95% | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Adjustment based on Regression Coefficient | '0.9685 | '0.9727 |
Natural Gasoline Swaps | Upper 95% | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Adjustment based on Regression Coefficient | '0.9716 | '0.9751 |
Natural Gasoline Swaps | Average Coefficient | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Adjustment based on Regression Coefficient | '0.9701 | '0.9739 |
Total NGL Swaps | Level 3 Fair Value Adjustments | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Adjustments | 56,000 | 464,000 |
NGL Linefill | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Prepaid expenses and other | $21,701,000 | $14,517,000 |
Recovered_Sheet2
Fair Value Of Financial Instruments (Summary Of Changes in NGL Linefill) (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | ||
In Thousands, unless otherwise specified | NGL Linefill | NGL Linefill | NGL Linefill | ||||
gal | Linefill Valued at Market | Linefill Valued on FIFO | |||||
gal | gal | ||||||
Beginning balance, Gallons | ' | ' | 17,326,000 | 5,788,000 | 11,538,000 | ||
Deliveries into NGL linefill | ' | ' | 26,650,000 | 1,050,000 | 25,600,000 | ||
NGL linefill sales | ' | ' | -20,622,000 | ' | -20,622,000 | ||
Ending balance, Gallons | ' | ' | 23,354,000 | 6,838,000 | 16,516,000 | ||
Beginning balance | $42,213 | $27,612 | $14,517 | $4,739 | $9,778 | ||
Deliveries into NGL linefill | ' | ' | 17,888 | 1,013 | 16,875 | ||
NGL linefill sales | ' | ' | -10,847 | ' | -10,847 | ||
Net change in NGL linefill valuation | ' | ' | 143 | [1] | 143 | [1] | ' |
Ending balance | $42,213 | $27,612 | $21,701 | $5,895 | $15,806 | ||
[1] | Included within gathering and processing revenues on the Partnership’s consolidated statements of operations. |
Fair_Value_of_Financial_Instru6
Fair Value of Financial Instruments (Other Financial Instruments Narrative) (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Disclosure Fair Value Of Financial Instruments Other Financial Instruments Narrative Details [Line Items] | ' | ' |
Long-term Debt, Fair Value | $2,875 | $2,841.70 |
Long-term debt carrying amount | $2,833.10 | $2,889 |
Fair_Value_of_Financial_Instru7
Fair Value of Financial Instruments (Schedule of Assets and Liabilities Measured on Non Recurring Basis) (Details) (USD $) | 3 Months Ended | 12 Months Ended | 3 Months Ended | 1 Months Ended | 3 Months Ended | 1 Months Ended | 12 Months Ended | |||||
Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | 7-May-13 | Feb. 29, 2012 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Jan. 31, 2013 | Dec. 31, 2013 | |
Level 3 | Level 3 | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | ||||
TEAK Acquisition | Gas Gathering System And Related Assets | Gas Gathering System And Related Assets | Gas Gathering System And Related Assets | Gas Gathering System And Related Assets | Gas Gathering System And Related Assets | Level 3 | ||||||
Accrued Liabilities | Maximum | Trigger Payments | TEAK Acquisition | |||||||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Asset Retirement Obligation, Fair Value Disclosure | $602,000 | $645,000 | ' | $602,000 | $645,000 | ' | ' | ' | ' | ' | ' | ' |
Assets Measured At Fair Value On A Nonrecurring Basis, Total | 602,000 | 645,000 | ' | 602,000 | 645,000 | ' | ' | ' | ' | ' | ' | ' |
Asset impairment | ' | ' | 38,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Business Acquisition, Purchase Price Allocation, Status | ' | ' | ' | ' | ' | '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 APL continues to evaluate the facts and circumstances that existed as of the acquisition date. | ' | ' | ' | ' | ' | 'During the year ended December 31, 2013, the Partnership completed the Arkoma Acquisition and ARP completed the EP Energy Acquisition. During the year ended December 31, 2013, APL completed the TEAK Acquisition. 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 estimates of fair value of the EP Energy and TEAK acquisitions as of their respective acquisition dates, which are reflected in the Partnership’s consolidated balance sheet as of March 31, 2014, are subject to change as the final valuations 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 7). These inputs require significant judgments and estimates by the Partnership’s and ARP’s management at the time of the valuation and are subject to change. |
Business Acquisition, Effective Date of Acquisition | ' | ' | ' | ' | ' | ' | ' | 1-Feb-12 | ' | ' | ' | ' |
Trigger Payments | ' | ' | ' | ' | ' | ' | 12,000,000 | ' | ' | ' | ' | ' |
Trigger Payments, Liabilities Recorded Upon Acquisition at Fair Value | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' |
Trigger Payments, Payments Made | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6,000,000 | ' |
Range Of Undiscounted Amounts Possible Related to Trigger Payments, Low End | ' | ' | ' | ' | ' | ' | ' | ' | ' | $6,000,000 | ' | ' |
Income_Taxes_Components_Of_Fed
Income Taxes (Components Of Federal And State Income Tax Expense (Benefit) of APL's Taxable Subsidiary Table) (Details) (USD $) | 3 Months Ended | |
Mar. 31, 2014 | Mar. 31, 2013 | |
Total income tax benefit | ($398,000) | ($9,000) |
Atlas Pipeline "APL" | ' | ' |
Federal | -357,000 | -8,000 |
State | -41,000 | -1,000 |
Total income tax benefit | ($398,000) | ($9,000) |
Income_Taxes_Narrative_Details
Income Taxes (Narrative) (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
Deferred income taxes, net | $32,892,000 | $33,290,000 |
Net operating loss carry forwards for federal income tax | 40,100,000 | ' |
Atlas Pipeline "APL" | ' | ' |
Deferred income taxes, net | $32,892,000 | $33,290,000 |
Income_Taxes_Components_Of_APL
Income Taxes (Components Of APL's Net Deferred Tax Liabilities Table) (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Net deferred tax liabilities | ($32,892) | ($33,290) |
Atlas Pipeline "APL" | ' | ' |
Net operating loss tax carryforwards and alternative minimum tax credits | 15,499 | 14,900 |
Deferred Tax Liabilities - Excess of asset carrying value over tax basis | -48,391 | -48,190 |
Net deferred tax liabilities | ($32,892) | ($33,290) |
Recovered_Sheet3
Certain Relationships And Related Party Transactions (Narrative) (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
ARP Relationship With Drilling Partners | ' | ' |
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 Partnership’s revenue and costs and expenses according to the respective partnership agreements. | ' |
ARP 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 three month periods ended March 31, 2014 and 2013, $0.1 million and $0.1 million, respectively, of gathering fees paid by ARP to APL were eliminated in consolidation. | ' |
Gathering Fees Paid, Eliminated In Consolidation | ARP Relationship With APL | ' | ' |
Related Party Transaction [Line Items] | ' | ' |
Related Party Transaction, Amounts of Transaction | $0.10 | $0.10 |
