Document and Entity Information
Document and Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | May 04, 2018 | Jun. 30, 2017 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2017 | ||
Document Fiscal Year Focus | 2,017 | ||
Document Fiscal Period Focus | FY | ||
Entity Registrant Name | Atlas Energy Group, LLC | ||
Entity Central Index Key | 1,623,595 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Public Float | $ 2.5 | ||
Entity Common Stock, Units Outstanding | 31,973,518 | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Well-known Seasoned Issuer | No | ||
Trading Symbol | ATLS |
COMBINED CONSOLIDATED BALANCE S
COMBINED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Current assets: | ||
Cash and cash equivalents | $ 12,929 | $ 12,009 |
Accounts receivable | 564 | 835 |
Prepaid expenses and other | 160 | 40 |
Total current assets | 13,653 | 12,884 |
Property, plant and equipment, net | 65,293 | 68,899 |
Other assets, net | 5,102 | 23,293 |
Total assets | 84,048 | 105,076 |
Current liabilities: | ||
Accounts payable | 332 | 890 |
Advances from affiliates | 9,602 | 4,147 |
Current portion of derivative payable | 497 | 284 |
Accrued interest | 23 | 28 |
Accrued liabilities | 7,948 | 12,050 |
Current portion of long-term debt | 79,350 | 81,100 |
Total current liabilities | 97,752 | 98,499 |
Long-term derivative liability | 280 | |
Asset retirement obligations and other | 1,968 | 4,863 |
Commitments and contingencies (Note 9) | ||
Unitholders’ equity (deficit): | ||
Common unitholders’ equity (deficit) | (84,900) | (115,734) |
Series A preferred equity | 45,148 | |
Warrants | 1,868 | 1,868 |
Unitholders'/owner's equity excluding non-controlling interests | (83,032) | (68,718) |
Non-controlling interests | 67,360 | 70,152 |
Total unitholders’ equity (deficit) | (15,672) | 1,434 |
Total liabilities and unitholders’ equity (deficit) | $ 84,048 | $ 105,076 |
COMBINED CONSOLIDATED STATEMENT
COMBINED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Revenues: | |||
Gas and oil production | $ 7,841 | $ 129,993 | $ 368,845 |
Gain (loss) on mark-to-market derivatives | 310 | (18,601) | 268,085 |
Other, net | 900 | 757 | 993 |
Total revenues | 9,051 | 137,158 | 753,493 |
Costs and expenses: | |||
Gas and oil production | 2,528 | 78,034 | 171,882 |
General and administrative | 5,478 | 56,459 | 109,569 |
Depreciation, depletion and amortization | 3,576 | 82,381 | 166,929 |
Asset impairment | 41,879 | 973,981 | |
Total costs and expenses | 11,582 | 277,084 | 1,507,662 |
Operating loss | (2,531) | (139,926) | (754,169) |
Interest expense | (20,937) | (83,744) | (125,658) |
Gain (loss) on early extinguishment of debt, net | 20,418 | (4,726) | |
Reorganization items, net | (21,649) | ||
Gain on deconsolidation | 46,951 | ||
Other income (loss) | 6,855 | (12,008) | (1,181) |
Net loss | (16,613) | (189,958) | (885,734) |
Preferred unitholders’ dividends | (339) | (3,360) | |
Net loss attributable to non-controlling interests | 2,792 | 176,854 | 649,316 |
Net loss attributable to unitholders’ interests | (13,821) | (13,443) | (239,778) |
Allocation of net loss attributable to unitholders’/owner’s interests: | |||
Portion applicable to owner’s interest (period prior to the transfer of assets on February 27, 2015) | (10,475) | ||
Portion applicable to unitholders’ interests (period subsequent to the transfer of assets on February 27, 2015) | $ (13,821) | $ (13,443) | $ (229,303) |
Net loss attributable to unitholders per common unit (Note 2): | |||
Basic | $ (0.50) | $ (0.52) | $ (8.82) |
Diluted | $ (0.50) | $ (0.52) | $ (8.82) |
Weighted average common units outstanding (Note 2): | |||
Basic | 29,965 | 26,035 | 26,011 |
Diluted | 29,965 | 26,035 | 26,011 |
Atlas Resource Partners, L.P. | |||
Revenues: | |||
Drilling Partnerships management | $ 25,009 | $ 115,570 | |
Costs and expenses: | |||
Drilling Partnerships management | 18,331 | $ 85,301 | |
Gain on deconsolidation | $ 46,951 |
COMBINED CONSOLIDATED STATEMEN4
COMBINED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Statement Of Income And Comprehensive Income [Abstract] | |||
Net loss | $ (16,613) | $ (189,958) | $ (885,734) |
Other comprehensive loss: | |||
Reclassification adjustment for gains due to impairment | (85,768) | ||
Reclassification to mark-to-market gains | (10,540) | (86,328) | |
Reclassification to gain on deconsolidation of Atlas Resource Partners, L.P. | (1,949) | ||
Total other comprehensive loss | (12,489) | (172,096) | |
Comprehensive loss | (16,613) | (202,447) | (1,057,830) |
Comprehensive loss attributable to non-controlling interests | 2,792 | 185,059 | 771,688 |
Comprehensive loss attributable to unitholders’ interest | $ (13,821) | $ (17,388) | $ (286,142) |
COMBINED CONSOLIDATED STATEMEN5
COMBINED CONSOLIDATED STATEMENT OF CHANGES IN UNITHOLDERS' EQUITY (DEFICIT) - USD ($) $ in Thousands | Total | Series A Preferred Equity | Common Unitholders' Equity (Deficit) | Owner's Equity | Warrants | Accumulated Other Comprehensive Income | Non-Controlling Interest |
Balance at Dec. 31, 2014 | $ 915,215 | $ 147,308 | $ 54,008 | $ 713,899 | |||
Net loss attributable to owner’s interest prior to the transfer of assets on February 27, 2015 | (10,475) | (10,475) | |||||
Net distribution to owner’s interest prior to the transfer of assets on February 27, 2015 | (19,758) | (19,758) | |||||
Net assets contributed by owner to Atlas Energy Group, LLC | $ 117,075 | $ (117,075) | |||||
Net assets contributed by owner to Atlas Energy Group, LLC, units | 26,010,766 | ||||||
Issuance of units | 268,880 | $ 40,536 | $ (536) | 228,880 | |||
Issuance of units (units) | 1,621,427 | ||||||
Distributions to non-controlling interests | (116,621) | (116,621) | |||||
Net issued and unissued units under incentive plan | 10,404 | 5,348 | 5,056 | ||||
Distribution equivalent rights paid on unissued units under incentive plans | (558) | (558) | |||||
Distribution payable | 10,910 | $ (338) | 11,248 | ||||
Gain on sale from subsidiary unit issuances | 4,268 | (4,268) | |||||
Dividends paid to preferred equity unitholders | (2,683) | (2,683) | |||||
Other comprehensive loss | (172,096) | (49,724) | (122,372) | ||||
Net income (loss) | (875,259) | 3,360 | (229,303) | (649,316) | |||
Balance at Dec. 31, 2015 | 7,959 | $ 40,875 | $ (103,148) | 4,284 | 65,948 | ||
Balance units at Dec. 31, 2015 | 1,621,427 | 26,010,766 | |||||
Issuance of units and warrants | 3,614 | $ 4,611 | $ (4,611) | $ 1,868 | 1,746 | ||
Issuance of units and warrants (units) | 184,431 | 4,668,044 | |||||
Distributions to non-controlling interests | (20,844) | (20,844) | |||||
Net issued and unissued units under incentive plan | 4,989 | $ 5,287 | (298) | ||||
Net issued and unissued units under incentive plan (units) | 33,826 | ||||||
Distribution equivalent rights paid on unissued units under incentive plans | (11) | (11) | |||||
Distribution payable | 3,730 | $ 338 | 3,392 | ||||
Gain on sale from subsidiary unit issuances | $ 181 | (181) | |||||
Dividends paid to preferred equity unitholders | (1,015) | (1,015) | |||||
Other comprehensive loss | (10,540) | (2,335) | (8,205) | ||||
Net income (loss) | (189,958) | 339 | (13,443) | (176,854) | |||
Deconsolidation of Atlas Resource Partners, L.P. | 203,510 | $ (1,949) | 205,459 | ||||
Balance at Dec. 31, 2016 | 1,434 | $ 45,148 | $ (115,734) | $ 1,868 | 70,152 | ||
Balance units at Dec. 31, 2016 | 1,805,858 | 26,044,592 | 4,668,044 | ||||
Issuance of units | $ 2,144 | $ (2,144) | |||||
Issuance of units (units) | 85,760 | ||||||
Net issued and unissued units under incentive plan | (493) | $ (493) | |||||
Net issued and unissued units under incentive plan (units) | 17,226 | ||||||
Conversion of Series A preferred units | $ (47,292) | $ 47,292 | |||||
Conversion of Series A preferred units (units) | (1,891,618) | 5,911,304 | |||||
Net income (loss) | (16,613) | $ (13,821) | (2,792) | ||||
Balance at Dec. 31, 2017 | $ (15,672) | $ (84,900) | $ 1,868 | $ 67,360 | |||
Balance units at Dec. 31, 2017 | 31,973,122 | 4,668,044 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | |||
Net loss | $ (16,613) | $ (189,958) | $ (885,734) |
Adjustments to reconcile net loss to net cash provided by (used in) operating activities: | |||
Depreciation, depletion and amortization | 3,576 | 82,381 | 166,929 |
Asset impairment | 41,879 | 973,981 | |
Gain on early extinguishment of debts, net | (20,418) | 4,726 | |
(Gain) loss on derivatives | 217 | 674 | (227,155) |
Amortization of deferred financing costs and debt discount | 690 | 15,331 | 34,083 |
Non-cash compensation expense | (493) | 5,778 | 10,324 |
Paid-in-kind interest | 19,258 | 11,721 | |
Other loss | 11,922 | 1,181 | |
Non cash gain on deconsolidation of ARP | (46,951) | ||
Gain on Lightfoot transaction | (9,908) | ||
Distributions paid to non-controlling interests | (20,844) | (117,179) | |
Equity income in unconsolidated companies | (900) | (549) | (742) |
Distributions received from unconsolidated companies | 1,574 | 1,873 | 2,847 |
Changes in operating assets and liabilities: | |||
Monetization of ARP’s derivatives | 243,552 | ||
Accounts receivable, prepaid expenses and other | (328) | 76,023 | 123,531 |
Advances to/from affiliates | 5,455 | 4,147 | 4,390 |
Accounts payable and accrued liabilities | (4,630) | (37,464) | (84,117) |
Net cash provided by (used in) operating activities | (2,102) | 179,097 | 7,065 |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Capital expenditures | (27,757) | (156,360) | |
Net cash paid for acquisitions | (120,332) | ||
Cash paid for investment in Joliet Terminals | (3,337) | ||
Proceeds from Lightfoot transaction | 28,006 | ||
Other | (1,156) | (1,223) | |
Net cash provided by (used in) investing activities | 24,669 | (28,913) | (277,915) |
CASH FLOWS FROM FINANCING ACTIVITIES: | |||
Borrowings under ARP’s revolving credit facility | 135,000 | ||
Repayments under credit facilities | (21,601) | ||
Repayments under ARP’s revolving credit facility | (291,191) | ||
ARP senior note repurchases | (5,528) | ||
Net proceeds from issuance of Series A units | 40,000 | ||
Net proceeds from issuance of our subsidiaries’ units to the public | 1,746 | 208,902 | |
Dividends to preferred unitholders | (1,015) | (2,683) | |
Net investment from (distributions to) Atlas Energy | (19,758) | ||
Deferred financing costs, distribution equivalent rights and other | (46) | (4,151) | (33,742) |
Net cash provided by (used in) financing activities | (21,647) | (169,389) | 243,706 |
Net change in cash and cash equivalents | 920 | (19,205) | (27,144) |
Cash and cash equivalents, beginning of year | 12,009 | 31,214 | 58,358 |
Cash and cash equivalents, end of period | $ 12,929 | 12,009 | 31,214 |
Atlas Energy | Term loan facilities | |||
CASH FLOWS FROM FINANCING ACTIVITIES: | |||
Borrowings under term loan facilities | 859,890 | ||
Repayments under term loan facilities | $ (4,250) | $ (808,903) |
Organization
Organization | 12 Months Ended |
Dec. 31, 2017 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | |
Organization | NOTE 1—ORGANIZATION We are a publicly traded (OTCQB: ATLS) Delaware limited liability company formed in October 2011. On February 27, 2015, our former owner, Atlas Energy, L.P. (“Atlas Energy”), transferred its assets and liabilities, other than those related to its midstream assets, to us, and effected a pro rata distribution of our common units representing a 100% interest in us, to Atlas Energy’s unitholders (the “Separation”). Concurrently with the distribution of our units, Atlas Energy and its remaining midstream interests merged with Targa Resources Corp. (“Targa”; NYSE: TRGP) and ceased trading. Our operations primarily consist of our ownership interests in the following: • All of the incentive distribution rights, an 80.0% general partner interest and a 2.1% limited partner interest in Atlas Growth Partners, L.P. (“AGP”), a Delaware limited partnership and an independent developer and producer of natural gas, crude oil and NGLs with operations primarily focused in the Eagle Ford Shale in South Texas; • A 12.0% limited partner interest in Lightfoot Capital Partners, L.P. (“Lightfoot L.P.”) and a 15.9% general partner interest in Lightfoot Capital Partners GP, LLC (“Lightfoot G.P.” and together with Lightfoot L.P., “Lightfoot”), the general partner of Lightfoot L.P., an entity for which Jonathan Cohen, Executive Chairman of the Company’s board of directors, is the Chairman of the board of directors. Lightfoot focuses its investments primarily on incubating new MLPs and providing capital to existing MLPs in need of additional equity or structured debt. See Note 2 for further disclosures regarding Lightfoot; • A membership interest in the founder shares of Osprey Sponsor, LLC (“Osprey Sponsor”) received in August 2017. Osprey Sponsor is the sponsor of Osprey Energy Acquisition Corp (“Osprey”). We received our membership interest in recognition of potential utilization, if any, of our office space, advisory services and personnel by Osprey. See Note 2 for further disclosures regarding Osprey and Osprey Sponsor; • Commencing September 1, 2016, Titan Energy, LLC (“Titan”), an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”) with operations in basins across the United States but primarily focused on the horizontal development of resource potential from the Eagle Ford Shale in South Texas. Titan Energy Management, LLC, our wholly owned subsidiary (“Titan Management”), holds the Series A Preferred Share of Titan, which entitles us to receive 2% of the aggregate of distributions paid to shareholders (as if we held 2% of Titan’s members’ equity, subject to potential dilution in the event of future equity interests) and to appoint four of seven directors. Titan sponsors and manages tax-advantaged investment partnerships (the “Drilling Partnerships”), in which it coinvests, to finance a portion of its natural gas, crude oil and NGL production activities. As discussed further below, Titan is the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”); • Through August 31, 2016, 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 23.3% limited partner interest in ARP. As discussed further below, ARP was the predecessor to the business and operations of Titan. At December 31, 2017, we had 31,973,122 common units issued and outstanding. The common units are a class of limited liability company interests in us. The holders of common units are entitled to participate in company distributions and exercise the rights or privileges available to holders of common units as outlined in the LLC Agreement. The Company will continue as a limited liability company until dissolved under the LLC Agreement. The LLC Agreement specifies the manner in which the Company will make cash distributions to holders of common units and other partnership securities (see Note 11). The following is a summary of the voting requirements specified for certain matters under the LLC Agreement: • Election of the directors to the Company’s board of directors - plurality of votes cast by the Company’s unitholders. • Issuance of additional company securities - no approval right, subject to the rules of any national securities exchange on which the Company’s securities are listed. • Amendment of the Company’s LLC Agreement - certain amendments may be made by the Company’s board of directors without the approval of the unitholders. Other amendments generally require the approval of a majority of the Company’s outstanding voting units. • Merger of the Company or the sale of all or substantially all of the Company’s assets - majority of the Company’s outstanding voting units in certain circumstances. • Dissolution of the Company - majority of the Company’s outstanding voting units. • Continuation of the Company upon dissolution - majority of the Company’s outstanding voting units. • The outstanding voting units consist of the Company’s common units and the Company’s Series A preferred units, which have voting rights identical to those of the Company’s common units on a “as converted” basis. ARP Restructuring and Emergence from Chapter 11 Proceedings On July 25, 2016, we, solely with respect to certain sections thereof, along with ARP and certain of its subsidiaries, entered into a Restructuring Support Agreement (the “Restructuring Support Agreement”) with certain of ARP’s and such subsidiaries’ lenders (the “Restructuring Support Parties”) to support ARP’s restructuring pursuant to a pre-packaged plan of reorganization (the “Plan”). On July 27, 2016, ARP and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”) in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court,” and the cases commenced thereby, the “Chapter 11 Filings”). The cases commenced thereby were jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.” On August 26, 2016, an order confirming the Plan was entered by the Bankruptcy Court. On September 1, 2016, (the “Plan Effective Date”), pursuant to the Plan, the following occurred: • ARP’s first lien lenders received cash payment of all obligations owed to them by ARP pursuant to the senior secured revolving credit facility (other than $440 million of principal and face amount of letters of credit) and became lenders under Titan’s first lien exit facility credit agreement, composed of a $410 million conforming reserve-based tranche and a $30 million non-conforming tranche. • ARP’s second lien lenders received a pro rata share of Titan’s second lien exit facility credit agreement with an aggregate principal amount of $252.5 million. In addition, ARP’s second lien lenders received a pro rata share of 10% of Titan’s common shares, subject to dilution by a management incentive plan. • ARP’s senior note holders, in exchange for 100% of the $668 million aggregate principal amount of senior notes outstanding plus accrued but unpaid interest as of the commencement of the Chapter 11 Filings, received 90% of Titan’s common shares, subject to dilution by a management incentive plan. • All of ARP’s preferred limited partnership units and common limited partnership units were cancelled without the receipt of any consideration or recovery. • ARP transferred all of its assets and operations to Titan as a new holding company and ARP dissolved. As a result, Titan became the successor issuer to ARP for purposes of and pursuant to Rule 12g-3 of the Securities Exchange Act of 1934, as amended. • Titan Management received a Series A Preferred Share of Titan, which entitles Titan Management to receive 2% of the aggregate of distributions paid to shareholders (as if it held 2% of Titan’s members’ equity, subject to potential dilution in the event of future equity interests) and to appoint four of seven directors and certain other rights. Four of the seven initial members of the board of directors of Titan are designated by Titan Management (the “Titan Class A Directors”). For so long as Titan Management holds such preferred share, the Titan Class A Directors will be appointed by a majority of the Titan Class A Directors then in office. Titan has a continuing right to purchase the preferred share at fair market value (as determined pursuant to the methodology provided for in Titan’s limited liability company agreement), subject to the receipt of certain approvals, including the holders of at least 67% of the outstanding common shares of Titan unaffiliated with Titan Management voting in favor of the exercise of the right to purchase the preferred share. We were not a party to ARP’s Restructuring. We remain controlled by the same ownership group and management team and thus, ARP’s Restructuring did not have a material impact on the ability of management to operate us or our other businesses. |
Basis of Presentation and Summa
Basis of Presentation and Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Basis of Presentation and Summary of Significant Accounting Policies | NOTE 2—BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 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 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 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 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 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 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 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 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 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 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 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 o |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2017 | |
Property Plant And Equipment [Abstract] | |
Property, Plant and Equipment | NOTE 3—PROPERTY, PLANT AND EQUIPMENT The following is a summary of property, plant and equipment at the dates indicated (in thousands): December 31, 2017 2016 Natural gas and oil properties: Proved properties $ 147,932 $ 84,631 Unproved properties — 63,314 Support equipment and other 3,188 3,188 Total natural gas and oil properties 151,120 151,133 Less – accumulated depreciation, depletion and amortization (85,827 ) (82,234 ) $ 65,293 $ 68,899 During the years ended December 31, 2016 and 2015, we recognized $0.4 million and $21.5 million of non-cash investing activities capital expenditures, which were reflected within the changes in accounts payable and accrued liabilities on our combined consolidated statement of cash flows. For the year ended December 31, 2016, we recognized $7.7 million of non-cash investing activities capital expenditures related to ARP’s consolidation of certain Drilling Partnerships (see Note 9), which was reflected within the changes to adjustments to reconcile net loss to net cash provided by operating activities – other (income) loss on our consolidated statement of cash flows. As of December 31, 2017, we transferred $63.3 million of AGP’s unproved properties to proved natural gas and oil properties as management finalized capital plans for drilling and developing the wells within the Eagle Ford operating area. For the year ended December 31, 2016, we recognized $16.5 million of asset impairment related to AGP’s unproved oil and gas properties in the Eagle Ford operating area, which were impaired For the year ended December 31, 2016, we recognized $25.4 million of asset impairment related to AGP’s proved oil and gas properties in our Eagle Ford operating area, which was impaired due to lower forecasted commodity prices and timing of capital financing and deployment for the development of our undeveloped properties. For the year ended December 31, 2015, we recognized $967.4 million of asset impairment of which $960 million related to ARP’s proved oil and gas properties in the Barnett, Coal-bed Methane, Rangely, Southern Appalachia, Marcellus and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices, net of $85.8 million of future hedge gains reclassified from accumulated other comprehensive income, and $7.4 million related to AGP’s proved oil and gas properties in the Marble Falls and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices. During the year ended December 31, 2015, we recognized a $1.2 million loss on asset sales and disposal related to ARP’s plugging and abandonment costs for certain wells in the New Albany Shale. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | NOTE 4—ASSET RETIREMENT OBLIGATIONS The estimated liability for asset retirement obligations was based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability was discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. We have no assets legally restricted for purposes of settling asset retirement obligations. Except for our gas and oil properties, we determined there were no other material retirement obligations associated with tangible long-lived assets. A reconciliation of our subsidiaries’ liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands): Years Ended December 31, 2017 2016 2015 Asset retirement obligations, beginning of year $ 184 $ 113,909 $ 108,101 Liabilities incurred — 12,458 2,074 Liabilities settled — 139 (2,591 ) Accretion expense 5 3,916 6,325 Deconsolidation of ARP (Note 2) — (130,238 ) — Asset retirement obligations, end of year $ 189 $ 184 $ 113,909 The above accretion expense was included in depreciation, depletion and amortization in our combined consolidated statements of operations. The above liabilities incurred during the year ended December 31, 2016 were primarily additions to ARP’s asset retirement obligations due to the consolidation of some of ARP’s Drilling Partnerships which was also included in the deconsolidation of ARP amount. |
Debt
