Document and Entity Information
Document and Entity Information - shares | 3 Months Ended | |
Mar. 31, 2016 | May. 12, 2016 | |
Document And Entity Information [Abstract] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Mar. 31, 2016 | |
Document Fiscal Year Focus | 2,016 | |
Document Fiscal Period Focus | Q1 | |
Entity Registrant Name | Atlas Energy Group, LLC | |
Entity Central Index Key | 1,623,595 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Accelerated Filer | |
Trading Symbol | ATLS | |
Entity Common Stock, Units Outstanding | 26,027,992 |
CONDENSED COMBINED CONSOLIDATED
CONDENSED COMBINED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands | Mar. 31, 2016 | Dec. 31, 2015 |
Current assets: | ||
Cash and cash equivalents | $ 47,994 | $ 31,214 |
Accounts receivable | 59,381 | 65,920 |
Current portion of derivative asset | 160,059 | 159,763 |
Subscriptions receivable | 19,877 | |
Prepaid expenses and other | 16,666 | 22,997 |
Total current assets | 284,100 | 299,771 |
Property, plant and equipment, net | 1,295,637 | 1,316,897 |
Goodwill and intangible assets, net | 14,062 | 14,095 |
Long-term derivative asset | 195,267 | 198,371 |
Other assets, net | 54,713 | 54,112 |
Total assets | 1,843,779 | 1,883,246 |
Current liabilities: | ||
Accounts payable | 48,985 | 52,550 |
Liabilities associated with drilling contracts | 21,483 | |
Current portion of derivative payable to Drilling Partnerships | 2,018 | 2,574 |
Accrued interest | 10,177 | 25,452 |
Accrued well drilling and completion costs | 4,731 | 33,555 |
Accrued liabilities | 32,120 | 42,440 |
Current portion of long-term debt | 976,795 | 4,250 |
Total current liabilities | 1,074,826 | 182,304 |
Long-term debt, net, less current portion | 647,604 | 1,568,064 |
Asset retirement obligations and other | $ 127,708 | $ 124,919 |
Commitments and contingencies (Note 8) | ||
Unitholders’ equity (deficit): | ||
Common unitholders’ equity (deficit) | $ (108,159) | $ (103,148) |
Series A preferred equity | 40,740 | 40,875 |
Accumulated other comprehensive income | 3,498 | 4,284 |
Unitholders'/owner's equity excluding non-controlling interests | (63,921) | (57,989) |
Non-controlling interests | 57,562 | 65,948 |
Total unitholders’ equity (deficit) | (6,359) | 7,959 |
Total liabilities and unitholders’ equity (deficit) | $ 1,843,779 | $ 1,883,246 |
CONDENSED COMBINED CONSOLIDATE3
CONDENSED COMBINED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Revenues: | ||
Gas and oil production | $ 51,593 | $ 106,560 |
Well construction and completion | 2,100 | 23,655 |
Gathering and processing | 1,495 | 2,184 |
Administration and oversight | 455 | 1,259 |
Well services | 4,432 | 6,624 |
Gain on mark-to-market derivatives | 46,453 | 105,585 |
Other, net | 325 | (68) |
Total revenues | 106,853 | 245,799 |
Costs and expenses: | ||
Gas and oil production | 36,656 | 45,989 |
Well construction and completion | 1,826 | 20,570 |
Gathering and processing | 2,279 | 2,417 |
Well services | 2,178 | 2,198 |
General and administrative | 21,920 | 41,928 |
Depreciation, depletion and amortization | 34,272 | 44,456 |
Total costs and expenses | 99,131 | 157,558 |
Operating income | 7,722 | 88,241 |
Gain (loss) on asset sales and disposal | 9 | (11) |
Interest expense | (29,448) | (34,751) |
Gain on early extinguishment of debt, net | 20,445 | 0 |
Net income (loss) | (1,272) | 53,479 |
Preferred unitholders’ dividends | (339) | (333) |
Income attributable to non-controlling interests | (5,340) | (58,298) |
Net loss attributable to unitholders’/owner’s interests | (6,951) | (5,152) |
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) | (6,951) | 5,323 |
Net loss attributable to unitholders’/owner’s interests | $ (6,951) | $ (5,152) |
Net income (loss) attributable to unitholders per common unit (Note 2): | ||
Basic | $ (0.27) | $ 0.20 |
Diluted | $ (0.27) | $ 0.18 |
Weighted average common units outstanding (Note 2): | ||
Basic | 26,028 | 26,011 |
Diluted | 26,028 | 30,976 |
CONDENSED COMBINED CONSOLIDATE4
CONDENSED COMBINED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Statement Of Income And Comprehensive Income [Abstract] | ||
Net income (loss) | $ (1,272) | $ 53,479 |
Other comprehensive loss: | ||
Reclassification to mark-to-market gains | (3,515) | (27,343) |
Total other comprehensive loss | (3,515) | (27,343) |
Comprehensive income (loss) | (4,787) | 26,136 |
Comprehensive loss attributable to non-controlling interests | (2,611) | (38,943) |
Comprehensive loss attributable to unitholders’ interest | $ (7,398) | $ (12,807) |
CONDENSED COMBINED CONSOLIDATE5
CONDENSED COMBINED CONSOLIDATED STATEMENT OF UNITHOLDERS' EQUITY (Unaudited) - 3 months ended Mar. 31, 2016 - USD ($) $ in Thousands | Total | Series A Preferred Equity | Common Unitholders' Equity (Deficit) | Accumulated Other Comprehensive Income | Non-Controlling Interest |
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 | (1,319) | $ 203 | $ (203) | (1,319) | |
Issuance of units , number of units | 8,109 | ||||
Distributions to non-controlling interests | (9,436) | (9,436) | |||
Net issued and unissued units under incentive plan | 1,915 | $ 1,962 | (47) | ||
Net issued and unissued units under incentive plan (units) | 17,226 | ||||
Distribution equivalent rights paid on unissued units under incentive plans | (11) | (11) | |||
Distribution payable | 335 | $ 338 | (3) | ||
Gain on sale from subsidiary unit issuances | $ 181 | (181) | |||
Dividends paid to preferred equity unitholders | (1,015) | (1,015) | |||
Other comprehensive loss | (3,515) | (786) | (2,729) | ||
Net income (loss) | (1,272) | 339 | (6,951) | 5,340 | |
Balance at Mar. 31, 2016 | $ (6,359) | $ 40,740 | $ (108,159) | $ 3,498 | $ 57,562 |
Balance units at Mar. 31, 2016 | 1,629,536 | 26,027,992 |
CONDENSED COMBINED CONSOLIDATE6
CONDENSED COMBINED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | ||
Net income (loss) | $ (1,272) | $ 53,479 |
Adjustments to reconcile net income (loss) to net cash used in operating activities: | ||
Depreciation, depletion and amortization | 34,272 | 44,456 |
Gain on early extinguishment of debts, net | (20,445) | 0 |
Gain on derivatives | (40,428) | (102,382) |
Amortization of deferred financing costs and discount and premium on long-term debt | 4,365 | 12,658 |
Non-cash compensation expense | 1,905 | 3,364 |
(Gain) loss on asset sales and disposal | (9) | 11 |
Distributions paid to non-controlling interests | (9,447) | (36,199) |
Equity (income) loss in unconsolidated companies | (211) | 102 |
Distributions received from unconsolidated companies | 471 | 455 |
Changes in operating assets and liabilities: | ||
Accounts receivable, prepaid expenses and other | 67,447 | 70,071 |
Accounts payable and accrued liabilities | (69,974) | (95,210) |
Net cash used in operating activities | (33,326) | (49,195) |
CASH FLOWS FROM INVESTING ACTIVITIES: | ||
Capital expenditures | (18,719) | (52,441) |
Net cash paid for acquisitions | 0 | (32,746) |
Other | 1,634 | (2,041) |
Net cash used in investing activities | (17,085) | (87,228) |
CASH FLOWS FROM FINANCING ACTIVITIES: | ||
Borrowings under ARP’s revolving credit facility | 135,000 | 161,000 |
Repayments under ARP’s revolving credit facility | (55,000) | (298,000) |
ARP senior note repurchases | (5,528) | 0 |
Net proceeds from issuance of Series A units | 0 | 40,000 |
Net proceeds from issuance of ARP and AGP units to the public | (1,319) | 23,083 |
Dividends to preferred unitholders | (1,015) | 0 |
Net investment from (distributions to) Atlas Energy | 0 | (19,758) |
Deferred financing costs, distribution equivalent rights and other | (697) | (12,447) |
Net cash provided by financing activities | 67,191 | 91,607 |
Net change in cash and cash equivalents | 16,780 | (44,816) |
Cash and cash equivalents, beginning of year | 31,214 | 58,358 |
Cash and cash equivalents, end of period | 47,994 | 13,542 |
Atlas Energy | Term loan facilities | ||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||
Borrowings under term loan facilities | 0 | 115,284 |
Repayments under term loan facilities | (4,250) | (160,055) |
ARP | ||
Adjustments to reconcile net income (loss) to net cash used in operating activities: | ||
Gain on early extinguishment of debts, net | (26,500) | |
ARP | Second lien term loan facility | ||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||
Borrowings under term loan facilities | $ 0 | $ 242,500 |
Basis of Presentation
Basis of Presentation | 3 Months Ended |
Mar. 31, 2016 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | |
Basis of Presentation | NOTE 1—BASIS OF PRESENTATION We are a publicly traded (OTCQX: ATLS) Delaware limited liability company formed in October 2011. Unless the context otherwise requires, references to “Atlas Energy Group, LLC,” “the Company,” “we,” “us,” “our” and “our company,” refer to Atlas Energy Group, LLC, and our combined and consolidated subsidiaries. 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. At March 31, 2016, our operations primarily consisted of our ownership interests in the following: · 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 23.3% limited partner interest (consisting of 20,962,485 common and 3,749,986 preferred limited partner units) in Atlas Resource Partners, L.P. (“ARP”), a publicly traded Delaware master limited partnership (“MLP”) (NYSE: ARP) and an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”), with operations in basins across the United States. As part of its exploration and production activities, ARP sponsors and manages tax-advantaged investment partnerships (“Drilling Partnerships”), in which it coinvests, to finance a portion of its natural gas and oil production activities; · 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. On June 30, 2015, AGP concluded a private placement offering, during which it issued $233.0 million of its common limited partner units. Of the $233.0 million of gross funds raised, we purchased $5.0 million common limited partner units. AGP’s registration statement on Form S-1 (Registration Number: 333-207537) was declared effective by the Securities and Exchange Commission on April 5, 2016. AGP is offering in the aggregate up to 100,000,000 Class A common units and Class T common units, each representing limited partner interests in AGP, pursuant to a primary offering on a "best efforts" basis. AGP must receive minimum offering proceeds of $1.0 million to break escrow, and the maximum offering proceeds of the primary offering may not exceed $1.0 billion. The Class A common units will be sold for a cash purchase price of $10.00 and the Class T common units will be sold for a cash purchase price of $9.60, with the remaining $0.40 constituting the Class T common unitholders' deferred payment obligation to AGP. AGP is also offering up to 21,505,376 Class A common units at $9.30 per unit pursuant to a distribution reinvestment plan; and · 12.0% limited partner interest in Lightfoot Capital Partners, L.P. (“Lightfoot L.P.”) and a 15.4% 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. Lightfoot L.P. focuses its investments primarily on incubating new MLPs and providing capital to existing MLPs in need of additional equity or structured debt. We account for our investment in Lightfoot under the equity method of accounting. During both the three months ended March 31, 2016 and 2015, we received net cash distributions of approximately $0.5 million. At March 31, 2016, we had 26,027,992 common limited partner 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 limited liability company agreement. The accompanying condensed combined consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2015, was derived from audited financial statements, have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission and are presented in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. It is suggested that these interim condensed combined consolidated financial statements be read in conjunction with the financial statements and the notes thereto included in our latest Annual Report Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of our financial position, results of operations and cash flows for the periods disclosed have been made. Certain amounts in the prior year’s financial statements have been reclassified to conform to the current year presentation due to the adoption of certain accounting standards (see Note 4). The results of operations for the interim periods presented may not necessarily be indicative of the results of operations for the full year. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 3 Months Ended |
Mar. 31, 2016 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation and Combination Our condensed combined consolidated financial statements for the three months ended March 31, 2016 and 2015, subsequent to the transfer of assets on February 27, 2015, include our accounts and accounts of our subsidiaries. Our condensed combined consolidated financial statements for the portion of 2015 which is prior to the transfer of assets on February 27, 2015, were derived from the separate records maintained by Atlas Energy and may not necessarily be indicative of the conditions or results of operations that would have existed if we had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various entities comprising us, Atlas Energy’s net investment in us is shown as equity in the condensed combined consolidated financial statements. U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed combined consolidated balance sheets and related condensed combined consolidated statements of operations. Such estimates included allocations made from the historical accounting records of Atlas Energy, based on management’s best estimates, in order to derive the financial statements of us. Actual balances and results could be different from those estimates. Transactions between us and other Atlas Energy operations have been identified in the condensed combined consolidated financial statements as transactions between affiliates. In connection with Atlas Energy’s merger with Targa and the concurrent Separation, we were required to repay $150.0 million of Atlas Energy’s term loan credit facility, which was issued in July 2013 for $240.0 million. In accordance with U.S. GAAP, we included $150.0 million of Atlas Energy’s original term loan at the time of issuance, and the related interest expense, within our historical financial statements. Atlas Energy’s other historical borrowings were allocated to our historical financial statements in the same ratio. We used proceeds from the issuance of our Series A preferred units (see Note 9) and borrowings under our term loan credit facilities to fund the $150.0 million payment. We determined that ARP and AGP are variable interest entities (“VIE’s”) based on their respective partnership agreements, our power, as the general partner, to direct activities that most significantly impact their economic performance, and our ownership of the incentive distribution rights. Accordingly, we consolidate the financial statements of ARP and AGP into our condensed combined consolidated financial statements. Our VIE’s operating results and assets balances are presented separately in Note 11 – Operating Segment Information. As the general partner for both ARP and AGP, we have unlimited liability for the obligations of ARP and AGP except for those contractual obligations that are expressly made without recourse to the general partner. The non-controlling interests in ARP and AGP are reflected as (income) loss attributable to non-controlling interests in the condensed combined consolidated statements of operations and as a component of unitholders’ equity on the condensed combined consolidated balance sheets. All material intercompany transactions have been eliminated. In accordance with established practice in the oil and gas industry, our condensed 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. Such interests generally approximate 30%. Our condensed combined consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of ARP’s Drilling Partnerships. Rather, ARP calculates these items specific to its own economics. 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 approximately $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. ARP accounted for the Arkoma Acquisition as a transaction between entities under common control in its standalone consolidated financial statements. Use of Estimates The preparation of our condensed 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 condensed combined consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. Our condensed combined consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization and fair value of derivative instruments. Such estimates included estimated allocations made from the historical accounting records of Atlas Energy in order to derive the historical financial statements of us. 