Document_and_Entity_Informatio
Document and Entity Information | 3 Months Ended | |
Mar. 31, 2015 | 5-May-15 | |
Document And Entity Information [Abstract] | ||
Document Type | 10-Q | |
Amendment Flag | FALSE | |
Document Period End Date | 31-Mar-15 | |
Document Fiscal Year Focus | 2015 | |
Document Fiscal Period Focus | Q1 | |
Entity Registrant Name | Atlas Energy Group, LLC | |
Entity Central Index Key | 1623595 | |
Current Fiscal Year End Date | -19 | |
Entity Filer Category | Non-accelerated Filer | |
Trading Symbol | ATLS | |
Entity Common Stock, Units Outstanding | 26,010,766 |
COMBINED_CONSOLIDATED_BALANCE_
COMBINED CONSOLIDATED BALANCE SHEETS (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Current assets: | ||
Cash and cash equivalents | $13,542 | $58,358 |
Accounts receivable | 97,376 | 115,290 |
Advances to affiliates | 4,389 | |
Current portion of derivative asset | 146,446 | 144,259 |
Subscriptions receivable | 32,398 | |
Prepaid expenses and other | 28,697 | 26,789 |
Total current assets | 286,061 | 381,483 |
Property, plant and equipment, net | 2,406,724 | 2,419,289 |
Goodwill and intangible assets, net | 14,271 | 14,330 |
Long-term derivative asset | 186,718 | 130,602 |
Other assets, net | 83,208 | 80,611 |
Total assets | 2,976,982 | 3,026,315 |
Current liabilities: | ||
Current portion of long-term debt | 104,419 | 1,500 |
Accounts payable | 104,479 | 123,670 |
Liabilities associated with drilling contracts | 16,956 | 40,611 |
Current portion of derivative payable to Drilling Partnerships | 1,526 | 932 |
Accrued interest | 12,190 | 26,479 |
Accrued well drilling and completion costs | 45,041 | 92,910 |
Deferred acquisition purchase price | 56,667 | 105,000 |
Accrued liabilities | 40,414 | 64,854 |
Total current liabilities | 381,692 | 455,956 |
Long-term debt, less current portion | 1,500,178 | 1,541,085 |
Asset retirement obligations and other | 117,818 | 114,059 |
Commitments and contingencies | ||
Unitholders’/owner’s equity: | ||
Common unitholders’ equity | 122,924 | |
Series A preferred equity | 40,000 | |
Owner’s equity | 147,308 | |
Accumulated other comprehensive income | 46,020 | 54,008 |
Unitholders'/owner's equity excluding non-controlling interests | 208,944 | 201,316 |
Non-controlling interests | 768,350 | 713,899 |
Total unitholders’/owner’s equity | 977,294 | 915,215 |
Total liabilities and unitholders’/owner’s equity | $2,976,982 | $3,026,315 |
COMBINED_CONSOLIDATED_STATEMEN
COMBINED CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) | 3 Months Ended | |
In Thousands, except Per Share data, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Revenues: | ||
Gas and oil production | $106,560 | $100,825 |
Well construction and completion | 23,655 | 49,377 |
Gathering and processing | 2,184 | 4,468 |
Administration and oversight | 1,259 | 1,729 |
Well services | 6,624 | 5,479 |
Gain on mark-to-market derivatives | 105,585 | |
Other, net | -68 | 269 |
Total revenues | 245,799 | 162,147 |
Costs and expenses: | ||
Gas and oil production | 45,989 | 38,758 |
Well construction and completion | 20,570 | 42,936 |
Gathering and processing | 2,417 | 4,413 |
Well services | 2,198 | 2,482 |
General and administrative | 41,928 | 21,391 |
Depreciation, depletion and amortization | 44,456 | 52,039 |
Total costs and expenses | 157,558 | 162,019 |
Operating income | 88,241 | 128 |
Loss on asset sales and disposal | -11 | -1,603 |
Interest expense | -34,751 | -15,976 |
Net income (loss) | 53,479 | -17,451 |
(Income) loss attributable to non-controlling interests | -58,298 | 10,308 |
Net loss attributable to unitholders’/owner interests | -4,819 | -7,143 |
Allocation of net income (loss) attributable to unitholders’ interests/owner: | ||
Portion applicable to owner’s interest (period prior to the transfer of assets on February 27, 2015) | -10,475 | -7,143 |
Portion applicable to unitholders’ interests (period subsequent to the transfer of assets on February 27, 2015) | 5,656 | |
Net loss attributable to unitholders’/owner interests | ($4,819) | ($7,143) |
Net income attributable to unitholders per common unit: | ||
Basic | $0.22 | |
Diluted | $0.18 | |
Weighted average common units outstanding: | ||
Basic | 26,011 | |
Diluted | 30,936 |
COMBINED_CONSOLIDATED_STATEMEN1
COMBINED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Statement Of Income And Comprehensive Income [Abstract] | ||
Net income (loss) | $53,479 | ($17,451) |
Other comprehensive (loss): | ||
Changes in fair value of derivative instruments accounted for as cash flow hedges | -36,255 | |
Less: reclassification adjustment for realized (gains) losses of cash flow hedges in net income (loss) | -27,343 | 14,569 |
Total other comprehensive loss | -27,343 | -21,686 |
Comprehensive income (loss) | 26,136 | -39,137 |
Comprehensive (income) loss attributable to non-controlling interests | -38,943 | 27,137 |
Comprehensive loss attributable to unitholders’/owner’s interest | ($12,807) | ($12,000) |
COMBINED_CONSOLIDATED_STATEMEN2
COMBINED CONSOLIDATED STATEMENT OF UNITHOLDERS'/OWNER'S EQUITY (USD $) | Total | Series A Preferred Equity | Common Unitholders' Equity | Owner's Equity | Accumulated Other Comprehensive Income | Non-Controlling Interest |
In Thousands, except Share data | ||||||
Balance at Dec. 31, 2014 | $915,215 | $147,308 | $54,008 | $713,899 | ||
Balance units at Dec. 31, 2014 | 0 | 0 | ||||
Portion applicable to owner’s interest (period prior to the transfer of assets on February 27, 2015) | -10,475 | -10,475 | ||||
Net distribution to owner’s interest prior to the transfer of assets on February 27, 2015 | -19,758 | -19,758 | ||||
Net assets contributed by owner to Atlas Energy Group, LLC | 117,075 | -117,075 | ||||
Issuance of units , number of units | 1,600,000 | 26,010,766 | ||||
Issuance of units | 83,063 | 40,000 | 43,063 | |||
Distributions to non-controlling interests | -35,934 | -35,934 | ||||
Net issued and unissued units under incentive plan | 3,435 | 3,435 | ||||
Distribution equivalent rights paid on unissued units under incentive plans | -265 | -265 | ||||
Distribution payable | 5,402 | 5,402 | ||||
Gain on sale from subsidiary unit issuances | 193 | -193 | ||||
Other comprehensive loss | -27,343 | -7,988 | -19,355 | |||
Net income | 63,954 | 5,656 | 58,298 | |||
Balance at Mar. 31, 2015 | $977,294 | $40,000 | $122,924 | $46,020 | $768,350 | |
Balance units at Mar. 31, 2015 | 1,600,000 | 26,010,766 |
COMBINED_CONSOLIDATED_STATEMEN3
COMBINED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
CASH FLOWS FROM OPERATING ACTIVITIES: | ||
Net income (loss) | $53,479 | ($17,451) |
Adjustments to reconcile net income (loss) to net cash used in operating activities: | ||
Depreciation, depletion and amortization | 44,456 | 52,039 |
Gain on mark-to-market derivatives | -105,585 | |
Amortization of deferred financing costs | 12,658 | 2,067 |
Non-cash compensation expense | 3,364 | 2,765 |
Loss on asset sales and disposal | 11 | 1,603 |
Distributions paid to non-controlling interests | -36,199 | -34,696 |
Equity loss (income) in unconsolidated companies | 102 | -195 |
Distributions received from unconsolidated companies | 455 | 311 |
Changes in operating assets and liabilities: | ||
Accounts receivable, prepaid expenses and other | 73,274 | 11,182 |
Accounts payable and accrued liabilities | -95,210 | -34,140 |
Net cash used in operating activities | -49,195 | -16,515 |
CASH FLOWS FROM INVESTING ACTIVITIES: | ||
Capital expenditures | -52,441 | -44,419 |
Net cash paid for acquisitions | -32,746 | |
Other | -2,041 | -2,070 |
Net cash used in investing activities | -87,228 | -46,489 |
CASH FLOWS FROM FINANCING ACTIVITIES: | ||
Borrowings under credit facilities | 161,000 | 162,000 |
Repayments under credit facilities | 298,000 | 215,000 |
Net proceeds from issuance of Series A units | 40,000 | |
Net proceeds from issuance of subsidiary units to the public | 23,083 | 130,680 |
Net distributions to owner | -19,758 | -14,577 |
Deferred financing costs, distribution equivalent rights and other | -12,447 | -529 |
Net cash provided by financing activities | 91,607 | 62,949 |
Net change in cash and cash equivalents | -44,816 | -55 |
Cash and cash equivalents, beginning of year | 58,358 | 10,625 |
Cash and cash equivalents, end of period | 13,542 | 10,570 |
Term Loan | ||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||
Borrowings under term loan facilities | 357,784 | 975 |
Repayments under term loan facilities | ($160,055) | ($600) |
Basis_of_Presentation
Basis of Presentation | 3 Months Ended | |
Mar. 31, 2015 | ||
Organization Consolidation And Presentation Of Financial Statements [Abstract] | ||
Basis of Presentation | NOTE 1—BASIS OF PRESENTATION | |
Atlas Energy Group, LLC is a Delaware limited liability company formed in October 2011 (the “Company”). At March 31, 2015, the Company’s operations primarily consisted of its ownership interests in the following: | ||
· | 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 27.5% limited partner interest (consisting of 20,962,485 common and 3,749,986 preferred limited partner units) in 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. As part of its exploration and production activities, ARP sponsors and manages tax-advantaged investment partnerships (“Drilling Partnerships”), in which it coinvests, to finance a portion of its natural gas and oil production activities; | |
● | 80.0% general partner interest and a 1.6% limited partner interest in its development subsidiary, a partnership that currently conducts natural gas and oil operations in the mid-continent region of the United States (the “Development Subsidiary”); | |
● | 15.9% general partner interest and 12.0% limited partner interest in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, its general partner, which incubate new MLPs and invest in existing MLPs; and | |
● | direct natural gas development and production assets in the Arkoma Basin in eastern Oklahoma. | |
On February 27, 2015, the Company’s former owner, Atlas Energy, L.P. (“Atlas Energy”), transferred its assets and liabilities, other than those related to its midstream assets, to the Company, and effected a pro rata distribution of the Company’s common units representing a 100% interest in the Company, to Atlas Energy’s unitholders (the “Separation”). Concurrently with the distribution of the Company’s units, Atlas Energy and its remaining midstream interests merged with Targa Resources Corp. (“Targa”; NYSE: TRGP) and ceased trading. | ||
The accompanying combined consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2014 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 Company’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 Company’s Annual Report on Form 10-K for the year ended December 31, 2014. The results of operations for the three months ended March 31, 2015 may not necessarily be indicative of the results of operations for the full year ending December 31, 2015. |
Summary_of_Significant_Account
Summary of Significant Accounting Policies | 3 Months Ended | ||||||||||||
Mar. 31, 2015 | |||||||||||||
Accounting Policies [Abstract] | |||||||||||||
Summary of Significant Accounting Policies | NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | ||||||||||||
Principles of Consolidation and Combination | |||||||||||||
The consolidated balance sheet at March 31, 2015 and the related combined consolidated statement of operations for the three months ended March 31, 2015, subsequent to the transfer of assets on February 27, 2015 include the accounts of the Company and its subsidiaries. The Company’s combined consolidated balance sheet at December 31, 2014, the combined consolidated statement of operations for the three months ended March 31, 2015 prior to the transfer of assets on February 27, 2015, and the combined consolidated statement of operations for the three months ended March 31, 2014 were derived from the separate records maintained by Atlas Energy and may not necessarily be indicative of the conditions or results of operations that would have existed if the Company had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various entities comprising the Company, Atlas Energy’s net investment in the Company is shown as equity in the combined consolidated financial statements. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the combined consolidated balance sheets and related combined consolidated statements of operations. Such estimates included allocations made from the historical accounting records of Atlas Energy, based on management’s best estimates, in order to derive the financial statements of the Company. Actual balances and results could be different from those estimates. Transactions between the Company and other Atlas Energy operations have been identified in the combined consolidated financial statements as transactions between affiliates. | |||||||||||||
In connection with Atlas Energy’s merger with Targa and the concurrent Separation, the Company was required to repay $150.0 million of Atlas Energy’s term loan credit facility, which was issued in July 2013 for $240.0 million. In accordance with generally accepted accounting principles, the Company included $150.0 million of Atlas Energy’s original term loan at the time of issuance, and the related interest expense, within its historical financial statements. Atlas Energy’s other historical borrowings were allocated to the Company’s historical financial statements in the same ratio. The Company used proceeds from the issuance of its Series A preferred units (see Note 12) and borrowings under its term loan credit facilities (see Note 7) to fund the $150.0 million payment. | |||||||||||||
The Company combines the financial statements of ARP and the Development Subsidiary into its combined consolidated financial statements rather than presenting its ownership interest as equity investments, as the Company controls these entities through its general partnership interests therein. As such, the non-controlling interests in ARP and the Development Subsidiary are reflected as (income) loss attributable to non-controlling interests in the combined consolidated statements of operations and as a component of unitholders’ equity on the combined consolidated balance sheets. All material intercompany transactions have been eliminated. | |||||||||||||
In accordance with established practice in the oil and gas industry, the Company’s combined 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 Company’s combined 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 (see “Property, Plant and Equipment”). | |||||||||||||
During the three months ended March 31, 2015, the Development Subsidiary issued $19.8 million of its common limited partner units, which was included within non-controlling interests on the Company’s combined consolidated balance sheets. In connection with the issuance of the Development Subsidiary’s common units, the Company recorded a gain of $0.4 million within equity and a corresponding decrease in non-controlling interests on its combined consolidated balance sheet and consolidated statement of unitholders’ equity. | |||||||||||||
Use of Estimates | |||||||||||||
The preparation of the Company’s combined 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 Company’s combined consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Company’s combined 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. Such estimates included estimated allocations made from the historical accounting records of Atlas Energy in order to derive the historical financial statements of the Company. 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, 2015 and 2014 represent actual results in all material respects (see “Revenue Recognition”). | |||||||||||||
Receivables | |||||||||||||
Accounts receivable on the combined consolidated balance sheets consist primarily of the trade accounts receivable associated with the Company and its subsidiaries. In evaluating the realizability of accounts receivable, management performs ongoing credit evaluations of customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness, as determined by management’s review of customers’ credit information. The Company and its subsidiaries extend credit on sales on an unsecured basis to many of its customers. At March 31, 2015 and December 31, 2014, the Company had recorded no allowance for uncollectible accounts receivable on its combined consolidated balance sheets. | |||||||||||||
Inventory | |||||||||||||
The Company had $8.4 million and $8.9 million of inventory at March 31, 2015 and December 31, 2014, respectively, which were included within prepaid expenses and other current assets on its combined consolidated balance sheets. The Company values inventories at the lower of cost or market. The Company’s inventories, which consist primarily of ARP’s materials, pipes, supplies and other inventories, were principally determined using the average cost method. | |||||||||||||
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 that 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 that 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 Company’s results of operations. | |||||||||||||
The Company and its subsidiaries 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 Company’s and its subsidiaries’ 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 Company’s combined consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s combined 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 Company’s combined 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 Company and its subsidiaries review 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 Company’s and its subsidiaries’ 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 Company and its subsidiaries 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 operating and administrative fees in addition to their proportionate share of external operating expenses. 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 Company 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 partnership 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 Company and its subsidiaries 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. There were no impairments of unproved gas and oil properties recorded on the Company’s combined consolidated statements of operations for the three months ended March 31, 2015 and 2014. | |||||||||||||
Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. During the year ended December 31, 2014, the Company recognized $562.6 million of asset impairment related to oil and gas properties within property, plant and equipment, net on its combined consolidated balance sheet primarily for ARP’s Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. Asset impairments for the year ended December 31, 2014 principally resulted from the decline in forward commodity prices during the fourth quarter of 2014. There were no impairments of proved gas and oil properties recorded by the Company for the three months ended March 31, 2015 and 2014. | |||||||||||||
The impairment of proved properties during the year ended December 31, 2014 related to the carrying amounts of these gas and oil properties being in excess of the Company’s estimate of their fair values at December 31, 2014. The estimate of the fair values of these gas and oil properties was impacted by, among other factors, the deterioration of commodity prices at the date of measurement. | |||||||||||||
Capitalized Interest | |||||||||||||
ARP capitalizes 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 were 6.1% and 5.6% for the three months ended March 31, 2015 and 2014, respectively. The amounts of interest capitalized by ARP were $3.9 million and $2.6 million for the three months ended March 31, 2015 and 2014, respectively. | |||||||||||||
Intangible Assets | |||||||||||||
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, 2015 and December 31, 2014 (in thousands): | |||||||||||||
March 31, | December 31, | Estimated | |||||||||||
Useful Lives | |||||||||||||
2015 | 2014 | In Years | |||||||||||
Gross Carrying Amount | $ | 14,344 | $ | 14,344 | 13 | ||||||||
Accumulated Amortization | (13,712 | ) | (13,653 | ) | |||||||||
Net Carrying Amount | $ | 632 | $ | 691 | |||||||||
Amortization expense on intangible assets was $0.1 million for both the three months ended March 31, 2015 and 2014, respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2015 - $0.2 million; 2016 - $0.1 million; 2017 - $0.1 million; 2018 - $0.1 million; and 2019 - $0.1 million. | |||||||||||||
Goodwill | |||||||||||||
At March 31, 2015 and December 31, 2014, the Company had $13.6 million of goodwill recorded in connection with ARP’s prior consummated acquisitions. No changes in the carrying amount of goodwill were recorded for the three months ended March 31, 2015 and 2014. | |||||||||||||
ARP tests 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 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. 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, 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 also considers 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 industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in ARP’s industry to determine whether those valuations appear reasonable in management’s judgment. ARP’s management will continue to evaluate goodwill at least annually or when impairment indicators arise. | |||||||||||||
As a result of its goodwill impairment evaluation at December 31, 2014, ARP recognized an $18.1 million non-cash impairment charge within asset impairments on the Company’s combined consolidated statement of operations for the year ended December 31, 2014. The goodwill impairment resulted from the reduction in ARP’s estimated fair value of its gas and oil production reporting unit in comparison to its carrying amount at December 31, 2014. ARP’s estimated fair value of its gas and oil production reporting unit was impacted by a decline in overall commodity prices during the fourth quarter of 2014. | |||||||||||||
Derivative Instruments | |||||||||||||
The Company and ARP enter into certain financial contracts to manage their exposure to movement in commodity prices and interest rates (see Note 8). The derivative instruments recorded in the combined consolidated balance sheets are measured as either an asset or liability at fair value. Changes in the fair value of derivative instruments are recognized currently in the Company’s combined consolidated statements of operations unless specific hedge accounting criteria are met. On January 1, 2015, the Company and ARP discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges. As such, changes in fair value after December 31, 2014 of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Company’s combined consolidated statements of operations, while the fair values of the instruments recorded in accumulated other comprehensive income as of December 31, 2014 will be reclassified to the combined consolidated statements of operations in the periods in which those respective derivative contracts settle. Prior to discontinuance of hedge accounting, the fair value of these commodity derivative instruments was recognized in accumulated other comprehensive income (loss) within unitholders’ equity on the Company’s consolidated balance sheets and reclassified to the Company’s consolidated statements of operations at the time the originally hedged physical transactions affected earnings. | |||||||||||||
Asset Retirement Obligations | |||||||||||||
The Company and its subsidiaries recognize an estimated liability for the plugging and abandonment of gas and oil wells and related facilities (see Note 6). The Company and its subsidiaries also recognize a liability for 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 Company and its subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization. | |||||||||||||
ARP Preferred Units | |||||||||||||
In connection with ARP’s acquisition of certain proved reserves and associated assets from Titan Operating, L.L.C. in July 2012, ARP issued 3.8 million newly created convertible Class B ARP preferred units (“Class B ARP Preferred Units”). While outstanding, the Class B ARP Preferred Units will receive regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution. On December 23, 2014, 3,796,900 of Class B ARP Preferred Units were converted into common units. In connection with ARP’s acquisition of certain proved reserves and associated assets from EP Energy, Inc. in July 2013, ARP issued 3.7 million newly created convertible Class C ARP preferred units to Atlas Energy (“Class C ARP Preferred Units”). While outstanding, the Class C ARP Preferred Units will receive regular quarterly cash distributions equal to the greater of (i) $0.51 and (ii) the quarterly common unit distribution. In October 2014, in connection with ARP’s acquisition of assets in the Eagle Ford Shale (see Note 3), ARP issued 3.2 million of its 8.625% Class D cumulative redeemable perpetual preferred units (“Class D ARP Preferred Units”) and in March 2015, issued an additional 800,000 Class D ARP Preferred Units (see Note 12). The initial quarterly distribution on the Class D ARP Preferred Units was $0.616927 per unit, representing the distribution for the period from October 2, 2014 through January 14, 2015. Subsequent to January 14, 2015, ARP will pay future quarterly distributions on the Class D ARP Preferred Units at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference. At March 31, 2015 and December 31, 2014, $97.6 million and $78.0 million, respectively, related to ARP’s preferred units, are included within non-controlling interests on the Company’s combined consolidated statements of unitholders’ equity. | |||||||||||||
Income Taxes | |||||||||||||
The Company, ARP, the Development Subsidiary, Lightfoot and the respective subsidiaries thereof are not subject to U.S. federal and most state income taxes. The partners of these entities are liable for income tax in regard to their distributive share of the entities’ taxable income. Such taxable income may vary substantially from net income (loss) reported in the accompanying combined consolidated financial statements. Certain corporate subsidiaries of ARP are subject to federal and state income tax. The federal and state income taxes related to the Company and these corporate subsidiaries were immaterial to the combined consolidated financial statements as of March 31, 2015 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 combined consolidated financial statements. | |||||||||||||
Each of the entities which comprise the Company evaluates tax positions taken or expected to be taken in the course of preparing their respective 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 Company’s management does not believe it has any tax positions taken within its combined consolidated financial statements that would not meet this threshold. The Company’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. The Company has not recognized any such potential interest or penalties in its combined consolidated financial statements for the three months ended March 31, 2015 and 2014. | |||||||||||||
The entities comprising the Company file Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the entities comprising the Company are no longer subject to income tax examinations by major tax authorities for years prior to 2011 and are not currently being examined by any jurisdiction and are not aware of any potential examinations as of March 31, 2015. | |||||||||||||
Net Income (Loss) Per Common Unit | |||||||||||||
Basic net income (loss) attributable to common unit holders per unit is computed by dividing net income (loss) attributable to common unit holders, which is determined after the deduction of net income attributable to participating securities, if applicable, by the weighted average number of common unit holders 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 Company’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 14), contain non-forfeitable rights to distribution equivalents of the Company. The participation rights result in a non-contingent transfer of value each time the Company 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 unit holders for purposes of calculating net income (loss) attributable to common unit holders per unit (in thousands, except unit data): | |||||||||||||
Three Months Ended | |||||||||||||
March 31, | |||||||||||||
2015 | 2014 | ||||||||||||
Net income (loss) | $ | 53,479 | $ | (17,451 | ) | ||||||||
Loss (income) attributable to non-controlling interests | (58,298 | ) | — | ||||||||||
Loss (income) attributable to owner’s interest (period prior to the transfer of assets on February 27, 2015) | (10,475 | ) | 17,451 | ||||||||||
Net income utilized in the calculation of net income attributable to common unit holders per unit | $ | 5,656 | $ | — | |||||||||
Diluted net income (loss) attributable to common unit holders per unit is calculated by dividing net income (loss) attributable to common unit holders, less income allocable to participating securities, by the sum of the weighted average number of common unit holder units outstanding and the dilutive effect of unit option awards and convertible preferred units, as calculated by the treasury stock or if converted methods, as applicable. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of the Company’s long-term incentive plans (see Note 14). | |||||||||||||
The following table sets forth the reconciliation of the Company’s weighted average number of common unit holder units used to compute basic net income (loss) attributable to common unit holders per unit with those used to compute diluted net income (loss) attributable to common unit holders per unit (in thousands): | |||||||||||||
Three Months Ended | |||||||||||||
March 31, | |||||||||||||
2015 | 2014 | ||||||||||||
Weighted average number of common unit holders per unit—basic | 26,011 | — | |||||||||||
Add effect of dilutive incentive awards | 23 | — | |||||||||||
Add effect of dilutive convertible preferred units | 4,902 | — | |||||||||||
Weighted average number of common unit holders per unit—diluted | 30,936 | — | |||||||||||
Revenue Recognition | |||||||||||||
Natural gas and oil production. The Company and its subsidiaries’ gas and oil production operations 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 Company and its subsidiaries have an interest with other producers, are recognized on the basis of the entity’s percentage ownership of the working interest and/or overriding royalty. | |||||||||||||
ARP’s Drilling Partnerships. Certain energy activities are conducted by ARP through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. Drilling Partnership investor capital raised by ARP is deployed to drill and complete wells included within the partnership. As ARP deploys Drilling Partnership investor capital, it recognizes certain management fees it is entitled to receive, including well construction and completion revenue and a portion of administration and oversight revenue. At each period end, if ARP has Drilling Partnership investor capital that has not yet been deployed, it will recognize a current liability titled “Liabilities Associated with Drilling Contracts” on the Company’s combined consolidated balance sheets. After the Drilling Partnership well is completed and turned in line, ARP is entitled to receive additional operating and management fees, which are included within well services and administration and oversight revenue, respectively, on a monthly basis while the well is operating. In addition to the management fees it is entitled to receive for services provided, ARP is also entitled to its pro-rata share of Drilling Partnership gas and oil production revenue, which generally approximate 30%. ARP recognizes its Drilling Partnership management fees in the following manner: | |||||||||||||
• | Well construction and completion. For each well that is drilled by a Drilling Partnership, ARP receives a 15% mark-up on those costs incurred to drill and complete wells included within the partnership. Such fees are earned, in accordance with the partnership agreement, and recognized as the services are performed, typically between 60 and 270 days, using the percentage of completion method. | ||||||||||||
• | Administration and oversight. For each well drilled by a Drilling Partnership, ARP receives a fixed fee between $100,000 and $500,000, depending on the type of well drilled, which is earned, in accordance with the partnership agreement, and recognized at the initiation of the well. Additionally, the Drilling Partnership pays ARP a monthly per well administrative fee of $75 for the life of the well. The well administrative fee is earned on a monthly basis as the services are performed. | ||||||||||||
• | Well services. Each Drilling Partnership pays ARP a monthly per well operating fee, currently $1,000 to $2,000, depending on the type of well, for the life of the well. Such fees are earned on a monthly basis as the services are performed. | ||||||||||||
While the historical structure has varied, ARP has generally agreed to subordinate a portion of its share of Drilling Partnership gas and oil production revenue, net of corresponding production costs and up to a maximum of 50% of unhedged revenue, from certain Drilling Partnerships for the benefit of the limited partner investors until they have received specified returns, typically 10% to 12% per year determined on a cumulative basis, over a specified period, typically the first five to eight years, in accordance with the terms of the partnership agreements. ARP periodically compares the projected return on investment for limited partners in a Drilling Partnership during the subordination period, based upon historical and projected cumulative gas and oil production revenue and expenses, with the return on investment subject to subordination agreed upon within the Drilling Partnership agreement. If the projected return on investment falls below the agreed upon rate, ARP recognizes subordination as an estimated reduction of its pro-rata share of gas and oil production revenue, net of corresponding production costs, during the current period in an amount that will achieve the agreed upon investment return, subject to the limitation of 50% of unhedged cumulative net production revenues over the subordination period. For Drilling Partnerships for which ARP has recognized subordination in a historical period, if projected investment returns subsequently reflect that the agreed upon limited partner investment return will be achieved during the subordination period, ARP will recognize an estimated increase in its portion of historical cumulative gas and oil net production, subject to a limitation of the cumulative subordination previously recognized. | |||||||||||||
ARP’s gathering and processing revenue. Gathering and processing revenue includes gathering fees ARP charges to the Drilling Partnership wells for ARP’s processing plants in the New Albany and the Chattanooga shales. Generally, ARP charges a gathering fee to the Drilling Partnership wells equivalent to the fees ARP remits. In Appalachia, a majority of the Drilling Partnership wells are subject to a gathering agreement, whereby ARP remits a gathering fee of 16%. However, based on the respective Drilling Partnership agreements, ARP charges the Drilling Partnership wells a 13% gathering fee. As a result, some of ARP’s gathering expenses, specifically those in the Appalachian Basin, will generally exceed the revenues collected from the Drilling Partnerships by approximately 3%. | |||||||||||||