Debt | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Debt | NOTE 5—DEBT Total debt consists of the following at the dates indicated (in thousands): December 31, 2017 2016 First Lien Credit Agreement $ 20,666 $ 37,962 Second Lien Credit Agreement 59,552 44,593 Debt discount, net of accumulated amortization of $1,090 and $623 (778 ) (1,244 ) Deferred financing costs, net of accumulated amortization of $2,704 and $2,538, respectively (90 ) (211 ) Total debt, net 79,350 81,100 Less current maturities (79,350 ) (81,100 ) Total long-term debt, net $ — $ — Cash Interest. Cash payments for interest were $1.0 million, $55.8 million and $106.7 million for the years ended December 31, 2017, 2016 and 2015, respectively. Credit Agreements First Lien Credit Agreement . On March 30, 2016, we, together with New Atlas Holdings, LLC (the “Borrower”) and Atlas Lightfoot, LLC, entered into a third amendment (the “Third Amendment”) to our credit agreement with Riverstone Credit Partners, L.P., as administrative agent (“Riverstone”), and the lenders (the “Lenders”) from time to time party thereto (the “First Lien Credit Agreement”). The outstanding loans under the First Lien Credit Agreement were bifurcated between the existing First Lien Credit Agreement and the new Second Lien Credit Agreement (defined below), with $35.0 million and $35.8 million (including $2.4 million in deemed prepayment premium) in borrowings outstanding, respectively. As a result of these transactions, we recognized $6.1 million as a loss on early extinguishment of debt, consisting of the $2.4 million prepayment penalty and $3.7 million of accelerated amortization of deferring financing costs, on our combined consolidated statement of operations for the year ended December 31, 2016. The Third Amendment amended the First Lien Credit Agreement to, among other things: • provide the ability for us and the Borrower to enter into the new Second Lien Credit Agreement (defined below); • shorten the maturity date of the First Lien Credit Agreement to September 30, 2017, subject to an optional extension to September 30, 2018 by the Borrower, assuming certain conditions are met, including a First Lien Leverage Ratio (as defined in the First Lien Credit Agreement) of not more than 6:00 to 1:00 and a 5% extension fee. Between September 29, 2017 and April 26, 2018, we entered into a series of amendments to extend the maturity date of our First Lien Credit Agreement to June 30, 2018. • modify the applicable cash interest rate margin for ABR Loans and Eurodollar Loans to 0.50% and 1.50%, respectively, and add a pay-in-kind interest payment of 11% of the principal balance per annum; • allow the Borrower to make mandatory pre-payments under the First Lien Credit Agreement or the new Second Lien Credit Agreement, in its discretion, and add additional mandatory pre-payment events, including a monthly cash sweep for balances in excess of $4 million; • provide that the First Lien Credit Agreement may be prepaid without premium; • replace the existing financial covenants with (i) the requirement that we maintain a minimum of $2 million in EBITDA on a trailing twelve-month basis, beginning with the quarter ending June 30, 2016, and (ii) the incorporation into the First Lien Credit Agreement of the financial covenants included in ARP’s credit agreement, beginning with the quarter ending June 30, 2016; • prohibit the payment of cash distributions on our common and preferred units; • require the receipt of quarterly distributions from Atlas Growth Partners, GP, LLC and Lightfoot; and • add a cross-default provision for defaults by ARP. On October 6, 2016, we entered into a fourth amendment to the First Lien Credit Agreement with Riverstone and the Lenders, effective as of September 1, 2016, that makes conforming changes to reflect the status of Titan as the successor to ARP following the consummation of the Chapter 11 Filings and also removed the financial covenants and related cross-defaults that had previously been incorporated from ARP’s credit agreement. In December 2017, we used the proceeds from the Proposed Transaction to pay down $21.6 million of our first lien credit facility. Second Lien Credit Agreement. Also on March 30, 2016, we and the Borrower entered into a new second lien credit agreement (the “Second Lien Credit Agreement”) with Riverstone and the Lenders. As described above, $35.8 million of the indebtedness previously outstanding under the First Lien Credit Agreement was moved under the Second Lien Credit Agreement. The Second Lien Credit Agreement also has an unamortized discount of $0.8 million as of December 31, 2017, related to the 4,668,044 warrants issued in connection with the Second Lien Credit Agreement. The Second Lien Credit Agreement matures on March 30, 2019, subject to an optional extension (the “Extension Option”) to March 30, 2020, assuming certain conditions are met, including a Total Leverage Ratio (as defined in the Second Lien Credit Agreement) of not more than 6:00 to 1:00 and a 5% extension fee. Borrowings under the Second Lien Credit Agreement are secured on a second priority basis by security interests in the same collateral that secures borrowings under the First Lien Credit Agreement. Borrowings under the Second Lien Credit Agreement bear interest at a rate of 30%, payable in-kind through an increase in the outstanding principal. If the First Lien Credit Agreement is repaid in full prior to March 30, 2018, the rate will be reduced to 20%. If the Extension Option is exercised, the rate will again be increased to 30%. If our market capitalization is greater than $75 million, we can issue common units in lieu of increasing the principal to satisfy the interest obligation. The Borrower may prepay the borrowings under the Second Lien Credit Agreement without premium at any time. The Second Lien Credit Agreement includes the same mandatory prepayment events as the First Lien Credit Agreement, subject to the Borrower’s discretion to prepay either the First Lien Credit Agreement or the Second Lien Credit Agreement. The Second Lien Credit Agreement contains the same negative and affirmative covenants and events of default as the First Lien Credit Agreement, including customary covenants that limit the Borrower’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from the distribution, merge into or consolidate with other persons, enter into swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions. In addition, the Second Lien Credit Agreement requires that we maintain an Asset Coverage Ratio (as defined in the Second Lien Credit Agreement) of not less than 2.00 to 1.00 as of September 30, 2017 and each fiscal quarter ending thereafter. In connection with the First Lien Credit Agreement and Second Lien Credit Agreement, the lenders thereunder continued their syndicated participation in the underlying loans consistent with the original term loan facilities and therefore certain of the Company’s current and former officers participated in approximately 12% of the loan syndication and warrants and a foundation affiliated with a 5% or more unitholder participated in approximately 12% of the loan syndication. On October 6, 2016, we entered into a first amendment to the Second Lien Credit Agreement with Riverstone and the Lenders, effective as of September 1, 2016, that makes conforming changes to reflect the status of Titan as the successor to ARP following the consummation of the Chapter 11 Filings and also removes the financial covenants and related cross-defaults that had previously been incorporated from ARP’s credit agreement. In addition to the $20.7 million of amounts outstanding under our First Lien Credit Agreement due on June 30, 2018, we classified the $59.6 million of amounts outstanding our Second Lien Credit Agreement 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 combined consolidated balance sheet as of December 31, 2017. The aggregate amount of our debt maturities, excluding the effect of future paid in kind interest to be accrued in accordance with the terms of the First and Second Lien Credit Agreements, is as follows (in thousands): Years Ended December 31: 2017 $ 80,218 2018 — 2019 — 2020 — 2021 — Thereafter — Total principal maturities 80,218 Deferred financing costs and debt discounts, net of accumulated amortization (868 ) Total debt $ 79,350 |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Derivative Instruments | NOTE 6—DERIVATIVE INSTRUMENTS We use swaps in connection with our commodity price risk management activities. We do not apply hedge accounting to any of our derivative instruments. As a result, gains and losses associated with derivative instruments are recognized as gains on mark-to-market derivatives on our consolidated statements of operations. We enter into commodity future option contracts to achieve more predictable cash flows by hedging our exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. Pursuant to ARP’s restructuring support agreement, ARP completed the sale of substantially all of its commodity hedge positions on July 25, 2016 and July 26, 2016 and used the proceeds to repay $233.5 million of borrowings outstanding under the ARP’s first lien credit facility. On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2). The following table summarizes the commodity derivative activity and presentation in our combined consolidated statement of operations for the periods indicated (in thousands): For the Years Ended December 31, 2017 2016 Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets (1) $ — $ 10,540 Portion of settlements attributable to subsequent mark—to—market gains (2) — 88,841 Total cash settlements on commodity derivative contracts $ — $ 99,381 Gain (loss) recognized on cash settlement (3) $ 527 $ (17,927 ) Gain (loss) recognized on open derivative contracts (3) (217 ) (674 ) Gain (loss) on mark-to-market derivatives $ 310 $ (18,601 ) (1) Recognized in gas and oil production revenue. (2) Excludes the effects of the $235.3 million, net of $8.2 million in ARP’s hedge monetization fees, paid directly to ARP’s First Lien Credit Facility lenders upon the sale of substantially all of ARP’s commodity hedge positions on July 25, 2016 and July 26, 2016. (3) Recognized in gain (loss) on mark-to-market derivatives. The following table summarizes the gross fair values of AGP’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our combined consolidated balance sheets as of the dates indicated (in thousands): Offsetting Derivatives as of December 31, 2017 Gross Amounts Recognized Gross Amounts Offset Net Amount Presented Current portion of derivative assets $ — $ — $ — Long-term portion of derivative assets — — — Total derivative assets $ — $ — $ — Current portion of derivative liabilities $ (497 ) $ — $ (497 ) Long-term portion of derivative liabilities — — — Total derivative liabilities $ (497 ) $ — $ (497 ) Offsetting Derivatives as of December 31, 2016 Current portion of derivative assets $ 97 $ (97 ) $ — Long-term portion of derivative assets — — — Total derivative assets $ 97 $ (97 ) $ — Current portion of derivative liabilities $ (381 ) $ 97 $ (284 ) Long-term portion of derivative liabilities (280 ) — (280 ) Total derivative liabilities $ (661 ) $ 97 $ (564 ) At December 31, 2017, AGP had the following commodity derivatives: Type Production Period Ending December 31, Volumes(1) Average Fixed Price Fair Value Asset (in thousands) (2) Crude Oil – Fixed Price Swaps 2018 74,500 $ 52.510 $ (497 ) Net liabilities (497 ) (1) Volumes for crude oil are stated in barrels. (2) Fair value of crude oil fixed price swaps are based on forward West Texas Intermediate (“WTI”) crude oil prices, as applicable. On May 1, 2015, AGP entered into a secured credit facility agreement with a syndicate of banks. As of December 31, 2017, the lenders under the credit facility have no commitment to lend to AGP under the credit facility and AGP has a zero dollar borrowing base, but AGP and its subsidiaries have the ability to enter into derivative contracts to manage their exposure to commodity price movements which will benefit from the collateral securing the credit facility. Obligations under the credit facility are secured by mortgages on AGP’s oil and gas properties and first priority security interests in substantially all of its assets. The credit facility may be amended in the future if AGP and the lenders agree to increase the borrowing base and the lenders’ commitments thereunder. The secured credit facility agreement contains covenants that limit AGP and its subsidiaries ability to incur indebtedness, grant liens, make loans or investments, make distributions, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions, including a sale of all or substantially all of its assets. AGP was in compliance with these covenants as of December 31, 2017. In addition, AGP’s credit facility includes customary events of default, including failure to timely pay, breach of covenants, bankruptcy, cross-default with other material indebtedness (including obligations under swap agreements in excess of any agreed upon threshold amount), and change of control provisions. |
Fair Value of Financial Instrum
Fair Value of Financial Instruments | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Instruments | NOTE 7—FAIR VALUE OF FINANCIAL INSTRUMENTS We have established a hierarchy to measure our financial instruments at fair value, which requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect our own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value: Level 1 – Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date. Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability. Level 3 – Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques. Assets and Liabilities Measured at Fair Value on a Recurring Basis We use a market approach fair value methodology to value our outstanding derivative contracts and financial instruments. The fair value of a financial instrument depends on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. We separate the fair value of our financial instruments into the three level hierarchy (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. As of December 31, 2017, all of our derivative financial instruments were classified as Level 2. Information for our financial instruments measured at fair value were as follows (in thousands): Level 1 Level 2 Level 3 Total As of December 31, 2017 Assets, gross Rabbi trust $ 1,502 $ — $ — $ 1,502 AGP Commodity swaps — — — — Total assets, gross 1,502 — — 1,502 Liabilities, gross AGP Commodity swaps — (497 ) — (497 ) Total derivative liabilities, gross — (497 ) — (497 ) Total assets, fair value, net $ 1,502 $ (497 ) $ — $ 1,005 As of December 31, 2016 Assets, gross Rabbi trust $ 4,208 $ — $ — $ 4,208 AGP Commodity swaps — 97 — 97 Total assets, gross 4,208 97 — 4,305 Liabilities, gross AGP Commodity swaps — (661 ) — (661 ) Total derivative liabilities, gross $ — (661 ) — (661 ) Total assets, fair value, net $ 4,208 $ (564 ) $ — $ 3,644 Other Financial Instruments Our other current assets and liabilities on our combined consolidated balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1. The estimated fair value of our debt at December 31, 2017 approximated its carrying value of $79.5 million, which consisted of our First Lien Credit Agreement and Second Lien Credit Agreement that bear interest at variable rates and are categorized as Level 1 values. Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis Acquisitions . Management estimated the fair values of ARP’s natural gas and oil properties transferred to ARP in June 2016 upon consolidation of certain Drilling Partnerships (see Note 4) based on a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, ARP’s future operating and development costs of the assets, the respective natural gas, oil and natural gas liquids forward price curves, and estimated salvage values using ARP’s historical experience and external estimates of recovery values. These estimates of fair value were Level 3 measurements as they were based on unobservable inputs. Management estimated the fair value of asset retirement obligations transferred to ARP in June 2016 upon consolidation of certain Drilling Partnerships (see Note 4) based on discounted cash flow projections using ARP’s historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future considering inflation rates, federal and state regulatory requirements, and ARP’s assumed credit-adjusted risk-free interest rate. These estimates of fair value were Level 3 measurements as they were based on unobservable inputs. Warrants. We estimated the fair value of the warrants associated the Second Lien Credit Agreement (see Note 10) using a Black-Scholes pricing model which was based on Level 3 inputs including a unit price on the date of issuance of $0.50, exercise price of $0.20, risk free rate of 1.8%, a term of 10 years, and estimated volatility rate of 57%. The volatility rate used was consistent with that of ARP and similar sized entities within the industry at the time of issuance. The estimated fair value per warrant was $0.40. Equity Method Investments . Management estimated the fair value of our equity method investment in ARP based on market data including ARP’s unit price and announcement of restructuring, which are Level 1 measurements as they are based on observable inputs. Management estimated the fair value of our equity method investment in Titan based on its estimated enterprise value and reorganizational value of assets and liabilities upon emergence from bankruptcy through fresh-start accounting utilizing the discounted cash flow method for both its gas and oil production business and its partnership management business based on the financial projections in ARP’s disclosure statement. The resulting fair value of Titan’s equity was used to value our equity method investment. These estimates of fair value are Level 3 measurements as they are based on unobservable inputs. Asset Impairments. We estimated the fair value of our gas and oil properties in connection with reviewing these assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions and judgments regarding such events or circumstances based on a discounted cash flow model, which considers the estimated remaining lives of the wells based on reserve estimates, our future operating and development costs of the assets, the respective natural gas, oil and natural gas liquids forward price curves and estimated salvage values using our historical experience and external estimates of recovery values. See Note 4 for disclosure of impairments of our gas and oil properties. These estimates of fair value are Level 3 measurements as they are based on unobservable inputs. |
Certain Relationships and Relat
Certain Relationships and Related Party Transactions | 12 Months Ended |
Dec. 31, 2017 | |
Related Party Transactions [Abstract] | |
Certain Relationships And Related Party Transactions | NOTE 8—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS Relationship with ARP . ARP did not directly employ any persons to manage or operate its business. These functions were provided by employees of us and/or our affiliates. On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2). Relationship with Titan . Other than its named executive officers, Titan does not directly employ any persons to manage or operate its business. These functions were provided by employees of us and/or our affiliates. On September 1, 2016, Titan entered into a Delegation of Management Agreement (the “Delegation Agreement”) with Titan Management, our wholly owned subsidiary. Pursuant to the Delegation Agreement, Titan has delegated to Titan Management all of Titan’s rights and powers to manage and control the business and affairs of Titan Energy Operating, LLC (“Titan Operating”), a wholly owned subsidiary of Titan. However, Titan’s board of directors retains management and control over certain non-delegated duties. In addition, Titan also entered into an Omnibus Agreement (the “Omnibus Agreement”) dated September 1, 2016 with Titan Management, Atlas Energy Resource Services, Inc. (“AERS”), our wholly owned subsidiary, and Titan Operating. Pursuant to the Omnibus Agreement, Titan Management and AERS will provide Titan and Titan Operating with certain financial, legal, accounting, tax advisory, financial advisory and engineering services (including cash management services) and Titan and Titan Operating will reimburse Titan Management and AERS for their direct and allocable indirect expenses incurred in connection with the provision of the services, subject to certain approval rights in favor of Titan’s Conflicts Committee. As of December 31, 2017 and December 31, 2016, we had payables of $9.6 million and $3.3 million to Titan related to the timing of funding cash accounts related to general and administrative expenses, such as payroll and benefits, which was recorded in advances from affiliates in our combined consolidated balance sheets. Relationship with AGP . AGP does not directly employ any persons to manage or operate its business. These functions are provided by employees of us and/or our affiliates. Atlas Growth Partners, GP, LLC (“AGP GP”) receives an annual management fee in connection with its management of AGP equivalent to 1% of capital contributions per annum. During each of the years ended December 31, 2017 and 2016, AGP paid a management fee of $2.3 million. We charge direct costs, such as salary and wages, and allocate indirect costs, such as rent for offices, to AGP by us based on the number of its employees who devoted their time to activities on its behalf. AGP reimburses us at cost for direct costs incurred on its behalf. AGP reimburses all necessary and reasonable indirect costs allocated by the general partner. Relationship with Lightfoot . Jonathan Cohen, Executive Chairman of the Company’s board of directors, is the Chairman of the board of directors of Lightfoot G.P. As part of the relationship, we assumed the obligations under an agreement pursuant to which Messrs. Cohen receives compensation in recognition of his role continued service as chair of Lightfoot G.P. Pursuant to the agreement, Messrs. Cohen receives an amount equal to 10% of the distributions that we receive from the Lightfoot entities, excluding amounts that constitute a return of capital to us. In connection with Lightfoot’s close of a portion of the Proposed Transaction, Messrs. Cohen received $2.0 million based on his Lightfoot agreement. In recognition of Messrs. Herz’s work in connection with Lightfoot’s Proposed Transaction, Mr. Herz received $0.2 million, representing 10% of the aggregate amount Messrs. Cohen had originally been entitled to receive. Relationship with Osprey Sponsor . We received our membership interest in Osprey Sponsor in recognition of potential utilization, if any, of our office space, advisory services and personnel by Osprey, for which we will be reimbursed at cost. We have provided a nominal amount of services to Osprey as of December 31, 2017. Relationship with Drilling Partnerships . ARP conducted certain activities through, and a portion of its revenues were attributable to, sponsorship of the Drilling Partnerships. Through the Plan Effective Date, ARP served as the ultimate general partner and operator of the Drilling Partnerships and assumed customary rights and obligations for the Drilling Partnerships. As the ultimate general partner, ARP was liable for the Drilling Partnerships’ liabilities and could have been liable to limited partners of the Drilling Partnerships if it breached its responsibilities with respect to the operations of the Drilling Partnerships. ARP was entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Drilling Partnership’s revenue and costs and expenses according to the respective partnership agreements. In March 2016, ARP transferred $36.7 million of investor capital raised and $13.3 million of accrued well drilling and completion costs incurred by ARP to the Atlas Eagle Ford 2015 L.P. private drilling partnership for activities directly related to their program. In June 2016, ARP transferred $5.2 million of funds to certain of the Drilling Partnerships that were projected to make monthly or quarterly distributions to their limited partners over the next several months and/or quarter to ensure accessible distribution funding coverage in accordance with the respective Drilling Partnerships’ operations and partnership agreements in the event ARP experienced a prolonged restructuring period as ARP performed all administrative and management functions for the Drilling Partnerships. During the quarter ended June 30, 2016, ARP recorded $7.2 million and $12.4 million of gas and oil properties and asset retirement obligations, respectively, transferred to ARP as a result of certain Drilling Partnership liquidations. The gas and oil properties and asset retirement obligations were recorded at their fair values on the respective dates of the Drilling Partnerships’ liquidation and transfer to ARP (see Note 7) and resulted in a non-cash loss of $6.2 million, net of liquidation and transfer adjustments, for the year ended December 31, 2016, which was recorded in other income/(loss) in the combined consolidated statements of operations. On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2), which includes the direct relationship with the Drilling Partnerships and the above activities. As of the Plan Effective Date, Titan serves as the ultimate general partner and operator of the Drilling Partnerships and assumed customary rights and obligations for the Drilling Partnerships. AGP’s Relationship with Titan . At our direction, AGP reimburses Titan for direct costs, such as salaries and wages, charged to AGP based on our employees who incurred time to activities on AGP’s behalf and indirect costs, such as rent and other general and administrative costs, allocated to AGP based on the number of our employees who devoted their time to activities on AGP’s behalf. As of December 31, 2017 and 2016, AGP had payables of $0.1 million and $0.8 million, respectively to Titan related to the direct costs, indirect cost allocation, and timing of funding of cash accounts, which was recorded in advances from affiliates in the combined consolidated balance sheets. Other Relationships. We have other related party transactions with regard to our First Lien Credit Agreement and Second Lien Credit Agreement (see Note 5), our Series A preferred units and our general partner and limited partner interest in Lightfoot (see Notes 1 and 2). |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
