| Basis of Presentation and Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
| Dec. 31, 2017 |
| Accounting Policies [Abstract] | |
| Basis of Presentation and Principles of Consolidation and Combination | Basis of Presentation and Principles of Consolidation Our combined consolidated financial statements for the years ended December 31, 2017 and 2016, subsequent to the transfer of assets on February 27, 2015, include our accounts and accounts of our subsidiaries. Our combined consolidated financial statements for the portion of 2015 that was prior to the transfer of assets on February 27, 2015 was 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 we had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various entities we comprise, Atlas Energy’s net investment in us is shown as equity in the combined consolidated financial statements. U.S. GAAP requires 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 our financial statements for the portion of 2015 that was prior to the transfer of assets on February 27, 2015. Actual balances and results could be different from those estimates. We have identified our transactions with other Atlas Energy operations in the combined consolidated financial statements as transactions between affiliates. We determined that ARP (through the Plan Effective Date, as discussed further below) and AGP are variable interest entities (“VIEs”) based on their respective partnership agreements, our power, as the general partner, to direct the activities that most significantly impact each of their respective economic performance, and our ownership of each of their respective incentive distribution rights. Accordingly, we consolidated the financial statements of ARP (until the date of ARP’s Chapter 11 Filings, as discussed further below) and AGP into our combined consolidated financial statements. Our consolidated VIEs’ operating results and asset balances are presented separately in Note 13 – Operating Segment Information. As the general partner for both ARP (through the Plan Effective Date) and AGP, we have unlimited liability for the obligations of ARP (through the Plan Effective Date) and AGP except for those contractual obligations that are expressly made without recourse to the general partner. The non-controlling interests in ARP (through the date of ARP’s Chapter 11 Filings, as discussed further below) and AGP 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 connection with ARP’s Chapter 11 Filings on July 27, 2016, we deconsolidated ARP’s financial statements from our combined consolidated financial statements, as we no longer had the power to direct the activities that most significantly impacted ARP’s economic performance; however, we retained the ability to exercise significant influence over the operating and financial decisions of ARP and therefore applied the equity method of accounting for our investment in ARP up to the Plan Effective Date. As a result of these changes, our combined consolidated financial statements subsequent to ARP’s Chapter 11 Filings will not be comparable to our combined consolidated financial statements prior to ARP’s Chapter 11 Filings. Our financial results for future periods following the application of equity method accounting will be different from historical trends and the differences may be material. Certain reclassifications have been made to our combined consolidated financial statements for the prior year periods to conform to classifications used in the current year, specifically related to ARP’s Drilling Partnerships management, which includes all of ARP’s managing and operating activities specific to ARP’s Drilling Partnerships including well construction and completion, administration and oversight, well services and gathering and processing. We previously presented these revenue and expense items separately; however, due to the deconsolidation of ARP on the date of the Chapter 11 Filings, we have aggregated these items to be presented as one combined revenue item and one combined expense item. As a result of this change, we have restated our prior year combined consolidated statements of operations to conform to our current presentation. In accordance with established practice in the oil and gas industry, our combined consolidated financial statements include our 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 through the date of ARP’s Chapter 11 Filings. Such interests generally approximated 30%. Our combined consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of the Drilling Partnerships through the date of ARP’s Chapter 11 Filings. Rather, ARP calculated these items specific to its own economics through the date of ARP’s Chapter 11 Filings. On the Plan Effective Date, we determined that Titan is a VIE based on its limited liability company agreement and the delegation of management and omnibus agreements between Titan and Titan Management, which provide us the power to direct activities that most significantly impact Titan’s economic performance, but we do not have a controlling financial interest. As a result, we do not consolidate Titan but rather apply the equity method of accounting as we have the ability to exercise significant influence over Titan’s operating and financial decisions. On June 5, 2015, ARP completed the acquisition of our coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma for $31.5 million, net of purchase price adjustments (the “Arkoma Acquisition”). ARP funded the purchase price using proceeds from the issuance of 6,500,000 common limited partner units. The Arkoma Acquisition had an effective date of January 1, 2015. |
