Titan Energy 10-Q 28 Nov 17 2017 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Nov. 27, 2017
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q3
Entity Registrant Name	Titan Energy, LLC
Entity Central Index Key	1,532,750
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Trading Symbol	TTEN
Entity Common Stock, Units Outstanding		5,444,794

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 21,581	$ 24,446
Accounts receivable	25,200	26,472
Advances to affiliates		4,145
Subscriptions receivable		5,656
Prepaid expenses and other	12,519	17,108
Current assets held for sale (Note 3)		8,271
Total current assets	59,300	86,098
Property, plant and equipment, net	527,397	670,769
Other assets, net	3,628	10,562
Non-current advances to affiliates	15,100
Non-current assets held for sale (Note 3)		114,405
Total assets	605,425	881,834
Current liabilities:
Accounts payable	29,868	27,647
Liabilities associated with drilling contracts		10,656
Current portion of derivative liability	3,629	30,519
Accrued well drilling and completion costs	1,959	4,933
Accrued interest	789	1,503
Accrued liabilities	13,079	17,171
Advances from affiliates	1,800
Current portion of long-term debt	538,085	694,810
Current liabilities held for sale (Note 3)		9,461
Total current liabilities	589,209	796,700
Long-term derivative liability	896	13,208
Asset retirement obligations	14,570	15,031
Other long-term liabilities	811	1,431
Non-current liabilities held for sale (Note 3)		62,405
Commitments and contingencies (Note 9)
Members’ Equity (Deficit):
Common shareholders’ equity (deficit)	(33)	(6,796)
Total members’ equity (deficit)	(61)	(6,941)
Total liabilities and members’ equity (deficit)	605,425	881,834
Preferred Series A
Members’ Equity (Deficit):
Series A Preferred member’s equity (deficit)	$ (28)	$ (145)

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Thousands, $ in Thousands		1 Months Ended	2 Months Ended	3 Months Ended	8 Months Ended	9 Months Ended
		Sep. 30, 2016	Aug. 31, 2016	Sep. 30, 2017	Aug. 31, 2016	Sep. 30, 2017
Revenues:
Gas and oil production		$ 17,261		$ 47,424		$ 160,930
Drilling partnership management		2,074		1,997		17,387
Gain (loss) on mark-to-market derivatives		(2,079)		(4,068)		36,925
Total revenues		17,256		45,353		215,242
Costs and expenses:
Gas and oil production		9,854		21,633		74,355
Drilling partnership management		1,266		248		10,026
General and administrative	[1]	4,530		10,142		32,961
Depreciation, depletion and amortization		5,152		11,934		38,402
Loss on divestiture				5,177		43,369
Total costs and expenses		20,802		49,134		199,113
Operating income (loss)		(3,546)		(3,781)		16,129
Interest expense	[1]	(3,470)		(15,268)		(41,816)
Gain (loss) on asset sales and disposal	[1]	5		(82)		25
Reorganization items, net	[1]	(353)
Other income (loss)	[1]			(777)		(925)
Loss before income taxes		(7,364)		(19,908)		(26,587)
Income tax provision (benefit)	[1]			(202)		(11,503)
Net loss from continuing operations		(7,364)		(19,706)		(15,084)
Net income (loss) from discontinued operations		(167)		2,156		20,945
Net income (loss)		(7,531)		(17,550)		5,861
Net income (loss) attributable to common shareholders and preferred members		(7,531)		(17,550)		5,861
Allocation of net income (loss) attributable to:
Preferred member		(151)		(351)		117
Net income (loss) attributable to common limited partners and the general partner		$ (7,380)		$ (17,199)		$ 5,744
Net loss attributable to common shareholders per share / common limited partners per unit (Note 2):
Basic and diluted loss continuing operations		$ (1.40)		$ (3.71)		$ (2.85)
Basic and diluted income (loss) discontinued operations		$ (0.03)		$ 0.41		$ 3.96
Weighted average shares / common limited partner units outstanding (Note 2):
Basic and diluted		5,139		5,208		5,186
Predecessor
Revenues:
Gas and oil production			$ 36,290		$ 129,077
Drilling partnership management			18,778		24,446
Gain (loss) on mark-to-market derivatives			2,353		(23,248)
Total revenues			57,421		130,275
Costs and expenses:
Gas and oil production			18,577		80,988
Drilling partnership management			16,121		17,427
General and administrative	[1]		5,128		41,038
Depreciation, depletion and amortization			20,585		73,272
Total costs and expenses			60,411		212,725
Operating income (loss)			(2,990)		(82,450)
Interest expense	[1]		(14,087)		(71,059)
Gain (loss) on asset sales and disposal	[1]		(18)		(551)
Gain on early extinguishment of debt	[1]				26,498
Reorganization items, net	[1]		(16,614)		(16,614)
Other income (loss)	[1]		(3,063)		(3,063)
Loss before income taxes			(36,772)		(147,239)
Net loss from continuing operations			(36,772)		(147,239)
Net income (loss) from discontinued operations			(11,852)		(30,191)
Net income (loss)			(48,624)		(177,430)
Preferred member / limited partner dividends					(4,013)
Allocation of net income (loss) attributable to:
Net income (loss) attributable to common limited partners and the general partner			(48,624)		(181,443)
Common limited partners’ interest			(47,651)		(177,814)
General partner’s interest			$ (973)		$ (3,629)
Net loss attributable to common shareholders per share / common limited partners per unit (Note 2):
Basic and diluted loss continuing operations			$ (0.35)		$ (1.44)
Basic and diluted income (loss) discontinued operations			$ (0.11)		$ (0.28)
Weighted average shares / common limited partner units outstanding (Note 2):
Basic and diluted			104,366		102,912
[1]	General and administrative expenses, interest expense, gain on early extinguishment of debt, gain (loss) on asset sales and disposal, reorganization items, net,, other income (loss) and income tax (provision) benefit have not been allocated to reportable segments as it would be impracticable to reasonably do so for the periods presented.