Issuance of Term Facility With CVC Credit Partners, LLC | Relationship With Resource America, Inc | ' | ' |
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_
Commitments and Contingencies (General Commitments) (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Minimum | ' | ' |
Partnership obligations to purchase units from investor partners | 5.00% | ' |
Percent of net partnership revenues subordinated | 10.00% | ' |
Maximum | ' | ' |
Partnership obligations to purchase units from investor partners | 10.00% | ' |
Atlas Resource Partners, L.P. | ' | ' |
Net partnership revenues subordinated | $3.50 | $2.10 |
Contractual Obligation, Due in Next Twelve Months | 6.6 | ' |
Contractual Obligation, Due in Second Year | 8.6 | ' |
Contractual Obligation, Due in Third Year | 2.1 | ' |
Contractual Obligation, Due in Fourth Year | 0 | ' |
Contractual Obligation, Due in Fifth Year | 0 | ' |
Atlas Pipeline "APL" | ' | ' |
Contractual Obligation, Due in Next Twelve Months | 6.3 | ' |
Contractual Obligation, Due in Second Year | 3.5 | ' |
Contractual Obligation, Due in Third Year | 3.5 | ' |
Contractual Obligation, Due in Fourth Year | 3.5 | ' |
Contractual Obligation, Due in Fifth Year | 2.7 | ' |
Transportation Contracts, Fees | 7.3 | 3 |
ARP and APL Combined | ' | ' |
Commitment to expend | $84.50 | ' |
Issuances_of_Units_EP_Energy_A
Issuances of Units (EP Energy Acquisition And Equity Distribution Program) (Details) (Atlas Resource Partners, L.P., USD $) | 1 Months Ended | 3 Months Ended | 12 Months Ended | 1 Months Ended | 3 Months Ended | 12 Months Ended | 1 Months Ended | 3 Months Ended | 1 Months Ended | 3 Months Ended | 1 Months Ended | ||
Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Jul. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Jul. 31, 2013 | Jun. 30, 2013 | Mar. 31, 2014 | Jul. 31, 2013 | Mar. 31, 2014 | Jun. 30, 2013 | |
Class C Convertible Preferred Units | Over Allotment Units Issued | Equity Distribution Program With Deutsche Bank Securities Inc. | Equity Distribution Program With Deutsche Bank Securities Inc. | Ep Energy | Ep Energy | Ep Energy | Ep Energy | Ep Energy | Ep Energy | ||||
Class C Convertible Preferred Units | Class C Convertible Preferred Units | Over Allotment Units Issued | |||||||||||
Capital Unit [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Partners' Capital Account, Units, Sold in Private Placement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,746,986 | ' | ' |
Negotiated Purchase Price Per Unit | $21.18 | $21.18 | ' | ' | ' | ' | ' | ' | $21.75 | ' | $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 | ' |
Partners' Capital Account, Units, Sale of units | 6,325,000 | ' | ' | ' | 825,000 | ' | 309,174 | 14,950,000 | 14,950,000 | ' | ' | ' | 1,950,000 |
Partners Capital Account Sale Of Units | 129,000,000 | ' | ' | ' | ' | ' | ' | ' | 313,100,000 | ' | ' | ' | ' |
Exchange Offer Registration Statement Agreement Description | ' | ' | ' | '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. | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Partners Capital Account Units Date Of Sale | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1-Jun-13 | ' | ' | ' |
Business Acquisition, Effective Date of Acquisition | ' | ' | ' | ' | ' | ' | ' | 1-May-13 | ' | ' | ' | ' | ' |
Aggregate Offering Price Of Common Units (Maximum) | ' | ' | ' | ' | ' | 25,000,000 | ' | ' | ' | ' | ' | ' | ' |
Payments for Commissions | ' | ' | ' | ' | ' | ' | 400,000 | ' | ' | ' | ' | ' | ' |
Proceeds from Issuance of Common Limited Partners Units | ' | ' | ' | ' | ' | ' | 6,900,000 | ' | ' | ' | ' | ' | ' |
Gain on sale of subsidiary unit issuances | ' | $14,600,000 | $27,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Issuances_of_Units_Atlas_Pipel
Issuances of Units (Atlas Pipeline Partners) (Details) (USD $) | 1 Months Ended | 3 Months Ended | 1 Months Ended | 3 Months Ended | 1 Months Ended | 3 Months Ended | 12 Months Ended | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||||
Apr. 17, 2013 | Apr. 17, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | 7-May-13 | Mar. 31, 2014 | Mar. 31, 2014 | 7-May-13 | Mar. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | |
Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | |
TEAK Acquisition | TEAK Acquisition | Class E Preferred Units | Class E Preferred Units | Class D Preferred Units | Class D Preferred Units | Class D Preferred Units | Class D Preferred Units | Citigroup Equity Distribution Program | Citigroup Equity Distribution Program | Citigroup Equity Distribution Program | Class E Preferred Units | ||||
Common Units To Maintain General Partner Interest | TEAK Acquisition | TEAK Acquisition | TEAK Acquisition | TEAK Acquisition | Common Units To Maintain General Partner Interest | ||||||||||
Net Unaccreted Beneficial Conversion Discount | Common Units To Maintain General Partner Interest | ||||||||||||||
Capital Unit [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Partners' Capital Account, Units, Sale of units | 11,845,000 | ' | 5,060,000 | ' | ' | ' | ' | ' | ' | 3,895,679 | ' | 6,325,000 | ' | ' | ' |
Proceeds from Issuance cost | ' | ' | $122,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Negotiated Purchase Price Per Unit | $34 | ' | $25 | $25 | ' | ' | ' | ' | ' | ' | ' | $21.18 | $21.18 | ' | ' |
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 there after | ' | ' | ' | $0.52 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Percentage of Preferred Unit Regular Quarterly Cash Distributions | ' | ' | ' | 8.25% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Redemption price per unit | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $25 |
Partners Capital Account Units Date Of Sale | ' | ' | ' | ' | ' | 1-May-13 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Embedded beneficial conversion discount | ' | ' | ' | ' | ' | ' | 50,200,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Accretion of the beneficial conversion discount | ' | ' | ' | ' | ' | 11,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Preferred stock distribution related to income statement | ' | ' | ' | ' | ' | 9,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Limited Partner, Unit Distribution | ' | ' | ' | ' | ' | 274,785 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Proceeds from Issuance of Common Limited Partners Units | 388,400,000 | 8,300,000 | ' | ' | ' | ' | ' | ' | ' | 137,800,000 | 2,800,000 | ' | ' | ' | ' |
General partner ownership interest | 2.00% | ' | ' | ' | 2.00% | ' | ' | ' | ' | 2.00% | ' | ' | ' | ' | ' |
Equity distribution agreement, value of common units | ' | ' | ' | ' | ' | ' | ' | ' | 150,000,000 | ' | ' | ' | ' | ' | ' |
Payments for Commissions | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,900,000 | ' | ' | ' | ' | ' |
Proceeds from Issuance of Preferred Limited Partners Units | ' | 8,300,000 | ' | ' | 397,700,000 | ' | ' | 8,200,000 | ' | ' | ' | ' | ' | ' | ' |