| Liquidity, Capital Resources, and Ability to Continue as a Going Concern | Liquidity, Capital Resources, and Ability to Continue as a Going Concern Our primary sources of liquidity are cash distributions received with respect to our ownership interests in AGP, Lightfoot, and Titan and AGP’s annual management fee. However, neither Titan nor AGP are currently paying distributions. In addition, Lightfoot completed a portion of its sale transaction that will result in lower quarterly distributions to us. Our primary cash requirements, in addition to normal operating expenses, are for debt service and capital expenditures, which we expect to fund through operating cash flow, and cash distributions received. Accordingly, our sources of liquidity are currently not sufficient to satisfy our obligations under our credit agreements. The significant risks and uncertainties related to our primary sources of liquidity raise substantial doubt about our ability to continue as a going concern. If we are unable to remain in compliance with the covenants under our credit agreements (as described in Note 5), absent relief from our lenders, we maybe be forced to repay or refinance such indebtedness. Upon the occurrence of an event of default, the lenders under our credit agreements could elect to declare all amounts outstanding immediately due and payable and could terminate all commitments to extend further credit. If an event of default occurs, we will not have sufficient liquidity to repay all of our outstanding indebtedness, and as a result, there would be substantial doubt regarding our ability to continue as a going concern. We entered into a series of agreements with our lenders to extend the maturity date of our first lien credit agreement from September 30, 2017 to June 30, 2018. In addition to the $20.7 million of indebtedness due June 30, 2018, we classified the remaining $59.6 million of outstanding indebtedness under our credit agreements as a current liability, based on the uncertainty regarding future covenant compliance. In total, we have $79.4 million of outstanding indebtedness under our credit agreements, which is net of $0.8 million of debt discounts and $0.1 million of deferred financing costs, as current portion of long term debt, net on our condensed consolidated balance sheet as of December 31, 2017. We continually monitor capital markets and may make changes to our capital structures from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening the balance sheet, meeting debt service obligations and/or achieving cost efficiency. For example, we could pursue options such as refinancing or reorganizing our indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address our liquidity concerns and high debt levels. There is no certainty that we will be able to implement any such options, and we cannot provide any assurances that any refinancing or changes to our debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for our stakeholders, including cancellation of debt income (“CODI”) which would be directly allocated to our unitholders and reported on such unitholders’ separate returns. It is possible additional adjustments to our strategic plan and outlook may occur based on market conditions and our needs at that time, which could include selling assets or seeking additional partners to develop our assets. Our combined consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. Our combined consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If we cannot continue as a going concern, adjustments to the carrying values and classification of our assets and liabilities and the reported amounts of income and expenses could be required and could be material. |
| Use of Estimates | Use of Estimates The preparation of our 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 our combined consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. Our combined consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion of gas and oil properties, fair value of derivative instruments and fair value of equity method investments. In addition, such estimates included estimated allocations made from the historical accounting records of Atlas Energy in order to derive our historical financial statements, for the portion of 2015 that was prior to the transfer of assets on February 27, 2015. 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. Actual results could differ from those estimates. |
| Cash Equivalents | Cash Equivalents We consider all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. These cash equivalents consist principally of temporary investments of cash in short-term money market instruments. |
| 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 our results of operations. We 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. Our 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. We also consider the estimated salvage value in the calculation of depreciation, depletion and amortization. Capitalized costs of developed producing properties in each field were 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 our combined consolidated statement of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within our combined consolidated balance sheet. 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 our combined consolidated statement 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. Support equipment and other are carried at cost and consist primarily of pipelines, processing and compression facilities, and gathering systems and related support equipment. We compute depreciation of support equipment and other using the straight-line balance method over the estimated useful life of each asset category as follows: Pipelines, processing and compression facilities: 15-20 years; Buildings and land improvements: 3-40 years; Other support equipment: 3-10 years. See Note 3 for additional disclosures regarding property, plant and equipment. |