CONDENSED CONSOLIDATED STATEME4

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME LOSS (Unaudited) - USD ($) $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended	8 Months Ended	9 Months Ended
	Sep. 30, 2016	Aug. 31, 2016	Sep. 30, 2017	Aug. 31, 2016	Sep. 30, 2017
Net income (loss)	$ (7,531)		$ (17,550)		$ 5,861
Other comprehensive loss:
Comprehensive income (loss) attributable to common and preferred limited partners and the general partner	$ (7,531)		$ (17,550)		$ 5,861
Predecessor
Net income (loss)		$ (48,624)		$ (177,430)
Other comprehensive loss:
Reclassification to net income (loss) of mark-to-market gains		(1,461)		(10,387)
Reclassification adjustment for net reorganization gain included in net loss		(8,617)		(8,617)
Total other comprehensive loss		(10,078)		(19,004)
Comprehensive income (loss) attributable to common and preferred limited partners and the general partner		$ (58,702)		$ (196,434)

CONDENSED CONSOLIDATED STATEME5

CONDENSED CONSOLIDATED STATEMENT OF MEMBERS' EQUITY (DEFICIT) (Unaudited) - 9 months ended Sep. 30, 2017 - USD ($) $ in Thousands	Total	Common Stockholders' Interest	Preferred Series A
Balance at Dec. 31, 2016	$ (6,941)	$ (6,796)	$ (145)
Balance (shares) at Dec. 31, 2016		5,447,787	1
Net issued and unissued shares under incentive plans	1,019	$ 1,019
Net issued and unissued shares under incentive plans (shares)		(20,240)
Net income	5,861	$ 5,744	$ 117
Balance at Sep. 30, 2017	$ (61)	$ (33)	$ (28)
Balance (shares) at Sep. 30, 2017		5,427,547	1

CONDENSED CONSOLIDATED STATEME6

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands		1 Months Ended	8 Months Ended	9 Months Ended
		Sep. 30, 2016	Aug. 31, 2016	Sep. 30, 2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		$ (7,531)		$ 5,861
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net (income) loss from discontinued operations		167		(20,945)
Depreciation, depletion and amortization		5,152		38,402
Loss on divestiture				43,369
(Gain) loss on derivatives		2,036		(16,516)
(Gain) loss on asset sales and disposal		(5)		347
Other (income) loss				1,890
Non-cash compensation expense		68		1,019
Non-cash interest expense		2,034		22,500
Valuation allowance on deferred tax asset				(11,025)
Amortization of deferred financing costs and discount and premium on long-term debt		125		1,849
Changes in operating assets and liabilities:
Accounts receivable, prepaid expenses and other		5,954		(31,142)
Accounts payable and accrued liabilities		(2,856)		(12,602)
Net cash provided by continuing operating activities		5,144		23,007
Net cash provided by discontinued operating activities		4,254		5,868
Net cash provided by operating activities		9,398		28,875
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(5,367)		(37,239)
Net proceeds from sale of assets				109,073
Net cash provided by (used in) continuing investing activities		(5,367)		71,834
Net cash provided by discontinued investing activities				76,953
Net cash provided by (used in) investing activities		(5,367)		148,787
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments under revolving credit facility				(179,536)
Deferred financing costs, distribution equivalent rights and other		(150)		(991)
Net cash used in financing activities		(150)		(180,527)
Net change in cash and cash equivalents		3,881		(2,865)
Cash and cash equivalents, beginning of period		15,428		24,446
Cash and cash equivalents, end of period		19,309	$ 15,428	$ 21,581
Predecessor
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)			(177,430)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net (income) loss from discontinued operations			30,191
Depreciation, depletion and amortization			73,272
Non-cash reorganization items			(10,312)
(Gain) loss on derivatives			13,804
(Gain) loss on asset sales and disposal			551
Gain on extinguishment of debt	[1]		(26,498)
Other (income) loss			3,063
Non-cash compensation expense			1,167
Valuation allowance on deferred tax asset			1,596
Amortization of deferred financing costs and discount and premium on long-term debt			12,361
Changes in operating assets and liabilities:
Monetization of derivatives			214,375
Accounts receivable, prepaid expenses and other			99,284
Accounts payable and accrued liabilities			(39,914)
Net cash provided by continuing operating activities			195,510
Net cash provided by discontinued operating activities			25,596
Net cash provided by operating activities			221,106
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures			(24,894)
Net cash provided by (used in) continuing investing activities			(24,894)
Net cash provided by (used in) investing activities			(24,894)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under revolving credit facility			135,000
Repayments under revolving credit facility			(291,191)
Senior note repurchases			(5,528)
Distributions paid to shareholders/unitholders			(12,578)
Net proceeds from issuance of common limited partner units			204
Deferred financing costs, distribution equivalent rights and other			(8,044)
Net cash used in financing activities			(182,137)
Net change in cash and cash equivalents			14,075
Cash and cash equivalents, beginning of period		$ 15,428	1,353
Cash and cash equivalents, end of period			$ 15,428
[1]	General and administrative expenses, interest expense, gain on early extinguishment of debt, gain (loss) on asset sales and disposal, reorganization items, net,, other income (loss) and income tax (provision) benefit have not been allocated to reportable segments as it would be impracticable to reasonably do so for the periods presented.

Organization

Organization	9 Months Ended
	Sep. 30, 2017
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Organization	NOTE 1 – ORGANIZATION We are a publicly traded (OTCQX: TTEN) Delaware limited liability company and an independent developer and producer of natural gas, crude oil and NGLs with operations in basins across the United States but primarily focused on the horizontal development of resource potential from the Eagle Ford Shale in South Texas. As discussed further below, we are the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”). Unless the context otherwise requires, references to “Titan Energy, LLC,” “Titan,” “the Company,” “we,” “us,” and “our,” refer to Titan Energy, LLC and our consolidated subsidiaries (and our predecessor, where applicable). Titan Energy Management, LLC (“Titan Management”) manages us and holds our Series A Preferred Share, which entitles Titan Management to receive 2% of the aggregate of distributions paid to shareholders (as if it held 2% of our members’ equity, subject to dilution as discussed below) and to appoint four of our seven directors. Titan Management is a wholly owned subsidiary of Atlas Energy Group, LLC (“ATLS”; OTCQX: ATLS), which is a publicly traded company. In addition to its preferred member interest in us, ATLS also holds general and limited partner interests in Atlas Growth Partners, L.P. (“AGP”), a Delaware limited partnership and an independent developer and producer of natural gas, oil and NGLs, with operations primarily focused in the Eagle Ford Shale, and in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, which incubate new MLPs and invest in existing MLPs. At September 30, 2017, we had 5,427,547 common shares representing limited liability company interests issued and outstanding. ARP Restructuring and Emergence from Chapter 11 Proceedings On July 25, 2016, ARP and certain of its subsidiaries and ATLS, solely with respect to certain sections thereof, entered into a Restructuring Support Agreement (the “Restructuring Support Agreement”) with certain of their lenders (the “Restructuring Support Parties”) to support ARP’s restructuring pursuant to a pre-packaged plan of reorganization (the “Plan”). On July 27, 2016, ARP and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court,” and the cases commenced thereby, the “Chapter 11 Filings”). The cases commenced thereby were jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.” On August 26, 2016, an order confirming the Plan was entered by the Bankruptcy Court. On September 1, 2016, (the “Plan Effective Date”), pursuant to the Plan, the following occurred: • ARP’s first lien lenders received cash payment of all obligations owed to them by ARP pursuant to the senior secured revolving credit facility (other than $440 million of principal and face amount of letters of credit) and became lenders under our first lien exit facility credit agreement, composed of a $410 million conforming reserve-based tranche and a $30 million non-conforming tranche (the “First Lien Credit Facility”) (refer to Note 5 – Debt for further information regarding terms and provisions). • ARP’s second lien lenders received a pro rata share of our second lien exit facility credit agreement with an aggregate principal amount of $252.5 million (the “Second Lien Credit Facility”) (refer to Note 5 – Debt for further information regarding terms and provisions). In addition, ARP’s second lien lenders received a pro rata share of 10% of our common shares, subject to dilution by a management incentive plan. • ARP’s senior note holders, in exchange for 100% of the $668 million aggregate principal amount of senior notes outstanding plus accrued but unpaid interest as of the commencement of the Chapter 11 Filings, received 90% of our common shares, subject to dilution by a management incentive plan. • All of ARP’s preferred limited partnership units and common limited partnership units were cancelled without the receipt of any consideration or recovery. • ARP transferred all of its assets and operations to us as a new holding company and ARP dissolved. As a result, we became the successor issuer to ARP for purposes of and pursuant to Rule 12g-3 of the Securities Exchange Act of 1934, as amended. • Titan Management, a wholly owned subsidiary of ATLS, received a Series A Preferred Share, which entitles Titan Management to receive 2% of the aggregate of distributions paid to shareholders (as if it held 2% of our members’ equity, subject to dilution if catch-up contributions are not made with respect to future equity issuances, other than pursuant to the management incentive plan) and certain other rights as provided for in the Restructuring Support Agreement. Four of the seven initial members of the board of directors were designated by Titan Management (the “Titan Class A Directors”). For so long as Titan Management holds such preferred share, the Titan Class A Directors will be appointed by a majority of the Titan Class A Directors then in office. We have a continuing right to purchase the preferred share at fair market value (as determined pursuant to the methodology provided for in our limited liability company agreement), subject to the receipt of certain approvals, including the holders of at least 67% of the outstanding common shares of us unaffiliated with Titan Management voting in favor of the exercise of the right to purchase the preferred share.