The Company and its subsidiaries’ gas and oil production operations accrue unbilled revenue 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 Company had unbilled revenues at March 31, 2015 and December 31, 2014 of $56.1 million and $85.5 million, respectively, which were included in accounts receivable within its combined 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 Company’s combined 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 8). The Company does not have any other type of transaction which would be included within other comprehensive income (loss). | |||||||||||||
Recently Issued Accounting Standards | |||||||||||||
In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-06, Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (“Update 2015-06”). Under Topic 260, Earnings per Share, master limited partnerships (“MLPs”) apply the two-class method to calculate earnings per unit (“EPU”) because the general partner, limited partners, and incentive distribution rights holders each participate differently in the distribution of available cash. When a general partner transfers (or “drops down”) net assets to a master limited partnership and that transaction is accounted for as a transaction between entities under common control, the statements of operations of the master limited partnership are adjusted retrospectively to reflect the drop down transaction as if it occurred on the earliest date during which the entities were under common control. The amendments in Update 2015-06 specify that for purposes of calculating historical EPU under the two-class method, the earnings (losses) of a transferred business before the date of a drop down transaction should be allocated entirely to the general partner interest, and previously reported EPU of the limited partners would not change as a result of a drop down transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the drop down transaction occurs also are required. The amendments in Update 2015-06 are effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted and amendments in Update 2015-06 should be applied retrospectively for all financial statements presented. The Company will adopt the requirements of Update 2015-06 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures. | |||||||||||||
In March 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30) (“Update 2015-03”). The amendments in Update 2015-03 are intended to simplify presentation of debt issuance costs and require that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs would not be affected by the amendments in Update 2015-03. The amendments in Update 2015-03 are effective for periods beginning after December 15, 2015, and interim periods within those periods. Early adoption is permitted, including adoption in an interim period, and an entity should apply the new guidance on a retrospective basis. The Company will adopt the requirements of Update 2015-03 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures. | |||||||||||||
In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“Update 2015-02”). The amendments in Update 2015-02 are intended to improve targeted areas of consolidation guidance for legal entities such as limited partnerships, limited liability corporations and securitization structures. The amendments simplify the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. The amendments in Update 2015-02 are effective for periods beginning after December 31, 2015. Early adoption is permitted, including adoption in an interim period. The Company will adopt the requirements of Update 2015-02 upon its effective date of January 1, 2016, and is evaluating the impact of adoption on its financial position, results of operations or related disclosures. | |||||||||||||
In January 2015, the FASB issued ASU 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items (“Update 2015-01”). The amendments in Update 2015-01 simplify the income statement presentation requirements in Subtopic 225-20 by eliminating the concept of extraordinary items. Extraordinary items are events and transactions that are distinguished by their unusual nature and by the infrequency of their occurrence. The amendments in Update 2015-01 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. A reporting entity may apply the amendments prospectively. A reporting entity may also apply the amendments retrospectively to all prior periods presented in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal year of adoption. The Company will adopt the requirements of Update 2015-01 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures. | |||||||||||||
In November 2014, the FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815) – Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share is More Akin to Debt or to Equity (“Update 2014-16”). Certain classes of shares include features that entitle the holders to preferences and rights (such as conversion rights, redemption rights, voting powers, and liquidation and dividend payment preferences) over the other shareholders. Shares that include embedded derivative features are referred to as hybrid financial instruments, which must be separated from the host contract and accounted for as a derivative if certain criteria are met under Subtopic 815-10. One criterion requires evaluating whether the nature of the host contract is more akin to debt or to equity and whether the economic characteristics and risks of the embedded derivative feature are “clearly and closely related” to the host contract. In making that evaluation, an issuer or investor may consider all terms and features in a hybrid financial instrument including the embedded derivative feature that is being evaluated for separate accounting or may consider all terms and features in the hybrid financial instrument except for the embedded derivative feature that is being evaluated for separate accounting. The use of different methods can result in different accounting outcomes for economically similar hybrid financial instruments. Additionally, there is diversity in practice with respect to the consideration of redemption features in relation to other features when determining whether the nature of a host contract is more akin to debt or to equity. The amendments in Update 2014-16 clarify how current U.S. GAAP should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. The effects of initially adopting the amendments in Update 2014-16 should be applied on a modified retrospective basis to existing hybrid financial instruments issued in the form of a share as of the beginning of the fiscal year for which the amendments are effective. Retrospective application is permitted to all relevant prior periods. The amendments in Update 2014-16 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The Company will adopt the requirements of Update 2014-16 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures. | |||||||||||||
In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements—Going Concern (Subtopic 205-40) (“Update 2014-15”). The amendments in Update 2014-15 provide U.S. GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management will be required to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early adoption is permitted. The Company will adopt the requirements of Update 2014-15 upon its effective date in 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures. | |||||||||||||
In June 2014, the FASB issued ASU 2014-12, Compensation—Stock Compensation (Topic 718) (“Update 2014-12”). The amendments in Update 2014-12 require that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. As such, the performance target should not be reflected in estimating the grant date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved. The amendments in Update 2014-12 are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Early adoption is permitted. Entities may apply the amendments in Update 2014-12 either (a) prospectively to all awards granted or modified after the effective date, or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. The Company will adopt the requirements of Update 2014-12 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures. | |||||||||||||
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles—Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. The Company will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2017, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures. On April 1, 2015, the FASB tentatively decided to defer the effective date of ASU 2014-09 by one year. As a result, public entities would apply the new revenue standard to annual reporting periods beginning after December 15, 2017, and to interim periods within that reporting period, with early adoption permitted. |
Acquisitions
Acquisitions | 3 Months Ended | ||||
Mar. 31, 2015 | |||||
Business Combinations [Abstract] | |||||
Acquisitions | NOTE 3—ACQUISITIONS | ||||
ARP’s Rangely Acquisition | |||||
On June 30, 2014, ARP completed an acquisition of a 25% non-operated net working interest in oil and natural gas liquids producing assets in the Rangely field in northwest Colorado from Merit Management Partners I, L.P., Merit Energy Partners III, L.P. and Merit Energy Company, LLC (collectively, “Merit Energy”) for approximately $408.9 million in cash, net of purchase price adjustments (the “Rangely Acquisition”). The purchase price was funded through borrowings under ARP’s revolving credit facility, the issuance of an additional $100.0 million of ARP’s 7.75% senior notes due 2021 (“7.75% ARP Senior Notes”) (see Note 7) and the issuance of 15,525,000 of ARP’s common limited partner units (see Note 12). The Rangely Acquisition had an effective date of April 1, 2014. The Company’s combined consolidated financial statements reflected the operating results of the acquired business commencing June 30, 2014 with the transaction closing. | |||||
ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 9). In conjunction with the issuance of ARP’s common limited partner units associated with the acquisition, ARP recorded $11.6 million of transaction fees which were included within non-controlling interests at December 31, 2014 on the Company’s combined consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred. Due to the recent date of the acquisition, the accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as ARP continues to evaluate the facts and circumstances that existed as of the acquisition date. | |||||
The following table presents the preliminary values assigned to the assets acquired and liabilities assumed in the acquisition, based on their estimated fair values at the date of the acquisition (in thousands): | |||||
Assets: | |||||
Prepaid expenses and other | 4,041 | ||||
Property, plant and equipment | 405,416 | ||||
Other assets, net | 2,888 | ||||
Total assets acquired | $ | 412,345 | |||
Liabilities: | |||||
Accrued liabilities | 2,117 | ||||
Asset retirement obligation | 1,305 | ||||
Total liabilities assumed | 3,422 | ||||
Net assets acquired | $ | 408,923 | |||
Other Acquisitions | |||||
On November 5, 2014, ARP and the Development Subsidiary completed an acquisition of oil and natural gas liquid interests in the Eagle Ford Shale in Atascosa County, Texas from Cima Resources, LLC and Cinco Resources, Inc. (together “Cinco”) for $339.2 million, net of purchase price adjustments (the “Eagle Ford Acquisition”). Approximately $179.5 million was paid in cash by ARP and $19.7 million was paid by the Development Subsidiary at closing, and approximately $140.0 million was to be paid in four quarterly installments beginning December 31, 2014. On December 31, 2014, the Development Subsidiary made its first installment payment of $35.0 million related to its Eagle Ford Acquisition. Prior to the March 31, 2015 installment, ARP, the Development Subsidiary, and Cinco amended the purchase and sale agreement to alter the timing and amount of the quarterly payments beginning with the March 31, 2015 payment and ending December 31, 2015, with no change to the overall purchase price. On March 31, 2015, the Development Subsidiary paid $28.3 million and ARP issued $20.0 million of its Class D ARP Preferred Units (see Note 12) to satisfy the second installment related to the Eagle Ford Acquisition. At March 31, 2015, ARP’s and the Development Subsidiary’s remaining deferred portion of the purchase price was $56.7 million, which consisted of $17.5 million, $17.5 million, and $21.7 million on June 30, 2015, September 30, 2015, and December 31, 2015, respectively. ARP’s issuance of Class D ARP Preferred Units represents a non-cash transaction for statement of cash flow purposes during the three months ended March 31, 2015. | |||||
On May 12, 2014, ARP completed the acquisition of certain assets from GeoMet, Inc. (“GeoMet”) (OTCQB: GMET) for approximately $97.9 million in cash, net of purchase price adjustments (the “GeoMet Acquisition”), with an effective date of January 1, 2014. The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia. | |||||
Property_Plant_and_Equipment
Property, Plant and Equipment | 3 Months Ended | ||||||||||||
Mar. 31, 2015 | |||||||||||||
Property Plant And Equipment [Abstract] | |||||||||||||
Property, Plant and Equipment | NOTE 4—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 | |||||||||||||
2015 | 2014 | in Years | |||||||||||
Natural gas and oil properties: | |||||||||||||
Proved properties: | |||||||||||||
Leasehold interests | $ | 458,507 | $ | 535,893 | |||||||||
Pre-development costs | 9,136 | 7,378 | |||||||||||
Wells and related equipment | 3,100,587 | 3,096,562 | |||||||||||
Total proved properties | 3,568,230 | 3,639,833 | |||||||||||
Unproved properties | 314,677 | 217,321 | |||||||||||
Support equipment | 40,992 | 37,359 | |||||||||||
Total natural gas and oil properties | 3,923,899 | 3,894,513 | |||||||||||
Pipelines, processing and compression facilities | 50,578 | 49,547 | 2 – 40 | ||||||||||
Rights of way | 829 | 830 | 20 – 40 | ||||||||||
Land, buildings and improvements | 9,201 | 9,160 | 3 – 40 | ||||||||||
Other | 18,059 | 17,936 | 3 – 10 | ||||||||||
4,002,566 | 3,971,986 | ||||||||||||
Less – accumulated depreciation, depletion and amortization | (1,595,842 | ) | (1,552,697 | ) | |||||||||
$ | 2,406,724 | $ | 2,419,289 | ||||||||||
During the three months ended March 31, 2015, the Company recognized approximately $11,000 of loss on asset sales and disposals. During the three months ended March 31, 2014, the Company recognized $1.6 million of loss on asset sales and 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. | |||||||||||||
There were no asset impairments for the three months ended March 31, 2015 and 2014. During the year ended December 31, 2014, the Company recognized $562.6 million of asset impairment related to oil and gas properties within property, plant and equipment, net on the Company’s combined consolidated balance sheet primarily for ARP’s Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. Asset impairments for the year ended December 31, 2014 principally resulted from the decline in forward commodity prices during the fourth quarter of 2014. These impairments related to the carrying amounts of gas and oil properties being in excess of the Company’s and its subsidiaries’ estimates of their fair values at December 31, 2014. The estimates of fair values of these gas and oil properties were impacted by, among other factors, the deterioration of commodity prices at the respective dates of measurement. | |||||||||||||
During the three months ended March 31, 2015 and 2014, the Company recognized $26.4 million and $18.7 million, respectively, of non-cash property, plant and equipment additions, which were included within the changes in accounts payable and accrued liabilities on the Company’s combined consolidated statement of cash flows. | |||||||||||||
Other_Assets
Other Assets | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Other Assets Noncurrent Disclosure [Abstract] | |||||||||
Other Assets | NOTE 5—OTHER ASSETS | ||||||||
The following is a summary of other assets at the dates indicated (in thousands): | |||||||||
March 31, | December 31, | ||||||||
2015 | 2014 | ||||||||
Deferred financing costs, net of accumulated amortization of $33,333 and $20,675 at March 31, 2015 and December 31, 2014, respectively | $ | 47,601 | $ | 46,120 | |||||
Investment in Lightfoot | 20,612 | 21,123 | |||||||
Rabbi Trust | 5,641 | 3,925 | |||||||
Security deposits | 229 | 229 | |||||||
ARP notes receivable | 3,926 | 3,866 | |||||||
Other | 5,199 | 5,348 | |||||||
$ | 83,208 | $ | 80,611 | ||||||
Deferred financing costs. Deferred financing costs are recorded at cost and amortized over the terms of the respective debt agreements (see Note 7). Amortization expense of the Company’s and its subsidiaries’ deferred financing costs was $2.7 million and $2.1 million for the three months ended March 31, 2015 and 2014, respectively, which was recorded within interest expense on the Company’s combined consolidated statements of operations. During the three months ended March 31, 2015, the Company recognized $5.7 million for accelerated amortization of deferred financing costs associated with Atlas Energy, L.P.’s credit facility and term loan. There was no accelerated amortization of deferred financing costs for the Company during the three months ended March 31, 2014. | |||||||||
During the three months ended March 31, 2015, ARP recognized $4.3 million for accelerated amortization of deferred financing costs associated with a reduction of the borrowing base under the revolving credit facility. There was no accelerated amortization of deferred financing costs for ARP during the three months ended March 31, 2014. | |||||||||
ARP notes receivable. At March 31, 2015 and December 31, 2014, ARP had notes receivable with certain investors of its Drilling Partnerships, which were included within other assets, net on the Company’s combined consolidated balance sheets. 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, 2015 and 2014, approximately $21,000 and $23,000, respectively, of interest income was recognized within other, net on the Company’s combined consolidated statements of operations. At March 31, 2015 and December 31, 2014, ARP recorded no allowance for credit losses within the Company’s combined consolidated balance sheets based upon payment history and ongoing credit evaluations associated with the ARP notes receivable. | |||||||||
Investment in Lightfoot. At March 31, 2015, the Company had 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 Company’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 Company accounts for its investment in Lightfoot under the equity method of accounting. During the three months ended March 31, 2015 and 2014, the Company recognized equity loss of approximately $0.1 million and equity income of approximately $0.2 million, respectively, within other, net on the Company’s combined consolidated statements of operations. During the three months ended March 31, 2015 and 2014, the Company received net cash distributions of approximately $0.5 million and $0.4 million, respectively. |
Asset_Retirement_Obligations
Asset Retirement Obligations | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Asset Retirement Obligation Disclosure [Abstract] | |||||||||
Asset Retirement Obligations | NOTE 6—ASSET RETIREMENT OBLIGATIONS | ||||||||
The Company and its subsidiaries recognized an estimated liability for the plugging and abandonment of their respective gas and oil wells and related facilities. The Company and its subsidiaries 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 Company 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 Company and its subsidiaries have no assets legally restricted for purposes of settling asset retirement obligations. Except for the Company and its subsidiaries’ gas and oil properties, 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, 2015, the Drilling Partnerships had $45.1 million of aggregate asset retirement obligation liabilities recognized on their combined balance sheets allocable to the limited partners, exclusive of ARP’s proportional interest in such liabilities. Under the terms of the respective partnership agreements, ARP maintains the right to retain a portion or all of the distributions to the limited partners of its Drilling Partnerships to cover the limited partners’ share of the plugging and abandonment costs up to a specified amount per month. As of March 31, 2015, ARP has withheld approximately $2.1 million of limited partner distributions related to the asset retirement obligations of certain Drilling Partnerships. ARP’s historical practice and continued intention is to retain distributions from the limited partners as the wells within each Drilling Partnership near the end of their useful life. On a partnership-by-partnership basis, ARP assesses its right to withhold amounts related to plugging and abandonment costs based on several factors, including commodity price trends, the natural decline in the production of the wells, and current and future costs. Generally, ARP’s intention is to retain distributions from the limited partners as the fair value of the future cash flows of the limited partners’ interest approaches the fair value of the future plugging and abandonment cost. Upon ARP’s decision to retain all future distributions to the limited partners of its Drilling Partnerships, ARP will assume the related asset retirement obligations of the limited partners. | |||||||||
A reconciliation of the Company and its subsidiaries’ liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands): | |||||||||
Three Months Ended | |||||||||
March 31, | |||||||||
2015 | 2014 | ||||||||
Asset retirement obligations, beginning of year | $ | 108,101 | $ | 91,214 | |||||
Liabilities incurred | 169 | 602 | |||||||
Liabilities settled | (347 | ) | (217 | ) | |||||
Accretion expense | 1,581 | 1,328 | |||||||
Asset retirement obligations, end of period | $ | 109,504 | $ | 92,927 | |||||
The above accretion expense was included in depreciation, depletion and amortization in the Company’s combined consolidated statements of operations and the asset retirement obligation liabilities were included within asset retirement obligations and other in the Company’s combined consolidated balance sheets. During the year ended December 31, 2014, the Company incurred $0.1 million of future plugging and abandonment costs within purchase accounting related to the acquisition it consummated during the period. During the year ended December 31, 2014, ARP incurred $7.0 million of future plugging and abandonment liabilities within purchase accounting related to the acquisitions it consummated during the periods (see Note 3). No future plugging and abandonment liabilities related to consummated acquisitions were incurred during the three months ended March 31, 2015 and 2014. | |||||||||
Debt
Debt | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Debt Disclosure [Abstract] | |||||||||
Debt | NOTE 7—DEBT | ||||||||
Total debt consists of the following at the dates indicated (in thousands): | |||||||||
March 31, | December 31, | ||||||||
2015 | 2014 | ||||||||
Term loan facilities | $ | 104,419 | $ | 148,125 | |||||
ARP revolving credit facility | 559,000 | 696,000 | |||||||
ARP term loan facility | 242,658 | — | |||||||
ARP 7.75% Senior Notes—due 2021 | 374,563 | 374,544 | |||||||
ARP 9.25% Senior Notes—due 2021 | 323,957 | 323,916 | |||||||
Total debt | 1,604,597 | 1,542,585 | |||||||
Less current maturities | (104,419 | ) | (1,500 | ) | |||||
Total long-term debt | $ | 1,500,178 | $ | 1,541,085 | |||||
Term Loan Facilities | |||||||||
On February 27, 2015, the Company entered into a credit agreement with Deutsche Bank AG New York Branch, as administrative agent, and the lenders party thereto (the “Credit Agreement”). The Credit Agreement provides for a Secured Senior Interim Term Loan Facility in an aggregate principal amount of $30.0 million (the “Interim Term Loan Facility”) and a Secured Senior Term Loan A Facility in an aggregate principal amount of approximately $97.8 million (the “Term Loan A Facility” and together with the Interim Term Loan Facility, the “Term Loan Facilities”). The proceeds from the issuance of the Term Loan Facilities were used to fund a portion of the Company’s $150.0 million payment to Atlas Energy in connection with the repayment of Atlas Energy’s term loan (see Note 2). At March 31, 2015, $104.4 million was outstanding under the Term Loan Facilities, net of $11.4 million of unamortized discount. The Interim Term Loan Facility matures on August 27, 2015 and the Term Loan A Facility matures on February 26, 2016. The Company’s obligations under the Term Loan Facilities are secured on a first priority basis by security interests in substantially all of the assets of the Company and its material subsidiaries, including all equity interests directly held by the Company, New Atlas Holdings, LLC, or any other guarantor, and all tangible and intangible property. Borrowings under the Term Loan Facilities bear interest, at the Company’s option, at either (i) LIBOR plus 7.5% (“Eurodollar Loans”) or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, in each case plus 6.5% (an “ABR Loan”). Interest is generally payable at interest payment periods selected by the Company for Eurodollar Loans and quarterly for ABR Loans. At March 31, 2015, the weighted average interest rate on outstanding borrowings under the term loan facilities was 8.5%. | |||||||||
The Company has the right at any time to prepay any borrowings outstanding under the Term Loan Facilities, without premium or penalty, provided the Interim Term Loan Facility is repaid prior to the Term Loan A Facility. Through March 31, 2015, the Company has prepaid $11.9 million of borrowings under the Term Loan Facilities. Subject to certain exceptions, the Company may also be required to prepay all or a portion of the Term Loan Facilities in certain instances, including the following: | |||||||||
if, at any time, the Recognized Value Ratio (as defined in the Credit Agreement) is less than 2.00 to 1.00, the Company must prepay the Term Loan Facilities and any revolving loans outstanding in an aggregate principal amount necessary to achieve a Recognized Value Ratio of greater than 2.00 to 1.00; the Recognized Value Ratio is equal to the ratio of the Recognized Value (the sum of the discounted net present values of the Loan Parties’ oil and gas properties and the values of the common units, Class A Units and Class C Units of ARP, determined as set forth in the Credit Agreement) to Total Funded Debt (as defined in the Credit Agreement); | |||||||||
if the Company disposes of all or any portion of the Arkoma Assets (as defined in the Credit Agreement), the Company must prepay the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds resulting from such disposition; | |||||||||
if the Company or any of its restricted subsidiaries dispose of property or assets (including equity interests), the Company must repay the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds from such disposition or casualty event; and | |||||||||
if the Company incurs any debt or issues any equity, it must repay the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds of such issuances or incurrences of debt or issuances of equity. | |||||||||
The Credit Agreement contains customary covenants that limit the Company’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 swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions. The Credit Agreement also requires that the Total Leverage Ratio (as defined in the Credit Agreement) not be greater than (i) as of the last day of any fiscal quarter prior to the full repayment of the Interim Term Loan Facility, 3.75 to 1.00, and (ii) as of the last day of any quarter thereafter, 3.50 to 1.00. Based on the definitions contained in the Credit Agreement, at March 31, 2015, the Company’s Total Leverage Ratio was 3.3 to 1.0. | |||||||||
Atlas Energy Term Loan Facility | |||||||||
On July 31, 2013, Atlas Energy entered into a $240.0 million secured term loan facility with a group of outside investors (the “Term Facility”). At December 31, 2014, $148.1 million of the Term Facility was attributable to the Company. The Term Facility had a maturity date of July 31, 2019. Borrowings under the Term Facility bore interest, at Atlas Energy’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 was generally payable quarterly for ABR loans and, for LIBOR loans at the interest periods selected by Atlas Energy. Atlas Energy was 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 was due. At December 31, 2014, the weighted average interest rate on outstanding borrowings under the Term Facility was 6.5%. | |||||||||
In connection with Atlas Energy’s merger with Targa, the Term Facility was repaid in full on February 27, 2015. | |||||||||
ARP Credit Facility | |||||||||
On February 23, 2015, ARP entered into a Sixth Amendment to its Second Amended and Restated Credit Agreement dated July 31, 2013 with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (the “ARP Credit Agreement”). Among other things, the Sixth Amendment: | |||||||||
· | reduces the borrowing base under the ARP Credit Agreement from $900.0 million to $750.0 million; | ||||||||
· | permits the incurrence of second lien debt in an aggregate principal amount up to $300.0 million; | ||||||||
· | reschedules ARP’s May 1, 2015 borrowing base redetermination for July 1, 2015 | ||||||||
· | if the borrowing base utilization (as defined in the ARP Credit Agreement) is less than 90%, increases the applicable margin on Eurodollar loans and ABR loans by 0.25% from previous levels, | ||||||||
· | following the next scheduled redetermination of the borrowing base, upon the issuance of senior notes or the incurrence of second lien debt, reduces the borrowing base by 25% of the stated amount of such senior notes or additional second lien debt; and | ||||||||
· | revises the maximum ratio of Total Funded Debt to EBITDA to be (i) 5.25 to 1.0 as of the last day of the quarters ended on March 31, 2015, June 30, 2015, September 30, 2015, December 31, 2015 and March 31, 2016, (ii) 5.00 to 1.0 as of the last day of the quarters ended on June 30, 2016, September 30, 2016 and December 31, 2016, (iii) 4.50 to 1.0 as of the last day of the quarter ended on March 31, 2017 and (iv) 4.00 to 1.0 as of the last day of each quarter thereafter. | ||||||||
ARP’s borrowing base is scheduled for semi-annual redeterminations on May 1 and November 1 of each year. At March 31, 2015, $559.0 million was outstanding under the credit facility. Up to $20.0 million of the revolving credit facility may be in the form of standby letters of credit, of which $4.3 million was outstanding at March 31, 2015. ARP’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by certain of ARP’s material subsidiaries, and any non-guarantor subsidiaries of ARP are minor. Borrowings under the credit facility bear interest, at ARP’s election, at either an adjusted LIBOR rate plus an applicable margin between 1.50% and 2.75% per annum or the base rate (which is the higher of the bank’s prime rate, the Federal funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 0.50% and 1.75% per annum. ARP is also required to pay a fee on the unused portion of the borrowing base at a rate of 0.375% per annum if less than 50% of the borrowing base is utilized and 0.5% if 50% or more of the borrowing base is utilized, which is included within interest expense on the Company’s combined consolidated statements of operations. At March 31, 2015, the weighted average interest rate on outstanding borrowings under the credit facility was 2.8%. | |||||||||
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, 2015. The ARP Credit Agreement also requires that ARP maintain a ratio of Total Funded Debt (as defined in the ARP Credit Agreement) to EBITDA (as defined in the ARP Credit Agreement) (actual or annualized, as applicable), calculated over a period of four consecutive fiscal quarters, of not greater than (i) 5.25 to 1.0 as of the last day of the quarters ended on March 31, 2015, June 30, 2015, September 30, 2015, December 31, 2015 and March 31, 2016, (ii) 5.00 to 1.0 as of the last day of the quarters ended on June 30, 2016, September 30, 2016 and December 31, 2016, (iii) 4.50 to 1.0 as of the last day of the quarter ended on March 31, 2017 and (iv) 4.00 to 1.0 as of the last day of each quarter thereafter, and a ratio of current assets (as defined in the ARP Credit Agreement) to current liabilities (as defined in the ARP Credit Agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter. Based on the definitions contained in the ARP Credit Agreement, at March 31, 2015, ARP’s ratio of current assets to current liabilities was 1.6 to 1.0, and its ratio of Total Funded Debt to EBITDA was 4.2 to 1.0. | |||||||||
ARP Term Loan Facility | |||||||||
On February 23, 2015, ARP entered into a Second Lien Credit Agreement with certain lenders and Wilmington Trust, National Association, as administrative agent. The Second Lien Credit Agreement provides for a second lien term loan in an original principal amount of $250.0 million (the “ARP Term Loan Facility”). The ARP Term Loan Facility matures on February 23, 2020. The ARP Term Loan Facility is presented net of unamortized discount of $7.3 million at March 31, 2015. | |||||||||
ARP has the option to prepay the ARP Term Loan Facility at any time, and is required to offer to prepay the ARP Term Loan Facility with 100% of the net cash proceeds from the issuance or incurrence of any debt and 100% of the excess net cash proceeds from certain asset sales and condemnation recoveries. ARP is also required to offer to prepay the ARP Term Loan Facility upon the occurrence of a change of control. All prepayments are subject to the following premiums, plus accrued and unpaid interest: | |||||||||
· | the make-whole premium (plus an additional amount if such prepayment is optional and funded with proceeds from the issuance of equity) for prepayments made during the first 12 months after the closing date; | ||||||||
· | 4.5% of the principal amount prepaid for prepayments made between 12 months and 24 months after the closing date; | ||||||||
· | 2.25% of the principal amount prepaid for prepayments made between 24 months and 36 months after the closing date; and | ||||||||
· | no premium for prepayments made following 36 months after the closing date. | ||||||||
ARP’s obligations under the ARP Term Loan Facility are secured on a second priority basis by security interests in all of its assets and those of its restricted subsidiaries (the “Loan Parties”) that guarantee ARP’s existing first lien revolving credit facility. In addition, the obligations under the ARP Term Loan Facility are guaranteed by ARP’s material restricted subsidiaries. Borrowings under the ARP Term Loan Facility bear interest, at ARP’s option, at either (i) LIBOR plus 9.0% or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, each plus 8.0% (an “ABR Loan”). Interest is generally payable at the applicable maturity date for Eurodollar loans and quarterly for ABR loans. At March 31, 2015, the weighted average interest rate on outstanding borrowings under the term loan facility was 10.0%. | |||||||||
The Second Lien Credit Agreement contains customary covenants that limit ARP’s ability to make restricted payments, take on indebtedness, issue preferred stock, grant liens, conduct sales of assets and subsidiary stock, make distributions from restricted subsidiaries, conduct affiliate transactions and engage in other business activities. In addition, the Second Lien Credit Agreement contains covenants substantially similar to those in ARP’s existing first lien revolving credit facility, including, among others, restrictions on swap agreements, debt of unrestricted subsidiaries, drilling and operating agreements and the sale or discount of receivables. ARP was in compliance with these covenants as of March 31, 2015. | |||||||||