| Impairment of Long-Lived Assets | Impairment of Long-Lived Assets We 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. Our unproved properties are assessed individually based on several factors including if a dry hole has been drilled in the area, other wells drilled in the area and operating results, remaining months in the lease’s primary term, and management’s future plans to drill and develop the area. As exploration and development work progresses and the reserves on properties are proven, capitalized costs of these properties are subject to depletion. If exploration activities are unsuccessful, the capitalized costs of the properties related to the unsuccessful work is charged to exploration expense. The timing of impairment of any significant unproved properties depends upon the nature, timing and extent of future exploration and development activities and their results. 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 our 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. We 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 undiscounted 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 were based on its own assumptions rather than its proportionate share of the Drilling Partnerships’ reserves. These assumptions included 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 resulted 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 resulted 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. We cannot predict what reserve revisions may be required in future periods. ARP’s method of calculating its reserves resulted in reserve quantities and values which were greater than those which would be calculated by the Drilling Partnerships. ARP’s reserve quantities included reserves in excess of its proportionate share of reserves in Drilling Partnerships, which ARP may have been unable to recover due to the Drilling Partnerships’ legal structure. See Note 3 for additional disclosures regarding impairment of property, plant and equipment. |
| Capitalized Interest | Capitalized Interest We capitalized interest on ARP’s 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 6.6% and 6.5% for the years ended December 31, 2016 and 2015, respectively. The aggregate amounts of interest capitalized were $5.4 million and $15.8 million for the years ended December 31, 2016 and 2015, respectively. |
| Derivative Instruments | Derivative Instruments We enter into certain financial contracts to manage our exposure to movement in commodity prices. The derivative instruments recorded in the consolidated balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in our consolidated statements of operations unless specific hedge accounting criteria are met. See Note 6 for additional disclosures regarding derivative instruments. |
| Other Assets | Other Assets Deferred financing costs related to revolving credit facility (line-of-credit) arrangements were recorded at cost, amortized over the term of the arrangement, and are presented net of accumulated amortization within other assets, net on our combined consolidated balance sheet. We had revolving credit facility deferred financing costs of $0.2 million, which were net of $0.1 million of accumulated amortization, recorded within other assets, net on our combined consolidated balance sheets at December 31, 2016. For the years ended December 31, 2016 and 2015, amortization expense of revolving credit facility deferred financing costs was $10.0 million and $14.2 million, respectively, which was recorded within interest expense on our consolidated statements of operations. On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2 - Basis of Presentation and Principles of Consolidation and Combination), |
| Equity Method Investments | Equity Method Investments Investment in Titan . At December 31, 2017, we had a 2% Series A Preferred interest in Titan. We account for our investment under the equity method of accounting due to our ability to exercise significant influence over Titan’s operating and financial decisions. As of both December 31, 2017 and December 31, 2016, the net carrying amount of our investment in Titan was zero. During the year ended December 31, 2017 and for the period from the Plan Effective Date to December 31, 2016, we recognized equity method loss of zero and $0.6 million, respectively, within other, net on our combined consolidated statements of operations. On the Plan Effective Date, we recorded our equity method investment of Titan at fair value of $0.6 million, which was recorded in gain on deconsolidation of ARP on our combined consolidated statements of operations for the year ended December 31, 2016. Investment in Lightfoot. At December 31, 2017, we 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. We account for our investment in Lightfoot under the equity method of accounting due to our ability to exercise significant influence over Lightfoot’s