Basis of Presentation and Summa

Basis of Presentation and Summary of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2017
Accounting Policies [Abstract]
Basis of Presentation and Summary of Significant Accounting Policies	NOTE 2 – BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and the applicable rules and regulations of the Securities and Exchange Commission regarding interim financial reporting and include all adjustments that are necessary for a fair presentation of our consolidated results of operations, financial condition and cash flows for the periods shown, including normal, recurring accruals and other items. The consolidated results of operations for the interim periods presented are not necessarily indicative of results for the full year. The year-end condensed consolidated balance sheet was derived from audited financial statements but does not include all disclosures required by U.S. GAAP. For a more complete discussion of our accounting policies and certain other information, refer to our consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016. In connection with the Chapter 11 Filings, we were subject to the provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852 Reorganizations Upon emergence from bankruptcy on the Plan Effective Date, we adopted fresh-start accounting in accordance with ASC 852. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Plan Effective Date, which differed materially from the recorded values of ARP’s assets and liabilities. As a result, our condensed consolidated statement of operations subsequent to the Plan Effective Date is not comparable to ARP’s condensed consolidated statement of operations prior to the Plan Effective Date. Our condensed consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented on or after the Plan Effective Date and dates prior. Our financial results for future periods following the application of fresh-start accounting will be different from historical trends and the differences may be material. References to “Successor” relate to the Company on and subsequent to the Plan Effective Date. References to “Predecessor” refer to the Company prior to the Plan Effective Date. The condensed consolidated financial statements of the Successor have been prepared assuming that the Company will continue as a going concern and contemplate the realization of assets and the satisfaction of liabilities in the normal course of business. Reclassifications Certain reclassifications have been made to our condensed consolidated financial statements for the prior year periods to conform to classifications used in the current year, specifically related to our discontinued operations (see Note 3) and our segment information on the condensed consolidated statement of operations and segment footnote disclosures (see Note 11). Principles of Consolidation Our condensed consolidated financial statements include our accounts and the accounts of our wholly-owned subsidiaries. Transactions between us and other ATLS managed operations have been identified in the condensed consolidated financial statements as transactions between affiliates, where applicable. All material intercompany transactions have been eliminated. We sponsored and continue to manage tax-advantaged investment partnerships (the “Drilling Partnerships”), in which we coinvested, to finance a portion of our natural gas, crude oil and NGL production activities. In accordance with established practice in the oil and gas industry, our condensed 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 we have an interest. Such interests generally approximate 10-30%. Our condensed consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of the Drilling Partnerships. Rather, we calculate these items specific to our own economics. Liquidity and Capital Resources and Ability to Continue as a Going Concern Since the Plan Effective Date, we have funded our operations through cash flows generated from our operations and cash on hand. We currently do not have the capacity to access additional liquidity from our First Lien Credit Facility and our ability to access public equity and debt markets may be limited. Our 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 continue to remain low in 2017. These lower commodity prices have negatively impacted our revenues, earnings and cash flows, which has negatively impacted our ability to remain in compliance with the covenants under our credit facilities. Sustained low commodity prices could have a material and adverse effect on our liquidity position. Even following the amendments described below, we continue to face liquidity issues and are currently considering, and are likely to make, changes to our capital structure to maintain sufficient liquidity, meet our debt obligations and manage and strengthen our balance sheet. If we are not able to enter into further amendments with our lenders prior to the expiration of the standstill period, we may be forced to seek further options as described below. We were not in compliance with certain of the financial covenants under our credit facilities as of December 31, 2016, as well as the requirement to deliver audited financial statements without a going concern qualification. As a result of the amendment referenced below, our financial covenants will not be tested again until the quarter ending December 31, 2017. We do not currently have sufficient liquidity to repay all of our outstanding indebtedness, and as a result, there is substantial doubt regarding our ability to continue as a going concern. We have classified $538.1 million of outstanding indebtedness under our credit facilities, which is net of $1.7 million of deferred financing costs, as current portion of long term debt, net within our condensed consolidated balance sheet as of September 30, 2017, based on the occurrence of the event of default, the lenders under our credit facilities, as applicable, could elect to declare all amounts outstanding immediately due and payable and the lenders could terminate all commitments to extend further credit. On April 19, 2017, we entered into an amendment to our First Lien Credit Facility (which has been superseded by subsequent amendments as described further below). This amendment provided for, among other things, waivers of our non-compliance, increases in certain financial covenant ratios and scheduled decreases in our borrowing base (refer to Note 5 – Debt for further information regarding the specific amended terms and provisions). As part of our overall business strategy, we have continued to execute on our sales of non-core assets, which has included the sale of our Appalachia and Rangely operations. The proceeds of the consummated asset sales were used to repay borrowings under our First Lien Credit Facility. Our strategy is to continue to sell non-core assets to reduce our leverage position, which will also help us to comply with the requirements of our First Lien Credit Facility amendments. In addition to the amendments to the financial ratio covenants, the First Lien Credit Facility lenders waived certain defaults by us with respect to the fourth quarter of 2016, including compliance with the ratios of Total Debt to EBITDA and First Lien Debt to EBITDA, as well as our obligation to deliver financial statements without a “going concern” qualification. The First Lien Credit Facility lenders’ waivers were subject to revocation in certain circumstances, including the exercise of remedies by junior lenders (including pursuant to our Second Lien Credit Facility), the failure to extend the standstill period under the intercreditor agreement at least 15 business days prior to its expiration, and the occurrence of additional events of default under the First Lien Credit Facility. On April 21, 2017, the lenders under the our Second Lien Credit Facility delivered a notice of events of default and reservation of rights, pursuant to which they noticed events of default related to financial covenants and the failure to deliver financial statements without a “going concern” qualification. The delivery of such notice began the 180-day standstill period under the intercreditor agreement, during which the lenders under the Second Lien Credit Facility were prevented from pursuing remedies against the collateral securing our obligations under the Second Lien Credit Facility. The lenders have not accelerated the payment of amounts outstanding under the Second Lien Credit Facility. On May 4, 2017, we entered into a definitive agreement to sell our conventional Appalachia and Marcellus assets to Diversified Gas & Oil, PLC (“Diversified”) for $84.2 million. The transaction included the