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. Liquidity and Capital Resources Our primary sources of liquidity are cash distributions received with respect to our ownership interests in ARP, AGP, and Lightfoot. Our primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures, and distributions to unitholders, which we expect to fund through operating cash flow, and cash distributions received. We rely on the cash flows from the distributions received on our ownership interests in ARP, AGP, and Lightfoot. The amount of cash that ARP and AGP can distribute to their partners, including us, principally depends upon the amount of cash they each generate from their operations. ARP’s and AGP’s future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2016. These lower commodity prices have negatively impacted ARP’s and AGP’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on ARP’s and AGP’s liquidity position and ability to make distributions. Reductions of such distributions to us would adversely affect our ability to fund our cash requirements and obligations and meet our financial covenants under our credit agreements. On May 5, 2016, the 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. As a result of ARP’s distribution suspension and uncertainty regarding future covenant compliance, we classified $70.8 million of our outstanding amounts on our first and second lien credit agreements, net of $0.2 million deferred financing costs, as current portion of long-term debt within our condensed combined consolidated balance sheet as of March 31, 2016. We, ARP and AGP continually monitor our/their respective capital markets and their capital structures and may make changes 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 and ARP could pursue options such as refinancing, restructuring or reorganizing our/its indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address its liquidity concerns and high debt levels. There is no certainty that we or ARP will be able to implement any such options, and we and ARP cannot provide any assurances that any refinancing or changes to our or its 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 its stakeholders, including cancellation of debt income (“CODI”) which would be directly allocated to its unitholders and reported on such unitholders’ separate returns (see Item 1A – Risk Factors for additional information). It is possible additional adjustments to our, ARP’s or AGP’s strategic plan and outlook may occur based on market conditions and our/their respective needs at that time, which could include selling assets, liquidating all or a portion of ARP’s hedge portfolio, seeking additional partners to develop our/their respective assets, reducing or suspending the payments of distributions to preferred unitholders and/or reducing our/their respective planned capital programs. Strategies involving further reduction or suspension of distributions to unitholders by AGP would adversely affect our ability to fund our cash requirements and obligations. Atlas Resource Partners - Liquidity and Capital Resources ARP has historically funded its operations, acquisitions and cash distributions primarily through cash generated from operations, amounts available under its credit facilities and equity and debt offerings. ARP’s future cash flows are subject to a number of variables, including oil and natural gas prices. The lower commodity prices discussed above have negatively impacted ARP’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on ARP’s liquidity position. On May 10, 2016, ARP entered into a ninth amendment (the “Ninth Amendment”) to its Second Amended and Restated Credit Agreement, dated July 31, 2013 (as amended from time to time, the “ARP Credit Agreement”), with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto, to, among other things, waive the requirement that ARP’s ratio of current assets to current liabilities (as calculated pursuant to the ARP Credit Agreement) not be less than 1.0 to 1.0 as of March 31, 2016 and waive the requirement that ARP’s ratio of the total First Lien Debt to EBITDA (as calculated pursuant to the ARP Credit Agreement) not be greater than 2.75 to 1.0 as of March 31, 2016, and required ARP to repay $2.5 million of outstanding borrowings. ARP is party to a Second Lien Credit Agreement, dated February 23, 2015, with certain lenders and Wilmington Trust, National Association, as administrative agent (the “ARP Term Loan Facility”), which contains the same financial covenants as those in the ARP Credit Agreement, and were automatically waived as a result of the Ninth Amendment to the Credit Agreement. Based on the terms of the Ninth Amendment to the ARP Credit Agreement and uncertainty regarding future covenant compliance, we classified $672.0 million of ARP’s outstanding amounts under the ARP Credit Agreement and $234.2 million of ARP’s outstanding amounts under the ARP Term Loan Facility, net of $10.0 million deferred financing costs and $5.8 million unamortized discount, as current portion of long-term debt within our condensed consolidated balance sheet as of March 31, 2016. ARP’s borrowing base, and thus its borrowing capacity, under the ARP Credit Agreement is impacted by the level of its oil and natural gas reserves. Downward revisions of its oil and natural gas reserves volume and value due to low commodity prices, the impact of lower estimated capital spending in response to lower prices, performance revisions, sales of assets or the incurrence of certain types of additional debt, among other items, could cause a reduction of its borrowing base in the future, and these reductions could be significant. The ARP Credit Agreement is currently in the process of its semi-annual redetermination. Based on projected market conditions, continued declines in commodity prices and recent conversations with its administrative agent, ARP expects that its borrowing base will be redetermined to a level below its outstanding borrowings of $672.0 million under the ARP Credit Agreement as of March 31, 2016. In the case of a borrowing base deficiency, the ARP Credit Agreement requires ARP to repay the deficiency, which it is permitted to do in equal monthly installments over a four-month period, or deposit additional collateral to eliminate such deficiency. If ARP’s borrowing base is redetermined below its current outstanding borrowings and ARP is unable to repay the deficiency or deposit additional collateral to eliminate such deficiency, there would be substantial doubt regarding ARP’s ability to continue as a going concern. In addition, if ARP is unable to remain in compliance with the covenants under its credit facilities or the indentures governing its senior notes, absent relief from its lenders or noteholders, as applicable, ARP may be forced to repay or refinance such indebtedness. Upon the occurrence of an event of default, the lenders under ARP’s credit facilities or holders or its notes, as applicable, could elect to declare all amounts outstanding immediately due and payable and the lenders could terminate all commitments to extend further credit. A breach of any of the covenants (including if ARP’s borrowing base is redetermined below its current outstanding borrowings and it is unable to repay the deficiency or deposit additional collateral to eliminate such deficiency) in these credit facilities or the indentures governing ARP’s senior notes, respectively, could result in an event of default thereunder as well as a cross-default under ARP’s other debt agreements and, in either case, our credit agreement. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, ARP will not have sufficient liquidity to repay all of its outstanding indebtedness, and as a result, there would be substantial doubt regarding ARP’s ability to continue as a going concern. As discussed above, ARP continually monitors the capital markets and its capital structure and may make changes to its capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening its balance sheet, meeting its debt service obligations and/or achieving cost efficiency. Although ARP has a significant hedge position for the remainder of 2016 through 2018, the forecasted long-term downturn in commodity prices has had a detrimental impact on ARP’s financial position. For example, ARP could pursue options such as refinancing, restructuring or reorganizing its indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address its liquidity concerns and high debt levels. ARP is evaluating various options with the lenders under the ARP Credit Agreement and ARP Term Loan Facility, and holders of ARP’s Senior Notes, but there is no certainty that ARP will be able to implement any such options, and ARP cannot provide any assurances that any refinancing or changes in its 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 its stakeholders, including CODI which would be directly allocated to its unitholders and reported on such unitholders’ separate returns (see Item 1A – Risk Factors for additional information). ARP also continues to implement various cost saving measures to reduce its capital, operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. ARP will continue to be opportunistic and aggressive in managing its cost structure and, in turn, its liquidity to meet its capital and operating needs. ARP cannot provide any assurances that any of these efforts will be successful or will result in cost reductions or cash flows or the timing of any such cost reductions or additional cash flows. It is also possible additional adjustments to ARP’s plan and outlook may occur based on market conditions and ARP’s needs at that time, which could include selling assets, liquidating all or a portion of its hedge portfolio, seeking additional partners to develop its assets, reducing or suspending the payments of distributions to preferred unitholders and/or reducing its planned capital program. In addition, to the extent commodity prices remain low or decline further, or ARP experiences disruptions in ARP’s longer-term access to or cost of capital, ARP’s ability to fund future capital expenditures or growth projects may be further impacted. Atlas Growth Partners - Liquidity and Capital Resources AGP has historically funded its operations, acquisitions and cash distributions primarily through cash generated from operations and financing activities, including its recent private placement. AGP’s future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2016. These lower commodity prices have negatively impacted AGP’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on AGP’s liquidity position. 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 unitholders 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, except unit data): Three Months Ended March 31, 2016 2015 Net income (loss) $ (1,272 ) $ 53,479 Preferred unitholders’ dividends (339 ) (333 ) Income attributable to non-controlling interests (5,340 ) (58,298 ) Loss attributable to owner’s interest (period prior to the transfer of assets on February 27, 2015) — 10,475 Net income (loss) attributable to common unitholders (6,951 ) 5,323 Less: Net income attributable to participating securities – phantom units (1) — 13 Net income (loss) utilized in the calculation of net loss attributable to common unitholders per unit – diluted (1) $ (6,951 ) $ 5,310 (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 three months ended March 31, 2016, net loss attributable common unitholder’s ownership interest is not allocated to approximately 263,000 phantom units, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners, less income allocable to participating securities, by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of unit option awards 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 unitholder 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): Three Months Ended March 31, 2016 2015 Weighted average number of common unitholders per unit—basic 26,028 26,011 Add effect of dilutive incentive awards (1) — 63 Add effect of dilutive convertible preferred units (1) — 4,902 Weighted average number of common unitholders per unit—diluted 26,028 30,976 (1) For the three months ended March 31, 2016, 2,689,000 phantom units 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. For the three months ended March 31, 2016, potential common units issuable upon conversion of our Series A preferred units were excluded from the computation of diluted earnings attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive. 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 March 31, 2016 and December 31, 2015, we reflected $3.9 million and $5.6 million, respectively, related to the value of the rabbi trust within other assets, net on our condensed combined consolidated balance sheets, and recorded corresponding liabilities of $3.9 million and $5.6 million as of those same dates, respectively, within asset retirement obligations and other on our condensed combined consolidated balance sheets. During the three months ended March 31, 2016, a $2.3 million distribution was made to participants related to the rabbi trust. No distributions were made to participants related to the rabbi trust for the three months ended March 31, 2015. 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 condensed combined consolidated financial statements. In August 2015, the FASB updated the accounting guidance related to the balance sheet presentation of debt issuance costs specific to line-of-credit arrangements. The updated accounting guidance allows the option of presenting deferred debt issuance costs related to line-of-credit arrangements as an asset, and subsequently amortizing over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings. We adopted the updated accounting guidance effective January 1, 2016 and it did not have a material impact on our condensed combined consolidated financial statements. In February 2015, the FASB updated the accounting guidance related to consolidation under the variable interest entity and voting interest entity models. The updated accounting guidance modifies the consolidation guidance for variable interest entities, limited partnerships and similar legal entities. We adopted this accounting guidance upon its effective date of January 1, 2016, and it did not have a material impact on our condensed combined consolidated financial statements. In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued and provide footnote disclosures, if necessary. We adopted this accounting guidance on January 1, 2016, and provided enhanced disclosures, as applicable, within our condensed combined consolidated financial statements. 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. The updated accounting guidance provides companies with alternative methods of adoption. We are currently in the process of determining the impact that the updated accounting guidance will have on our condensed combined consolidated financial statements and our method of adoption. |
Property, Plant and Equipment
Property, Plant and Equipment | 3 Months Ended |
Mar. 31, 2016 | |
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): March 31, December 31, Estimated Useful Lives 2016 2015 in Years Natural gas and oil properties: Proved properties: Leasehold interests $ 570,934 $ 569,377 Pre-development costs 7,047 6,529 Wells and related equipment 3,165,776 3,157,708 Total proved properties 3,743,757 3,733,614 Unproved properties 213,047 213,047 Support equipment 45,136 44,921 Total natural gas and oil properties 4,001,940 3,991,582 Pipelines, processing and compression facilities 60,589 59,733 15 – 20 Rights of way 829 829 20 – 40 Land, buildings and improvements 9,798 9,798 3 – 40 Other 18,420 18,405 3 – 10 4,091,576 4,080,347 Less – accumulated depreciation, depletion and amortization (2,795,939 ) (2,763,450 ) $ 1,295,637 $ 1,316,897 During the three months ended March 31, 2016 and 2015, we recognized $18.7 million and $26.4 million, respectively, of non-cash property, plant and equipment additions, within the changes in accounts payable and accrued liabilities on our condensed combined consolidated statements of cash flows. ARP capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rates used to capitalize interest on combined borrowed funds by ARP were 6.7% and 6.1% for the three months ended March 31, 2016 and 2015, respectively. The amounts of interest capitalized by ARP was $2.4 million and $3.9 million for the three months ended March 31, 2016 and 2015, respectively. For the three months ended March 31, 2016 and 2015, we recorded $1.7 million and $1.6 million, respectively, of accretion expense related to ARP and AGP’s asset retirement obligations within in depreciation, depletion and amortization in our condensed combined consolidated statements of operations. For the three months ended March 31, 2016 and 2015, ARP incurred liabilities of $2.8 million and $0.2 million, respectively, in asset retirement obligations in our condensed consolidated balance sheet due to the liquidation of some of ARP’s Drilling Partnerships. |
Debt
Debt | 3 Months Ended |
Mar. 31, 2016 | |
Debt Disclosure [Abstract] | |
Debt | NOTE 4—DEBT Total debt consists of the following at the dates indicated (in thousands): March 31, December 31, 2016 2015 Term loan facilities $ 70,855 $ 72,700 Deferred financing costs (216 ) (3,813 ) ARP revolving credit facility 672,000 592,000 ARP term loan facility 244,159 243,783 ARP 7.75% Senior Notes—due 2021 354,366 374,619 ARP 9.25% Senior Notes—due 2021 312,055 324,080 ARP deferred financing costs (28,820 ) (31,055 ) Total debt, net 1,624,399 1,572,314 Less current maturities (976,795 ) (4,250 ) Total long-term debt, net $ 647,604 $ 1,568,064 In April 2015, the FASB updated the accounting guidance related to the balance sheet presentation of debt issuance costs. The updated accounting guidance requires that debt issuance costs be presented as a direct deduction from the associated debt obligation. We adopted this accounting guidance upon its effective date of January 1, 2016. The retrospective effect of the reclassification resulted in the following changes: Condensed Combined Consolidated Balance Sheet Previously Filed Adjustment Restated December 31, 2015: Other assets, net $ 88,980 $ (34,868 ) $ 54,112 Long-term debt, less current portion $ 1,602,932 $ (34,868 ) $ 1,568,064 Cash Interest . Cash payments for interest by us and our subsidiaries on our/their respective borrowings were $42.6 million and $38.5 million for the three months ended March 31, 2016 and 2015, respectively. Term Loan Facilities First Lien Credit Facility . 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. In connection with the execution of the Third Amendment, the Borrower made a prepayment of approximately $4.25 million of the outstanding principal, which was classified as current portion of long-term debt on our condensed combined consolidated balance sheet at December 31, 2015, and $0.5 million of interest. 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; · 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 AGP and Lightfoot; and · add a cross-default provision for defaults by ARP. 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 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 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. As a result of the Third Amendment to the First Lien Credit Agreement and the Second Lien Credit Agreement, ARP’s distribution suspension and uncertainty regarding ARP’s future covenant compliance, we classified $70.8 million of our outstanding amounts on our first and second lien credit agreements, net of $0.2 million deferred financing costs, as current portion of long-term debt within our condensed combined consolidated balance sheet as of March 31, 2016. In connection with the Term Loan Facilities, the lenders thereunder syndicated participations in loans underlying the facilities. As a result, certain of the Company’s current and former officers participated in approximately 12% of the loan syndication and warrants and a foundation affiliated with 5% or more unitholder participated in approximately 12% of the loan syndication. ARP Credit Facility ARP is a party to a ARP Credit Agreement with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto, which provides for a senior secured revolving credit facility with a borrowing base of $700.0 million as of March 31, 2016 and a maximum facility amount of $1.5 billion scheduled to mature in July 2018. At March 31, 2016, $672.0 million was outstanding under the credit facility. ARP’s borrowing base is scheduled for semi-annual redeterminations in May and November of each year. Up to $20.0 million of the revolving credit facility may be in the form of standby letters of credit, of which $4.2 million was outstanding at March 31, 2016. ARP’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by certain of ARP’s material subsidiaries, and any non-guarantor subsidiaries of ARP are minor. At March 31, 2016, the weighted average interest rate on outstanding borrowings under the credit facility was 3.6%. The ARP Credit Agreement contains customary covenants including, without limitation, covenants that limit ARP’s ability to incur additional indebtedness (but which permits second lien debt in an aggregate principal amount of up to $300.0 million and third lien debt that satisfies certain conditions including pro forma financial covenants), grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merge or consolidate with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. The ARP Credit Agreement also requires that ARP maintain a ratio of First Lien Debt to EBITDA (ratio as defined in the Credit Agreement) of not greater than 2.75 to 1.00, and a ratio of current assets to current liabilities (ratio as defined in the ARP Credit Agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter. On May 10, 2016, ARP entered into the Ninth Amendment to the ARP Credit Agreement, to, among other things, waive the requirement that ARP’s ratio of current assets to current liabilities (as calculated pursuant to the ARP Credit Agreement) not be less than 1.0 to 1.0 as of March 31, 2016 and waive the requirement that ARP’s ratio of the total First Lien Debt to EBITDA (as calculated pursuant to the ARP Credit Agreement) not be greater than 2.75 to 1.0 as of March 31, 2016, and required ARP to repay $2.5 million of outstanding borrowings. As a result of the Ninth