operating and financial decisions. As of December 31, 2017 and 2016, the net carrying amount of our investment in Lightfoot was zero and $18.7 million, respectively, which was included in other assets, net on our combined consolidated balance sheets. For the years ended December 31, 2017, 2016 and 2015, we recognized equity method income of $0.9 million, $1.2 million and $0.7 million, respectively, within other, net on our combined consolidated statement of operations. For the year ended December 31, 2017, 2016 and 2015, we received net cash distributions of approximately $1.6 million, $1.9 million and $2.8 million, respectively. On August 29, 2017, Lightfoot G.P., Lightfoot L.P. and Lightfoot’s subsidiary, Arc Logistics Partners LP (NYSE: ARCX) (“Arc Logistics”), entered into a Purchase Agreement and Plan of Merger (the “Merger Agreement”) with Zenith Energy U.S., L.P. (together with its affiliates, “Zenith”), a portfolio company of Warburg Pincus, pursuant to which Zenith will acquire Arc Logistics GP LLC (“Arc GP”), the general partner of Arc Logistics (the “GP Transfer”), and all of the outstanding common units of Arc Logistics (the “Merger” and, together with the GP Transfer, the “Proposed Transaction”). Under the terms of the Merger Agreement, Lightfoot L.P. will receive $14.50 per common unit of Arc Logistics in cash for the approximately 5.2 million common units held by it. Lightfoot G.P. will receive $94.5 million for 100% of the membership interests in Arc GP. In December 2017, Lightfoot closed on a portion Proposed Transaction which resulted in a net distribution to us of $21.6 million. We used the net proceeds to pay down $21.6 million of our first lien credit agreement. As a result of this transaction, we reduced our net carrying amount of our investment in Lightfoot to zero and recognized a $6.9 million net gain on the Lightfoot transaction, which is net of $3.1 million of contractual agreements, in other income on our combined consolidated statement of operations for the year ended December 31, 2017. The remaining part of the Proposed Transaction is subject to the closing of the purchase by Zenith of a 5.51646 % interest (and, subject to certain conditions, an additional 4.16154% interest) in Gulf LNG Holdings Group, LLC (“Gulf LNG”), which owns a liquefied natural gas regasification and storage facility in Pascagoula, Mississippi, from LCP LNG Holdings, LLC, a subsidiary of Lightfoot L.P. (“LCP’). We anticipate receiving net proceeds of approximately $3.0 million from LCP selling its interest in Gulf LNG. The remaining part of the Proposed Transaction is not subject to a financing condition and closing is targeted in the second quarter of 2018. We anticipate using the proceeds from this transaction to pay down our first lien credit agreement. Investment in ARP . As a result of deconsolidating ARP and recording our equity method investment in ARP a fair value of zero on the date of the Chapter 11 Filings, we recognized a $46.4 million non-cash gain, which is recorded in gain on deconsolidation of ARP on our condensed combined consolidated statements of operations for the year ended December 31, 2016, and includes a $61.7 million gain related to the remeasurement of our retained noncontrolling investment to fair value. During the period after the Chapter 11 Filings through August 31, 2016, ARP generated a net loss and therefore we did not record any equity method income/(loss) based on our 25% proportionate share because such loss exceeded our investment. Due to the cancellation of ARP’s preferred limited partnership units and common limited partnership units without the receipt of any consideration or recovery on the Plan Effective Date, we no longer hold an equity method investment in ARP. Interest in Joliet Terminal In connection with the closing of the first portion of Lightfoot’s Proposed Transaction in December 2017, we acquired a 1.8% ownership interest in Zenith Energy Terminals Joliet Holdings, LLC (“Joliet Terminal”) for $3.3 million. The Joliet Terminal is a unit train facility capable of unloading 85,000 barrels per day of crude oil. The facility is located within a few miles of three major refinery complexes in the Chicago market and has direct pipeline access to one of these refineries. The Joliet Terminal has the ability to receive and/or deliver crude and other heavy and light products through railcar, marine vessels, trucks or through its proprietary pipeline and potentially other various pipelines in the vicinity of the facility. The Joliet Terminal has 300,000 barrels of storage capacity; however, it can be expanded to store an additional one million barrels. We account for our interest as a cost method investment. Interest in Osprey Sponsor At December 31, 2017, we have a membership interest in Osprey Sponsor, which is the sponsor of Osprey. We received our membership interest in recognition of potential utilization, if any, of our office space, advisory services and personnel by Osprey. On July 26, 2017, Osprey, for which certain of our executives, namely Jonathan Cohen, Edward Cohen and Daniel Herz, serve as CEO, Executive Chairman and President, respectively, consummated its initial public offering. Osprey was formed for the purpose of acquiring, through a merger, capital stock exchange, asset acquisition, stock purchase, reorganization, or other similar business transaction, one or more operating businesses or assets (a “Business Combination”) that Osprey has not yet