sale of approximately 8,400 oil and gas wells across Pennsylvania, Ohio, Tennessee, New York and West Virginia, along with the associated infrastructure (the “Appalachian Assets”). We retained our Utica Shale position, Indiana assets and West Virginia CBM assets in the region. On June 30, 2017, we completed a majority of the Appalachian Assets sale for net cash proceeds of $65.6 million, which included customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under our First Lien Credit Facility. On June 12, 2017, we entered into a definitive agreement to sell our 25% interest in Rangely Field to an affiliate of Merit Energy Company, LLC for $105 million. Rangely is a CO 2 2 On September 27, 2017, the lenders under our Second Lien Credit Facility entered into a letter agreement with us and the lenders under our First Lien Credit Facility (the “Extension Letter”) (which has been superseded by subsequent amendments as described further below). Pursuant to the Extension Letter, the Second Lien Credit Facility lenders agreed to extend the 180-day standstill period under the intercreditor agreement (during which the lenders under the Second Lien Credit Facility were prevented from pursuing remedies against the collateral securing the Company’s obligations under the Second Lien Credit Facility) by an additional 35 days from October 18, 2017 to November 22, 2017. In addition, the extension of the standstill period extends the waiver of certain defaults under the First Lien Credit Facility, which terminates 15 business days prior to the expiration of the standstill period. The parties agreed to extend the standstill period to provide the Company with additional time to negotiate proposed amendments to each of the First Lien Credit Facility and the Second Lien Credit Facility. On September 29, 2017, we completed the remainder of the Appalachia Assets sale for additional cash proceeds of $10.4 million, all of which was used to repay a portion of outstanding borrowings under our First Lien Credit Facility. On November 6, 2017, we entered into a fourth amendment to our First Lien Credit Facility. The fourth amendment has an effective date of October 31, 2017 and confirms the conforming and non-conforming tranches of the borrowing base at $228.7 million and $30 million, respectively, but requires us to take actions (which can include asset sales and equity offerings) to reduce the conforming tranche of the borrowing base to $190 million by December 8, 2017 and to $150 million by August 31, 2018. The maturity date of the non-conforming tranche of the borrowing base was confirmed as May 1, 2018. We are required to use proceeds from asset sales to make prepayments. In addition to the requirements above, the First Lien Credit Facility lenders also agreed to a limited waiver of certain existing defaults with respect to financial covenants, required repayments of borrowings and other related matters. The waiver terminates upon the earliest of (i) December 8, 2017, (ii) the occurrence of additional events of default under the First Lien Credit Facility and (iii) the exercise of remedies under our Second Lien Credit Facility. Pursuant to the fourth amendment, we are required to hedge at least 50% and 80% of our 2019 projected proved developed producing production by December 31, 2017 and March 31, 2018, respectively. In connection with, and as a condition to, the effectiveness of the fourth amendment to our First Lien Credit Facility, the lenders under our Second Lien Credit Facility agreed to extend the standstill period under the intercreditor agreement (during which the lenders under the Second Lien Credit Facility are prevented from pursuing remedies against the collateral securing our obligations under the Second Lien Credit Facility) until December 29, 2017. We continually review and may make changes to our capital structure from time to time, with the goal of strengthening our balance sheet and meeting our debt service obligations. We could pursue options such as refinancing, restructuring or reorganizing our indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address our liquidity concerns and high debt levels. We are evaluating various options, but there is no certainty that we will be able to implement any such options, and we cannot provide any assurances that any refinancing or changes in our debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for our stakeholders. We cannot assure you that we will be able to implement the above actions, if necessary, on commercially reasonable terms, or at all, in a manner that will be permitted under the terms of our debt instruments or in a manner that does not negatively impact the price of our securities. Additionally, there can be no assurance that the above actions will allow us to meet our debt obligations and capital requirements. Use of Estimates The preparation of our condensed 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 consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. Our condensed consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion of gas and oil properties, fair value of derivative instruments, and the fair value of assets held for sale. The oil and 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. Assets Held For Sale Assets are classified as held for sale when we commit to a plan to sell the assets and there is reasonable certainty the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less estimated costs to sell. Any subsequent changes to the fair value less estimated costs to sell impact the measurement of assets held for sale, with any gain or loss reflected in the loss on divestitures line item in our condensed consolidated statements of operations. See Note 3 for additional disclosures regarding assets held for sale. Discontinued Operations A disposal of a component of our entity is classified as discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on our operations and financial results. For components classified as discontinued operations, the balance sheet amounts and results of operations are reclassified from their historical presentation to assets and liabilities held for sale on the condensed consolidated balance sheet and to net income (loss) from discontinued operations on the condensed consolidated statement of operations for all periods presented. The gains or losses associated with these divested components are recorded in net income (loss) from discontinued operations on the condensed consolidated statement of operations. See Note 3 for additional disclosures regarding discontinued operations. Predecessor’s Reorganization Items, Net Incremental costs incurred as a result of the Chapter 11 Filings, net gain on settlement of liabilities subject to compromise and reorganization adjustments, and net impact of fresh start adjustments are classified as “Reorganization items, net” in the Predecessor’s condensed consolidated statement of operations. The following table summarizes the reorganization items: Professional fees and other $ (33,065) Accelerated amortization of deferred financing costs (9,565) Net gain on reorganization adjustments 361,479 Net loss on fresh start adjustments (335,463) Total reorganization items, net $ (16,614) Income Taxes Our effective tax rates for the Successor three and nine months ended September 30, 2017 were 1.27% and 0.74%, respectively, which represent our expected Texas Franchise Tax liability. Our income tax provision differs from the provision computed by applying the U.S. Federal statutory corporate income tax rate of 35% primarily due to the valuation allowance on our deferred tax assets. For the Successor three and nine months ended September 30, 2017, we recognized a provision for income taxes of $0.2 million and $11.5 million, respectively, in net income (loss) from discontinued operations on our condensed consolidated statement of operations. For the Successor three and nine months ended September 30, 2017, we recognized a corresponding income tax benefit of $0.2 million and $11.5 million, respectively, in net income (loss) from continuing operations on our condensed consolidated statement of operations, which represents a direct offset of the provision for income taxes included within our discontinued operations. Successor’s Management Incentive Plan Pursuant to the Titan Energy, LLC Management Incentive Plan (the “MIP”) plan, participants are allowed to withhold or surrender shares for the payment of taxes. These shares are available for re-issuance under the MIP. For the three months ended September 30, 2017, 91,710 shares under the MIP became unrestricted. Of these shares, 42,251 were withheld for taxes, which resulted in $0.2 million