Commitments And Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | NOTE 9—COMMITMENTS AND CONTINGENCIES General Commitments We lease office space and equipment under leases with varying expiration dates. Our rental expense was $0.2 million, $7.0 million and $16.2 million for the years ended December 31, 2017, 2016 and 2015, respectively. As of December 31, 2017, we did not have any future rental commitments, firm transportation or gas gathering commitments, or commitments related to our drilling and completion and capital expenditures. On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2). ARP’s Drilling Partnership Commitments ARP was the ultimate managing general partner of the Drilling Partnerships and had agreed to indemnify each investor partner from any liability that exceeded such partner’s share of Drilling Partnership assets. ARP had structured certain Drilling Partnerships to allow limited partners to have the right to present their interests for purchase. Generally, for Drilling Partnerships with this structure, ARP was not obligated to purchase more than 5% to 10% of the units in any calendar year, no units may be purchased during the first five years after closing for the Drilling Partnership, and ARP could immediately suspend the presentment structure for a Drilling Partnership by giving notice to the limited partners that it did not have adequate liquidity for redemptions. In accordance with the Drilling Partnership agreement, the purchase price for limited partner interests would generally be based upon a percentage of the present value of future cash flows allocable to the interest, discounted at 10%, as of the date of presentment, subject to estimated changes by ARP to reflect current well performance, commodity prices and production costs, among other items. Based on historical experience, as of the date of the Chapter 11 Filings, ARP’s estimated liability for such redemptions of limited partner interests in the Drilling Partnerships which allow such transactions was not material. While its historical structure has varied, ARP had 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 had 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. Titan 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 fells 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 had 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. For the years ended December 31, 2016 and 2015, $0.8 million and $1.7 million, respectively, of ARP’s gas and oil production revenues, net of corresponding production costs, from certain Drilling Partnerships were subordinated, which reduced gas and oil production revenues and expenses. On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2), which includes the direct relationship with the Drilling Partnerships and the above activities. Subsequent to the Plan Effective Date, Titan is the ultimate managing general partner of the Drilling Partnerships and performs the above responsibilities and evaluations. Legal Proceedings We are parties to various routine legal proceedings arising out of the ordinary course of business. Our management and our subsidiaries believe that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations. Environmental Matters We are subject to various federal, state and local laws and regulations relating to the protection of the environment. We have established procedures for the ongoing evaluation of our and our subsidiaries’ operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. We maintain insurance which may cover in whole or in part certain environmental expenditures. We had no environmental matters requiring specific disclosure or requiring the recognition of a liability as of December 31, 2017, 2016 and 2015. |
Issuances of Units
Issuances of Units | 12 Months Ended |
Dec. 31, 2017 | |
Proceeds From Issuance Or Sale Of Equity [Abstract] | |
Issuances of Units | NOTE 10—ISSUANCES OF UNITS We recognize gains or losses on AGP’s equity transactions as credits or debits, respectively, to unitholders’ equity on our combined consolidated balance sheets rather than as income or loss on our combined consolidated statements of operations. These gains or losses represent our portion of the excess or the shortage of the net offering price per unit of each of AGP’s common units as compared to the book carrying amount per unit. In connection with the Second Lien Credit Agreement, on April 27, 2016, we issued to the Lenders, warrants (the “Warrants”) to purchase up to 4,668,044 common units representing limited partner interests at an exercise price of $0.20 per unit. The Warrants expire on March 30, 2026 and are subject to customary anti-dilution provisions. On April 27, 2016, we entered into a registration rights agreement pursuant to which we agreed to register the offer and resale of our common units underlying the Warrants as well as any common units issued as in-kind interest payments under the Second Lien Credit Agreement. The Warrants include a cashless exercise provision entitling the Lenders to surrender a portion of the underlying common units that has a value equal to the aggregate exercise price in lieu of paying cash upon exercise of a warrant. As a result of issuance of the Warrants, we recognized a $1.9 million debt discount on the Second Lien Credit Agreement, which will be amortized over the term of the debt, and a corresponding $1.9 million increase to unitholders’ equity – warrants on our combined balance sheet as of December 31, 2016. On May 5, 2017, the holders of all 1.9 million of our outstanding Series A Preferred Units elected to convert their units into 5.9 million common units. On January 7, 2016, we were notified by the NYSE that we were not in compliance with NYSE’s continued listing criteria under Section 802.01C of the NYSE Listed Company Manual because the average closing price of our common units had been less than $1.00 for 30 consecutive trading days. We also were notified by the NYSE on December 23, 2015, that we were not in compliance with the NYSE’s continued listing criteria under Section 802.01B of the NYSE Listed Company Manual because our average market capitalization had been less than $50 million for 30 consecutive trading days and our stockholders’ equity had been less than $50 million. On March 18, 2016, we were notified by the NYSE that it determined to commence proceedings to delist our common units from the NYSE as a result of our failure to comply with the continued listing standard set forth in Section 802.01B of the NYSE Listed Company Manual to maintain an average global market capitalization over a consecutive 30 trading-day period of at least $15 million. The NYSE also suspended the trading of our common units at the close of trading on March 18, 2016. Our common units began trading on the OTCQB on March 21, 2016 under the ticker symbol: ATLS. On August 26, 2015, at a special meeting of our unitholders, the unitholders approved changes to the terms of the Series A Preferred Units to provide that each Series A Preferred Unit will be convertible into common units at the option of the holder. On February 27, 2015, we issued and sold an aggregate of 1.6 million of Series A convertible preferred units, with a liquidation preference of $25.00 per unit (the “Series A Preferred Units”), at a purchase price of $25.00 per unit to certain members of our management, two management members of the Board, and outside investors. Holders of the Series A Preferred Units are entitled to monthly distributions of cash at a rate equal to the greater of (i) 10% of the liquidation preference per annum, increasing to 12% per annum, 14% per annum and 16% per annum on the first, second and third anniversaries of the of the private placement, respectively, or (ii) the monthly equivalent of any cash distribution declared by us to holders of our common units, as well as Series A Preferred Units at a rate equal to 2% of the liquidation preference per annum. All or a portion of the Series A Preferred Units were convertible into our units at the option of the holder at any time following the later of (i) the one-year anniversary of the distribution and (ii) prior to August 26, 2015, receipt of unitholder approval. The conversion price will be equal to the greater of (i) $8.00 per common unit; and (ii) the lower of (a) 110.0% of the volume weighted average price for our common units over the 30 trading days following the distribution date; and (b) $16.00 per common unit. We sold the Series A Preferred Units in a private transaction exempt from registration under Section 4(a)(2) of the Securities Act. The Series A Preferred Units resulted in proceeds to us of $40.0 million. We used the proceeds to fund a portion of the $150.0 million payment by us to Atlas Energy related to the repayment of Atlas Energy’s term loan (see Note 5). The Series A Purchase Agreement contains customary terms for private placements, including representations, warranties, covenants and indemnities. Atlas Resource Partners On July 12, 2016, ARP received notification from the New York Stock Exchange that the NYSE commenced proceedings to delist ARP’s common units as a result of ARP’s failure to comply with the continued listed standards set forth in Section 802.01C of the NYSE Listed Company Manual to maintain an average closing price of $1.00 per unit over a consecutive 30 day period. The Class D ARP Preferred Units and Class E ARP Preferred Units were also delisted from the NYSE. ARP’s common units, Class D ARP Preferred Units, and Class E ARP Preferred Units began trading on the OTCQX market on July 13, 2016 with the ticker symbol “ARPJ” for ARP’s common units, “ARPJP” for Class D ARP Preferred Units, and “ARPJN” for Class E ARP Preferred Units. ARP had an equity distribution agreement with Deutsche Bank Securities Inc., as representative of the several banks named therein (the “Agents”). Pursuant to the equity distribution agreement, ARP sold from time to time through the Agents common units representing limited partner interests of ARP having an aggregate offering price of up to $100.0 million. Sales of common units, if any, were made in negotiated transactions or transactions that are deemed to be “at-the-market” offerings as defined in Rule 415 of the Securities Act, including sales made directly on the New York Stock Exchange, the former trading market for the common units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. ARP paid each of the Agents a commission, which in each case was not be more than 2.0% of the gross sales price of common units sold through such Agent. Under the terms of the equity distribution agreement, ARP sold common units from time to time to any Agent as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to an Agent as principal was pursuant to the terms of a separate agreement between ARP and such Agent. During the year ended December 31, 2016, ARP issued 245,175 common limited partner units under the equity distribution program for net proceeds of $0.2 million, net of $4,000 in commissions and offering expenses paid. During the year ended December 31, 2015, ARP issued 9,803,451 common limited partner units under the equity distribution agreement for net proceeds of $44.2 million, net of $1.1 million in commissions and offering expenses paid. In August 2015, ARP entered into a distribution agreement with MLV & Co. LLC (“MLV”) which ARP terminated and replaced in November 2015, when ARP entered into a distribution agreement with MLV and FBR Capital Markets & Co. pursuant to which ARP sold its 8.625% Class D Cumulative Redeemable Perpetual Preferred Units (“Class D ARP Preferred Units”) and 10.75% Class E Cumulative Redeemable Perpetual Preferred Units (“Class E ARP Preferred Units”). ARP did not issue any Class D Preferred Units nor Class E Preferred Units under the August 2015 and November 2015 preferred equity distribution programs for the period ended July 27, 2016. During the year ended December 31, 2015, ARP issued 90,328 Class D ARP Preferred Units and 1,083 Class E ARP Preferred Units under its preferred equity distribution program for net proceeds of $0.9 million, net of $0.3 million in commissions and offering expenses paid. Under the November 2015 ATM Agreement, our Predecessor did not issue any Class D Preferred Units nor Class E Preferred Units under the preferred equity distribution program, but incurred $0.1 million of net offering expenses. In May 2015, in connection with the Arkoma Acquisition, ARP issued 6,500,000 of its common limited partner units in a public offering at a price of $7.97 per unit, yielding net proceeds of $49.7 million. ARP used a portion of the net proceeds to fund the Arkoma Acquisition and to reduce borrowings outstanding under ARP’s First Lien Credit Facility. In April 2015, ARP issued 255,000 of its 10.75% Class E ARP Preferred Units at a public offering price of $25.00 per unit for net proceeds of $6.0 million. On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2). Atlas Growth Partners On November 2, 2016, AGP decided to temporarily suspend its current primary offering efforts in light of new regulations and the challenging fund raising environment until such time as market participants have had an opportunity to ascertain the impact of such issues. As a result of AGP’s decision to temporarily suspend its current primary offering efforts (see Note 2), AGP reclassified $5.3 million of offering costs to other loss on our consolidated statement of operations for the year ended December 31, 2016. These offering costs were previously capitalized within noncontrolling interest on our consolidated balance sheet as an offset to any proceeds raised in AGP’s current primary offering and include $1.5 million that were previously capitalized within noncontrolling interest on our consolidated balance sheet as of December 31, 2015. Private Placement Offering . Under the terms of AGP’s initial offering, AGP offered in a private placement $500.0 million of its common limited partner units. The termination date of the private placement offering was December 31, 2014, subject to two 90 day extensions to the extent that it had not sold $500.0 million of common units at any extension date. AGP exercised each of such extensions. Under the terms of the offering, an investor received, for no additional consideration, warrants to purchase additional common units in an amount equal to 10% of the common units purchased by such investor. The warrants are exercisable at a price of $10.00 per common unit being purchased and may be exercised from and after the warrant date (generally, the date upon which AGP gives the holder notice of a liquidity event) until the expiration date (generally, the date that is one day prior to the liquidity event or, if the liquidity event is a listing on a national securities exchange, 30 days after the liquidity event occurs). Under the warrant, a liquidity event is defined as either (i) a listing of the common units on a national securities exchange, (ii) a business combination with or into an existing publicly-traded entity, or (iii) a sale of all or substantially all of AGP’s assets. Through the completion of AGP’s private placement offering on June 30, 2015, AGP issued $233.0 million, or 23,300,410 of its common limited partner units, in exchange for proceeds to AGP, net of dealer manager fees and commissions and expenses, of $203.4 million. We purchased 500,010 common units for $5.0 million during the offering. In connection with the issuance of common limited partner units, unitholders received 2,330,041 warrants to purchase AGP’s common units at an exercise price of $10.00 per unit. During the year ended December 31, 2015, AGP sold an aggregate of 12,623,500 of its common limited partner units at a gross offering price of $10.00 per unit. Of such amount, we purchased $2.7 million, or 300,000 common units, during the year ended December 31, 2015. In connection with the issuance of its common limited partner units, unitholders received 1,262,350 warrants to purchase its common limited partner units at an exercise price of $10.00 per unit. In connection with the issuance of ARP’s unit offerings during the year ended December 31, 2016, we recorded gains of $0.2 million within unitholders’ equity and a corresponding decrease in non-controlling interests on our combined consolidated balance sheet and combined consolidated statement of unitholders’ equity. |
Cash Distributions
Cash Distributions | 12 Months Ended |
Dec. 31, 2017 | |
Distributions Made To Members Or Limited Partners [Abstract] | |
Cash Distributions | NOTE 11—CASH DISTRIBUTIONS Our Cash Distributions . We have a cash distribution policy under which we distribute, within 50 days following the end of each calendar quarter, all of our available cash (as defined in our limited liability company agreement) for that quarter to our unitholders. However, as a result of the First Lien Credit Agreement and Second Lien Credit Agreement entered into on March 30, 2016 (see Note 5), we are prohibited from paying cash distributions on our units. Prior to these amendments, during the year ended December 31, 2016, we paid a distribution of $1.0 million to Class A preferred unitholders. During the year ended December 31, 2015, we paid a distribution of $2.7 million to Class A preferred unitholders. ARP Cash Distributions . ARP had a monthly cash distribution program whereby ARP distributed all of its available cash (as defined in the partnership agreement) for that month to its unitholders within 45 days from the month end. If ARP’s common unit distributions in any quarter exceeded specified target levels, we received between 13% and 48% of such distributions in excess of the specified target levels. While outstanding, the Class B ARP Preferred Units received regular quarterly cash distributions equal to the greater of (i) $0.40 (or $0.1333 per unit paid on a monthly basis) and (ii) the quarterly common unit distribution. In July 2015, the remaining 39,654 Class B Preferred Units were converted into ARP common limited partner units. The Class C ARP Preferred Units received regular quarterly cash distributions equal to the greater of (i) $0.51 (or $0.17 per unit paid on a monthly basis) and (ii) the quarterly common unit distribution. On May 5, 2016, ARP’s Board of Directors elected to suspend ARP’s common unit and Class C preferred distributions, beginning with the month of March of 2016, due to the continued lower commodity price environment. ARP paid quarterly distributions on its Class D ARP Preferred Units at an annual rate of $2.15625 per unit, $0.5390625 per unit paid on a quarterly basis, or 8.625% of the $25.00 liquidation preference. ARP paid quarterly distributions on its Class E ARP Preferred Units at an annual rate of $2.6875 per unit, or $0.671875 per unit on a quarterly basis, or 10.75% of the $25.00 liquidation preference. On June 16, 2016, ARP’s Board of Directors elected to suspend the distributions on the Class D ARP Preferred Units and the Class E ARP Preferred Units, beginning with the second quarter 2016 distribution, due to the continued lower commodity price environment. The Class D ARP Preferred Units and Class E ARP Preferred Units accrued distributions of $3.4 million and $0.3 million, respectively, from April 15, 2016 through August 31, 2016. However, due to the distribution suspension and ARP’s Chapter 11 Filings, these amounts were not earned as the preferred units were cancelled without receipt of any consideration on the Plan Effective Date. During the year ended December 31, 2016, ARP paid four monthly cash distributions totaling $5.1 million to common limited partners ($0.0125 per unit per month); $2.5 million to Preferred Class C limited partners ($0.0125 per unit per month); and $0.2 million to the General Partner Class A holder ($0.0125 per unit per month). During the year ended December 31, 2015, ARP paid twelve monthly cash distributions totaling $126.3 million to common limited partners ($0.1966 per unit in both January and February 2015, $0.1083 per unit in March through November 2015 and $0.0125 per unit in December 2015); $7.8 million to Preferred Class C limited partners ($0.1966 per unit in both January and February 2015 and $0.17 per unit in March through December 2015); approximately $42,000 to Preferred Class B limited partners ($0.1966 per unit in both January and February 2015 and $0.1333 per unit in March through July 2015); and $4.8 million to the General Partner Class A holder ($0.1966 per unit in both January and February 2015, $0.1083 per unit in March through November 2015 and $0.0125 per unit in December 2015). During the year ended December 31, 2016, ARP paid two distributions totaling $4.4 million to Class D Preferred Units ($0.5390625 per unit) for the period October 15, 2015 through April 14, 2016. During the year ended December 31, 2015, ARP paid three distributions totaling $8.5 million to Class D Preferred Units ($0.6169270 per unit for the period October 2, 2014 through January 14, 2015 and $0.539063 per unit for the period January 15, 2015 through October 14, 2015). During the year ended December 31, 2016, ARP paid two distributions totaling $0.3 million to Class E Preferred Units ($0.671875 per unit) for the period October 15, 2015 through April 14, 2016. During the year ended December 31, 2015, ARP paid two $0.3 million distribution to Class E Preferred Units ($0.6793 per unit) for the period April 14, 2015 through October 14, 2015. On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2). AGP Cash Distributions. AGP has a cash distribution policy under which it distributes to holders of common units and Class A units on a quarterly basis a distribution of $0.175 per unit, or $0.70 per unit per year, to the extent AGP has sufficient available cash after establishing appropriate reserves and paying fees and expenses, including reimbursements of expenses to the general partner and its affiliates. Distributions are generally paid within 45 days of the end of the quarter to unitholders of record on the applicable record date. Unitholders are entitled to receive distributions from AGP beginning with the quarter following the quarter in which AGP first admits them as limited partners. On November 2, 2016, AGP’s Board of Directors determined to suspend its quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order to retain its cash flow and reinvest in its business and assets. During the year ended December 31, 2016, AGP paid distributions of $12.2 million to common limited partners ($0.1750 per unit per quarter for the distributions paid from January 1, 2016 through June 30, 2016) and $0.3 million to the general partner’s Class A units ($0.1750 per unit per quarter for the distributions paid from January 1, 2016 through June 30, 2016). During the year ended December 31, 2015, AGP paid a distribution of $10.5 million to common limited partners ($0.1750 per unit per quarter) and $0.2 million to the general partner’s Class A units ($0.1750 per unit per quarter). |
Share Based Compensation Plans