identified. The initial public offering, including the overallotment exercised by the underwriters, generated net proceeds of $275 million through the issuance of 27.5 million units, which were contributed to a trust account and are intended to be applied generally toward consummating a Business Combination. Our membership interest in Osprey Sponsor is an allocation of 1,250,000 founder shares, consisting of 1,250,000 shares of Class B common stock of Osprey that are automatically convertible into Class A common stock of Osprey upon the consummation of a Business Combination on a one-for-one basis. Additionally, another 125,000 founder shares have been allocated to our employees other than Messrs. Cohen, Cohen and Herz. Pursuant to the Osprey Sponsor limited liability company agreement, owners of the founder shares agree to (i) vote their shares in favor of approving a Business Combination, (ii) waive their redemption rights in connection with the consummation of a Business Combination, and (iii) waive their rights to liquidating distributions from the trust account if Osprey fails to consummate a Business Combination. In addition, Osprey Sponsor has agreed to not to transfer, assign or sell any of the founder shares until the earlier of (i) one year after the date of the consummation of a Business Combination, or (ii) the date on which the last sales price of Osprey’s common stock equals or exceeds $12.00 per share (as adjusted for stock splits, stock dividends, reorganizations and recapitalizations) for any 20 trading days within any 30-trading day period commencing 150 days after a Business Combination, or earlier, in each case, if subsequent to a Business Combination, Osprey consummates a subsequent liquidation, merger, stock exchange, reorganization or other similar transaction which results in all of Osprey’s stockholders having the right to exchange their common stock for cash, securities or other property. We have determined that Osprey Sponsor is a VIE based on its limited liability company agreement. Through our direct interest and indirectly through the interests of our related parties, we have certain characteristics of a controlling financial interest and the power to direct activities that most significantly impact Osprey Sponsor’s economic performance; however, we are not the primary beneficiary. As a result, we do not consolidate Osprey Sponsor but rather apply the equity method of accounting as we, through our direct interest and indirectly through the interests of our related parties, have the ability to exercise significant influence over Osprey Sponsor’s operating and financial decisions. As of December 31, 2017, the net carrying amount of our interest in Osprey Sponsor was zero as our membership interest was received in recognition of potential utilization, if any, of our office space, advisory services and personnel by Osprey, and we have provided a nominal amount of services to Osprey as of December 31, 2017. During the year ended December 31, 2017, we did not recognize any equity method income as Osprey Sponsor has no operations. |
| Rabbi Trust | Rabbi Trust In 2011, we established an excess 401(k) plan relating to certain executives. In connection with the plan, we established a “rabbi” trust for the contributed amounts. At December 31, 2017 and 2016, we reflected $1.5 million and $4.1 million, respectively, related to the value of the rabbi trust within other assets, net on our combined consolidated balance sheets, and recorded corresponding liabilities of $1.5 million and $4.1 million, respectively, as of those same dates, within asset retirement obligations and other on our combined consolidated balance sheets. During the years ended December 31, 2017 and 2016, we distributed $3.1 million and $2.3 million, respectively, to certain executives related to the rabbi trust. During the year ended December 31, 2015, no distributions were made to certain executives related to the rabbi trust. |
| Asset Retirement Obligations | Asset Retirement Obligations We recognize an estimated liability for the plugging and abandonment of gas and oil wells and related facilities. We 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. See Note 4 for additional disclosures regarding asset retirement obligations. |
| Accrued Liabilities | Accrued Liabilities We had $6.6 million and $10.6 million of accrued payroll and benefit items at December 31, 2017 and 2016, respectively, which were included within accrued liabilities on our combined consolidated balance sheets. |
| Other Non-current Liabilities | Other Non-current Liabilities We have two lease agreements in AGP’s Eagle Ford operating area that require us to perform certain drilling and development activities by a specified date or pay liquidated damages to maintain the leases. We determined the liquidated damages were a probable loss contingency and estimated the value of the liquidated damages enforceable under Texas law to be $0.5 million which was recorded as a non-current liability on our consolidated balance sheet as of December 31, 2016. As of December 31, 2017, we presented |