recognized in our consolidated statement of changes in members’ equity. For the nine months ended September 30, 2017, 91,710 shares under the MIP became unrestricted and 37,324 shares were granted and vested immediately. Of these shares, 57,562 were withheld for taxes, which resulted in $0.3 million recognized in our consolidated statement of changes in members’ equity. For the Successor period September 1, 2016 through September 30, 2016, 138,750 shares were granted and vested immediately. Predecessor’s 2012 Long-Term Incentive Plan On May 12, 2016, due to the income tax ramifications of the potential options our Predecessor was considering, our Predecessor’s 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 August 31, 2016. The delayed vesting schedule did not have a significant impact on the compensation expense recorded in general and administrative expenses on the condensed consolidated statement of operations for the Predecessor period from January 1, 2016 through August 31, 2016 or our Predecessor’s remaining unrecognized compensation expense related to such awards. As a result of the Chapter 11 Filings, our Predecessor’s 2012 LTIP phantom units were cancelled. The remaining unrecognized compensation cost of $0.8 million was recognized upon the cancellation and was recorded in general and administrative expenses on the condensed consolidated statement of operations for the Predecessor period from July 1, 2016 through August 31, 2016. Successor’s Net Income Attributable to Common Shareholders Per Share The Successor’s basic net income attributable to common shareholders per share is computed by dividing net income attributable to our common shareholders by the weighted-average number of common shares outstanding, excluding any unvested restricted shares, for the period. The Successor’s diluted net income attributable to common shareholders per share is similarly calculated except that the common shares outstanding for the period are increased using the treasury stock method to reflect the potential dilution that could occur if outstanding share based awards were vested at the end of the applicable period. Anti-dilutive shares represent potentially dilutive securities that are excluded from the computation of diluted net income attributable to common shareholders per share as their impact would be anti-dilutive. We determine if potentially dilutive shares are anti-dilutive based on their impact to net income (loss) from continuing operations. The following is a reconciliation of net income attributable to our Successor’s common shareholders for purposes of calculating net income attributable to our Successor’s common shareholders per share (in thousands): Successor Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017 Period from September 1, 2016 through September 30, 2016 Net loss from continuing operations $ (19,706 ) $ (15,084 ) $ (7,364 ) Less: Series A Preferred member interest in loss from continuing operations (394 ) (302 ) (147 ) Net loss from continuing operations utilized in the calculation of net loss attributable to common shareholders per share $ (19,312 ) $ (14,782 ) $ (7,217 ) Net income (loss) from discontinued operations $ 2,156 $ 20,945 $ (167 ) Less: Series A Preferred member interest in net income (loss) from discontinued operations 43 419 (4 ) Net income (loss) from discontinued operations utilized in the calculation of net income (loss) attributable to common shareholders per share $ 2,113 $ 20,526 $ (163 ) The following table is a reconciliation of the Successor’s basic and diluted weighted average number of common shares used to calculate basic and diluted net income attributable to common shareholders per share (in thousands): Successor Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017 Period from September 1, 2016 through September 30, 2016 Weighted average number of common shares - basic (1) 5,208 5,186 5,139 Add dilutive effect of share based awards at end of period (2) — — — Weighted average number of common shares - diluted 5,208 5,186 5,139 (1) For the three and nine months ended September 30, 2017, 186,000 and 278,000 restricted common shares outstanding, respectively, were excluded from the calculation of basic weighted average number of common shares because they were not vested. For the Successor period from September 1, 2016 through September 30, 2016, 278,000 restricted common shares outstanding were excluded from the calculation of basic weighted average number of common shares because they were not vested. (2) We determine if potentially dilutive shares are anti-dilutive based on their impact to net income (loss) from continuing operations. Since all of the periods presented resulted in net loss from continuing operations attributable to common shareholders, potentially dilutive shares were excluded because their inclusion would have been anti-dilutive. Predecessor’s Net Income (Loss) Per Common Unit The following is a reconciliation of net income (loss) allocated to our Predecessor’s common limited partners for purposes of calculating net income (loss) attributable to our Predecessor’s common limited partners per unit (in thousands): Predecessor Period From July 1 through August 31, 2016 Period From January 1 through August 31, 2016 Net loss from continuing operations $ (36,772 ) $ (147,239 ) Preferred limited partner dividends — (4,013 ) Net loss from continuing operations attributable to common limited partners and the general partner (36,772 ) (151,252 ) Less: General partner’s interest in net loss from continuing operations (736 ) (3,025 ) Net loss from continuing operations attributable to common limited partners (36,036 ) (148,227 ) Less: Net income from continuing operations attributable to participating securities – phantom units — — Net loss from continuing operations utilized in the calculation of net loss attributable to common limited partners per unit – Basic (36,036 ) (148,227 ) Plus: Convertible preferred limited partner dividends (1) — — Net loss from continuing operations utilized in the calculation of net loss attributable to common limited partners per unit – Diluted $ (36,036 ) $ (148,227 ) Net loss from discontinued operations attributable to common limited partners and the general partner $ (11,852 ) $ (30,191 ) Less: General partner’s interest in net loss from discontinued operations (237 ) (604 ) Net loss from discontinued operations attributable to common limited partners (11,615 ) (29,587 ) Less: Net income from discontinued operations attributable to participating securities – phantom units — — Net loss from discontinued operations utilized in the calculation of net loss attributable to common limited partners per unit – Basic (11,615 ) (29,587 ) Plus: Convertible preferred limited partner dividends (1) — — Net loss from discontinued operations utilized in the calculation of net loss attributable to common limited partners per unit – Diluted $ (11,615 ) $ (29,587 ) (1) For the periods presented, distributions on our Predecessor’s Class C convertible preferred units were The following table sets forth the reconciliation of our Predecessor’s weighted average number of common limited partner units used to compute basic net income (loss) attributable to our Predecessor’s common limited partners per unit with those used to compute diluted net income attributable to our Predecessor’s common limited partners per unit (in thousands): Predecessor Period From July 1 through August 31, 2016 Period From January 1 through August 31, 2016 Weighted average number of common limited partner units—basic 104,366 102,912 Add effect of dilutive incentive awards (1) — — Add effect of dilutive convertible preferred limited partner units (2) — — Weighted average number of common limited partner units—diluted 104,366 102,912 (1) For the Predecessor periods from July 1, 2016 through August 31, 2016 and from January 1, 2016 through August 31, 2016, 247,000 and 274,000 phantom units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. (2) For the periods presented, potential common limited partner units issuable upon (a) conversion of our Predecessor’s Class C preferred units and (b) exercise of the common unit warrants issued with our Predecessor’s Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. As our Predecessor’s Class D and Class E preferred units were convertible only upon a change of control event, they were not considered dilutive securities for earnings per unit purposes. Recently Issued Accounting Standards In February 2016, the 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 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. We have made progress on our contract reviews and documentation.