Amendment to the ARP Credit Agreement and uncertainty regarding future covenant compliance, we classified $672.0 million of ARP’s outstanding amounts under the ARP Credit Agreement as current portion of long-term debt within our condensed consolidated balance sheet as of March 31, 2016. See Note 2 for additional disclosure regarding ARP’s liquidity and capital resources. ARP’s Credit Agreement is currently in the process of its semi-annual redetermination. Based on projected market conditions, continued declines in commodity prices and recent conversations with its administrative agent, ARP expects that its borrowing base will be redetermined to a level below its outstanding borrowings under the ARP Credit Agreement as of March 31, 2016. In the case of a borrowing base deficiency, the ARP Credit Agreement requires ARP to repay the deficiency, which it is permitted to do in equal monthly installments over a four-month period, or deposit additional collateral to eliminate such deficiency. See Note 2 for additional disclosure regarding our liquidity and capital resources. ARP Term Loan Facility ARP is party to the ARP Term Loan Facility, which provides for a second lien term loan in an original principal amount of $250.0 million. The ARP Term Loan Facility matures on February 23, 2020. The ARP Term Loan Facility is presented in the table above net of unamortized discount of $5.8 million at March 31, 2016. ARP’s obligations under the ARP Term Loan Facility are secured on a second priority basis by security interests in all of its assets and those of its restricted subsidiaries that guarantee ARP’s existing first lien revolving credit facility. In addition, the obligations under the ARP Term Loan Facility are guaranteed by ARP’s material restricted subsidiaries. At March 31, 2016, the weighted average interest rate on outstanding borrowings under the ARP Term Loan Facility was 10.0%. The ARP Term Loan Facility contains customary covenants including, without limitation, covenants that limit ARP’s ability to make restricted payments, take on indebtedness, issue preferred stock, grant liens, conduct sales of assets and subsidiary stock, make distributions from restricted subsidiaries, conduct affiliate transactions and engage in other business activities. In addition, the ARP Term Loan Facility contains covenants substantially similar to those in the ARP Credit Agreement, including, among others, restrictions on swap agreements, debt of unrestricted subsidiaries, drilling and operating agreements and the sale or discount of receivables. The financial covenants of the Term Loan Facility were automatically waived as a result of the Ninth Amendment to the Credit Agreement. Based on the terms of the Ninth Amendment to the ARP Credit Agreement and uncertainty regarding future covenant compliance, we classified $234.2 million of ARP’s outstanding amounts under the ARP Term Loan Facility, net of $10.0 million deferred financing costs and $5.8 million unamortized discount, as current portion of long-term debt within our condensed consolidated balance sheet as of March 31, 2016. See Note 2 for additional disclosure regarding our liquidity and capital resources. ARP Senior Notes At March 31, 2016, ARP had $354.4 million outstanding of its 7.75% senior unsecured notes due 2021 (“7.75% ARP Senior Notes”). The 7.75% ARP Senior Notes were presented net of a $0.4 million unamortized discount as of March 31, 2016. At March 31, 2016, ARP had $312.1 million outstanding of its 9.25% senior unsecured notes due 2021 (“9.25% ARP Senior Notes”). The 9.25% ARP Senior Notes were presented net of a $0.9 million unamortized discount as of March 31, 2016. In January and February 2016, ARP executed transactions to repurchase portions of its senior unsecured notes. As of March 31, 2016, ARP repurchased approximately $20.3 million of its 7.75% Senior Notes due 2021 and approximately $12.1 million of its 9.25% Senior Notes due 2021 for approximately $5.5 million, which includes $0.6 million of interest. As a result of these transactions, ARP recognized approximately $26.5 million as gain on early extinguishment of debt in the first quarter of 2016. The 7.75% ARP Senior Notes and 9.25% ARP Senior Notes are guaranteed by certain of ARP’s material subsidiaries. The guarantees under the 7.75% ARP Senior Notes and 9.25% ARP Senior Notes are full and unconditional and joint and several, subject to certain customary automatic release provisions, including, in certain circumstances, the sale or other disposition of all or substantially all the assets of, or all of the equity interests in, the subsidiary guarantor, or the subsidiary guarantor is declared “unrestricted” for covenant purposes, and any subsidiaries of ARP, other than the subsidiary guarantors, are minor. There are no restrictions on ARP’s ability to obtain cash or any other distributions of funds from the guarantor subsidiaries. The indentures governing the 7.75% ARP Senior Notes and 9.25% ARP Senior Notes contain covenants including, without limitation, covenants that limit ARP’s ability to incur certain liens, incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase, or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of ARP’s assets. ARP was in compliance with these covenants as of March 31, 2016. |
Derivative Instruments
Derivative Instruments | 3 Months Ended |
Mar. 31, 2016 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Derivative Instruments | NOTE 5—DERIVATIVE INSTRUMENTS ARP and AGP use a number of different derivative instruments, principally swaps and options, in connection with their commodity price risk management activities. ARP and AGP do not apply hedge accounting to any of their derivative instruments. As a result, gains and losses associated with derivative instruments are recognized in earnings. AGP and ARP enter into commodity future option contracts to achieve more predictable cash flows by hedging their exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. Natural gas liquids fixed price swaps are priced based on a WTI crude oil index, while ethane, propane, butane and iso butane contracts are based on the respective Mt. Belvieu price. These contracts were recorded at their fair values. We recorded net derivative assets on our condensed combined consolidated balance sheets of $355.3 million and $358.1 million at March 31, 2016 and December 31, 2015, respectively. Of the $3.5 million of net gain in accumulated other comprehensive income within unitholders’ equity on our condensed combined consolidated balance sheet related to derivatives at March 31, 2016, we expect to reclassify $2.7 million of gains to our condensed combined consolidated statement of operations over the next twelve-month period as these contracts expire. Aggregate gains of $0.8 million of gas and oil production revenues will be reclassified to our condensed combined consolidated statements of operations in later periods as the remaining contracts expire. The following table summarizes the commodity derivative activity and presentation in our condensed combined consolidated statement of operations for the periods indicated (in thousands): Three Months Ended March 31, 2016 2015 Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets (1) $ 3,515 $ 27,343 Portion of settlements attributable to subsequent mark to market gains 45,430 15,203 Total cash settlements on commodity derivative contracts $ 48,945 $ 42,546 Gains recognized on cash settlement (2) $ 6,025 $ 3,203 Gains recognized on open derivative contracts (2) 40,428 102,382 Gains on mark-to-market derivatives $ 46,453 $ 105,585 (1) Recognized in gas and oil production revenue. (2) Recognized in gain on mark-to-market derivatives. During the three months ended March 31, 2015, we received approximately $4.9 million in net proceeds from the early termination of our remaining natural gas and oil derivative positions for production periods from 2015 through 2018. The net proceeds from the early termination of these derivatives were used to reduce indebtedness under our Term Loan Facilities. Atlas Growth Partners On May 1, 2015, AGP entered into a secured credit facility agreement with a syndicate of banks. As of March 31, 2016, the lenders under the credit facility have no commitment to lend to AGP under the credit facility, 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 March 31, 2016. 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. 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 condensed combined consolidated balance sheets as of the dates indicated (in thousands): Offsetting Derivatives as of March 31, 2016 Gross Amounts Recognized Gross Amounts Offset Net Amount Presented Current portion of derivative assets $ 366 $ (52 ) $ 314 Long-term portion of derivative assets 196 (3 ) 193 Total derivative assets $ 562 $ (55 ) $ 507 Current portion of derivative liabilities $ (52 ) $ 52 $ — Long-term portion of derivative liabilities (3 ) 3 — Total derivative liabilities $ (55 ) $ 55 $ — Offsetting Derivatives as of December 31, 2015 Current portion of derivative assets $ 399 $ (96 ) $ 303 Long-term portion of derivative assets 162 (53 ) 109 Total derivative assets $ 561 $ (149 ) $ 412 Current portion of derivative liabilities $ (96 ) $ 96 $ — Long-term portion of derivative liabilities (53 ) 53 — Total derivative liabilities $ (149 ) $ 149 $ — At March 31, 2016, AGP had the following commodity derivatives: Type Production Period Ending December 31, Volumes (1) Average Fixed Price (1) Fair Value Asset/(Liability) Total Type (in thousands) (2) (in thousands) (2) Crude Oil – Fixed Price Swaps 2016 (3) 53,600 $ 45.585 $ 253 2017 37,100 $ 49.968 $ 200 2018 26,500 $ 48.850 $ 54 AGP’s net assets $ 507 (1) Volumes for crude oil are stated in barrels. (2) Fair value of crude oil fixed price swaps are based on forward WTI crude oil prices, as applicable. (3) The production volumes for 2016 include the remaining nine months of 2016 beginning April 1, 2016. Atlas Resource Partners The following table summarizes the gross fair values of ARP’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our condensed combined consolidated balance sheets as of the dates indicated (in thousands): Offsetting Derivatives as of March 31, 2016 Gross Amounts Recognized Gross Amounts Offset Net Amount Presented Current portion of derivative assets $ 159,745 $ — $ 159,745 Long-term portion of derivative assets 195,074 — 195,074 Total derivative assets $ 354,819 $ — $ 354,819 Current portion of derivative liabilities $ — $ — $ — Long-term portion of derivative liabilities — — — Total derivative liabilities $ — $ — $ — Offsetting Derivatives as of December 31, 2015 Current portion of derivative assets $ 159,460 $ — $ 159,460 Long-term portion of derivative assets 198,262 — 198,262 Total derivative assets $ 357,722 $ — $ 357,722 Current portion of derivative liabilities $ — $ — $ — Long-term portion of derivative liabilities — — — Total derivative liabilities $ — $ — $ — At March 31, 2016, ARP had the following commodity derivatives: Type Production Period Ending December 31, Volumes (1) Average Fixed Price (1) Fair Value Asset Total type (in thousands) (2) (in thousands) (2) Natural Gas – Fixed Price Swaps 2016 (3) 40,354,500 $ 4.226 $ 80,594 2017 50,120,000 $ 4.221 $ 72,296 2018 40,300,000 $ 4.168 $ 51,782 2019 15,860,000 $ 4.019 $ 16,932 $ 221,604 Natural Gas – Put Options – Drilling Partnerships 2016 (3) 1,080,000 $ 4.150 $ 2,078 $ 2,078 Crude Oil – Fixed Price Swaps 2016 (3) 1,230,800 $ 81.685 $ 49,864 2017 1,200,000 $ 77.610 $ 39,372 2018 1,080,000 $ 76.281 $ 31,413 2019 540,000 $ 68.371 $ 10,488 $ 131,137 Total ARP net assets $ 354,819 (1) Volumes for natural gas are stated in million British Thermal Units. Volumes for crude oil are stated in barrels. (2) Fair value for natural gas fixed price swaps and natural gas put options based on forward NYMEX natural gas prices, as applicable. Fair value for crude oil fixed price swaps are based on forward WTI crude oil prices, as applicable. (3) The production volumes for 2016 include the remaining nine months of 2016 beginning April 1, 2016. |
Fair Value of Financial Instrum
Fair Value of Financial Instruments | 3 Months Ended |
Mar. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Instruments | NOTE 6—FAIR VALUE OF FINANCIAL INSTRUMENTS We and our subsidiaries use a market approach fair value methodology to value our 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 and our subsidiaries separate the fair value of our financial instruments into the three level hierarchy (Levels 1, 2 and 3) based on our/their assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. As of March 31, 2016 and December 31, 2015, all derivative financial instruments were classified as Level 2. Information for our and our subsidiaries’ financial instruments measured at fair value at March 31, 2016 and December 31, 2015 were as follows (in thousands): Level 1 Level 2 Level 3 Total As of March 31, 2016 Assets, gross Rabbi trust $ 3,904 $ — $ — $ 3,904 ARP Commodity swaps — 352,741 — 352,741 ARP Commodity puts — 2,078 — 2,078 AGP Commodity swaps — 562 — 562 Total assets, gross 3,904 355,381 — 359,285 Liabilities, gross AGP Commodity swaps — (55 ) — (55 ) Total derivative liabilities, gross — (55 ) — (55 ) Total assets, fair value, net $ 3,904 $ 355,326 $ — $ 359,320 As of December 31, 2015 Assets, gross Rabbi trust $ 5,584 $ — $ — $ 5,584 ARP Commodity swaps — 355,329 — 355,329 ARP Commodity puts — 2,393 — 2,393 AGP Commodity swaps — 561 — 561 Total assets, gross 5,584 358,283 — 363,867 Liabilities, gross AGP Commodity swaps — (149 ) — (149 ) Total derivative liabilities, gross $ — $ (149 ) $ — $ (149 ) Total assets, fair value, net 5,584 358,134 — 363,718 Other Financial Instruments We and our subsidiaries’ other current assets and liabilities on our condensed combined consolidated balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1. The estimated fair values of our and ARP’s debt at March 31, 2016 and December 31, 2015, which consist of borrowings under our term loan facilities, ARP’s senior notes and borrowings under ARP’s term loan and revolving credit facility, were $1,096.9 million and $929.2 million, respectively, compared with the carrying amounts of $1,624.4 million and $1,572.3 million, respectively. The carrying values of outstanding borrowings under the ARP revolving credit facility, which bear interest at variable interest rates, approximated their estimated fair value. The estimated fair values of the ARP senior notes and term loan facility were based upon the market approach and calculated using the yields of the ARP senior notes and term loan facility as provided by financial institutions and thus were categorized as Level 3 values. |
Certain Relationships and Relat
Certain Relationships and Related Party Transactions | 3 Months Ended |
Mar. 31, 2016 | |
Related Party Transactions [Abstract] | |
Certain Relationships And Related Party Transactions | NOTE 7—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS Relationship with ARP. ARP does not directly employ any persons to manage or operate its business. These functions are provided by employees of us and/or our affiliates. 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 the three months ended March 31, 2016 and 2015, AGP paid approximately $0.6 million and $0.3 million related to AGP GP for this management fee. Other indirect costs, such as rent for offices, are allocated to AGP by us based on the number of its employees who devoted substantially all of their time to activities on its behalf. AGP reimburses us at cost for direct costs incurred on its behalf. AGP will reimburse all necessary and reasonable costs allocated by the general partner. AGP was required to pay AGP GP an amount equal to any actual, out-of-pocket expenses related to its private placement offering and the formation and financing of AGP, including legal costs incurred by AGP GP, which payments were approximately 2% of the gross proceeds of its private placement offering. Relationship with Drilling Partnerships. ARP conducts certain activities through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. ARP serves as the ultimate general partner and operator of the Drilling Partnerships and assumes customary rights and obligations for the Drilling Partnerships. As the ultimate general partner, ARP is liable for the Drilling Partnerships’ liabilities and can be liable to limited partners of the Drilling Partnerships if it breaches its responsibilities with respect to the operations of the Drilling Partnerships. ARP is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Drilling Partnership’s revenue and costs and expenses according to the respective partnership agreements. In March 2016, ARP transferred $36.7 million of investor capital raised and $13.3 million of accrued well drilling and completion costs incurred to the Atlas Eagle Ford 2015 L.P. private drilling partnership for activities directly related to their program. ARP intends to continue to fund the Drilling Partnerships’ operations and obligations, as necessary, until they are liquidated. Depending on commodity pricing and each of the Drilling Partnerships’ reserves value, ARP expects to realize all outstanding receivables from the Drilling Partnerships’ through the receipt of cash flows from their operations and/or the transfer of net assets and liabilities to ARP upon their liquidation. As of March 31, 2016 and December 31, 2015, ARP had receivables of $7.9 million and $6.6 million, respectively, from certain of the Drilling Partnerships’, which was recorded in accounts receivable in the condensed consolidated balance sheets. As of March 31, 2016 and December 31, 2015, ARP had payables of $3.9 million and $3.0 million, respectively, to certain of the Drilling Partnerships’, which was recorded in accounts payable in the condensed consolidated balance sheets. Other Relationships. We have other related party transactions with regard to our Term Loan Facilities (see Note 4), our Series A preferred units (Note 9) and our general partner and limited partner interest in Lightfoot (see Note 1). |
Commitments and Contingencies
Commitments and Contingencies | 3 Months Ended |
Mar. 31, 2016 | |