Gain on sale of subsidiary unit issuances | ' | ' | ' | ' | ' | ' | ' | ' | ' | $11,900,000 | ' | ' | $14,600,000 | $27,300,000 | ' |
Cash_Distributions_Schedule_of
Cash Distributions (Schedule of Distributions Declared by Partnership) (Details) (USD $) | 3 Months Ended | 1 Months Ended | 3 Months Ended | 1 Months Ended | 3 Months Ended | 1 Months Ended | 3 Months Ended | 1 Months Ended | 3 Months Ended | ||||||||||||||||||||||||||||||||||||
Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Mar. 31, 2014 | Apr. 30, 2014 | Apr. 23, 2014 | Mar. 31, 2014 | Apr. 30, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Feb. 28, 2014 | Jan. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Feb. 28, 2014 | Jan. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Feb. 28, 2014 | Jan. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Feb. 28, 2014 | Jan. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Apr. 30, 2014 | Mar. 31, 2014 | Apr. 30, 2014 | Apr. 23, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | |
ATLS | ATLS | ATLS | ATLS | ATLS | ATLS | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | ||||||
Dividend Declared | Dividend Declared | Dividend Declared | Dividend Paid | Dividend Paid | Limited Partner Interest | Limited Partner Interest | Limited Partner Interest | Limited Partner Interest | Limited Partner Interest | Limited Partner Interest | Preferred Limited Partner | Preferred Limited Partner | Preferred Limited Partner | Preferred Limited Partner | Preferred Limited Partner | Preferred Limited Partner | General Partner Interest | General Partner Interest | General Partner Interest | General Partner Interest | General Partner Interest | General Partner Interest | Minimum | Maximum | Dividend Declared | Dividend Declared | Dividend Paid | Dividend Paid | Dividend Paid | Dividend Paid | Dividend Paid | ||||||||||||||
Subsequent Event | Subsequent Event | Subsequent Event | Subsequent Event | Subsequent Event | Subsequent Event | Subsequent Event | Subsequent Event | Subsequent Event | Subsequent Event | Subsequent Event | Subsequent Event | ||||||||||||||||||||||||||||||||||
Preferred Limited Partner | General Partner Interest | ||||||||||||||||||||||||||||||||||||||||||||
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. | ' | ' | ' | ' | ' | 'ARP has a cash distribution policy under which it distributes, within 45 days following the end of each calendar quarter, all of its available cash (as defined in the partnership agreement) for that quarter to its common unitholders and general partner. In January 2014, ARP’s board of directors approved the modification of its cash distribution payment practice to a monthly cash distribution program beginning for the month of January 2014, whereby the monthly cash distribution will be paid within 45 days from the month end. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Distribution Date | 13-Mar-12 | 19-Feb-14 | 19-Nov-13 | 19-Aug-13 | 20-May-13 | ' | ' | ' | ' | 20-May-14 | 20-May-14 | ' | 14-Apr-14 | 17-Mar-14 | 14-Feb-14 | 14-Nov-13 | 14-Aug-13 | 15-May-13 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15-May-14 | 15-May-14 | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | ' | $0.46 | $0.46 | $0.44 | $0.31 | ' | $0.46 | $0.46 | ' | ' | ' | ' | $0.19 | $0.19 | $0.58 | $0.56 | $0.54 | $0.51 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $0.19 | ' | ' | ' |
Distribution Made to Member or Limited Partner, Cash Distributions Paid | ' | $23,681,000 | $23,649,000 | $22,611,000 | $15,928,000 | ' | ' | ' | ' | $23,900,000 | $23,900,000 | ' | ' | ' | ' | ' | ' | ' | $12,719,000 | $12,718,000 | $34,489,000 | $33,291,000 | $32,097,000 | $22,428,000 | $1,466,000 | $1,467,000 | $4,400,000 | $4,248,000 | $2,072,000 | $1,957,000 | $1,055,000 | $1,055,000 | $2,891,000 | $2,443,000 | $1,884,000 | $946,000 | ' | ' | ' | ' | ' | ' | ' | $1,500,000 | $1,100,000 |
Distribution Made to Member or Limited Partner, Declaration Date | ' | ' | ' | ' | ' | ' | 23-Apr-14 | ' | 23-Apr-14 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 23-Apr-14 | 23-Apr-14 | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Date of Record | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7-May-14 | 7-May-14 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7-May-14 | ' | 7-May-14 | ' | ' |
Percentage Of Distributions In Excess Of Targets | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13.00% | 48.00% | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Cash Distributions Paid | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $15,300,000 | ' | $15,300,000 | ' | ' |
Cash_Distributions_Schedule_of1
Cash Distributions (Schedule of Common Unit and General Partner Distributions) (Details) (USD $) | 1 Months Ended | 3 Months Ended | 1 Months Ended | 3 Months Ended | 1 Months Ended | 3 Months Ended | ||||||||||||||||||||||
In Thousands, except Share data, unless otherwise specified | Feb. 29, 2012 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Mar. 31, 2014 | Apr. 30, 2014 | Mar. 31, 2014 | Apr. 30, 2014 | Apr. 22, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 |
Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | APL Cash Distributions | APL Cash Distributions | |||||||
Subsequent Event | Dividend Paid | Dividend Paid | Dividend Declared | Dividend Declared | Dividend Declared | Limited Partner Interest | Limited Partner Interest | Limited Partner Interest | Limited Partner Interest | General Partner Interest | General Partner Interest | General Partner Interest | General Partner Interest | General Partner Interest | Minimum | Maximum | ||||||||||||
Class D Preferred Units | Subsequent Event | Subsequent Event | Subsequent Event | Subsequent Event | Subsequent Event | Dividend Paid | ||||||||||||||||||||||
Subsequent Event | ||||||||||||||||||||||||||||
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. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Percentage Of Distributions In Excess Of Targets | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13.00% | 48.00% |
Distribution Made to Member or Limited Partner, Distribution Date | ' | 13-Mar-12 | 19-Feb-14 | 19-Nov-13 | 19-Aug-13 | 20-May-13 | ' | 14-Feb-14 | 14-Nov-13 | 14-Aug-13 | 15-May-13 | ' | 15-May-14 | 15-May-14 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | ' | ' | $0.46 | $0.46 | $0.44 | $0.31 | ' | $0.62 | $0.62 | $0.62 | $0.59 | ' | ' | ' | ' | $0.62 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Cash Distributions Paid | ' | ' | $23,681 | $23,649 | $22,611 | $15,928 | ' | ' | ' | ' | ' | ' | ' | $56,100 | ' | ' | ' | $49,969 | $49,298 | $48,165 | $45,382 | $6,095 | $6,013 | $5,875 | $3,980 | $6,100 | ' | ' |