Discontinued Operations and Div

Discontinued Operations and Divestitures	9 Months Ended
	Sep. 30, 2017
Discontinued Operations And Disposal Groups [Abstract]
Discontinued Operations and Divestitures	NOTE 3 – DISCONTINUED OPERATIONS AND DIVESTITURES Appalachia Divestiture – Discontinued Operations As disclosed in Note 2, on June 30, 2017, we completed a majority of the Appalachian Assets sale for net cash proceeds of $65.6 million, which included customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under our First Lien Credit Facility. On September 29, 2017, we completed the remainder of the Appalachian Assets sale for additional cash proceeds of $10.4 million, all of which was used to repay a portion of outstanding borrowings under our First Lien Credit Facility. We determined the Appalachian Assets represent discontinued operations as they constitute a disposal of a group of components and a strategic shift that will have a major effect on our operations and financial results. We evaluated the Appalachian Assets sale on our gas and oil production and Drilling Partnership management segments’ results of operations and cash flows, as well as expected asset retirement obligations, and concluded the impact will have a major effect on our expected operations and financial results. As a result, we reclassified the Appalachian Assets from their historical presentation to assets and liabilities held for sale on the condensed consolidated balance sheet and to net income (loss) from discontinued operations on the condensed consolidated statement of operations for all periods presented. We determined that the carrying value of the remainder of our Appalachian Assets exceeded the fair value less costs to sell, which resulted in an impairment of $4.3 million recognized in net income (loss) from discontinued operations on our condensed consolidated statement of operations during the nine months ended September 30, 2017. The following table reconciles the major classes of line items from the discontinued operations of the Appalachian Assets included within net income (loss) from discontinued operations, in thousands: Successor Predecessor Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017 Period From September 1 to September 30, 2016 Period From July 1 to August 31, 2016 Period From January 1 to August 31, 2016 Revenues: Gas and oil production $ 288 $ 21,213 $ 1,197 $ 2,917 $ 10,037 Drilling partnership management — 5,114 1,320 3,621 12,100 Gain (loss) on mark-to-market derivatives — 4,955 750 875 (667 ) Total revenues 288 31,282 3,267 7,413 21,470 Costs and expenses: Gas and oil production $ 924 $ 9,091 $ 760 $ 1,454 $ 6,244 Drilling partnership management 597 5,824 1,074 2,312 9,801 Depreciation, depletion and amortization — 4,842 869 2,693 9,059 General and administrative 298 4,378 395 12,044 16,974 Gain on sale of assets (4,319 ) (32,921 ) (4 ) (50 ) (72 ) Impairment on assets held for sale — 4,272 — — — Interest expense 115 2,769 340 842 3,529 Other (income) loss 541 541 — (30 ) 6,126 Total costs and expenses $ (1,844 ) $ (1,204 ) $ 3,434 $ 19,265 $ 51,661 Income (loss) from discontinued operations before income taxes 2,132 32,486 (167 ) (11,852 ) (30,191 ) Income tax provision (benefit) (24 ) 11,541 — — — Net income (loss) from discontinued operations $ 2,156 $ 20,945 $ (167 ) $ (11,852 ) $ (30,191 ) We allocated First Lien Credit Facility interest expense to our discontinued operations based on the relative proportion of the net cash proceeds from the sale of the Appalachian Assets used to repay outstanding indebtedness under our First Lien Credit Facility to the total outstanding indebtedness under our First Lien Credit Facility for the periods presented. We allocated gain (loss) on mark-to-market natural gas commodity derivatives to our discontinued operations based on the relative proportion of the Appalachian Assets’ natural gas production volumes to our total natural gas production volumes for the periods presented. The following table details the major classes of assets and liabilities of the Appalachian Assets discontinued operations classified as held for sale for the prior period presented, in thousands: December 31, 2016 Current assets: Accounts receivable $ 7,254 Prepaid expenses and other 1,017 Total current assets 8,271 Property, plant and equipment, net 113,956 Other assets 449 Total non-current assets 114,405 Total assets classified as held for sale $ 122,676 Current liabilities: Accounts payable $ 2,516 Current portion of derivative liability 4,279 Accrued liabilities and other 2,666 Total current liabilities 9,461 Long-term derivative liability 1,407 Asset retirement obligations 60,316 Other long-term liabilities 682 Total non-current liabilities 62,405 Total liabilities classified as held for sale $ 71,866 We allocated natural gas commodity derivatives assets and liabilities to our discontinued operations held for sale based on the relative proportion of the Appalachian Assets’ natural gas production volumes to our total natural gas production volumes as of December 31, 2016. Rangely Divestiture As disclosed in Note 2, on August 7, 2017, we completed the Rangely Assets sale for net cash proceeds of $103.5 million, which included customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under our First Lien Credit Facility. We determined that the carrying value of the Rangely Assets exceeded the fair value less costs to sell, which resulted in an impairment of $38.2 million recognized in loss on divesture on our condensed consolidated statement of operations during the Successor nine months ended September 30, 2017. We recognized a $5.2 million loss on asset sale from the closing of the Rangely Assets sale during the Successor three and nine months ended September 30, 2017 resulting from final negotiations and settlement of working capital adjustments in connection with the preliminary purchase price adjustments. We considered the Rangely Assets to be an individually significant component of our operations. The following table presents the net income (loss) before income taxes of the Rangely Assets for the periods presented, in thousands: Successor Predecessor Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017 Period From September 1 to September 30, 2016 Period From July 1 to August 31, 2016 Period From January 1 to August 31, 2016 Income (loss) before income taxes (1) $ (4,292 ) $ (38,379 ) $ 532 $ 1,253 $ 2,011 (1) Income (loss) before income taxes reflects gas and oil production revenues less gas and oil production expenses, general and administrative expenses, depletion, depreciation, and amortization expenses for all periods presented. The Successor three and nine months ended September 30, 2017 include $5.2 million of loss on asset sale resulting from the closing of the Rangely Asset sale. The Successor nine months ended September 30, 2017 also includes $38.2 million loss on divestiture resulting from the carrying value of the Rangely Assets exceeding the fair value less costs to sell as disclosed above.