Commitments And Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | NOTE 8—COMMITMENTS AND CONTINGENCIES ARP is the ultimate managing general partner of the Drilling Partnerships and has agreed to indemnify each investor partner from any liability that exceeds such partner’s share of Drilling Partnership assets. ARP has structured certain Drilling Partnerships to allow limited partners to have the right to present their interests for purchase. Generally for Drilling Partnerships with this structure, ARP is not obligated to purchase more than 5% to 10% of the units in any calendar year, no units may be purchased during the first five years after closing for the Drilling Partnership, and ARP may immediately suspend the presentment structure for a Drilling Partnership by giving notice to the limited partners that it does not have adequate liquidity for redemptions. In accordance with the Drilling Partnership agreement, the purchase price for limited partner interests would generally be based upon a percentage of the present value of future cash flows allocable to the interest, discounted at 10%, as of the date of presentment, subject to estimated changes by ARP to reflect current well performance, commodity prices and production costs, among other items. Based on its historical experience, as of March 31, 2016, the management of ARP believes that any such estimated liability for redemptions of limited partner interests in Drilling Partnerships which allow such transactions would not be material. While its historical structure has varied, ARP has generally agreed to subordinate a portion of its share of Drilling Partnership gas and oil production revenue, net of corresponding production costs and up to a maximum of 50% of unhedged revenue, from certain Drilling Partnerships for the benefit of the limited partner investors until they have received specified returns, typically 10% to 12% per year determined on a cumulative basis, over a specified period, typically the first five to eight years, in accordance with the terms of the partnership agreements. ARP periodically compares the projected return on investment for limited partners in a Drilling Partnership during the subordination period, based upon historical and projected cumulative gas and oil production revenue and expenses, with the return on investment subject to subordination agreed upon within the Drilling Partnership agreement. If the projected return on investment falls below the agreed upon rate, ARP recognizes subordination as an estimated reduction of its pro-rata share of gas and oil production revenue, net of corresponding production costs, during the current period in an amount that will achieve the agreed upon investment return, subject to the limitation of 50% of unhedged cumulative net production revenues over the subordination period. For Drilling Partnerships for which ARP has recognized subordination in a historical period, if projected investment returns subsequently reflect that the agreed upon limited partner investment return will be achieved during the subordination period, ARP will recognize an estimated increase in its portion of historical cumulative gas and oil net production, subject to a limitation of the cumulative subordination previously recognized. For the three months ended March 31, 2016 and 2015, $0.1 million and $0.5 million, respectively, of ARP’s gas and oil production revenues, net of corresponding production costs, from certain Drilling Partnerships were subordinated, which reduced gas and oil production revenues and expenses. As of March 31, 2016, we and our subsidiaries are committed to expend approximately $9.1 million on drilling and completion expenditures. Legal Proceedings We and our subsidiaries are parties to various routine legal proceedings arising out of the ordinary course of our business. Our and our subsidiaries’ management 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. |
Issuances of Units
Issuances of Units | 3 Months Ended |
Mar. 31, 2016 | |
Proceeds From Issuance Or Sale Of Equity [Abstract] | |
Issuances of Units | NOTE 9—ISSUANCES OF UNITS We recognize gains or losses on ARP’s and AGP’s equity transactions as credits or debits, respectively, to unitholders’ equity on our condensed combined consolidated balance sheets rather than as income or loss on our condensed 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 ARP’s and AGP’s common units as compared to the book carrying amount per unit. On February 27, 2015 we issued and sold an aggregate of 1.6 million of our newly created Series A convertible preferred units, with a liquidation preference of $25.00 per unit (the “Series A Preferred Units”), at a purchase price of $25.00 per unit to certain members of 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 will be 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) 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 2). The Series A Purchase Agreement contains customary terms for private placements, including representations, warranties, covenants and indemnities. 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 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 OTCQX on Monday, March 21, 2016 under the ticker symbol: ATLS. Atlas Resource Partners ARP has an equity distribution agreement with Deutsche Bank Securities Inc., as representative of the several banks named therein (the “Agents”). Pursuant to the equity distribution agreement, ARP may sell from time to time through the Agents common units representing limited partner interests of ARP having an aggregate offering price of up to $100.0 million. Sales of common units, if any, may be made in negotiated transactions or transactions that are deemed to be “at-the-market” offerings as defined in Rule 415 of the Securities Act, including sales made directly on the New York Stock Exchange, the existing trading market for the common units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. ARP will pay each of the Agents a commission, which in each case shall not be more than 2.0% of the gross sales price of common units sold through such Agent. Under the terms of the equity distribution agreement, ARP may also sell common units from time to time to any Agent as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to an Agent as principal would be pursuant to the terms of a separate agreement between ARP and such Agent. During the three months ended March 31, 2016, ARP issued 245,175 common limited partner units under the equity distribution program for net proceeds of $0.2 million, net of approximately $19,000 in commissions and offering expenses paid. During the three months ended March 31, 2015, ARP issued 420,586 common limited partner units under the equity distribution program for net proceeds of $3.3 million, net of $0.1 million in commissions 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 may sell 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 three months ended March 31, 2016 and 2015. On March 31, 2015, to partially pay its portion of the quarterly installment related to the Eagle Ford acquisition, ARP issued an additional 800,000 Class D Preferred Units to the seller at a value of $25.00 per unit. On January 12, 2016, ARP was notified by the NYSE that it was 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 its common units had been less than $1.00 for 30 consecutive trading days. ARP is working to remedy this situation in a timely manner as set forth in the applicable NYSE rules in order to maintain its listing on the NYSE. Atlas Growth Partners On April 5, 2016, we announced that AGP’s registration statement on Form S-1 (Registration Number: 333-207537) was declared effective by the Securities and Exchange Commission. 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 approximately $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. In connection with the issuance of ARP’s unit offerings during the three months ended March 31, 2016, we recorded gains of $0.2 million within unitholders’ equity and a corresponding decrease in non-controlling interests on our condensed combined consolidated balance sheet and condensed combined consolidated statement of unitholders’ equity. In connection with the issuance of ARP’s and AGP’s unit offerings for the three months ended March 31, 2015, we recorded gains of $0.2 million within equity and a corresponding decrease in non-controlling interests on our condensed combined consolidated balance sheets and condensed combined consolidated statement of unitholders’ equity. |
Cash Distributions
Cash Distributions | 3 Months Ended |
Mar. 31, 2016 | |
Distributions Made To Members Or Limited Partners [Abstract] | |
Cash Distributions | NOTE 10—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. As a result of the First Lien Credit Agreement and Second Lien Credit Agreement (see Note 4), we are prohibited from paying cash distributions on our common and preferred units. During the three months ended March 31, 2016, we paid a distribution of $1.0 million to Class A preferred unitholders. No distributions were paid to Class A preferred unitholders during the three months ended March 31, 2015. ARP Cash Distributions. ARP has a monthly cash distribution program whereby it distributes all of its available cash (as defined in ARP’s partnership agreement) for that month to its unitholders within 45 days from the month end. If ARP’s common unit distributions in any quarter exceed specified target levels, we will receive 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. While outstanding, the Class C ARP Preferred Units receive 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. ARP pays quarterly distributions on the 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 pays distributions on the 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 May 5, 2016, the Board of Directors elected to suspend ARP’s common unit and Class C Preferred Unit distributions, beginning with the month of March of 2016, due to the continued lower commodity price environment. During the three months ended March 31, 2016, ARP paid three monthly cash distributions totaling approximately $3.8 million to common limited partners ($0.0125 per unit per month); $1.9 million to Preferred Class C limited partners ($0.17 per unit per month); and $0.1 million to the General Partner Class A holder ($0.0125 per unit per month). During the three months ended March 31, 2015, ARP paid three monthly cash distributions totaling approximately $42.8 million to common limited partners ($0.1966 per unit for both January and February 2015 and $0.1083 per unit for March 2015); $2.1 million to Preferred Class C limited partners ($0.1966 per unit for both January and February 2015 and $0.17 per unit for March 2015); and $3.0 million to the General Partner Class A holder ($0.1966 per unit for both January and February 2015 and $0.1083 per unit for March 2015). During the three months ended March 31, 2016, ARP paid a distribution of $2.2 million to Class D Preferred limited partners ($0.5390625 per unit) for the period October 15, 2015 through January 14, 2016. During the three months ended March 31, 2015, ARP paid a distribution of $2.0 million to Class D Preferred limited partners ($0.6169270 per unit) for the period October 2, 2014 through January 14, 2015. During the three months ended March 31, 2016, ARP paid a distribution of $0.2 million to Class E Preferred limited partners ($0.671875 per unit) for the period October 15, 2015 through January 14, 2016. No distributions were paid to Class E Preferred limited partners during the three months ended March 31, 2015. 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. During the three months ended March 31, 2016, AGP paid a distribution of $4.1 million to common limited partners ($0.1750 per unit) and $0.1 million to the general partner’s Class A units ($0.1750 per unit). During the three months ended March 31, 2015, AGP paid a distribution of $1.6 million to common limited partners ($0.1750 per unit) and approximately $33,000 to the general partner’s Class A units ($0.1750 per unit). |
Operating Segment Information
Operating Segment Information | 3 Months Ended |
Mar. 31, 2016 | |
Segment Reporting [Abstract] | |
Operating Segment Information | NOTE 11—OPERATING SEGMENT INFORMATION Our operations include three reportable operating segments: ARP, AGP, and corporate and other. These operating segments reflect the way we manage our operations and make business decisions. Corporate and other includes our equity investment in Lightfoot (see Note 1), as well as our general and administrative and interest expenses. Operating segment data for the periods indicated were as follows (in thousands): Three Months Ended March 31, 2016 2015 Atlas Resource Partners: Revenues $ 103,208 $ 243,589 Operating costs and expenses (59,202 ) (87,818 ) Depreciation, depletion and amortization expense (30,045 ) (42,991 ) Gain (loss) on asset sales and disposal 9 (11 ) Interest expense (27,705 ) (25,197 ) Gain on early extinguishment of debt 26,498 — Segment income $ 12,763 $ 87,572 Atlas Growth Partners: Revenues $ 3,434 $ 2,311 Operating costs and expenses (3,503 ) (5,069 ) Depreciation, depletion and amortization expense (4,227 ) (1,465 ) Segment loss $ (4,296 ) $ (4,223 ) Corporate and other: Revenues $ 211 $ (101 ) General and administrative (2,154 ) (20,215 ) Interest expense (1,743 ) (9,554 ) Loss on early extinguishment of debt (6,053 ) — Segment loss $ (9,739 ) $ (29,870 ) Reconciliation of segment loss to net loss: Segment income (loss): Atlas Resource Partners $ 12,763 $ 87,572 Atlas Growth Partners (4,296 ) (4,223 ) Corporate and other $ (9,739 ) $ (29,870 ) Net income (loss) $ (1,272 ) $ 53,479 Reconciliation of segment revenues to total revenues: Segment revenues: Atlas Resource Partners $ 103,208 $ 243,589 Atlas Growth Partners 3,434 2,311 Corporate and other 211 (101 ) Total revenues $ 106,853 $ 245,799 Capital expenditures: Atlas Resource Partners $ 13,170 $ 42,498 Atlas Growth Partners 5,549 9,943 Corporate and other — — Total capital expenditures $ 18,719 $ 52,441 March 31, December 31, 2016 2015 Balance sheet: Goodwill: Atlas Resource Partners $ 13,639 $ 13,639 Atlas Growth Partners — — Corporate and other — — Total goodwill $ 13,639 $ 13,639 Total assets: Atlas Resource Partners $ 1,679,497 $ 1,699,949 Atlas Growth Partners 147,752 159,622 Corporate and other 16,530 23,675 Total assets $ 1,843,779 $ 1,883,246 |
Subsequent Events
Subsequent Events | 3 Months Ended |
Mar. 31, 2016 | |
Subsequent Events [Abstract] | |
Subsequent Events | NOTE 12—SUBSEQUENT EVENTS Issuance of Warrants . Pursuant to the terms of the Second Lien Credit Agreement, on April 27, 2016 we issued to the Lenders warrants (the “Warrants”) to purchase an aggregate of up to 4,668,044 common units representing limited partner interests in us at an exercise price of $0.20 per unit. The Warrants expire on March 30, 2026 and are subject to customary anti-dilution provisions. In connection with the issuance and sale of the Warrants, we entered into a registration rights agreement with the Lenders, dated April 27, 2016 (the “Registration Rights Agreement”), relating to the registered resale of the common units underlying the Warrants, as well as any common units issued as in-kind interest payments under the Second Lien Credit Agreement. Pursuant to the Registration Rights Agreement, we are required to file a shelf registration statement within 90 days of request by the Lenders and to use commercially reasonable efforts to cause such registration statement to become effective within 120 days of such request. Long-Term Incentive Plan Vesting Delay . On May 12, 2016, due to the income tax ramifications of potential options we are currently 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. Atlas Resource Partners Cash Distributions. On April 15, 2016, ARP paid a quarterly distribution of $0.5390625 per Class D Preferred Unit, or $2.2 million, for the period from January 15, 2016 through April 14, 2016 to Class D Preferred Unitholders of record as of April 1, 2016. On April 15, 2016, ARP paid a quarterly distribution of $0.671875 per Class E Preferred Unit, or $0.2 million, for the period from January 15, 2016 through April 14, 2016 to Class E Preferred Unitholders of record as of April 1, 2016. On May 5, 2016, the 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. Ninth Amendment to the ARP Credit Agreement . On May 10, 2016, ARP entered into the Ninth Amendment to the ARP Credit Agreement (see Note 4). Long-Term Incentive Plan Vesting Delay . On May 12, 2016, due to the income tax ramifications of the options ARP is currently considering, the Board of Directors delayed the vesting date of approximately 110,000 units granted to employees, directors and officers until March 2017. The phantom units were set to vest between May 15, 2016 and September 1, 2016. Atlas Growth Partners Cash Distributions. On May 4, 2016, AGP declared a quarterly distribution of $0.1750 per common unit for the quarter ended March 31, 2016. The $4.2 million distribution, including $0.1 million to its general partner, will be paid on May 13, 2016 to unitholders of record at the close of business on March 31, 2016. |
Summary of Significant Accoun19
Summary of Significant Accounting Policies (Policies) | 3 Months Ended |
Mar. 31, 2016 | |
Accounting Policies [Abstract] | |
Principles of Consolidation and Combination | Principles of Consolidation and Combination Our condensed combined consolidated financial statements for the three months ended March 31, 2016 and 2015, subsequent to the transfer of assets on February 27, 2015, include our accounts and accounts of our subsidiaries. Our condensed combined consolidated financial statements for the portion of 2015 which is prior to the transfer of assets on February 27, 2015, were derived from the separate records maintained by Atlas Energy and may not necessarily be indicative of the conditions or results of operations that would have existed if we had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various entities comprising us, Atlas Energy’s net investment in us is shown as equity in the condensed combined consolidated financial statements. U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed combined consolidated balance sheets and related condensed combined consolidated statements of operations. Such estimates included allocations made from the historical accounting records of Atlas Energy, based on management’s best estimates, in order to derive the financial statements of us. Actual balances and results could be different from those estimates. Transactions between us and other Atlas Energy operations have been identified in the condensed combined consolidated financial statements as transactions between affiliates. In connection with Atlas Energy’s merger with Targa and the concurrent Separation, we were required to repay $150.0 million of Atlas Energy’s term loan credit facility, which was issued in July 2013 for $240.0 million. In accordance with U.S. GAAP, we included $150.0 million of Atlas Energy’s original term loan at the time of issuance, and the related interest expense, within our historical financial statements. Atlas Energy’s other historical borrowings were allocated to our historical financial statements in the same ratio. We used proceeds from the issuance of our Series A preferred units (see Note 9) and borrowings under our term loan credit facilities to fund the $150.0 million payment. We determined that ARP and AGP are variable interest entities (“VIE’s”) based on their respective partnership agreements, our power, as the general partner, to direct activities that most significantly impact their economic performance, and our ownership of the incentive distribution rights. Accordingly, we consolidate the financial statements of ARP and AGP into our condensed combined consolidated financial statements. Our VIE’s operating results and assets balances are presented separately in Note 11 – Operating Segment Information. As the general partner for both ARP and AGP, we have unlimited liability for the obligations of ARP and AGP except for those contractual obligations that are expressly made without recourse to the general partner. The non-controlling interests in ARP and AGP are reflected as (income) loss attributable to non-controlling interests in the condensed combined consolidated statements of operations and as a component of unitholders’ equity on the condensed combined consolidated balance sheets. All material intercompany transactions have been eliminated. In accordance with established practice in the oil and gas industry, our condensed 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. Such interests generally approximate 30%. Our condensed combined consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of ARP’s Drilling Partnerships. Rather, ARP calculates these items specific to its own economics. 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 approximately $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. ARP accounted for the Arkoma Acquisition as a transaction between entities under common control in its standalone consolidated financial statements. |