Distribution Made to Member or Limited Partner, Declaration Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 22-Apr-14 | ' | 22-Apr-14 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Date of Record | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8-May-14 | 8-May-14 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Share Distribution | 5,240,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 317,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Benefit_Plans_2010_Long_Term_I
Benefit Plans (2010 Long Term Incentive Plan Narrative) (Details) (Partnership 2010 Long Term Incentive Plan) | 3 Months Ended |
Mar. 31, 2014 | |
Partnership 2010 Long Term Incentive Plan | ' |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' |
Deferred Compensation Arrangements, Overall, Description | 'The Board of Directors of the General Partner 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 And Unit Options Outstanding | 4,454,130 |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 1,217,255 |
Benefit_Plans_2010_LTIP_Phanto
Benefit Plans (2010 LTIP Phantom Unit Activity) (Details) (USD $) | 3 Months Ended | |||
Mar. 31, 2014 | Mar. 31, 2013 | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | ' | ||
Granted (Units) | 2,398,000 | 2,216,000 | ||
Vested and issued (Units) | -15,500 | [1] | -2,465 | [1] |
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested But Not Yet Been Issued In Period Intrinsic Value | $500,000 | $0 | ||
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 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, Award Vesting Rights, Percentage | 25.00% | ' | ||
Share Based Compensation Arrangement By Share Based Payment Award Number Of Outstanding Units To Vest Within Next Twelve Months | 1,243,877 | ' | ||
Distribution equivalent rights paid on unissued units under incentive plans | 900,000 | 600,000 | ||
Outstanding, beginning of period (Units) | 2,054,534 | 2,044,227 | ||
Granted (Units) | ' | ' | ||
Vested and issued (Units) | -38,335 | [2] | -2,936 | [2] |
Forfeited (Units) | -11,768 | ' | ||
Outstanding, end of period (Units) | 2,004,431 | [3] | 2,041,291 | [3] |
Vested and not yet issued (Units) | 344,553 | [4] | ' | |
Outstanding, beginning of period | $22.56 | $20.88 | ||
Granted | ' | ' | ||
Vested and issued | $20.29 | $17.47 | ||
Forfeited | $27.25 | ' | ||
Outstanding, end of period | $22.57 | $20.88 | ||
Vested and not yet issued | $20.60 | ' | ||
Non-cash compensation expense recognized (in thousands) | 2,928,000 | 3,108,000 | ||
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested In Period Intrinsic Value | 1,700,000 | 100,000 | ||
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested But Not Yet Been Issued In Period Intrinsic Value | 15,000,000 | 0 | ||
Unrecognized compensation expense related to unvested phantom units | $13,300,000 | ' | ||
Partnership 2010 Phantom Units | Employees | 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 | ' | ||
Partnership 2010 Phantom Units | Employees | 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 | ' | ||
Partnership 2010 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 Vesting Period | '4 years | ' | ||
[1] | The intrinsic value of phantom unit awards vested and issued during the three months ended March 31, 2014 and 2013 was $0.3 million and $0.1 million, respectively. | |||
[2] | The aggregate intrinsic values of phantom unit awards vested and issued were $1.7 million and $0.1 million, respectively, for the three months ended March 31, 2014 and 2013, respectively. | |||
[3] | The aggregate intrinsic value of phantom unit awards outstanding at March 31, 2014 was $86.3 million. | |||
[4] | The intrinsic value of phantom unit awards vested, but not yet issued at March 31, 2014 was $15.0 million. No phantom unit awards had vested, but had not yet been issued at March 31, 2013. |
Benefit_Plans_2010_Unit_Option
Benefit Plans (2010 Unit Option Activity) (Details) (Partnership 2010 Unit Options, USD $) | 3 Months Ended | |||
Mar. 31, 2014 | Mar. 31, 2013 | |||
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 Unit Options To Vest Within Next Twelve Months | 1,723,698 | ' | ||
Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options | $0 | $0 | ||
Outstanding, beginning of period (Units) | 2,452,412 | 2,504,703 | ||
Granted (Units) | ' | ' | ||
Exercised (Units) | ' | [1] | ' | [1] |
Forfeited (Units) | -2,713 | -2,604 | ||
Outstanding, end of period (Units) | 2,449,699 | [2],[3] | 2,502,099 | [2],[3] |
Options exercisable, end of period (Units) | 569,368 | [4] | 3,398 | [4] |
Outstanding, beginning of period | $20.52 | $20.51 | ||
Granted | ' | ' | ||
Exercised | ' | [5] | ' | [5] |
Forfeited | $17.47 | $17.47 | ||
Outstanding, end of period | $20.52 | [6],[7] | $20.52 | [6],[7] |
Options exercisable, end of period | $20.43 | [4] | $20.85 | [4] |
Non-cash compensation expense recognized (in thousands) | 1,438,000 | 1,515,000 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Term | '7 years | ' | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value | 55,200,000 | ' | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term | '7 years | '8 years 4 months 24 days | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value | 12,900,000 | 100,000 | ||
Unrecognized compensation expense related to unvested unit options | $4,200,000 | ' | ||
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. | ' | ||
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] | No options were exercised during the three months ended March 31, 2014 and 2013. | |||
[2] | The weighted average remaining contractual life for outstanding options at March 31, 2014 was 7.0 years. | |||
[3] | The options outstanding at March 31, 2014 had an aggregate intrinsic value of $55.2 million | |||
[4] | The weighted average remaining contractual lives for exercisable options at March 31, 2014 and 2013 were 7.0 years and 8.4 years, respectively. The intrinsic values of exercisable options at March 31, 2014 and 2013 were $12.9 million and $0.1 million, respectively. | |||
[5] | No | |||
[6] | The weighted average remaining contractual life for outstanding options at March 31, 2014 was 7.0 years | |||
[7] | The options outstanding at March 31, 2014 had an aggregate intrinsic value of $55.2 million. |
Benefit_Plans_2006_Long_Term_I
Benefit Plans (2006 Long Term Incentive Plan Narrative) (Details) (Partnership 2006 Long Term Incentive Plan) | 3 Months Ended |
Mar. 31, 2014 | |
Partnership 2006 Long Term Incentive Plan | ' |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' |
Deferred Compensation Arrangements, Overall, 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 And Unit Options Outstanding | 1,534,966 |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 339,639 |
Benefit_Plans_2006_LTIP_Phanto
Benefit Plans (2006 LTIP Phantom Unit Activity) (Details) (USD $) | 3 Months Ended | ||||
Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | ' | ' | ||
Granted (Units) | 2,398,000 | 2,216,000 | ' | ||
Vested and issued (Units) | -15,500 | [1] | -2,465 | [1] | ' |
