| 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”). |
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| 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. |
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| 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. |
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| 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): |
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| | | 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 | | | | | |
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| 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 |
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| 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. |
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| 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 |
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| 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 |
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| 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 |
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| 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. |
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| 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. |
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| 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): |
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| | 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 | | | $ | — | | | | | |
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| 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). |
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| 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): |
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| | 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 | | | | — | | | | | |
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| 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. |
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| 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. |
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| 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. |
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| 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. |
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| 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. |