Property, Plant and Equipment

Property, Plant and Equipment	9 Months Ended
	Sep. 30, 2017
Property Plant And Equipment [Abstract]
Property, Plant and Equipment	NOTE 4 – PROPERTY, PLANT AND EQUIPMENT The following is a summary of property, plant and equipment at the dates indicated (in thousands): September 30, 2017 December 31, 2016 Natural gas and oil properties: Proved properties $ 519,147 $ 608,901 Unproved properties 52,767 73,057 Support equipment and other 8,690 8,081 Total natural gas and oil properties 580,604 690,039 Less – accumulated depreciation, depletion and amortization (53,207 ) (19,270 ) Total property, plant and equipment, net $ 527,397 $ 670,769 During the Successor nine months ended September 30, 2017, the Successor period from September 1, 2016 through September 30, 2016 and the Predecessor period from January 1, 2016 through August 31, 2016, we recognized $0.7 million, $3.5 million and $19.6 million, respectively, of non-cash investing activities capital expenditures, which was reflected within the changes in accounts payable and accrued liabilities on our condensed consolidated statements of cash flows. We capitalize 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 rate used to capitalize interest on borrowed funds during the Successor three and nine months ended September 30, 2017, the Successor period September 1, 2016 through September 30, 2016, and the Predecessor periods from July 1, 2016 through August 31, 2016 and January 1, 2016 through August 31, 2016 were 9.5%, 8.4%, 7.6%, 6.0% and 6.5%, respectively. The aggregate amount of interest capitalized during the Successor three and nine months ended September 30, 2017, the Successor period September 1, 2016 through September 30, 2016, and the Predecessor periods from July 1, 2016 through August 31, 2016 and January 1, 2016 through August 31, 2016 were $0.2 million, $0.4 million, $0.7 million, $1.7 million and $6.5 million, respectively. For the Successor three and nine months ended September 30, 2017, the Successor period September 1, 2016 through September 30, 2016, and the Predecessor periods from July 1, 2016 through August 31, 2016 and January 1, 2016 through August 31, 2016, we recorded $0.4 million, $1.1 million, $0.5 million, $1.3 million and $4.6 million, respectively, of accretion expense related to our asset retirement obligations within depreciation, depletion and amortization in our condensed consolidated statements of operations.