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested But Not Yet Been Issued In Period Intrinsic Value | $500,000 | $0 | ' | ||
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, Award Vesting Rights, Percentage | 25.00% | ' | ' | ||
Share Based Compensation Arrangement By Share Based Payment Award Number Of Outstanding Units To Vest Within Next Twelve Months | 264,859 | ' | ' | ||
Distribution equivalent rights paid on unissued units under incentive plans | 100,000 | 100,000 | ' | ||
Outstanding, beginning of period (Units) | 234,940 | 50,759 | ' | ||
Granted (Units) | 423,837 | 204,777 | ' | ||
Vested and issued (Units) | -63,750 | [2],[3] | -5,500 | [2],[3] | ' |
Forfeited (Units) | ' | ' | ' | ||
Outstanding, end of period (Units) | 595,027 | [4],[5] | 250,036 | [4],[5] | ' |
Vested and not yet issued (Units) | 11,497 | [6] | ' | ' | |
Outstanding, beginning of period | $35.82 | $21.02 | ' | ||
Granted | $43.23 | $37.92 | ' | ||
Vested and issued | $35.33 | [2],[3] | $18.16 | [2],[3] | ' |
Forfeited | ' | ' | ' | ||
Outstanding, end of period | $41.15 | [4],[5] | $34.92 | [4],[5] | ' |
Vested and not yet issued(5) | $37.68 | [6] | ' | ' | |
Non-cash compensation expense recognized (in thousands) | 2,988,000 | 1,147,000 | ' | ||
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested In Period Intrinsic Value | 3,000,000 | 200,000 | ' | ||
Share Based Compensation Arrangement By Share Based Payment Award Other Than Options Outstanding Intrinsic Value | 25,600,000 | ' | ' | ||
Deferred Compensation Share-based Arrangements, Liability, Current And Noncurrent | 700,000 | ' | 1,100,000 | ||
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Nonvested Number Classified As Liabilities | 41,067 | ' | 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 | $36.53 | ' | $29.67 | ||
Unrecognized compensation expense related to unvested phantom units | 19,400,000 | ' | ' | ||
Partnership 2006 Phantom Units | Vested Units Settled In Cash | ' | ' | ' | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | ' | ' | ||
Vested and issued (Units) | 3,884 | 522 | ' | ||
Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options | $185,000 | $20,000 | ' | ||
Partnership 2006 Phantom Units | Employees | 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 | ' | ' | ||
Partnership 2006 Phantom Units | Employees | 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 | ' | ' | ||
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 Vesting Period | '4 years | ' | ' | ||
[1] | The intrinsic value of phantom unit awards vested and issued during the three months ended March 31, 2014 and 2013 was $0.3 million and $0.1 million, respectively. | ||||
[2] | The intrinsic value for phantom unit awards vested and issued during the three months ended March 31, 2014 and 2013 were $3.0 million and $0.2 million, respectively. | ||||
[3] | There were 3,884 and 522 vested units during the three months ended March 31, 2014 and 2013, respectively, that settled for cash consideration of approximately $185,000 and approximately $20,000, respectively | ||||
[4] | The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2014 was $25.6 million. | ||||
[5] | There was $0.7 million and $1.1 million recognized as liabilities on the Partnership’s consolidated balance sheets at March 31, 2014 and December 31, 2013, respectively, representing 41,067 and 41,525 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 are $36.53 and $29.67 as of March 31, 2014 and December 31, 2013, respectively. | ||||
[6] | The intrinsic value of phantom unit awards vested, but not yet issued at March 31, 2014 was $0.5 million. No phantom units were vested, but not yet issued at March 31, 2013 |
Benefit_Plans_2006_Unit_Option
Benefit Plans (2006 Unit Option Activity) (Details) (Partnership 2006 Unit Options, USD $) | 3 Months Ended | |||
Mar. 31, 2014 | Mar. 31, 2013 | |||
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 Unit Options To Vest Within Next Twelve Months | 2,500 | ' | ||
Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options | $0 | $0 | ||
Outstanding, beginning of period (Units) | 939,939 | 929,939 | ||
Granted (Units) | ' | 10,000 | ||
Exercised (Units) | ' | [1] | ' | [1] |
Forfeited (Units) | ' | ' | ||
Outstanding, end of period (Units) | 939,939 | [2],[3] | 939,939 | [2],[3] |
Options exercisable, end of period (Units) | 932,439 | [4],[5] | 929,939 | [4],[5] |
Outstanding, beginning of period | $20.94 | $20.75 | ||
Granted | ' | $38.51 | ||
Exercised | ' | [1] | ' | [1] |
Forfeited | ' | ' | ||
Outstanding, end of period | $20.94 | [2],[3] | $20.94 | [2],[3] |
Options exercisable, end of period | $20.80 | [4],[5] | $20.75 | [4],[5] |
Non-cash compensation expense recognized (in thousands) | 7,000 | 7,000 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value | 0 | 0 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Term | '2 years 8 months 12 days | ' | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value | 20,800,000 | ' | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term | '2 years 8 months 12 days | '3 years 7 months 6 days | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value | 20,700,000 | 21,700,000 | ||
Unrecognized compensation expense related to unvested unit options | $33,000 | ' | ||
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 | ||
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] | No options were exercised during the three months ended March 31, 2014 and 2013. | |||
[2] | The weighted average remaining contractual life for outstanding options at March 31, 2014 was 2.7 years. | |||
[3] | The aggregate intrinsic value of options outstanding at March 31, 2014 was approximately $20.8 million. | |||
[4] | The weighted average remaining contractual lives for exercisable options at March 31, 2014 and 2013 were 2.6 years and 3.6 years, respectively. | |||
[5] | The aggregate intrinsic values of options exercisable at March 31, 2014 and 2013 were $20.7 million and $21.7 million, respectively. |
Benefit_Plans_ARP_Long_Term_In
Benefit Plans (ARP Long Term Incentive Plan Narrative) (Details) (ARP Long Term Incentive Plan) | 3 Months Ended |
Mar. 31, 2014 | |
ARP Long Term Incentive Plan | ' |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' |
Deferred Compensation Arrangements, Overall, Description | 'ARP has a 2012 Long-Term Incentive Plan effective March 2012 (the “ARP LTIPâ€). Awards of options to purchase units, restricted units and phantom units may be granted to officers, employees and directors of ARP’s general partner under the ARP LTIP, and such awards may be subject to vesting terms and conditions in the discretion of the administrator of the ARP LTIP. |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 29,000,000 |
Phantom Units, Restricted Units and Unit Options Outstanding | 2,284,983 |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 372,711 |
Benefit_Plans_ARP_Phantom_Unit
Benefit Plans (ARP Phantom Unit Activity) (Details) (USD $) | 3 Months Ended | ||||
Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | ' | ' | ||
Phantom units not attributable to net loss | 2,398,000 | 2,216,000 | ' | ||
Vested and issued (Units) | -15,500 | [1] | -2,465 | [1] | ' |
Vested and not yet issued | 6,875 | [2] | ' | ' | |
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested But Not Yet Been Issued In Period Intrinsic Value | $500,000 | $0 | ' | ||
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 | 275,545 | ' | ' | ||
Distribution equivalent rights paid on unissued units under incentive plans | 600,000 | 500,000 | ' | ||
Outstanding, beginning of period (Units) | 839,808 | 948,476 | ' | ||
Phantom units not attributable to net loss | 3,500 | 83,250 | ' | ||
Forfeited (Units) | -15,500 | -4,000 | ' | ||
Outstanding, end of period (Units) | 812,308 | [3],[4] | 1,025,261 | [3],[4] | ' |
Outstanding, beginning of period | $24.31 | $24.76 | ' | ||
Granted | $20.99 | $21.96 | ' | ||
Vested and issued | $22.69 | [5] | $24.67 | [5] | ' |
Forfeited | $22.63 | $25.14 | ' | ||
Outstanding, end of period | $24.35 | [3],[4] | $24.53 | [3],[4] | ' |
Vested and not yet issued(5) | $22.76 | [2] | ' | ' | |
Non-cash compensation expense recognized (in thousands) | 1,731,000 | 3,053,000 | ' | ||
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested But Not Yet Been Issued In Period Intrinsic Value | 100,000 | 0 | ' | ||
Share Based Compensation Arrangement By Share Based Payment Award Other Than Options Outstanding Intrinsic Value | 17,000,000 | ' | ' | ||
Deferred Compensation Share-based Arrangements, Liability, Current And Noncurrent | 100,000 | 44,000 | 100,000 | ||
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Nonvested Number Classified As Liabilities | 16,084 | 3,476 | 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 | $22.15 | $28.75 | $22.15 | ||
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested In Period Intrinsic Value | 300,000 | 100,000 | ' | ||
Unrecognized compensation expense related to unvested phantom units | $6,900,000 | ' | ' | ||
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 Other Than Options Vesting Period Percentage | 25.00% | ' | ' | ||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period | '4 years | ' | ' | ||
[1] | The intrinsic value of phantom unit awards vested and issued during the three months ended March 31, 2014 and 2013 was $0.3 million and $0.1 million, respectively. | ||||
[2] | The intrinsic value of phantom unit awards vested, but not yet issued at March 31, 2014 was $0.1 million. No phantom unit awards had vested, but had not yet been issued at March 31, 2013. | ||||
[3] | The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2014 was $17.0 million. | ||||
[4] | There was $0.1 million recognized as liabilities on the Partnership’s consolidated balance sheets at the periods ended March 31, 2014 and December 31, 2013, representing 16,084 units for the periods ending March 31, 2014 and December 31, 2013 due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair value for these units was $22.15 for the periods ending March 31, 2014 and December 31, 2013, respectively. There was approximately $44,000 recognized as liabilities on the Partnership’s consolidated balance sheet at March 31, 2013, representing 3,476 units, due to the option of the participants to settle in cash instead of units. The weighted average grant date fair value for these units was $28.75 at March 31, 2013. | ||||
[5] | The intrinsic value of phantom unit awards vested and issued during the three months ended March 31, 2014 and 2013 was $0.3 million and $0.1 million, respectively |
Benefit_Plans_ARP_Unit_Option_
Benefit Plans (ARP Unit Option Activity) (Details) (ARP Unit Options, USD $) | 3 Months Ended | |||
Mar. 31, 2014 | Mar. 31, 2013 | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | ' | ||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights | 'ARP Unit Options. The exercise price of the unit option may be equal to or more than the fair market value of ARP’s common unit on the date of grant of the option. | ' | ||
Years From Date Of Grant Unit Option Awards Expire | '10 years | ' | ||
Share Based Compensation Arrangement By Share Based Payment Award Number Of Outstanding Unit Options To Vest Within Next Twelve Months | 367,575 | ' | ||
Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options | $0 | $0 | ||
Outstanding, beginning of period (Units) | 1,482,675 | 1,515,500 | ||
Granted (Units) | ' | 2,000 | ||
Exercised (Units) | ' | [1] | ' | [1] |
Forfeited (Units) | -10,000 | -4,000 | ||
Outstanding, end of period (Units) | 1,472,675 | [2],[3] | 1,513,500 | [2],[3] |
Options exercisable, end of period (Units) | 368,825 | [4] | ' | |
Outstanding, beginning of period | $24.66 | $24.68 | ||
Granted | ' | $22.27 | ||
Exercised | ' | [1] | ' | [1] |
Forfeited | $23.40 | $25.14 | ||
Outstanding, end of period | $24.66 | [2],[3] | $24.67 | [2],[3] |
Options exercisable, end of period | $24.67 | [4] | ' | |
Non-cash compensation expense recognized (in thousands) | 612,000 | 1,194,000 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Term | '8 years 1 month 6 days | ' | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value | 2,000,000,000 | ' | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value | 0 | 0 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term | '8 years 1 month 6 days | ' | ||
Unrecognized compensation expense related to unvested unit options | $2,200,000 | ' | ||
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 | ' | 6.60% | ||
Expected unit price volatility | ' | 44.00% | ||
Risk-free interest rate | ' | 1.10% | ||
Expected term (in years) | '0 years | '6 years 3 months | ||
Fair value of unit options granted | ' | $4.85 | ||
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% | ' | ||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period | '4 years | ' | ||
[1] | No options were exercised during the three months ended March 31, 2014, and 2013. | |||
[2] | The weighted average remaining contractual life for outstanding options at March 31, 2014 was 8.1 years. | |||
[3] | The aggregate intrinsic value of options outstanding at March 31, 2014 was approximately $2,000. | |||
[4] | The weighted average remaining contractual life for exercisable options at March 31, 2014 was 8.1 years. There were no intrinsic values for options exercisable at March 31, 2014 and 2013. |
Benefit_Plans_APL_Long_Term_In
Benefit Plans (APL Long Term Incentive Plans Narrative) (Details) (APL Long Term Incentive Plans) | 3 Months Ended |
Mar. 31, 2014 | |
APL Long Term Incentive Plans | ' |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' |