Under the Second Lien Credit Agreement, ARP may elect to add one or more incremental term loan tranches to the ARP Term Loan Facility so long as the aggregate outstanding principal amount of the ARP Term Loan Facility plus the principal amount of any incremental term loan does not exceed $300.0 million and certain other conditions are adhered to. Any such incremental term loans may not mature on a date earlier than February 23, 2020. | |||||||||
Senior Notes | |||||||||
At March 31, 2015, ARP had $374.6 million outstanding of its 7.75% senior unsecured notes due 2021 (“7.75% ARP Senior Notes”). The 7.75% ARP Senior Notes were presented net of a $0.4 million unamortized discount as of March 31, 2015. Interest on the 7.75% ARP Senior Notes is payable semi-annually on January 15 and July 15. At any time prior to January 15, 2016, the 7.75% ARP Senior Notes are redeemable for up to 35% of the outstanding principal amount with the net cash proceeds of equity offerings at the redemption price of 107.75%. The 7.75% ARP Senior Notes are also subject to repurchase at a price equal to 101% of the principal amount, plus accrued and unpaid interest, upon a change of control. At any time prior to January 15, 2017, ARP may redeem the 7.75% ARP Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes plus the Applicable Premium (as defined in the governing indenture), plus accrued and unpaid 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. 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 7.75% ARP Senior Notes. | |||||||||
At March 31, 2015, ARP had $324.0 million outstanding of its 9.25% senior unsecured notes due 2021 (“9.25% ARP Senior Notes”). The 9.25% ARP Senior Notes were presented net of a $1.0 million unamortized discount as of March 31, 2015. Interest on the 9.25% ARP Senior Notes is payable semi-annually on February 15 and August 15. At any time prior to August 15, 2017, ARP may redeem the 9.25% ARP Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes plus the Applicable Premium (as defined in the governing indenture), plus accrued and unpaid interest, if any. 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%. 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 $75.0 million of 9.25% ARP Senior Notes on October 14, 2014, ARP entered into a registration rights agreement whereby it agreed to (a) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated by July 11, 2015. On April 15, 2015, the registration statement relating to the exchange offer for the 9.25% ARP Senior Notes was declared effective, and the exchange offer was subsequently launched on April 15, 2015. | |||||||||
The 7.75% ARP Senior Notes and 9.25% ARP Senior Notes are guaranteed by certain of ARP’s material subsidiaries. The guarantees under the 7.75% ARP Senior Notes and 9.25% ARP Senior Notes are full and unconditional and joint and several and any subsidiaries of ARP, other than the subsidiary guarantors, are minor. There are no restrictions on ARP’s ability to obtain cash or any other distributions of funds from the guarantor subsidiaries. | |||||||||
The indentures governing the 7.75% ARP Senior Notes and 9.25% ARP Senior Notes contain covenants, including limitations of ARP’s ability to incur certain liens, incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase, or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of ARP’s assets. ARP was in compliance with these covenants as of March 31, 2015. | |||||||||
Cash payments for interest by the Company and its subsidiaries were $38.5 million and $28.9 million for the three months ended March 31, 2015 and 2014, respectively. |
Derivative_Instruments
Derivative Instruments | 3 Months Ended | ||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |||||||||||||||||
Derivative Instruments | NOTE 8—DERIVATIVE INSTRUMENTS | ||||||||||||||||
The Company and ARP 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 Company and ARP 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 Company and ARP receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. 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. | |||||||||||||||||
On January 1, 2015, the Company and ARP discontinued hedge accounting for their qualified commodity derivatives. As such, changes in fair value of these derivatives after December 31, 2014 are recognized immediately within gain (loss) on mark-to-market derivatives in the Company’s combined consolidated statements of operations. The fair values of these commodity derivative instruments at December 31, 2014, which were recognized in accumulated other comprehensive income within unitholders’ equity on the Company’s combined consolidated balance sheet, will be reclassified to the Company’s combined consolidated statements of operations in the future at the time the originally hedged physical transactions settle. | |||||||||||||||||
The Company and ARP 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 Company’s combined 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 Company’s combined consolidated balance sheets as the initial value of the options. | |||||||||||||||||
The Company and ARP 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 Company’s combined consolidated balance sheets as assets or liabilities at fair value. The Company reflected net derivative assets on its combined consolidated balance sheets of $333.2 million and $274.9 million at March 31, 2015 and December 31, 2014, respectively. Of the $46.0 million of net gain in accumulated other comprehensive income within unitholders’ equity on the Company’s combined consolidated balance sheet related to derivatives at March 31, 2015, the Company will reclassify $22.6 million of gains to its combined consolidated statement of operations over the next twelve month period as these contracts expire with the remaining gains of $23.4 million gains being reclassified to the Company’s combined consolidated statements of operations in later periods as the remaining contracts expire. During the three months ended March 31, 2014, no amounts were reclassified from other comprehensive income related to derivative instruments entered into during that same period. | |||||||||||||||||
The following table summarizes the commodity derivative activity for the three months ended March 31, 2015 (in thousands): | |||||||||||||||||
Three Months Ended | |||||||||||||||||
March 31, | |||||||||||||||||
2015 | |||||||||||||||||
Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets(1) | $ | (27,343 | ) | ||||||||||||||
Portion of settlements attributable to subsequent mark to market gains | (15,203 | ) | |||||||||||||||
Total cash settlements on commodity derivative contracts | (42,546 | ) | |||||||||||||||
2015 Unrealized gains prior to settlement(2) | 3,203 | ||||||||||||||||
Unrealized gain on open derivative contracts at March 31, 2015, net of amounts recognized in income in prior year(2) | 102,382 | ||||||||||||||||
Gains on mark-to-market derivatives | $ | 105,585 | |||||||||||||||
-1 | Recognized in gas and oil production revenue. | ||||||||||||||||
(2) Recognized in gain on mark-to-market derivatives. | |||||||||||||||||
The Company had $42.5 million of cash settlements during the three months ended March 31, 2015. As the underlying prices and terms in the Company’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, 2015 and 2014 for hedge ineffectiveness. | |||||||||||||||||
The Company | |||||||||||||||||
The following table summarizes the gross fair values of the Company’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company’s combined 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 | Combined | Combined | |||||||||||||||
Consolidated | Consolidated | ||||||||||||||||
Balance Sheets | Balance Sheets | ||||||||||||||||
Offsetting Derivative Assets | |||||||||||||||||
As of March 31, 2015 | |||||||||||||||||
Current portion of derivative assets | $ | 947 | $ | — | $ | 947 | |||||||||||
Total derivative assets | $ | 947 | $ | — | $ | 947 | |||||||||||
As of December 31, 2014 | |||||||||||||||||
Current portion of derivative assets | $ | 2,893 | $ | — | $ | 2,893 | |||||||||||
Long-term portion of derivative assets | 2,669 | 2,669 | |||||||||||||||
Total derivative assets | $ | 5,562 | $ | — | $ | 5,562 | |||||||||||
Gross | Gross | Net Amount of | |||||||||||||||
Amounts of | Amounts | Liabilities | |||||||||||||||
Recognized | Offset in the | Presented in the | |||||||||||||||
Liabilities | Combined | Combined | |||||||||||||||
Consolidated | Consolidated | ||||||||||||||||
Balance Sheets | Balance Sheets | ||||||||||||||||
Offsetting Derivative Liabilities | |||||||||||||||||
As of March 31, 2015 | |||||||||||||||||
Current portion of derivative liabilities | $ | — | $ | — | $ | — | |||||||||||
Total derivative liabilities | $ | — | $ | — | $ | — | |||||||||||
As of December 31, 2014 | |||||||||||||||||
Current portion of derivative liabilities | $ | — | $ | — | $ | — | |||||||||||
Total derivative liabilities | $ | — | $ | — | $ | — | |||||||||||
At March 31, 2015, the Company had the following commodity derivatives: | |||||||||||||||||
Natural Gas Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
March 31, | |||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | |||||||||||||||
2015 | 570,000 | $ | 4.302 | $ | 947 | ||||||||||||
The Company’s net asset | $ | 947 | |||||||||||||||
(1) | “MMBtu” represents million British Thermal Units. | ||||||||||||||||
(2) | Fair value based on forward NYMEX natural gas prices, as applicable. | ||||||||||||||||
During the three months ended March 31, 2015, the Company received approximately $4.9 million in net proceeds from the early termination of natural gas and oil derivative positions for production periods from 2015 through 2018. The net proceeds from the early termination of these derivatives were used to reduce indebtedness under the Company’s Term Loan Facilities (see Note 7). | |||||||||||||||||
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 Company’s combined 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 Combined | |||||||||||||||
Assets | Combined | Consolidated | |||||||||||||||
Consolidated | Balance Sheets | ||||||||||||||||
Balance Sheets | |||||||||||||||||
Offsetting Derivative Assets | |||||||||||||||||
As of March 31, 2015 | |||||||||||||||||
Current portion of derivative assets | $ | 145,520 | $ | (21 | ) | $ | 145,499 | ||||||||||
Long-term portion of derivative assets | 186,916 | (198 | ) | 186,718 | |||||||||||||
Total derivative assets | $ | 332,436 | $ | (219 | ) | 332,217 | |||||||||||
As of December 31, 2014 | |||||||||||||||||
Current portion of derivative assets | $ | 141,464 | $ | (98 | ) | $ | 141,366 | ||||||||||
Long-term portion of derivative assets | 128,303 | (370 | ) | 127,933 | |||||||||||||
Total derivative assets | $ | 269,767 | $ | (468 | ) | $ | 269,299 | ||||||||||
Gross | Gross | Net Amount of | |||||||||||||||
Amounts of | Amounts | Liabilities Presented | |||||||||||||||
Recognized | Offset in the | in the Combined | |||||||||||||||
Liabilities | Combined | Consolidated | |||||||||||||||
Consolidated | Balance Sheets | ||||||||||||||||
Balance Sheets | |||||||||||||||||
Offsetting Derivative Liabilities | |||||||||||||||||
As of March 31, 2015 | |||||||||||||||||
Current portion of derivative liabilities | $ | (21 | ) | $ | 21 | $ | — | ||||||||||
Long-term portion of derivative liabilities | (198 | ) | 198 | — | |||||||||||||
Total derivative liabilities | $ | (219 | ) | $ | 219 | $ | — | ||||||||||
As of December 31, 2014 | |||||||||||||||||
Current portion of derivative liabilities | $ | (98 | ) | $ | 98 | $ | — | ||||||||||
Long-term portion of derivative liabilities | (370 | ) | 370 | — | |||||||||||||
Total derivative liabilities | $ | (468 | ) | $ | 468 | $ | — | ||||||||||
At March 31, 2015, ARP had the following commodity derivatives: | |||||||||||||||||
Natural Gas – Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | |||||||||||||||
2015 | 40,053,400 | $ | 4.21 | $ | 56,994 | ||||||||||||
2016 | 53,546,300 | $ | 4.229 | 59,049 | |||||||||||||
2017 | 49,920,000 | $ | 4.219 | 42,447 | |||||||||||||
2018 | 40,800,000 | $ | 4.17 | 28,182 | |||||||||||||
2019 | 15,960,000 | $ | 4.017 | 7,319 | |||||||||||||
$ | 193,991 | ||||||||||||||||
Natural Gas – Costless Collars | |||||||||||||||||
Production | Option Type | Volumes | Average Floor | Fair Value | |||||||||||||
Period Ending | and Cap | Asset/ | |||||||||||||||
December 31, | (Liability) | ||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | |||||||||||||||
2015 | Puts purchased | 2,520,000 | $ | 4.21 | $ | 3,670 | |||||||||||
2015 | Calls sold | 2,520,000 | $ | 5.09 | (16 | ) | |||||||||||
$ | 3,654 | ||||||||||||||||
Natural Gas – Put Options – Drilling Partnerships | |||||||||||||||||
Production | Option Type | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | |||||||||||||||
2015 | Puts purchased | 1,080,000 | $ | 4 | $ | 1,328 | |||||||||||
2016 | Puts purchased | 1,440,000 | $ | 4.15 | 1,633 | ||||||||||||
$ | 2,961 | ||||||||||||||||
Natural Gas – WAHA Basis Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(7) | |||||||||||||||
2015 | 3,600,000 | $ | (0.090 | ) | $ | 239 | |||||||||||
$ | 239 | ||||||||||||||||
Natural Gas Liquids – Natural Gasoline Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(8) | |||||||||||||||
2015 | 3,780,000 | $ | 1.956 | $ | 3,122 | ||||||||||||
$ | 3,122 | ||||||||||||||||
Natural Gas Liquids – Propane Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(4) | |||||||||||||||
2015 | 6,048,000 | $ | 1.016 | $ | 2,896 | ||||||||||||
$ | 2,896 | ||||||||||||||||
Natural Gas Liquids – Butane Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(5) | |||||||||||||||
2015 | 1,134,000 | $ | 1.248 | $ | 676 | ||||||||||||
$ | 676 | ||||||||||||||||
Natural Gas Liquids – Iso Butane Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(6) | |||||||||||||||
2015 | 1,134,000 | $ | 1.263 | $ | 689 | ||||||||||||
$ | 689 | ||||||||||||||||
Natural Gas Liquids – Crude Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | |||||||||||||||
2016 | 84,000 | $ | 85.651 | $ | 2,274 | ||||||||||||
2017 | 60,000 | $ | 83.78 | 1,315 | |||||||||||||
$ | 3,589 | ||||||||||||||||
Crude Oil – Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | |||||||||||||||
2015 | 1,444,500 | $ | 87.585 | $ | 50,453 | ||||||||||||
2016 | 1,425,000 | $ | 83.496 | 35,544 | |||||||||||||
2017 | 1,140,000 | $ | 77.285 | 17,766 | |||||||||||||
2018 | 1,080,000 | $ | 76.281 | 13,804 | |||||||||||||
2019 | 540,000 | $ | 68.371 | $ | 2,196 | ||||||||||||
$ | 119,763 | ||||||||||||||||
Crude Oil – Costless Collars | |||||||||||||||||
Production | Option Type | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Floor | Asset/ | |||||||||||||||
December 31, | and Cap | (Liability) | |||||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | |||||||||||||||
2015 | Puts purchased | 19,500 | $ | 83.846 | $ | 638 | |||||||||||
2015 | Calls sold | 19,500 | $ | 110.654 | (1 | ) | |||||||||||
$ | 637 | ||||||||||||||||
ARP’s net assets | $ | 332,217 | |||||||||||||||
-1 | “MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons. | ||||||||||||||||
(2) | Fair value based on forward NYMEX natural gas prices, as applicable. | ||||||||||||||||
-3 | Fair value based on forward WTI crude oil prices, as applicable. | ||||||||||||||||
-4 | Fair value based on forward Mt. Belvieu propane prices, as applicable. | ||||||||||||||||
-5 | Fair value based on forward Mt. Belvieu butane prices, as applicable. | ||||||||||||||||
(6) | Fair value based on forward Mt. Belvieu iso butane prices, as applicable. | ||||||||||||||||
(7) | Fair value based on forward WAHA natural gas prices, as applicable | ||||||||||||||||
(8) | Fair value based on forward Mt. Belvieu natural gasoline prices, as applicable. | ||||||||||||||||
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, 2015, net unrealized derivative assets of $3.0 million were payable to the limited partners in the Drilling Partnerships related to these natural gas put option contracts. | |||||||||||||||||
At March 31, 2015, 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 7), 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. |
Fair_Value_of_Financial_Instru
Fair Value of Financial Instruments | 3 Months Ended | ||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||||||
Fair Value of Financial Instruments | NOTE 9—FAIR VALUE OF FINANCIAL INSTRUMENTS | ||||||||||||||||
The Company 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 Company’s 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 Company and ARP use a market approach fair value methodology to value the assets and liabilities for their outstanding derivative contracts (see Note 8) and the Company’s rabbi trust assets (see Note 14). The Company and ARP manage and report derivative assets and liabilities on the basis of their exposure to market risks and credit risks by counterparty. The Company’s and ARP’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. These derivative instruments are calculated by utilizing commodity indices quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument. Investments held in the Company’s rabbi trust are publicly traded equity and debt securities and are therefore defined as Level 1 fair value measurements. | |||||||||||||||||
Information for the Company’s and ARP’s assets and liabilities measured at fair value at March 31, 2015 and December 31, 2014 was as follows (in thousands): | |||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||||
As of March 31, 2015 | |||||||||||||||||
Assets, gross | |||||||||||||||||
Rabbi trust | $ | 5,641 | $ | — | $ | — | $ | 5,641 | |||||||||
Commodity swaps | — | 947 | — | 947 | |||||||||||||
ARP Commodity swaps | — | 325,167 | — | 325,167 | |||||||||||||
ARP Commodity puts | — | 2,961 | — | 2,961 | |||||||||||||
ARP Commodity options | — | 4,308 | — | 4,308 | |||||||||||||
Total assets, gross | 5,641 | 333,383 | — | 339,024 | |||||||||||||
Liabilities, gross | |||||||||||||||||
Commodity swaps | — | — | — | — | |||||||||||||
ARP Commodity swaps | — | (202 | ) | — | (202 | ) | |||||||||||
ARP Commodity options | — | (17 | ) | — | (17 | ) | |||||||||||
Total derivative liabilities, gross | — | (219 | ) | — | (219 | ) | |||||||||||
Total assets, fair value, net | $ | 5,641 | $ | 333,164 | $ | — | $ | 338,805 | |||||||||
As of December 31, 2014 | |||||||||||||||||
Assets, gross | |||||||||||||||||
Rabbi trust | $ | 3,925 | $ | — | $ | — | $ | 3,925 | |||||||||
Commodity swaps | — | 5,562 | — | 5,562 | |||||||||||||
ARP Commodity swaps | — | 261,680 | — | 261,680 | |||||||||||||
ARP Commodity puts | — | 2,767 | — | 2,767 | |||||||||||||
ARP Commodity options | — | 5,320 | — | 5,320 | |||||||||||||
Total assets, gross | 3,925 | 275,329 | — | 279,254 | |||||||||||||
Liabilities, gross | |||||||||||||||||
Commodity swaps | — | — | — | — | |||||||||||||
ARP Commodity swaps | — | (401 | ) | — | (401 | ) | |||||||||||
ARP Commodity options | — | (67 | ) | — | (67 | ) | |||||||||||
Total derivative liabilities, gross | — | (468 | ) | — | (468 | ) | |||||||||||
Total assets, fair value, net | $ | 3,925 | $ | 274,861 | $ | — | $ | 278,786 | |||||||||
Other Financial Instruments | |||||||||||||||||
The estimated fair values of the Company’s and its subsidiaries’ other financial instruments have been determined based upon their assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Company and its subsidiaries could realize upon the sale or refinancing of such financial instruments. | |||||||||||||||||
The Company’s and its subsidiaries’ other current assets and liabilities on its combined 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 Company’s and ARP’s debt at March 31, 2015 and December 31, 2014, which consist principally of ARP’s senior notes, borrowings under the Company’s term loan facilities, and borrowings under ARP’s term loan and revolving credit facilities, were $1,402.2 million and $1,363.4 million, respectively, compared with the carrying amounts of $1,604.6 million and $1,542.6 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 senior notes were based upon the market approach and calculated using the yields of the ARP senior notes as provided by financial institutions and thus were categorized as Level 3 values. | |||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis | |||||||||||||||||
The Company and its subsidiaries 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 Company and its subsidiaries and estimated inflation rates (see Note 6). | |||||||||||||||||
Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the three months ended March 31, 2015 and 2014 was as follows (in thousands): | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2015 | 2014 | ||||||||||||||||
Level 3 | Total | Level 3 | Total | ||||||||||||||
Asset retirement obligations | $ | 169 | $ | 169 | $ | 602 | $ | 602 | |||||||||
Total | $ | 169 | $ | 169 | $ | 602 | $ | 602 | |||||||||
The Company and its subsidiaries estimate the fair value of their 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. No impairments were recognized during the three months ended March 31, 2015 and 2014. | |||||||||||||||||
During the year ended December 31, 2014, ARP completed the Eagle Ford, Rangely and GeoMet acquisitions and the Development Subsidiary completed the Eagle Ford Acquisition (see Note 3). The fair value measurements of assets acquired and liabilities assumed for each of these acquisitions are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The estimated fair values of the assets acquired and liabilities assumed in the Eagle Ford and Rangely acquisitions as of the acquisition date, which are reflected in the Company’s combined consolidated balance sheet as of March 31, 2015 are subject to change as the final valuations have not yet been completed, and such changes could 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 Company’s and its subsidiaries’ existing methodology for recognizing an estimated liability for the plugging and abandonment of their gas and oil wells (see Note 6). These inputs require significant judgments and estimates by the Company’s and its subsidiaries’ management at the time of the valuation and are subject to change. |
Certain_Relationships_and_Rela
Certain Relationships and Related Party Transactions | 3 Months Ended |
Mar. 31, 2015 | |
Related Party Transactions [Abstract] | |
Certain Relationships And Related Party Transactions | NOTE 10—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS |
Relationship with Drilling Partnerships. ARP conducts certain activities through, and a portion of its revenues are attributable to, sponsorship of 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. | |
Commitments_and_Contingencies
Commitments and Contingencies | 3 Months Ended |
Mar. 31, 2015 | |
Commitments And Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | NOTE 11—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. ARP has structured certain Drilling Partnerships to allow limited partners to have the right to present their interests for purchase. Generally for Drilling Partnerships with this structure, ARP is not obligated to purchase more than 5% to 10% of the units in any calendar year, no units may be purchased during the first five years after closing for the Drilling Partnership, and ARP may immediately suspend the presentment structure for a Drilling Partnership by giving notice to the limited partners that it does not have adequate liquidity for redemptions. In accordance with the Drilling Partnership agreement, the purchase price for limited partner interests would generally be based upon a percentage of the present value of future cash flows allocable to the interest, discounted at 10%, as of the date of presentment, subject to estimated changes by ARP to reflect current well performance, commodity prices and production costs, among other items. Based on its historical experience, as of March 31, 2015, the management of ARP believes that any such estimated liability for redemptions of limited partner interests in Drilling Partnerships which allow such transactions would not be material. | |
While its historical structure has varied, ARP has generally agreed to subordinate a portion of its share of Drilling Partnership gas and oil production revenue, net of corresponding production costs and up to a maximum of 50% of unhedged revenue, from certain Drilling Partnerships for the benefit of the limited partner investors until they have received specified returns, typically 10% to 12% per year determined on a cumulative basis, over a specified period, typically the first five to eight years, in accordance with the terms of the partnership agreements. ARP periodically compares the projected return on investment for limited partners in a Drilling Partnership during the subordination period, based upon historical and projected cumulative gas and oil production revenue and expenses, with the return on investment subject to subordination agreed upon within the Drilling Partnership agreement. If the projected return on investment falls below the agreed upon rate, ARP recognizes subordination as an estimated reduction of its pro-rata share of gas and oil production revenue, net of corresponding production costs, during the current period in an amount that will achieve the agreed upon investment return, subject to the limitation of 50% of unhedged cumulative net production revenues over the subordination period. For Drilling Partnerships for which ARP has recognized subordination in a historical period, if projected investment returns subsequently reflect that the agreed upon limited partner investment return will be achieved during the subordination period, ARP will recognize an estimated increase in its portion of historical cumulative gas and oil net production, subject to a limitation of the cumulative subordination previously recognized. For the three months ended March 31, 2015 and 2014, $0.5 million and $3.5 million, respectively, of ARP’s gas and oil production revenues, net of corresponding production costs, from certain Drilling Partnerships were subordinated, which reduced gas and oil production revenues and expenses. | |
In connection with the Eagle Ford Acquisition (see Note 3), ARP guaranteed the timely payment of the deferred portion of the purchase price that is to be paid by the Development Subsidiary. Pursuant to the agreement between ARP and the Development Subsidiary, ARP will have the right to receive some or all of the assets acquired by the Development Subsidiary in the event of its failure to contribute its portion of any deferred payments. ARP’s and the Development Subsidiary’s deferred purchase obligations are included within deferred acquisition purchase price on the Company’s combined consolidated balance sheets at March 31, 2015 and December 31, 2014 (see Note 3). | |
In connection with ARP’s GeoMet 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, 2015 were as follows: 2015— $2.3 million; 2016— $2.3 million; 2017— $1.9 million; 2018— $1.8 million; 2019— $1.8 million; thereafter— $6.5 million. | |
In connection with ARP’s acquisition of assets from EP Energy E&P Company, L.P. on July 31, 2013 (the “EP Energy Acquisition”), ARP acquired certain long-term annual firm transportation obligations. Estimated fixed and determinable portions of ARP’s firm transportation obligations as of March 31, 2015 were as follows: 2015— $6.2 million; 2016— $2.1 million; and 2017 to 2019— none. | |
As of March 31, 2015, the Company and its subsidiaries are committed to expend approximately $4.1 million on drilling and completion expenditures. | |
Legal Proceedings | |
The Company and its subsidiaries are parties to various routine legal proceedings arising out of the ordinary course of its business. Management of the Company and its subsidiaries believe that none of these actions, individually or in the aggregate, will have a material adverse effect on the Company’s financial condition or results of operations. |
Issuances_of_Units
Issuances of Units | 3 Months Ended |
Mar. 31, 2015 | |
Proceeds From Issuance Or Sale Of Equity [Abstract] | |
Issuances of Units | NOTE 12—ISSUANCES OF UNITS |
The Company recognizes gains on ARP’s and the Development Subsidiary’s equity transactions as credits to unitholders’ equity on its combined consolidated balance sheets rather than as income on its combined consolidated statements of operations. These gains represent the Company’s portion of the excess net offering price per unit of each of ARP’s and the Development Subsidiary’s common units over the book carrying amount per unit (see Note 2). | |
On February 27, 2015 the Company issued and sold an aggregate of 1.6 million of its newly created Series A convertible preferred units, with a liquidation preference of $25.00 per unit (the “Series A Preferred Units”), at a purchase price of $25.00 per unit to certain members of the Company’s management, two management members of the Board, and outside investors. Holders of the Series A Preferred Units are entitled to monthly distributions of cash at a rate equal to the greater of (i) 10% of the liquidation preference per annum, increasing to 12% per annum, 14% per annum and 16% per annum on the first, second and third anniversaries of the of the private placement, respectively or (ii) the monthly equivalent of any cash distribution declared by the Company to holders of the Company’s common units, as well as Series A Preferred Units at a rate equal to 2% of the liquidation preference per annum. All or a portion of the Series A Preferred Units will be convertible into the Company’s units at the option of the holder at any time following the later of (i) the one year anniversary of the distribution and (ii) receipt of unitholder approval. The conversion price will be equal to the greater of (i) $8.00 per common unit of the Company; and (ii) the lower of (a) 110.0% of the volume weighted average price for the Company’s common units on the NYSE over the 30 trading days following the distribution date; and (b) $16.00 per common unit of the Company. The Company sold the Series A Preferred Units in a private transaction exempt from registration under Section 4(2) of the Securities Act. The Series A Preferred Units resulted in proceeds to the Company of $40.0 million. The Company used the proceeds to fund a portion of the $150.0 million payment by the Company to Atlas Energy related to the repayment of Atlas Energy’s term loan (see Note 2). The Series A Purchase Agreement contains customary terms for private placements, including representations, warranties, covenants and indemnities. | |
Atlas Resource Partners | |
Equity Offerings | |
In October 2014, in connection with the Eagle Ford Acquisition (see Note 3), ARP issued 3,200,000 8.625% Class D Preferred Units at a public offering price of $25.00 per Class D ARP Preferred Units, yielding net proceeds of approximately $77.3 million from the offering, after deducting underwriting discounts and estimated offering expenses. ARP used the net proceeds from the offering to fund a portion of the Eagle Ford Acquisition. On March 31, 2015, to partially pay its portion of the quarterly installment related to the Eagle Ford Acquisition, ARP issued an additional 800,000 Class D ARP Preferred Units to the seller at a value of $25.00 per unit. On January 15, 2015, ARP paid an initial quarterly distribution of $0.616927 per unit for the extended period from October 2, 2014 through January 14, 2015 to holders of record as of January 2, 2015 (see Note 13). ARP will pay future cumulative distributions on a quarterly basis, at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference. | |
The Class D ARP Preferred Units rank senior to ARP’s common units and Class C ARP Preferred Units with respect to the payment of distributions and distributions upon a liquidation event and equal with ARP’s Class B convertible preferred units. The Class D ARP Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by ARP or converted into its common units in connection with a change in control. At any time on or after October 15, 2019, ARP may, at its option, redeem the Class D ARP Preferred Units in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, ARP may redeem the Class D ARP Preferred Units following certain changes of control, as described in the Certificate of Designation. If ARP does not exercise this redemption option upon a change of control, then holders of the Class D ARP Preferred Units will have the option to convert the Class D ARP Preferred Units into a number of ARP common units per Class D unit as set forth in the Certificate of Designation. If ARP exercises any of its redemption rights relating to the Class D ARP Preferred Units, the holders of such Class D ARP Preferred Units will not have the conversion right described above with respect to the Class D ARP Preferred Units called for redemption. | |
In August 2014, ARP entered into an equity distribution agreement with Deutsche Bank Securities Inc., as representative of the several banks named therein (the “Agents”). Pursuant to the equity distribution agreement, ARP may sell from time to time through the Agents common units representing limited partner interests of ARP having an aggregate offering price of up to $100.0 million. Sales of common units, if any, may be made in negotiated transactions or transactions that are deemed to be “at-the-market” offerings as defined in Rule 415 of the Securities Act, including sales made directly on the New York Stock Exchange, the existing trading market for the common units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. ARP will pay each of the Agents a commission, which in each case shall not be more than 2.0% of the gross sales price of common units sold through such Agent. Under the terms of the equity distribution agreement, ARP may also sell common units from time to time to any Agent as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to an Agent as principal would be pursuant to the terms of a separate terms agreement between ARP and such Agent. During the three months ended March 31, 2015, ARP issued 420,586 common limited partner units under the equity distribution program for net proceeds of $3.3 million, net of $0.1 million in commissions paid. | |
In May 2014, in connection with the Rangely Acquisition (see Note 3), ARP issued 15,525,000 of its common limited partner units (including 2,025,000 units pursuant to an over-allotment option) in a public offering at a price of $19.90 per unit, yielding net proceeds of approximately $297.3 million. | |
In March 2014, in connection with the GeoMet Acquisition (see Note 3), 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. | |
In connection with the issuance of ARP’s unit offerings during the three months ended March 31, 2015, the Company recorded losses of $0.2 million within unitholders’ equity and a corresponding decrease in non-controlling interests on its combined consolidated balance sheet and combined consolidated statement of unitholders’/owner’s equity. For the year ended December 31, 2014, the Company recorded gains of $40.5 million within equity and a corresponding decrease in non-controlling interests on its combined consolidated balance sheets and combined consolidated statement of equity. |
Cash_Distributions
Cash Distributions | 3 Months Ended | |||||||||||||||||||
Mar. 31, 2015 | ||||||||||||||||||||
Distributions Made To Members Or Limited Partners [Abstract] | ||||||||||||||||||||