Use of Estimates | Use of Estimates The preparation of our condensed 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 condensed combined consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. Our condensed combined consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization and fair value of derivative instruments. Such estimates included estimated allocations made from the historical accounting records of Atlas Energy in order to derive the historical financial statements of us. 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. |
Liquidity and Capital Resources | Liquidity and Capital Resources Our primary sources of liquidity are cash distributions received with respect to our ownership interests in ARP, AGP, and Lightfoot. Our primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures, and distributions to unitholders, which we expect to fund through operating cash flow, and cash distributions received. We rely on the cash flows from the distributions received on our ownership interests in ARP, AGP, and Lightfoot. The amount of cash that ARP and AGP can distribute to their partners, including us, principally depends upon the amount of cash they each generate from their operations. ARP’s and AGP’s future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2016. These lower commodity prices have negatively impacted ARP’s and AGP’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on ARP’s and AGP’s liquidity position and ability to make distributions. Reductions of such distributions to us would adversely affect our ability to fund our cash requirements and obligations and meet our financial covenants under our credit agreements. On May 5, 2016, the 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. As a result of ARP’s distribution suspension and uncertainty regarding future covenant compliance, we classified $70.8 million of our outstanding amounts on our first and second lien credit agreements, net of $0.2 million deferred financing costs, as current portion of long-term debt within our condensed combined consolidated balance sheet as of March 31, 2016. We, ARP and AGP continually monitor our/their respective capital markets and their capital structures and may make changes 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 and ARP could pursue options such as refinancing, restructuring or reorganizing our/its indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address its liquidity concerns and high debt levels. There is no certainty that we or ARP will be able to implement any such options, and we and ARP cannot provide any assurances that any refinancing or changes to our or its 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 its stakeholders, including cancellation of debt income (“CODI”) which would be directly allocated to its unitholders and reported on such unitholders’ separate returns (see Item 1A – Risk Factors for additional information). It is possible additional adjustments to our, ARP’s or AGP’s strategic plan and outlook may occur based on market conditions and our/their respective needs at that time, which could include selling assets, liquidating all or a portion of ARP’s hedge portfolio, seeking additional partners to develop our/their respective assets, reducing or suspending the payments of distributions to preferred unitholders and/or reducing our/their respective planned capital programs. Strategies involving further reduction or suspension of distributions to unitholders by AGP would adversely affect our ability to fund our cash requirements and obligations. Atlas Resource Partners - Liquidity and Capital Resources ARP has historically funded its operations, acquisitions and cash distributions primarily through cash generated from operations, amounts available under its credit facilities and equity and debt offerings. ARP’s future cash flows are subject to a number of variables, including oil and natural gas prices. The lower commodity prices discussed above have negatively impacted ARP’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on ARP’s liquidity position. On May 10, 2016, ARP entered into a ninth amendment (the “Ninth Amendment”) to its Second Amended and Restated Credit Agreement, dated July 31, 2013 (as amended from time to time, the “ARP Credit Agreement”), with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto, to, among other things, waive the requirement that ARP’s ratio of current assets to current liabilities (as calculated pursuant to the ARP Credit Agreement) not be less than 1.0 to 1.0 as of March 31, 2016 and waive the requirement that ARP’s ratio of the total First Lien Debt to EBITDA (as calculated pursuant to the ARP Credit Agreement) not be greater than 2.75 to 1.0 as of March 31, 2016, and required ARP to repay $2.5 million of outstanding borrowings. ARP is party to a Second Lien Credit Agreement, dated February 23, 2015, with certain lenders and Wilmington Trust, National Association, as administrative agent (the “ARP Term Loan Facility”), which contains the same financial covenants as those in the ARP Credit Agreement, and were automatically waived as a result of the Ninth Amendment to the Credit Agreement. Based on the terms of the Ninth Amendment to the ARP Credit Agreement and uncertainty regarding future covenant compliance, we classified $672.0 million of ARP’s outstanding amounts under the ARP Credit Agreement and $234.2 million of ARP’s outstanding amounts under the ARP Term Loan Facility, net of $10.0 million deferred financing costs and $5.8 million unamortized discount, as current portion of long-term debt within our condensed consolidated balance sheet as of March 31, 2016. ARP’s borrowing base, and thus its borrowing capacity, under the ARP Credit Agreement is impacted by the level of its oil and natural gas reserves. Downward revisions of its oil and natural gas reserves volume and value due to low commodity prices, the impact of lower estimated capital spending in response to lower prices, performance revisions, sales of assets or the incurrence of certain types of additional debt, among other items, could cause a reduction of its borrowing base in the future, and these reductions could be significant. The ARP Credit Agreement is currently in the process of its semi-annual redetermination. Based on projected market conditions, continued declines in commodity prices and recent conversations with its administrative agent, ARP expects that its borrowing base will be redetermined to a level below its outstanding borrowings of $672.0 million under the ARP Credit Agreement as of March 31, 2016. In the case of a borrowing base deficiency, the ARP Credit Agreement requires ARP to repay the deficiency, which it is permitted to do in equal monthly installments over a four-month period, or deposit additional collateral to eliminate such deficiency. If ARP’s borrowing base is redetermined below its current outstanding borrowings and ARP is unable to repay the deficiency or deposit additional collateral to eliminate such deficiency, there would be substantial doubt regarding ARP’s ability to continue as a going concern. In addition, if ARP is unable to remain in compliance with the covenants under its credit facilities or the indentures governing its senior notes, absent relief from its lenders or noteholders, as applicable, ARP may be forced to repay or refinance such indebtedness. Upon the occurrence of an event of default, the lenders under ARP’s credit facilities or holders or its notes, as applicable, could elect to declare all amounts outstanding immediately due and payable and the lenders could terminate all commitments to extend further credit. A breach of any of the covenants (including if ARP’s borrowing base is redetermined below its current outstanding borrowings and it is unable to repay the deficiency or deposit additional collateral to eliminate such deficiency) in these credit facilities or the indentures governing ARP’s senior notes, respectively, could result in an event of default thereunder as well as a cross-default under ARP’s other debt agreements and, in either case, our credit agreement. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, ARP will not have sufficient liquidity to repay all of its outstanding indebtedness, and as a result, there would be substantial doubt regarding ARP’s ability to continue as a going concern. As discussed above, ARP continually monitors the capital markets and its capital structure and may make changes to its capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening its balance sheet, meeting its debt service obligations and/or achieving cost efficiency. Although ARP has a significant hedge position for the remainder of 2016 through 2018, the forecasted long-term downturn in commodity prices has had a detrimental impact on ARP’s financial position. For example, ARP could pursue options such as refinancing, restructuring or reorganizing its indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address its liquidity concerns and high debt levels. ARP is evaluating various options with the lenders under the ARP Credit Agreement and ARP Term Loan Facility, and holders of ARP’s Senior Notes, but there is no certainty that ARP will be able to implement any such options, and ARP cannot provide any assurances that any refinancing or changes in its 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 its stakeholders, including CODI which would be directly allocated to its unitholders and reported on such unitholders’ separate returns (see Item 1A – Risk Factors for additional information). ARP also continues to implement various cost saving measures to reduce its capital, operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. ARP will continue to be opportunistic and aggressive in managing its cost structure and, in turn, its liquidity to meet its capital and operating needs. ARP cannot provide any assurances that any of these efforts will be successful or will result in cost reductions or cash flows or the timing of any such cost reductions or additional cash flows. It is also possible additional adjustments to ARP’s plan and outlook may occur based on market conditions and ARP’s needs at that time, which could include selling assets, liquidating all or a portion of its hedge portfolio, seeking additional partners to develop its assets, reducing or suspending the payments of distributions to preferred unitholders and/or reducing its planned capital program. In addition, to the extent commodity prices remain low or decline further, or ARP experiences disruptions in ARP’s longer-term access to or cost of capital, ARP’s ability to fund future capital expenditures or growth projects may be further impacted. Atlas Growth Partners - Liquidity and Capital Resources AGP has historically funded its operations, acquisitions and cash distributions primarily through cash generated from operations and financing activities, including its recent private placement. AGP’s future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2016. These lower commodity prices have negatively impacted AGP’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on AGP’s liquidity position. |
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 unitholders 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, except unit data): Three Months Ended March 31, 2016 2015 Net income (loss) $ (1,272 ) $ 53,479 Preferred unitholders’ dividends (339 ) (333 ) Income attributable to non-controlling interests (5,340 ) (58,298 ) Loss attributable to owner’s interest (period prior to the transfer of assets on February 27, 2015) — 10,475 Net income (loss) attributable to common unitholders (6,951 ) 5,323 Less: Net income attributable to participating securities – phantom units (1) — 13 Net income (loss) utilized in the calculation of net loss attributable to common unitholders per unit – diluted (1) $ (6,951 ) $ 5,310 (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 three months ended March 31, 2016, net loss attributable common unitholder’s ownership interest is not allocated to approximately 263,000 phantom units, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners, less income allocable to participating securities, by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of unit option awards 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 unitholder 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): Three Months Ended March 31, 2016 2015 Weighted average number of common unitholders per unit—basic 26,028 26,011 Add effect of dilutive incentive awards (1) — 63 Add effect of dilutive convertible preferred units (1) — 4,902 Weighted average number of common unitholders per unit—diluted 26,028 30,976 (1) For the three months ended March 31, 2016, 2,689,000 phantom units 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. For the three months ended March 31, 2016, potential common units issuable upon conversion of our Series A preferred units were excluded from the computation of diluted earnings attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive. |
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 March 31, 2016 and December 31, 2015, we reflected $3.9 million and $5.6 million, respectively, related to the value of the rabbi trust within other assets, net on our condensed combined consolidated balance sheets, and recorded corresponding liabilities of $3.9 million and $5.6 million as of those same dates, respectively, within asset retirement obligations and other on our condensed combined consolidated balance sheets. During the three months ended March 31, 2016, a $2.3 million distribution was made to participants related to the rabbi trust. No distributions were made to participants related to the rabbi trust for the three months ended March 31, 2015. |
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 condensed combined consolidated financial statements. In August 2015, the FASB updated the accounting guidance related to the balance sheet presentation of debt issuance costs specific to line-of-credit arrangements. The updated accounting guidance allows the option of presenting deferred debt issuance costs related to line-of-credit arrangements as an asset, and subsequently amortizing over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings. We adopted the updated accounting guidance effective January 1, 2016 and it did not have a material impact on our condensed combined consolidated financial statements. In February 2015, the FASB updated the accounting guidance related to consolidation under the variable interest entity and voting interest entity models. The updated accounting guidance modifies the consolidation guidance for variable interest entities, limited partnerships and similar legal entities. We adopted this accounting guidance upon its effective date of January 1, 2016, and it did not have a material impact on our condensed combined consolidated financial statements. In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued and provide footnote disclosures, if necessary. We adopted this accounting guidance on January 1, 2016, and provided enhanced disclosures, as applicable, within our condensed combined consolidated financial statements. 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. The updated accounting guidance provides companies with alternative methods of adoption. We are currently in the process of determining the impact that the updated accounting guidance will have on our condensed combined consolidated financial statements and our method of adoption. |
Summary of Significant Accoun20
Summary of Significant Accounting Policies (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
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, except unit data): Three Months Ended March 31, 2016 2015 Net income (loss) $ (1,272 ) $ 53,479 Preferred unitholders’ dividends (339 ) (333 ) Income attributable to non-controlling interests (5,340 ) (58,298 ) Loss attributable to owner’s interest (period prior to the transfer of assets on February 27, 2015) — 10,475 Net income (loss) attributable to common unitholders (6,951 ) 5,323 Less: Net income attributable to participating securities – phantom units (1) — 13 Net income (loss) utilized in the calculation of net loss attributable to common unitholders per unit – diluted (1) $ (6,951 ) $ 5,310 (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 three months ended March 31, 2016, net loss attributable common unitholder’s ownership interest is not allocated to approximately 263,000 phantom units, 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 unitholder 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): Three Months Ended March 31, 2016 2015 Weighted average number of common unitholders per unit—basic 26,028 26,011 Add effect of dilutive incentive awards (1) — 63 Add effect of dilutive convertible preferred units (1) — 4,902 Weighted average number of common unitholders per unit—diluted 26,028 30,976 (1) For the three months ended March 31, 2016, 2,689,000 phantom units 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. For the three months ended March 31, 2016, potential common units issuable upon conversion of our Series A preferred units were excluded from the computation of diluted earnings attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive. |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Property Plant And Equipment [Abstract] | |
Summary of Property, Plant and Equipment | The following is a summary of property, plant and equipment at the dates indicated (in thousands): March 31, December 31, Estimated Useful Lives 2016 2015 in Years Natural gas and oil properties: Proved properties: Leasehold interests $ 570,934 $ 569,377 Pre-development costs 7,047 6,529 Wells and related equipment 3,165,776 3,157,708 Total proved properties 3,743,757 3,733,614 Unproved properties 213,047 213,047 Support equipment 45,136 44,921 Total natural gas and oil properties 4,001,940 3,991,582 Pipelines, processing and compression facilities 60,589 59,733 15 – 20 Rights of way 829 829 20 – 40 Land, buildings and improvements 9,798 9,798 3 – 40 Other 18,420 18,405 3 – 10 4,091,576 4,080,347 Less – accumulated depreciation, depletion and amortization (2,795,939 ) (2,763,450 ) $ 1,295,637 $ 1,316,897 |
Debt (Tables)
Debt (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Debt Disclosure [Abstract] | |
Schedule of Total Long-term Debt Instruments | Total debt consists of the following at the dates indicated (in thousands): March 31, December 31, 2016 2015 Term loan facilities $ 70,855 $ 72,700 Deferred financing costs (216 ) (3,813 ) ARP revolving credit facility 672,000 592,000 ARP term loan facility 244,159 243,783 ARP 7.75% Senior Notes—due 2021 354,366 374,619 ARP 9.25% Senior Notes—due 2021 312,055 324,080 ARP deferred financing costs (28,820 ) (31,055 ) Total debt, net 1,624,399 1,572,314 Less current maturities (976,795 ) (4,250 ) Total long-term debt, net $ 647,604 $ 1,568,064 |
Schedule of Retrospective Effect of Debt Issuance Cost Reclassification | The retrospective effect of the reclassification resulted in the following changes: Condensed Combined Consolidated Balance Sheet Previously Filed Adjustment Restated December 31, 2015: Other assets, net $ 88,980 $ (34,868 ) $ 54,112 Long-term debt, less current portion $ 1,602,932 $ (34,868 ) $ 1,568,064 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Derivatives Fair Value [Line Items] | |