Deferred Compensation Arrangements, Overall, Description | 'APL has a 2004 Long-Term Incentive Plan (“APL 2004 LTIPâ€), and a 2010 Long-Term Incentive Plan, which was modified on April 26, 2011 (“APL 2010 LTIP†and collectively with the APL 2004 LTIP, the “APL LTIPsâ€), in which officers, employees and non-employee managing board members of APL’s general partner and employees of APL’s general partner’s affiliates and consultants are eligible to participate. The APL LTIPs are administered by APL’s compensation committee (the “APL LTIP Committeeâ€). |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 3,435,000 |
Phantom Units Outstanding | 1,664,642 |
Unit Options Outstanding | 0 |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 608,369 |
Benefit_Plans_APL_Phantom_Unit
Benefit Plans (APL Phantom Unit Activity) (Details) (USD $) | 3 Months Ended | |||||
Mar. 31, 2014 | Mar. 31, 2013 | Feb. 28, 2014 | Dec. 31, 2013 | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | ' | ' | ' | ||
Phantom units not attributable to net loss | 2,398,000 | 2,216,000 | ' | ' | ||
Vested and issued (Units) | -15,500 | [1] | -2,465 | [1] | ' | ' |
APL 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 | 'Through March 31, 2014, phantom units granted under the APL LTIPs generally had vesting periods of four years. | ' | ' | ' | ||
Share Based Compensation Arrangement By Share Based Payment Award Number Of Outstanding Units To Vest Within Next Twelve Months | 531,244 | ' | ' | ' | ||
Share Based Compensation Arrangement By Share Based Payment Award Unit Options To Vest In Three Years | ' | ' | 227,000 | ' | ||
Distribution equivalent rights paid on unissued units under incentive plans | $900,000 | $600,000 | ' | ' | ||
Outstanding, beginning of period (Units) | 1,446,553 | 1,053,242 | ' | ' | ||
Phantom units not attributable to net loss | 234,701 | 6,804 | ' | ' | ||
Vested and issued (Units) | -14,412 | [2] | -2,963 | [2] | ' | ' |
Forfeited (Units) | -2,200 | ' | ' | ' | ||
Outstanding, end of period (Units) | 1,664,642 | [3],[4] | 1,057,083 | [3],[4] | ' | ' |
Outstanding, beginning of period | $36.32 | $33.21 | ' | ' | ||
Granted | $31.03 | $33.06 | ' | ' | ||
Vested and issued | $34.03 | [2] | $28.94 | [2] | ' | ' |
Forfeited | $39.51 | ' | ' | ' | ||
Outstanding, end of period | $35.59 | [3],[4] | $33.22 | [3],[4] | ' | ' |
Non-cash compensation expense recognized (in thousands) | 6,439,000 | 4,384,000 | ' | ' | ||
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested And Issued In Period Intrinsic Value | 500,000 | 100,000 | ' | ' | ||
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Nonvested Number Classified As Liabilities | 25,228 | ' | ' | 22,539 | ||
Share Based Compensation Arrangement By Share Based Payment Award Other Than Options Outstanding Intrinsic Value | 53,500,000 | ' | ' | 50,700,000 | ||
Unrecognized compensation expense related to unvested phantom units | $31,500,000 | ' | ' | ' | ||
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition | '2 years | ' | ' | ' | ||
[1] | The intrinsic value of phantom unit awards vested and issued during the three months ended March 31, 2014 and 2013 was $0.3 million and $0.1 million, respectively. | |||||
[2] | The intrinsic values for phantom unit awards vested and issued were $0.5 million and $0.1 million, respectively, during the three months ended March 31, 2014 and 2013, respectively. | |||||
[3] | There were 25,228 and 22,539 outstanding phantom unit awards at March 31, 2014 and December 31, 2013, respectively, which were classified as liabilities due to a cash option available on the related phantom unit awards | |||||
[4] | The aggregate intrinsic values for phantom unit awards outstanding at ended March 31, 2014 and December 31, 2013 were $53.5 million and $50.7 million, respectively |
Operating_Segment_Information_1
Operating Segment Information (Narrative) (Details) | 3 Months Ended |
Mar. 31, 2014 | |
Segment | |
Segment Reporting Information [Line Items] | ' |
Number of reportable operating segments | 3 |
Operating_Segment_Information_2
Operating Segment Information (Operating Segment Data) (Details) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Segment Reporting Information [Line Items] | ' | ' |
Revenues | $860,262 | $522,102 |
Depreciation, depletion and amortization expense | -101,278 | -51,666 |
Loss on asset sales and disposal | -1,603 | -702 |
Interest expense | -41,314 | -25,810 |
Segment income (loss) | -21,067 | -41,694 |
Loss on early extinguishment of debt | ' | -26,582 |
Operating Segments | Atlas Resource Partners, L.P. | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Revenues | 157,345 | 112,048 |
Operating costs and expenses | -103,078 | -88,626 |
Depreciation, depletion and amortization expense | -50,237 | -21,208 |
Loss on asset sales and disposal | -1,603 | -702 |
Interest expense | -13,188 | -6,889 |
Segment income (loss) | -10,761 | -5,377 |
Operating Segments | Atlas Pipeline Partners, L.P. | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Revenues | 698,089 | 409,952 |
Operating costs and expenses | -618,138 | -361,718 |
Depreciation, depletion and amortization expense | -49,239 | -30,458 |
Loss on asset sales and disposal | ' | ' |
Interest expense | -23,663 | -18,686 |
Segment income (loss) | 7,049 | -27,492 |
Loss on early extinguishment of debt | ' | -26,582 |
Operating Segments | Corporate and Other | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Revenues | 4,828 | 102 |
Operating costs and expenses | -15,918 | -8,692 |
Depreciation, depletion and amortization expense | -1,802 | ' |
Loss on asset sales and disposal | ' | ' |
Interest expense | -4,463 | -235 |
Segment income (loss) | ($17,355) | ($8,825) |
Operating_Segment_Information_3
Operating Segment Information (Reconciliation of Segment Income to Net Income) (Details) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Segment Reporting Information [Line Items] | ' | ' |
Net loss | ($21,067) | ($41,694) |
Operating Segments | Atlas Resource Partners, L.P. | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Net loss | -10,761 | -5,377 |
Operating Segments | Atlas Pipeline Partners, L.P. | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Net loss | 7,049 | -27,492 |
Operating Segments | Corporate and Other | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Net loss | ($17,355) | ($8,825) |
Operating_Segment_Information_4
Operating Segment Information (Capital Expenditures) (Details) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Segment Reporting Information [Line Items] | ' | ' |
Capital expenditures | $172,750 | $167,003 |
Operating Segments | Atlas Resource Partners, L.P. | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Capital expenditures | 39,897 | 58,487 |
Operating Segments | Atlas Pipeline Partners, L.P. | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Capital expenditures | 128,331 | 108,516 |
Operating Segments | Corporate and Other | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Capital expenditures | $4,522 | ' |
Operating_Segment_Information_5
Operating Segment Information (Balance Sheet) (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Segment Reporting Information [Line Items] | ' | ' |