| Income Taxes | Income Taxes We and our consolidated subsidiaries are not subject to U.S. federal and most state income taxes. Our unitholders and the limited partners of our subsidiaries 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 combined consolidated financial statements. Certain corporate subsidiaries of ARP were subject to federal and state income tax and were immaterial to our combined consolidated financial statements for each year presented and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for in our combined consolidated financial statements. We evaluate tax positions taken or expected to be taken in the course of preparing the respective tax returns and disallow the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. We do not believe we have any tax positions taken within our combined consolidated financial statements that would not meet this threshold. Our policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. We have not recognized any such potential interest or penalties in our combined consolidated financial statements for the years ended December 31, 2017, 2016 and 2015. We file Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, we are no longer subject to income tax examinations by major tax authorities for years prior to 2013 and are not currently being examined by any jurisdiction and are not aware of any potential examinations as of December 31, 2017. On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”) that makes significant changes to the U.S. Internal Revenue Code. Among other changes, the Tax Act includes a new deduction on certain pass-through income, a repeal of the partnership technical termination rule, and new limitations on certain deductions and credits, including interest expense deductions. Since our operations are not subject to federal income tax, the Tax Act is not expected to have a material impact on us. |
| Share Based Compensation Plans | Share Based Compensation Plans We recognize all unit-based payments to employees, including grants of employee unit options, in the combined consolidated financial statements based on their fair values (see Note 12). |
| ARP's Arkoma Acquisition | ARP’s Arkoma Acquisition On June 5, 2015, ARP completed the acquisition of the Company’s coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma for approximately $31.5 million, net of purchase price adjustments (the “Arkoma Acquisition”). ARP funded the purchase price through the issuance of 6,500,000 common limited partner units. The Arkoma Acquisition had an effective date of January 1, 2015. ARP accounted for the Arkoma Acquisition as a transaction between entities under common control in its standalone consolidated financial statements. |
| Net Income (Loss) Per Common Unit | Net Income (Loss) Per Common Unit Basic net income (loss) attributable to common unitholders per unit is computed by dividing net income (loss) attributable to common unitholders, which is determined after the deduction of net income attributable to participating securities and the preferred unitholders’ interests, if applicable, by the weighted average number of common units outstanding during the period. Unvested unit-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities. A portion of our phantom unit awards, which consist of common units issuable under the terms of our long-term incentive plans and incentive compensation agreements, contain non-forfeitable rights to distribution equivalents. The participation rights result in a non-contingent transfer of value each time we declare 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 unitholders for purposes of calculating net income (loss) attributable to common unitholders per unit (in thousands):
Years Ended December 31,
2017
2016
2015
Net loss
$
(16,613
)
$
(189,958
)
$
(885,734
)
Preferred unitholders’ dividends
—
(339
)
(3,360
)
Loss attributable to non-controlling interests
2,792
176,854
649,316
—
—
10,475
Net loss attributable to common unitholders
(13,821
)
(13,443
)
(229,303
)
Less: Net income attributable to participating securities – phantom units (1)
—
—
—
Net loss utilized in the calculation of net loss attributable to common unitholders per unit – diluted (1)
$
(13,821
)
$
(13,443
)
$
(229,303
)
(1)
Net income (loss) attributable to common unitholders for the net income (loss) attributable to common unitholders per unit calculation is net income (loss) attributable to common unitholders, less income allocable to participating securities. For the years ended December 31, 2017 and 2016, net loss attributable to common unitholder’s ownership interest was not allocated to approximately 59,000 and 330,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. Diluted net income (loss) attributable to common unitholders per unit is calculated by dividing net income (loss) attributable to common unitholders, less income allocable to participating securities, by the sum of the weighted average number of common unitholder 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 our long-term incentive plan. The following table sets forth the reconciliation of our weighted average number of common units used to compute basic net loss attributable to common unitholders per unit with those used to compute diluted net loss attributable to common unitholders per unit (in thousands):
Years Ended December 31,
2017
2016
2015
Weighted average number of common units—basic
29,965
26,035
26,011
Add effect of dilutive incentive awards (1)
—
—
—
Add effect of dilutive convertible preferred units and warrants (2)
—
—
—
Weighted average number of common units—diluted
29,965
26,035
26,011
(1)
For the years ended December 31, 2017 and 2016, approximately 3,117,122 and 2,986,000 phantom units, respectively, were excluded from the computation of diluted net income (loss) attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive.