Summary of Commodity Derivative Activity Presentation in Statement of Operations | The following table summarizes the commodity derivative activity and presentation in our condensed combined consolidated statement of operations for the periods indicated (in thousands): Three Months Ended March 31, 2016 2015 Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets (1) $ 3,515 $ 27,343 Portion of settlements attributable to subsequent mark to market gains 45,430 15,203 Total cash settlements on commodity derivative contracts $ 48,945 $ 42,546 Gains recognized on cash settlement (2) $ 6,025 $ 3,203 Gains recognized on open derivative contracts (2) 40,428 102,382 Gains on mark-to-market derivatives $ 46,453 $ 105,585 (1) Recognized in gas and oil production revenue. (2) Recognized in gain on mark-to-market derivatives. |
Fair Value of Derivative Instruments Table | The following table summarizes the gross fair values of AGP’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our condensed combined consolidated balance sheets as of the dates indicated (in thousands): Offsetting Derivatives as of March 31, 2016 Gross Amounts Recognized Gross Amounts Offset Net Amount Presented Current portion of derivative assets $ 366 $ (52 ) $ 314 Long-term portion of derivative assets 196 (3 ) 193 Total derivative assets $ 562 $ (55 ) $ 507 Current portion of derivative liabilities $ (52 ) $ 52 $ — Long-term portion of derivative liabilities (3 ) 3 — Total derivative liabilities $ (55 ) $ 55 $ — Offsetting Derivatives as of December 31, 2015 Current portion of derivative assets $ 399 $ (96 ) $ 303 Long-term portion of derivative assets 162 (53 ) 109 Total derivative assets $ 561 $ (149 ) $ 412 Current portion of derivative liabilities $ (96 ) $ 96 $ — Long-term portion of derivative liabilities (53 ) 53 — Total derivative liabilities $ (149 ) $ 149 $ — |
Commodity Derivative Instruments by Type Table | At March 31, 2016, AGP had the following commodity derivatives: Type Production Period Ending December 31, Volumes (1) Average Fixed Price (1) Fair Value Asset/(Liability) Total Type (in thousands) (2) (in thousands) (2) Crude Oil – Fixed Price Swaps 2016 (3) 53,600 $ 45.585 $ 253 2017 37,100 $ 49.968 $ 200 2018 26,500 $ 48.850 $ 54 AGP’s net assets $ 507 (1) Volumes for crude oil are stated in barrels. (2) Fair value of crude oil fixed price swaps are based on forward WTI crude oil prices, as applicable. (3) The production volumes for 2016 include the remaining nine months of 2016 beginning April 1, 2016. |
Atlas Resource Partners, L.P. | |
Derivatives Fair Value [Line Items] | |
Fair Value of Derivative Instruments Table | The following table summarizes the gross fair values of ARP’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our condensed combined consolidated balance sheets as of the dates indicated (in thousands): Offsetting Derivatives as of March 31, 2016 Gross Amounts Recognized Gross Amounts Offset Net Amount Presented Current portion of derivative assets $ 159,745 $ — $ 159,745 Long-term portion of derivative assets 195,074 — 195,074 Total derivative assets $ 354,819 $ — $ 354,819 Current portion of derivative liabilities $ — $ — $ — Long-term portion of derivative liabilities — — — Total derivative liabilities $ — $ — $ — Offsetting Derivatives as of December 31, 2015 Current portion of derivative assets $ 159,460 $ — $ 159,460 Long-term portion of derivative assets 198,262 — 198,262 Total derivative assets $ 357,722 $ — $ 357,722 Current portion of derivative liabilities $ — $ — $ — Long-term portion of derivative liabilities — — — Total derivative liabilities $ — $ — $ — |
Commodity Derivative Instruments by Type Table | At March 31, 2016, ARP had the following commodity derivatives: Type Production Period Ending December 31, Volumes (1) Average Fixed Price (1) Fair Value Asset Total type (in thousands) (2) (in thousands) (2) Natural Gas – Fixed Price Swaps 2016 (3) 40,354,500 $ 4.226 $ 80,594 2017 50,120,000 $ 4.221 $ 72,296 2018 40,300,000 $ 4.168 $ 51,782 2019 15,860,000 $ 4.019 $ 16,932 $ 221,604 Natural Gas – Put Options – Drilling Partnerships 2016 (3) 1,080,000 $ 4.150 $ 2,078 $ 2,078 Crude Oil – Fixed Price Swaps 2016 (3) 1,230,800 $ 81.685 $ 49,864 2017 1,200,000 $ 77.610 $ 39,372 2018 1,080,000 $ 76.281 $ 31,413 2019 540,000 $ 68.371 $ 10,488 $ 131,137 Total ARP net assets $ 354,819 (1) Volumes for natural gas are stated in million British Thermal Units. Volumes for crude oil are stated in barrels. (2) Fair value for natural gas fixed price swaps and natural gas put options based on forward NYMEX natural gas prices, as applicable. Fair value for crude oil fixed price swaps are based on forward WTI crude oil prices, as applicable. (3) The production volumes for 2016 include the remaining nine months of 2016 beginning April 1, 2016. |
Fair Value of Financial Instr24
Fair Value of Financial Instruments (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Company, ARP Financial Instruments Measured at Fair Value | Information for our and our subsidiaries’ financial instruments measured at fair value at March 31, 2016 and December 31, 2015 were as follows (in thousands): Level 1 Level 2 Level 3 Total As of March 31, 2016 Assets, gross Rabbi trust $ 3,904 $ — $ — $ 3,904 ARP Commodity swaps — 352,741 — 352,741 ARP Commodity puts — 2,078 — 2,078 AGP Commodity swaps — 562 — 562 Total assets, gross 3,904 355,381 — 359,285 Liabilities, gross AGP Commodity swaps — (55 ) — (55 ) Total derivative liabilities, gross — (55 ) — (55 ) Total assets, fair value, net $ 3,904 $ 355,326 $ — $ 359,320 As of December 31, 2015 Assets, gross Rabbi trust $ 5,584 $ — $ — $ 5,584 ARP Commodity swaps — 355,329 — 355,329 ARP Commodity puts — 2,393 — 2,393 AGP Commodity swaps — 561 — 561 Total assets, gross 5,584 358,283 — 363,867 Liabilities, gross AGP Commodity swaps — (149 ) — (149 ) Total derivative liabilities, gross $ — $ (149 ) $ — $ (149 ) Total assets, fair value, net 5,584 358,134 — 363,718 |
Operating Segment Information (
Operating Segment Information (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Segment Reporting [Abstract] | |
Operating Segment Data | Our operations include three reportable operating segments: ARP, AGP, and corporate and other. These operating segments reflect the way we manage our operations and make business decisions. Corporate and other includes our equity investment in Lightfoot (see Note 1), as well as our general and administrative and interest expenses. Operating segment data for the periods indicated were as follows (in thousands): Three Months Ended March 31, 2016 2015 Atlas Resource Partners: Revenues $ 103,208 $ 243,589 Operating costs and expenses (59,202 ) (87,818 ) Depreciation, depletion and amortization expense (30,045 ) (42,991 ) Gain (loss) on asset sales and disposal 9 (11 ) Interest expense (27,705 ) (25,197 ) Gain on early extinguishment of debt 26,498 — Segment income $ 12,763 $ 87,572 Atlas Growth Partners: Revenues $ 3,434 $ 2,311 Operating costs and expenses (3,503 ) (5,069 ) Depreciation, depletion and amortization expense (4,227 ) (1,465 ) Segment loss $ (4,296 ) $ (4,223 ) Corporate and other: Revenues $ 211 $ (101 ) General and administrative (2,154 ) (20,215 ) Interest expense (1,743 ) (9,554 ) Loss on early extinguishment of debt (6,053 ) — Segment loss $ (9,739 ) $ (29,870 ) Reconciliation of segment loss to net loss: Segment income (loss): Atlas Resource Partners $ 12,763 $ 87,572 Atlas Growth Partners (4,296 ) (4,223 ) Corporate and other $ (9,739 ) $ (29,870 ) Net income (loss) $ (1,272 ) $ 53,479 Reconciliation of segment revenues to total revenues: Segment revenues: Atlas Resource Partners $ 103,208 $ 243,589 Atlas Growth Partners 3,434 2,311 Corporate and other 211 (101 ) Total revenues $ 106,853 $ 245,799 Capital expenditures: Atlas Resource Partners $ 13,170 $ 42,498 Atlas Growth Partners 5,549 9,943 Corporate and other — — Total capital expenditures $ 18,719 $ 52,441 March 31, December 31, 2016 2015 Balance sheet: Goodwill: Atlas Resource Partners $ 13,639 $ 13,639 Atlas Growth Partners — — Corporate and other — — Total goodwill $ 13,639 $ 13,639 Total assets: Atlas Resource Partners $ 1,679,497 $ 1,699,949 Atlas Growth Partners 147,752 159,622 Corporate and other 16,530 23,675 Total assets $ 1,843,779 $ 1,883,246 |
Basis of Presentation (Narrativ
Basis of Presentation (Narrative) (Details) - USD ($) | Jun. 30, 2015 | Feb. 27, 2015 | Mar. 31, 2016 | Mar. 31, 2015 |
Basis Of Presentation [Line Items] | ||||
Percentage of interest represented by common units which is effected by pro rata distribution | 100.00% | |||
Distributions received from unconsolidated companies | $ 471,000 | $ 455,000 | ||
Limited partners units issued | 26,027,992 | |||
Limited partners units outstanding | 26,027,992 | |||
Lightfoot Capital Partners, LP | ||||
Basis Of Presentation [Line Items] | ||||
General partner ownership interest | 15.40% | |||
Common limited partner ownership interest | 12.00% | |||
Distributions received from unconsolidated companies | $ 500,000 | $ 500,000 | ||
Preferred Limited Partner Units | ||||
Basis Of Presentation [Line Items] | ||||
Common limited partner interest in ARP, units | 3,749,986 | |||
Atlas Resource Partners, L.P. | ||||
Basis Of Presentation [Line Items] | ||||
General partner ownership interest | 100.00% | |||
Common limited partner ownership interest | 23.30% | |||
Common limited partner interest in ARP, units | 20,962,485 | |||
Atlas Growth Partners, L.P | ||||
Basis Of Presentation [Line Items] | ||||
General partner ownership interest | 80.00% | |||
Common limited partner ownership interest | 2.10% | |||
Common limited partner units issued | $ 233,000,000 | |||
Common limited partner units purchased | $ 5,000,000 | |||
Minimum offering proceeds to break escrow | $ 1,000,000 | |||
Maximum offering proceeds of primary offering | $ 1,000,000,000 | |||
Atlas Growth Partners, L.P | Class A Common Units | ||||
Basis Of Presentation [Line Items] | ||||
Partners unit issue price per share | $ 10 | |||
Partners unit issued, under distribution reinvestment plan | 21,505,376 | |||
Partners unit issue price per share under distribution reinvestment plan | $ 9.30 | |||
Atlas Growth Partners, L.P | Class T Common Units | ||||
Basis Of Presentation [Line Items] | ||||
Common units aggregate offering | 100,000,000 | |||
Partners unit issue price per share | $ 9.60 | |||
Deferred payment obligation price per share | $ 0.40 | |||
Atlas Growth Partners, L.P | Maximum | Class A Common Units | ||||
Basis Of Presentation [Line Items] | ||||
Common units aggregate offering | 100,000,000 |
Summary of Significant Accoun27
Summary of Significant Accounting Policies (Narrative) (Details) - USD ($) | Jun. 05, 2015 | Mar. 31, 2016 | Mar. 31, 2015 | May. 10, 2016 | Dec. 31, 2015 | Jul. 31, 2013 |
Summary Of Significant Accounting Policies [Line Items] | ||||||
Repayments under credit facilities | $ 55,000,000 | $ 298,000,000 | ||||
Pro-rata share in Drilling Partnerships | 30.00% | |||||
Partners unit, issued | 245,175 | 420,586 | ||||
Rabbi Trust other assets | $ 54,713,000 | $ 54,112,000 | ||||
Rabbi trust other liabilities recorded | 127,708,000 | 124,919,000 | ||||
Rabbi trust | ||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||
Rabbi Trust other assets | 3,900,000 | 5,600,000 | ||||
Rabbi trust other liabilities recorded | 3,900,000 | 5,600,000 | ||||
Partnership distributed to participants | 2,300,000 | $ 0 | ||||
Ninth Amendment | Subsequent Event | ||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||
Outstanding borrowings, repayment amount required | $ 2,500,000 | |||||
First and Second Lien Credit Agreement | Current Portion Of Long Term Debt | ||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||
Revolving credit facility | 70,800,000 | |||||
Deferred financing costs | 200,000 | |||||
Atlas Resource Partners, L.P. | ||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||
Revolving credit facility | 672,000,000 | 592,000,000 | ||||
Deferred financing costs | 28,820,000 | 31,055,000 | ||||
Term loan facilities | $ 244,159,000 | $ 243,783,000 | ||||
Atlas Resource Partners, L.P. | Ninth Amendment | ||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||
Line of credit facility covenant terms | On May 10, 2016, ARP entered into a ninth amendment (the “Ninth Amendment”) to its Second Amended and Restated Credit Agreement, dated July 31, 2013 (as amended from time to time, the “ARP Credit Agreement”), with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto, to, among other things, waive the requirement that ARP’s ratio of current assets to current liabilities (as calculated pursuant to the ARP Credit Agreement) not be less than 1.0 to 1.0 as of March 31, 2016 and waive the requirement that ARP’s ratio of the total First Lien Debt to EBITDA (as calculated pursuant to the ARP Credit Agreement) not be greater than 2.75 to 1.0 as of March 31, 2016, and required ARP to repay $2.5 million of outstanding borrowings. ARP is party to a Second Lien Credit Agreement, dated February 23, 2015, with certain lenders and Wilmington Trust, National Association, as administrative agent (the “ARP Term Loan Facility”), which contains the same financial covenants as those in the ARP Credit Agreement, and were automatically waived as a result of the Ninth Amendment to the Credit Agreement. | |||||
Required current assets to current liabilities ratio | 1.00% | |||||
Atlas Resource Partners, L.P. | Current Portion Of Long Term Debt | Ninth Amendment | ||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||
Revolving credit facility | $ 672,000,000 | |||||
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 | 6,500,000 | |||||
Business acquisition, effective date of acquisition | Jan. 1, 2015 | |||||
Secured Term Facility | ||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||
Repayments under credit facilities | 150,000,000 | |||||
Credit facility | $ 240,000,000 | |||||
Term loan facilities | Atlas Resource Partners, L.P. | ||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||
Credit facility | 250,000,000 | |||||
Term Loan Facilities, unamortized discount | 5,800,000 | |||||
Term loan facilities | Atlas Resource Partners, L.P. | Current Portion Of Long Term Debt | Ninth Amendment | ||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||
Deferred financing costs | 10,000,000 | |||||
Term loan facilities | 234,200,000 | |||||
Term Loan Facilities, unamortized discount | 5,800,000 | |||||
Series A Preferred Units | Secured Term Facility | ||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||
Proceeds from Issuance of Convertible Preferred Stock | $ 150,000,000 |
Summary of Significant Accoun28
Summary of Significant Accounting Policies (Schedule of Net Income (Loss) Reconciliation) (Details) - USD ($) $ in Thousands | 3 Months Ended | ||
Mar. 31, 2016 | Mar. 31, 2015 | ||
Reconciliation Of Net Income [Line Items] | |||
Net income (loss) | $ (1,272) | $ 53,479 | |
Preferred unitholders’ dividends | (339) | (333) | |
Income attributable to non-controlling interests | (5,340) | (58,298) | |
Portion applicable to owner’s interest (period prior to the transfer of assets on February 27, 2015) | 10,475 | ||
Net income (loss) attributable to common unitholders | (6,951) | 5,323 | |
Less: Net income attributable to participating securities – phantom units | [1] | 13 | |
Net income (loss) utilized in the calculation of net loss attributable to common unitholders per unit – diluted | [1] | $ (6,951) | 5,310 |
Antidilutive Phantom Unit Securities Excluded from Computation of Diluted Earnings Attributable to Common Unit Holders Outstanding Units | 263,000 | ||
Continuing Operations | |||
Reconciliation Of Net Income [Line Items] | |||
Preferred unitholders’ dividends | $ (339) | $ (333) | |
[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 three months ended March 31, 2016, net loss attributable common unitholder’s ownership interest is not allocated to approximately 263,000 phantom units, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. |
Summary of Significant Accoun29
Summary of Significant Accounting Policies (Reconciliation of Weighted Average Number of Common Unit Holder Units) (Details) - shares | 3 Months Ended | ||
Mar. 31, 2016 | Mar. 31, 2015 | ||
Accounting Policies [Abstract] | |||
Weighted average number of common unitholders per unit—basic | 26,028,000 | 26,011,000 | |
Add effect of dilutive incentive awards | [1] | 63,000 | |
Add effect of dilutive convertible preferred units | [1] | 4,902,000 | |
Weighted average number of common unitholders per unit—diluted | 26,028,000 | 30,976,000 | |
Antidilutive Securities Excluded From Computation Of Diluted Net Income (Loss) Attributable To Common Limited Partners Outstanding Units | 2,689,000 | ||
[1] | For the three months ended March 31, 2016, 2,689,000 phantom units 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. For the three months ended March 31, 2016, potential common units issuable upon conversion of our Series A preferred units were excluded from the computation of diluted earnings attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive. |
Property, Plant and Equipment30
Property, Plant and Equipment (Summary of Property, Plant and Equipment) (Details) - USD ($) $ in Thousands | Mar. 31, 2016 | Dec. 31, 2015 |
Property Plant And Equipment [Abstract] | ||
Proved properties: Leasehold interests | $ 570,934 | $ 569,377 |
Proved properties: Pre-development costs | 7,047 | 6,529 |
Proved properties: Wells and related equipment | 3,165,776 | 3,157,708 |
Total proved properties | 3,743,757 | 3,733,614 |
Unproved properties | 213,047 | 213,047 |
Support equipment | 45,136 | 44,921 |
Total natural gas and oil properties | 4,001,940 | 3,991,582 |
Pipelines, processing and compression facilities | 60,589 | 59,733 |
Rights of way | 829 | 829 |
Land, buildings and improvements | 9,798 | 9,798 |
Other | 18,420 | 18,405 |
Total gross property, plant and equipment | 4,091,576 | 4,080,347 |
Less – accumulated depreciation, depletion and amortization | (2,795,939) | (2,763,450) |
Property, plant and equipment, Net, Total | $ 1,295,637 | $ 1,316,897 |
Property, Plant and Equipment31
Property, Plant and Equipment (Useful Life Narrative) (Details) | 3 Months Ended |
Mar. 31, 2016 | |
Pipelines, processing and compression facilities | Minimum | |
Property Plant And Equipment [Line Items] | |
Property, plant and equipment useful life | 15 years |
Pipelines, processing and compression facilities | Maximum | |
Property Plant And Equipment [Line Items] | |
Property, plant and equipment useful life | 20 years |
Rights of way | Minimum | |
Property Plant And Equipment [Line Items] | |
Property, plant and equipment useful life | 20 years |
Rights of way | Maximum | |
Property Plant And Equipment [Line Items] | |
Property, plant and equipment useful life | 40 years |
Land, buildings and improvements | Minimum | |
Property Plant And Equipment [Line Items] | |
Property, plant and equipment useful life | 3 years |
Land, buildings and improvements | Maximum | |
Property Plant And Equipment [Line Items] | |
Property, plant and equipment useful life | 40 years |
Other | Minimum | |
Property Plant And Equipment [Line Items] | |
Property, plant and equipment useful life | 3 years |
Other | Maximum | |
Property Plant And Equipment [Line Items] | |
Property, plant and equipment useful life | 10 years |
Property, Plant and Equipment32
Property, Plant and Equipment (Narrative) (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Property Plant And Equipment [Line Items] | ||
Non-cash property, plant and equipment additions | $ 18.7 | $ 26.4 |
Atlas Resource Partners, L.P. | ||
Property Plant And Equipment [Line Items] | ||
Weighted average interest rate used to capitalize interest | 6.70% | 6.10% |