Share Based Compensation Plans | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Share Based Compensation Plans | NOTE 12— SHARE BASED COMPENSATION PLANS 2015 Long-Term Incentive Plan Our Board of Directors approved and adopted the 2015 Long-Term Incentive Plan (“2015 LTIP”) effective February 2015. The 2015 LTIP provides equity incentive awards to our officers, employees and managing board members and our affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for us. The 2015 LTIP is administered by a committee consisting of the Board of Directors or committee of the Board of Directors or board of an affiliate appointed by the Board of Directors (the “LTIP Committee”). Under the 2015 LTIP, the LTIP Committee may grant awards of phantom units, restricted units or unit options for an aggregate of 5,250,000 units. At December 31, 2017, we had 2,855,152 phantom units and unit options outstanding under the 2015 LTIP, with 2,043,796 phantom units and unit options available for grant. Share based payments to non-employee directors, which have a cash settlement option, are recognized within liabilities in the consolidated financial statements based upon their current fair market value. In the case of awards held by eligible employees, following a “change in control”, as defined in the 2015 LTIP, upon the eligible employee’s termination of employment without “cause”, as defined in the 2015 LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the option. Upon a change in control, all unvested awards held by directors will immediately vest in full. In connection with a change in control, the LTIP Committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any Participant, subject to the terms of any award agreements and employment agreements to which we (or any affiliate) and any Participant are party, may take one or more of the following actions (with discretion to differentiate between individual Participants and awards for any reason): • cause awards to be assumed or substituted by the surviving entity (or a parent, subsidiary or affiliate of such surviving entity); • accelerate the vesting of awards as of immediately prior to the consummation of the transaction that constitutes the change in control so that awards shall vest (and, with respect to options, become exercisable) as to the units that otherwise would have been unvested so that Participants (as holders of awards granted under the new equity plan) may participate in the transaction; • provide for the payment of cash or other consideration to Participants in exchange for the cancellation of outstanding awards (in an amount equal to the fair market value of such cancelled awards); • terminate all or some awards upon the consummation of the change-in-control transaction, but only if the LTIP Committee provides for full vesting of awards immediately prior to the consummation of such transaction; and • make such other modifications, adjustments or amendments to outstanding awards as the LTIP Committee deems necessary or appropriate. 2015 Phantom Units. A phantom unit entitles a Participant to receive a common unit or its then-fair market value in cash or other securities or property, upon vesting of the phantom unit. In tandem with phantom unit grants, the LTIP Committee may grant Distribution Equivalent Rights (“DERs”), which are the right to receive cash, securities, or property per phantom unit in an amount equal to, and at the same time as, the cash distributions or other distributions of securities or property we make on a common unit during the period such phantom unit is outstanding. Of the phantom units outstanding under the 2015 LTIP at December 31, 2017, there were 2,379,564 units that will vest within the following twelve months. The director phantom units outstanding under the 2015 LTIP at December 31, 2017 include DERs. No amounts were paid during the years ended December 31, 2017, 2016 and 2015 with respect to DERs. On February 20, 2017, our Board of Directors authorized the deferral until March 1, 2018 of the vesting of all phantom units granted to officers and employees under the 2015 LTIP that had previously been scheduled to vest during 2017. As consideration for the deferral, we made a deferred vesting payment to all employees (including the officers) equal to approximately 25% of the value of affected phantom units. On May 12, 2016, due to the income tax ramifications of potential options we were considering, the Board of Directors delayed the vesting of approximately 911,900 units granted, under our long-term incentive plan, to employees, directors and officers, until March 2017. The phantom units were set to vest between June 8, 2016 and September 1, 2016. The delayed vesting schedule did not have a significant impact on the compensation expense recorded in general and administrative expenses on our combined consolidated statement of operations for the years ended December 31, 2017 and 2016 or our remaining unrecognized compensation expense related to such awards. The following table sets forth the 2015 LTIP phantom unit activity for the periods indicated: Years Ended December 31, 2017 2016 2015 Number of Units Weighted Average Grant Date Fair Value Number of Units Weighted Average Grant Date Fair Value Number of Units Weighted Average Grant Date Fair Value Outstanding, beginning of year 3,995,214 $ 3.99 2,564,910 $ 6.46 — $ — Granted — — 2,110,000 1.53 2,794,710 6.46 Vested (1) (317,226 ) 1.24 (33,826 ) 6.97 — — Forfeited (822,836 ) 4.54 (645,870 ) 5.58 (229,800 ) 6.43 Outstanding, end of year (2)(3) 2,855,152 $ 4.14 3,995,214 $ 3.99 2,564,910 $ 6.46 Non-cash compensation expense (reversal) recognized (in thousands) $ (135 ) $ 4,984 $ 5,678 (1) The intrinsic value of phantom awards vested during the years ended December 31, 2017 and 2016 was approximately $0.2 million and $31,000. No phantom unit awards vested during the years ended December 31, 2015. (2) The aggregate intrinsic value of phantom unit awards outstanding at December 31, 2017 was $0.1 million. (3) There was approximately $1,000 recognized as liabilities on our consolidated balance sheet at December 31, 2017 representing 22,972 units, due to the option of the Participants to settle in cash instead of units. The respective weighted average grant date fair value for these units was $9.07 at December 31, 2017. At December 31, 2017, we had approximately $1.3 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2015 LTIP based upon the fair value of the awards which is expected to be recognized over a weighted average period of 0.9 years. 2015 Unit Options. A unit option entitles a Participant to receive our common unit upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option shall not be less than the fair market value of our common unit on the date of grant of the option. The LTIP Committee also determines how the exercise price may be paid by the Participant. The LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Generally, unit options to be granted under the 2015 LTIP will vest over a designated period of time. There are no unit options outstanding under the 2015 LTIP at December 31, 2017. No cash was received from the exercise of options for the years ended December 31, 2017, 2016 and 2015. Restricted Units Restricted units are actual common units issued to a Participant that are subject to vesting restrictions and evidenced in such manner as the LTIP Committee may deem appropriate, including book-entry registration or issuance of one or more unit certificates. Prior to or upon the grant of an award of restricted units, the LTIP Committee will condition the vesting or transferability of the restricted units upon continued service, the attainment of performance goals or both. A holder of restricted units will have certain rights of holders of common units in general, including the right to vote the restricted units. However, during the period in which the restricted units are subject to vesting restrictions, the holder will not be permitted to sell, assign, transfer, pledge or otherwise encumber the restricted units. There were no restricted units granted, issued or outstanding through December 31, 2017. ARP’s 2012 Long-Term Incentive Plan ARP’s 2012 Long-Term Incentive Plan (“2012 ARP LTIP”), effective March 2012, provided incentive awards to officers, employees and directors and employees of ARP’s general partner and its affiliates, consultants and joint venture partners (collectively, the “ARP Participants”), who performed services for ARP. The 2012 ARP LTIP was administered by the board of ARP’s general partner, a committee of the board or the board (or committee of the board) of an affiliate (the “ARP LTIP Committee”). Under the 2012 ARP LTIP, the ARP LTIP Committee granted awards of phantom units, restricted units or unit options. ARP’s 2012 ARP LTIP Phantom Units Phantom units represented rights to receive a common unit, an amount of cash or other securities or property based on the value of a common unit, or a combination of common units and cash or other securities or property upon vesting. Phantom units were subject to terms and conditions determined by the ARP LTIP Committee, which included vesting restrictions. In tandem with phantom unit grants, the ARP LTIP Committee granted DERs, which were the right to receive an amount in cash, securities, or other property equal to, and at the same time as, the cash distributions or other distributions of securities or other property made by ARP with respect to a common unit during the period that the underlying phantom unit was outstanding. During the period from January 1, 2016 through the date of ARP’s Chapter 11 Filings and the year ended December 31, 2015, ARP paid approximately $15,000 and $0.7 million, respectively, with respect to the 2012 ARP LTIP’s DERs. These amounts were recorded as reductions of the non-controlling interest portion of equity on our combined consolidated balance sheets. For the year ended December 31, 2015, the 2012 ARP LTIP phantom unit activity was as follows: Outstanding beginning of year: 799,192; Granted: 9,730; Vested: 472,278; Forfeited: 34,539; Outstanding end of year: 302,105. For the period from January 1, 2016 through the date of ARP’s Chapter 11 Filings, the 2012 ARP LTIP phantom unit activity was as follows: Outstanding beginning of period: 302,105; Granted: 30,000; Vested: 24,679; Forfeited: 60,639; Outstanding end of period: 246,787. On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2). During the years ended December 31, 2016 and 2015, we recognized 2012 ARP LTIP unit based compensation expense for phantom units of $0.3 million and $4.1 million, respectively, which was recorded in general and administrative expenses on our combined consolidated statements of operations. ARP’s 2012 ARP LTIP Unit Options A unit option was the right to purchase ARP’s common unit in the future at a predetermined price (the exercise price). The exercise price of each option was determined by the ARP LTIP Committee and may be equal to or greater than the fair market value of a common unit on the date the option was granted. The ARP LTIP Committee determined the vesting and exercise restrictions applicable to an award of options, if any, and the method by which the exercise price may be paid by the ARP Participant. Unit option awards expired 10 years from the date of grant. For the year ended December 31, 2015, the 2012 ARP LTIP unit option activity was as follows: Outstanding beginning of year: 1,458,300; Granted: none; Exercised: none; Forfeited: 103,775; Outstanding end of year: 1,354,525. For the period from January 1, 2016 through the date of ARP’s Chapter 11 Filings, the 2012 ARP LTIP unit option activity was as follows: Outstanding beginning of period: 1,354,525; Granted: none; Exercised: none; Forfeited: 40,689; Outstanding end of period: 1,313,836. On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2). During the years ended December 31, 2016 and 2015, we recognized 2012 ARP LTIP unit based compensation expense for unit options of approximately $31,000 and $0.8 million, respectively, which was recorded in general and administrative expenses on our combined consolidated statements of operations. ARP’s 2012 ARP LTIP Restricted Units Restricted units were actual common units to be issued to an ARP Participant that were subject to vesting restrictions and evidenced in such manner as the ARP LTIP Committee deemed appropriate, including book-entry registration or issuance of one or more unit certificates. Prior to or upon the grant of an award of restricted units, the ARP LTIP Committee would condition the vesting or transferability of the restricted units upon continued service, the attainment of performance goals or both. During the period from January 1, 2016 through the date of ARP’s Chapter 11 Filings and the year ended December 31, 2015, ARP had no restricted units granted or outstanding. On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2) |
Operating Segment Information
Operating Segment Information | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting [Abstract] | |
Operating Segment Information | NOTE 13—OPERATING SEGMENT INFORMATION Our operations included three reportable operating segments: ARP (through the date of the Chapter 11 Filings), AGP, and corporate and other. These operating segments reflected the way we managed our operations and made business decisions. Corporate and other includes our equity investments in Lightfoot (see Note 2) and Titan (see Note 2), as well as our general and administrative and interest expenses. Operating segment data for the periods indicated were as follows (in thousands): Years Ended December 31, 2017 2016 2015 Atlas Resource Partners: Revenues (1) $ — $ 125,582 $ 740,033 Operating costs and expenses — (134,718 ) (320,922 ) Depreciation, depletion and amortization expense — (67,513 ) (157,978 ) Asset impairment — — (966,635 ) Interest expense — (68,883 ) (102,133 ) Gain on early extinguishment of debt — 26,498 — Reorganization items, net — (21,649 ) — Other income (loss) — (6,625 ) (1,181 ) Segment loss $ — $ (147,308 ) $ (808,816 ) Atlas Growth Partners: Revenues (1) $ 8,151 $ 11,071 $ 12,708 Operating costs and expenses (7,472 ) (12,578 ) (14,968 ) Depreciation, depletion and amortization expense (3,576 ) (14,868 ) (8,951 ) Asset impairment — (41,879 ) (7,346 ) Other loss — (5,383 ) — Segment loss $ (2,897 ) $ (63,637 ) $ (18,557 ) Corporate and other: Revenues $ 900 $ 505 $ 752 General and administrative (2) (534 ) (5,528 ) (30,862 ) Interest expense (20,937 ) (14,861 ) (23,525 ) Other income 6,855 — — Loss on early extinguishment of debt — (6,080 ) (4,726 ) Gain on deconsolidation of Atlas Resource Partners, L.P. — 46,951 — Segment income (loss) $ (13,716 ) $ 20,987 $ (58,361 ) Reconciliation of segment income (loss) to net loss: Segment income (loss): Atlas Resource Partners $ — $ (147,308 ) $ (808,816 ) Atlas Growth Partners (2,897 ) (63,637 ) (18,557 ) Corporate and other (13,716 ) 20,987 (58,361 ) Net loss $ (16,613 ) $ (189,958 ) $ (885,734 ) Reconciliation of segment revenues to total revenues: Segment revenues: Atlas Resource Partners (1) $ — $ 125,582 $ 740,033 Atlas Growth Partners (1) 8,151 11,071 12,708 Corporate and other 900 505 752 Total revenues $ 9,051 $ 137,158 $ 753,493 Capital expenditures: Atlas Resource Partners $ — $ 21,155 $ 127,138 Atlas Growth Partners — 6,602 29,222 Total capital expenditures $ — $ 27,757 $ 156,360 December 31, 2017 2016 Balance sheet: Total assets: Atlas Growth Partners $ 74,219 $ 78,500 Corporate and other 9,829 26,576 Total assets $ 84,048 $ 105,076 1) Revenues include respective portions of gains (losses) on mark—to—market derivatives. 2) As disclosed in Note 12, for the year ended December, 31, 2017, 822,836 phantom units under the 2015 LTIP were forfeited, primarily due to Titan’s completion of the majority of the sale of its Appalachian assets and reductions in workforce, which resulted in a $2.5 million reversal of previously recognized stock compensation expense recorded in general and administrative expenses on our combined consolidated statements of operations for the year ended December 31, 2017. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2017 | |
Subsequent Events [Abstract] | |
Subsequent Events | NOTE 14—SUBSEQUENT EVENTS Credit Agreement Amendment. On April 26, 2018, we entered into an additional agreement with our lenders to extend the maturity date of our first lien credit agreement to June 30, 2018 (se e Note 5). |
Supplemental Oil and Gas Inform
Supplemental Oil and Gas Information (Unaudited) | 12 Months Ended |
Dec. 31, 2017 | |
Oil And Gas Exploration And Production Industries Disclosures [Abstract] | |
Supplemental Oil and Gas Information (Unaudited) | NOTE 15—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) Oil, Gas and NGL Reserve Information . The preparation of the our natural gas, oil and NGL reserve estimates was completed in accordance with the prescribed internal control procedures by our reserve engineers. Wright & Company, Inc., an independent third-party reserve engineer, was retained to prepare a report of proved reserves related to us. The independent reserve engineer’s evaluation was based on more than 40 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. Our internal control procedures include verification of input data delivered to our third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our Director of Reservoir Engineering, who is a member of the Society of Petroleum Engineers and has more than 18 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by our senior engineering staff and management, with final approval by the Executive Vice President of Operations. The reserve disclosures that follow reflect our estimates of proved reserves, proved developed reserves and proved undeveloped reserves, net of royalty interests, of natural gas, crude oil and NGLs owned at year end and changes in proved reserves during the last three years. Proved oil, gas and NGL reserves are those quantities of oil, gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved developed reserves are those reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for undeveloped reserves cannot be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. The proved reserves quantities and future net cash flows were estimated using an unweighted 12-month average pricing based on the prices on the first day of each month during the years ended December 31, 2017, 2016 and 2015, including adjustments related to regional price differentials and energy content. There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of our oil and gas reserves or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil and gas prices and in production and development costs and other factors, for their effects have not been proved. Reserve quantity information and a reconciliation of changes in our proved reserve quantities are as follows: Gas (MMcf) Oil (MBbls) NGLs (MBbls) Total (MMcfe) Balance, January 1, 2015 1,064,878 62,950 23,380 1,582,858 Extensions, discoveries and other additions (1) 6,806 3,460 293 29,324 Sales of reserves in-place (2,714 ) (2 ) — (2,726 ) Purchase of reserves in-place — — — — Transfers to Drilling Partnerships (2,959 ) (482 ) (342 ) (7,903 ) Revisions of previous estimates (2) (379,058 ) (11,224 ) (13,770 ) (529,022 ) Production (79,267 ) (2,119 ) (1,085 ) (98,491 ) Balance, December 31, 2015 607,686 52,583 8,476 974,040 Extensions, discoveries and other additions 789 135 — 1,599 Sales of reserves in-place (3) (530,817 ) (37,926 ) (6,030 ) (794,553 ) Purchase of reserves in-place 1,616 13 — 1,694 Transfers to Drilling Partnerships — — — — Revisions of previous estimates (2) (37,822 ) (10,227 ) (1,726 ) (109,540 ) Production (40,020 ) (1,191 ) (453 ) (49,884 ) Balance, December 31, 2016 1,432 3,387 267 23,356 Extensions, discoveries and other additions — — — — Sales of reserves in-place — — — — Purchase of reserves in-place — — — — Transfers to Drilling Partnerships — — — — Revisions of previous estimates (2) 548 1,231 169 8,949 Production (114 ) (143 ) (20 ) (1,092 ) Balance, December 31, 2017 1,866 4,475 416 31,213 Proved developed reserves at: January 1, 2015 889,074 31,151 12,210 1,149,240 December 31, 2015 568,794 27,130 6,489 770,508 December 31, 2016 652 925 100 6,802 December 31, 2017 613 788 121 6,069 Proved undeveloped reserves at: January 1, 2015 175,804 31,799 11,170 433,618 December 31, 2015 38,892 25,453 1,987 203,532 December 31, 2016 780 2,462 167 16,554 December 31, 2017 1,253 3,687 295 25,144 (1) For the year ended December 31, 2015, the increase represents PUD additions related to our development and leasing activity in the Eagle Ford Shale. (2) See “ Revisions of Previous Estimates (3) For the year ended December 31, 2016, the decrease was due to the deconsolidation of ARP for financial reporting purposes in connection with ARP’s Chapter 11 Filings (see Note 2). Revisions of Previous Estimates The following represents the unweighted average of the first-day-of-the-month prices for each of the previous twelve months from the periods presented above: December 31, 2017 2016 2015 Unadjusted Prices Natural gas (per MMBtu) $ 2.98 $ 2.48 $ 2.59 Oil (per Bbl) $ 51.34 $ 42.75 $ 50.28 Natural gas liquids (per Bbl) $ 20.33 $ 19.57 $ 11.02 For the year ended December 31, 2017 we had positive revisions of 8,585 MMcfe due to modifications in our Eagle Ford development plan, focusing on longer lateral lengths, and 1,208 MMcfe due to increases in pricing, partially offset by negative revision of 844 MMcfe due to our production underperforming previous year’s forecast. For the year ended December 31, 2016 we had negative revisions of 58,818 MMcfe due to decreases in pricing and 60,860 MMcfe due to the removal of proved undeveloped properties that became uneconomic due to pricing, partially offset by positive revision of 10,133 MMcfe due to our production outperforming the comparable period’s forecast. For the year ended December 31, 2015, we had negative revisions of 258,667 MMcfe due to decreases in pricing, 223,551 MMcfe due to the removal of proved undeveloped properties that became uneconomic due to pricing and 46,804 MMcfe due to production underperforming previous year’s forecast. Capitalized Costs Related to Oil and Gas Producing Activities . The components of capitalized costs related to oil and gas producing activities as of the periods indicated were as follows (in thousands): December 31, 2017 2016 Natural gas and oil properties: Proved properties $ 147,932 $ 84,631 Unproved properties (1) — 63,314 Support equipment 29 29 147,961 147,974 Accumulated depreciation, depletion and amortization (85,328 ) (81,901 ) Net capitalized costs $ 62,633 $ 66,073 (1) As of December 31, 2017, we classified $4.2 million of AGP’s unproved properties to proved natural gas and oil properties as management finalized capital plans for drilling and developing one well within our Eagle Ford operating area in 2018. Results of Operations from Oil and Gas Producing Activities . The results of operations related to our oil and gas producing activities during the periods indicated were as follows (in thousands): Years Ended December 31, 2017 2016 2015 Revenues $ 7,841 $ 129,993 $ 368,845 Production costs (2,528 ) (78,034 ) (171,882 ) Depreciation, depletion and amortization (3,410 ) (79,013 ) (153,938 ) Asset impairment (1) — (41,879 ) (973,981 ) $ 1,903 $ (68,933 ) $ (930,956 ) (1) For the year ended December 31, 2016, we recognized $25.4 million and $16.5 million of asset impairment related to AGP’s proved and unproved oil and gas properties in the Eagle Ford operating area, respectively, which were impaired due to lower forecasted commodity prices and timing of capital financing and deployment for the development of our undeveloped properties. During the year ended December 31, 2015, we recognized $974 million of asset impairment of which $960 million related to ARP’s proved oil and gas properties in the Barnett, Coal-bed Methane, Rangely, Southern Appalachia, Marcellus and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices, net of $85.8 million of future hedge gains reclassified from accumulated other comprehensive income, $6.6 million of asset impairments in ARP’s unproved gas and oil properties primarily related to ARP’s unproved acreage in the New Albany Shale, which was impaired due to expiring acreage and no intention to pursue development, and $7.4 million related to AGP’s proved oil and gas properties in the Marble Falls and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices. Costs Incurred in Oil and Gas Producing Activities. The costs incurred in our oil and gas activities during the periods indicated are as follows (in thousands): Years Ended December 31, 2017 2016 2015 Property acquisition costs: Proved properties $ — $ 2,207 $ 55,033 Unproved properties — — 43,820 Exploration costs (1) — 825 1,601 Development costs — 16,792 102,110 Total costs incurred in oil & gas producing activities $ — $ 19,824 $ 202,564 (1) There were no exploratory wells drilled during the periods presented. Standardized Measure of Discounted Future Cash Flows . The following schedule presents the standardized measure of estimated discounted future net cash flows relating to our proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2017, 2016 and 2015, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels and include the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations (in thousands): Years Ended December 31, 2017 2016 2015 Future cash inflows $ 243,644 $ 145,857 $ 3,910,339 Future production costs (73,792 ) (53,738 ) (1,954,564 ) Future development costs (68,321 ) (51,942 ) (1,289,841 ) Future net cash flows 101,531 40,177 665,934 Less 10% annual discount for estimated timing of cash flows (61,082 ) (22,796 ) (90,703 ) Standardized measure of discounted future net cash flows $ 40,449 $ 17,381 $ 575,231 Changes in Standardized Discounted Future Cash Flows. The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved oil, gas and NGL reserves (in thousands), including amounts related to asset retirement obligations. Since AGP and ARP allocate taxable income to their respective owners, no recognition has been given to income taxes: Years Ended December 31, 2017 2016 2015 Balance, beginning of year $ 17,381 $ 575,231 $ 2,236,764 Increase (decrease) in discounted future net cash flows: (1) Sales and transfers of oil and gas, net of related costs (5,403 ) (59,246 ) (137,942 ) Net changes in prices and production costs 22,401 (226,641 ) (1,629,945 ) Revisions of previous quantity estimates 15,568 (32,208 ) (41,147 ) Development costs incurred — — 88,261 Changes in future development costs (11,236 ) 6,914 (167,995 ) Transfers to Drilling Partnerships — — (13,291 ) Extensions, discoveries, and improved recovery less related costs — (50 ) 20,408 Purchases of reserves in-place — 711 — Sales of reserves in-place — (297,227 ) (2,162 ) Accretion of discount 1,738 51,238 223,676 Estimated settlement of asset retirement obligations — (1,332 ) (224 ) Estimated proceeds on disposals of well equipment — (9 ) (1,172 ) Changes in production rates (timing) and other — — — Outstanding, end of year $ 40,449 $ 17,381 $ 575,231 (1) See “ Reserve Quantity Information Revisions of Previous Estimates |
Quarterly Results (Unaudited)
Quarterly Results (Unaudited) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |
Quarterly Results (Unaudited) | NOTE 16 — QUARTERLY RESULTS (UNAUDITED) Fourth Quarter Third Quarter Second Quarter First Quarter (in thousands, except unit data) Year ended December 31, 2017: Revenues $ 1,229 $ 1,298 $ 2,649 $ 3,875 Net loss (944 ) (7,341 ) (3,425 ) (4,903 ) Loss attributable to non-controlling interests 1,146 1,022 343 281 Net income (loss) attributable to unitholders’/owner’s interests $ 202 $ (6,319 ) $ (3,082 ) $ (4,622 ) Net income (loss) attributable to common unitholders per unit: Basic (1) $ (0.03 ) $ (0.20 ) $ (0.10 ) $ (0.18 ) Diluted (1) $ (0.03 ) $ (0.20 ) $ (0.10 ) $ (0.18 ) (1) For the fourth quarter, third quarter, second quarter and first quarter of the year ended December 31, 2017, approximately 2,896,000, 2,917,000 3,143,000 and 3,521,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit, because the inclusion of such units would have been anti-dilutive. Fourth Quarter Third Quarter (3) Second Quarter First Quarter (in thousands, except unit data) Year ended December 31, 2016: Revenues (1) $ 1,872 $ 42,237 $ (13,804 ) $ 106,853 Net income (loss) (3)(4) (51,537 ) 13,568 (150,717 ) (1,611 ) (Income) loss attributable to non-controlling interests 43,938 23,619 114,637 (5,340 ) Net income (loss) attributable to unitholders’/owner’s interests $ (7,599 ) $ 37,187 $ (36,080 ) $ (6,951 ) Net income (loss) attributable to common unitholders per unit: Basic (2) $ (0.29 ) $ 1.41 $ (1.39 ) $ (0.27 ) Diluted (2) $ (0.29 ) $ 1.00 $ (1.39 ) $ (0.27 ) (2) Revenues include gains (losses) on mark to market derivatives. A $73.3 million loss on ARP’s mark-to-market derivatives is included for the second quarter related to increases in commodity future prices relative to ARP’s commodity fixed price swaps during the second quarter as compared to the prior year period. (3) For the fourth quarter, second quarter and first quarter of the year ended December 31, 2016, approximately 9,709,000, 7,956,000 and 7,781,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit, because the inclusion of such units would have been anti-dilutive. (4) ARP was deconsolidated in the third quarter of 2016, resulting in the recognition of a $46.9 million gain in that quarter. (5) Includes an asset impairment charge of $41.9 million in the fourth quarter of 2016. |
Basis of Presentation and Sum23
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. |
Basis of Presentation and Sum24
Basis of Presentation and Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Schedule of Net Income (Loss) Reconciliation | 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. |
Reconciliation of Weighted Average Number of Common Unit holder Units | 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. |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Property Plant And Equipment [Abstract] | |
Summary of Property, Plant and Equipment | The following is a summary of property, plant and equipment at the dates indicated (in thousands): December 31, 2017 2016 Natural gas and oil properties: Proved properties $ 147,932 $ 84,631 Unproved properties — 63,314 Support equipment and other 3,188 3,188 Total natural gas and oil properties 151,120 151,133 Less – accumulated depreciation, depletion and amortization (85,827 ) (82,234 ) $ 65,293 $ 68,899 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Reconciliation of Liability for Well Plugging and Abandonment Costs | A reconciliation of our subsidiaries’ liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands): Years Ended December 31, 2017 2016 2015 Asset retirement obligations, beginning of year $ 184 $ 113,909 $ 108,101 Liabilities incurred — 12,458 2,074 Liabilities settled — 139 (2,591 ) Accretion expense 5 3,916 6,325 Deconsolidation of ARP (Note 2) — (130,238 ) — Asset retirement obligations, end of year $ 189 $ 184 $ 113,909 |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Schedule of Total Long-term Debt Instruments | Total debt consists of the following at the dates indicated (in thousands): December 31, 2017 2016 First Lien Credit Agreement $ 20,666 $ 37,962 Second Lien Credit Agreement 59,552 44,593 Debt discount, net of accumulated amortization of $1,090 and $623 (778 ) (1,244 ) Deferred financing costs, net of accumulated amortization of $2,704 and $2,538, respectively (90 ) (211 ) Total debt, net 79,350 81,100 Less current maturities (79,350 ) (81,100 ) Total long-term debt, net $ — $ — |
Schedule of Maturities of Long-term Debt | The aggregate amount of our debt maturities, excluding the effect of future paid in kind interest to be accrued in accordance with the terms of the First and Second Lien Credit Agreements, is as follows (in thousands): Years Ended December 31: 2017 $ 80,218 2018 — 2019 — 2020 — 2021 — Thereafter — Total principal maturities 80,218 Deferred financing costs and debt discounts, net of accumulated amortization (868 ) Total debt $ 79,350 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Summary of Commodity Derivative Activity Presentation in Statement of Operations | The following table summarizes the commodity derivative activity and presentation in our combined consolidated statement of operations for the periods indicated (in thousands): For the Years Ended December 31, 2017 2016 Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets (1) $ — $ 10,540 Portion of settlements attributable to subsequent mark—to—market gains (2) — 88,841 Total cash settlements on commodity derivative contracts $ — $ 99,381 Gain (loss) recognized on cash settlement (3) $ 527 $ (17,927 ) Gain (loss) recognized on open derivative contracts (3) (217 ) (674 ) Gain (loss) on mark-to-market derivatives $ 310 $ (18,601 ) (1) Recognized in gas and oil production revenue. (2) Excludes the effects of the $235.3 million, net of $8.2 million in ARP’s hedge monetization fees, paid directly to ARP’s First Lien Credit Facility lenders upon the sale of substantially all of ARP’s commodity hedge positions on July 25, 2016 and July 26, 2016. (3) Recognized in gain (loss) on mark-to-market derivatives. |
Fair Value of Derivative Instruments Table | The following table summarizes the gross fair values of AGP’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our combined consolidated balance sheets as of the dates indicated (in thousands): Offsetting Derivatives as of December 31, 2017 Gross Amounts Recognized Gross Amounts Offset Net Amount Presented Current portion of derivative assets $ — $ — $ — Long-term portion of derivative assets — — — Total derivative assets $ — $ — $ — Current portion of derivative liabilities $ (497 ) $ — $ (497 ) Long-term portion of derivative liabilities — — — Total derivative liabilities $ (497 ) $ — $ (497 ) Offsetting Derivatives as of December 31, 2016 Current portion of derivative assets $ 97 $ (97 ) $ — Long-term portion of derivative assets — — — Total derivative assets $ 97 $ (97 ) $ — Current portion of derivative liabilities $ (381 ) $ 97 $ (284 ) Long-term portion of derivative liabilities (280 ) — (280 ) Total derivative liabilities $ (661 ) $ 97 $ (564 ) |
Commodity Derivative Instruments by Type Table | At December 31, 2017, AGP had the following commodity derivatives: Type Production Period Ending December 31, Volumes(1) Average Fixed Price Fair Value Asset (in thousands) (2) Crude Oil – Fixed Price Swaps 2018 74,500 $ 52.510 $ (497 ) Net liabilities (497 ) (1) Volumes for crude oil are stated in barrels. (2) Fair value of crude oil fixed price swaps are based on forward West Texas Intermediate (“WTI”) crude oil prices, as applicable. |
Fair Value of Financial Instr29
Fair Value of Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Company, ARP Financial Instruments Measured at Fair Value | Information for our financial instruments measured at fair value were as follows (in thousands): Level 1 Level 2 Level 3 Total As of December 31, 2017 Assets, gross Rabbi trust $ 1,502 $ — $ — $ 1,502 AGP Commodity swaps — — — — Total assets, gross 1,502 — — 1,502 Liabilities, gross AGP Commodity swaps — (497 ) — (497 ) Total derivative liabilities, gross — (497 ) — (497 ) Total assets, fair value, net $ 1,502 $ (497 ) $ — $ 1,005 As of December 31, 2016 Assets, gross Rabbi trust $ 4,208 $ — $ — $ 4,208 AGP Commodity swaps — 97 — 97 Total assets, gross 4,208 97 — 4,305 Liabilities, gross AGP Commodity swaps — (661 ) — (661 ) Total derivative liabilities, gross $ — (661 ) — (661 ) Total assets, fair value, net $ 4,208 $ (564 ) $ — $ 3,644 |
Share Based Compensation Plans
Share Based Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Phantom Unit Activity | The following table sets forth the 2015 LTIP phantom unit activity for the periods indicated: Years Ended December 31, 2017 2016 2015 Number of Units Weighted Average Grant Date Fair Value Number of Units Weighted Average Grant Date Fair Value Number of Units Weighted Average Grant Date Fair Value Outstanding, beginning of year 3,995,214 $ 3.99 2,564,910 $ 6.46 — $ — Granted — — 2,110,000 1.53 2,794,710 6.46 Vested (1) (317,226 ) 1.24 (33,826 ) 6.97 — — Forfeited (822,836 ) 4.54 (645,870 ) 5.58 (229,800 ) 6.43 Outstanding, end of year (2)(3) 2,855,152 $ 4.14 3,995,214 $ 3.99 2,564,910 $ 6.46 Non-cash compensation expense (reversal) recognized (in thousands) $ (135 ) $ 4,984 $ 5,678 (1) The intrinsic value of phantom awards vested during the years ended December 31, 2017 and 2016 was approximately $0.2 million and $31,000. No phantom unit awards vested during the years ended December 31, 2015. (2) The aggregate intrinsic value of phantom unit awards outstanding at December 31, 2017 was $0.1 million. (3) There was approximately $1,000 recognized as liabilities on our consolidated balance sheet at December 31, 2017 representing 22,972 units, due to the option of the Participants to settle in cash instead of units. The respective weighted average grant date fair value for these units was $9.07 at December 31, 2017. |
Operating Segment Information (
Operating Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting [Abstract] | |
Operating Segment Data | Our operations included three reportable operating segments: ARP (through the date of the Chapter 11 Filings), AGP, and corporate and other. These operating segments reflected the way we managed our operations and made business decisions. Corporate and other includes our equity investments in Lightfoot (see Note 2) and Titan (see Note 2), as well as our general and administrative and interest expenses. Operating segment data for the periods indicated were as follows (in thousands): Years Ended December 31, 2017 2016 2015 Atlas Resource Partners: Revenues (1) $ — $ 125,582 $ 740,033 Operating costs and expenses — (134,718 ) (320,922 ) Depreciation, depletion and amortization expense — (67,513 ) (157,978 ) Asset impairment — — (966,635 ) Interest expense — (68,883 ) (102,133 ) Gain on early extinguishment of debt — 26,498 — Reorganization items, net — (21,649 ) — Other income (loss) — (6,625 ) (1,181 ) Segment loss $ — $ (147,308 ) $ (808,816 ) Atlas Growth Partners: Revenues (1) $ 8,151 $ 11,071 $ 12,708 Operating costs and expenses (7,472 ) (12,578 ) (14,968 ) Depreciation, depletion and amortization expense (3,576 ) (14,868 ) (8,951 ) Asset impairment — (41,879 ) (7,346 ) Other loss — (5,383 ) — Segment loss $ (2,897 ) $ (63,637 ) $ (18,557 ) Corporate and other: Revenues $ 900 $ 505 $ 752 General and administrative (2) (534 ) (5,528 ) (30,862 ) Interest expense (20,937 ) (14,861 ) (23,525 ) Other income 6,855 — — Loss on early extinguishment of debt — (6,080 ) (4,726 ) Gain on deconsolidation of Atlas Resource Partners, L.P. — 46,951 — Segment income (loss) $ (13,716 ) $ 20,987 $ (58,361 ) Reconciliation of segment income (loss) to net loss: Segment income (loss): Atlas Resource Partners $ — $ (147,308 ) $ (808,816 ) Atlas Growth Partners (2,897 ) (63,637 ) (18,557 ) Corporate and other (13,716 ) 20,987 (58,361 ) Net loss $ (16,613 ) $ (189,958 ) $ (885,734 ) Reconciliation of segment revenues to total revenues: Segment revenues: Atlas Resource Partners (1) $ — $ 125,582 $ 740,033 Atlas Growth Partners (1) 8,151 11,071 12,708 Corporate and other 900 505 752 Total revenues $ 9,051 $ 137,158 $ 753,493 Capital expenditures: Atlas Resource Partners $ — $ 21,155 $ 127,138 Atlas Growth Partners — 6,602 29,222 Total capital expenditures $ — $ 27,757 $ 156,360 December 31, 2017 2016 Balance sheet: Total assets: Atlas Growth Partners $ 74,219 $ 78,500 Corporate and other 9,829 26,576 Total assets $ 84,048 $ 105,076 |
Supplemental Oil and Gas Info32
Supplemental Oil and Gas Information (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Oil And Gas Exploration And Production Industries Disclosures [Abstract] | |
Reserve Quantity Information | Reserve quantity information and a reconciliation of changes in our proved reserve quantities are as follows: Gas (MMcf) Oil (MBbls) NGLs (MBbls) Total (MMcfe) Balance, January 1, 2015 1,064,878 62,950 23,380 1,582,858 Extensions, discoveries and other additions (1) 6,806 3,460 293 29,324 Sales of reserves in-place (2,714 ) (2 ) — (2,726 ) Purchase of reserves in-place — — — — Transfers to Drilling Partnerships (2,959 ) (482 ) (342 ) (7,903 ) Revisions of previous estimates (2) (379,058 ) (11,224 ) (13,770 ) (529,022 ) Production (79,267 ) (2,119 ) (1,085 ) (98,491 ) Balance, December 31, 2015 607,686 52,583 8,476 974,040 Extensions, discoveries and other additions 789 135 — 1,599 Sales of reserves in-place (3) (530,817 ) (37,926 ) (6,030 ) (794,553 ) Purchase of reserves in-place 1,616 13 — 1,694 Transfers to Drilling Partnerships — — — — Revisions of previous estimates (2) (37,822 ) (10,227 ) (1,726 ) (109,540 ) Production (40,020 ) (1,191 ) (453 ) (49,884 ) Balance, December 31, 2016 1,432 3,387 267 23,356 Extensions, discoveries and other additions — — — — Sales of reserves in-place — — — — Purchase of reserves in-place — — — — Transfers to Drilling Partnerships — — — — Revisions of previous estimates (2) 548 1,231 169 8,949 Production (114 ) (143 ) (20 ) (1,092 ) Balance, December 31, 2017 1,866 4,475 416 31,213 Proved developed reserves at: January 1, 2015 889,074 31,151 12,210 1,149,240 December 31, 2015 568,794 27,130 6,489 770,508 December 31, 2016 652 925 100 6,802 December 31, 2017 613 788 121 6,069 Proved undeveloped reserves at: January 1, 2015 175,804 31,799 11,170 433,618 December 31, 2015 38,892 25,453 1,987 203,532 December 31, 2016 780 2,462 167 16,554 December 31, 2017 1,253 3,687 295 25,144 (1) For the year ended December 31, 2015, the increase represents PUD additions related to our development and leasing activity in the Eagle Ford Shale. (2) See “ Revisions of Previous Estimates (3) For the year ended December 31, 2016, the decrease was due to the deconsolidation of ARP for financial reporting purposes in connection with ARP’s Chapter 11 Filings (see Note 2). |
Schedule of Revisions of Previous Estimates | The following represents the unweighted average of the first-day-of-the-month prices for each of the previous twelve months from the periods presented above: December 31, 2017 2016 2015 Unadjusted Prices Natural gas (per MMBtu) $ 2.98 $ 2.48 $ 2.59 Oil (per Bbl) $ 51.34 $ 42.75 $ 50.28 Natural gas liquids (per Bbl) $ 20.33 $ 19.57 $ 11.02 |
Schedule of Capitalized Costs Related to Oil and Gas Producing Activities | Capitalized Costs Related to Oil and Gas Producing Activities . The components of capitalized costs related to oil and gas producing activities as of the periods indicated were as follows (in thousands): December 31, 2017 2016 Natural gas and oil properties: Proved properties $ 147,932 $ 84,631 Unproved properties (1) — 63,314 Support equipment 29 29 147,961 147,974 Accumulated depreciation, depletion and amortization (85,328 ) (81,901 ) Net capitalized costs $ 62,633 $ 66,073 |
Schedule of Results of Operations from Oil and gas Producing Activities | Results of Operations from Oil and Gas Producing Activities . The results of operations related to our oil and gas producing activities during the periods indicated were as follows (in thousands): Years Ended December 31, 2017 2016 2015 Revenues $ 7,841 $ 129,993 $ 368,845 Production costs (2,528 ) (78,034 ) (171,882 ) Depreciation, depletion and amortization (3,410 ) (79,013 ) (153,938 ) Asset impairment (1) — (41,879 ) (973,981 ) $ 1,903 $ (68,933 ) $ (930,956 ) (1) For the year ended December 31, 2016, we recognized $25.4 million and $16.5 million of asset impairment related to AGP’s proved and unproved oil and gas properties in the Eagle Ford operating area, respectively, which were impaired due to lower forecasted commodity prices and timing of capital financing and deployment for the development of our undeveloped properties. During the year ended December 31, 2015, we recognized $974 million of asset impairment of which $960 million related to ARP’s proved oil and gas properties in the Barnett, Coal-bed Methane, Rangely, Southern Appalachia, Marcellus and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices, net of $85.8 million of future hedge gains reclassified from accumulated other comprehensive income, $6.6 million of asset impairments in ARP’s unproved gas and oil properties primarily related to ARP’s unproved acreage in the New Albany Shale, which was impaired due to expiring acreage and no intention to pursue development, and $7.4 million related to AGP’s proved oil and gas properties in the Marble Falls and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices. |
Schedule of Costs Incurred in Oil and gas Producing Activities | Costs Incurred in Oil and Gas Producing Activities. The costs incurred in our oil and gas activities during the periods indicated are as follows (in thousands): Years Ended December 31, 2017 2016 2015 Property acquisition costs: Proved properties $ — $ 2,207 $ 55,033 Unproved properties — — 43,820 Exploration costs (1) — 825 1,601 Development costs — 16,792 102,110 Total costs incurred in oil & gas producing activities $ — $ 19,824 $ 202,564 (1) There were no exploratory wells drilled during the periods presented. |
Schedule of Standardized Measure of Estimated Discounted Future Net Cash Flows | Standardized Measure of Discounted Future Cash Flows . The following schedule presents the standardized measure of estimated discounted future net cash flows relating to our proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2017, 2016 and 2015, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels and include the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations (in thousands): Years Ended December 31, 2017 2016 2015 Future cash inflows $ 243,644 $ 145,857 $ 3,910,339 Future production costs (73,792 ) (53,738 ) (1,954,564 ) Future development costs (68,321 ) (51,942 ) (1,289,841 ) Future net cash flows 101,531 40,177 665,934 Less 10% annual discount for estimated timing of cash flows (61,082 ) (22,796 ) (90,703 ) Standardized measure of discounted future net cash flows $ 40,449 $ 17,381 $ 575,231 |
Schedule of Changes in Discounted Future Net Cash Flows | Changes in Standardized Discounted Future Cash Flows. The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved oil, gas and NGL reserves (in thousands), including amounts related to asset retirement obligations. Since AGP and ARP allocate taxable income to their respective owners, no recognition has been given to income taxes: Years Ended December 31, 2017 2016 2015 Balance, beginning of year $ 17,381 $ 575,231 $ 2,236,764 Increase (decrease) in discounted future net cash flows: (1) Sales and transfers of oil and gas, net of related costs (5,403 ) (59,246 ) (137,942 ) Net changes in prices and production costs 22,401 (226,641 ) (1,629,945 ) Revisions of previous quantity estimates 15,568 (32,208 ) (41,147 ) Development costs incurred — — 88,261 Changes in future development costs (11,236 ) 6,914 (167,995 ) Transfers to Drilling Partnerships — — (13,291 ) Extensions, discoveries, and improved recovery less related costs — (50 ) 20,408 Purchases of reserves in-place — 711 — Sales of reserves in-place — (297,227 ) (2,162 ) Accretion of discount 1,738 51,238 223,676 Estimated settlement of asset retirement obligations — (1,332 ) (224 ) Estimated proceeds on disposals of well equipment — (9 ) (1,172 ) Changes in production rates (timing) and other — — — Outstanding, end of year $ 40,449 $ 17,381 $ 575,231 (1) See “ Reserve Quantity Information Revisions of Previous Estimates |
Quarterly Results (Unaudited) (
Quarterly Results (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of Quarterly Financial Information | Fourth Quarter Third Quarter Second Quarter First Quarter (in thousands, except unit data) Year ended December 31, 2017: Revenues $ 1,229 $ 1,298 $ 2,649 $ 3,875 Net loss (944 ) (7,341 ) (3,425 ) (4,903 ) Loss attributable to non-controlling interests 1,146 1,022 343 281 Net income (loss) attributable to unitholders’/owner’s interests $ 202 $ (6,319 ) $ (3,082 ) $ (4,622 ) Net income (loss) attributable to common unitholders per unit: Basic (1) $ (0.03 ) $ (0.20 ) $ (0.10 ) $ (0.18 ) Diluted (1) $ (0.03 ) $ (0.20 ) $ (0.10 ) $ (0.18 ) (1) For the fourth quarter, third quarter, second quarter and first quarter of the year ended December 31, 2017, approximately 2,896,000, 2,917,000 3,143,000 and 3,521,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit, because the inclusion of such units would have been anti-dilutive. Fourth Quarter Third Quarter (3) Second Quarter First Quarter (in thousands, except unit data) Year ended December 31, 2016: Revenues (1) $ 1,872 $ 42,237 $ (13,804 ) $ 106,853 Net income (loss) (3)(4) (51,537 ) 13,568 (150,717 ) (1,611 ) (Income) loss attributable to non-controlling interests 43,938 23,619 114,637 (5,340 ) Net income (loss) attributable to unitholders’/owner’s interests $ (7,599 ) $ 37,187 $ (36,080 ) $ (6,951 ) Net income (loss) attributable to common unitholders per unit: Basic (2) $ (0.29 ) $ 1.41 $ (1.39 ) $ (0.27 ) Diluted (2) $ (0.29 ) $ 1.00 $ (1.39 ) $ (0.27 ) (2) Revenues include gains (losses) on mark to market derivatives. A $73.3 million loss on ARP’s mark-to-market derivatives is included for the second quarter related to increases in commodity future prices relative to ARP’s commodity fixed price swaps during the second quarter as compared to the prior year period. (3) For the fourth quarter, second quarter and first quarter of the year ended December 31, 2016, approximately 9,709,000, 7,956,000 and 7,781,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit, because the inclusion of such units would have been anti-dilutive. (4) ARP was deconsolidated in the third quarter of 2016, resulting in the recognition of a $46.9 million gain in that quarter. (5) Includes an asset impairment charge of $41.9 million in the fourth quarter of 2016. |
Organization (Narrative) (Detai
Organization (Narrative) (Details) - USD ($) | Sep. 02, 2016 | Feb. 27, 2015 | Aug. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2017 | Sep. 01, 2016 |
Organization [Line Items] | ||||||
Percentage of interest represented by common units which is effected by pro rata distribution | 100.00% | |||||
Common units issued | 31,973,122 | 31,973,122 | ||||
Common units outstanding | 31,973,122 | 31,973,122 | ||||
Lightfoot Capital Partners, LP | ||||||
Organization [Line Items] | ||||||
General partner ownership interest | 15.90% | |||||
Common limited partner ownership interest | 12.00% | |||||
Titan | ||||||
Organization [Line Items] | ||||||
Percentage of common equity interest | 2.00% | |||||
Titan | Limited Liability Company | ||||||
Organization [Line Items] | ||||||
Percentage of common stock voting rights | 67.00% | |||||
Titan | Series A Preferred Units | ||||||
Organization [Line Items] | ||||||
Percentage of preferred share | 2.00% | 2.00% | 2.00% | |||
Atlas Growth Partners, L.P | ||||||
Organization [Line Items] | ||||||
General partner ownership interest | 80.00% | |||||
Common limited partner ownership interest | 2.10% | |||||
Atlas Resource Partners, L.P. | ||||||
Organization [Line Items] | ||||||
Percentage of common equity interest | 25.00% | |||||
General partner ownership interest | 100.00% | |||||
Common limited partner ownership interest | 23.30% | |||||
Percentage of Senior Notes Outstanding | 100.00% | |||||
Senior Notes | $ 668,000,000 | |||||
Percentage of common equity interest | 90.00% | |||||
Atlas Resource Partners, L.P. | Second Lien Lenders | ||||||
Organization [Line Items] | ||||||
Percentage of common equity interest | 10.00% | |||||
Line of credit, maximum borrowing capacity | $ 252,500,000 | |||||
Atlas Resource Partners, L.P. | First Lien Lenders | ||||||
Organization [Line Items] | ||||||
Line of credit, maximum borrowing capacity | 440,000,000 | |||||
Atlas Resource Partners, L.P. | First Lien Lenders | Revolving Credit Facility Conforming Tranche | ||||||
Organization [Line Items] | ||||||
Line of credit, maximum borrowing capacity | 410,000,000 | |||||
Atlas Resource Partners, L.P. | First Lien Lenders | Revolving Credit Facility Nonconforming Tranche | ||||||
Organization [Line Items] | ||||||
Line of credit, maximum borrowing capacity | $ 30,000,000 |
Basis of Presentation and Sum35
Basis of Presentation and Summary of Significant Accounting Policies (Narrative) (Details) | Sep. 29, 2017 | Aug. 29, 2017USD ($)$ / sharesshares | Jul. 26, 2017USD ($)shares | Jul. 27, 2016USD ($) | Mar. 30, 2016USD ($) | Jun. 05, 2015USD ($)shares | Dec. 31, 2017USD ($)Lease$ / sharesshares | Aug. 31, 2016 | May 31, 2015$ / sharesshares | Sep. 30, 2016USD ($) | Dec. 31, 2017USD ($)LeaseCustomer$ / sharessharesbblMMBbls | Dec. 31, 2016USD ($)Customershares | Dec. 31, 2015USD ($)Customer$ / sharesshares | Dec. 31, 2017USD ($)Lease$ / sharesshares |
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Pro-rata share in Drilling Partnerships | 30.00% | |||||||||||||
Partners unit, issued | shares | 245,175 | 9,803,451 | ||||||||||||
Weighted average interest rate used to capitalize interest | 6.60% | 6.50% | ||||||||||||
Interest costs capitalized | $ 5,400,000 | $ 15,800,000 | ||||||||||||
Distributions received from unconsolidated companies | $ 1,574,000 | 1,873,000 | 2,847,000 | |||||||||||
Repayment of credit facility | 291,191,000 | |||||||||||||
Recognized net gain on sale of equity investments | 9,908,000 | |||||||||||||
Net proceeds from equity method investments | 28,006,000 | |||||||||||||
Gain on deconsolidation | 46,951,000 | |||||||||||||
Other assets, net | $ 5,102,000 | 5,102,000 | 23,293,000 | $ 5,102,000 | ||||||||||
Other liabilities recorded | $ 1,968,000 | $ 1,968,000 | 4,863,000 | $ 1,968,000 | ||||||||||
Number of lease agreements | Lease | 2 | 2 | 2 | |||||||||||
Deferred income tax benefit | $ 0 | |||||||||||||
Unrecognized income tax penalties and interest expense | $ 0 | 0 | 0 | |||||||||||
Concentration Risk, Credit Risk, Uninsured Deposits | 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. | |||||||||||||