Cash Distributions | NOTE 13—CASH DISTRIBUTIONS | |||||||||||||||||||
The Company’s Cash Distributions. The Company has a cash distribution policy under which it distributes, within 50 days following the end of each calendar quarter, all of its available cash (as defined in its limited liability company agreement) for that quarter to its unitholders. | ||||||||||||||||||||
On April 22, 2015, the Company declared a monthly distribution of $0.3 million for the month ended March 31, 2015 related to its Series A Preferred Units. The distribution will be paid on May 15, 2015 to unitholders of record at the close of business on May 8, 2015. | ||||||||||||||||||||
ARP Cash Distributions. In January 2014, ARP’s board of directors approved the modification of its cash distribution payment practice to a monthly cash distribution program whereby it distributes all of its available cash (as defined in the partnership agreement) for that month to its unitholders within 45 days from the month end. Prior to that, ARP paid quarterly cash distributions within 45 days from the end of each calendar quarter. If ARP’s common unit distributions in any quarter exceed specified target levels, the Company will receive between 13% and 48% of such distributions in excess of the specified target levels. Distributions declared by ARP from January 1, 2014 through March 31, 2015 were as follows (in thousands, except per unit amounts): | ||||||||||||||||||||
Date Cash Distribution Paid | For Month | Cash | Total Cash | Total Cash | Total Cash | |||||||||||||||
Ended | Distribution | Distribution | Distribution | Distribution | ||||||||||||||||
per Common | to Common | To Preferred | to the General | |||||||||||||||||
Limited | Limited | Limited | Partner’s | |||||||||||||||||
Partner Unit | Partners | Partners | Class | |||||||||||||||||
A Units | ||||||||||||||||||||
17-Mar-14 | 31-Jan-14 | $ | 0.1933 | $ | 12,718 | $ | 1,467 | $ | 1,055 | |||||||||||
14-Apr-14 | 28-Feb-14 | $ | 0.1933 | $ | 12,719 | $ | 1,466 | $ | 1,055 | |||||||||||
15-May-14 | 31-Mar-14 | $ | 0.1933 | $ | 12,719 | $ | 1,466 | $ | 1,054 | |||||||||||
13-Jun-14 | 30-Apr-14 | $ | 0.1933 | $ | 15,752 | $ | 1,466 | $ | 1,279 | |||||||||||
15-Jul-14 | 31-May-14 | $ | 0.1933 | $ | 15,752 | $ | 1,466 | $ | 1,279 | |||||||||||
14-Aug-14 | 30-Jun-14 | $ | 0.1966 | $ | 16,029 | $ | 1,492 | $ | 1,377 | |||||||||||
12-Sep-14 | 31-Jul-14 | $ | 0.1966 | $ | 16,028 | $ | 1,493 | $ | 1,378 | |||||||||||
15-Oct-14 | 31-Aug-14 | $ | 0.1966 | $ | 16,032 | $ | 1,491 | $ | 1,378 | |||||||||||
14-Nov-14 | 30-Sep-14 | $ | 0.1966 | $ | 16,032 | $ | 1,492 | $ | 1,378 | |||||||||||
15-Dec-14 | 31-Oct-14 | $ | 0.1966 | $ | 16,033 | $ | 1,491 | $ | 1,378 | |||||||||||
14-Jan-15 | 30-Nov-14 | $ | 0.1966 | $ | 16,779 | $ | 745 | -1 | $ | 1,378 | ||||||||||
13-Feb-15 | 31-Dec-14 | $ | 0.1966 | $ | 16,782 | $ | 745 | -1 | $ | 1,378 | ||||||||||
17-Mar-15 | 31-Jan-15 | $ | 0.1083 | $ | 9,284 | $ | 643 | -1 | $ | 203 | ||||||||||
14-Apr-15 | 28-Feb-15 | $ | 0.1083 | $ | 9,347 | $ | 643 | -1 | $ | 204 | ||||||||||
-1 | Excludes the Class D preferred unit quarterly distribution (see Note 12). | |||||||||||||||||||
At December 31, 2014, ARP had 3.2 million of its 8.625% Class D ARP Preferred Units outstanding (see Note 12). On January 15, 2015, ARP paid an initial quarterly distribution of $0.616927 per unit for the extended period from October 2, 2014 through January 14, 2015 to holders of record as of January 2, 2015. | ||||||||||||||||||||
At March 31, 2015, ARP had 4.0 million of its 8.625% Class D ARP Preferred Units outstanding (see Note 12). On April 15, 2015, ARP paid a quarterly distribution of $0.539063 per unit for the first quarter of 2015 to holders of record as of April 1, 2015. | ||||||||||||||||||||
On April 22, 2015, ARP declared a monthly distribution of $0.1083 per common unit for the month of March 31, 2015. The $10.3 million distribution, including $0.2 million and $0.6 million to the general partner and preferred limited partners, respectively, will be paid on May 15, 2015 to unitholders of record at the close of business on May 8, 2015. | ||||||||||||||||||||
Benefit_Plans
Benefit Plans | 3 Months Ended | ||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |||||||||||||||||
Benefit Plans | NOTE 14—BENEFIT PLANS | ||||||||||||||||
2015 Long-Term Incentive Plan | |||||||||||||||||
The Board of Directors of the Company approved and adopted the Company’s 2015 Long-Term Incentive Plan (“2015 LTIP”) effective February 2015. The 2015 LTIP provides equity incentive awards to officers, employees and managing board members of the Company and its affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for the Company. The 2015 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”). Under the 2015 LTIP, the LTIP Committee may grant awards of phantom units, restricted units or unit options for an aggregate of 5,250,000 units. At March 31, 2015, the Company had 68,910 phantom units and unit options outstanding under the 2015 LTIP, with 5,181,090 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 2015 LTIP, upon the eligible employee’s termination of employment without “cause”, as defined in the 2015 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 LTIP Committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any Participant, subject to the terms of any award agreements and employment agreements to which the Company (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 a parent, subsidiary 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 shall vest (and, with respect to options, become exercisable) as to the 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 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 as the LTIP Committee deems necessary or appropriate. | ||||||||||||||||
2015 Phantom Units. A phantom unit entitles a Participant to receive a Company common unit or its then-Fair Market Value in cash or other securities or property, upon vesting of the phantom unit. In tandem with phantom unit grants, the LTIP Committee may grant Distribution Equivalent Rights (“DERs”), which are the right to receive cash, securities, or property per phantom unit in an amount equal to, and at the same time as, the cash distributions or other distributions of securities or property the Company makes on a common unit during the period such phantom unit is outstanding. Generally, phantom units to be granted to employees under the 2015 LTIP will vest over a designated period of time 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 2015 LTIP at March 31, 2015, there are 17,226 units that will vest within the following twelve months. All phantom units outstanding under the 2015 LTIP at March 31, 2015 include DERs. No amounts were paid during the three months ended March 31, 2015 and 2014 with respect to DERs. | |||||||||||||||||
The following table sets forth the 2015 LTIP phantom unit activity for the periods indicated: | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2015 | 2014 | ||||||||||||||||
Number | Weighted | Number | Weighted | ||||||||||||||
of Units | Average | of Units | Average | ||||||||||||||
Grant Date | Grant Date | ||||||||||||||||
Fair Value | Fair Value | ||||||||||||||||
Outstanding, beginning of year | — | $ | — | — | $ | — | |||||||||||
Granted | 68,910 | 9.07 | — | — | |||||||||||||
Vested and issued(1) | — | — | — | — | |||||||||||||
Forfeited | — | — | — | — | |||||||||||||
Outstanding, end of period(2)(3)(4) | 68,910 | $ | 9.07 | — | $ | — | |||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 20 | $ | — | |||||||||||||
(1) | No phantom unit awards vested during the three months ended March 31, 2015 and 2014. | ||||||||||||||||
(2) | The aggregate intrinsic value of phantom unit awards outstanding at March 31, 2015 was approximately $414,000. | ||||||||||||||||
(3) | There was approximately $20,000 recognized as liabilities on the Company’s consolidated balance sheet at March 31, 2015 representing 68,910 units, 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 $9.07 at March 31, 2015. | ||||||||||||||||
(4) | No phantom unit awards had vested, but had not yet been issued at March 31, 2015 and 2014. | ||||||||||||||||
At March 31, 2015, the Company had approximately $0.4 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2015 LTIP based upon the fair value of the awards which is expected to be recognized over a weighted average period of 2.3 years. | |||||||||||||||||
2015 Unit Options. A unit option entitles a Participant to receive a common unit of the Company upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option shall not be less than the fair market value of the Company’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 to be granted under the 2015 LTIP will vest over a designated period of time. There are no unit options outstanding under the 2015 LTIP at March 31, 2015. No cash was received from the exercise of options for the three months ended March 31, 2015 and 2014, respectively. | |||||||||||||||||
Restricted Units | |||||||||||||||||
Restricted units are actual common units issued to a participant that are subject to vesting restrictions and evidenced in such manner as the LTIP Committee may deem appropriate, including book-entry registration or issuance of one or more unit certificates. Prior to or upon the grant of an award of restricted units, the LTIP Committee will condition the vesting or transferability of the restricted units upon continued service, the attainment of performance goals or both. A holder of restricted units will have certain rights of holders of common units in general, including the right to vote the restricted units. However, during the period in which the restricted units are subject to vesting restrictions, the holder will not be permitted to sell, assign, transfer, pledge or otherwise encumber the restricted units. | |||||||||||||||||
Rabbi Trust | |||||||||||||||||
In 2011, the Company established an excess 401(k) plan relating to certain executives. In connection with the plan, the Company established a “rabbi” trust for the contributed amounts. At March 31, 2015 and December 31, 2014, the Company reflected $5.6 million and $3.9 million, respectively, related to the value of the rabbi trust within other assets, net on its combined consolidated balance sheets, and recorded corresponding liabilities of $5.6 million and $3.9 million as of those same dates within asset retirement obligations and other on its combined consolidated balance sheets. During the three months ended March 31, 2015 and 2014, no distributions were made to participants related to the rabbi trust. | |||||||||||||||||
ARP Long-Term Incentive Plan | |||||||||||||||||
ARP’s 2012 Long-Term Incentive Plan (the “ARP LTIP”), effective March 2012, provides incentive awards to officers, employees and directors as well as employees of the Company and its affiliates, consultants and joint venture partners who perform services for ARP. The ARP LTIP is administered by the board of the Company, a committee of the board or the board (or committee of the board) of an affiliate (the “ARP LTIP Committee”). Under ARP’s 2012 LTIP, the ARP LTIP Committee may grant awards of phantom units, restricted units, or unit options for an aggregate of 2,900,000 common limited partner units of ARP. At March 31, 2015, ARP had 2,085,310 phantom units, restricted units and unit options outstanding under the ARP LTIP with 135,663 phantom units, restricted units and unit options available for grant. Share based payments to non-employee directors, which have a cash settlement option, are recognized within liabilities in the consolidated financial statements based upon their current fair market value. | |||||||||||||||||
In the case of awards held by eligible employees, following a “change in control”, as defined in the ARP LTIP, upon the eligible employee’s termination of employment without “cause”, as defined in the ARP LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the option. Upon a change in control, all unvested awards held by directors will immediately vest in full. | |||||||||||||||||
In connection with a change in control, the ARP LTIP Committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any participant, but subject to the terms of any award agreements and employment agreements to which the Company, 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 represent rights to receive a common unit, an amount of cash or other securities or property based on the value of a common unit, or a combination of common units and cash or other securities or property upon vesting. Phantom units are subject to terms and conditions determined by the ARP LTIP Committee, which may include vesting restrictions. In tandem with phantom unit grants, the ARP LTIP Committee may grant DERs, which are the right to receive an amount in cash, securities, or other property equal to, and at the same time as, the cash distributions or other distributions of securities or other property made by ARP with respect to a common unit during the period that the underlying phantom unit is outstanding. 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, 2015, 194,224 units will vest within the following twelve months. All phantom units outstanding under the ARP LTIP at March 31, 2015 include DERs. During the three months ended March 31, 2015 and 2014, ARP paid $0.4 million and $0.6 million, respectively, with respect to the ARP LTIP’s DERs. These amounts were recorded as reductions of equity on the Company’s combined consolidated balance sheets. | |||||||||||||||||
The following table sets forth the ARP LTIP phantom unit activity for the periods indicated: | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2015 | 2014 | ||||||||||||||||
Number | Weighted | Number | Weighted | ||||||||||||||
of Units | Average | of Units | Average | ||||||||||||||
Grant Date | Grant Date | ||||||||||||||||
Fair Value | Fair Value | ||||||||||||||||
Outstanding, beginning of year | 799,192 | $ | 22.7 | 839,808 | $ | 24.31 | |||||||||||
Granted | — | — | 3,500 | 20.99 | |||||||||||||
Vested and issued(1) | (167,182 | ) | 23.97 | (15,500 | ) | 22.69 | |||||||||||
Forfeited | — | — | (15,500 | ) | 22.63 | ||||||||||||
Outstanding, end of period(2)(3) | 632,010 | $ | 22.37 | 812,308 | $ | 24.35 | |||||||||||
Vested and not yet issued(4) | 110,125 | $ | 24.67 | 6,875 | $ | 22.76 | |||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 2,514 | $ | 1,731 | |||||||||||||
-1 | The intrinsic values of phantom unit awards vested during the three months ended March 31, 2015 and 2014 were $1.6 million and $0.3 million, respectively. | ||||||||||||||||
-2 | The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2015 was $4.9 million. | ||||||||||||||||
-3 | There were approximately $29,000 and $0.2 million recognized as liabilities on the Partnership’s consolidated balance sheets at March 31, 2015 and December 31, 2014, respectively, representing 6,647 and 26,579 units, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units were $21.63 and $21.16 at March 31, 2015 and December 31, 2014, respectively. There was $0.1 million recognized as liabilities on the Company’s consolidated balance sheet at the period ended March 31, 2014 representing 16,084 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 $22.15 for the period ending March 31, 2014. | ||||||||||||||||
-4 | The intrinsic values of phantom unit awards vested, but not yet issued at March 31, 2015 and 2014 were $1.1 million and $0.1 million, respectively. | ||||||||||||||||
At March 31, 2015, ARP had approximately $4.2 million in unrecognized compensation expense related to unvested phantom units outstanding under the ARP LTIP based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 1.8 years. | |||||||||||||||||
ARP Unit Options. A unit option is the right to purchase an ARP common unit in the future at a predetermined price (the exercise price). The exercise price of each ARP unit option is determined by the ARP LTIP Committee and may be equal to or greater than the fair market value of ARP’s common unit on the date of grant of the option. The ARP LTIP Committee will determine the vesting and exercise restrictions applicable to an ARP award of options, if any, and the method by which the exercise price may be paid by the participant. Unit option awards expire 10 years from the date of grant. Unit options granted under the ARP LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. There were 106,950 unit options outstanding under the ARP LTIP at March 31, 2015 that will vest within the following twelve months. No cash was received from the exercise of options for the three months ended March 31, 2015 and 2014. | |||||||||||||||||
The following table sets forth the ARP LTIP unit option activity for the periods indicated: | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2015 | 2014 | ||||||||||||||||
Number | Weighted | Number | Weighted | ||||||||||||||
of Unit Options | Average | of Unit Options | Average | ||||||||||||||
Exercise Price | Exercise Price | ||||||||||||||||
Outstanding, beginning of year | 1,458,300 | $ | 24.66 | 1,482,675 | $ | 24.66 | |||||||||||
Granted | — | — | — | — | |||||||||||||
Exercised (1) | — | — | — | — | |||||||||||||
Forfeited | (5,000 | ) | 24.67 | (10,000 | ) | 23.4 | |||||||||||
Outstanding, end of period(2)(3) | 1,453,300 | $ | 24.66 | 1,472,675 | $ | 24.66 | |||||||||||
Options exercisable, end of year(4) | 1,238,275 | $ | 24.67 | 368,825 | $ | 24.67 | |||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 831 | $ | 612 | |||||||||||||
-1 | No options were exercised during the three months ended March 31, 2015 and 2014. | ||||||||||||||||
-2 | The weighted average remaining contractual life for outstanding options at March 31, 2015 was 7.1 years. | ||||||||||||||||
-3 | There was no aggregate intrinsic value of options outstanding at March 31, 2015. 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, 2015 was 7.1 years. There were no intrinsic values for options exercisable at March 31, 2015 and 2014. | ||||||||||||||||
At March 31, 2015, ARP had approximately $0.2 million in unrecognized compensation expense related to unvested unit options outstanding under the ARP LTIP based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 1.0 years. ARP used the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted. | |||||||||||||||||
Restricted Units | |||||||||||||||||
Restricted units are actual common units issued to a participant that are subject to vesting restrictions and evidenced in such manner as the ARP LTIP Committee may deem appropriate, including book-entry registration or issuance of one or more unit certificates. Prior to or upon the grant of an award of restricted units, the ARP LTIP Committee will condition the vesting or transferability of the restricted units upon continued service, the attainment of performance goals or both. A holder of restricted units will have certain rights of holders of common units in general, including the right to vote the restricted units. However, during the period in which the restricted units are subject to vesting restrictions, the holder will not be permitted to sell, assign, transfer, pledge or otherwise encumber the restricted units. |
Operating_Segment_Information
Operating Segment Information | 3 Months Ended | |||||||||
Mar. 31, 2015 | ||||||||||
Segment Reporting [Abstract] | ||||||||||
Operating Segment Information | NOTE 15—OPERATING SEGMENT INFORMATION | |||||||||
The Company’s operations include three reportable operating segments: ARP, other operations, and corporate and other. These operating segments reflect the way the Company manages its operations and makes business decisions. ARP consists of ARP’s operations. Other operations include the operations of the Arkoma assets and the Development Subsidiary (see Note 1). Corporate and other includes the Company’s equity investment in Lightfoot (see Note 1), as well as its general and administrative and interest expenses. Operating segment data for the periods indicated were as follows (in thousands): | ||||||||||
Three Months Ended | ||||||||||
March 31, | ||||||||||
2015 | 2014 | |||||||||
Atlas Resource Partners: | ||||||||||
Revenues | $ | 239,247 | $ | 157,345 | ||||||
Operating costs and expenses | -86,536 | -103,078 | ||||||||
Depreciation, depletion and amortization expense | -41,866 | -50,237 | ||||||||
Loss on asset sales and disposal | -11 | -1,603 | ||||||||
Interest expense | -25,197 | -13,187 | ||||||||
Segment income (loss) | $ | 85,637 | $ | -10,760 | ||||||
Other Operations: | ||||||||||
Revenues | $ | 5,588 | $ | 4,580 | ||||||
Operating costs and expenses | -1,769 | -1,966 | ||||||||
Depreciation, depletion and amortization expense | -2,590 | -1,802 | ||||||||
Segment income | $ | 1,229 | $ | 812 | ||||||
Corporate and other: | ||||||||||
Revenues | $ | 964 | $ | 222 | ||||||
General and administrative | -24,797 | -4,936 | ||||||||
Interest expense | -9,554 | -2,789 | ||||||||
Segment loss | $ | -33,387 | $ | -7,503 | ||||||
Reconciliation of segment income (loss) to net loss: | ||||||||||
Segment income (loss): | ||||||||||
Atlas Resource | $ | 85,637 | $ | -10,760 | ||||||
Other Operations | 1,229 | 812 | ||||||||
Corporate and other | -33,387 | -7,503 | ||||||||
Net income (loss) | $ | 53,479 | $ | -17,451 | ||||||
Reconciliation of segment revenues to total revenues: | ||||||||||
Segment revenues: | ||||||||||
Atlas Resource | $ | 239,247 | $ | 157,345 | ||||||
Other Operations | 5,588 | 4,580 | ||||||||
Corporate and other | 964 | 222 | ||||||||
Total revenues | $ | 245,799 | $ | 162,147 | ||||||
Capital expenditures: | ||||||||||
Atlas Resource | $ | 42,498 | $ | 39,897 | ||||||
Other Operations | 9,943 | 4,522 | ||||||||
Corporate and other | — | — | ||||||||
Total capital expenditures | $ | 52,441 | $ | 44,419 | ||||||
March 31, | December 31, | |||||||||
2015 | 2014 | |||||||||
Balance sheet: | ||||||||||
Goodwill: | ||||||||||
Atlas Resource | $ | 13,639 | $ | 13,639 | ||||||
Other Operations | — | — | ||||||||
Corporate and other | — | — | ||||||||
$ | 13,639 | $ | 13,639 | |||||||
Total assets: | ||||||||||
Atlas Resource | $ | 2,747,576 | $ | 2,727,575 | ||||||
Other Operations | 216,656 | 257,800 | ||||||||
Corporate and other | 12,750 | 40,940 | ||||||||
$ | 2,976,982 | $ | 3,026,315 | |||||||
Subsequent_Events
Subsequent Events | 3 Months Ended |
Mar. 31, 2015 | |
Subsequent Events [Abstract] | |
Subsequent Events | NOTE 16—SUBSEQUENT EVENTS |
The Company | |
On April 22, 2015, the Company declared a quarterly distribution of $0.3 million for the month ended March 31, 2015 related to its Series A Preferred Units. The distribution will be paid on May 15, 2015 to unitholders of record at the close of business on May 8, 2015. | |
Atlas Resource | |
Issuance of Preferred Units. On April 7, 2015, ARP issued 255,000 of its 10.75% Class E Cumulative Redeemable Perpetual Preferred Units (“Class E ARP Preferred Units”) at a public offering price of $25.00 per unit for net proceeds of approximately $6.0 million. The underwriters have been granted a 30-day option to purchase up to an additional 38,250 Class E ARP Preferred Units at the public offering price less the underwriting discount. ARP will pay distributions on the Class E ARP Preferred Units at a rate of 10.75% per annum of the stated liquidation preference of $25.00. | |
Cash Distributions. On April 22, 2015, ARP declared a monthly distribution of $0.1083 per common unit for the month of March 31, 2015. The $10.3 million distribution, including $0.2 million and $0.6 million to the general partner and preferred limited partners, respectively, will be paid on May 15, 2015 to unitholders of record at the close of business on May 8, 2015. | |
On April 15, 2015, ARP paid a quarterly distribution of $0.539063 per ARP Class D Preferred Unit, or $2.2 million, for the first quarter of 2015 to ARP Class D Preferred Unit holders of record as of April 1, 2015. |
Summary_of_Significant_Account1
Summary of Significant Accounting Policies (Policies) | 3 Months Ended | ||||||||||||
Mar. 31, 2015 | |||||||||||||
Accounting Policies [Abstract] | |||||||||||||
Principles of Consolidation and Combination | Principles of Consolidation and Combination | ||||||||||||
The consolidated balance sheet at March 31, 2015 and the related combined consolidated statement of operations for the three months ended March 31, 2015, subsequent to the transfer of assets on February 27, 2015 include the accounts of the Company and its subsidiaries. The Company’s combined consolidated balance sheet at December 31, 2014, the combined consolidated statement of operations for the three months ended March 31, 2015 prior to the transfer of assets on February 27, 2015, and the combined consolidated statement of operations for the three months ended March 31, 2014 were derived from the separate records maintained by Atlas Energy and may not necessarily be indicative of the conditions or results of operations that would have existed if the Company had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various entities comprising the Company, Atlas Energy’s net investment in the Company is shown as equity in the combined consolidated financial statements. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the combined consolidated balance sheets and related combined consolidated statements of operations. Such estimates included allocations made from the historical accounting records of Atlas Energy, based on management’s best estimates, in order to derive the financial statements of the Company. Actual balances and results could be different from those estimates. Transactions between the Company and other Atlas Energy operations have been identified in the combined consolidated financial statements as transactions between affiliates. | |||||||||||||
In connection with Atlas Energy’s merger with Targa and the concurrent Separation, the Company was required to repay $150.0 million of Atlas Energy’s term loan credit facility, which was issued in July 2013 for $240.0 million. In accordance with generally accepted accounting principles, the Company included $150.0 million of Atlas Energy’s original term loan at the time of issuance, and the related interest expense, within its historical financial statements. Atlas Energy’s other historical borrowings were allocated to the Company’s historical financial statements in the same ratio. The Company used proceeds from the issuance of its Series A preferred units (see Note 12) and borrowings under its term loan credit facilities (see Note 7) to fund the $150.0 million payment. | |||||||||||||
The Company combines the financial statements of ARP and the Development Subsidiary into its combined consolidated financial statements rather than presenting its ownership interest as equity investments, as the Company controls these entities through its general partnership interests therein. As such, the non-controlling interests in ARP and the Development Subsidiary are reflected as (income) loss attributable to non-controlling interests in the combined consolidated statements of operations and as a component of unitholders’ equity on the combined consolidated balance sheets. All material intercompany transactions have been eliminated. | |||||||||||||
In accordance with established practice in the oil and gas industry, the Company’s combined 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 Company’s combined 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 (see “Property, Plant and Equipment”). | |||||||||||||
During the three months ended March 31, 2015, the Development Subsidiary issued $19.8 million of its common limited partner units, which was included within non-controlling interests on the Company’s combined consolidated balance sheets. In connection with the issuance of the Development Subsidiary’s common units, the Company recorded a gain of $0.4 million within equity and a corresponding decrease in non-controlling interests on its combined consolidated balance sheet and consolidated statement of unitholders’ equity. | |||||||||||||
Use of Estimates | Use of Estimates | ||||||||||||
The preparation of the Company’s combined 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 Company’s combined consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Company’s combined 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. Such estimates included estimated allocations made from the historical accounting records of Atlas Energy in order to derive the historical financial statements of the Company. 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, 2015 and 2014 represent actual results in all material respects (see “Revenue Recognition”). | |||||||||||||
Receivables | Receivables | ||||||||||||
Accounts receivable on the combined consolidated balance sheets consist primarily of the trade accounts receivable associated with the Company and its subsidiaries. In evaluating the realizability of accounts receivable, management performs ongoing credit evaluations of customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness, as determined by management’s review of customers’ credit information. The Company and its subsidiaries extend credit on sales on an unsecured basis to many of its customers. At March 31, 2015 and December 31, 2014, the Company had recorded no allowance for uncollectible accounts receivable on its combined consolidated balance sheets. | |||||||||||||
Inventory | Inventory | ||||||||||||
The Company had $8.4 million and $8.9 million of inventory at March 31, 2015 and December 31, 2014, respectively, which were included within prepaid expenses and other current assets on its combined consolidated balance sheets. The Company values inventories at the lower of cost or market. The Company’s inventories, which consist primarily of ARP’s materials, pipes, supplies and other inventories, were principally determined using the average cost method. | |||||||||||||
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 that 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 that 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 Company’s results of operations. | |||||||||||||
The Company and its subsidiaries 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 Company’s and its subsidiaries’ 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 Company’s combined consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s combined 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 Company’s combined 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 Company and its subsidiaries review 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 Company’s and its subsidiaries’ 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 Company and its subsidiaries 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 operating and administrative fees in addition to their proportionate share of external operating expenses. 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 Company 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 partnership 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 Company and its subsidiaries 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. There were no impairments of unproved gas and oil properties recorded on the Company’s combined consolidated statements of operations for the three months ended March 31, 2015 and 2014. | |||||||||||||
Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. During the year ended December 31, 2014, the Company recognized $562.6 million of asset impairment related to oil and gas properties within property, plant and equipment, net on its combined consolidated balance sheet primarily for ARP’s Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. Asset impairments for the year ended December 31, 2014 principally resulted from the decline in forward commodity prices during the fourth quarter of 2014. There were no impairments of proved gas and oil properties recorded by the Company for the three months ended March 31, 2015 and 2014. | |||||||||||||
The impairment of proved properties during the year ended December 31, 2014 related to the carrying amounts of these gas and oil properties being in excess of the Company’s estimate of their fair values at December 31, 2014. The estimate of the fair values of these gas and oil properties was impacted by, among other factors, the deterioration of commodity prices at the date of measurement. | |||||||||||||
Capitalized Interest | Capitalized Interest | ||||||||||||
ARP capitalizes 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 were 6.1% and 5.6% for the three months ended March 31, 2015 and 2014, respectively. The amounts of interest capitalized by ARP were $3.9 million and $2.6 million for the three months ended March 31, 2015 and 2014, respectively. | |||||||||||||
Intangible Assets | Intangible Assets | ||||||||||||
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, 2015 and December 31, 2014 (in thousands): | |||||||||||||
March 31, | December 31, | Estimated | |||||||||||
Useful Lives | |||||||||||||
2015 | 2014 | In Years | |||||||||||
Gross Carrying Amount | $ | 14,344 | $ | 14,344 | 13 | ||||||||
Accumulated Amortization | (13,712 | ) | (13,653 | ) | |||||||||
Net Carrying Amount | $ | 632 | $ | 691 | |||||||||
Amortization expense on intangible assets was $0.1 million for both the three months ended March 31, 2015 and 2014, respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2015 - $0.2 million; 2016 - $0.1 million; 2017 - $0.1 million; 2018 - $0.1 million; and 2019 - $0.1 million. | |||||||||||||
Goodwill | Goodwill | ||||||||||||
At March 31, 2015 and December 31, 2014, the Company had $13.6 million of goodwill recorded in connection with ARP’s prior consummated acquisitions. No changes in the carrying amount of goodwill were recorded for the three months ended March 31, 2015 and 2014. | |||||||||||||
ARP tests 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 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. 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, 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 also considers 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 industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in ARP’s industry to determine whether those valuations appear reasonable in management’s judgment. ARP’s management will continue to evaluate goodwill at least annually or when impairment indicators arise. | |||||||||||||
As a result of its goodwill impairment evaluation at December 31, 2014, ARP recognized an $18.1 million non-cash impairment charge within asset impairments on the Company’s combined consolidated statement of operations for the year ended December 31, 2014. The goodwill impairment resulted from the reduction in ARP’s estimated fair value of its gas and oil production reporting unit in comparison to its carrying amount at December 31, 2014. ARP’s estimated fair value of its gas and oil production reporting unit was impacted by a decline in overall commodity prices during the fourth quarter of 2014. | |||||||||||||
Derivative Instruments | Derivative Instruments | ||||||||||||