(2)
For the years ended December 31, 2017 and 2016, our warrants issued in connection with the Second Lien Credit Agreement were excluded from the computation of diluted earnings attributable to common unitholders per unit because the inclusion of such warrants and units would have been anti-dilutive. For the years ended December 31, 2017 and 2016, our convertible Series A Preferred Units were excluded from the computation of diluted earnings attributable to common unitholders per unit, because the inclusion of such warrants and units would have been anti-dilutive. |
| Concentration of Credit Risk | Concentration of Credit Risk Financial instruments, which potentially subject us to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. We place our temporary cash investments in high-quality short-term money market instruments and deposits with high-quality financial institutions and brokerage firms. At December 31, 2017 and 2016, we had $12.3 million and $13.9 million, respectively, in deposits at various banks, of which $11.1 million and $12.2 million, respectively, were over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments to date. Cash on deposit at various banks may differ from the balance of cash and cash equivalents at period end due to certain reconciling items, including any outstanding checks as of period end. We sell natural gas, oil, NGLs and condensate under contract to various purchasers in the normal course of business. For the year ended December 31, 2017, AGP had one customer, Shell Trading Company within its gas and oil production segment that individually accounted for approximately 91% of AGP’s natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. We are subject to the risk of loss on our derivative instruments that would occur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We maintain credit policies with regard to our counterparties to minimize their overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the quarterly monitoring of our oil, natural gas and NGLs counterparties’ credit exposures; (iii) comprehensive credit reviews on significant counterparties from physical and financial transactions on an ongoing basis; (iv) the utilization of contractual language that affords them netting or set off opportunities to mitigate exposure risk; and (v) when appropriate, requiring counterparties to post cash collateral, parent guarantees or letters of credit to minimize credit risk. AGP’s liabilities related to derivatives as of December 31, 2017 represent financial instruments from one counterparty; which is a financial institutions that has an “investment grade” (minimum Standard & Poor’s rating of BBB+ or better) credit rating and are lenders associated with AGP’s secured credit facility. Subject to the terms of AGP’s secured credit facility, collateral or other securities are not exchanged in relation to derivatives activities with the parties in the secured credit facility. |
| Revenue Recognition | Revenue Recognition Natural gas and oil production . Our 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 the 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 we 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 were conducted by ARP through, and a portion of its revenues were attributable to, sponsorship of the Drilling Partnerships. Drilling Partnership investor capital raised by ARP was deployed to drill and complete wells included within the partnership. As ARP deployed Drilling Partnership investor capital, it recognized certain management fees it was entitled to receive, including well construction and completion revenue and a portion of administration and oversight revenue. At each period end, if ARP had Drilling Partnership investor capital that had not yet been deployed, it would recognize a current liability titled “Liabilities Associated with Drilling Contracts” on our combined consolidated balance sheets. After the Drilling Partnership well was completed and turned in line, ARP was entitled to receive additional operating and management fees, which were included within well services and administration and oversight revenue, respectively, on a monthly basis while the well was operating. In addition to the management fees it was entitled to receive for services provided, ARP was also entitled to its pro-rata share of Drilling Partnership gas and oil production revenue, which was generally between 10-30%. ARP recognized its Drilling Partnership management fees in the following manner:
•
Well construction and completion . For each well that was drilled by a Drilling Partnership, ARP received a 15% mark-up on those costs incurred to drill and complete wells included within the partnership. Such fees were earned, in accordance with the partnership agreement, and recognized as the services were performed, typically between 60 and 270 days.