Cash Equivalents, at Carrying Value | $ 12,300,000 | $ 12,300,000 | 13,900,000 | $ 12,300,000 | ||||||||||
Cash, Uninsured Amount | 11,100,000 | $ 11,100,000 | 12,200,000 | 11,100,000 | ||||||||||
Proportion of amount received on cost incurred to drill | 15.00% | |||||||||||||
Monthly administrative fee per well | $ 75 | |||||||||||||
Gathering Fee Percentage | 16.00% | |||||||||||||
Gathering Fee Percentage Net Margin | 3.00% | |||||||||||||
Unbilled Contracts Receivable | 600,000 | $ 600,000 | 800,000 | 600,000 | ||||||||||
Lease Agreements in AGP's Eagle Ford Operating Area One | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Other liabilities recorded | 100,000 | 100,000 | 100,000 | |||||||||||
Lease Agreements in AGP's Eagle Ford Operating Area Two | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Other liabilities recorded | 300,000 | 300,000 | 300,000 | |||||||||||
Rabbi trust | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Other assets, net | 1,500,000 | 1,500,000 | 4,100,000 | 1,500,000 | ||||||||||
Other liabilities recorded | 1,500,000 | 1,500,000 | 4,100,000 | 1,500,000 | ||||||||||
Partnership distributed to executives | 3,100,000 | 2,300,000 | 0 | |||||||||||
Osprey Sponsor, LLC | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Net carrying amount of investment | 0 | 0 | 0 | |||||||||||
Equity method income (loss) | 0 | |||||||||||||
Accrued Liabilities | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Accrued payroll and benefit items | 6,600,000 | 6,600,000 | 10,600,000 | 6,600,000 | ||||||||||
Other Noncurrent Liabilities | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Probable loss contingency | 500,000 | |||||||||||||
Lightfoot Capital Partners, LP | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Net carrying amount of investment | 0 | 0 | 0 | |||||||||||
Equity method income (loss) | $ 900,000 | 1,200,000 | 700,000 | |||||||||||
Common limited partner ownership interest | 12.00% | |||||||||||||
General partner ownership interest | 15.90% | |||||||||||||
Distributions received from unconsolidated companies | 21,600,000 | $ 1,600,000 | 1,900,000 | 2,800,000 | ||||||||||
Recognized net gain on sale of equity investments | 6,900,000 | |||||||||||||
Lightfoot Capital Partners, LP | Other Income | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Net of contractual agreements | 3,100,000 | |||||||||||||
Lightfoot Capital Partners, LP | Other Assets | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Net carrying amount of investment | 0 | $ 0 | 18,700,000 | 0 | ||||||||||
Gulf L N G Holdings Group L L C | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Common limited partner ownership interest | 5.51646% | |||||||||||||
Common limited partner additional ownership interest | 4.16154% | |||||||||||||
Gulf L N G Holdings Group L L C | LCP LP | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Net proceeds from equity method investments | $ 3,000,000 | |||||||||||||
Zenith Energy Terminals Joliet Holdings, LLC | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Common limited partner ownership interest | 1.80% | |||||||||||||
Payments to acquire ownership interests | $ 3,300,000 | |||||||||||||
Capability of unloading barrel per day | bbl | 85,000 | |||||||||||||
Storage capacity | bbl | 300,000 | |||||||||||||
Additional possible storage capacity | MMBbls | 1 | |||||||||||||
Revolving Credit Facility | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Deferred financing cost, net of accumulated amortization | 200,000 | $ 200,000 | 200,000 | 200,000 | ||||||||||
Amortization expense of deferred financing costs | 10,000,000 | $ 14,200,000 | ||||||||||||
Accumulated amortization | 100,000 | 100,000 | 100,000 | 100,000 | ||||||||||
Deferred financing costs net | 15,500,000 | $ 15,500,000 | 15,500,000 | |||||||||||
Minimum | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Pro-rata share in Drilling Partnerships | 10.00% | |||||||||||||
Recognition period to receive fees | 60 days | |||||||||||||
Amount of fixed fees received by each well drilled | $ 100,000 | |||||||||||||
Monthly operating fee paid per well | $ 1,000 | |||||||||||||
Return on unhedged revenue percentage | 10.00% | |||||||||||||
Period of return on unhedged revenue | 5 years | |||||||||||||
Maximum | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Pro-rata share in Drilling Partnerships | 30.00% | |||||||||||||
Recognition period to receive fees | 270 days | |||||||||||||
Amount of fixed fees received by each well drilled | $ 500,000 | |||||||||||||
Monthly operating fee paid per well | $ 2,000 | |||||||||||||
Percentage on unhedged revenue | 50.00% | |||||||||||||
Return on unhedged revenue percentage | 12.00% | |||||||||||||
Period of return on unhedged revenue | 8 years | |||||||||||||
Pipelines, Processing and Compression Facilities | Minimum | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Property, plant and equipment useful life | 15 years | |||||||||||||
Pipelines, Processing and Compression Facilities | Maximum | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Property, plant and equipment useful life | 20 years | |||||||||||||
Buildings and Land Improvements | Minimum | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Property, plant and equipment useful life | 3 years | |||||||||||||
Buildings and Land Improvements | Maximum | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Property, plant and equipment useful life | 40 years | |||||||||||||
Other Support Equipment | Minimum | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Property, plant and equipment useful life | 3 years | |||||||||||||
Other Support Equipment | Maximum | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Property, plant and equipment useful life | 10 years | |||||||||||||
First Lien Credit Agreement | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Repayment of credit facility | 21,600,000 | |||||||||||||
Credit Agreements | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Outstanding indebtedness | 79,400,000 | $ 79,400,000 | 79,400,000 | |||||||||||
Debt discounts | 800,000 | 800,000 | 800,000 | |||||||||||
Deferred financing costs | 100,000 | $ 100,000 | 100,000 | |||||||||||
Credit Agreements | First Lien Credit Agreement | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Line of credit facility, expiration date | Sep. 30, 2017 | |||||||||||||
Term loans | $ 35,000,000 | 20,700,000 | $ 20,700,000 | 20,700,000 | ||||||||||
Line of credit facility extended expiration date | Jun. 30, 2018 | Jun. 30, 2018 | ||||||||||||
Credit Agreements | Second lien term loan facility | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Line of credit facility, expiration date | Mar. 30, 2019 | |||||||||||||
Term loans | $ 35,800,000 | $ 59,600,000 | $ 59,600,000 | $ 59,600,000 | ||||||||||
Line of credit facility extended expiration date | Mar. 30, 2020 | |||||||||||||
Arkoma Acquisition | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Partners unit, issued | shares | 6,500,000 | |||||||||||||
Receivable price per common unit in cash | $ / shares | $ 7.97 | |||||||||||||
Arc GP | Merger Agreement | LCP LP | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Receivable price per common unit in cash | $ / shares | $ 14.50 | |||||||||||||
Number of common unit held | shares | 5,200,000 | |||||||||||||
Arc GP | Merger Agreement | LCP GP | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Price receivable as net proceeds for common unit held | $ 94,500,000 | |||||||||||||
Percentage of membership interests | 100.00% | |||||||||||||
Osprey Energy Acquisition Corp | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Net proceeds from initial public offering | $ 275,000,000 | |||||||||||||
Issuance of units in initial public offering | shares | 27,500,000 | |||||||||||||
Common stock, conversion basis | one-for-one | |||||||||||||
Number of founder shares allocated to employees | shares | 125,000 | 125,000 | 125,000 | |||||||||||
Terms of agreement | 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. | |||||||||||||
Threshold of common stock sales price per share | $ / shares | $ 12 | $ 12 | $ 12 | |||||||||||
Osprey Energy Acquisition Corp | Class B common stock | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Founder shares allocated for membership interest | shares | 1,250,000 | 1,250,000 | 1,250,000 | |||||||||||
Atlas Resource Partners, L.P. | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Equity method investments | $ 0 | |||||||||||||
Common limited partner ownership interest | 23.30% | |||||||||||||
General partner ownership interest | 100.00% | |||||||||||||
Gain on deconsolidation | 46,400,000 | $ 46,900,000 | $ 46,951,000 | |||||||||||
Gain related to remeasurement of retained investment | $ 61,700,000 | |||||||||||||
Percentage of common equity interest | 25.00% | |||||||||||||
Number of customers | Customer | 3 | 4 | ||||||||||||
Atlas Resource Partners, L.P. | Customer Concentration Risk Customer 1 | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Concentration Risk, Percentage | 29.00% | 21.00% | ||||||||||||
Atlas Resource Partners, L.P. | Customer Concentration Risk Customer 2 | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Concentration Risk, Percentage | 15.00% | 15.00% | ||||||||||||
Atlas Resource Partners, L.P. | Customer Concentration Risk Customer 3 | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Concentration Risk, Percentage | 14.00% | 11.00% | ||||||||||||
Atlas Resource Partners, L.P. | Customer Concentration Risk Customer4 | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Concentration Risk, Percentage | 11.00% | |||||||||||||
Atlas Resource Partners, L.P. | Arkoma Acquisition | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Business acquisition, cost of acquired entity, cash paid | $ 31,500,000 | |||||||||||||
Partners unit, issued | shares | 6,500,000 | |||||||||||||
Business acquisition, effective date of acquisition | Jan. 1, 2015 | |||||||||||||
Titan | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Net carrying amount of investment | $ 0 | $ 0 | $ 0 | $ 0 | ||||||||||
Equity method income (loss) | $ 0 | (600,000) | ||||||||||||
Equity method investments | $ 600,000 | |||||||||||||
Percentage of common equity interest | 2.00% | |||||||||||||
Titan | Series A Preferred Units | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Equity method investment percentage | 2.00% | 2.00% | 2.00% | |||||||||||
Atlas Growth Partners, L.P | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Partners unit, issued | shares | 2,330,041 | 12,623,500 | ||||||||||||
Common limited partner ownership interest | 2.10% | |||||||||||||
General partner ownership interest | 80.00% | |||||||||||||
Receivable price per common unit in cash | $ / shares | $ 10 | |||||||||||||
Number of customers | Customer | 1 | 2 | 3 | |||||||||||
Atlas Growth Partners, L.P | Customer Concentration Risk Customer 1 | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Concentration Risk, Percentage | 91.00% | 64.00% | 59.00% | |||||||||||
Atlas Growth Partners, L.P | Customer Concentration Risk Customer 2 | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Concentration Risk, Percentage | 29.00% | 28.00% | ||||||||||||
Atlas Growth Partners, L.P | Customer Concentration Risk Customer 3 | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Concentration Risk, Percentage | 12.00% | |||||||||||||
Drilling Partnership Wells | ||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||||
Gathering Fee Percentage | 13.00% |
Basis of Presentation and Sum36
Basis of Presentation and Summary of Significant Accounting Policies (Schedule of Net Income (Loss) Reconciliation) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | [1] | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Reconciliation Of Net Income Loss [Line Items] | |||||||||||||
Net loss | $ (16,613) | $ (189,958) | $ (885,734) | ||||||||||
Preferred unitholders’ dividends | (339) | (3,360) | |||||||||||
Loss attributable to non-controlling interests | $ 1,146 | $ 1,022 | $ 343 | $ 281 | $ 43,938 | $ 23,619 | $ 114,637 | $ (5,340) | 2,792 | 176,854 | 649,316 | ||
Loss attributable to owner's interest (period prior to the transfer of assets on February 27, 2015) | 10,475 | ||||||||||||
Net loss attributable to common unitholders | (13,821) | (13,443) | (229,303) | ||||||||||
Net loss utilized in the calculation of net loss attributable to common unitholders per unit – diluted | [2] | $ (13,821) | $ (13,443) | (229,303) | |||||||||
Antidilutive Phantom Unit Securities Excluded from Computation of Diluted Earnings Attributable to Common Unit Holders Outstanding Units | 59,000 | 330,000 | |||||||||||
Continuing Operations | |||||||||||||
Reconciliation Of Net Income Loss [Line Items] | |||||||||||||
Preferred unitholders’ dividends | $ (339) | $ (3,360) | |||||||||||
[1] | For the fourth quarter, second quarter and first quarter of the year ended December 31, 2016, approximately 9,709,000, 7,956,000 and 7,781,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit, because the inclusion of such units would have been anti-dilutive. | ||||||||||||
[2] | 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. |
Basis of Presentation and Sum37
Basis of Presentation and Summary of Significant Accounting Policies (Reconciliation of Weighted Average Number of Common Unit Holder Units) (Details) - shares | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Accounting Policies [Abstract] | |||
Weighted average number of common units—basic | 29,965,000 | 26,035,000 | 26,011,000 |
Weighted average number of common units—diluted | 29,965,000 | 26,035,000 | 26,011,000 |
Antidilutive Securities Excluded From Computation Of Diluted Net Income (Loss) Attributable To Common Limited Partners Outstanding Units | 3,117,122 | 2,986,000 |
Property, Plant and Equipment38
Property, Plant and Equipment (Summary of Property, Plant and Equipment) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Property Plant And Equipment [Abstract] | ||
Proved properties | $ 147,932 | $ 84,631 |
Unproved properties | 63,314 | |
Support equipment and other | 3,188 | 3,188 |
Total natural gas and oil properties | 151,120 | 151,133 |
Less – accumulated depreciation, depletion and amortization | (85,827) | (82,234) |
Property, plant and equipment, Net, Total | $ 65,293 | $ 68,899 |
Property, Plant and Equipment39
Property, Plant and Equipment (Narrative) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2017 | |
Property Plant And Equipment [Line Items] | ||||
Non-cash investing activities capital expenditures | $ 400 | $ 21,500 | ||
Asset impairment | $ 41,900 | 41,879 | 973,981 | |
(Gain) loss on asset sales and disposal | 1,200 | |||
Proved Properties | ||||
Property Plant And Equipment [Line Items] | ||||
Asset impairment | 967,400 | |||
Net future hedge gains | 85,800 | |||
Atlas Resource Partners, L.P. | ||||
Property Plant And Equipment [Line Items] | ||||
Non-cash investing activities capital expenditures | 7,700 | |||
Atlas Resource Partners, L.P. | Unproved Properties | ||||
Property Plant And Equipment [Line Items] | ||||
Asset impairment | 6,600 | |||
Atlas Resource Partners, L.P. | Proved Properties | ||||
Property Plant And Equipment [Line Items] | ||||
Asset impairment | 960,000 | |||
Atlas Growth Partners, L.P | ||||
Property Plant And Equipment [Line Items] | ||||
Unproved properties transferred to proved natural gas and oil properties | $ 63,300 | |||
Atlas Growth Partners, L.P | Unproved Properties | ||||
Property Plant And Equipment [Line Items] | ||||
Asset impairment | 16,500 | |||
Atlas Growth Partners, L.P | Proved Properties | ||||
Property Plant And Equipment [Line Items] | ||||
Asset impairment | $ 25,400 | $ 7,400 |
Asset Retirement Obligations (R
Asset Retirement Obligations (Reconciliation of Liability for Well Plugging and Abandonment Costs) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Asset Retirement Obligation Roll Forward Analysis Roll Forward | |||
Asset retirement obligations, beginning of year | $ 184 | $ 113,909 | $ 108,101 |
Liabilities incurred | 12,458 | 2,074 | |
Liabilities settled | 139 | (2,591) | |
Accretion expense | 5 | 3,916 | 6,325 |
Deconsolidation of ARP (Note 2) | (130,238) | ||
Asset retirement obligations, end of year | $ 189 | $ 184 | $ 113,909 |
Debt (Schedule of Total Debt Ou
Debt (Schedule of Total Debt Outstanding) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Debt Instrument [Line Items] | ||
Debt discount, net of accumulated amortization | $ (778) | $ (1,244) |
Total debt, net | 79,350 | 81,100 |
Less current maturities | (79,350) | (81,100) |
Atlas Energy | ||
Debt Instrument [Line Items] | ||
Deferred financing costs, net of accumulated amortization | (90) | (211) |
Atlas Energy | First Lien Credit Agreement | ||
Debt Instrument [Line Items] | ||
Term loans | 20,666 | 37,962 |
Atlas Energy | Second lien term loan facility | ||
Debt Instrument [Line Items] | ||
Term loans | $ 59,552 | $ 44,593 |
Debt (Schedule of Total Debt 42
Debt (Schedule of Total Debt Outstanding) (Parenthetical) (Details) - Atlas Energy - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Debt Instrument [Line Items] | ||
Accumulated amortization of debt discount | $ 1,090 | $ 623 |
Accumulated amortization of deferred financing costs | $ 2,704 | $ 2,538 |
Debt (Narrative) (Details)
Debt (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |||
Cash Payments For Interest On Debt | $ 1 | $ 55.8 | $ 106.7 |
Debt (Credit Agreements) (Detai
Debt (Credit Agreements) (Details) | Apr. 26, 2018 | Sep. 29, 2017 | Mar. 30, 2016USD ($) | Dec. 31, 2017USD ($) | Apr. 26, 2018 | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Sep. 30, 2017 | Apr. 27, 2016USD ($)shares |
Debt Instrument [Line Items] | ||||||||||
Gain (loss) on early extinguishment of debt | $ 20,418,000 | $ (4,726,000) | ||||||||
Repayment of credit facility | 291,191,000 | |||||||||
Company's Current and Former Officers | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Percentage of lenders participated in loan syndication | 12.00% | |||||||||
Minimum | Unitholders | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Percentage of lenders participated in loan syndication | 5.00% | |||||||||
Credit Agreements | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Deemed prepayment premium | $ 2,400,000 | |||||||||
Gain (loss) on early extinguishment of debt | (6,100,000) | |||||||||
Prepayment penalty | 2,400,000 | |||||||||
Accelerated amortization of deferring financing costs | $ 3,700,000 | |||||||||
Outstanding indebtedness | $ 79,400,000 | $ 79,400,000 | ||||||||
Debt discounts | 800,000 | 800,000 | ||||||||
Deferred financing costs | 100,000 | 100,000 | ||||||||
Credit Agreements | Maximum | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Market Capitalization | 75,000,000 | |||||||||
First Lien Credit Agreement | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Repayment of credit facility | 21,600,000 | |||||||||
First Lien Credit Agreement | Credit Agreements | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Term loans | $ 35,000,000 | 20,700,000 | $ 20,700,000 | |||||||
Line of credit facility, expiration date | Sep. 30, 2017 | |||||||||
Line of credit facility extended expiration date | Jun. 30, 2018 | Jun. 30, 2018 | ||||||||
First Lien Credit Agreement | Credit Agreements | Third Amendment | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Line of credit facility, expiration date | Sep. 30, 2017 | |||||||||
Line of credit facility extended expiration date | Sep. 30, 2018 | |||||||||
Restricted cash balance | $ 4,000,000 | |||||||||
Minimum reserve balance in EBITDA on trailing twelve-months basis | $ 2,000,000 | |||||||||
Line of credit facility covenant terms | Replace the existing financial covenants with (i) the requirement that we maintain a minimum of $2 million in EBITDA on a trailing twelve-month basis, beginning with the quarter ending June 30, 2016, and (ii) the incorporation into the First Lien Credit Agreement of the financial covenants included in ARP?s credit agreement, beginning with the quarter ending June 30, 2016 | |||||||||
First Lien Credit Agreement | Credit Agreements | Third Amendment | Alternative Base Rate | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Cash interest rate margin | 0.50% | |||||||||
Pay-in-kind interest payment percentage | 11.00% | |||||||||
First Lien Credit Agreement | Credit Agreements | Third Amendment | Eurodollar Loans | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Cash interest rate margin | 1.50% | |||||||||
First Lien Credit Agreement | Credit Agreements | Third Amendment | Maximum | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Leverage ratio | 6 | |||||||||
Extension fee percentage | 5.00% | |||||||||
First Lien Credit Agreement | Credit Agreements | Riverstone Credit Agreement | Subsequent Event | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Line of credit facility extended expiration date | Jun. 30, 2018 | Jun. 30, 2018 | ||||||||
Second lien term loan facility | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt Instrument, Unamortized Discount | 800,000 | $ 800,000 | $ 1,900,000 | |||||||
Warrants issued | shares | 4,668,044 | |||||||||
Second lien term loan facility | Maximum | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Warrants issued | shares | 4,668,044 | |||||||||
Second lien term loan facility | Minimum | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Asset coverage ratio | 2 | |||||||||
Second lien term loan facility | Credit Agreements | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Term loans | $ 35,800,000 | $ 59,600,000 | $ 59,600,000 | |||||||
Line of credit facility, expiration date | Mar. 30, 2019 | |||||||||
Line of credit facility extended expiration date | Mar. 30, 2020 | |||||||||
Line of Credit Facility interest rate description | Borrowings under the Second Lien Credit Agreement bear interest at a rate of 30%, payable in-kind through an increase in the outstanding principal. If the First Lien Credit Agreement is repaid in full prior to March 30, 2018, the rate will be reduced to 20%. If the Extension Option is exercised, the rate will again be increased to 30%. If our market capitalization is greater than $75 million, we can issue common units in lieu of increasing the principal to satisfy the interest obligation. | |||||||||
Borrowings bearing interest rate | 30.00% | |||||||||
Borrowings interest rate if First Lien Credit Agreement is fully repaid prior to March 30, 2018 | 20.00% | |||||||||
Borrowings interest rate if extension option is exercised | 30.00% | |||||||||
Second lien term loan facility | Credit Agreements | Maximum | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Leverage ratio | 6 | |||||||||
Extension fee percentage | 5.00% |
Debt (Aggregate Amount of Debt
Debt (Aggregate Amount of Debt Maturities) (Details) $ in Thousands | Dec. 31, 2017USD ($) |
Debt Disclosure [Abstract] | |
2,017 | $ 80,218 |
Total principal maturities | 80,218 |
Deferred financing costs and debt discounts, net of accumulated amortization | (868) |
Total debt | $ 79,350 |
Derivative Instruments (Narrati
Derivative Instruments (Narrative) (Details) - USD ($) | Jul. 28, 2016 | Dec. 31, 2016 |
Derivative Instruments Gain Loss [Line Items] | ||
Repayments of borrowings | $ 291,191,000 | |
First Lien Lenders | Atlas Resource Partners, L.P. | ||
Derivative Instruments Gain Loss [Line Items] | ||
Repayments of borrowings | $ 233,500,000 |
Derivative Instruments (Summary
Derivative Instruments (Summary of Commodity Derivative Activity and Presentation in Partnership's Consolidated Statement of Operations) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Derivative Instruments And Hedging Activities Disclosure [Abstract] | ||||
Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets | [1] | $ 10,540 | ||
Portion of settlements attributable to subsequent mark-to-market gains | [2] | 88,841 | ||
Total cash settlements on commodity derivative contracts | 99,381 | |||
Gain (loss) recognized on cash settlement | [3] | $ 527 | (17,927) | |
Gain (loss) recognized on open derivative contracts | [3] | (217) | (674) | |
Gain (loss) on mark-to-market derivatives | $ 310 | $ (18,601) | $ 268,085 | |
[1] | Recognized in gas and oil production revenue. | |||
[2] | Excludes the effects of the $235.3 million, net of $8.2 million in ARP’s hedge monetization fees, paid directly to ARP’s First Lien Credit Facility lenders upon the sale of substantially all of ARP’s commodity hedge positions on July 25, 2016 and July 26, 2016. | |||
[3] | Recognized in gain (loss) on mark-to-market derivatives. |
Derivative Instruments (Summa48
Derivative Instruments (Summary of Commodity Derivative Activity and Presentation in Partnership's Consolidated Statement of Operations) (Parenthetical) (Details) - Atlas Resource Partners, L.P. - First Lien Lenders $ in Millions | Jul. 27, 2016USD ($) |
Derivative Instruments Gain Loss [Line Items] | |
Effect of hedge monetization fees paid | $ 235.3 |
Net of hedge monetization fees paid | $ 8.2 |
Derivative Instruments (Fair Va
Derivative Instruments (Fair Values of the Company's Derivative Instruments Table) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Assets | $ 1,502 | $ 4,305 |
Gross Amounts Recognized, Liabilities | (497) | (661) |
Atlas Growth Partners, L.P | Derivative Financial Instruments Current Liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Liabilities | (497) | (381) |
Gross Amounts Offset, Liabilities | 97 | |
Net Amount Presented, Liabilities | (497) | (284) |
Atlas Growth Partners, L.P | Derivative Financial Instruments Long Term Liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Liabilities | (280) | |