The Company and ARP enter into certain financial contracts to manage their exposure to movement in commodity prices and interest rates (see Note 8). The derivative instruments recorded in the combined consolidated balance sheets are measured as either an asset or liability at fair value. Changes in the fair value of derivative instruments are recognized currently in the Company’s combined consolidated statements of operations unless specific hedge accounting criteria are met. On January 1, 2015, the Company and ARP discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges. As such, changes in fair value after December 31, 2014 of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Company’s combined consolidated statements of operations, while the fair values of the instruments recorded in accumulated other comprehensive income as of December 31, 2014 will be reclassified to the combined consolidated statements of operations in the periods in which those respective derivative contracts settle. Prior to discontinuance of hedge accounting, the fair value of these commodity derivative instruments was recognized in accumulated other comprehensive income (loss) within unitholders’ equity on the Company’s consolidated balance sheets and reclassified to the Company’s consolidated statements of operations at the time the originally hedged physical transactions affected earnings. | |||||||||||||
Asset Retirement Obligations | Asset Retirement Obligations | ||||||||||||
The Company and its subsidiaries recognize an estimated liability for the plugging and abandonment of gas and oil wells and related facilities (see Note 6). The Company and its subsidiaries also recognize a liability for 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 Company and its subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization. | |||||||||||||
ARP Preferred Units | ARP Preferred Units | ||||||||||||
In connection with ARP’s acquisition of certain proved reserves and associated assets from Titan Operating, L.L.C. in July 2012, ARP issued 3.8 million newly created convertible Class B ARP preferred units (“Class B ARP Preferred Units”). While outstanding, the Class B ARP Preferred Units will receive regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution. On December 23, 2014, 3,796,900 of Class B ARP Preferred Units were converted into common units. In connection with ARP’s acquisition of certain proved reserves and associated assets from EP Energy, Inc. in July 2013, ARP issued 3.7 million newly created convertible Class C ARP preferred units to Atlas Energy (“Class C ARP Preferred Units”). While outstanding, the Class C ARP Preferred Units will receive regular quarterly cash distributions equal to the greater of (i) $0.51 and (ii) the quarterly common unit distribution. In October 2014, in connection with ARP’s acquisition of assets in the Eagle Ford Shale (see Note 3), ARP issued 3.2 million of its 8.625% Class D cumulative redeemable perpetual preferred units (“Class D ARP Preferred Units”) and in March 2015, issued an additional 800,000 Class D ARP Preferred Units (see Note 12). The initial quarterly distribution on the Class D ARP Preferred Units was $0.616927 per unit, representing the distribution for the period from October 2, 2014 through January 14, 2015. Subsequent to January 14, 2015, ARP will pay future quarterly distributions on the Class D ARP Preferred Units at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference. At March 31, 2015 and December 31, 2014, $97.6 million and $78.0 million, respectively, related to ARP’s preferred units, are included within non-controlling interests on the Company’s combined consolidated statements of unitholders’ equity. | |||||||||||||
Income Taxes | Income Taxes | ||||||||||||
The Company, ARP, the Development Subsidiary, Lightfoot and the respective subsidiaries thereof are not subject to U.S. federal and most state income taxes. The partners of these entities are liable for income tax in regard to their distributive share of the entities’ taxable income. Such taxable income may vary substantially from net income (loss) reported in the accompanying combined consolidated financial statements. Certain corporate subsidiaries of ARP are subject to federal and state income tax. The federal and state income taxes related to the Company and these corporate subsidiaries were immaterial to the combined consolidated financial statements as of March 31, 2015 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 combined consolidated financial statements. | |||||||||||||
Each of the entities which comprise the Company evaluates tax positions taken or expected to be taken in the course of preparing their respective 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 Company’s management does not believe it has any tax positions taken within its combined consolidated financial statements that would not meet this threshold. The Company’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. The Company has not recognized any such potential interest or penalties in its combined consolidated financial statements for the three months ended March 31, 2015 and 2014. | |||||||||||||
The entities comprising the Company file Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the entities comprising the Company are no longer subject to income tax examinations by major tax authorities for years prior to 2011 and are not currently being examined by any jurisdiction and are not aware of any potential examinations as of March 31, 2015. | |||||||||||||
Net Income (Loss) Per Common Unit | Net Income (Loss) Per Common Unit | ||||||||||||
Basic net income (loss) attributable to common unit holders per unit is computed by dividing net income (loss) attributable to common unit holders, which is determined after the deduction of net income attributable to participating securities, if applicable, by the weighted average number of common unit holders 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 Company’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 14), contain non-forfeitable rights to distribution equivalents of the Company. The participation rights result in a non-contingent transfer of value each time the Company 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 unit holders for purposes of calculating net income (loss) attributable to common unit holders per unit (in thousands, except unit data): | |||||||||||||
Three Months Ended | |||||||||||||
March 31, | |||||||||||||
2015 | 2014 | ||||||||||||
Net income (loss) | $ | 53,479 | $ | (17,451 | ) | ||||||||
Loss (income) attributable to non-controlling interests | (58,298 | ) | — | ||||||||||
Loss (income) attributable to owner’s interest (period prior to the transfer of assets on February 27, 2015) | (10,475 | ) | 17,451 | ||||||||||
Net income utilized in the calculation of net income attributable to common unit holders per unit | $ | 5,656 | $ | — | |||||||||
Diluted net income (loss) attributable to common unit holders per unit is calculated by dividing net income (loss) attributable to common unit holders, less income allocable to participating securities, by the sum of the weighted average number of common unit holder units outstanding and the dilutive effect of unit option awards and convertible preferred units, as calculated by the treasury stock or if converted methods, as applicable. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of the Company’s long-term incentive plans (see Note 14). | |||||||||||||
The following table sets forth the reconciliation of the Company’s weighted average number of common unit holder units used to compute basic net income (loss) attributable to common unit holders per unit with those used to compute diluted net income (loss) attributable to common unit holders per unit (in thousands): | |||||||||||||
Three Months Ended | |||||||||||||
March 31, | |||||||||||||
2015 | 2014 | ||||||||||||
Weighted average number of common unit holders per unit—basic | 26,011 | — | |||||||||||
Add effect of dilutive incentive awards | 23 | — | |||||||||||
Add effect of dilutive convertible preferred units | 4,902 | — | |||||||||||
Weighted average number of common unit holders per unit—diluted | 30,936 | — | |||||||||||
Revenue Recognition | Revenue Recognition | ||||||||||||
Natural gas and oil production. The Company and its subsidiaries’ gas and oil production operations 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 Company and its subsidiaries have an interest with other producers, are recognized on the basis of the entity’s percentage ownership of the working interest and/or overriding royalty. | |||||||||||||
ARP’s Drilling Partnerships. Certain energy activities are conducted by ARP through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. Drilling Partnership investor capital raised by ARP is deployed to drill and complete wells included within the partnership. As ARP deploys Drilling Partnership investor capital, it recognizes certain management fees it is entitled to receive, including well construction and completion revenue and a portion of administration and oversight revenue. At each period end, if ARP has Drilling Partnership investor capital that has not yet been deployed, it will recognize a current liability titled “Liabilities Associated with Drilling Contracts” on the Company’s combined consolidated balance sheets. After the Drilling Partnership well is completed and turned in line, ARP is entitled to receive additional operating and management fees, which are included within well services and administration and oversight revenue, respectively, on a monthly basis while the well is operating. In addition to the management fees it is entitled to receive for services provided, ARP is also entitled to its pro-rata share of Drilling Partnership gas and oil production revenue, which generally approximate 30%. ARP recognizes its Drilling Partnership management fees in the following manner: | |||||||||||||
• | Well construction and completion. For each well that is drilled by a Drilling Partnership, ARP receives a 15% mark-up on those costs incurred to drill and complete wells included within the partnership. Such fees are earned, in accordance with the partnership agreement, and recognized as the services are performed, typically between 60 and 270 days, using the percentage of completion method. | ||||||||||||
• | Administration and oversight. For each well drilled by a Drilling Partnership, ARP receives a fixed fee between $100,000 and $500,000, depending on the type of well drilled, which is earned, in accordance with the partnership agreement, and recognized at the initiation of the well. Additionally, the Drilling Partnership pays ARP a monthly per well administrative fee of $75 for the life of the well. The well administrative fee is earned on a monthly basis as the services are performed. | ||||||||||||
• | Well services. Each Drilling Partnership pays ARP a monthly per well operating fee, currently $1,000 to $2,000, depending on the type of well, for the life of the well. Such fees are earned on a monthly basis as the services are performed. | ||||||||||||
While the historical structure has varied, ARP has generally agreed to subordinate a portion of its share of Drilling Partnership gas and oil production revenue, net of corresponding production costs and up to a maximum of 50% of unhedged revenue, from certain Drilling Partnerships for the benefit of the limited partner investors until they have received specified returns, typically 10% to 12% per year determined on a cumulative basis, over a specified period, typically the first five to eight years, in accordance with the terms of the partnership agreements. ARP periodically compares the projected return on investment for limited partners in a Drilling Partnership during the subordination period, based upon historical and projected cumulative gas and oil production revenue and expenses, with the return on investment subject to subordination agreed upon within the Drilling Partnership agreement. If the projected return on investment falls below the agreed upon rate, ARP recognizes subordination as an estimated reduction of its pro-rata share of gas and oil production revenue, net of corresponding production costs, during the current period in an amount that will achieve the agreed upon investment return, subject to the limitation of 50% of unhedged cumulative net production revenues over the subordination period. For Drilling Partnerships for which ARP has recognized subordination in a historical period, if projected investment returns subsequently reflect that the agreed upon limited partner investment return will be achieved during the subordination period, ARP will recognize an estimated increase in its portion of historical cumulative gas and oil net production, subject to a limitation of the cumulative subordination previously recognized. | |||||||||||||
ARP’s gathering and processing revenue. Gathering and processing revenue includes gathering fees ARP charges to the Drilling Partnership wells for ARP’s processing plants in the New Albany and the Chattanooga shales. Generally, ARP charges a gathering fee to the Drilling Partnership wells equivalent to the fees ARP remits. In Appalachia, a majority of the Drilling Partnership wells are subject to a gathering agreement, whereby ARP remits a gathering fee of 16%. However, based on the respective Drilling Partnership agreements, ARP charges the Drilling Partnership wells a 13% gathering fee. As a result, some of ARP’s gathering expenses, specifically those in the Appalachian Basin, will generally exceed the revenues collected from the Drilling Partnerships by approximately 3%. | |||||||||||||
The Company and its subsidiaries’ gas and oil production operations accrue unbilled revenue 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 Company had unbilled revenues at March 31, 2015 and December 31, 2014 of $56.1 million and $85.5 million, respectively, which were included in accounts receivable within its combined 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 Company’s combined 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 8). The Company does not have any other type of transaction which would be included within other comprehensive income (loss). | |||||||||||||
Recently Issued Accounting Standards | Recently Issued Accounting Standards | ||||||||||||
In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-06, Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (“Update 2015-06”). Under Topic 260, Earnings per Share, master limited partnerships (“MLPs”) apply the two-class method to calculate earnings per unit (“EPU”) because the general partner, limited partners, and incentive distribution rights holders each participate differently in the distribution of available cash. When a general partner transfers (or “drops down”) net assets to a master limited partnership and that transaction is accounted for as a transaction between entities under common control, the statements of operations of the master limited partnership are adjusted retrospectively to reflect the drop down transaction as if it occurred on the earliest date during which the entities were under common control. The amendments in Update 2015-06 specify that for purposes of calculating historical EPU under the two-class method, the earnings (losses) of a transferred business before the date of a drop down transaction should be allocated entirely to the general partner interest, and previously reported EPU of the limited partners would not change as a result of a drop down transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the drop down transaction occurs also are required. The amendments in Update 2015-06 are effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted and amendments in Update 2015-06 should be applied retrospectively for all financial statements presented. The Company will adopt the requirements of Update 2015-06 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures. | |||||||||||||
In March 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30) (“Update 2015-03”). The amendments in Update 2015-03 are intended to simplify presentation of debt issuance costs and require that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs would not be affected by the amendments in Update 2015-03. The amendments in Update 2015-03 are effective for periods beginning after December 15, 2015, and interim periods within those periods. Early adoption is permitted, including adoption in an interim period, and an entity should apply the new guidance on a retrospective basis. The Company will adopt the requirements of Update 2015-03 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures. | |||||||||||||
In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“Update 2015-02”). The amendments in Update 2015-02 are intended to improve targeted areas of consolidation guidance for legal entities such as limited partnerships, limited liability corporations and securitization structures. The amendments simplify the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. The amendments in Update 2015-02 are effective for periods beginning after December 31, 2015. Early adoption is permitted, including adoption in an interim period. The Company will adopt the requirements of Update 2015-02 upon its effective date of January 1, 2016, and is evaluating the impact of adoption on its financial position, results of operations or related disclosures. | |||||||||||||
In January 2015, the FASB issued ASU 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items (“Update 2015-01”). The amendments in Update 2015-01 simplify the income statement presentation requirements in Subtopic 225-20 by eliminating the concept of extraordinary items. Extraordinary items are events and transactions that are distinguished by their unusual nature and by the infrequency of their occurrence. The amendments in Update 2015-01 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. A reporting entity may apply the amendments prospectively. A reporting entity may also apply the amendments retrospectively to all prior periods presented in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal year of adoption. The Company will adopt the requirements of Update 2015-01 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures. | |||||||||||||
In November 2014, the FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815) – Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share is More Akin to Debt or to Equity (“Update 2014-16”). Certain classes of shares include features that entitle the holders to preferences and rights (such as conversion rights, redemption rights, voting powers, and liquidation and dividend payment preferences) over the other shareholders. Shares that include embedded derivative features are referred to as hybrid financial instruments, which must be separated from the host contract and accounted for as a derivative if certain criteria are met under Subtopic 815-10. One criterion requires evaluating whether the nature of the host contract is more akin to debt or to equity and whether the economic characteristics and risks of the embedded derivative feature are “clearly and closely related” to the host contract. In making that evaluation, an issuer or investor may consider all terms and features in a hybrid financial instrument including the embedded derivative feature that is being evaluated for separate accounting or may consider all terms and features in the hybrid financial instrument except for the embedded derivative feature that is being evaluated for separate accounting. The use of different methods can result in different accounting outcomes for economically similar hybrid financial instruments. Additionally, there is diversity in practice with respect to the consideration of redemption features in relation to other features when determining whether the nature of a host contract is more akin to debt or to equity. The amendments in Update 2014-16 clarify how current U.S. GAAP should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. The effects of initially adopting the amendments in Update 2014-16 should be applied on a modified retrospective basis to existing hybrid financial instruments issued in the form of a share as of the beginning of the fiscal year for which the amendments are effective. Retrospective application is permitted to all relevant prior periods. The amendments in Update 2014-16 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The Company will adopt the requirements of Update 2014-16 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures. | |||||||||||||
In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements—Going Concern (Subtopic 205-40) (“Update 2014-15”). The amendments in Update 2014-15 provide U.S. GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management will be required to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early adoption is permitted. The Company will adopt the requirements of Update 2014-15 upon its effective date in 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures. | |||||||||||||
In June 2014, the FASB issued ASU 2014-12, Compensation—Stock Compensation (Topic 718) (“Update 2014-12”). The amendments in Update 2014-12 require that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. As such, the performance target should not be reflected in estimating the grant date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved. The amendments in Update 2014-12 are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Early adoption is permitted. Entities may apply the amendments in Update 2014-12 either (a) prospectively to all awards granted or modified after the effective date, or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. The Company will adopt the requirements of Update 2014-12 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures. | |||||||||||||
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles—Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. The Company will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2017, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures. On April 1, 2015, the FASB tentatively decided to defer the effective date of ASU 2014-09 by one year. As a result, public entities would apply the new revenue standard to annual reporting periods beginning after December 15, 2017, and to interim periods within that reporting period, with early adoption permitted. | |||||||||||||
Derivatives, Methods of Accounting, Derivative Types | The Company and ARP 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 Company and ARP 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 Company and ARP receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. 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 | On January 1, 2015, the Company and ARP discontinued hedge accounting for their qualified commodity derivatives. As such, changes in fair value of these derivatives after December 31, 2014 are recognized immediately within gain (loss) on mark-to-market derivatives in the Company’s combined consolidated statements of operations. The fair values of these commodity derivative instruments at December 31, 2014, which were recognized in accumulated other comprehensive income within unitholders’ equity on the Company’s combined consolidated balance sheet, will be reclassified to the Company’s combined consolidated statements of operations in the future at the time the originally hedged physical transactions settle. | ||||||||||||
Derivatives, Basis and Use of Derivatives, Use of Derivatives | The Company and ARP 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 Company’s combined 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 Company’s combined consolidated balance sheets as the initial value of the options. |
Summary_of_Significant_Account2
Summary of Significant Accounting Policies (Tables) | 3 Months Ended | ||||||||||||
Mar. 31, 2015 | |||||||||||||
Accounting Policies [Abstract] | |||||||||||||
Schedule of the Components of Intangible Assets Being Amortized | The following table reflects the components of intangible assets being amortized at March 31, 2015 and December 31, 2014 (in thousands): | ||||||||||||
March 31, | December 31, | Estimated | |||||||||||
Useful Lives | |||||||||||||
2015 | 2014 | In Years | |||||||||||
Gross Carrying Amount | $ | 14,344 | $ | 14,344 | 13 | ||||||||
Accumulated Amortization | (13,712 | ) | (13,653 | ) | |||||||||
Net Carrying Amount | $ | 632 | $ | 691 | |||||||||
Reconciliation of Net Income (Loss) | The following is a reconciliation of net income (loss) allocated to the common unit holders for purposes of calculating net income (loss) attributable to common unit holders per unit (in thousands, except unit data): | ||||||||||||
Three Months Ended | |||||||||||||
March 31, | |||||||||||||
2015 | 2014 | ||||||||||||
Net income (loss) | $ | 53,479 | $ | (17,451 | ) | ||||||||
Loss (income) attributable to non-controlling interests | (58,298 | ) | — | ||||||||||
Loss (income) attributable to owner’s interest (period prior to the transfer of assets on February 27, 2015) | (10,475 | ) | 17,451 | ||||||||||
Net income utilized in the calculation of net income attributable to common unit holders per unit | $ | 5,656 | $ | — | |||||||||
Reconciliation of the Company's Weighted Average Number of Common Unit holder Units | The following table sets forth the reconciliation of the Company’s weighted average number of common unit holder units used to compute basic net income (loss) attributable to common unit holders per unit with those used to compute diluted net income (loss) attributable to common unit holders per unit (in thousands): | ||||||||||||
Three Months Ended | |||||||||||||
March 31, | |||||||||||||
2015 | 2014 | ||||||||||||
Weighted average number of common unit holders per unit—basic | 26,011 | — | |||||||||||
Add effect of dilutive incentive awards | 23 | — | |||||||||||
Add effect of dilutive convertible preferred units | 4,902 | — | |||||||||||
Weighted average number of common unit holders per unit—diluted | 30,936 | — | |||||||||||
Acquisitions_Tables
Acquisitions (Tables) | 3 Months Ended | ||||
Mar. 31, 2015 | |||||
Business Combinations [Abstract] | |||||
Assets Acquired and Liabilities Assumed in Acquisition | The following table presents the preliminary values assigned to the assets acquired and liabilities assumed in the acquisition, based on their estimated fair values at the date of the acquisition (in thousands): | ||||
Assets: | |||||
Prepaid expenses and other | 4,041 | ||||
Property, plant and equipment | 405,416 | ||||
Other assets, net | 2,888 | ||||
Total assets acquired | $ | 412,345 | |||
Liabilities: | |||||
Accrued liabilities | 2,117 | ||||
Asset retirement obligation | 1,305 | ||||
Total liabilities assumed | 3,422 | ||||
Net assets acquired | $ | 408,923 | |||
Property_Plant_and_Equipment_T
Property, Plant and Equipment (Tables) | 3 Months Ended | ||||||||||||
Mar. 31, 2015 | |||||||||||||
Property Plant And Equipment [Abstract] | |||||||||||||
Summary of Property, Plant and Equipment | The following is a summary of property, plant and equipment at the dates indicated (in thousands): | ||||||||||||
March 31, | December 31, | Estimated | |||||||||||
Useful Lives | |||||||||||||
2015 | 2014 | in Years | |||||||||||
Natural gas and oil properties: | |||||||||||||
Proved properties: | |||||||||||||
Leasehold interests | $ | 458,507 | $ | 535,893 | |||||||||
Pre-development costs | 9,136 | 7,378 | |||||||||||
Wells and related equipment | 3,100,587 | 3,096,562 | |||||||||||
Total proved properties | 3,568,230 | 3,639,833 | |||||||||||
Unproved properties | 314,677 | 217,321 | |||||||||||
Support equipment | 40,992 | 37,359 | |||||||||||
Total natural gas and oil properties | 3,923,899 | 3,894,513 | |||||||||||
Pipelines, processing and compression facilities | 50,578 | 49,547 | 2 – 40 | ||||||||||
Rights of way | 829 | 830 | 20 – 40 | ||||||||||
Land, buildings and improvements | 9,201 | 9,160 | 3 – 40 | ||||||||||
Other | 18,059 | 17,936 | 3 – 10 | ||||||||||
4,002,566 | 3,971,986 | ||||||||||||
Less – accumulated depreciation, depletion and amortization | (1,595,842 | ) | (1,552,697 | ) | |||||||||
$ | 2,406,724 | $ | 2,419,289 | ||||||||||
Other_Assets_Tables
Other Assets (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Other Assets Noncurrent Disclosure [Abstract] | |||||||||
Summary of Other Assets | The following is a summary of other assets at the dates indicated (in thousands): | ||||||||
March 31, | December 31, | ||||||||
2015 | 2014 | ||||||||
Deferred financing costs, net of accumulated amortization of $33,333 and $20,675 at March 31, 2015 and December 31, 2014, respectively | $ | 47,601 | $ | 46,120 | |||||
Investment in Lightfoot | 20,612 | 21,123 | |||||||
Rabbi Trust | 5,641 | 3,925 | |||||||
Security deposits | 229 | 229 | |||||||
ARP notes receivable | 3,926 | 3,866 | |||||||
Other | 5,199 | 5,348 | |||||||
$ | 83,208 | $ | 80,611 | ||||||
Asset_Retirement_Obligations_T
Asset Retirement Obligations (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Asset Retirement Obligation Disclosure [Abstract] | |||||||||
Reconciliation of Liability for Well Plugging and Abandonment Costs | A reconciliation of the Company and its subsidiaries’ liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands): | ||||||||
Three Months Ended | |||||||||
March 31, | |||||||||
2015 | 2014 | ||||||||
Asset retirement obligations, beginning of year | $ | 108,101 | $ | 91,214 | |||||
Liabilities incurred | 169 | 602 | |||||||
Liabilities settled | (347 | ) | (217 | ) | |||||
Accretion expense | 1,581 | 1,328 | |||||||
Asset retirement obligations, end of period | $ | 109,504 | $ | 92,927 | |||||
Debt_Tables
Debt (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Debt Disclosure [Abstract] | |||||||||
Schedule of Long-term Debt Instruments | Total debt consists of the following at the dates indicated (in thousands): | ||||||||
March 31, | December 31, | ||||||||
2015 | 2014 | ||||||||
Term loan facilities | $ | 104,419 | $ | 148,125 | |||||
ARP revolving credit facility | 559,000 | 696,000 | |||||||
ARP term loan facility | 242,658 | — | |||||||
ARP 7.75% Senior Notes—due 2021 | 374,563 | 374,544 | |||||||
ARP 9.25% Senior Notes—due 2021 | 323,957 | 323,916 | |||||||
Total debt | 1,604,597 | 1,542,585 | |||||||
Less current maturities | (104,419 | ) | (1,500 | ) | |||||
Total long-term debt | $ | 1,500,178 | $ | 1,541,085 | |||||
Derivative_Instruments_Tables
Derivative Instruments (Tables) | 3 Months Ended | ||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||
Derivatives Fair Value [Line Items] | |||||||||||||||||
Summary of Commodity Derivative Activity | The following table summarizes the commodity derivative activity for the three months ended March 31, 2015 (in thousands): | ||||||||||||||||
Three Months Ended | |||||||||||||||||
March 31, | |||||||||||||||||
2015 | |||||||||||||||||
Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets(1) | $ | (27,343 | ) | ||||||||||||||
Portion of settlements attributable to subsequent mark to market gains | (15,203 | ) | |||||||||||||||
Total cash settlements on commodity derivative contracts | (42,546 | ) | |||||||||||||||
2015 Unrealized gains prior to settlement(2) | 3,203 | ||||||||||||||||
Unrealized gain on open derivative contracts at March 31, 2015, net of amounts recognized in income in prior year(2) | 102,382 | ||||||||||||||||
Gains on mark-to-market derivatives | $ | 105,585 | |||||||||||||||
-1 | Recognized in gas and oil production revenue. | ||||||||||||||||
(2) Recognized in gain on mark-to-market derivatives. | |||||||||||||||||
Fair Value of Derivative Instruments Table | The following table summarizes the gross fair values of the Company’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company’s combined 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 | Combined | Combined | |||||||||||||||
Consolidated | Consolidated | ||||||||||||||||
Balance Sheets | Balance Sheets | ||||||||||||||||
Offsetting Derivative Assets | |||||||||||||||||
As of March 31, 2015 | |||||||||||||||||
Current portion of derivative assets | $ | 947 | $ | — | $ | 947 | |||||||||||
Total derivative assets | $ | 947 | $ | — | $ | 947 | |||||||||||
As of December 31, 2014 | |||||||||||||||||
Current portion of derivative assets | $ | 2,893 | $ | — | $ | 2,893 | |||||||||||
Long-term portion of derivative assets | 2,669 | 2,669 | |||||||||||||||
Total derivative assets | $ | 5,562 | $ | — | $ | 5,562 | |||||||||||
Gross | Gross | Net Amount of | |||||||||||||||
Amounts of | Amounts | Liabilities | |||||||||||||||
Recognized | Offset in the | Presented in the | |||||||||||||||
Liabilities | Combined | Combined | |||||||||||||||
Consolidated | Consolidated | ||||||||||||||||
Balance Sheets | Balance Sheets | ||||||||||||||||
Offsetting Derivative Liabilities | |||||||||||||||||
As of March 31, 2015 | |||||||||||||||||
Current portion of derivative liabilities | $ | — | $ | — | $ | — | |||||||||||
Total derivative liabilities | $ | — | $ | — | $ | — | |||||||||||
As of December 31, 2014 | |||||||||||||||||
Current portion of derivative liabilities | $ | — | $ | — | $ | — | |||||||||||
Total derivative liabilities | $ | — | $ | — | $ | — | |||||||||||
Commodity Derivative Instruments by Type Table | At March 31, 2015, the Company had the following commodity derivatives: | ||||||||||||||||
Natural Gas Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
March 31, | |||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | |||||||||||||||
2015 | 570,000 | $ | 4.302 | $ | 947 | ||||||||||||
The Company’s net asset | $ | 947 | |||||||||||||||
(1) | “MMBtu” represents million British Thermal Units. | ||||||||||||||||
(2) | Fair value based on forward NYMEX natural gas prices, as applicable. | ||||||||||||||||
Atlas Resource Partners, L.P. | |||||||||||||||||
Derivatives Fair Value [Line Items] | |||||||||||||||||
Fair Value of Derivative Instruments Table | The following table summarizes the gross fair values of ARP’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company’s combined 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 Combined | |||||||||||||||
Assets | Combined | Consolidated | |||||||||||||||
Consolidated | Balance Sheets | ||||||||||||||||
Balance Sheets | |||||||||||||||||
Offsetting Derivative Assets | |||||||||||||||||
As of March 31, 2015 | |||||||||||||||||
Current portion of derivative assets | $ | 145,520 | $ | (21 | ) | $ | 145,499 | ||||||||||
Long-term portion of derivative assets | 186,916 | (198 | ) | 186,718 | |||||||||||||
Total derivative assets | $ | 332,436 | $ | (219 | ) | 332,217 | |||||||||||
As of December 31, 2014 | |||||||||||||||||
Current portion of derivative assets | $ | 141,464 | $ | (98 | ) | $ | 141,366 | ||||||||||
Long-term portion of derivative assets | 128,303 | (370 | ) | 127,933 | |||||||||||||
Total derivative assets | $ | 269,767 | $ | (468 | ) | $ | 269,299 | ||||||||||
Gross | Gross | Net Amount of | |||||||||||||||
Amounts of | Amounts | Liabilities Presented | |||||||||||||||
Recognized | Offset in the | in the Combined | |||||||||||||||
Liabilities | Combined | Consolidated | |||||||||||||||
Consolidated | Balance Sheets | ||||||||||||||||
Balance Sheets | |||||||||||||||||
Offsetting Derivative Liabilities | |||||||||||||||||
As of March 31, 2015 | |||||||||||||||||
Current portion of derivative liabilities | $ | (21 | ) | $ | 21 | $ | — | ||||||||||
Long-term portion of derivative liabilities | (198 | ) | 198 | — | |||||||||||||
Total derivative liabilities | $ | (219 | ) | $ | 219 | $ | — | ||||||||||
As of December 31, 2014 | |||||||||||||||||
Current portion of derivative liabilities | $ | (98 | ) | $ | 98 | $ | — | ||||||||||
Long-term portion of derivative liabilities | (370 | ) | 370 | — | |||||||||||||
Total derivative liabilities | $ | (468 | ) | $ | 468 | $ | — | ||||||||||
Commodity Derivative Instruments by Type Table | At March 31, 2015, ARP had the following commodity derivatives: | ||||||||||||||||
Natural Gas – Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | |||||||||||||||
2015 | 40,053,400 | $ | 4.21 | $ | 56,994 | ||||||||||||