•
Administration and oversight . For each well drilled by a Drilling Partnership, ARP received a fixed fee between $100,000 and $500,000, depending on the type of well drilled, which was earned, in accordance with the partnership agreement, and recognized at the initiation of the well. Additionally, the Drilling Partnership paid ARP a monthly per well administrative fee of $75 for the life of the well. The well administrative fee was earned on a monthly basis as the services were performed.
•
Well services . Each Drilling Partnership paid ARP a monthly per well operating fee, $1,000 to $2,000, depending on the type of well, for the life of the well. Such fees were earned on a monthly basis as the services were performed. While the historical structure varied, ARP 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 cumulative 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 compared 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 fell below the agreed upon rate, ARP recognized 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 would 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 reflected that the agreed upon limited partner investment return would be achieved during the subordination period, ARP would 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 included gathering fees ARP charges to the Drilling Partnership wells for ARP’s processing plants in the New Albany and the Chattanooga shales. Generally, ARP charged a gathering fee to the Drilling Partnership wells equivalent to the fees ARP remitted. In Appalachia, a majority of the Drilling Partnership wells were subject to a gathering agreement, whereby ARP remitted a gathering fee of 16%. However, based on the respective Drilling Partnership agreements, ARP charged the Drilling Partnership wells a 13% gathering fee. As a result, some of ARP’s gathering expenses, specifically those in the Appalachian Basin, would generally exceed the revenues collected from the Drilling Partnerships by approximately 3%. Our 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. We had unbilled revenues at December 31, 2017 and 2016 of $0.6 million and $0.8 million, respectively, which were included in accounts receivable within our 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 our 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 7). We do 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 February 2016, the Financial Accounting Standards Board (“FASB”) updated the accounting guidance related to leases. The updated accounting guidance requires lessees to recognize a lease asset and liability at the commencement date of all leases (with the exception of short-term leases), initially measured at the present value of the lease payments. The updated guidance is effective for us as of January 1, 2019 and requires a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest period presented. We are currently in the process of determining the impact that the updated accounting guidance will have on our combined consolidated financial statements. In January 2016, the FASB updated the accounting guidance related to the recognition and measurement of financial assets and financial liabilities. The updated accounting guidance, among other things, requires that all nonconsolidated equity investments, except those accounted for under the equity method, be measured at fair value and that the changes in fair value be recognized in net income. The accounting guidance requires nonmarketable equity securities to be recorded at cost and adjusted to fair value at each reporting period. However, the guidance allows for a measurement alternative, which is to record the investments at cost, less impairment, if any, and subsequently adjust for observable price changes of identical or similar investments of the same issuer. We adopted the new accounting guidance on January 1, 2018 and plan to apply the measurement alternative to our interest in Joliet Terminal as there is not a readily determinable fair value for our investment. In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. We have completed our detailed contract reviews and documentation. Substantially all of our revenue is earned pursuant to agreements under which we have currently interpreted one performance obligation, which is satisfied at a point-in-time. We adopted the new accounting guidance using the modified retrospective method of adoption on January 1, 2018. We do not expect the new accounting guidance to have a material impact on our financial position, results of operations or cash flows in 2018. The new accounting guidance will require that our revenue recognition policy disclosures include further detail regarding our performance obligations as to the nature, amount, timing, and estimates of revenue and cash flows from contracts with customers including disaggregation of revenues, beginning with our Form 10-Q for the three months ended March 31, 2018. |