Net Amount Presented, Liabilities | (280) | |
Atlas Growth Partners, L.P | Derivative Financial Instruments Liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Liabilities | (497) | (661) |
Gross Amounts Offset, Liabilities | 97 | |
Net Amount Presented, Liabilities | $ (497) | (564) |
Atlas Growth Partners, L.P | Current portion of derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Assets | 97 | |
Gross Amounts Offset, Assets | (97) | |
Atlas Growth Partners, L.P | Total derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Assets | 97 | |
Gross Amounts Offset, Assets | $ (97) |
Derivative Instruments (The Com
Derivative Instruments (The Company's Commodity Derivative Instruments by Type Table) (Details) - Atlas Growth Partners, L.P $ in Thousands | Dec. 31, 2017USD ($)bbl$ / bbl | |
Derivatives Fair Value [Line Items] | ||
Fair Value Asset / (Liability) | $ (497) | [1] |
Crude Oil - Fixed Price Swaps for Production Period Ending December 31, 2018 | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | bbl | 74,500 | [2] |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 52.510 | |
Fair Value Asset / (Liability) | $ (497) | [1] |
[1] | Fair value of crude oil fixed price swaps are based on forward West Texas Intermediate (“WTI”) crude oil prices, as applicable. | |
[2] | Volumes for crude oil are stated in barrels. |
Fair Value of Financial Instr51
Fair Value of Financial Instruments (Schedule of Financial Instruments at Fair Value) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | $ 1,502 | $ 4,305 |
Liabilities, gross | (497) | (661) |
Total assets, fair value, net | 1,005 | 3,644 |
Rabbi trust | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Rabbi trust | 1,502 | 4,208 |
Atlas Growth Partners, L.P | Swap | Commodity Contract | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 97 | |
Liabilities, gross | (497) | (661) |
Level 1 | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 1,502 | 4,208 |
Total assets, fair value, net | 1,502 | 4,208 |
Level 1 | Rabbi trust | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Rabbi trust | 1,502 | 4,208 |
Level 2 | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 97 | |
Liabilities, gross | (497) | (661) |
Total assets, fair value, net | (497) | (564) |
Level 2 | Atlas Growth Partners, L.P | Swap | Commodity Contract | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 97 | |
Liabilities, gross | $ (497) | $ (661) |
Fair Value of Financial Instr52
Fair Value of Financial Instruments (Narrative) (Details) $ / shares in Units, $ in Thousands | 12 Months Ended |
Dec. 31, 2017USD ($)$ / shares | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |
Long-term debt | $ | $ 79,350 |
Level 3 | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |
Warrants fair value unit price on the date of issuance | $ 0.50 |
Warrants fair value assumptions, exercise price | $ 0.20 |
Warrants fair value assumptions, risk free rate | 1.80% |
Warrants fair value assumptions, expected term | 10 years |
Warrants fair value assumptions, estimated volatility rate | 57.00% |
Estimated fair value per warrant | $ 0.40 |
First and Second Lien Credit Agreement | Level 1 | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |
Long-term debt | $ | $ 79,500 |
Certain Relationships and Rel53
Certain Relationships and Related Party Transactions (Narrative) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2014 | |
Related Party Transaction [Line Items] | ||||||
Asset retirement obligation | $ 189 | $ 184 | $ 113,909 | $ 108,101 | ||
Other income (loss) | 6,855 | (12,008) | $ (1,181) | |||
Relationship With Drilling Partnerships | ||||||
Related Party Transaction [Line Items] | ||||||
Capital raised from investors | $ 36,700 | |||||
Accrued well drilling and completion costs | $ 13,300 | |||||
Funds transferred to partners | $ 5,200 | |||||
Oil and gas properties transferred | 7,200 | |||||
Asset retirement obligation | $ 12,400 | |||||
Other income (loss) | (6,200) | |||||
Titan | ||||||
Related Party Transaction [Line Items] | ||||||
Accounts Payable, Related Parties, Current | $ 9,600 | 3,300 | ||||
Relationship with AGP | ||||||
Related Party Transaction [Line Items] | ||||||
Percentage of capital contribution | 1.00% | |||||
Payment for management fee | $ 2,300 | 2,300 | ||||
Relationship with Lightfoot | Jonathan Cohen | ||||||
Related Party Transaction [Line Items] | ||||||
Percentage of distributions receives excluding return of capital | 10.00% | |||||
Portion of proposed transaction received based on agreement | $ 2,000 | |||||
Relationship with Lightfoot | Daniel Herz | ||||||
Related Party Transaction [Line Items] | ||||||
Recognition amount received in connection with proposed transaction | $ 200 | |||||
Percentage of recognition received in connection with proposed transaction of aggregate amount | 10.00% | |||||
Relationship with Titan | ||||||
Related Party Transaction [Line Items] | ||||||
Accounts Payable, Related Parties, Current | $ 100 | $ 800 |
Commitments and Contingencies (
Commitments and Contingencies (Narrative) (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Operating leases, rent expense, net | $ 200,000 | $ 7,000,000 | $ 16,200,000 |
Percentage of present value of future cash flows | 10.00% | ||
Net partnership revenues subordinated | 800,000 | 1,700,000 | |
Environmental remediation expense | $ 0 | $ 0 | $ 0 |
Minimum | |||
Partnership obligations to purchase units from investor partners | 5.00% | ||
Investor partners return on investment | 10.00% | ||
Maximum | |||
Partnership obligations to purchase units from investor partners | 10.00% | ||
Percentage on unhedged revenue | 50.00% | ||
Investor partners return on investment | 12.00% |
Issuances of Units (Common Unit
Issuances of Units (Common Unit Purchase Agreement) (Details) - USD ($) $ / shares in Units, $ in Thousands | May 05, 2017 | Jul. 12, 2016 | Apr. 27, 2016 | Mar. 18, 2016 | Jan. 07, 2016 | Dec. 31, 2017 | Dec. 31, 2016 |
Capital Unit [Line Items] | |||||||
Warrants | $ 1,868 | $ 1,868 | |||||
Average closing price of common unit | $ 1 | ||||||
Consecutive trading days | 30 days | 30 days | 30 days | ||||
Series A Preferred Equity | |||||||
Capital Unit [Line Items] | |||||||
Conversion of Series A preferred units to common units | 1,900,000 | ||||||
Common Unitholders' Equity (Deficit) | |||||||
Capital Unit [Line Items] | |||||||
Conversion of Series A preferred units to common units | 5,900,000 | ||||||
Maximum | |||||||
Capital Unit [Line Items] | |||||||
Average closing price of common unit | $ 1 | ||||||
Average market capitalization | $ 50,000 | ||||||
Stockholders' equity | $ 50,000 | ||||||
Minimum | |||||||
Capital Unit [Line Items] | |||||||
Average market capitalization | $ 15,000 | ||||||
Second lien term loan facility | |||||||
Capital Unit [Line Items] | |||||||
Warrant to purchase common units | 4,668,044 | ||||||
Investment warrants exercise price | $ 0.20 | ||||||
Warrants, expiration date | Mar. 30, 2026 | ||||||
Debt Instrument, Unamortized Discount | $ 1,900 | $ 800 | |||||
Warrants | $ 1,900 | ||||||
Second lien term loan facility | Maximum | |||||||
Capital Unit [Line Items] | |||||||
Warrant to purchase common units | 4,668,044 |
Issuances of Units (Preferred U
Issuances of Units (Preferred Unit Purchase Agreement) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | Feb. 27, 2015 | Dec. 31, 2017 |
Capital Unit [Line Items] | ||
Percentage Of Common Unit Regular Quarterly Cash Distributions | 2.00% | |
Series A Convertible Preferred Units | ||
Capital Unit [Line Items] | ||
Partners' Capital Account, Units, Sold in Private Placement | 1.6 | |
Redemption price per unit | $ 25 | |
Subsidiary or Equity Method Investee, Price-Per-Share | $ 25 | |
Partners' Capital Account, Private Placement of Units | $ 40 | |
Cash consideration | $ 150 | |
Percentage of Preferred Unit Regular Quarterly Cash Distributions | 2.00% | |
Conversion price policy description | The conversion price will be equal to the greater of (i) $8.00 per common unit; and (ii) the lower of (a) 110.0% of the volume weighted average price for our common units over the 30 trading days following the distribution date; and (b) $16.00 per common unit. | |
Volume weighted average price | 110.00% | |
Series A Convertible Preferred Units | Maximum | ||
Capital Unit [Line Items] | ||
Conversion per unit | $ 16 | |
Series A Convertible Preferred Units | Minimum | ||
Capital Unit [Line Items] | ||
Conversion per unit | $ 8 | |
Series A Convertible Preferred Units | Private Placement | Maximum | ||
Capital Unit [Line Items] | ||
Percentage of Preferred Unit Regular Quarterly Cash Distributions | 10.00% | |
Series A Convertible Preferred Units | First Anniversary | Private Placement | Maximum | ||
Capital Unit [Line Items] | ||
Percentage of Preferred Unit Regular Quarterly Cash Distributions | 12.00% | |
Series A Convertible Preferred Units | Second Anniversary | Private Placement | Maximum | ||
Capital Unit [Line Items] | ||
Percentage of Preferred Unit Regular Quarterly Cash Distributions | 14.00% | |
Series A Convertible Preferred Units | Third Anniversary | Private Placement | Maximum | ||
Capital Unit [Line Items] | ||
Percentage of Preferred Unit Regular Quarterly Cash Distributions | 16.00% |
Issuances of Units (Atlas Resou
Issuances of Units (Atlas Resource Partners) (Details) - USD ($) | Jul. 12, 2016 | Mar. 18, 2016 | Jan. 07, 2016 | Nov. 30, 2015 | Aug. 31, 2015 | May 31, 2015 | Apr. 30, 2015 | Jul. 27, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Capital Unit [Line Items] | |||||||||||
Average closing price of common unit | $ 1 | ||||||||||
Consecutive trading days | 30 days | 30 days | 30 days | ||||||||
Aggregate Offering Price Of Common Units (Maximum) | $ 100,000,000 | ||||||||||
Agent commission, maximum percentage, of the gross sales price of common limited partner units sold. | 2.00% | ||||||||||
Partners unit, issued | 245,175 | 9,803,451 | |||||||||
Net proceeds from issuance of common limited partner units | $ 200,000 | $ 44,200,000 | |||||||||
Payments for commissions and offering expenses | $ 4,000 | 1,100,000 | |||||||||
Arkoma Acquisition | |||||||||||
Capital Unit [Line Items] | |||||||||||
Partners unit, issued | 6,500,000 | ||||||||||
Partners Capital Account Units Date Of Sale | May 2,015 | ||||||||||
Subsidiary or Equity Method Investee, Price-Per-Share | $ 7.97 | ||||||||||
Partners Capital Account Sale Of Units | $ 49,700,000 | ||||||||||
Class E Preferred Units | |||||||||||
Capital Unit [Line Items] | |||||||||||
Partners unit, issued | 255,000 | ||||||||||
Partners' Capital Account, Units, Percentage | 10.75% | ||||||||||
Partners Capital Account Units Date Of Sale | April 2,015 | ||||||||||
Partners Capital Account Sale Of Units | $ 6,000,000 | ||||||||||
Public offer price per share | $ 25 | ||||||||||
Equity Distribution Agreement with MLV & Co. LLC | |||||||||||
Capital Unit [Line Items] | |||||||||||
Net proceeds from issuance of common limited partner units | 900,000 | ||||||||||
Payments for commissions and offering expenses | $ 300,000 | ||||||||||
Equity Distribution Agreement with MLV & Co. LLC | Class D Preferred Units | |||||||||||
Capital Unit [Line Items] | |||||||||||
Partners unit, issued | 0 | 0 | 90,328 | ||||||||
Partners' Capital Account, Units, Percentage | 8.625% | ||||||||||
Equity Distribution Agreement with MLV & Co. LLC | Class E Preferred Units | |||||||||||
Capital Unit [Line Items] | |||||||||||
Partners unit, issued | 0 | 0 | 1,083 | ||||||||
Partners' Capital Account, Units, Percentage | 10.75% | ||||||||||
Equity Distribution Agreement with MLV & Co. LLC | Class D and Class E Preferred Units | |||||||||||
Capital Unit [Line Items] | |||||||||||
Net offering expenses incurred | $ 100,000 |
Issuances of Units (Atlas Growt
Issuances of Units (Atlas Growth Partners) (Details) - USD ($) $ / shares in Units, $ in Millions | Jun. 30, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Capital Unit [Line Items] | ||||
Reclassification of offering cost to other loss | $ 5.3 | |||
Offering cost previously capitalized | $ 1.5 | |||
Partners unit, issued | 245,175 | 9,803,451 | ||
Gain on sale of subsidiary unit issuances | $ 0.2 | |||
Atlas Growth Partners, L.P | ||||
Capital Unit [Line Items] | ||||
Primary offering suspension date | Nov. 2, 2016 | |||
Common limited partner units issued | $ 233 | |||
Percentage of warrants to purchase additional common units in amount equal to | 10.00% | |||
Warrants, exercise price | $ 10 | $ 10 | ||
Common limited partner number of units purchased | 300,000 | |||
Common limited partner units purchased | $ 2.7 | |||
Partners unit, issued | 2,330,041 | 12,623,500 | ||
Subsidiary or Equity Method Investee, Price-Per-Share | $ 10 | |||
Warrants received | 1,262,350 | |||
Atlas Growth Partners, L.P | Private Placement | ||||
Capital Unit [Line Items] | ||||
Common limited partner units issued | $ 500 | |||
Number of days extension private placement offering | two 90 day | |||
Issuance of units in initial public offering | 23,300,410 | |||
Fees and commission and expenses | $ 203.4 | |||
Common limited partner number of units purchased | 500,010 | |||
Common limited partner units purchased | $ 5 |
Cash Distributions - Additional
Cash Distributions - Additional Information (Details) - USD ($) | Jul. 25, 2015 | Dec. 31, 2015 | Nov. 30, 2015 | Oct. 31, 2015 | Sep. 30, 2015 | Aug. 31, 2015 | Jul. 31, 2015 | Jun. 30, 2015 | May 31, 2015 | Apr. 30, 2015 | Mar. 31, 2015 | Feb. 28, 2015 | Jan. 31, 2015 | Jun. 30, 2016 | Mar. 31, 2016 | Aug. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Common Limited Partners | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 5,100,000 | $ 126,300,000 | |||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $ 0.0125 | $ 0.1083 | $ 0.1083 | $ 0.1083 | $ 0.1083 | $ 0.1083 | $ 0.1083 | $ 0.1083 | $ 0.1083 | $ 0.1083 | $ 0.1966 | $ 0.1966 | $ 0.0125 | ||||||
Class C Preferred Limited Partners | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 2,500,000 | 7,800,000 | |||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | 0.17 | 0.17 | 0.17 | 0.17 | 0.17 | 0.17 | 0.17 | 0.17 | 0.17 | 0.17 | 0.1966 | 0.1966 | $ 0.0125 | ||||||
Class A General Partner | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 200,000 | 4,800,000 | |||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $ 0.0125 | $ 0.1083 | $ 0.1083 | $ 0.1083 | $ 0.1083 | 0.1083 | 0.1083 | 0.1083 | 0.1083 | 0.1083 | 0.1966 | 0.1966 | $ 0.0125 | ||||||
Class B Preferred Limited Partners | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | 42,000 | ||||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $ 0.1333 | $ 0.1333 | $ 0.1333 | $ 0.1333 | $ 0.1333 | $ 0.1966 | $ 0.1966 | ||||||||||||
Atlas Resource Partners, L.P. | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Policy, Members or Limited Partners, Description | ARP had a monthly cash distribution program whereby ARP distributed all of its available cash (as defined in the partnership agreement) for that month to its unitholders within 45 days from the month end. | ||||||||||||||||||
Atlas Resource Partners, L.P. | Class D Preferred Limited Partners | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 8,500,000 | ||||||||||||||||||
Atlas Resource Partners, L.P. | Class D Preferred Limited Partners | October 15, 2015 – April 14, 2016 | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 4,400,000 | ||||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $ 0.5390625 | $ 0.6169270 | |||||||||||||||||
Atlas Resource Partners, L.P. | Class D Preferred Limited Partners | October 02, 2014 – January 14, 2015 | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 8,500,000 | ||||||||||||||||||
Atlas Resource Partners, L.P. | Class D Preferred Limited Partners | January 15, 2015 – October 14, 2015 | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 8,500,000 | ||||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $ 0.539063 | ||||||||||||||||||
Atlas Resource Partners, L.P. | Class E Preferred Limited Partners | October 15, 2015 – April 14, 2016 | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 300,000 | ||||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $ 0.671875 | ||||||||||||||||||
Atlas Resource Partners, L.P. | Class E Preferred Limited Partners | April 14, 2015 - October 14, 2015 | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 300,000 | ||||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $ 0.6793 | ||||||||||||||||||
Atlas Resource Partners, L.P. | Preferred Class B | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Preferred Unit Regular Monthly Cash Distributions Per Unit | $ 0.1333 | ||||||||||||||||||
Conversion of Class B preferred units (units) | 39,654 | ||||||||||||||||||
Atlas Resource Partners, L.P. | Class C Preferred Units | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Preferred Unit Regular Monthly Cash Distributions Per Unit | 0.17 | ||||||||||||||||||
Atlas Resource Partners, L.P. | Preferred class D | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | 0.5390625 | ||||||||||||||||||
Preferred Unit Regular Cash Distributions Per Unit | $ 2.15625 | ||||||||||||||||||
Partners' Capital Account, Units, Percentage | 8.625% | ||||||||||||||||||
Preferred Stock Liquidation Preference | $ 25 | ||||||||||||||||||
Preferred stock units accrued distributions | $ 3,400,000 | ||||||||||||||||||
Atlas Resource Partners, L.P. | Preferred class E | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | 0.671875 | ||||||||||||||||||
Preferred Unit Regular Cash Distributions Per Unit | $ 2.6875 | ||||||||||||||||||
Partners' Capital Account, Units, Percentage | 10.75% | ||||||||||||||||||
Preferred Stock Liquidation Preference | $ 25 | ||||||||||||||||||
Preferred stock units accrued distributions | $ 300,000 | ||||||||||||||||||
Atlas Resource Partners, L.P. | Minimum | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Percentage Of Distributions In Excess Of Targets | 13.00% | ||||||||||||||||||
Atlas Resource Partners, L.P. | Minimum | Preferred Class B | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $ 0.40 | ||||||||||||||||||
Atlas Resource Partners, L.P. | Minimum | Class C Preferred Units | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $ 0.51 | ||||||||||||||||||
Atlas Resource Partners, L.P. | Maximum | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Percentage Of Distributions In Excess Of Targets | 48.00% | ||||||||||||||||||
Atlas Growth Partners, L.P | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Quarterly cash distribution target | $ 0.175 | ||||||||||||||||||
Yearly cash distribution target | $ 0.70 | ||||||||||||||||||
Atlas Growth Partners, L.P | Common Limited Partners | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 12,200,000 | $ 10,500,000 | |||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $ 0.1750 | $ 0.1750 | $ 0.1750 | ||||||||||||||||
Atlas Growth Partners, L.P | Class A General Partner | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | 300,000 | $ 200,000 | |||||||||||||||||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $ 0.1750 | $ 0.1750 | $ 0.1750 | ||||||||||||||||
Class A Preferred Units | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 1,000,000 | $ 2,700,000 | |||||||||||||||||
Atlas Energy | |||||||||||||||||||
Distribution Made To Limited Partner [Line Items] | |||||||||||||||||||
Distribution Policy, Members or Limited Partners, Description | We have a cash distribution policy under which we distribute, within 50 days following the end of each calendar quarter, all of our available cash (as defined in our limited liability company agreement) for that quarter to our unitholders. |
Share Based Compensation Plan60
Share Based Compensation Plans (2015 Long Term Incentive Plan Narrative) (Details) - 2015 Long Term Incentive Plan | 12 Months Ended |
Dec. 31, 2017shares | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |
Share-based Compensation Arrangement by Share-based Payment Award, Description | Our Board of Directors approved and adopted the 2015 Long-Term Incentive Plan (“2015 LTIP”) effective February 2015. The 2015 LTIP provides equity incentive awards to our officers, employees and managing board members and our affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for us. The 2015 LTIP is administered by a committee consisting of the Board of Directors or committee of the Board of Directors or board of an affiliate appointed by the Board of Directors (the “LTIP Committee”). |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 5,250,000 |
Phantom Units, Restricted Units and Unit Options Outstanding | 2,855,152 |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 2,043,796 |
Share Based Compensation Plan61
Share Based Compensation Plans (2015 LTIP Phantom Unit Activity) (Details) - 2015 Phantom Units - USD ($) | Feb. 20, 2017 | May 12, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Share Based Compensation Arrangement By Share Based Payment Award Number Of Outstanding Units To Vest Within Next Twelve Months | 2,379,564 | |||||
Distribution Equivalent Rights Paid On Unissued Units Under Incentive Plans | $ 0 | $ 0 | $ 0 | |||
Share based compensation arrangement By share based payment award deferred vesting payment to all employees | 25.00% | |||||
Granted (in units) | 2,110,000 | 2,794,710 | ||||
Number of Units, Outstanding, beginning of year | [1],[2] | 3,995,214 | 2,564,910 | |||
Number of Units, Granted | 2,110,000 | 2,794,710 | ||||
Number of Units, Vested | [3] | (317,226) | (33,826) | |||
Number of Units, Forfeited | (822,836) | (645,870) | (229,800) | |||
Number of Units, Outstanding, end of year | [1],[2] | 2,855,152 | 3,995,214 | 2,564,910 | ||
Weighted Average Grant Date Fair Value, Outstanding, beginning of year | [1],[2] | $ 3.99 | $ 6.46 | |||
Weighted Average Grant Date Fair Value, Granted | 1.53 | $ 6.46 | ||||
Weighted Average Grant Date Fair Value, Vested | [3] | 1.24 | 6.97 | |||
Weighted Average Grant Date Fair Value, Forfeited | 4.54 | 5.58 | 6.43 | |||
Weighted Average Grant Date Fair Value, Outstanding, end of year | [1],[2] | $ 4.14 | $ 3.99 | $ 6.46 | ||
Non-cash compensation expense (reversal) recognized (in thousands) | $ (135,000) | $ 4,984,000 | $ 5,678,000 | |||
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested In Period Intrinsic Value | 200,000 | $ 31,000 | $ 0 | |||
Share Based Compensation Arrangement By Share Based Payment Award Other Than Options Outstanding Intrinsic Value | 100,000 | |||||
Liabilities Related to Outstanding Phantom Units | $ 1,000 | |||||
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Units Classified Within Liabilities | 22,972 | |||||
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Weighted Average Grant Date Fair Value Units Classified Within Liabilities | $ 9.07 | |||||
Unrecognized compensation expense related to unvested phantom units | $ 1,300,000 | |||||
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition | 10 months 24 days | |||||
Board of Directors | ||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||||
Granted (in units) | 911,900 | |||||
Number of Units, Granted | 911,900 | |||||
[1] | The aggregate intrinsic value of phantom unit awards outstanding at December 31, 2017 was $0.1 million. | |||||
[2] | There was approximately $1,000 recognized as liabilities on our consolidated balance sheet at December 31, 2017 representing 22,972 units, due to the option of the Participants to settle in cash instead of units. The respective weighted average grant date fair value for these units was $9.07 at December 31, 2017. | |||||
[3] | The intrinsic value of phantom awards vested during the years ended December 31, 2017 and 2016 was approximately $0.2 million and $31,000. No phantom unit awards vested during the years ended December 31, 2015. |
Share Based Compensation Plan62
Share Based Compensation Plans (2015 Unit Option Activity) (Details) - 2015 Unit Options - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights | The LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Generally, unit options to be granted under the 2015 LTIP will vest over a designated period of time. | ||
Years From Date Of Grant Unit Option Awards Expire | 10 years | ||
Share Based Compensation Arrangement By Share Based Payment Award Number Of Outstanding Units To Vest Within Next Twelve Months | 0 | ||
Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options | $ 0 | $ 0 | $ 0 |
Share Based Compensation Plan63
Share Based Compensation Plans (Restricted Units Narrative) (Details) - Restricted Stock | 12 Months Ended |
Dec. 31, 2017shares | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |
Shares, Issued | 0 |
Shares, Granted | 0 |
Shares, Outstanding | 0 |
Share Based Compensation Plan64
Share Based Compensation Plans (ARP 2012 Long-Term Incentive Plan (Details) | 12 Months Ended |
Dec. 31, 2017 | |
ARP's 2012 Long-Term Incentive Plan | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |
Share-based Compensation Arrangement by Share-based Payment Award, Description | ARP’s 2012 Long-Term Incentive Plan (“2012 ARP LTIP”), effective March 2012, provided incentive awards to officers, employees and directors and employees of ARP’s general partner and its affiliates, consultants and joint venture partners (collectively, the “ARP Participants”), who performed services for ARP. The 2012 ARP LTIP was administered by the board of ARP’s general partner, a committee of the board or the board (or committee of the board) of an affiliate (the “ARP LTIP Committee”). |
Share Based Compensation Plan65
Share Based Compensation Plans (ARP 2012 LTIP Phantom Unit Activity) (Details) - Phantom Units - USD ($) | 7 Months Ended | 12 Months Ended | |