2016 | 53,546,300 | $ | 4.229 | 59,049 | |||||||||||||
2017 | 49,920,000 | $ | 4.219 | 42,447 | |||||||||||||
2018 | 40,800,000 | $ | 4.17 | 28,182 | |||||||||||||
2019 | 15,960,000 | $ | 4.017 | 7,319 | |||||||||||||
$ | 193,991 | ||||||||||||||||
Natural Gas – Costless Collars | |||||||||||||||||
Production | Option Type | Volumes | Average Floor | Fair Value | |||||||||||||
Period Ending | and Cap | Asset/ | |||||||||||||||
December 31, | (Liability) | ||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | |||||||||||||||
2015 | Puts purchased | 2,520,000 | $ | 4.21 | $ | 3,670 | |||||||||||
2015 | Calls sold | 2,520,000 | $ | 5.09 | (16 | ) | |||||||||||
$ | 3,654 | ||||||||||||||||
Natural Gas – Put Options – Drilling Partnerships | |||||||||||||||||
Production | Option Type | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | |||||||||||||||
2015 | Puts purchased | 1,080,000 | $ | 4 | $ | 1,328 | |||||||||||
2016 | Puts purchased | 1,440,000 | $ | 4.15 | 1,633 | ||||||||||||
$ | 2,961 | ||||||||||||||||
Natural Gas – WAHA Basis Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(7) | |||||||||||||||
2015 | 3,600,000 | $ | (0.090 | ) | $ | 239 | |||||||||||
$ | 239 | ||||||||||||||||
Natural Gas Liquids – Natural Gasoline Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(8) | |||||||||||||||
2015 | 3,780,000 | $ | 1.956 | $ | 3,122 | ||||||||||||
$ | 3,122 | ||||||||||||||||
Natural Gas Liquids – Propane Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(4) | |||||||||||||||
2015 | 6,048,000 | $ | 1.016 | $ | 2,896 | ||||||||||||
$ | 2,896 | ||||||||||||||||
Natural Gas Liquids – Butane Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(5) | |||||||||||||||
2015 | 1,134,000 | $ | 1.248 | $ | 676 | ||||||||||||
$ | 676 | ||||||||||||||||
Natural Gas Liquids – Iso Butane Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(Gal)(1) | (per Gal)(1) | (in thousands)(6) | |||||||||||||||
2015 | 1,134,000 | $ | 1.263 | $ | 689 | ||||||||||||
$ | 689 | ||||||||||||||||
Natural Gas Liquids – Crude Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | |||||||||||||||
2016 | 84,000 | $ | 85.651 | $ | 2,274 | ||||||||||||
2017 | 60,000 | $ | 83.78 | 1,315 | |||||||||||||
$ | 3,589 | ||||||||||||||||
Crude Oil – Fixed Price Swaps | |||||||||||||||||
Production | Volumes | Average | Fair Value | ||||||||||||||
Period Ending | Fixed Price | Asset | |||||||||||||||
December 31, | |||||||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | |||||||||||||||
2015 | 1,444,500 | $ | 87.585 | $ | 50,453 | ||||||||||||
2016 | 1,425,000 | $ | 83.496 | 35,544 | |||||||||||||
2017 | 1,140,000 | $ | 77.285 | 17,766 | |||||||||||||
2018 | 1,080,000 | $ | 76.281 | 13,804 | |||||||||||||
2019 | 540,000 | $ | 68.371 | $ | 2,196 | ||||||||||||
$ | 119,763 | ||||||||||||||||
Crude Oil – Costless Collars | |||||||||||||||||
Production | Option Type | Volumes | Average | Fair Value | |||||||||||||
Period Ending | Floor | Asset/ | |||||||||||||||
December 31, | and Cap | (Liability) | |||||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | |||||||||||||||
2015 | Puts purchased | 19,500 | $ | 83.846 | $ | 638 | |||||||||||
2015 | Calls sold | 19,500 | $ | 110.654 | (1 | ) | |||||||||||
$ | 637 | ||||||||||||||||
ARP’s net assets | $ | 332,217 | |||||||||||||||
-1 | “MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons. | ||||||||||||||||
(2) | Fair value based on forward NYMEX natural gas prices, as applicable. | ||||||||||||||||
-3 | Fair value based on forward WTI crude oil prices, as applicable. | ||||||||||||||||
-4 | Fair value based on forward Mt. Belvieu propane prices, as applicable. | ||||||||||||||||
-5 | Fair value based on forward Mt. Belvieu butane prices, as applicable. | ||||||||||||||||
(6) | Fair value based on forward Mt. Belvieu iso butane prices, as applicable. | ||||||||||||||||
(7) | Fair value based on forward WAHA natural gas prices, as applicable | ||||||||||||||||
(8) | Fair value based on forward Mt. Belvieu natural gasoline prices, as applicable. |
Fair_Value_of_Financial_Instru1
Fair Value of Financial Instruments (Tables) | 3 Months Ended | ||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||||||
Company, ARP Assets and Liabilities Measured at Fair Value | Information for the Company’s and ARP’s assets and liabilities measured at fair value at March 31, 2015 and December 31, 2014 was as follows (in thousands): | ||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||||
As of March 31, 2015 | |||||||||||||||||
Assets, gross | |||||||||||||||||
Rabbi trust | $ | 5,641 | $ | — | $ | — | $ | 5,641 | |||||||||
Commodity swaps | — | 947 | — | 947 | |||||||||||||
ARP Commodity swaps | — | 325,167 | — | 325,167 | |||||||||||||
ARP Commodity puts | — | 2,961 | — | 2,961 | |||||||||||||
ARP Commodity options | — | 4,308 | — | 4,308 | |||||||||||||
Total assets, gross | 5,641 | 333,383 | — | 339,024 | |||||||||||||
Liabilities, gross | |||||||||||||||||
Commodity swaps | — | — | — | — | |||||||||||||
ARP Commodity swaps | — | (202 | ) | — | (202 | ) | |||||||||||
ARP Commodity options | — | (17 | ) | — | (17 | ) | |||||||||||
Total derivative liabilities, gross | — | (219 | ) | — | (219 | ) | |||||||||||
Total assets, fair value, net | $ | 5,641 | $ | 333,164 | $ | — | $ | 338,805 | |||||||||
As of December 31, 2014 | |||||||||||||||||
Assets, gross | |||||||||||||||||
Rabbi trust | $ | 3,925 | $ | — | $ | — | $ | 3,925 | |||||||||
Commodity swaps | — | 5,562 | — | 5,562 | |||||||||||||
ARP Commodity swaps | — | 261,680 | — | 261,680 | |||||||||||||
ARP Commodity puts | — | 2,767 | — | 2,767 | |||||||||||||
ARP Commodity options | — | 5,320 | — | 5,320 | |||||||||||||
Total assets, gross | 3,925 | 275,329 | — | 279,254 | |||||||||||||
Liabilities, gross | |||||||||||||||||
Commodity swaps | — | — | — | — | |||||||||||||
ARP Commodity swaps | — | (401 | ) | — | (401 | ) | |||||||||||
ARP Commodity options | — | (67 | ) | — | (67 | ) | |||||||||||
Total derivative liabilities, gross | — | (468 | ) | — | (468 | ) | |||||||||||
Total assets, fair value, net | $ | 3,925 | $ | 274,861 | $ | — | $ | 278,786 | |||||||||
Schedule of Assets and Liabilities Measured on Non Recurring Basis | Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the three months ended March 31, 2015 and 2014 was as follows (in thousands): | ||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2015 | 2014 | ||||||||||||||||
Level 3 | Total | Level 3 | Total | ||||||||||||||
Asset retirement obligations | $ | 169 | $ | 169 | $ | 602 | $ | 602 | |||||||||
Total | $ | 169 | $ | 169 | $ | 602 | $ | 602 | |||||||||
Cash_Distribution_Distribution
Cash Distribution (Distributions Declared) (Tables) (Atlas Resource Partners, L.P.) | 3 Months Ended | |||||||||||||||||||
Mar. 31, 2015 | ||||||||||||||||||||
Atlas Resource Partners, L.P. | ||||||||||||||||||||
Schedule of Distributions Made by Partnership | Distributions declared by ARP from January 1, 2014 through March 31, 2015 were as follows (in thousands, except per unit amounts): | |||||||||||||||||||
Date Cash Distribution Paid | For Month | Cash | Total Cash | Total Cash | Total Cash | |||||||||||||||
Ended | Distribution | Distribution | Distribution | Distribution | ||||||||||||||||
per Common | to Common | To Preferred | to the General | |||||||||||||||||
Limited | Limited | Limited | Partner’s | |||||||||||||||||
Partner Unit | Partners | Partners | Class | |||||||||||||||||
A Units | ||||||||||||||||||||
17-Mar-14 | 31-Jan-14 | $ | 0.1933 | $ | 12,718 | $ | 1,467 | $ | 1,055 | |||||||||||
14-Apr-14 | 28-Feb-14 | $ | 0.1933 | $ | 12,719 | $ | 1,466 | $ | 1,055 | |||||||||||
15-May-14 | 31-Mar-14 | $ | 0.1933 | $ | 12,719 | $ | 1,466 | $ | 1,054 | |||||||||||
13-Jun-14 | 30-Apr-14 | $ | 0.1933 | $ | 15,752 | $ | 1,466 | $ | 1,279 | |||||||||||
15-Jul-14 | 31-May-14 | $ | 0.1933 | $ | 15,752 | $ | 1,466 | $ | 1,279 | |||||||||||
14-Aug-14 | 30-Jun-14 | $ | 0.1966 | $ | 16,029 | $ | 1,492 | $ | 1,377 | |||||||||||
12-Sep-14 | 31-Jul-14 | $ | 0.1966 | $ | 16,028 | $ | 1,493 | $ | 1,378 | |||||||||||
15-Oct-14 | 31-Aug-14 | $ | 0.1966 | $ | 16,032 | $ | 1,491 | $ | 1,378 | |||||||||||
14-Nov-14 | 30-Sep-14 | $ | 0.1966 | $ | 16,032 | $ | 1,492 | $ | 1,378 | |||||||||||
15-Dec-14 | 31-Oct-14 | $ | 0.1966 | $ | 16,033 | $ | 1,491 | $ | 1,378 | |||||||||||
14-Jan-15 | 30-Nov-14 | $ | 0.1966 | $ | 16,779 | $ | 745 | -1 | $ | 1,378 | ||||||||||
13-Feb-15 | 31-Dec-14 | $ | 0.1966 | $ | 16,782 | $ | 745 | -1 | $ | 1,378 | ||||||||||
17-Mar-15 | 31-Jan-15 | $ | 0.1083 | $ | 9,284 | $ | 643 | -1 | $ | 203 | ||||||||||
14-Apr-15 | 28-Feb-15 | $ | 0.1083 | $ | 9,347 | $ | 643 | -1 | $ | 204 | ||||||||||
-1 | Excludes the Class D preferred unit quarterly distribution (see Note 12). | |||||||||||||||||||
Benefit_Plans_Tables
Benefit Plans (Tables) | 3 Months Ended | ||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||
2015 Long Term Incentive Plan | |||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||||||||||
Phantom Unit Activity | The following table sets forth the 2015 LTIP phantom unit activity for the periods indicated: | ||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2015 | 2014 | ||||||||||||||||
Number | Weighted | Number | Weighted | ||||||||||||||
of Units | Average | of Units | Average | ||||||||||||||
Grant Date | Grant Date | ||||||||||||||||
Fair Value | Fair Value | ||||||||||||||||
Outstanding, beginning of year | — | $ | — | — | $ | — | |||||||||||
Granted | 68,910 | 9.07 | — | — | |||||||||||||
Vested and issued(1) | — | — | — | — | |||||||||||||
Forfeited | — | — | — | — | |||||||||||||
Outstanding, end of period(2)(3)(4) | 68,910 | $ | 9.07 | — | $ | — | |||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 20 | $ | — | |||||||||||||
(1) | No phantom unit awards vested during the three months ended March 31, 2015 and 2014. | ||||||||||||||||
(2) | The aggregate intrinsic value of phantom unit awards outstanding at March 31, 2015 was approximately $414,000. | ||||||||||||||||
(3) | There was approximately $20,000 recognized as liabilities on the Company’s consolidated balance sheet at March 31, 2015 representing 68,910 units, 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 $9.07 at March 31, 2015. | ||||||||||||||||
(4) | No phantom unit awards had vested, but had not yet been issued at March 31, 2015 and 2014. | ||||||||||||||||
ARP Long Term Incentive Plan | |||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||||||||||
Phantom Unit Activity | The following table sets forth the ARP LTIP phantom unit activity for the periods indicated: | ||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2015 | 2014 | ||||||||||||||||
Number | Weighted | Number | Weighted | ||||||||||||||
of Units | Average | of Units | Average | ||||||||||||||
Grant Date | Grant Date | ||||||||||||||||
Fair Value | Fair Value | ||||||||||||||||
Outstanding, beginning of year | 799,192 | $ | 22.7 | 839,808 | $ | 24.31 | |||||||||||
Granted | — | — | 3,500 | 20.99 | |||||||||||||
Vested and issued(1) | (167,182 | ) | 23.97 | (15,500 | ) | 22.69 | |||||||||||
Forfeited | — | — | (15,500 | ) | 22.63 | ||||||||||||
Outstanding, end of period(2)(3) | 632,010 | $ | 22.37 | 812,308 | $ | 24.35 | |||||||||||
Vested and not yet issued(4) | 110,125 | $ | 24.67 | 6,875 | $ | 22.76 | |||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 2,514 | $ | 1,731 | |||||||||||||
-1 | The intrinsic values of phantom unit awards vested during the three months ended March 31, 2015 and 2014 were $1.6 million and $0.3 million, respectively. | ||||||||||||||||
-2 | The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2015 was $4.9 million. | ||||||||||||||||
-3 | There were approximately $29,000 and $0.2 million recognized as liabilities on the Partnership’s consolidated balance sheets at March 31, 2015 and December 31, 2014, respectively, representing 6,647 and 26,579 units, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units were $21.63 and $21.16 at March 31, 2015 and December 31, 2014, respectively. There was $0.1 million recognized as liabilities on the Company’s consolidated balance sheet at the period ended March 31, 2014 representing 16,084 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 $22.15 for the period ending March 31, 2014. | ||||||||||||||||
-4 | The intrinsic values of phantom unit awards vested, but not yet issued at March 31, 2015 and 2014 were $1.1 million and $0.1 million, respectively. | ||||||||||||||||
Unit Option Activity | The following table sets forth the ARP LTIP unit option activity for the periods indicated: | ||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2015 | 2014 | ||||||||||||||||
Number | Weighted | Number | Weighted | ||||||||||||||
of Unit Options | Average | of Unit Options | Average | ||||||||||||||
Exercise Price | Exercise Price | ||||||||||||||||
Outstanding, beginning of year | 1,458,300 | $ | 24.66 | 1,482,675 | $ | 24.66 | |||||||||||
Granted | — | — | — | — | |||||||||||||
Exercised (1) | — | — | — | — | |||||||||||||
Forfeited | (5,000 | ) | 24.67 | (10,000 | ) | 23.4 | |||||||||||
Outstanding, end of period(2)(3) | 1,453,300 | $ | 24.66 | 1,472,675 | $ | 24.66 | |||||||||||
Options exercisable, end of year(4) | 1,238,275 | $ | 24.67 | 368,825 | $ | 24.67 | |||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 831 | $ | 612 | |||||||||||||
-1 | No options were exercised during the three months ended March 31, 2015 and 2014. | ||||||||||||||||
-2 | The weighted average remaining contractual life for outstanding options at March 31, 2015 was 7.1 years. | ||||||||||||||||
-3 | There was no aggregate intrinsic value of options outstanding at March 31, 2015. 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, 2015 was 7.1 years. There were no intrinsic values for options exercisable at March 31, 2015 and 2014. |
Operating_Segment_Information_
Operating Segment Information (Tables) | 3 Months Ended | |||||||||
Mar. 31, 2015 | ||||||||||
Segment Reporting [Abstract] | ||||||||||
Operating Segment Data | The Company’s operations include three reportable operating segments: ARP, other operations, and corporate and other. These operating segments reflect the way the Company manages its operations and makes business decisions. ARP consists of ARP’s operations. Other operations include the operations of the Arkoma assets and the Development Subsidiary (see Note 1). Corporate and other includes the Company’s equity investment in Lightfoot (see Note 1), as well as its general and administrative and interest expenses. Operating segment data for the periods indicated were as follows (in thousands): | |||||||||
Three Months Ended | ||||||||||
March 31, | ||||||||||
2015 | 2014 | |||||||||
Atlas Resource Partners: | ||||||||||
Revenues | $ | 239,247 | $ | 157,345 | ||||||
Operating costs and expenses | -86,536 | -103,078 | ||||||||
Depreciation, depletion and amortization expense | -41,866 | -50,237 | ||||||||
Loss on asset sales and disposal | -11 | -1,603 | ||||||||
Interest expense | -25,197 | -13,187 | ||||||||
Segment income (loss) | $ | 85,637 | $ | -10,760 | ||||||
Other Operations: | ||||||||||
Revenues | $ | 5,588 | $ | 4,580 | ||||||
Operating costs and expenses | -1,769 | -1,966 | ||||||||
Depreciation, depletion and amortization expense | -2,590 | -1,802 | ||||||||
Segment income | $ | 1,229 | $ | 812 | ||||||
Corporate and other: | ||||||||||
Revenues | $ | 964 | $ | 222 | ||||||
General and administrative | -24,797 | -4,936 | ||||||||
Interest expense | -9,554 | -2,789 | ||||||||
Segment loss | $ | -33,387 | $ | -7,503 | ||||||
Reconciliation of segment income (loss) to net loss: | ||||||||||
Segment income (loss): | ||||||||||
Atlas Resource | $ | 85,637 | $ | -10,760 | ||||||
Other Operations | 1,229 | 812 | ||||||||
Corporate and other | -33,387 | -7,503 | ||||||||
Net income (loss) | $ | 53,479 | $ | -17,451 | ||||||
Reconciliation of segment revenues to total revenues: | ||||||||||
Segment revenues: | ||||||||||
Atlas Resource | $ | 239,247 | $ | 157,345 | ||||||
Other Operations | 5,588 | 4,580 | ||||||||
Corporate and other | 964 | 222 | ||||||||
Total revenues | $ | 245,799 | $ | 162,147 | ||||||
Capital expenditures: | ||||||||||
Atlas Resource | $ | 42,498 | $ | 39,897 | ||||||
Other Operations | 9,943 | 4,522 | ||||||||
Corporate and other | — | — | ||||||||
Total capital expenditures | $ | 52,441 | $ | 44,419 | ||||||
March 31, | December 31, | |||||||||
2015 | 2014 | |||||||||
Balance sheet: | ||||||||||
Goodwill: | ||||||||||
Atlas Resource | $ | 13,639 | $ | 13,639 | ||||||
Other Operations | — | — | ||||||||
Corporate and other | — | — | ||||||||
$ | 13,639 | $ | 13,639 | |||||||
Total assets: | ||||||||||
Atlas Resource | $ | 2,747,576 | $ | 2,727,575 | ||||||
Other Operations | 216,656 | 257,800 | ||||||||
Corporate and other | 12,750 | 40,940 | ||||||||
$ | 2,976,982 | $ | 3,026,315 | |||||||
Basis_of_Presentation_Narrativ
Basis of Presentation (Narrative) (Details) | 0 Months Ended | 3 Months Ended |
Feb. 27, 2015 | Mar. 31, 2015 | |
Basis Of Presentation [Line Items] | ||
Percentage of interest represented by common units which is effected by pro rata distribution | 100.00% | |
Development Subsidiary | ||
Basis Of Presentation [Line Items] | ||
General partner ownership interest | 80.00% | |
Common limited partner ownership interest | 1.60% | |
Lightfoot Capital Partners, LP | ||
Basis Of Presentation [Line Items] | ||
General partner ownership interest | 15.90% | |
Common limited partner ownership interest | 12.00% | |
Atlas Resource Partners, L.P. | ||
Basis Of Presentation [Line Items] | ||
General partner ownership interest | 100.00% | |
Common limited partner ownership interest | 27.50% | |
Common limited partner interest in ARP, units | 20,962,485 | |
Atlas Resource Partners, L.P. | Preferred Limited Partner Units | ||
Basis Of Presentation [Line Items] | ||
Common limited partner interest in ARP, units | 3,749,986 |
Summary_of_Significant_Account3
Summary of Significant Accounting Policies (Narrative) (Details) (USD $) | 3 Months Ended | 12 Months Ended | 0 Months Ended | 1 Months Ended | ||||
Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 23, 2014 | Jul. 31, 2013 | Jan. 14, 2015 | Mar. 31, 2015 | Oct. 31, 2014 | |
Summary Of Significant Accounting Policies [Line Items] | ||||||||
Repayments under credit facilities | $298,000,000 | $215,000,000 | ||||||
Pro-rata share in Drilling Partnerships | 30.00% | |||||||
Allowance for Doubtful Accounts Receivable | 0 | 0 | 0 | |||||
Materials, supplies and other inventory | 8,400,000 | 8,900,000 | 8,400,000 | |||||
Impairments of Unproved Gas and Oil Properties | 0 | 0 | ||||||
Asset impairment | 0 | 0 | ||||||
Future Hedge Gains | 82,300,000 | |||||||
Impairments of Proved Gas And Oil Properties | 0 | 0 | ||||||
Weighted Average Interest Rate Used To Capitalize Interest | 6.10% | 5.60% | ||||||
Interest Costs Capitalized | 3,900,000 | 2,600,000 | ||||||
Amortization of Intangible Assets | 100,000 | 100,000 | ||||||
Future Amortization Expense, remainder of 2015 | 200,000 | 200,000 | ||||||
Future Amortization Expense, 2016 | 100,000 | 100,000 | ||||||
Future Amortization Expense, 2017 | 100,000 | 100,000 | ||||||
Future Amortization Expense, 2018 | 100,000 | 100,000 | ||||||
Future Amortization Expense, 2019 | 100,000 | 100,000 | ||||||
Goodwill | 13,639,000 | 13,639,000 | 13,639,000 | |||||
Changes in carrying amount of goodwill | 0 | 0 | ||||||
Partners unit, issued | 420,586 | |||||||
Deferred income tax benefit | 0 | |||||||
Proportion of amount received on cost incurred to drill | 15.00% | |||||||
Monthly administrative fee per well | 75 | |||||||
Gathering Fee Percentage | 16.00% | |||||||
Gathering Fee Percentage Net Margin | 3.00% | |||||||
Unbilled Contracts Receivable | 56,100,000 | 85,500,000 | 56,100,000 | |||||
Minimum | ||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||
Recognition period to receive fees | 60 days | |||||||
Amount of fixed fees received by each well drilled | 100,000 | |||||||
Monthly operating fee paid per well | 1,000 | |||||||
Return on unhedged revenue percentage | 10.00% | |||||||
Period of return on unhedged revenue | 5 years | |||||||
Maximum | ||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||
Recognition period to receive fees | 270 days | |||||||
Amount of fixed fees received by each well drilled | 500,000 | |||||||
Monthly operating fee paid per well | 2,000 | |||||||
Percentage on unhedged revenue | 50.00% | |||||||
Return on unhedged revenue percentage | 12.00% | |||||||
Period of return on unhedged revenue | 8 years | |||||||
ARP Acquisitions | ||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||
Goodwill | 13,600,000 | 13,600,000 | 13,600,000 | |||||
Goodwill, Impairment Loss | 18,100,000 | |||||||
Preferred stock participation rights | While outstanding, the Class C ARP Preferred Units will receive regular quarterly cash distributions equal to the greater of (i) $0.51 and (ii) the quarterly common unit distribution. | |||||||
ARP Acquisitions | Class B Preferred Units | ||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||
Conversion of Class B preferred units (units) | 3,796,900 | |||||||
ARP Acquisitions | Class C Preferred Units | ||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||
Partners unit, issued | 3,700,000 | |||||||
ARP Acquisitions | Class C Preferred Units | Minimum | ||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||
Distribution Made to Limited Partner, Distributions Declared, Per Unit | 0.51 | |||||||
ARP Acquisitions | Preferred class D | ||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||
Partners unit, issued | 800,000 | 3,200,000 | ||||||
Partners' Capital Account, Units, Percentage | 8.63% | |||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $0.62 | |||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit there after | $2.16 | |||||||
Percentage of Preferred Unit Regular Quarterly Cash Distributions | 8.63% | |||||||
Development Subsidiary | ||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||
Stock Issued During Period, Value, New Issues | 19,800,000 | |||||||
Gain on sale of subsidiary unit issuances | 400,000 | |||||||
Atlas Resource Partners, L.P. | ||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||
Gain on sale of subsidiary unit issuances | 200,000 | 40,500,000 | ||||||
Asset impairment | 562,600,000 | |||||||
Atlas Resource Partners, L.P. | Preferred Units | ||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||
Non-controlling interests | 97,600,000 | 78,000,000 | 97,600,000 | |||||
Atlas Resource Partners, L.P. | Titan Acquisition | ||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||
Preferred stock participation rights | While outstanding, the Class B ARP Preferred Units will receive regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution. | |||||||
Atlas Resource Partners, L.P. | Titan Acquisition | Class B Preferred Units | ||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||
Partners unit, issued | 3,800,000 | |||||||
Atlas Resource Partners, L.P. | Titan Acquisition | Class B Preferred Units | Minimum | ||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||
Distribution Made to Limited Partner, Distributions Declared, Per Unit | $0.40 | |||||||
Drilling Partnership wells | ||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||
Gathering Fee Percentage | 13.00% | |||||||
Secured Term Facility | ||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||
Repayments under credit facilities | 150,000,000 | |||||||
Credit facility | 240,000,000 | |||||||
Series A Preferred Units | Secured Term Facility | ||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||
Proceeds from Issuance of Convertible Preferred Stock | $150,000,000 |
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, 2015 | Dec. 31, 2014 |
Accounting Policies [Abstract] | ||
Gross Carrying Amount | $14,344 | $14,344 |
Accumulated Amortization | -13,712 | -13,653 |
Net Carrying Amount | $632 | $691 |
Estimated Useful Lives In Years | 13 years |
Summary_of_Significant_Account5
Summary of Significant Accounting Policies (Schedule of Net Income Reconciliation) (Details) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Reconciliation Of Net Income [Line Items] | ||
Net income (loss) | $53,479 | ($17,451) |
Loss (income) attributable to owner’s interest (period prior to the transfer of assets on February 27, 2015) | -10,475 | -7,143 |
Continuing Operations | ||
Reconciliation Of Net Income [Line Items] | ||
Loss (income) attributable to non-controlling interests | -58,298 | |
Loss (income) attributable to owner’s interest (period prior to the transfer of assets on February 27, 2015) | -10,475 | 17,451 |
Net income utilized in the calculation of net income attributable to common unit holders per unit | $5,656 |
Summary_of_Significant_Account6
Summary of Significant Accounting Policies (Reconciliation of Weighted Average Number of Common Unit Holder Units) (Details) | 3 Months Ended |
In Thousands, unless otherwise specified | Mar. 31, 2015 |
Accounting Policies [Abstract] | |
Weighted average number of common unit holders per unit—basic | 26,011 |
Add effect of dilutive incentive awards | 23 |
Add effect of dilutive convertible preferred units | 4,902 |
Weighted average number of common unit holders per unit—diluted | 30,936 |
Acquisitions_Rangely_Acquisiti
Acquisitions (Rangely Acquisition) (Narrative) (Details) (USD $) | 3 Months Ended | 1 Months Ended | ||
In Millions, except Share data, unless otherwise specified | Mar. 31, 2015 | 31-May-14 | Jun. 30, 2014 | Dec. 31, 2014 |
Business Acquisition [Line Items] | ||||
Partners unit, issued | 420,586 | |||
Rangely Acquisition | ||||
Business Acquisition [Line Items] | ||||
Partners unit, issued | 15,525,000 | |||
Atlas Resource Partners, L.P. | 7.75% Senior Notes | ||||
Business Acquisition [Line Items] | ||||
Debt instrument, interest rate, stated percentage | 7.75% | |||
Atlas Resource Partners, L.P. | Rangely Acquisition | ||||
Business Acquisition [Line Items] | ||||
Business acquisition, percentage of voting interests acquired | 25.00% | |||
Business acquisition, cost of acquired entity, cash paid | $408.90 | |||
Debt instrument, maturity date | 15-Aug-21 | |||
Business acquisition, effective date of acquisition | 1-Apr-14 | |||
Business acquisition, purchase price allocation, methodology | ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 9). | |||
Business acquisition, purchase price allocation, status | In conjunction with the issuance of ARP’s common limited partner units associated with the acquisition, ARP recorded $11.6 million of transaction fees which were included within non-controlling interests at December 31, 2014 on the Company’s combined consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred. Due to the recent date of the acquisition, the accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as ARP continues to evaluate the facts and circumstances that existed as of the acquisition date. | |||
Business acquisition, cost of acquired entity, transaction costs | 11.6 | |||
Atlas Resource Partners, L.P. | Rangely Acquisition | 7.75% Senior Notes | ||||
Business Acquisition [Line Items] | ||||
Proceed from additional senior notes | $100 | |||
Debt instrument, interest rate, stated percentage | 7.75% | |||
Partners unit, issued | 15,525,000 |
Acquisitions_Rangely_Acquisiti1
Acquisitions (Rangely Acquisition Schedule of Assets Acquired and Liabilities Assumed) (Details) (Rangely Acquisition, USD $) | Mar. 31, 2015 |
In Thousands, unless otherwise specified | |
Rangely Acquisition | |
Business Acquisition [Line Items] | |
Prepaid expenses and other | $4,041 |
Property, plant and equipment | 405,416 |
Other assets, net | 2,888 |
Total assets acquired | 412,345 |
Accrued liabilities | 2,117 |
Asset retirement obligation | 1,305 |
Total liabilities assumed | 3,422 |
Net assets acquired | $408,923 |
Acquisitions_Other_Acquisition
Acquisitions (Other Acquisition) (Narrative) (Details) (USD $) | 0 Months Ended | 3 Months Ended | 0 Months Ended | ||||
In Millions, unless otherwise specified | Nov. 05, 2014 | Mar. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | 12-May-14 |
Eagle Ford Acquisition | |||||||
Business Acquisition [Line Items] | |||||||
Business acquisition, date of acquisition agreement | 5-Nov-14 | ||||||
Net cash acquired | $339.20 | ||||||
Deferred portion of purchase price | 140 | ||||||
Purchase price represent non-cash transaction | 56.7 | ||||||
Business acquisition, effective date of acquisition | 1-Jul-14 | ||||||
Eagle Ford Acquisition | Development Subsidiary | |||||||
Business Acquisition [Line Items] | |||||||
Cash consideration | 19.7 | 28.3 | |||||
Deferred portion of purchase price | 35 | ||||||
Eagle Ford Acquisition | Atlas Resource Partners, L.P. | |||||||
Business Acquisition [Line Items] | |||||||
Cash consideration | 179.5 | ||||||
Deferred portion of purchase price payable in quarterly installments, beginning date | 30-Jun-15 | ||||||
Eagle Ford Acquisition | Atlas Resource Partners, L.P. | Class D Preferred Units | |||||||
Business Acquisition [Line Items] | |||||||
Business acquisition, cost of acquired entity, equity interests issued and issuable | 20 | ||||||
Eagle Ford Acquisition | Scenario Forecast | |||||||
Business Acquisition [Line Items] | |||||||
Deferred portion of purchase price | 21.7 | 17.5 | 17.5 | ||||
Geo Met | |||||||
Business Acquisition [Line Items] | |||||||
Cash consideration | $97.90 | ||||||
Business acquisition, effective date of acquisition | 1-Jan-14 | ||||||
Business acquisition, description of acquired entity | The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia. |
Property_Plant_and_Equipment_S
Property, Plant and Equipment (Summary of Property, Plant and Equipment) (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Property Plant And Equipment [Abstract] | ||
Proved properties: Leasehold interests | $458,507 | $535,893 |
Proved properties: Pre-development costs | 9,136 | 7,378 |
Proved properties: Wells and related equipment | 3,100,587 | 3,096,562 |
Total proved properties | 3,568,230 | 3,639,833 |
Unproved properties | 314,677 | 217,321 |
Support equipment | 40,992 | 37,359 |
Total natural gas and oil properties | 3,923,899 | 3,894,513 |
Pipelines, processing and compression facilities | 50,578 | 49,547 |
Rights of way | 829 | 830 |
Land, buildings and improvements | 9,201 | 9,160 |
Other | 18,059 | 17,936 |
Total gross property, plant and equipment | 4,002,566 | 3,971,986 |
Less – accumulated depreciation, depletion and amortization | -1,595,842 | -1,552,697 |
Property, plant and equipment, Net, Total | $2,406,724 | $2,419,289 |
Property_Plant_and_Equipment_U
Property, Plant and Equipment (Useful Life Narrative) (Details) | 3 Months Ended |
Mar. 31, 2015 | |
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, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | |
Property Plant And Equipment [Line Items] | |||
Loss on asset sales and disposal | ($11,000) | ($1,603,000) | |
Asset impairment | 0 | 0 | |
Future Hedge Gains | 82,300,000 | ||
Non-cash property, plant and equipment additions | 26,400,000 | 18,700,000 | |
Atlas Resource Partners, L.P. | |||
Property Plant And Equipment [Line Items] | |||
Asset impairment | $562,600,000 |
Other_Assets_Summary_of_Other_
Other Assets (Summary of Other Assets) (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Other Assets [Line Items] | ||
Deferred financing costs, net of accumulated amortization of $33,333 and $20,675 at March 31, 2015 and December 31, 2014, respectively | $47,601 | $46,120 |
Rabbi Trust | 5,641 | 3,925 |
Security deposits | 229 | 229 |
Other | 5,199 | 5,348 |
Total Other Assets | 83,208 | 80,611 |
Lightfoot | ||
Other Assets [Line Items] | ||
Investment in Lightfoot | 20,612 | 21,123 |
Atlas Resource Partners, L.P. | ||
Other Assets [Line Items] | ||
ARP notes receivable | $3,926 | $3,866 |
Other_Assets_Narrative_Details
Other Assets (Narrative) (Details) (USD $) | 3 Months Ended | ||
Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | |
Other Assets [Line Items] | |||
Accumulated amortization | $33,333,000 | $20,675,000 | |
Amortization of financing costs | 2,700,000 | 2,100,000 | |
Accelerated amortization of deferred financing costs | 5,700,000 | 0 | |
Distributions received from unconsolidated companies | 455,000 | 311,000 | |
Lightfoot LP | |||
Other Assets [Line Items] | |||
Equity method investment ownership percentage | 12.00% | ||
Distributions received from unconsolidated companies | 500,000 | 400,000 | |
Lightfoot GP | |||
Other Assets [Line Items] | |||
Equity method investment ownership percentage | 15.90% | ||
Lightfoot | |||
Other Assets [Line Items] | |||
Equity income (loss) in joint ventures | -100,000 | 200,000 | |
Atlas Resource Partners, L.P. | |||
Other Assets [Line Items] | |||
Accelerated amortization of deferred financing costs | 4,300,000 | 0 | |
Allowance for credit loss | 0 | 0 | |
Atlas Resource Partners, L.P. | Notes Receivable | |||
Other Assets [Line Items] | |||
Senior notes, maturity date | 31-Mar-22 | ||
Note agreement interest rate per annum | 2.25% | ||
Other interest and dividend income | $21,000 | $23,000 | |
Atlas Resource Partners, L.P. | Note Agreement, Option to Extend Maturity Date | |||
Other Assets [Line Items] | |||
Senior notes, maturity date | 31-Mar-27 | ||
Note agreement extension fee percent | 1.00% |
Asset_Retirement_Obligations_R
Asset Retirement Obligations (Reconciliation of Liability for Well Plugging and Abandonment Costs) (Narrative) (Details) (USD $) | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | |
Asset Retirement Obligations [Line Items] | ||||
Asset retirement obligations | $109,504,000 | $92,927,000 | $108,101,000 | $91,214,000 |
Limited Partner Interest | Series of Individually Immaterial Business Acquisitions | ||||
Asset Retirement Obligations [Line Items] | ||||
Oil and gas reclamation liabilities noncurrent | 0 | 0 | 100,000 | |
Relationship With Drilling Partnerships | ||||
Asset Retirement Obligations [Line Items] | ||||
Limited partner distributions withheld related to the asset retirement obligations of certain Drilling Partnerships | 2,100,000 | |||
Relationship With Drilling Partnerships | Limited Partner Interest | ||||
Asset Retirement Obligations [Line Items] | ||||
Asset retirement obligations | 45,100,000 | |||
Atlas Resource Partners, L.P. | Series of Individually Immaterial Business Acquisitions | ||||
Asset Retirement Obligations [Line Items] | ||||
Oil and gas reclamation liabilities noncurrent | $7,000,000 |
Asset_Retirement_Obligations_R1
Asset Retirement Obligations (Reconciliation of Liability for Well Plugging and Abandonment Costs) (Details) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Asset Retirement Obligation Roll Forward Analysis Roll Forward | ||
Asset retirement obligations, beginning of year | $108,101 | $91,214 |
Liabilities incurred | 169 | 602 |
Liabilities settled | -347 | -217 |
Accretion expense | 1,581 | 1,328 |
Asset retirement obligations, end of period | $109,504 | $92,927 |
Debt_Schedule_of_Total_Debt_Ou
Debt (Schedule of Total Debt Outstanding) (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Debt Instrument [Line Items] | ||
Total debt | $1,604,597 | |
Less current maturities | -104,419 | -1,500 |
Total long-term debt | 1,500,178 | |
9.25% Senior Notes | ||
Debt Instrument [Line Items] | ||
Debt instrument, interest rate, stated percentage | 9.25% | |
Atlas Energy | Term Loan | ||
Debt Instrument [Line Items] | ||
Term loan facilities | 104,419 | |
Atlas Resource Partners, L.P. | ||
Debt Instrument [Line Items] | ||
Term loan facilities | 242,658 | |
Revolving credit facility | 559,000 | |
Atlas Resource Partners, L.P. | 7.75% Senior Notes | ||
Debt Instrument [Line Items] | ||
Senior Notes | 374,563 | |