Interest costs capitalized | $ 2.4 | $ 3.9 |
Liabilities incurred in asset retirement obligations | 2.8 | 0.2 |
Atlas Resource Partners, L.P. | Depreciation, depletion and amortization | ||
Property Plant And Equipment [Line Items] | ||
Accretion expense related to asset retirement obligations | $ 1.7 | $ 1.6 |
Debt (Schedule of Total Debt Ou
Debt (Schedule of Total Debt Outstanding) (Details) - USD ($) $ in Thousands | Mar. 31, 2016 | Dec. 31, 2015 |
Debt Instrument [Line Items] | ||
Total debt, net | $ 1,624,399 | $ 1,572,314 |
Less current maturities | (976,795) | (4,250) |
Total long-term debt, net | $ 647,604 | 1,568,064 |
9.25% Senior Notes | ||
Debt Instrument [Line Items] | ||
Debt instrument, interest rate, stated percentage | 9.25% | |
Atlas Energy | ||
Debt Instrument [Line Items] | ||
Deferred financing costs | $ (216) | (3,813) |
Atlas Energy | Term loan facilities | ||
Debt Instrument [Line Items] | ||
Term loan facilities | 70,855 | 72,700 |
Atlas Resource Partners, L.P. | ||
Debt Instrument [Line Items] | ||
Term loan facilities | 244,159 | 243,783 |
Deferred financing costs | (28,820) | (31,055) |
Revolving credit facility | 672,000 | 592,000 |
Atlas Resource Partners, L.P. | 7.75% Senior Notes | ||
Debt Instrument [Line Items] | ||
Senior Notes | $ 354,366 | $ 374,619 |
Debt instrument, interest rate, stated percentage | 7.75% | 7.75% |
Atlas Resource Partners, L.P. | 9.25% Senior Notes | ||
Debt Instrument [Line Items] | ||
Senior Notes | $ 312,055 | $ 324,080 |
Debt instrument, interest rate, stated percentage | 9.25% | 9.25% |
Debt (Schedule of Retrospective
Debt (Schedule of Retrospective Effect of Debt Issuance Cost Reclassification) (Details) - USD ($) $ in Thousands | Mar. 31, 2016 | Dec. 31, 2015 |
Debt Instrument [Line Items] | ||
Other assets, net | $ 54,713 | $ 54,112 |
Long-term debt, net, less current portion | $ 647,604 | 1,568,064 |
Previously Filed | ||
Debt Instrument [Line Items] | ||
Other assets, net | 88,980 | |
Long-term debt, net, less current portion | 1,602,932 | |
Adjustment | ||
Debt Instrument [Line Items] | ||
Other assets, net | (34,868) | |
Long-term debt, net, less current portion | $ (34,868) |
Debt (Narrative) (Details)
Debt (Narrative) (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Debt Disclosure [Abstract] | ||
Cash Payments For Interest On Debt | $ 42.6 | $ 38.5 |
Debt (Term Loan Facilities) (De
Debt (Term Loan Facilities) (Details) | Apr. 27, 2016$ / sharesshares | Mar. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Sep. 30, 2017 |
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% | |||
Third Amendment | ||||
Debt Instrument [Line Items] | ||||
Debt maturities, excluding future payment-in-kind interest payments, 2017 | $ 992,900,000 | |||
Debt maturities, excluding future payment-in-kind interest payments, 2021 | $ 667,700,000 | |||
Term loan facilities | ||||
Debt Instrument [Line Items] | ||||
Deemed prepayment premium | $ 2,400,000 | |||
Term loan facilities | Maximum | ||||
Debt Instrument [Line Items] | ||||
Market Capitalization | 75,000,000 | |||
Term loan facilities | Third Amendment | ||||
Debt Instrument [Line Items] | ||||
Prepayment of outstanding principal | 4,250,000 | |||
Prepayment of interest | 500,000 | |||
First Lien Credit Agreement | Term loan facilities | ||||
Debt Instrument [Line Items] | ||||
Term loan facilities | $ 35,000,000 | |||
First Lien Credit Agreement | Term loan facilities | 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 | Term loan facilities | 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 | Term loan facilities | Third Amendment | Eurodollar Loans | ||||
Debt Instrument [Line Items] | ||||
Cash interest rate margin | 1.50% | |||
First Lien Credit Agreement | Term loan facilities | Third Amendment | Maximum | ||||
Debt Instrument [Line Items] | ||||
Leverage ratio | 6 | |||
Extension fee percentage | 5.00% | |||
Second lien term loan facility | ||||
Debt Instrument [Line Items] | ||||
Warrants Issue Date | Apr. 27, 2016 | |||
Warrants, expiration date | Mar. 30, 2026 | |||
Second lien term loan facility | Subsequent Event | ||||
Debt Instrument [Line Items] | ||||
Investment warrants exercise price | $ / shares | $ 0.20 | |||
Second lien term loan facility | Maximum | Subsequent Event | ||||
Debt Instrument [Line Items] | ||||
Warrant to purchase common units | shares | 4,668,044 | |||
Second lien term loan facility | Minimum | Scenario Forecast | ||||
Debt Instrument [Line Items] | ||||
Asset coverage ratio | 2 | |||
Second lien term loan facility | Term loan facilities | ||||
Debt Instrument [Line Items] | ||||
Term loan facilities | $ 35,800,000 | |||
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 | Term loan facilities | Maximum | ||||
Debt Instrument [Line Items] | ||||
Leverage ratio | 6 | |||
Extension fee percentage | 5.00% | |||
First and Second Lien Credit Agreement | Current Portion Of Long Term Debt | ||||
Debt Instrument [Line Items] | ||||
Revolving credit facility | $ 70,800,000 | |||
Deferred financing costs | $ 200,000 |
Debt (ARP Credit Facility) (Det
Debt (ARP Credit Facility) (Details) - USD ($) | 3 Months Ended | ||
Mar. 31, 2016 | May. 10, 2016 | Dec. 31, 2015 | |
Line Of Credit Facility [Line Items] | |||
Line of Credit Facility, weighted average interest rate | 10.00% | ||
Revolving Credit Facility | |||
Line Of Credit Facility [Line Items] | |||
Required current assets to current liabilities ratio | 1.00% | ||
Ninth Amendment | Subsequent Event | |||
Line Of Credit Facility [Line Items] | |||
Outstanding borrowings, repayment amount required | $ 2,500,000 | ||
Atlas Resource Partners, L.P. | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility | $ 672,000,000 | $ 592,000,000 | |
Atlas Resource Partners, L.P. | Revolving Credit Facility | |||
Line Of Credit Facility [Line Items] | |||
Amended borrowing base | 700,000,000 | ||
Line Of Credit Facility Maximum Borrowing Capacity | $ 1,500,000,000 | ||
Line of credit facility, expiration date | Jul. 1, 2018 | ||
Revolving credit facility | $ 672,000,000 | ||
Letters of credit outstanding maximum | 20,000,000 | ||
Letters of credit outstanding amount | $ 4,200,000 | ||
Line of Credit Facility collateral | ARP’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by certain of ARP’s material subsidiaries, and any non-guarantor subsidiaries of ARP are minor. | ||
Line of Credit Facility interest rate description | At March 31, 2016, the weighted average interest rate on outstanding borrowings under the credit facility was 3.6%. | ||
Line of Credit Facility, weighted average interest rate | 3.60% | ||
Aggregate principal amount | $ 300,000,000 | ||
Line of credit facility covenant terms | The ARP Credit Agreement contains customary covenants including, without limitation, covenants that limit ARP’s ability to incur additional indebtedness (but which permits second lien debt in an aggregate principal amount of up to $300.0 million and third lien debt that satisfies certain conditions including pro forma financial covenants), grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merge or consolidate with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. The ARP Credit Agreement also requires that ARP maintain a ratio of First Lien Debt to EBITDA (ratio as defined in the Credit Agreement) of not greater than 2.75 to 1.00, and a ratio of current assets to current liabilities (ratio as defined in the ARP Credit Agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter. | ||
Atlas Resource Partners, L.P. | Ninth Amendment | |||
Line Of Credit Facility [Line Items] | |||
Line of credit facility covenant terms | On May 10, 2016, ARP entered into a ninth amendment (the “Ninth Amendment”) to its Second Amended and Restated Credit Agreement, dated July 31, 2013 (as amended from time to time, the “ARP Credit Agreement”), with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto, to, among other things, waive the requirement that ARP’s ratio of current assets to current liabilities (as calculated pursuant to the ARP Credit Agreement) not be less than 1.0 to 1.0 as of March 31, 2016 and waive the requirement that ARP’s ratio of the total First Lien Debt to EBITDA (as calculated pursuant to the ARP Credit Agreement) not be greater than 2.75 to 1.0 as of March 31, 2016, and required ARP to repay $2.5 million of outstanding borrowings. ARP is party to a Second Lien Credit Agreement, dated February 23, 2015, with certain lenders and Wilmington Trust, National Association, as administrative agent (the “ARP Term Loan Facility”), which contains the same financial covenants as those in the ARP Credit Agreement, and were automatically waived as a result of the Ninth Amendment to the Credit Agreement. | ||
Required current assets to current liabilities ratio | 1.00% | ||
Line of Credit Facility, Covenant Compliance | On May 10, 2016, ARP entered into the Ninth Amendment to the ARP Credit Agreement, to, among other things, waive the requirement that ARP’s ratio of current assets to current liabilities (as calculated pursuant to the ARP Credit Agreement) not be less than 1.0 to 1.0 as of March 31, 2016 and waive the requirement that ARP’s ratio of the total First Lien Debt to EBITDA (as calculated pursuant to the ARP Credit Agreement) not be greater than 2.75 to 1.0 as of March 31, 2016, and required ARP to repay $2.5 million of outstanding borrowings. | ||
Atlas Resource Partners, L.P. | Ninth Amendment | Current Portion Of Long Term Debt | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility | $ 672,000,000 |
Debt (ARP Term Loan Facility) (
Debt (ARP Term Loan Facility) (Details) - USD ($) | 3 Months Ended | |
Mar. 31, 2016 | Dec. 31, 2015 | |
Debt Instrument [Line Items] | ||
Line of Credit Facility, weighted average interest rate | 10.00% | |
Atlas Resource Partners, L.P. | ||
Debt Instrument [Line Items] | ||
Term loan facilities | $ 244,159,000 | $ 243,783,000 |
Deferred financing costs | 28,820,000 | $ 31,055,000 |
Atlas Resource Partners, L.P. | Term Loan Facility | ||
Debt Instrument [Line Items] | ||
Line of Credit Facility, aggregate principal amount | $ 250,000,000 | |
Line of credit facility, expiration date | Feb. 23, 2020 | |
Term Loan Facilities, unamortized discount | $ 5,800,000 | |
Atlas Resource Partners, L.P. | Term Loan Facility | Ninth Amendment | Current Portion Of Long Term Debt | ||
Debt Instrument [Line Items] | ||
Term Loan Facilities, unamortized discount | 5,800,000 | |
Term loan facilities | 234,200,000 | |
Deferred financing costs | $ 10,000,000 |
Debt (ARP Senior Notes) (Detail
Debt (ARP Senior Notes) (Details) - USD ($) | Mar. 31, 2016 | Mar. 31, 2016 | Mar. 31, 2015 | Dec. 31, 2015 |
Debt Instrument [Line Items] | ||||
Cash Payments For Interest On Debt | $ 42,600,000 | $ 38,500,000 | ||
Gain on early extinguishment of debt | $ 20,445,000 | $ 0 | ||
Debt instrument, restrictive covenants | The indentures governing the 7.75% ARP Senior Notes and 9.25% ARP Senior Notes contain covenants including, without limitation, covenants that limit ARP’s ability to incur certain liens, incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase, or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of ARP’s assets. | |||
Debt instrument, covenant compliance | ARP was in compliance with these covenants as of March 31, 2016. | |||
7.75% Senior Notes | ||||
Debt Instrument [Line Items] | ||||
Senior Notes, maturity | 2,021 | |||
Restrictions as to the ability to obtain cash or any other distribution of funds from the guarantor | $ 0 | |||
9.25% Senior Notes | ||||
Debt Instrument [Line Items] | ||||
Aggregate principal amount | $ 312,100,000 | $ 312,100,000 | ||
Senior Notes, maturity | 2,021 | |||
Debt instrument, interest rate, stated percentage | 9.25% | 9.25% | ||
Term Loan Facilities, unamortized discount | $ 900,000 | $ 900,000 | ||
9.25% Senior Notes due 2021 | ||||
Debt Instrument [Line Items] | ||||
Senior Notes, maturity | 2,021 | |||
Atlas Resource Partners, L.P. | ||||
Debt Instrument [Line Items] | ||||
Repayment of debt | $ 5,500,000 | |||
Cash Payments For Interest On Debt | 600,000 | |||
Gain on early extinguishment of debt | 26,500,000 | |||
Atlas Resource Partners, L.P. | 7.75% Senior Notes | ||||
Debt Instrument [Line Items] | ||||
Aggregate principal amount | $ 354,400,000 | $ 354,400,000 | ||
Senior Notes, maturity | 2,021 | |||
Debt instrument, interest rate, stated percentage | 7.75% | 7.75% | 7.75% | |
Term Loan Facilities, unamortized discount | $ 400,000 | $ 400,000 | ||
Senior unsecured notes, repurchased | $ 20,300,000 | $ 20,300,000 | ||
Atlas Resource Partners, L.P. | 9.25% Senior Notes | ||||
Debt Instrument [Line Items] | ||||
Debt instrument, interest rate, stated percentage | 9.25% | 9.25% | 9.25% | |
Senior unsecured notes, repurchased | $ 12,100,000 | $ 12,100,000 |
Derivative Instruments (Narrati
Derivative Instruments (Narrative) (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2016 | Mar. 31, 2015 | Dec. 31, 2015 | |
Derivative Instruments Gain Loss [Line Items] | |||
Net derivative assets | $ 355.3 | $ 358.1 | |
Net gain in accumulated other comprehensive income | 3.5 | ||
Cash flow hedge gain (losses) to be reclassified within twelve months | 2.7 | ||
Cash flow hedge gain (loss) to be reclassified in later periods | $ 0.8 | ||
Atlas Resource Partners, L.P. | Crude Oil and Natural Gas | |||
Derivative Instruments Gain Loss [Line Items] | |||
Proceeds from early termination of commodity derivatives | $ 4.9 |
Derivative Instruments (Summary
Derivative Instruments (Summary of Commodity Derivative Activity and Presentation in Partnership's Consolidated Statement of Operations) (Details) - USD ($) $ in Thousands | 3 Months Ended | ||
Mar. 31, 2016 | Mar. 31, 2015 | ||
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |||
Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets | [1] | $ 3,515 | $ 27,343 |
Portion of settlements attributable to subsequent mark to market gains | 45,430 | 15,203 | |
Total cash settlements on commodity derivative contracts | 48,945 | 42,546 | |
Gains recognized on cash settlement | [2] | 6,025 | 3,203 |
Gains recognized on open derivative contracts | [2] | 40,428 | 102,382 |
Gains on mark-to-market derivatives | $ 46,453 | $ 105,585 | |
[1] | Recognized in gas and oil production revenue. | ||
[2] | Recognized in gain on mark-to-market derivatives. |
Derivative Instruments (Fair Va
Derivative Instruments (Fair Values of the Company's Derivative Instruments Table) (Details) - USD ($) $ in Thousands | Mar. 31, 2016 | Dec. 31, 2015 |
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Assets | $ 359,285 | $ 363,867 |
Net derivative assets | 355,300 | 358,100 |
Gross Amounts Recognized, Liabilities | (55) | (149) |
Atlas Growth Partners, L.P | Derivative Financial Instruments Current Liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Liabilities | (52) | (96) |
Gross Amounts Offset, Liabilities | 52 | 96 |
Atlas Growth Partners, L.P | Derivative Financial Instruments Long Term Liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Liabilities | (3) | (53) |
Gross Amounts Offset, Liabilities | 3 | 53 |
Atlas Growth Partners, L.P | Derivative Financial Instruments Liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Liabilities | (55) | (149) |
Gross Amounts Offset, Liabilities | 55 | 149 |
Atlas Growth Partners, L.P | Current portion of derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Assets | 366 | 399 |
Gross Amounts Offset, Assets | (52) | (96) |
Net derivative assets | 314 | 303 |
Atlas Growth Partners, L.P | Long-term portion of derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Assets | 196 | 162 |
Gross Amounts Offset, Assets | (3) | (53) |
Net derivative assets | 193 | 109 |
Atlas Growth Partners, L.P | Total derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Assets | 562 | 561 |
Gross Amounts Offset, Assets | (55) | (149) |
Net derivative assets | $ 507 | $ 412 |
Derivative Instruments (The Com
Derivative Instruments (The Company's Commodity Derivative Instruments by Type Table) (Details) - Atlas Growth Partners, L.P - Natural Gas Liquids – Crude Oil Fixed Price Swaps $ in Thousands | Mar. 31, 2016USD ($)bbl$ / bbl | |
Derivatives Fair Value [Line Items] | ||
Fair Value Asset / (Liability) | $ 507 | [1] |
Production Period Ending December 31 2016 | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | bbl | 53,600 | [2],[3] |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 45.585 | [2],[3] |
Fair Value Asset / (Liability) | $ 253 | [1],[2] |
Production Period Ending December 31 2017 | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | bbl | 37,100 | [3] |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 49.968 | [3] |
Fair Value Asset / (Liability) | $ 200 | [1] |
Production Period Ending December 31 2018 | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | bbl | 26,500 | [3] |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 48.850 | [3] |
Fair Value Asset / (Liability) | $ 54 | [1] |
[1] | Fair value of crude oil fixed price swaps are based on forward WTI crude oil prices, as applicable | |
[2] | The production volumes for 2016 include the remaining nine months of 2016 beginning April 1, 2016. | |
[3] | Volumes for crude oil are stated in barrels |
Derivative Instruments (Fair 44
Derivative Instruments (Fair Value of ARP's Derivative Instruments Table) (Details) - USD ($) $ in Thousands | Mar. 31, 2016 | Dec. 31, 2015 |
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Assets | $ 359,285 | $ 363,867 |
Net derivative assets | 355,300 | 358,100 |
Gross Amounts Recognized, Liabilities | 55 | 149 |
Atlas Resource Partners, L.P. | Current portion of derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Assets | 159,745 | 159,460 |
Net derivative assets | 159,745 | 159,460 |
Atlas Resource Partners, L.P. | Long-term portion of derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Assets | 195,074 | 198,262 |
Net derivative assets | 195,074 | 198,262 |
Atlas Resource Partners, L.P. | Total derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Assets | 354,819 | 357,722 |
Net derivative assets | $ 354,819 | $ 357,722 |
Derivative Instruments (ARP's C
Derivative Instruments (ARP's Commodity Derivative Instruments by Type Table) (Details) - Atlas Resource Partners, L.P. $ in Thousands | Mar. 31, 2016USD ($)bblMMBTU$ / bbl$ / MMBTU | |
Derivatives Fair Value [Line Items] | ||
Fair Value Asset / (Liability) | $ 354,819 | [1] |
Natural Gas - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset / (Liability) | 221,604 | [1] |
Natural Gas Put Options Drilling Partnership | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset / (Liability) | 2,078 | [1] |
Natural Gas Liquids – Crude Oil Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset / (Liability) | $ 131,137 | [1] |
Production Period Ending December 31 2016 | Natural Gas - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | MMBTU | 40,354,500 | [2],[3] |
Derivative, Swap Type, Average Fixed Price | $ / MMBTU | 4.226 | [2],[3] |
Fair Value Asset / (Liability) | $ 80,594 | [1],[2] |
Production Period Ending December 31 2016 | Natural Gas Put Options Drilling Partnership | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | MMBTU | 1,080,000 | [2],[3] |
Derivative, Swap Type, Average Fixed Price | $ / MMBTU | 4.150 | [2],[3] |
Fair Value Asset / (Liability) | $ 2,078 | [1],[2] |
Production Period Ending December 31 2016 | Natural Gas Liquids – Crude Oil Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | bbl | 1,230,800 | [2],[3] |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 81.685 | [2],[3] |
Fair Value Asset / (Liability) | $ 49,864 | [1],[2] |