Jul. 27, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Number of Units, Outstanding, beginning of year | 302,105 | 799,192 | |
Number of units, Granted | 30,000 | 9,730 | |
Number of units, Vested | 24,679 | 472,278 | |
Number of units, Forfeited | 60,639 | 34,539 | |
Number of Units, Outstanding, end of year | 246,787 | 302,105 | |
Unit based compensation expense recognized | $ 300,000 | $ 4,100,000 | |
Atlas Resource Partners, L.P. | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Distribution Equivalent Rights Paid On Unissued Units Under Incentive Plans | $ 15,000 | $ 700,000 |
Share Based Compensation Plan66
Share Based Compensation Plans (ARP's 2012 ARP LTIP Unit Options) (Details) - 2012 ARP Long Term Incentive Plans Unit Options - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights | The ARP LTIP Committee determined the vesting and exercise restrictions applicable to an award of options, if any, and the method by which the exercise price may be paid by the ARP Participant. Unit option awards expired 10 years from the date of grant. | ||
Years From Date Of Grant Unit Option Awards Expire | 10 years | ||
Number of unit options Outstanding, beginning of year | 1,313,836 | 1,354,525 | 1,458,300 |
Number of unit options, Granted | 0 | 0 | |
Number of unit options, Exercised | 0 | 0 | |
Number of unit options, Forfeited | 40,689 | 103,775 | |
Number of unit options, Outstanding end of year | 1,313,836 | 1,354,525 | |
Share based compensation expense | $ 31,000 | $ 800,000 |
Share Based Compensation Plan67
Share Based Compensation Plans (ARP 2012 LTIP Restricted Units Narrative) (Details) - Restricted Stock - shares | 7 Months Ended | 12 Months Ended | ||
Jul. 27, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Shares, Granted | 0 | |||
Shares, Outstanding | 0 | |||
ARP | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Shares, Granted | 0 | 0 | 0 | |
Shares, Outstanding | 0 | 0 | 0 |
Operating Segment Information68
Operating Segment Information (Narrative) (Details) | 12 Months Ended |
Dec. 31, 2017Segment | |
Segment Reporting [Abstract] | |
Number of reportable operating segments | 3 |
Operating Segment Information69
Operating Segment Information (Operating Segment Data) (Details) - USD ($) $ in Thousands | Jul. 27, 2016 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | [1] | Mar. 31, 2016 | [1] | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |||
Segment Reporting Information [Line Items] | |||||||||||||||||
Revenues | $ 1,229 | $ 1,298 | $ 2,649 | $ 3,875 | $ 1,872 | [1] | $ 42,237 | [1],[2] | $ (13,804) | $ 106,853 | $ 9,051 | $ 137,158 | $ 753,493 | ||||
Depreciation, depletion and amortization expense | (3,576) | (82,381) | (166,929) | ||||||||||||||
Asset impairment | $ (41,900) | (41,879) | (973,981) | ||||||||||||||
Interest expense | (20,937) | (83,744) | (125,658) | ||||||||||||||
Gain (loss) on early extinguishment of debt, net | 20,418 | (4,726) | |||||||||||||||
Reorganization items, net | (21,649) | ||||||||||||||||
Other income (loss) | 6,855 | (12,008) | (1,181) | ||||||||||||||
Gain on deconsolidation | 46,951 | ||||||||||||||||
Atlas Resource Partners, L.P. | |||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||
Gain on deconsolidation | $ 46,400 | $ 46,900 | 46,951 | ||||||||||||||
Reportable Legal Entities | Atlas Resource Partners, L.P. | |||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||
Revenues | [3] | 125,582 | 740,033 | ||||||||||||||
Operating costs and expenses | (134,718) | (320,922) | |||||||||||||||
Depreciation, depletion and amortization expense | (67,513) | (157,978) | |||||||||||||||
Asset impairment | (966,635) | ||||||||||||||||
Interest expense | (68,883) | (102,133) | |||||||||||||||
Gain (loss) on early extinguishment of debt, net | 26,498 | ||||||||||||||||
Reorganization items, net | (21,649) | ||||||||||||||||
Other income (loss) | (6,625) | (1,181) | |||||||||||||||
Segment income (loss) | (147,308) | (808,816) | |||||||||||||||
Reportable Legal Entities | Atlas Growth Partners, L.P | |||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||
Revenues | [3] | 8,151 | 11,071 | 12,708 | |||||||||||||
Operating costs and expenses | (7,472) | (12,578) | (14,968) | ||||||||||||||
Depreciation, depletion and amortization expense | (3,576) | (14,868) | (8,951) | ||||||||||||||
Asset impairment | (41,879) | (7,346) | |||||||||||||||
Other income (loss) | (5,383) | ||||||||||||||||
Segment income (loss) | (2,897) | (63,637) | (18,557) | ||||||||||||||
Operating Segments | Corporate and Other | |||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||
Revenues | 900 | 505 | 752 | ||||||||||||||
General and administrative | [4] | (534) | (5,528) | (30,862) | |||||||||||||
Interest expense | (20,937) | (14,861) | (23,525) | ||||||||||||||
Gain (loss) on early extinguishment of debt, net | (6,080) | (4,726) | |||||||||||||||
Other income (loss) | 6,855 | ||||||||||||||||
Segment income (loss) | $ (13,716) | $ 20,987 | $ (58,361) | ||||||||||||||
[1] | For the fourth quarter, third quarter, second quarter and first quarter of the year ended December 31, 2017, approximately 2,896,000, 2,917,000 3,143,000 and 3,521,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit, because the inclusion of such units would have been anti-dilutive. | ||||||||||||||||
[2] | For the fourth quarter, second quarter and first quarter of the year ended December 31, 2016, approximately 9,709,000, 7,956,000 and 7,781,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit, because the inclusion of such units would have been anti-dilutive. | ||||||||||||||||
[3] | Revenues include respective portions of gains (losses) on mark—to—market derivatives. | ||||||||||||||||
[4] | As disclosed in Note 12, for the year ended December, 31, 2017, 822,836 phantom units under the 2015 LTIP were forfeited, primarily due to Titan’s completion of the majority of the sale of its Appalachian assets and reductions in workforce, which resulted in a $2.5 million reversal of previously recognized stock compensation expense recorded in general and administrative expenses on our combined consolidated statements of operations for the year ended December 31, 2017. |
Operating Segment Information70
Operating Segment Information (Reconciliation of Segment Income (Loss) to Net Loss) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Segment Reporting Information [Line Items] | |||
Net loss | $ (16,613) | $ (189,958) | $ (885,734) |
Reportable Legal Entities | Atlas Resource Partners, L.P. | |||
Segment Reporting Information [Line Items] | |||
Net loss | (147,308) | (808,816) | |
Reportable Legal Entities | Atlas Growth Partners, L.P | |||
Segment Reporting Information [Line Items] | |||
Net loss | (2,897) | (63,637) | (18,557) |
Operating Segments | Corporate and Other | |||
Segment Reporting Information [Line Items] | |||
Net loss | $ (13,716) | $ 20,987 | $ (58,361) |
Operating Segment Information71
Operating Segment Information (Reconciliation of Segment Revenues to Total Revenues) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||||||||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | [1] | Sep. 30, 2016 | [1],[2] | Jun. 30, 2016 | [1] | Mar. 31, 2016 | [1] | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Segment Reporting Information [Line Items] | ||||||||||||||||
Total revenues | $ 1,229 | $ 1,298 | $ 2,649 | $ 3,875 | $ 1,872 | $ 42,237 | $ (13,804) | $ 106,853 | $ 9,051 | $ 137,158 | $ 753,493 | |||||
Reportable Legal Entities | Atlas Resource Partners, L.P. | ||||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||||
Total revenues | [3] | 125,582 | 740,033 | |||||||||||||
Reportable Legal Entities | Atlas Growth Partners, L.P | ||||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||||
Total revenues | [3] | 8,151 | 11,071 | 12,708 | ||||||||||||
Operating Segments | Corporate and Other | ||||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||||
Total revenues | $ 900 | $ 505 | $ 752 | |||||||||||||
[1] | For the fourth quarter, third quarter, second quarter and first quarter of the year ended December 31, 2017, approximately 2,896,000, 2,917,000 3,143,000 and 3,521,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit, because the inclusion of such units would have been anti-dilutive. | |||||||||||||||
[2] | For the fourth quarter, second quarter and first quarter of the year ended December 31, 2016, approximately 9,709,000, 7,956,000 and 7,781,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit, because the inclusion of such units would have been anti-dilutive. | |||||||||||||||
[3] | Revenues include respective portions of gains (losses) on mark—to—market derivatives. |
Operating Segment Information72
Operating Segment Information (Capital Expenditures) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Segment Reporting Information [Line Items] | ||
Capital expenditures | $ 27,757 | $ 156,360 |
Reportable Legal Entities | Atlas Resource Partners, L.P. | ||
Segment Reporting Information [Line Items] | ||
Capital expenditures | 21,155 | 127,138 |
Reportable Legal Entities | Atlas Growth Partners, L.P | ||
Segment Reporting Information [Line Items] | ||
Capital expenditures | $ 6,602 | $ 29,222 |
Operating Segment Information73
Operating Segment Information (Balance Sheet) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Segment Reporting Information [Line Items] | ||
Total assets | $ 84,048 | $ 105,076 |
Reportable Legal Entities | Atlas Growth Partners, L.P | ||
Segment Reporting Information [Line Items] | ||
Total assets | 74,219 | 78,500 |
Operating Segments | Corporate and Other | ||
Segment Reporting Information [Line Items] | ||
Total assets | $ 9,829 | $ 26,576 |
Operating Segment Information74
Operating Segment Information (Parenthetical) (Details) - 2015 Phantom Units - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Segment Reporting Information [Line Items] | |||
Number of units, Forfeited | 822,836 | 645,870 | 229,800 |
Reversal of stock compensation expense recognized | $ 2.5 |
Subsequent Events (Narrative) (
Subsequent Events (Narrative) (Details) - First Lien Credit Agreement - Credit Agreements | Apr. 26, 2018 | Sep. 29, 2017 | Apr. 26, 2018 | Dec. 31, 2017 |
Subsequent Event [Line Items] | ||||
Line of credit facility extended expiration date | Jun. 30, 2018 | Jun. 30, 2018 | ||
Riverstone Credit Agreement | Subsequent Event | ||||
Subsequent Event [Line Items] | ||||
Line of credit facility extended expiration date | Jun. 30, 2018 | Jun. 30, 2018 |
Supplemental Oil and Gas Info76
Supplemental Oil and Gas Information (Reserve Quantity Information) (Details) | 12 Months Ended | ||||||
Dec. 31, 2017MMcfeMMcfMBbls | Dec. 31, 2016MMcfeMMcfMBbls | Dec. 31, 2015MMcfeMMcfMBbls | Dec. 31, 2014MMcfeMMcfMBbls | ||||
Reserve Quantities [Line Items] | |||||||
Balance | MMcfe | 23,356 | 974,040 | 1,582,858 | ||||
Extensions, discoveries and other additions | MMcfe | 1,599 | 29,324 | [1] | ||||
Sales of reserves in-place | MMcfe | (794,553) | [2] | (2,726) | ||||
Purchase of reserves in-place | MMcfe | 1,694 | ||||||
Transfers to Drilling Partnerships | MMcfe | (7,903) | ||||||
Revisions of previous estimates | MMcfe | [3] | 8,949 | (109,540) | (529,022) | |||
Production | MMcfe | (1,092) | (49,884) | (98,491) | ||||
Balance | MMcfe | 31,213 | 23,356 | 974,040 | ||||
Proved developed reserves | MMcfe | 6,069 | 6,802 | 770,508 | 1,149,240 | |||
Proved undeveloped reserves | MMcfe | 25,144 | 16,554 | 203,532 | 433,618 | |||
Natural Gas Reserves | |||||||
Reserve Quantities [Line Items] | |||||||
Balance | MMcf | 1,432 | 607,686 | 1,064,878 | ||||
Extensions, discoveries and other additions | MMcf | 789 | 6,806 | [1] | ||||
Sales of reserves in-place | MMcf | (530,817) | [2] | (2,714) | ||||
Purchase of reserves in-place | MMcf | 1,616 | ||||||
Transfers to Drilling Partnerships | MMcf | (2,959) | ||||||
Revisions of previous estimates | MMcf | [3] | 548 | (37,822) | (379,058) | |||
Production | MMcf | (114) | (40,020) | (79,267) | ||||
Balance | MMcf | 1,866 | 1,432 | 607,686 | ||||
Proved developed reserves | MMcf | 613 | 652 | 568,794 | 889,074 | |||
Proved undeveloped reserves | MMcf | 1,253 | 780 | 38,892 | 175,804 | |||
Oil | |||||||
Reserve Quantities [Line Items] | |||||||
Balance | 3,387 | 52,583 | 62,950 | ||||
Extensions, discoveries and other additions | 135 | 3,460 | [1] | ||||
Sales of reserves in-place | (37,926) | [2] | (2) | ||||
Purchase of reserves in-place | 13 | ||||||
Transfers to Drilling Partnerships | (482) | ||||||
Revisions of previous estimates | [3] | 1,231 | (10,227) | (11,224) | |||
Production | (143) | (1,191) | (2,119) | ||||
Balance | 4,475 | 3,387 | 52,583 | ||||
Proved developed reserves | 788 | 925 | 27,130 | 31,151 | |||
Proved undeveloped reserves | 3,687 | 2,462 | 25,453 | 31,799 | |||
Natural Gas Liquids Reserves | |||||||
Reserve Quantities [Line Items] | |||||||
Balance | 267 | 8,476 | 23,380 | ||||
Extensions, discoveries and other additions | [1] | 293 | |||||
Sales of reserves in-place | [2] | (6,030) | |||||
Transfers to Drilling Partnerships | (342) | ||||||
Revisions of previous estimates | [3] | 169 | (1,726) | (13,770) | |||
Production | (20) | (453) | (1,085) | ||||
Balance | 416 | 267 | 8,476 | ||||
Proved developed reserves | 121 | 100 | 6,489 | 12,210 | |||
Proved undeveloped reserves | 295 | 167 | 1,987 | 11,170 | |||
[1] | For the year ended December 31, 2015, the increase represents PUD additions related to our development and leasing activity in the Eagle Ford Shale. | ||||||
[2] | For the year ended December 31, 2016, the decrease was due to the deconsolidation of ARP for financial reporting purposes in connection with ARP’s Chapter 11 Filings (see Note 2). | ||||||
[3] | See “Revisions of Previous Estimates” section below for additional discussion and analysis of significant components of revisions of previous estimates. |
Supplemental Oil and Gas Info77
Supplemental Oil and Gas Information (Schedule of Revisions of Previous Estimates) (Details) | 12 Months Ended | ||
Dec. 31, 2017$ / bbl$ / MMBTU | Dec. 31, 2016$ / bbl$ / MMBTU | Dec. 31, 2015$ / bbl$ / MMBTU | |
Natural Gas | |||
Average Sales Price And Production Costs Per Unit Of Production [Line Items] | |||
Unadjusted Prices | $ / MMBTU | 2.98 | 2.48 | 2.59 |
Oil | |||
Average Sales Price And Production Costs Per Unit Of Production [Line Items] | |||
Unadjusted Prices | 51.34 | 42.75 | 50.28 |
Natural Gas Liquids | |||
Average Sales Price And Production Costs Per Unit Of Production [Line Items] | |||
Unadjusted Prices | 20.33 | 19.57 | 11.02 |
Supplemental Oil and Gas Info78
Supplemental Oil and Gas Information (Narrative) (Details) - MMcfe | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Extractive Industries [Abstract] | |||
Revisions of previous estimates, positive revisions due to modification in development plan, focusing on longer lateral lengths | 8,585 | ||
Revisions of previous estimates, positive revisions due to increase in pricing | 1,208 | ||
Revisions of previous estimates, negative revisions due to production underperforming | 844 | 46,804 | |
Revisions of previous estimates, negative revisions due to decreases in pricing | 58,818 | 258,667 | |
Revisions of previous estimates, negative revisions due to removal of proved undeveloped properties | 60,860 | 223,551 | |
Revisions of previous estimates, partially offset by positive revisions due to production outperforming | 10,133 |
Supplemental Oil and Gas Info79
Supplemental Oil and Gas Information (Schedule of Capitalized Costs Related to Oil and Gas Producing Activities) (Details) $ in Thousands | Dec. 31, 2017USD ($)Well | Dec. 31, 2016USD ($) | |
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items] | |||
Proved properties | $ 147,932 | $ 84,631 | |
Unproved properties | 63,314 | ||
Support equipment | 3,188 | 3,188 | |
Capitalized Costs Related To Oil And Gas Producing Activities | |||
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items] | |||
Proved properties | 147,932 | 84,631 | |
Unproved properties | [1] | 63,314 | |
Support equipment | 29 | 29 | |
Total natural gas and oil properties | 147,961 | 147,974 | |
Accumulated depreciation, depletion and amortization | (85,328) | (81,901) | |
Net capitalized costs | 62,633 | $ 66,073 | |
Atlas Growth Partners, L.P Capitalized Costs Related To Oil And Gas Producing Activities | |||
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items] | |||
Unproved properties transferred to proved natural gas and oil properties | $ 4,200 | ||
Atlas Growth Partners, L.P Capitalized Costs Related To Oil And Gas Producing Activities | Eagle Ford Acquisition | |||
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items] | |||
Number of well planned for drilling and developing | Well | 1 | ||
[1] | As of December 31, 2017, we classified $4.2 million of AGP’s unproved properties to proved natural gas and oil properties as management finalized capital plans for drilling and developing one well within our Eagle Ford operating area in 2018. |
Supplemental Oil and Gas Info80
Supplemental Oil and Gas Information (Schedule of Results of Operations from Oil and gas Producing Activities) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Supplemental Oil and Gas Information (Unaudited) [Abstract] | ||||
Long-lived asset impairment | $ (41,879) | $ (973,981) | ||
Revenues | $ 7,841 | 129,993 | 368,845 | |
Production costs | (2,528) | (78,034) | (171,882) | |
Depreciation, depletion and amortization | (3,410) | (79,013) | (153,938) | |
Long-lived asset impairment | [1] | (41,879) | (973,981) | |
Results of Operations, Income before Income Taxes, Total | $ 1,903 | (68,933) | (930,956) | |
Atlas Resource Partners, L.P. | Proved Properties | ||||
Supplemental Oil and Gas Information (Unaudited) [Abstract] | ||||
Long-lived asset impairment | (960,000) | |||
Atlas Growth Partners, L.P | Unproved Gas and Oil Properties | Eagle Ford Acquisition | ||||
Supplemental Oil and Gas Information (Unaudited) [Abstract] | ||||
Long-lived asset impairment | (16,500) | |||
Atlas Growth Partners, L.P | Proved Properties | Eagle Ford Acquisition | ||||
Supplemental Oil and Gas Information (Unaudited) [Abstract] | ||||
Long-lived asset impairment | $ (25,400) | |||
Reclassification out of Accumulated Other Comprehensive Income | ||||
Supplemental Oil and Gas Information (Unaudited) [Abstract] | ||||
Net future hedge gains reclassified from accumulated other comprehensive income | 85,800 | |||
New Albany Shale | Atlas Resource Partners, L.P. | Unproved Gas and Oil Properties | ||||
Supplemental Oil and Gas Information (Unaudited) [Abstract] | ||||
Long-lived asset impairment | (6,600) | |||
Marble Falls and Mississippi Lime | Atlas Growth Partners, L.P | Proved Properties | ||||
Supplemental Oil and Gas Information (Unaudited) [Abstract] | ||||
Long-lived asset impairment | $ (7,400) | |||
[1] | For the year ended December 31, 2016, we recognized $25.4 million and $16.5 million of asset impairment related to AGP’s proved and unproved oil and gas properties in the Eagle Ford operating area, respectively, which were impaired due to lower forecasted commodity prices and timing of capital financing and deployment for the development of our undeveloped properties. During the year ended December 31, 2015, we recognized $974 million of asset impairment of which $960 million related to ARP’s proved oil and gas properties in the Barnett, Coal-bed Methane, Rangely, Southern Appalachia, Marcellus and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices, net of $85.8 million of future hedge gains reclassified from accumulated other comprehensive income, $6.6 million of asset impairments in ARP’s unproved gas and oil properties primarily related to ARP’s unproved acreage in the New Albany Shale, which was impaired due to expiring acreage and no intention to pursue development, and $7.4 million related to AGP’s proved oil and gas properties in the Marble Falls and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices. |
Supplemental Oil and Gas Info81
Supplemental Oil and Gas Information (Schedule of Costs Incurred in Oil and gas Producing Activities) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | ||
Supplemental Oil and Gas Information (Unaudited) [Abstract] | |||
Proved properties | $ 2,207 | $ 55,033 | |
Unproved properties | 43,820 | ||
Exploration costs | [1] | 825 | 1,601 |
Development costs | 16,792 | 102,110 | |
Total costs incurred in oil & gas producing activities | $ 19,824 | $ 202,564 | |
[1] | There were no exploratory wells drilled during the periods presented. |
Supplemental Oil and Gas Info82
Supplemental Oil and Gas Information (Schedule of Standardized Measure of Estimated Discounted Future Net Cash Flows) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Supplemental Oil and Gas Information (Unaudited) [Abstract] | |||
Future cash inflows | $ 243,644 | $ 145,857 | $ 3,910,339 |
Future production costs | (73,792) | (53,738) | (1,954,564) |
Future development costs | (68,321) | (51,942) | (1,289,841) |
Future net cash flows | 101,531 | 40,177 | 665,934 |
Less 10% annual discount for estimated timing of cash flows | (61,082) | (22,796) | (90,703) |
Standardized measure of discounted future net cash flows | $ 40,449 | $ 17,381 | $ 575,231 |
Supplemental Oil and Gas Info83
Supplemental Oil and Gas Information (Schedule of Changes in Discounted Future Net Cash Flows) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Supplemental Oil and Gas Information (Unaudited) [Abstract] | ||||
Balance, beginning of year | $ 17,381 | $ 575,231 | $ 2,236,764 | |
Sales and transfers of oil and gas, net of related costs | [1] | (5,403) | (59,246) | (137,942) |
Net changes in prices and production costs | [1] | 22,401 | (226,641) | (1,629,945) |
Revisions of previous quantity estimates | [1] | 15,568 | (32,208) | (41,147) |
Development costs incurred | [1] | 88,261 | ||
Changes in future development costs | [1] | (11,236) | 6,914 | (167,995) |
Transfers to Drilling Partnerships | [1] | (13,291) | ||
Extensions, discoveries, and improved recovery less related costs | [1] | (50) | 20,408 | |
Purchases of reserves in-place | [1] | 711 | ||
Sales of reserves in-place | [1] | (297,227) | (2,162) | |
Accretion of discount | [1] | 1,738 | 51,238 | 223,676 |
Estimated settlement of asset retirement obligations | [1] | (1,332) | (224) | |
Estimated proceeds on disposals of well equipment | [1] | (9) | (1,172) | |
Outstanding, end of year | $ 40,449 | $ 17,381 | $ 575,231 | |
[1] | (1)See “Reserve Quantity Information” and “Revisions of Previous Estimates” sections above for additional discussion and analysis of significant changes within the periods presented. |
Quarterly Results (Unaudited) -
Quarterly Results (Unaudited) - Schedule of Quarterly Financial Information (Details) - USD ($) $ / shares in Units, $ in Thousands | Jul. 27, 2016 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||||||||
Schedule Of Quarterly Financial Information [Line Items] | ||||||||||||||||||||
Revenues | $ 1,229 | $ 1,298 | $ 2,649 | $ 3,875 | $ 1,872 | [1] | $ 42,237 | [1],[2] | $ (13,804) | [1] | $ 106,853 | [1] | $ 9,051 | $ 137,158 | $ 753,493 | |||||
Net income (loss) | (944) | (7,341) | (3,425) | (4,903) | (51,537) | [2],[3] | 13,568 | [2],[3] | (150,717) | [2],[3] | (1,611) | [2],[3] | ||||||||
Loss attributable to non-controlling interests | 1,146 | 1,022 | 343 | 281 | 43,938 | 23,619 | [2] | 114,637 | (5,340) | 2,792 | 176,854 | 649,316 | ||||||||
Net income (loss) attributable to unitholders’/owner’s interests | $ 202 | $ (6,319) | $ (3,082) | $ (4,622) | $ (7,599) | $ 37,187 | [2] | $ (36,080) | $ (6,951) | |||||||||||
Basic | $ (0.03) | [1] | $ (0.20) | [1] | $ (0.10) | [1] | $ (0.18) | [1] | $ (0.29) | [4] | $ 1.41 | [2],[4] | $ (1.39) | [4] | $ (0.27) | [4] | ||||
Diluted | $ (0.03) | [1] | $ (0.20) | [1] | $ (0.10) | [1] | $ (0.18) | [1] | $ (0.29) | [4] | $ 1 | [2],[4] | $ (1.39) | [4] | $ (0.27) | [4] | ||||
Antidilutive Securities Excluded From Computation Of Diluted Earnings Attributable To Common Limited Partners Outstanding Units | 2,896,000 | 2,917,000 | 3,143,000 | 3,521,000 | 9,709,000 | 7,956,000 | 7,781,000 | |||||||||||||
Gains (losses) on mark to market derivatives | $ (310) | 18,601 | (268,085) | |||||||||||||||||
Gain on deconsolidation | 46,951 | |||||||||||||||||||
Asset impairment | $ 41,900 | 41,879 | $ 973,981 | |||||||||||||||||
Atlas Resource Partners, L.P. | ||||||||||||||||||||
Schedule Of Quarterly Financial Information [Line Items] | ||||||||||||||||||||
Gains (losses) on mark to market derivatives | $ 73,300 | |||||||||||||||||||
Gain on deconsolidation | $ 46,400 | $ 46,900 | $ 46,951 | |||||||||||||||||
[1] | For the fourth quarter, third quarter, second quarter and first quarter of the year ended December 31, 2017, approximately 2,896,000, 2,917,000 3,143,000 and 3,521,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit, because the inclusion of such units would have been anti-dilutive. | |||||||||||||||||||
[2] | For the fourth quarter, second quarter and first quarter of the year ended December 31, 2016, approximately 9,709,000, 7,956,000 and 7,781,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit, because the inclusion of such units would have been anti-dilutive. | |||||||||||||||||||
[3] | ARP was deconsolidated in the third quarter of 2016, resulting in the recognition of a $46.9 million gain in that quarter. | |||||||||||||||||||
[4] | Revenues include gains (losses) on mark to market derivatives. A $73.3 million loss on ARP’s mark-to-market derivatives is included for the second quarter related to increases in commodity future prices relative to ARP’s commodity fixed price swaps during the second quarter as compared to the prior year period. |