Debt instrument, interest rate, stated percentage | 7.75% | |
Atlas Resource Partners, L.P. | 9.25% Senior Notes | ||
Debt Instrument [Line Items] | ||
Senior Notes | $323,957 | |
Debt instrument, interest rate, stated percentage | 9.25% |
Debt_Term_Loan_Facilities_Deta
Debt (Term Loan Facilities) (Details) (USD $) | 3 Months Ended | 0 Months Ended | ||
Mar. 31, 2015 | Mar. 31, 2014 | Feb. 27, 2015 | Jul. 31, 2013 | |
Debt Instrument [Line Items] | ||||
Line of Credit Facility, initiation date | 27-Feb-15 | |||
Repayments under credit facilities | $298,000,000 | $215,000,000 | ||
Secured Term Facility | ||||
Debt Instrument [Line Items] | ||||
Line of Credit Facility, aggregate principal amount | 240,000,000 | |||
Repayments under credit facilities | 150,000,000 | |||
Term loan facilities | ||||
Debt Instrument [Line Items] | ||||
Recognized value ratio, description | Recognized Value Ratio (as defined in the Credit Agreement) is less than 2.00 to 1.00, the Company must prepay the Term Loan Facilities and any revolving loans outstanding in an aggregate principal amount necessary to achieve a Recognized Value Ratio of greater than 2.00 to 1.00; the Recognized Value Ratio is equal to the ratio of the Recognized Value | |||
Net cash proceeds from disposition of assets | 100.00% | |||
Leverage ratio under condition one | 3.75% | |||
Leverage ratio under condition two | 3.50% | |||
Total leverage ratio | 3.30% | |||
Term loan facilities | Maximum | ||||
Debt Instrument [Line Items] | ||||
Recognized value ratio | 200.00% | |||
Term loan facilities | Minimum | ||||
Debt Instrument [Line Items] | ||||
Recognized value ratio | 2.00% | |||
Secured Term Loan Facilities | ||||
Debt Instrument [Line Items] | ||||
Outstanding Term Facility, weighted average interest rate | 8.50% | |||
London Interbank Offered Rate (LIBOR) | Secured Term Loan Facilities | ||||
Debt Instrument [Line Items] | ||||
Debt instrument, basis spread on variable rate | 7.50% | |||
Federal Funds Effective Swap Rate | Secured Term Loan Facilities | ||||
Debt Instrument [Line Items] | ||||
Debt instrument, basis spread on variable rate | 0.50% | |||
One Month L I B O R | Secured Term Loan Facilities | ||||
Debt Instrument [Line Items] | ||||
Debt instrument, basis spread on variable rate | 1.00% | |||
Base Rate | Secured Term Loan Facilities | ||||
Debt Instrument [Line Items] | ||||
Debt instrument, basis spread on variable rate | 2.00% | |||
Alternate Base Rate | Secured Term Loan Facilities | ||||
Debt Instrument [Line Items] | ||||
Debt instrument, basis spread on variable rate | 6.50% | |||
Credit Agreement | ||||
Debt Instrument [Line Items] | ||||
Line of Credit Facility interest rate description | Borrowings under the Term Loan Facilities bear interest, at the Company’s option, at either (i) LIBOR plus 7.5% (“Eurodollar Loansâ€) or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, in each case plus 6.5% (an “ABR Loanâ€). Interest is generally payable at interest payment periods selected by the Company for Eurodollar Loans and quarterly for ABR Loans. At March 31, 2015, the weighted average interest rate on outstanding borrowings under the term loan facilities was 8.5%. | |||
Credit Agreement | Interim Term Loan Facility | ||||
Debt Instrument [Line Items] | ||||
Line of Credit Facility, aggregate principal amount | 30,000,000 | |||
Line of Credit Facility, expiration date | 27-Aug-15 | |||
Credit Agreement | Term A Loan Facility | ||||
Debt Instrument [Line Items] | ||||
Line of Credit Facility, aggregate principal amount | 97,800,000 | |||
Line of Credit Facility, expiration date | 26-Feb-16 | |||
Atlas Energy | ||||
Debt Instrument [Line Items] | ||||
Line of Credit Facility, initiation date | 31-Jul-13 | |||
Line of Credit Facility, aggregate principal amount | 240,000,000 | |||
Line of Credit Facility, expiration date | 31-Jul-19 | |||
Outstanding Term Facility, weighted average interest rate | 6.50% | |||
Atlas Energy | Term loan facilities | ||||
Debt Instrument [Line Items] | ||||
Term Loan Facilities, outstanding | 104,400,000 | |||
Term Loan Facilities, unamortized discount | 11,400,000 | |||
Term Loan Facilities | $11,900,000 |
Debt_Atlas_Energy_Term_Loan_Fa
Debt (Atlas Energy Term Loan Facility) (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Jul. 31, 2013 |
Debt Instrument [Line Items] | ||
Line of Credit Facility, initiation date | 27-Feb-15 | |
Atlas Energy | ||
Debt Instrument [Line Items] | ||
Line of Credit Facility, initiation date | 31-Jul-13 | |
Credit facility | $240 | |
Line of Credit Facility, expiration date | 31-Jul-19 | |
Senior Notes interest payment dates and terms | Borrowings under the Term Facility bore interest, at Atlas Energy’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 was generally payable quarterly for ABR loans and, for LIBOR loans at the interest periods selected by Atlas Energy. Atlas Energy was 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 was 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 | $0.60 | |
Outstanding Term Facility, weighted average interest rate | 6.50% |
Debt_ARP_Credit_Facility_Detai
Debt (ARP Credit Facility) (Details) (USD $) | 3 Months Ended | 0 Months Ended |
Mar. 31, 2015 | Feb. 23, 2015 | |
Revolving Credit Facility | ||
Line Of Credit Facility [Line Items] | ||
Required Total Funded Debt to EBITDA ratio | 5.25% | |
Revolving credit facility | $559,000,000 | |
Letters of credit outstanding amount | 4,300,000 | |
Line of Credit Facility collateral | ARP’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by certain of ARP’s material subsidiaries, and any non-guarantor subsidiaries of ARP are minor. | |
Line of Credit Facility interest rate description | at either an adjusted LIBOR rate plus an applicable margin between 1.50% and 2.75% per annum or the base rate (which is the higher of the bank’s prime rate, the Federal funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 0.50% and 1.75% per annum. ARP is also required to pay a fee on the unused portion of the borrowing base at a rate of 0.375% per annum if less than 50% of the borrowing base is utilized and 0.5% if 50% or more of the borrowing base is utilized, which is included within interest expense on the Company’s combined consolidated statements of operations. At March 31, 2015, the weighted average interest rate on outstanding borrowings under the credit facility was 2.8%. | |
Line of Credit Facility, weighted average interest rate | 2.80% | |
Line Of Credit Facility covenant terms | The ARP Credit Agreement contains customary covenants that limit ARP’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. ARP was in compliance with these covenants as of March 31, 2015. The ARP Credit Agreement also requires that ARP maintain a ratio of Total Funded Debt (as defined in the ARP Credit Agreement) to EBITDA (as defined in the ARP Credit Agreement) (actual or annualized, as applicable), calculated over a period of four consecutive fiscal quarters, of not greater than (i) 5.25 to 1.0 as of the last day of the quarters ended on March 31, 2015, June 30, 2015, September 30, 2015, December 31, 2015 and March 31, 2016, (ii) 5.00 to 1.0 as of the last day of the quarters ended on June 30, 2016, September 30, 2016 and December 31, 2016, (iii) 4.50 to 1.0 as of the last day of the quarter ended on March 31, 2017 and (iv) 4.00 to 1.0 as of the last day of each quarter thereafter, and a ratio of current assets (as defined in the ARP Credit Agreement) to current liabilities (as defined in the ARP Credit Agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter. | |
Line of Credit Facility, Covenant Compliance | ARP was in compliance with these covenants as of March 31, 2015. | |
Required current assets to current liabilities ratio | 1.00% | |
Current assets to current liabilities ratio | 1.60% | |
Total Funded Debt to EBITDA ratio | 4.20% | |
Revolving Credit Facility | Quarter Ended June Thirty Two Thousand And Fifteen | ||
Line Of Credit Facility [Line Items] | ||
Required Total Funded Debt to EBITDA ratio | 5.25% | |
Revolving Credit Facility | Quarter Ended September Thirty Two Thousand And Fifteen | ||
Line Of Credit Facility [Line Items] | ||
Required Total Funded Debt to EBITDA ratio | 5.25% | |
Revolving Credit Facility | Quarter Ended December Thirty First Two Thousand And Fifteen | ||
Line Of Credit Facility [Line Items] | ||
Required Total Funded Debt to EBITDA ratio | 5.25% | |
Revolving Credit Facility | Quarter Ended March Thirty First Two Thousand And Sixteen | ||
Line Of Credit Facility [Line Items] | ||
Required Total Funded Debt to EBITDA ratio | 5.25% | |
Revolving Credit Facility | Quarter Ended June Thirty Two Thousand And Sixteen | ||
Line Of Credit Facility [Line Items] | ||
Required Total Funded Debt to EBITDA ratio | 5.00% | |
Revolving Credit Facility | Quarter Ended September Thirty Two Thousand And Sixteen | ||
Line Of Credit Facility [Line Items] | ||
Required Total Funded Debt to EBITDA ratio | 5.00% | |
Revolving Credit Facility | Quarter Ended December Thirty First Two Thousand And Sixteen | ||
Line Of Credit Facility [Line Items] | ||
Required Total Funded Debt to EBITDA ratio | 5.00% | |
Revolving Credit Facility | Quarter Ended March Thirty First Two Thousand And Seventeen | ||
Line Of Credit Facility [Line Items] | ||
Required Total Funded Debt to EBITDA ratio | 4.50% | |
Revolving Credit Facility | Fiscal quarters ending thereafter | ||
Line Of Credit Facility [Line Items] | ||
Required Total Funded Debt to EBITDA ratio | 4.00% | |
Atlas Resource Partners, L.P. | ||
Line Of Credit Facility [Line Items] | ||
Revolving credit facility | 559,000,000 | |
Atlas Resource Partners, L.P. | Revolving Credit Facility | ||
Line Of Credit Facility [Line Items] | ||
Line of Credit Facility, current borrowing capacity | 900,000,000 | 750,000,000 |
Aggregate principal amount of second lien debt | $300,000,000 | |
Percentage of stated amount of senior notes or additional second lien debt that borrowing base reduced | 25.00% | |
Atlas Resource Partners, L.P. | Revolving Credit Facility | Borrowing base utilization is less than 90% | Eurodollar | ||
Line Of Credit Facility [Line Items] | ||
Increase in applicable margin | 0.25% | |
Atlas Resource Partners, L.P. | Revolving Credit Facility | Borrowing base utilization is less than 90% | Alternate Base Rate | ||
Line Of Credit Facility [Line Items] | ||
Increase in applicable margin | 0.25% | |
Atlas Resource Partners, L.P. | Revolving Credit Facility | Quarter ended March 31, 2015 | ||
Line Of Credit Facility [Line Items] | ||
Required Total Funded Debt to EBITDA ratio | 5.25% | |
Atlas Resource Partners, L.P. | Revolving Credit Facility | Quarter Ended June Thirty Two Thousand And Fifteen | ||
Line Of Credit Facility [Line Items] | ||
Required Total Funded Debt to EBITDA ratio | 5.25% | |
Atlas Resource Partners, L.P. | Revolving Credit Facility | Quarter Ended September Thirty Two Thousand And Fifteen | ||
Line Of Credit Facility [Line Items] | ||
Required Total Funded Debt to EBITDA ratio | 5.25% | |
Atlas Resource Partners, L.P. | Revolving Credit Facility | Quarter Ended December Thirty First Two Thousand And Fifteen | ||
Line Of Credit Facility [Line Items] | ||
Required Total Funded Debt to EBITDA ratio | 5.25% | |
Atlas Resource Partners, L.P. | Revolving Credit Facility | Quarter Ended March Thirty First Two Thousand And Sixteen | ||
Line Of Credit Facility [Line Items] | ||
Required Total Funded Debt to EBITDA ratio | 5.25% | |
Atlas Resource Partners, L.P. | Revolving Credit Facility | Quarter Ended June Thirty Two Thousand And Sixteen | ||
Line Of Credit Facility [Line Items] | ||
Required Total Funded Debt to EBITDA ratio | 5.00% | |
Atlas Resource Partners, L.P. | Revolving Credit Facility | Quarter Ended September Thirty Two Thousand And Sixteen | ||
Line Of Credit Facility [Line Items] | ||
Required Total Funded Debt to EBITDA ratio | 5.00% | |
Atlas Resource Partners, L.P. | Revolving Credit Facility | Quarter Ended December Thirty First Two Thousand And Sixteen | ||
Line Of Credit Facility [Line Items] | ||
Required Total Funded Debt to EBITDA ratio | 5.00% | |
Atlas Resource Partners, L.P. | Revolving Credit Facility | Quarter Ended March Thirty First Two Thousand And Seventeen | ||
Line Of Credit Facility [Line Items] | ||
Required Total Funded Debt to EBITDA ratio | 4.50% | |
Atlas Resource Partners, L.P. | Revolving Credit Facility | Fiscal quarters ending thereafter | ||
Line Of Credit Facility [Line Items] | ||
Required Total Funded Debt to EBITDA ratio | 4.00% | |
Atlas Resource Partners, L.P. | Revolving Credit Facility | Maximum | Borrowing base utilization is less than 90% | ||
Line Of Credit Facility [Line Items] | ||
Percentage of borrowing base utilized | 90.00% |
Debt_ARP_Term_Loan_Facility_De
Debt (ARP Term Loan Facility) (Details) (USD $) | 0 Months Ended | 3 Months Ended |
In Millions, unless otherwise specified | Feb. 23, 2015 | Mar. 31, 2015 |
Debt Instrument, Redemption, Period Two | ||
Debt Instrument [Line Items] | ||
Principal amount prepaid for repayments | 45.00% | |
Debt Instrument, Redemption, Period Three | ||
Debt Instrument [Line Items] | ||
Principal amount prepaid for repayments | 2.25% | |
Second Lien Credit Agreement | ||
Debt Instrument [Line Items] | ||
Line of Credit Facility interest rate description | Borrowings under the ARP Term Loan Facility bear interest, at ARP’s option, at either (i) LIBOR plus 9.0% or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, each plus 8.0% (an “ABR Loanâ€). Interest is generally payable at the applicable maturity date for Eurodollar loans and quarterly for ABR loans. | |
Line of Credit Facility, weighted average interest rate | 10.00% | |
Principal amount of term loan facility | $300 | |
Second Lien Credit Agreement | Incremental Term Loan | ||
Debt Instrument [Line Items] | ||
Line of Credit Facility, expiration date | 23-Feb-20 | |
Second Lien Credit Agreement | London Interbank Offered Rate (LIBOR) | ||
Debt Instrument [Line Items] | ||
Debt instrument, basis spread on variable rate | 9.00% | |
Second Lien Credit Agreement | Federal Funds Effective Swap Rate | ||
Debt Instrument [Line Items] | ||
Debt instrument, basis spread on variable rate | 0.50% | |
Second Lien Credit Agreement | One Month L I B O R | ||
Debt Instrument [Line Items] | ||
Debt instrument, basis spread on variable rate | 1.00% | |
Second Lien Credit Agreement | Base Rate | ||
Debt Instrument [Line Items] | ||
Debt instrument, basis spread on variable rate | 2.00% | |
Second Lien Credit Agreement | Alternate Base Rate | ||
Debt Instrument [Line Items] | ||
Debt instrument, basis spread on variable rate | 8.00% | |
Second Lien Credit Agreement | Debt Instrument, Redemption, Period Four | ||
Debt Instrument [Line Items] | ||
Principal amount prepaid for repayments | 0.00% | |
Atlas Resource Partners, L.P. | Second Lien Credit Agreement | ||
Debt Instrument [Line Items] | ||
Line of Credit Facility, aggregate principal amount | 250 | |
Line of Credit Facility, expiration date | 23-Feb-20 | |
Term Loan Facilities, unamortized discount | 7.3 | |
Net cash proceeds from the issuance or incurrence of debt | 100.00% | |
Excess net cash proceeds from certain asset sales and condemnation recoveries | 100.00% |
Debt_Senior_Notes_Details
Debt (Senior Notes) (Details) (USD $) | 3 Months Ended | 0 Months Ended | ||
Mar. 31, 2015 | Mar. 31, 2014 | Oct. 14, 2014 | Jun. 02, 2014 | |
Debt Instrument [Line Items] | ||||
Debt instrument, restrictive covenants | The indentures governing the 7.75% ARP Senior Notes and 9.25% ARP Senior Notes contain covenants, including limitations of ARP’s ability to incur certain liens, incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase, or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of ARP’s assets. | |||
Debt instrument, covenant compliance | ARP was in compliance with these covenants as of March 31, 2015. | |||
Cash paid on accrued interest on debt | $38,500,000 | $28,900,000 | ||
7.75% Senior Notes | ||||
Debt Instrument [Line Items] | ||||
Restrictions as to the ability to obtain cash or any other distribution of funds from the guarantor | 0 | |||
9.25% Senior Notes | ||||
Debt Instrument [Line Items] | ||||
Debt instrument, issuance date | 14-Oct-14 | |||
Aggregate principal amount of second lien debt | 324,000,000 | 75,000,000 | ||
Senior Notes, maturity | 2021 | |||
Debt instrument, interest rate, stated percentage | 9.25% | |||
Term Loan Facilities, unamortized discount | 1,000,000 | |||
Senior Notes interest payment dates and terms | Interest on the 9.25% ARP Senior Notes is payable semi-annually on February 15 and August 15. | |||
Debt instrument, call feature | At any time prior to August 15, 2017, ARP may redeem the 9.25% ARP Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes plus the Applicable Premium (as defined in the governing indenture), plus accrued and unpaid interest, if any. 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%. 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. | |||
Registration rights agreement, description and terms | On April 15, 2015, the registration statement relating to the exchange offer for the 9.25% ARP Senior Notes was declared effective, and the exchange offer was subsequently launched on April 15, 2015. | |||
Atlas Resource Partners, L.P. | 7.75% Senior Notes | ||||
Debt Instrument [Line Items] | ||||
Debt instrument, issuance date | 2-Jun-14 | |||
Aggregate principal amount of second lien debt | 374,600,000 | |||
Senior Notes, maturity | 2021 | |||
Debt instrument, interest rate, stated percentage | 7.75% | |||
Term Loan Facilities, unamortized discount | $400,000 | |||
Senior Notes interest payment dates and terms | Interest on the 7.75% ARP Senior Notes is payable semi-annually on January 15 and July 15. | |||
Repurchase, make whole and redemption terms and description | At any time prior to January 15, 2016, the 7.75% ARP Senior Notes are redeemable for up to 35% of the outstanding principal amount with the net cash proceeds of equity offerings at the redemption price of 107.75%. The 7.75% ARP Senior Notes are also subject to repurchase at a price equal to 101% of the principal amount, plus accrued and unpaid interest, upon a change of control. At any time prior to January 15, 2017, ARP may redeem the 7.75% ARP Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes plus the Applicable Premium (as defined in the governing indenture), plus accrued and unpaid interest, if any. On and after January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price of 103.875%, decreasing to 101.938% on January 15, 2018 and 100% on January 15, 2019 | |||
Atlas Resource Partners, L.P. | 9.25% Senior Notes | ||||
Debt Instrument [Line Items] | ||||
Debt instrument, interest rate, stated percentage | 9.25% |
Derivative_Instruments_Narrati
Derivative Instruments (Narrative) (Details) (USD $) | 3 Months Ended | ||
Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | |
Derivative Instruments Gain Loss [Line Items] | |||
Cash flow hedges derivative assets at fair value, net | $333,200,000 | $274,900,000 | |
Net gain in accumulated other comprehensive income | 46,000,000 | ||
Cash flow hedge gain (losses) to be reclassified within twelve months | 22,600,000 | ||
Cash flow hedge gain (loss) to be reclassified in later periods | 23,400,000 | ||
Derivative instruments, gains reclassified from accumulated OCI into income, effective portion | 0 | ||
Cash settlements on commodity derivative contracts | 42,546,000 | ||
Gain (loss) recognized for hedge Ineffectiveness or as a result of discontinuance of cash flow hedges | 0 | 0 | |
Atlas Resource Partners, L.P. | |||
Derivative Instruments Gain Loss [Line Items] | |||
Net unrealized derivative assets payable to limited partners | 3,000,000 | ||
Crude Oil and Natural Gas | |||
Derivative Instruments Gain Loss [Line Items] | |||
Proceeds from early termination of commodity derivatives | $4,900,000 |
Derivative_Instruments_Summary
Derivative Instruments (Summary of Commodity Derivative Activity) (Details) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | ||
Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets | ($27,343) | [1] |
Portion of settlements attributable to subsequent mark to market gains | -15,203 | |
Total cash settlements on commodity derivative contracts | -42,546 | |
2015 Unrealized gains prior to settlement | 3,203 | [2] |
Unrealized gain on open derivative contracts at March 31, 2015, net of amounts recognized in income in prior year | $102,382 | [2] |
[1] | Recognized in gas and oil production revenue. | |
[2] | Recognized in gain on mark-to-market derivatives. |
Derivative_Instruments_Fair_Va
Derivative Instruments (Fair Values of the Company's Derivative Instruments Table) (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | $339,024 | $279,254 |
Gross Amounts of Recognized Liabilities | -219 | -468 |
Current portion of derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 947 | 2,893 |
Net Amount of Assets Presented in the Combined Consolidated Balance Sheets | 947 | 2,893 |
Total derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 947 | 5,562 |
Net Amount of Assets Presented in the Combined Consolidated Balance Sheets | 947 | 5,562 |
Long-term portion of derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 2,669 | |
Net Amount of Assets Presented in the Combined Consolidated Balance Sheets | $2,669 |
Derivative_Instruments_The_Com
Derivative Instruments (The Company's Commodity Derivative Instruments by Type Table) (Details) (USD $) | Mar. 31, 2015 | |
In Thousands, unless otherwise specified | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset / (Liability) | $119,763 | [1] |
Production Period Ending March 31 2015 | Natural Gas - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 570,000 | [2] |
Derivative, Swap Type, Average Fixed Price | 4.302 | [2] |
Fair Value Asset / (Liability) | 947 | [3] |
Production Period Ending March 31 2016 | Natural Gas - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset / (Liability) | $947 | [3] |
[1] | Fair value based on forward WTI crude oil prices, as applicable. | |
[2] | “MMBtu†represents million British Thermal Units. | |
[3] | Fair value based on forward NYMEX natural gas prices, as applicable. |
Derivative_Instruments_Fair_Va1
Derivative Instruments (Fair Value of ARP's Derivative Instruments Table) (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | $339,024 | $279,254 |
Gross Amounts of Recognized Liabilities | -219 | -468 |
Current portion of derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 947 | 2,893 |
Net Amount of Assets Presented in the Combined Consolidated Balance Sheets | 947 | 2,893 |
Long-term portion of derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 2,669 | |
Net Amount of Assets Presented in the Combined Consolidated Balance Sheets | 2,669 | |
Total derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 947 | 5,562 |
Net Amount of Assets Presented in the Combined Consolidated Balance Sheets | 947 | 5,562 |
Atlas Resource Partners, L.P. | Current portion of derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 145,520 | 141,464 |
Gross Amounts Offset in the Combined Consolidated Balance Sheets | -21 | -98 |
Net Amount of Assets Presented in the Combined Consolidated Balance Sheets | 145,499 | 141,366 |
Atlas Resource Partners, L.P. | Long-term portion of derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 186,916 | 128,303 |
Gross Amounts Offset in the Combined Consolidated Balance Sheets | -198 | -370 |
Net Amount of Assets Presented in the Combined Consolidated Balance Sheets | 186,718 | 127,933 |
Atlas Resource Partners, L.P. | Total derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Assets | 332,436 | 269,767 |
Gross Amounts Offset in the Combined Consolidated Balance Sheets | -219 | -468 |
Net Amount of Assets Presented in the Combined Consolidated Balance Sheets | 332,217 | 269,299 |
Atlas Resource Partners, L.P. | Current portion of derivative liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Liabilities | -21 | -98 |
Gross Amounts Offset in the Combined Consolidated Balance Sheets | 21 | 98 |
Atlas Resource Partners, L.P. | Long-term portion of derivative liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Liabilities | -198 | -370 |
Gross Amounts Offset in the Combined Consolidated Balance Sheets | 198 | 370 |
Atlas Resource Partners, L.P. | Total derivative liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts of Recognized Liabilities | -219 | -468 |
Gross Amounts Offset in the Combined Consolidated Balance Sheets | $219 | $468 |
Derivative_Instruments_ARPs_Co
Derivative Instruments (ARP's Commodity Derivative Instruments by Type Table) (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2013 | ||
In Thousands, unless otherwise specified | ||||
Derivatives Fair Value [Line Items] | ||||
Fair Value Asset / (Liability) | $119,763 | [1] | ||
Atlas Resource Partners, L.P. | Natural Gas - Fixed Price Swaps | ||||
Derivatives Fair Value [Line Items] | ||||
Fair Value Asset / (Liability) | 193,991 | [2] | ||
Atlas Resource Partners, L.P. | Natural Gas Costless Collars | ||||
Derivatives Fair Value [Line Items] | ||||
Fair Value Asset / (Liability) | 3,654 | [2] | ||
Atlas Resource Partners, L.P. | Natural Gas Put Options Drilling Partnership | ||||
Derivatives Fair Value [Line Items] | ||||
Fair Value Asset / (Liability) | 2,961 | [2] | ||
Atlas Resource Partners, L.P. | Natural Gas - WAHA Basis Swaps | ||||
Derivatives Fair Value [Line Items] | ||||
Fair Value Asset / (Liability) | 239 | [3] | ||
Atlas Resource Partners, L.P. | Natural Gas Liquids Natural Gasoline Fixed Price Swaps | ||||
Derivatives Fair Value [Line Items] | ||||
Fair Value Asset / (Liability) | 3,122 | [4] | ||
Atlas Resource Partners, L.P. | Natural Gas Liquids Propane Fixed Price Swaps | ||||
Derivatives Fair Value [Line Items] | ||||
Fair Value Asset / (Liability) | 2,896 | [5] | ||
Atlas Resource Partners, L.P. | Natural Gas Liquids - Butane Fixed Price Swaps | ||||
Derivatives Fair Value [Line Items] | ||||
Fair Value Asset / (Liability) | 676 | [6] | ||
Atlas Resource Partners, L.P. | Natural Gas Liquids Iso Butane Fixed Price Swaps | ||||
Derivatives Fair Value [Line Items] | ||||
Fair Value Asset / (Liability) | 689 | [7] | ||
Atlas Resource Partners, L.P. | Natural Gas Liquids Crude Oil Fixed Price Swaps | ||||
Derivatives Fair Value [Line Items] | ||||
Fair Value Asset / (Liability) | 3,589 | [1] | ||
Atlas Resource Partners, L.P. | Crude Oil - Costless Collars | ||||
Derivatives Fair Value [Line Items] | ||||
Fair Value Asset / (Liability) | 637 | [1] | ||
Atlas Resource Partners, L.P. | Total ARP Net Liability | ||||
Derivatives Fair Value [Line Items] | ||||
Fair Value Asset / (Liability) | 332,217 | [1] | ||
Atlas Resource Partners, L.P. | 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 | 40,053,400 | [8] | ||
Derivative, Swap Type, Average Fixed Price | 4.21 | [8] | ||
Fair Value Asset / (Liability) | 56,994 | [2] | ||
Atlas Resource Partners, L.P. | 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 | 2,520,000 | [8] | ||
Fair Value Asset / (Liability) | 3,670 | [2] | ||
Average Floor and Cap | 4.21 | [8] | ||
Atlas Resource Partners, L.P. | 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 | 2,520,000 | [8] | ||
Fair Value Asset / (Liability) | -16 | [2] | ||
Average Floor and Cap | 5.09 | [8] | ||
Atlas Resource Partners, L.P. | 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 | 1,080,000 | [8] | ||
Derivative, Swap Type, Average Fixed Price | 4 | [8] | ||
Fair Value Asset / (Liability) | 1,328 | [2] | ||
Atlas Resource Partners, L.P. | Production Period Ending December 31 2015 | Natural Gas - WAHA Basis Swaps | ||||
Derivatives Fair Value [Line Items] | ||||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 3,600,000 | [8] | ||
Derivative, Swap Type, Average Fixed Price | -0.09 | [8] | ||
Fair Value Asset / (Liability) | 239 | [3] | ||
Atlas Resource Partners, L.P. | Production Period Ending December 31 2015 | Natural Gas Liquids Natural Gasoline Fixed Price Swaps | ||||
Derivatives Fair Value [Line Items] | ||||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 3,780,000 | [8] | ||
Derivative, Swap Type, Average Fixed Price | 1.956 | [8] | ||
Fair Value Asset / (Liability) | 3,122 | [4] | ||
Atlas Resource Partners, L.P. | Production Period Ending December 31 2015 | Natural Gas Liquids Propane Fixed Price Swaps | ||||
Derivatives Fair Value [Line Items] | ||||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 6,048,000 | [8] | ||
Derivative, Swap Type, Average Fixed Price | 1.016 | [8] | ||
Fair Value Asset / (Liability) | 2,896 | [5] | ||
Atlas Resource Partners, L.P. | Production Period Ending December 31 2015 | Natural Gas Liquids - Butane Fixed Price Swaps | ||||
Derivatives Fair Value [Line Items] | ||||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 1,134,000 | [8] | ||
Derivative, Swap Type, Average Fixed Price | 1.248 | [8] | ||
Fair Value Asset / (Liability) | 676 | [6] | ||
Atlas Resource Partners, L.P. | Production Period Ending December 31 2015 | Natural Gas Liquids Iso Butane Fixed Price Swaps | ||||
Derivatives Fair Value [Line Items] | ||||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 1,134,000 | [8] | ||
Derivative, Swap Type, Average Fixed Price | 1.263 | [8] | ||
Fair Value Asset / (Liability) | 689 | [7] | ||
Atlas Resource Partners, L.P. | Production Period Ending December 31 2015 | Natural Gas Liquids – Crude Oil Fixed Price Swaps | ||||
Derivatives Fair Value [Line Items] | ||||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 1,444,500 | [8] | ||
Derivative, Swap Type, Average Fixed Price | 87.585 | [8] | ||
Fair Value Asset / (Liability) | 50,453 | [1] | ||
Atlas Resource Partners, L.P. | Production Period Ending December 31 2015 | Crude Oil - Costless Collars | Puts Purchased | ||||
Derivatives Fair Value [Line Items] | ||||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 19,500 | [8] | ||
Fair Value Asset / (Liability) | 638 | [1] | ||
Average Floor and Cap | 83.846 | [8] | ||
Atlas Resource Partners, L.P. | Production Period Ending December 31 2015 | Crude Oil - Costless Collars | Calls Sold | ||||
Derivatives Fair Value [Line Items] | ||||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 19,500 | [8] | ||
Fair Value Asset / (Liability) | -1 | [1] | ||
Average Floor and Cap | 110.654 | [8] | ||
Atlas Resource Partners, L.P. | Production Period Ending December 31 2016 | Natural Gas - Fixed Price Swaps | ||||
Derivatives Fair Value [Line Items] | ||||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 53,546,300 | [8] | ||
Derivative, Swap Type, Average Fixed Price | 4.229 | [8] | ||
Fair Value Asset / (Liability) | 59,049 | [2] | ||
Atlas Resource Partners, L.P. | 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 | [8] | ||
Derivative, Swap Type, Average Fixed Price | 4.15 | [8] | ||
Fair Value Asset / (Liability) | 1,633 | [2] | ||
Atlas Resource Partners, L.P. | Production Period Ending December 31 2016 | Natural Gas Liquids Crude Oil Fixed Price Swaps | ||||
Derivatives Fair Value [Line Items] | ||||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 84,000 | [8] | ||
Derivative, Swap Type, Average Fixed Price | 85.651 | [8] | ||
Fair Value Asset / (Liability) | 2,274 | [1] | ||
Atlas Resource Partners, L.P. | Production Period Ending December 31 2016 | Natural Gas Liquids – Crude Oil Fixed Price Swaps | ||||
Derivatives Fair Value [Line Items] | ||||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 1,425,000 | [8] | ||
Derivative, Swap Type, Average Fixed Price | 83.496 | [8] | ||
Fair Value Asset / (Liability) | 35,544 | [1] | ||
Atlas Resource Partners, L.P. | 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 | 49,920,000 | [8] | ||
Derivative, Swap Type, Average Fixed Price | 4.219 | [8] | ||
Fair Value Asset / (Liability) | 42,447 | [2] | ||
Atlas Resource Partners, L.P. | Production Period Ending December 31 2017 | Natural Gas Liquids Crude Oil Fixed Price Swaps | ||||
Derivatives Fair Value [Line Items] | ||||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 60,000 | [8] | ||
Derivative, Swap Type, Average Fixed Price | 83.78 | [8] | ||
Fair Value Asset / (Liability) | 1,315 | [1] | ||
Atlas Resource Partners, L.P. | Production Period Ending December 31 2017 | Natural Gas Liquids – Crude Oil Fixed Price Swaps | ||||
Derivatives Fair Value [Line Items] | ||||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 1,140,000 | [8] | ||
Derivative, Swap Type, Average Fixed Price | 77.285 | [8] | ||
Fair Value Asset / (Liability) | 17,766 | [1] | ||
Atlas Resource Partners, L.P. | 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 | 40,800,000 | [8] | ||
Derivative, Swap Type, Average Fixed Price | 4.17 | [8] | ||
Fair Value Asset / (Liability) | 28,182 | [2] | ||
Atlas Resource Partners, L.P. | Production Period Ending December 31 2018 | Natural Gas Liquids – Crude Oil Fixed Price Swaps | ||||
Derivatives Fair Value [Line Items] | ||||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 1,080,000 | [8] | ||
Derivative, Swap Type, Average Fixed Price | 76.281 | [8] | ||
Fair Value Asset / (Liability) | 13,804 | [1] | ||
Atlas Resource Partners, L.P. | Production Period Ending December 31 2019 | Natural Gas - Fixed Price Swaps | ||||
Derivatives Fair Value [Line Items] | ||||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 15,960,000 | [8] | ||
Derivative, Swap Type, Average Fixed Price | 4.017 | [8] | ||
Fair Value Asset / (Liability) | 7,319 | [2] | ||
Atlas Resource Partners, L.P. | Production Period Ending December 31 2019 | Natural Gas Liquids – Crude Oil Fixed Price Swaps | ||||
Derivatives Fair Value [Line Items] | ||||
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units | 540,000 | [8] | ||
Derivative, Swap Type, Average Fixed Price | 68.371 | [8] | ||
Fair Value Asset / (Liability) | $2,196 | [1] | ||
[1] | Fair value based on forward WTI crude oil prices, as applicable. | |||
[2] | Fair value based on forward NYMEX natural gas prices, as applicable. | |||
[3] | Fair value based on forward WAHA natural gas prices, as applicable | |||
[4] | Fair value based on forward Mt. Belvieu natural gasoline prices, as applicable. | |||
[5] | Fair value based on forward Mt. Belvieu propane prices, as applicable. | |||
[6] | Fair value based on forward Mt. Belvieu butane prices, as applicable. | |||
[7] | Fair value based on forward Mt. Belvieu iso butane prices, as applicable. | |||
[8] | “MMBtu†represents million British Thermal Units; “Bbl†represents barrels; “Gal†represents gallons. |
Fair_Value_of_Financial_Instru2
Fair Value of Financial Instruments (Schedule of Assets/Liabilities at Fair Value) (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | $339,024 | $279,254 |
Liabilities, gross | -219 | -468 |
Total assets, fair value, net | 338,805 | 278,786 |
Rabbi trust | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Rabbi trust | 5,641 | 3,925 |
Swap | Commodity Contract | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 947 | 5,562 |
Level 1 | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 5,641 | 3,925 |
Total assets, fair value, net | 5,641 | 3,925 |
Level 1 | Rabbi trust | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Rabbi trust | 5,641 | 3,925 |
Level 2 | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 333,383 | 275,329 |
Liabilities, gross | -219 | -468 |
Total assets, fair value, net | 333,164 | 274,861 |
Level 2 | Swap | Commodity Contract | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 947 | 5,562 |
Atlas Resource Partners, L.P. | Puts | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 2,961 | 2,767 |
Atlas Resource Partners, L.P. | Swap | Commodity Contract | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 325,167 | 261,680 |