Production Period Ending December 31 2017 | Natural Gas - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | MMBTU | 50,120,000 | [3] |
Derivative, Swap Type, Average Fixed Price | $ / MMBTU | 4.221 | [3] |
Fair Value Asset / (Liability) | $ 72,296 | [1] |
Production Period Ending December 31 2017 | Natural Gas Liquids – Crude Oil Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | bbl | 1,200,000 | [3] |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 77.610 | [3] |
Fair Value Asset / (Liability) | $ 39,372 | [1] |
Production Period Ending December 31 2018 | Natural Gas - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | MMBTU | 40,300,000 | [3] |
Derivative, Swap Type, Average Fixed Price | $ / MMBTU | 4.168 | [3] |
Fair Value Asset / (Liability) | $ 51,782 | [1] |
Production Period Ending December 31 2018 | Natural Gas Liquids – Crude Oil Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | bbl | 1,080,000 | [3] |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 76.281 | [3] |
Fair Value Asset / (Liability) | $ 31,413 | [1] |
Production Period Ending December 31 2019 | Natural Gas - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | MMBTU | 15,860,000 | [3] |
Derivative, Swap Type, Average Fixed Price | $ / MMBTU | 4.019 | [3] |
Fair Value Asset / (Liability) | $ 16,932 | [1] |
Production Period Ending December 31 2019 | Natural Gas Liquids – Crude Oil Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | bbl | 540,000 | [3] |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 68.371 | [3] |
Fair Value Asset / (Liability) | $ 10,488 | [1] |
[1] | Fair value for natural gas fixed price swaps and natural gas put options based on forward NYMEX natural gas prices, as applicable. Fair value for crude oil fixed price swaps are based on forward WTI crude oil prices, as applicable. | |
[2] | The production volumes for 2016 include the remaining nine months of 2016 beginning April 1, 2016. | |
[3] | Volumes for natural gas are stated in million British Thermal Units. Volumes for crude oil are stated in barrels. |
Fair Value of Financial Instr46
Fair Value of Financial Instruments (Schedule of Financial Instruments at Fair Value) (Details) - USD ($) $ in Thousands | Mar. 31, 2016 | Dec. 31, 2015 |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | $ 359,285 | $ 363,867 |
Liabilities, gross | (55) | (149) |
Total assets, fair value, net | 359,320 | 363,718 |
Rabbi trust | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Rabbi trust | 3,904 | 5,584 |
Atlas Resource Partners, L.P. | Puts | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 2,078 | 2,393 |
Atlas Resource Partners, L.P. | Swap | Commodity Contract | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 352,741 | 355,329 |
Atlas Growth Partners, L.P | Swap | Commodity Contract | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 562 | 561 |
Liabilities, gross | (55) | (149) |
Level 1 | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 3,904 | 5,584 |
Total assets, fair value, net | 3,904 | 5,584 |
Level 1 | Rabbi trust | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Rabbi trust | 3,904 | 5,584 |
Level 2 | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 355,381 | 358,283 |
Liabilities, gross | (55) | (149) |
Total assets, fair value, net | 355,326 | 358,134 |
Level 2 | Atlas Resource Partners, L.P. | Puts | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 2,078 | 2,393 |
Level 2 | Atlas Resource Partners, L.P. | Swap | Commodity Contract | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets, gross | 352,741 | 355,329 |
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 | 562 | 561 |
Liabilities, gross | $ (55) | $ (149) |
Fair Value of Financial Instr47
Fair Value of Financial Instruments (Narrative) (Details) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Fair Value Disclosures [Abstract] | ||
Long-term debt, fair value | $ 1,096.9 | $ 929.2 |
Long-term debt | $ 1,624.4 | $ 1,572.3 |
Certain Relationships and Rel48
Certain Relationships and Related Party Transactions (Narrative) (Details) - USD ($) $ in Thousands | 3 Months Ended | ||
Mar. 31, 2016 | Mar. 31, 2015 | Dec. 31, 2015 | |
Related Party Transaction [Line Items] | |||
Accrued well drilling and completion costs | $ 4,731 | $ 33,555 | |
Relationship With Drilling Partnerships | |||
Related Party Transaction [Line Items] | |||
Related party transaction, description of transaction | ARP conducts certain activities through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. ARP serves as the ultimate general partner and operator of the Drilling Partnerships and assumes customary rights and obligations for the Drilling Partnerships. As the ultimate general partner, ARP is liable for the Drilling Partnerships’ liabilities and can be liable to limited partners of the Drilling Partnerships if it breaches its responsibilities with respect to the operations of the Drilling Partnerships. ARP is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Drilling Partnership’s revenue and costs and expenses according to the respective partnership agreements. | ||
Accounts Receivable, Related Parties, Current | $ 7,900 | 6,600 | |
Accounts Payable, Related Parties, Current | 3,900 | $ 3,000 | |
Capital raised from investors | 36,700 | ||
Accrued well drilling and completion costs | $ 13,300 | ||
Relationship with AGP | |||
Related Party Transaction [Line Items] | |||
Percentage of capital contribution | 1.00% | ||
Payment for management fee | $ 600 | $ 300 | |
Gross proceeds of private placement offering percentage | 2.00% |
Commitments and Contingencies (
Commitments and Contingencies (General Commitments) (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Percentage of present value of future cash flows | 10.00% | |
Net partnership revenues subordinated | $ 0.1 | $ 0.5 |
Commitment to expend | $ 9.1 | |
Minimum | ||
Partnership obligations to purchase units from investor partners | 5.00% | |
Investor partners return on investment | 10.00% | |
Maximum | ||
Partnership obligations to purchase units from investor partners | 10.00% | |
Percentage on unhedged revenue | 50.00% | |
Investor partners return on investment | 12.00% |
Issuances of Units (Preferred U
Issuances of Units (Preferred Unit Purchase Agreement) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | Mar. 18, 2016 | Jan. 12, 2016 | Jan. 07, 2016 | Feb. 27, 2015 | Mar. 31, 2016 |
Capital Unit [Line Items] | |||||
Percentage Of Common Unit Regular Quarterly Cash Distributions | 2.00% | ||||
Consecutive trading days | 30 days | 30 days | 30 days | ||
Maximum | |||||
Capital Unit [Line Items] | |||||
Average closing price of common unit | $ 1 | $ 1 | |||
Average market capitalization | $ 50 | ||||
Stockholders’ equity | $ 50 | ||||
Minimum | |||||
Capital Unit [Line Items] | |||||
Average market capitalization | $ 15 | ||||
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 ($) | Mar. 18, 2016 | Jan. 12, 2016 | Jan. 07, 2016 | Aug. 31, 2015 | Mar. 31, 2016 | Mar. 31, 2015 |
Capital Unit [Line Items] | ||||||
Partners unit, issued | 245,175 | 420,586 | ||||
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% | |||||
Proceeds from Issuance of Common Limited Partners Units | $ 200,000 | $ 3,300,000 | ||||
Payments for Commissions | $ 19,000 | $ 100,000 | ||||
Consecutive trading days | 30 days | 30 days | 30 days | |||
Maximum | ||||||
Capital Unit [Line Items] | ||||||
Average closing price of common unit | $ 1 | $ 1 | ||||
Class D Preferred Units | ||||||
Capital Unit [Line Items] | ||||||
Partners unit, issued | 800,000 | |||||
Subsidiary or Equity Method Investee, Price-Per-Share | $ 25 | |||||
Equity Distribution Agreement with MLV & Co. LLC | Class D Preferred Units | ||||||
Capital Unit [Line Items] | ||||||
Partners' Capital Account, Units, Percentage | 8.625% | |||||
Equity Distribution Agreement with MLV & Co. LLC | Class E Preferred Units | ||||||
Capital Unit [Line Items] | ||||||
Partners' Capital Account, Units, Percentage | 10.75% |
Issuances of Units (Atlas Growt
Issuances of Units (Atlas Growth Partners) (Details) - USD ($) $ / shares in Units, $ in Millions | Jun. 30, 2015 | Mar. 31, 2016 | Mar. 31, 2015 |
Capital Unit [Line Items] | |||
Partners unit, issued | 245,175 | 420,586 | |
Atlas Growth Partners, L.P | |||
Capital Unit [Line Items] | |||
Common limited partner units issued | $ 233 | ||
Percentage of warrants to purchase additional common units in amount equal to | 10.00% | ||
Warrants, exercise price | $ 10 | ||
Common limited partner units purchased | $ 5 | ||
Partners unit, issued | 2,330,041 | ||
Atlas Resource Partners, L.P. and Atlas Growth Partners, L.P | |||
Capital Unit [Line Items] | |||
Gain on sale of subsidiary unit issuances | $ 0.2 | $ 0.2 | |
Private Placement | Atlas Growth Partners, L.P | |||
Capital Unit [Line Items] | |||
Common limited partner units issued | $ 500 | ||
Number of days extension private placement offering | two 90 day | ||
Stock issued during period, shares | 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 ($) | 1 Months Ended | 3 Months Ended | |||
Mar. 31, 2015 | Feb. 28, 2015 | Jan. 31, 2015 | Mar. 31, 2016 | Mar. 31, 2015 | |
Class A Preferred Units | |||||
Distribution Made To Limited Partner [Line Items] | |||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 1,000,000 | $ 0 | |||
Atlas Energy | |||||
Distribution Made To Limited Partner [Line Items] | |||||
Distribution Policy, Members or Limited Partners, Description | We had a cash distribution policy under which we distributed, within 50 days following the end of each calendar quarter, all of our available cash (as defined in its limited liability company agreement) for that quarter to our unitholders. | ||||
Atlas Resource Partners, L.P. | |||||
Distribution Made To Limited Partner [Line Items] | |||||
Distribution Policy, Members or Limited Partners, Description | ARP has a monthly cash distribution program whereby it distributes all of its available cash (as defined in ARP’s partnership agreement) for that month to its unitholders within 45 days from the month end. | ||||
Atlas Resource Partners, L.P. | Common Limited Partners | |||||
Distribution Made To Limited Partner [Line Items] | |||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 3,800,000 | 42,800,000 | |||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $ 0.1083 | $ 0.1966 | $ 0.1966 | $ 0.0125 | |
Atlas Resource Partners, L.P. | Class C Preferred Limited Partners | |||||
Distribution Made To Limited Partner [Line Items] | |||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 1,900,000 | 2,100,000 | |||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | 0.17 | 0.1966 | 0.1966 | $ 0.17 | |
Atlas Resource Partners, L.P. | Class A General Partner | |||||
Distribution Made To Limited Partner [Line Items] | |||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 100,000 | 3,000,000 | |||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $ 0.1083 | $ 0.1966 | $ 0.1966 | $ 0.0125 | |
Atlas Resource Partners, L.P. | Class D Preferred Limited Partners | October 15, 2015 – January 14, 2016 | |||||
Distribution Made To Limited Partner [Line Items] | |||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 2,200,000 | ||||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $ 0.5390625 | ||||
Atlas Resource Partners, L.P. | Class D Preferred Limited Partners | October 2, 2014 – January 14, 2015 | |||||
Distribution Made To Limited Partner [Line Items] | |||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 2,000,000 | ||||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $ 0.6169270 | ||||
Atlas Resource Partners, L.P. | Class E Preferred Limited Partners | |||||
Distribution Made To Limited Partner [Line Items] | |||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 0 | ||||
Atlas Resource Partners, L.P. | Class E Preferred Limited Partners | October 15, 2015 – January 14, 2016 | |||||
Distribution Made To Limited Partner [Line Items] | |||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 200,000 | ||||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $ 0.671875 | ||||
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 | ||||
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 | ||||
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 | ||||
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 | $ 4,100,000 | $ 1,600,000 | |||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $ 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 | $ 100,000 | $ 33,000,000 | |||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $ 0.1750 | $ 0.1750 |
Operating Segment Information54
Operating Segment Information (Narrative) (Details) | 3 Months Ended |
Mar. 31, 2016Segment | |
Segment Reporting [Abstract] | |
Number of reportable operating segments | 3 |
Operating Segment Information55
Operating Segment Information (Operating Segment Data) (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Segment Reporting Information [Line Items] | ||
Revenues | $ 106,853 | $ 245,799 |
Depreciation, depletion and amortization expense | (34,272) | (44,456) |
Gain (loss) on asset sales and disposal | 9 | (11) |
General and administrative | (21,920) | (41,928) |
Interest expense | (29,448) | (34,751) |
Gain on early extinguishment of debt | 20,445 | 0 |
Atlas Resource Partners, L.P. | ||
Segment Reporting Information [Line Items] | ||
Gain on early extinguishment of debt | 26,500 | |
Reportable Legal Entities | Atlas Resource Partners, L.P. | ||
Segment Reporting Information [Line Items] | ||
Revenues | 103,208 | 243,589 |
Operating costs and expenses | (59,202) | (87,818) |
Depreciation, depletion and amortization expense | (30,045) | (42,991) |
Gain (loss) on asset sales and disposal | 9 | (11) |
Interest expense | (27,705) | (25,197) |
Gain on early extinguishment of debt | 26,498 | |
Segment income (loss) | 12,763 | 87,572 |
Reportable Legal Entities | Atlas Growth Partners, L.P | ||
Segment Reporting Information [Line Items] | ||
Revenues | 3,434 | 2,311 |
Operating costs and expenses | (3,503) | (5,069) |
Depreciation, depletion and amortization expense | (4,227) | (1,465) |
Segment income (loss) | (4,296) | (4,223) |
Operating Segments | Corporate and Other | ||
Segment Reporting Information [Line Items] | ||
Revenues | 211 | (101) |
General and administrative | (2,154) | (20,215) |
Interest expense | (1,743) | (9,554) |
Gain on early extinguishment of debt | (6,053) | |
Segment income (loss) | $ (9,739) | $ (29,870) |
Operating Segment Information56
Operating Segment Information (Reconciliation of Segment Income (Loss) to Net Loss) (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Segment Reporting Information [Line Items] | ||
Net income (loss) | $ (1,272) | $ 53,479 |
Reportable Legal Entities | Atlas Resource Partners, L.P. | ||
Segment Reporting Information [Line Items] | ||
Net income (loss) | 12,763 | 87,572 |
Reportable Legal Entities | Atlas Growth Partners, L.P | ||
Segment Reporting Information [Line Items] | ||
Net income (loss) | (4,296) | (4,223) |
Operating Segments | Corporate and Other | ||
Segment Reporting Information [Line Items] | ||
Net income (loss) | $ (9,739) | $ (29,870) |
Operating Segment Information57
Operating Segment Information (Reconciliation of Segment Revenues to Total Revenues) (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Segment Reporting Information [Line Items] | ||
Total revenues | $ 106,853 | $ 245,799 |
Reportable Legal Entities | Atlas Resource Partners, L.P. | ||
Segment Reporting Information [Line Items] | ||
Total revenues | 103,208 | 243,589 |
Reportable Legal Entities | Atlas Growth Partners, L.P | ||
Segment Reporting Information [Line Items] | ||
Total revenues | 3,434 | 2,311 |
Operating Segments | Corporate and Other | ||
Segment Reporting Information [Line Items] | ||
Total revenues | $ 211 | $ (101) |
Operating Segment Information58
Operating Segment Information (Capital Expenditures) (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Segment Reporting Information [Line Items] | ||
Capital expenditures | $ 18,719 | $ 52,441 |
Reportable Legal Entities | Atlas Resource Partners, L.P. | ||
Segment Reporting Information [Line Items] | ||
Capital expenditures | 13,170 | 42,498 |
Reportable Legal Entities | Atlas Growth Partners, L.P | ||
Segment Reporting Information [Line Items] | ||
Capital expenditures | $ 5,549 | $ 9,943 |
Operating Segment Information59
Operating Segment Information (Balance Sheet) (Details) - USD ($) $ in Thousands | Mar. 31, 2016 | Dec. 31, 2015 |
Segment Reporting Information [Line Items] | ||
Goodwill | $ 13,639 | $ 13,639 |
Total assets | 1,843,779 | 1,883,246 |
Reportable Legal Entities | Atlas Resource Partners, L.P. | ||
Segment Reporting Information [Line Items] | ||
Goodwill | 13,639 | 13,639 |
Total assets | 1,679,497 | 1,699,949 |
Reportable Legal Entities | Atlas Growth Partners, L.P | ||
Segment Reporting Information [Line Items] | ||
Total assets | 147,752 | 159,622 |
Operating Segments | Corporate and Other | ||
Segment Reporting Information [Line Items] | ||
Total assets | $ 16,530 | $ 23,675 |
Subsequent Events (Our Subseque
Subsequent Events (Our Subsequent Events) (Details) - $ / shares | May. 12, 2016 | Apr. 27, 2016 | Mar. 31, 2016 |
Subsequent Event | Board of Directors | Phantom Units | |||
Subsequent Event [Line Items] | |||
Granted (in units) | 911,900 | ||
Second Lien Credit Agreement | |||
Subsequent Event [Line Items] | |||
Warrants, expiration date | Mar. 30, 2026 | ||
Second Lien Credit Agreement | Subsequent Event | |||
Subsequent Event [Line Items] | |||
Investment warrants exercise price | $ 0.20 | ||
Second Lien Credit Agreement | Subsequent Event | Maximum | |||
Subsequent Event [Line Items] | |||
Warrant to purchase common units | 4,668,044 |
Subsequent Events (Atlas Resour
Subsequent Events (Atlas Resource Cash Distribution) (Details) - Subsequent Event - USD ($) $ / shares in Units, $ in Millions | May. 12, 2016 | Apr. 15, 2016 |
Board of Directors | Phantom Units | ||
Subsequent Event [Line Items] | ||
Granted (in units) | 911,900 | |
Atlas Resource Partners, L.P. | Board of Directors | Phantom Units | ||
Subsequent Event [Line Items] | ||
Granted (in units) | 110,000 | |
Atlas Resource Partners, L.P. | Class D Preferred Units | Cash Distribution Paid | ||
Subsequent Event [Line Items] | ||
Distribution Made to Member or Limited Partner, Distribution Date | Apr. 15, 2016 | |
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $ 0.5390625 | |
Distribution Made to Limited Partner, Cash Distributions Paid | $ 2.2 | |
Atlas Resource Partners, L.P. | Class E Preferred Units | Cash Distribution Paid | ||
Subsequent Event [Line Items] | ||
Distribution Made to Member or Limited Partner, Distribution Date | Apr. 15, 2016 | |
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $ 0.671875 | |
Distribution Made to Limited Partner, Cash Distributions Paid | $ 0.2 |
Subsequent Events (Atlas Growth
Subsequent Events (Atlas Growth Cash Distribution) (Details) - Atlas Growth Partners, L.P - Subsequent Event $ / shares in Units, $ in Millions | May. 04, 2016USD ($)$ / shares |
Cash Distribution Declared | |
Subsequent Event [Line Items] | |
Distribution Made to Member or Limited Partner, Declaration Date | May 4, 2016 |
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit | $ / shares | $ 0.1750 |
Cash Distribution Paid | |
Subsequent Event [Line Items] | |
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $ 4.2 |
Distribution Made to Member or Limited Partner, Distribution Date | May 13, 2016 |
Distribution Made to Member or Limited Partner, Date of Record | Mar. 31, 2016 |
Cash Distribution Paid | General Partner | |
Subsequent Event [Line Items] | |
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $ 0.1 |