Goodwill, net | $402,180 | $400,356 |
Total assets | 6,898,236 | 6,792,641 |
Atlas Resource Partners, L.P. | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Goodwill, net | 31,784 | 31,784 |
Atlas Pipeline Partners, L.P. | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Goodwill, net | 370,396 | 368,572 |
Operating Segments | Atlas Resource Partners, L.P. | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Goodwill, net | 31,784 | 31,784 |
Total assets | 2,321,905 | 2,343,800 |
Operating Segments | Atlas Pipeline Partners, L.P. | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Goodwill, net | 370,396 | 368,572 |
Total assets | 4,446,958 | 4,327,845 |
Operating Segments | Corporate and Other | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Goodwill, net | ' | ' |
Total assets | $129,373 | $120,996 |
Subsequent_Events_Partnership_
Subsequent Events (Partnership Cash Distributions) (Details) (USD $) | 3 Months Ended | 1 Months Ended | 3 Months Ended | 1 Months Ended | 3 Months Ended | |||||
In Thousands, except Per Share data, unless otherwise specified | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Apr. 30, 2014 | Apr. 23, 2014 | Mar. 31, 2014 | Apr. 30, 2014 | Mar. 31, 2014 |
ATLS | ATLS | ATLS | ATLS | ATLS | ||||||
Subsequent Event | Subsequent Event | Subsequent Event | Subsequent Event | Subsequent Event | ||||||
Dividend Declared | Dividend Declared | Dividend Declared | Dividend Paid | Dividend Paid | ||||||
Subsequent Event [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Declaration Date | ' | ' | ' | ' | ' | 23-Apr-14 | ' | 23-Apr-14 | ' | ' |
Distribution Made to Limited Partner, Distributions Declared, Per Unit | ' | $0.46 | $0.46 | $0.44 | $0.31 | $0.46 | $0.46 | ' | ' | ' |
Distribution Made to Limited Partner, Cash Distributions Paid | ' | $23,681 | $23,649 | $22,611 | $15,928 | ' | ' | ' | $23,900 | $23,900 |
Distribution Made to Limited Partner, Date of Record | ' | ' | ' | ' | ' | ' | ' | ' | 7-May-14 | 7-May-14 |
Distribution Made to Member or Limited Partner, Distribution Date | 13-Mar-12 | 19-Feb-14 | 19-Nov-13 | 19-Aug-13 | 20-May-13 | ' | ' | ' | 20-May-14 | 20-May-14 |
Subsequent_Events_Atlas_Resour
Subsequent Events (Atlas Resource Cash Distribution) (Details) (USD $) | 3 Months Ended | 1 Months Ended | 3 Months Ended | 0 Months Ended | 1 Months Ended | 3 Months Ended | 1 Months Ended | 3 Months Ended | 1 Months Ended | ||||||||||||
In Millions, except Share data, unless otherwise specified | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Mar. 31, 2014 | Feb. 28, 2014 | Jan. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | 8-May-14 | 7-May-14 | Apr. 30, 2014 | Apr. 30, 2014 | Mar. 31, 2014 | Apr. 30, 2014 | Mar. 31, 2014 | Apr. 30, 2014 | Apr. 30, 2014 |
Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | Atlas Resource Partners, L.P. | ||||||
Subsequent Event | Subsequent Event | Subsequent Event | Dividend Declared | Dividend Declared | Dividend Paid | Dividend Paid | Dividend Paid | Dividend Paid | |||||||||||||
Merit | Merit | Merit | Subsequent Event | Subsequent Event | Subsequent Event | Subsequent Event | Subsequent Event | Subsequent Event | |||||||||||||
General Partner Interest | Preferred Limited Partner | ||||||||||||||||||||
Subsequent Event [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Declaration Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 23-Apr-14 | 23-Apr-14 | ' | ' | ' | ' |
Distribution Made to Limited Partner, Distributions Declared, Per Unit | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $0.19 | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Cash Distributions Paid | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $15.30 | $15.30 | $1.10 | $1.50 |
Distribution Made to Member or Limited Partner, Distribution Date | 13-Mar-12 | 19-Feb-14 | 19-Nov-13 | 19-Aug-13 | 20-May-13 | ' | 14-Apr-14 | 17-Mar-14 | 14-Feb-14 | 14-Nov-13 | 14-Aug-13 | 15-May-13 | ' | ' | ' | ' | 15-May-14 | 15-May-14 | ' | ' | ' |
Distribution Made to Member or Limited Partner, Date of Record | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7-May-14 | 7-May-14 | ' | ' |
Business Acquisition, Cost of Acquired Entity, Cash Paid | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 420 | ' | ' | ' | ' | ' | ' | ' |
Business Acquisition, Closing Date Of Acquisition | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1-Apr-14 | ' | ' | ' | ' | ' | ' |
Partners' Capital Account, Units, Sale of units | ' | ' | ' | ' | ' | 6,325,000 | ' | ' | ' | ' | ' | ' | 13,500,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Negotiated Purchase Price Per Unit | ' | ' | ' | ' | ' | $21.18 | ' | ' | ' | ' | ' | ' | $19.18 | ' | ' | ' | ' | ' | ' | ' | ' |
Partners Capital Account Sale Of Units | ' | ' | ' | ' | ' | $129 | ' | ' | ' | ' | ' | ' | $258.70 | ' | ' | ' | ' | ' | ' | ' | ' |
Subsequent_Events_Atlas_Pipeli
Subsequent Events (Atlas Pipeline Cash Distribution) (Details) (USD $) | 3 Months Ended | 1 Months Ended | 3 Months Ended | 1 Months Ended | 3 Months Ended | 1 Months Ended | |||||||||
In Millions, except Share data, unless otherwise specified | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | 5-May-14 | Apr. 30, 2014 | Mar. 31, 2014 | Apr. 30, 2014 | Mar. 31, 2014 | Apr. 30, 2014 |
Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | Atlas Pipeline "APL" | ||||||
Subsequent Event | Dividend Declared | Dividend Declared | Dividend Paid | Dividend Paid | Dividend Paid | ||||||||||
Subsequent Event | Subsequent Event | Subsequent Event | Subsequent Event | Subsequent Event | |||||||||||
General Partner Interest | |||||||||||||||
Subsequent Event [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Declaration Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 22-Apr-14 | 22-Apr-14 | ' | ' | ' |
Distribution Made to Limited Partner, Distributions Declared, Per Unit | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $0.62 | ' | ' | ' | ' |
Distribution Made to Member or Limited Partner, Cash Distributions Paid | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $56.10 | ' | $6.10 |
Distribution Made to Member or Limited Partner, Distribution Date | 13-Mar-12 | 19-Feb-14 | 19-Nov-13 | 19-Aug-13 | 20-May-13 | 14-Feb-14 | 14-Nov-13 | 14-Aug-13 | 15-May-13 | ' | ' | ' | 15-May-14 | 15-May-14 | ' |
Distribution Made to Member or Limited Partner, Date of Record | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8-May-14 | 8-May-14 | ' |
Class D Preferred Units | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 317,000 | ' | ' | ' | ' |
Definitive agreement to sell interest in business, percentage of interest to be sold | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20.00% | ' | ' | ' | ' | ' |
Definitive agreement to sell interest in business, expected cash proceeds | ' | ' | ' | ' | ' | ' | ' | ' | ' | $135 | ' | ' | ' | ' | ' |