Liabilities, gross | -202 | -401 |
Atlas Resource Partners, L.P. | Commodity Options | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 4,308 | 5,320 |
Liabilities, gross | -17 | -67 |
Atlas Resource Partners, L.P. | Level 2 | Puts | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 2,961 | 2,767 |
Atlas Resource Partners, L.P. | Level 2 | Swap | Commodity Contract | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 325,167 | 261,680 |
Liabilities, gross | -202 | -401 |
Atlas Resource Partners, L.P. | Level 2 | Commodity Options | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 4,308 | 5,320 |
Liabilities, gross | ($17) | ($67) |
Fair_Value_of_Financial_Instru3
Fair Value of Financial Instruments (Narrative) (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Dec. 31, 2014 |
Fair Value Disclosures [Abstract] | ||
Long-term debt, fair value | 1,402.20 | $1,363.40 |
Long-term debt | 1,604.60 | $1,542.60 |
Level 3 | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Business acquisition, purchase price allocation, status | During the year ended December 31, 2014, ARP completed the Eagle Ford, Rangely and GeoMet acquisitions and the Development Subsidiary completed the Eagle Ford Acquisition (see Note 3). The fair value measurements of assets acquired and liabilities assumed for each of these acquisitions are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The estimated fair values of the assets acquired and liabilities assumed in the Eagle Ford and Rangely acquisitions as of the acquisition date, which are reflected in the Company’s combined consolidated balance sheet as of March 31, 2015 are subject to change as the final valuations have not yet been completed, and such changes could 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 Company’s and its subsidiaries’ existing methodology for recognizing an estimated liability for the plugging and abandonment of their gas and oil wells (see Note 6). These inputs require significant judgments and estimates by the Company’s and its subsidiaries’ management at the time of the valuation and are subject to change. |
Fair_Value_of_Financial_Instru4
Fair Value of Financial Instruments (Schedule of Assets and Liabilities Measured on Non Recurring Basis) (Details) (USD $) | 3 Months Ended | |
Mar. 31, 2015 | Mar. 31, 2014 | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Liabilities incurred | $169,000 | $602,000 |
Asset impairment | 0 | 0 |
Level 3 | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Liabilities incurred | 169,000 | 602,000 |
Asset Retirement Obligations | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Liabilities incurred | 169,000 | 602,000 |
Asset Retirement Obligations | Level 3 | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Liabilities incurred | $169,000 | $602,000 |
Certain_Relationships_and_Rela1
Certain Relationships and Related Party Transactions (Narrative) (Details) (Relationship With Drilling Partnerships) | 3 Months Ended |
Mar. 31, 2015 | |
Relationship With Drilling Partnerships | |
Related Party Transaction [Line Items] | |
Related party transaction, description of transaction | ARP conducts certain activities through, and a portion of its revenues are attributable to, sponsorship of 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 |
Commitments_and_Contingencies_
Commitments and Contingencies (General Commitments) (Details) (USD $) | 3 Months Ended | |
Mar. 31, 2015 | Mar. 31, 2014 | |
Percentage of present value of future cash flows | 10.00% | |
Net partnership revenues subordinated | $500,000 | $3,500,000 |
Commitment to expend | 4,100,000 | |
Geo Met | ||
Contractual obligation, due remainder of the fiscal year | 2,300,000 | |
Contractual obligation, due in second year | 2,300,000 | |
Contractual obligation, due in third year | 1,900,000 | |
Contractual obligation, due in fourth year | 1,800,000 | |
Contractual obligation, due in fifth year | 1,800,000 | |
Contractual obligation, due in thereafter | 6,500,000 | |
EP Energy Acquisition | ||
Contractual obligation, due remainder of the fiscal year | 6,200,000 | |
Contractual obligation, due in second year | 2,100,000 | |
Contractual obligation, due in third year | 0 | |
Contractual obligation, due in fourth year | 0 | |
Contractual obligation, due in fifth year | $0 | |
Minimum | ||
Partnership obligations to purchase units from investor partners | 5.00% | |
Investor partners return on investment | 10.00% | |
Maximum | ||
Partnership obligations to purchase units from investor partners | 10.00% | |
Percentage on unhedged revenue | 50.00% | |
Investor partners return on investment | 12.00% |
Issuances_of_Units_Preferred_U
Issuances of Units (Preferred Unit Purchase Agreement) (Details) (USD $) | 0 Months Ended | 3 Months Ended |
In Millions, except Per Share data, unless otherwise specified | Feb. 27, 2015 | Mar. 31, 2015 |
Capital Unit [Line Items] | ||
Percentage Of Common Unit Regular Quarterly Cash Distributions | 2.00% | |
Series A Convertible Preferred Units | ||
Capital Unit [Line Items] | ||
Partners Capital Account Units Date Of Sale | 27-Feb-15 | |
Partners' Capital Account, Units, Sold in Private Placement | 1.6 | |
Redemption price per unit | $25 | |
Subsidiary or Equity Method Investee, Price-Per-Share | $25 | |
Partners' Capital Account, Private Placement of Units | $40 | |
Cash consideration | $150 | |
Percentage of Preferred Unit Regular Quarterly Cash Distributions | 2.00% | |
Conversion price policy description | The conversion price will be equal to the greater of (i) $8.00 per common unit of the Company; and (ii) the lower of (a) 110.0% of the volume weighted average price for the Company’s common units on the NYSE over the 30 trading days following the distribution date; and (b) $16.00 per common unit of the Company. | |
Volume weighted average price | 110.00% | |
Series A Convertible Preferred Units | Maximum | ||
Capital Unit [Line Items] | ||
Conversion per unit | 16 | |
Series A Convertible Preferred Units | Minimum | ||
Capital Unit [Line Items] | ||
Conversion per unit | 8 | |
Series A Convertible Preferred Units | Private Placement | Maximum | ||
Capital Unit [Line Items] | ||
Percentage of Preferred Unit Regular Quarterly Cash Distributions | 10.00% | |
Series A Convertible Preferred Units | Private Placement | First Anniversary | Maximum | ||
Capital Unit [Line Items] | ||
Percentage of Preferred Unit Regular Quarterly Cash Distributions | 12.00% | |
Series A Convertible Preferred Units | Private Placement | Second Anniversary | Maximum | ||
Capital Unit [Line Items] | ||
Percentage of Preferred Unit Regular Quarterly Cash Distributions | 14.00% | |
Series A Convertible Preferred Units | Private Placement | Third Anniversary | Maximum | ||
Capital Unit [Line Items] | ||
Percentage of Preferred Unit Regular Quarterly Cash Distributions | 16.00% |
Issuances_of_Units_Atlas_Resou
Issuances of Units (Atlas Resource Partners) (Details) (USD $) | 1 Months Ended | 3 Months Ended | 12 Months Ended | 0 Months Ended | 1 Months Ended | ||
In Millions, except Share data, unless otherwise specified | Aug. 31, 2014 | Mar. 31, 2015 | Dec. 31, 2014 | Jan. 15, 2015 | Oct. 31, 2014 | 31-May-14 | Mar. 31, 2014 |
Capital Unit [Line Items] | |||||||
Partners unit, issued | 420,586 | ||||||
Aggregate Offering Price Of Common Units (Maximum) | $100 | ||||||
Agent commission, maximum percentage, of the gross sales price of common limited partner units sold. | 2.00% | ||||||
Proceeds from Issuance of Common Limited Partners Units | 3.3 | ||||||
Payments for Commissions | 0.1 | ||||||
Atlas Resource Partners, L.P. | |||||||
Capital Unit [Line Items] | |||||||
Gain on sale of subsidiary unit issuances | 0.2 | 40.5 | |||||
Preferred class D | |||||||
Capital Unit [Line Items] | |||||||
Partners unit, issued | 4,000,000 | 3,200,000 | |||||
Partners' Capital Account, Units, Percentage | 8.63% | 8.63% | |||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $0.62 | ||||||
Redemption price per unit | $25 | ||||||
Eagle Ford Acquisition | Class D Preferred Units | |||||||
Capital Unit [Line Items] | |||||||
Partners Capital Account Units Date Of Sale | Oct-14 | ||||||
Partners unit, issued | 800,000 | 3,200,000 | |||||
Partners' Capital Account, Units, Percentage | 8.63% | ||||||
Subsidiary or Equity Method Investee, Price-Per-Share | $25 | $25 | |||||
Partners Capital Account Sale Of Units | 77.3 | ||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $0.62 | ||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit there after | $2.16 | ||||||
Percentage of Preferred Unit Regular Quarterly Cash Distributions | 8.63% | ||||||
Rangely Acquisition | |||||||
Capital Unit [Line Items] | |||||||
Partners Capital Account Units Date Of Sale | May-14 | ||||||
Partners unit, issued | 15,525,000 | ||||||
Subsidiary or Equity Method Investee, Price-Per-Share | $19.90 | ||||||
Partners Capital Account Sale Of Units | 297.3 | ||||||
Rangely Acquisition | Over Allotment Units Issued | |||||||
Capital Unit [Line Items] | |||||||
Partners unit, issued | 2,025,000 | ||||||
Geo Met | |||||||
Capital Unit [Line Items] | |||||||
Partners Capital Account Units Date Of Sale | Mar-14 | ||||||
Partners unit, issued | 6,325,000 | ||||||
Subsidiary or Equity Method Investee, Price-Per-Share | $21.18 | ||||||
Partners Capital Account Sale Of Units | $129 | ||||||
Geo Met | Over Allotment Units Issued | |||||||
Capital Unit [Line Items] | |||||||
Partners unit, issued | 825,000 |
Cash_Distributions_Additional_
Cash Distributions - Additional Information (Details) (USD $) | 3 Months Ended | 0 Months Ended | 12 Months Ended | 0 Months Ended | 1 Months Ended | |||||||||||||||
In Millions, except Share data, unless otherwise specified | Mar. 31, 2015 | Jan. 15, 2015 | Dec. 31, 2014 | Apr. 15, 2015 | Apr. 22, 2015 | Apr. 30, 2015 | Feb. 28, 2015 | Jan. 31, 2015 | Dec. 31, 2014 | Nov. 30, 2014 | Oct. 31, 2014 | Sep. 30, 2014 | Aug. 31, 2014 | Jul. 31, 2014 | Jun. 30, 2014 | 31-May-14 | Apr. 30, 2014 | Mar. 31, 2014 | Feb. 28, 2014 | Jan. 31, 2014 |
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Partners unit, issued | 420,586 | |||||||||||||||||||
Preferred class D | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Partners unit, issued | 4,000,000 | 3,200,000 | ||||||||||||||||||
Partners' Capital Account, Units, Percentage | 8.63% | 8.63% | ||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $0.62 | |||||||||||||||||||
Subsequent Event | Preferred class D | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $0.54 | |||||||||||||||||||
Cash Distribution Declared | Series A Preferred Units | Subsequent Event | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Declaration Date | 22-Apr-15 | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $0.30 | |||||||||||||||||||
Cash Distribution Paid | Series A Preferred Units | Subsequent Event | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 15-May-15 | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Date of Record | 8-May-15 | |||||||||||||||||||
Atlas Energy | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Policy, Members or Limited Partners, Description | The Company has a cash distribution policy under which it distributes, within 50 days following the end of each calendar quarter, all of its available cash (as defined in its limited liability company agreement) for that quarter to its unitholders. | |||||||||||||||||||
Atlas Energy | Cash Distribution Declared | Series A Preferred Units | Subsequent Event | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Declaration Date | 22-Apr-15 | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | 0.3 | |||||||||||||||||||
Atlas Energy | Cash Distribution Paid | Series A Preferred Units | Subsequent Event | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 15-May-15 | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Date of Record | 8-May-15 | |||||||||||||||||||
Atlas Resource Partners, L.P. | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Policy, Members or Limited Partners, Description | ARP Cash Distributions. In January 2014, ARP’s board of directors approved the modification of its cash distribution payment practice to a monthly cash distribution program whereby it distributes all of its available cash (as defined in the partnership agreement) for that month to its unitholders within 45 days from the month end. Prior to that, ARP paid quarterly cash distributions within 45 days from the end of each calendar quarter. | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $0.11 | $0.11 | $0.20 | $0.20 | $0.20 | $0.20 | $0.20 | $0.20 | $0.20 | $0.19 | $0.19 | $0.19 | $0.19 | $0.19 | ||||||
Atlas Resource Partners, L.P. | Minimum | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Percentage of Distributions in Excess of Targets | 13.00% | |||||||||||||||||||
Atlas Resource Partners, L.P. | Maximum | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Percentage of Distributions in Excess of Targets | 48.00% | |||||||||||||||||||
Atlas Resource Partners, L.P. | Cash Distribution Declared | Subsequent Event | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Declaration Date | 22-Apr-15 | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $0.11 | |||||||||||||||||||
Atlas Resource Partners, L.P. | Cash Distribution Paid | Subsequent Event | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | 10.3 | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 15-May-15 | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Date of Record | 8-May-15 | |||||||||||||||||||
Atlas Resource Partners, L.P. | Cash Distribution Paid | Subsequent Event | General Partner | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | 0.2 | |||||||||||||||||||
Atlas Resource Partners, L.P. | Cash Distribution Paid | Subsequent Event | Preferred Limited Partners' Interest | ||||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $0.60 |
Cash_Distributions_Schedule_of
Cash Distributions (Schedule of Distributions Declared by Partnership) (Details) (USD $) | 1 Months Ended | 3 Months Ended | |||||||||||||||||
Feb. 28, 2015 | Jan. 31, 2015 | Dec. 31, 2014 | Nov. 30, 2014 | Oct. 31, 2014 | Sep. 30, 2014 | Aug. 31, 2014 | Jul. 31, 2014 | Jun. 30, 2014 | 31-May-14 | Apr. 30, 2014 | Mar. 31, 2014 | Feb. 28, 2014 | Jan. 31, 2014 | Mar. 31, 2015 | |||||
Atlas Resource Partners, L.P. | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $0.11 | $0.11 | $0.20 | $0.20 | $0.20 | $0.20 | $0.20 | $0.20 | $0.20 | $0.19 | $0.19 | $0.19 | $0.19 | $0.19 | |||||
Atlas Resource Partners, L.P. | Limited Partner Interest | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | $9,347,000 | $9,284,000 | $16,782,000 | $16,779,000 | $16,033,000 | $16,032,000 | $16,032,000 | $16,028,000 | $16,029,000 | $15,752,000 | $15,752,000 | $12,719,000 | $12,719,000 | $12,718,000 | |||||
Atlas Resource Partners, L.P. | Preferred Limited Partners' Interest | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | 643,000 | [1] | 643,000 | [1] | 745,000 | [1] | 745,000 | [1] | 1,491,000 | 1,492,000 | 1,491,000 | 1,493,000 | 1,492,000 | 1,466,000 | 1,466,000 | 1,466,000 | 1,466,000 | 1,467,000 | |
Atlas Resource Partners, L.P. | General Partner | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | $204,000 | $203,000 | $1,378,000 | $1,378,000 | $1,378,000 | $1,378,000 | $1,378,000 | $1,378,000 | $1,377,000 | $1,279,000 | $1,279,000 | $1,054,000 | $1,055,000 | $1,055,000 | |||||
Month Ended January 31, 2014 | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 17-Mar-14 | ||||||||||||||||||
Month Ended February 28, 2014 | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 14-Apr-14 | ||||||||||||||||||
Month Ended March 31, 2014 | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 15-May-14 | ||||||||||||||||||
Month Ended April 30, 2014 | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 13-Jun-14 | ||||||||||||||||||
Month Ended May 31, 2014 | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 15-Jul-14 | ||||||||||||||||||
Month Ended June 30, 2014 | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 14-Aug-14 | ||||||||||||||||||
Month Ended July 31, 2014 | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 12-Sep-14 | ||||||||||||||||||
Month Ended August 31, 2014 | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 15-Oct-14 | ||||||||||||||||||
Month Ended September 30, 2014 | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 14-Nov-14 | ||||||||||||||||||
Month Ended October 30, 2014 | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 15-Dec-14 | ||||||||||||||||||
Month Ended November 30, 2014 | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 14-Jan-15 | ||||||||||||||||||
Month Ended December 31, 2014 | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 13-Feb-15 | ||||||||||||||||||
Month Ended January 31, 2015 | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 17-Mar-15 | ||||||||||||||||||
Month Ended February 28, 2015 | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 14-Apr-15 | ||||||||||||||||||
[1] | Excludes the Class D preferred unit quarterly distribution (see Note 12). |
Benefit_Plans_2015_Long_Term_I
Benefit Plans (2015 Long Term Incentive Plan Narrative) (Details) (2015 Long Term Incentive Plan) | 3 Months Ended |
Mar. 31, 2015 | |
2015 Long Term Incentive Plan | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |
Share-based Compensation Arrangement by Share-based Payment Award, Description | The Board of Directors of the Company approved and adopted the Company’s 2015 Long-Term Incentive Plan (“2015 LTIPâ€) effective February 2015. The 2015 LTIP provides equity incentive awards to officers, employees and managing board members of the Company and its affiliates, consultants and joint-venture partners (collectively, the “Participantsâ€) who perform services for the Company. The 2015 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€). |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 5,250,000 |
Phantom Units, Restricted Units and Unit Options Outstanding | 68,910 |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 5,181,090 |
Benefit_Plans_2015_LTIP_Phanto
Benefit Plans (2015 LTIP Phantom Unit Activity) (Details) (2015 Phantom Units, USD $) | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | ||
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 to be granted to employees under the 2015 LTIP will vest over a designated period of time | |||
Share Based Compensation Arrangement By Share Based Payment Award Award Other Than Options Vesting Period Percentage | 25.00% | |||
Share Based Compensation Arrangement By Share Based Payment Award Number Of Outstanding Units To Vest Within Next Twelve Months | 17,226 | |||
Distribution Equivalent Rights Paid On Unissued Units Under Incentive Plans | $0 | $0 | ||
Granted (Units) | 68,910 | |||
Outstanding, end of period (Units) | 68,910 | [1],[2],[3] | ||
Granted | $9.07 | |||
Outstanding, end of period | $9.07 | [1],[2],[3] | ||
Non-cash compensation expense recognized | 20,000 | |||
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested In Period Intrinsic Value | 0 | 0 | ||
Share Based Compensation Arrangement By Share Based Payment Award Other Than Options Outstanding Intrinsic Value | 414,000 | |||
Liabilities Related to Outstanding Phantom Units | 20,000 | |||
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Units Classified Within Liabilities | 68,910 | |||
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Weighted Average Grant Date Fair Value Units Classified Within Liabilities | $9.07 | |||
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 | 0 | 0 | ||
Unrecognized compensation expense related to unvested phantom units | $400,000 | |||
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition | 2 years 3 months 18 days | |||
Non Employees | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period | 4 years | |||
[1] | The aggregate intrinsic value of phantom unit awards outstanding at March 31, 2015 was approximately $414,000. | |||
[2] | No phantom unit awards had vested, but had not yet been issued at March 31, 2015 and 2014 | |||
[3] | There was approximately $20,000 recognized as liabilities on the Company’s consolidated balance sheet at March 31, 2015 representing 68,910 units, 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 $9.07 at March 31, 2015. |
Benefit_Plans_2015_Unit_Option
Benefit Plans (2015 Unit Option Activity) (Details) (2015 Unit Options, USD $) | 3 Months Ended | |
Mar. 31, 2015 | Mar. 31, 2014 | |
2015 Unit Options | ||
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 to be granted under the 2015 LTIP will vest over a designated period of time. | |
Years From Date Of Grant Unit Option Awards Expire | 10 years | |
Share Based Compensation Arrangement By Share Based Payment Award Number Of Outstanding Units To Vest Within Next Twelve Months | 0 | |
Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options | $0 | $0 |
Benefit_Plans_Rabbi_Trust_Narr
Benefit Plans (Rabbi Trust Narrative) (Details) (USD $) | 3 Months Ended | ||
Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Rabbi Trust | $5,641,000 | $3,925,000 | |
Rabbi trust liabilities recorded | 5,600,000 | 3,900,000 | |
Rabbi trust | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Partnership distributed to participants | $0 | $0 |
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, 2015 | |
ARP Long Term Incentive Plan | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |
Share-based Compensation Arrangement by Share-based Payment Award, Description | ARP’s 2012 Long-Term Incentive Plan (the “ARP LTIPâ€), effective March 2012, provides incentive awards to officers, employees and directors as well as employees of the Company and its affiliates, consultants and joint venture partners who perform services for ARP. The ARP LTIP is administered by the board of the Company, a committee of the board or the board (or committee of the board) of an affiliate (the “ARP LTIP Committeeâ€). |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 2,900,000 |
Phantom Units, Restricted Units and Unit Options Outstanding | 2,085,310 |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 135,663 |
Benefit_Plans_ARP_LTIP_Phantom
Benefit Plans (ARP LTIP Phantom Unit Activity) (Details) (ARP Phantom Units, USD $) | 3 Months Ended | ||||
Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||
Outstanding, beginning of year (Units) | 799,192 | 839,808 | |||
Granted (Units) | 3,500 | ||||
Vested and issued (Units) | -167,182 | [1] | -15,500 | [1] | |
Forfeited (Units) | -15,500 | ||||
Outstanding, end of period (Units) | 632,010 | [2],[3] | 812,308 | [2],[3] | |
Vested and not yet issued (Units) | 110,125 | [4] | 6,875 | [4] | |
Outstanding, beginning of year | $22.70 | $24.31 | |||
Granted | $20.99 | ||||
Vested and issued | $23.97 | [1] | $22.69 | [1] | |
Forfeited | $22.63 | ||||
Outstanding, end of period | $22.37 | [2],[3] | $24.35 | [2],[3] | |
Vested and not yet issued | $24.67 | [4] | $22.76 | [4] | |
Non-cash compensation expense recognized | $2,514,000 | $1,731,000 | |||
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested In Period Intrinsic Value | 1,600,000 | 300,000 | |||
Share Based Compensation Arrangement By Share Based Payment Award Other Than Options Outstanding Intrinsic Value | 4,900,000 | ||||
Liabilities Related to Outstanding Phantom Units | 29,000 | 100,000 | 200,000 | ||
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Units Classified Within Liabilities | 6,647 | 16,084 | 26,579 | ||
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Weighted Average Grant Date Fair Value Units Classified Within Liabilities | $21.63 | $22.15 | $21.16 | ||
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 | 1,100,000 | 100,000 | |||
Unrecognized compensation expense related to unvested phantom units | 4,200,000 | ||||
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition | 1 year 9 months 18 days | ||||
Atlas Resource Partners, L.P. | |||||
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 | 194,224 | ||||
Distribution Equivalent Rights Paid On Unissued Units Under Incentive Plans | $400,000 | $600,000 | |||
Atlas Resource Partners, L.P. | Vesting Percentage On Each Of Next Four Anniversaries Of Date Of Grant | |||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||
Share Based Compensation Arrangement By Share Based Payment Award Award Other Than Options Vesting Period Percentage | 25.00% | ||||
[1] | The intrinsic values of phantom unit awards vested during the three months ended March 31, 2015 and 2014 were $1.6 million and $0.3 million, respectively. | ||||
[2] | The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2015 was $4.9 million. | ||||
[3] | There were approximately $29,000 and $0.2 million recognized as liabilities on the Partnership’s consolidated balance sheets at March 31, 2015 and December 31, 2014, respectively, representing 6,647 and 26,579 units, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units were $21.63 and $21.16 at March 31, 2015 and December 31, 2014, respectively. There was $0.1 million recognized as liabilities on the Company’s consolidated balance sheet at the period ended March 31, 2014 representing 16,084 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 $22.15 for the period ending March 31, 2014. | ||||
[4] | The intrinsic values of phantom unit awards vested, but not yet issued at March 31, 2015 and 2014 were $1.1 million and $0.1 million, respectively. |
Benefit_Plans_ARP_Unit_Options
Benefit Plans (ARP Unit Options Activity) (Details) (2012 Long Term Incentive Plans - Phantom Units, USD $) | 3 Months Ended | |||
Mar. 31, 2015 | Mar. 31, 2014 | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights | The ARP LTIP Committee will determine the vesting and exercise restrictions applicable to an ARP award of options, if any, and the method by which the exercise price may be paid by the participant. Unit option awards expire 10 years from the date of grant. Unit options granted under the ARP LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. | |||
Years From Date Of Grant Unit Option Awards Expire | 10 years | |||
Share Based Compensation Arrangement By Share Based Payment Award Fair Value Assumptions Outstanding Options To Vest Within Next Twelve Months | 106,950 | |||
Proceeds from Stock Options Exercised | $0 | $0 | ||
Outstanding, beginning of year (Units) | 1,458,300 | 1,482,675 | ||
Forfeited (Units) | -5,000 | -10,000 | ||
Outstanding, end of period (Units) | 1,453,300 | [1],[2] | 1,472,675 | [1],[2] |
Options exercisable (Units) | 1,238,275 | [3] | 368,825 | [3] |
Outstanding, beginning of year | $24.66 | $24.66 | ||
Forfeited | $24.67 | $23.40 | ||
Outstanding, end of period | $24.66 | [1],[2] | $24.66 | [1],[2] |
Options exercisable, end of year | $24.67 | [3] | $24.67 | [3] |
Non-cash compensation expense recognized | 831,000 | 612,000 | ||
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, Outstanding, Weighted Average Remaining Contractual Term | 7 years 1 month 6 days | |||
Aggregate Intrinsic Value Of Options Outstanding | 0 | 2,000 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term | 7 years 1 month 6 days | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value | 0 | 0 | ||
Unrecognized compensation expense related to unvested unit options | $200,000 | |||
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition | 1 year | |||
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. | |||
Vesting Percentage On Each Of Next Four Anniversaries Of Date Of Grant | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Share Based Compensation Arrangement By Share Based Payment Award Options Vesting Period Percentage | 25.00% | |||
[1] | The weighted average remaining contractual life for outstanding options at March 31, 2015 was 7.1 years. | |||
[2] | There was no aggregate intrinsic value of options outstanding at March 31, 2015. The aggregate intrinsic value of options outstanding at March 31, 2014 was approximately $2,000. | |||
[3] | The weighted average remaining contractual life for exercisable options at March 31, 2015 was 7.1 years. There were no intrinsic values for options exercisable at March 31, 2015 and 2014. |
Operating_Segment_Information_1
Operating Segment Information (Narrative) (Details) | 3 Months Ended |
Mar. 31, 2015 | |
Segment | |
Segment Reporting [Abstract] | |
Number of reportable operating segments | 3 |
Operating_Segment_Information_2
Operating Segment Information (Operating Segment Data) (Details) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Segment Reporting Information [Line Items] | ||
Revenues | $245,799 | $162,147 |
General And Administrative Expense | -41,928 | -21,391 |
Depreciation, depletion and amortization expense | -44,456 | -52,039 |
Loss on asset sales and disposal | -11 | -1,603 |
Interest expense | -34,751 | -15,976 |
Reportable Legal Entities | Atlas Resource Partners, L.P. | ||
Segment Reporting Information [Line Items] | ||
Revenues | 239,247 | 157,345 |
Operating costs and expenses | -86,536 | -103,078 |
Depreciation, depletion and amortization expense | -41,866 | -50,237 |
Loss on asset sales and disposal | -11 | -1,603 |
Interest expense | -25,197 | -13,187 |
Segment income (loss) | 85,637 | -10,760 |
Reportable Legal Entities | New Atlas | ||
Segment Reporting Information [Line Items] | ||
Revenues | 5,588 | 4,580 |
Operating costs and expenses | -1,769 | -1,966 |
Depreciation, depletion and amortization expense | -2,590 | -1,802 |
Segment income (loss) | 1,229 | 812 |
Operating Segments | Corporate and Other | ||
Segment Reporting Information [Line Items] | ||
Revenues | 964 | 222 |
General And Administrative Expense | -24,797 | -4,936 |
Interest expense | -9,554 | -2,789 |
Segment income (loss) | ($33,387) | ($7,503) |
Operating_Segment_Information_3
Operating Segment Information (Reconciliation of Segment Income (Loss) to Net Loss) (Details) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Segment Reporting Information [Line Items] | ||
Net loss | $53,479 | ($17,451) |
Reportable Legal Entities | Atlas Resource Partners, L.P. | ||
Segment Reporting Information [Line Items] | ||
Net loss | 85,637 | -10,760 |
Reportable Legal Entities | New Atlas | ||
Segment Reporting Information [Line Items] | ||
Net loss | 1,229 | 812 |
Operating Segments | Corporate and Other | ||
Segment Reporting Information [Line Items] | ||
Net loss | ($33,387) | ($7,503) |
Operating_Segment_Information_4
Operating Segment Information (Reconciliation of Segment Revenues to Total Revenues) (Details) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Segment Reporting Information [Line Items] | ||
Total revenues | $245,799 | $162,147 |
Reportable Legal Entities | Atlas Resource Partners, L.P. | ||
Segment Reporting Information [Line Items] | ||
Total revenues | 239,247 | 157,345 |
Reportable Legal Entities | New Atlas | ||
Segment Reporting Information [Line Items] | ||
Total revenues | 5,588 | 4,580 |
Operating Segments | Corporate and Other | ||
Segment Reporting Information [Line Items] | ||
Total revenues | $964 | $222 |
Operating_Segment_Information_5
Operating Segment Information (Capital Expenditures) (Details) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Segment Reporting Information [Line Items] | ||
Capital expenditures | $52,441 | $44,419 |
Reportable Legal Entities | Atlas Resource Partners, L.P. | ||
Segment Reporting Information [Line Items] | ||
Capital expenditures | 42,498 | 39,897 |
Reportable Legal Entities | New Atlas | ||
Segment Reporting Information [Line Items] | ||
Capital expenditures | $9,943 | $4,522 |
Operating_Segment_Information_6
Operating Segment Information (Balance Sheet) (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Segment Reporting Information [Line Items] | ||
Goodwill | $13,639 | $13,639 |
Total assets | 2,976,982 | 3,026,315 |
Reportable Legal Entities | Atlas Resource Partners, L.P. | ||
Segment Reporting Information [Line Items] | ||
Goodwill | 13,639 | 13,639 |
Total assets | 2,747,576 | 2,727,575 |
Reportable Legal Entities | New Atlas | ||
Segment Reporting Information [Line Items] | ||
Total assets | 216,656 | 257,800 |
Operating Segments | Corporate and Other | ||
Segment Reporting Information [Line Items] | ||
Total assets | $12,750 | $40,940 |
Subsequent_Events_The_Company_
Subsequent Events (The Company) (Details) (Subsequent Event, Series A Preferred Units, USD $) | 0 Months Ended |
In Millions, unless otherwise specified | Apr. 22, 2015 |
Cash Distribution Declared | |
Subsequent Event [Line Items] | |
Distribution Made to Member or Limited Partner, Declaration Date | 22-Apr-15 |
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $0.30 |
Cash Distribution Paid | |
Subsequent Event [Line Items] | |
Distribution Made to Member or Limited Partner, Date of Record | 8-May-15 |
Distribution Made to Member or Limited Partner, Distribution Date | 15-May-15 |
Subsequent_Events_Atlas_Resour
Subsequent Events (Atlas Resource Issuance of Preferred Units) (Details) (USD $) | 3 Months Ended | 0 Months Ended |
In Millions, except Share data, unless otherwise specified | Mar. 31, 2015 | Apr. 07, 2015 |
Subsequent Event [Line Items] | ||
Partners unit, issued | 420,586 | |
Subsequent Event | Eagle Ford Acquisition | Class E Cumulative Redeemable Perpetual Preferred Units | ||
Subsequent Event [Line Items] | ||
Partners unit, issued | 255,000 | |
Partners' Capital Account, Units, Percentage | 10.75% | |
Redemption price per unit | $25 | |
Partners Capital Account Sale Of Units | $6 | |
Additional Public Offering Price Per Share | 38,250 | |
Preferred Unit Regular Quarterly Cash Distributions Per Unit there after | $25 | |
Percentage of Preferred Unit Regular Quarterly Cash Distributions | 10.75% |
Subsequent_Events_Atlas_Resour1
Subsequent Events (Atlas Resource Cash Distribution) (Details) (Atlas Resource Partners, L.P., USD $) | 1 Months Ended | 0 Months Ended | ||||||||||||||
Feb. 28, 2015 | Jan. 31, 2015 | Dec. 31, 2014 | Nov. 30, 2014 | Oct. 31, 2014 | Sep. 30, 2014 | Aug. 31, 2014 | Jul. 31, 2014 | Jun. 30, 2014 | 31-May-14 | Apr. 30, 2014 | Mar. 31, 2014 | Feb. 28, 2014 | Jan. 31, 2014 | Apr. 15, 2015 | Apr. 22, 2015 | |
Subsequent Event [Line Items] | ||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $0.11 | $0.11 | $0.20 | $0.20 | $0.20 | $0.20 | $0.20 | $0.20 | $0.20 | $0.19 | $0.19 | $0.19 | $0.19 | $0.19 | ||
General Partner | ||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | $204,000 | $203,000 | $1,378,000 | $1,378,000 | $1,378,000 | $1,378,000 | $1,378,000 | $1,378,000 | $1,377,000 | $1,279,000 | $1,279,000 | $1,054,000 | $1,055,000 | $1,055,000 | ||
Subsequent Event | Class D Preferred Units | ||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $0.54 | |||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | 2,200,000 | |||||||||||||||
Subsequent Event | Cash Distribution Declared | ||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||
Distribution Made to Member or Limited Partner, Declaration Date | 22-Apr-15 | |||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $0.11 | |||||||||||||||
Subsequent Event | Cash Distribution Paid | ||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | 10,300,000 | |||||||||||||||
Distribution Made to Member or Limited Partner, Distribution Date | 15-May-15 | |||||||||||||||
Distribution Made to Member or Limited Partner, Date of Record | 8-May-15 | |||||||||||||||
Subsequent Event | Cash Distribution Paid | General Partner | ||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | 200,000 | |||||||||||||||
Subsequent Event | Cash Distribution Paid | Preferred Limited Partner Units | ||||||||||||||||
Subsequent Event [Line Items] | ||||||||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $600,000 |