Debt

Debt	9 Months Ended
	Sep. 30, 2017
Debt Disclosure [Abstract]
Debt	NOTE 5 – DEBT Total debt consists of the following at the dates indicated (in thousands): September 30, December 31, 2017 2016 First Lien Credit Facility $ 256,273 $ 435,809 Second Lien Credit Facility 283,523 261,022 Deferred financing costs, net of accumulated amortization of $686 and $172, respectively (1,711 ) (2,021 ) Total debt, net 538,085 694,810 Less current maturities (538,085 ) (694,810 ) Total long-term debt, net $ — $ — Cash Interest . Total cash payments for interest for the Successor three and nine months ended September 30, 2017, the Successor period September 1, 2016 through September 30, 2016 and the Predecessor period from January 1, 2016 through August 31, 2016, were $7.3 million, $21.2 million, $0.5 million and $53.7 million, respectively. There were no cash payments for interest for the Predecessor period from July 1, 2016 through August 31, 2016 due to our Predecessor’s Chapter 11 Filings. First Lien Credit Facility On September 1, 2016, we entered into our $440 million First Lien Credit Facility with Wells Fargo Bank, National Association (“Wells Fargo”), as administrative agent, and the lenders party thereto. A summary of the key provisions of the First Lien Credit Facility is as follows (of which certain provisions have been modified through subsequent amendments as described further below): • Borrowing base of a $410 million conforming reserve based tranche plus a $30 million non-conforming tranche. • Provides for the issuance of letters of credit, which reduce borrowing capacity. • Obligations are secured by mortgages on substantially all of our oil and gas properties and first priority security interests in substantially all of our assets and are guaranteed by certain of our material subsidiaries, and any non-guarantor subsidiaries of ours are minor. • Borrowings bear interest at our election at either LIBOR plus an applicable margin between 3.00% and 4.00% per annum or the “alternate base rate” plus an applicable margin between 2.00% and 3.00% per annum, which fluctuates based on utilization. We are also required to pay a fee of 0.50% per annum on the unused portion of the borrowing base. At September 30, 2017, the weighted average interest rate on outstanding borrowings under the First Lien Credit Facility was 5.2%. • Contains covenants that limit our ability to incur additional 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 our assets. • Requires us to enter into commodity hedges covering at least 80% of our expected 2019 production prior to December 31, 2017. We were not in compliance with certain of the financial covenants under our credit facilities as of December 31, 2016, as well as the requirement to deliver audited financial statements without a going concern qualification. On April 19, 2017, we, Titan Energy Operating, LLC (our wholly owned subsidiary), as borrower, and certain subsidiary guarantors entered into a third amendment to the First Lien Credit Facility with Wells Fargo, as administrative agent, and the lenders party thereto. Pursuant to the third amendment, certain of the financial ratio covenants were revised upwards. Specifically, beginning December 31, 2017, we will be required to maintain a ratio of Total Debt to EBITDA (each as defined in the First Lien Credit Facility) of not more than 5.50 to 1.00 for each fiscal quarter through December 31, 2018 and of not more than 5.00 to 1.00 thereafter. We will also be required, beginning December 31, 2017, to maintain a ratio of First Lien Debt (as defined in the First Lien Credit Facility) to EBITDA of not more than 4.00 to 1.00 for each fiscal quarter through December 31, 2018 and of not more than 3.50 to 1.00 thereafter. In addition to the amendments to the financial ratio covenants, the First Lien Credit Facility lenders waived certain defaults by us with respect to the fourth quarter of 2016, including compliance with the ratios of Total Debt to EBITDA and First Lien Debt to EBITDA, as well as our obligation to deliver financial statements without a “going concern” qualification. The First Lien Credit Facility lenders’ waivers were subject to revocation in certain circumstances, including the exercise of remedies by junior lenders (including pursuant to our second lien credit facility), the failure to extend the 180-day standstill period under the intercreditor agreement at least 15 business days prior to its expiration, and the occurrence of additional events of default under the First Lien Credit Facility. The third amendment to the First Lien Credit Facility confirmed the conforming and non-conforming tranches of the borrowing base at $410 million and $30 million, respectively, but required us to take actions (which included asset sales) to reduce the conforming tranche of the borrowing base to $330 million by August 31, 2017 and to $190 million by October 1, 2017 (subject to extension at the administrative agent’s option to October 31, 2017). Similarly, the non-conforming tranche of the borrowing base was required to be reduced to $10 million by November 1, 2017. In addition, we were required to use excess asset sale proceeds (after application in accordance with the existing terms of the First Lien Credit Facility) to repay outstanding borrowings and reduce the applicable borrowing base to the required level. On June 30, 2017, we completed a majority of the Appalachian Assets sale for net cash proceeds of $65.6 million, which included customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under our First Lien Credit Facility. On August 7, 2017, we completed the Rangely Assets sale for net cash proceeds of $103.5 million, which included customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under our First Lien Credit Facility and achieve compliance with the requirement to reduce our First Lien Credit Facility borrowings below $360 million, as required by August 31, 2017. On September 29, 2017, we completed the remainder of the Appalachia Assets sale for additional cash proceeds of $10.4 million, all of which was used to repay a portion of outstanding borrowings under our First Lien Credit Facility. On November 6, 2017, we entered into a fourth amendment to our First Lien Credit Facility. The fourth amendment has an effective date of October 31, 2017 and confirms the conforming and non-conforming tranches of the borrowing base at $228.7 million and $30 million, respectively, but requires us to take actions (which can include asset sales and equity offerings) to reduce the conforming tranche of the borrowing base to $190 million by December 8, 2017 and to $150 million by August 31, 2018. The maturity date of the non-conforming tranche of the borrowing base was confirmed as May 1, 2018. We are required to use proceeds from asset sales to make prepayments. In addition to the requirements above, the First Lien Credit Facility lenders also agreed to a limited waiver of certain existing defaults with respect to financial covenants, required repayments of borrowings and other related matters. The waiver terminates upon the earliest of (i) December 8, 2017, (ii) the occurrence of additional events of default under the First Lien Credit Facility and (iii) the exercise of remedies under our Second Lien Credit Facility. Pursuant to the fourth amendment, we are required to hedge at least 50% and 80% of our 2019 projected proved developed producing production by December 31, 2017 and March 31, 2018, respectively. Second Lien Credit Facility On September 1, 2016, we entered into our Second Lien Credit Facility with Wilmington Trust, National Association, as administrative agent, and the lenders party thereto for an aggregate principal amount of $252.5 million maturing on February 23, 2020. A summary of the key provisions of the Second Lien Credit Facility is as follows (of which certain provisions have been modified through subsequent amendments as described further below): • Until May 1, 2017, interest will be payable at a rate of 2% in cash plus paid-in-kind interest at a rate equal to the Adjusted LIBO Rate (as defined in the Second Lien Credit Facility) plus 9% per annum. During the subsequent 15-month period, cash and paid-in-kind interest will vary based on a pricing grid tied to our leverage ratio under the First Lien Credit Facility. After such 15-month period, interest will accrue at a rate equal to the Adjusted LIBO Rate plus 9% per annum and will be payable in cash. • All prepayments are subject to the following premiums, plus accrued and unpaid interest: o 4.5% of the principal amount prepaid for prepayments prior to February 23, 2017; o 2.25% of the principal amount prepaid for prepayments on or after February 23, 2017 and prior to February 23, 2018; and o no premium for prepayments on or after February 23, 2018. • Obligations are secured on a second priority basis by security interests in the same collateral securing the First Lien Credit Facility and are guaranteed by certain of our material subsidiaries, and any non-guarantor subsidiaries of ours are minor. • Contains covenants that limit our 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, engage in other business activities, and other covenants substantially similar to those in the First Lien Credit Facility, including, among others, restrictions on swap agreements, debt of unrestricted subsidiaries, drilling and operating agreements and the sale or discount of receivables. • Requires us to maintain certain financial ratios (the financial ratios used an annualized EBITDA measurement for periods prior to June 30, 2017): o EBITDA to Interest Expense (each as defined in the Second Lien Credit Facility) of not less than 2.50 to 1.00; o Total Leverage Ratio (as defined in the Second Lien Credit Facility) of no greater than 5.5 to 1.0 prior to December 31, 2017 and no greater than 5.0 to 1.0 thereafter; and o Current assets to current liabilities (each as defined in the Second Lien Credit Facility) of not less than 1.0 to 1.0. On April 21, 2017, the lenders under the our Second Lien Credit Facility delivered a Notice, pursuant to which they noticed events of default related to financial covenants and the failure to deliver financial statements without a “going concern” qualification. The delivery of the Notice began the 180-day standstill period under the intercreditor agreement, during which the lenders under the Second Lien Credit Facility were prevented from pursuing remedies against the collateral securing our obligations under the Second Lien Credit Facility. The lenders have not accelerated the payment of amounts outstanding under the Second Lien Credit Facility. On September 27, 2017, the lenders under our Second Lien Credit Facility entered into the Extension Letter with us and the lenders under our First Lien Credit Facility. Pursuant to the Extension Letter, the Second Lien Credit Facility lenders agreed to extend the 180-day standstill period under the intercreditor agreement (during which the lenders under the Second Lien Credit Facility were prevented from pursuing remedies against the collateral securing the Company’s obligations under the Second Lien Credit Facility) by an additional 35 days from October 18, 2017 to November 22, 2017. In addition, the extension of the standstill period extends the waiver of certain defaults under the First Lien Credit Facility, which terminates 15 business days prior to the expiration of the standstill period. The parties agreed to extend the standstill period to provide the Company with additional time to negotiate proposed amendments to each of the First Lien Credit Facility and the Second Lien Credit Facility. In connection with, and as a condition to, the effectiveness of the fourth amendment to our First Lien Credit Facility, on November 6, 2017, the lenders under our Second Lien Credit Facility agreed to extend the standstill period under the intercreditor agreement (during which the lenders under the Second Lien Credit Facility are prevented from pursuing remedies against the collateral securing our obligations under the Second Lien Credit Facility) until December 29, 2017.

Derivative Instruments

Derivative Instruments	9 Months Ended
	Sep. 30, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Instruments	NOTE 6 – DERIVATIVE INSTRUMENTS We use a number of different derivative instruments, principally swaps and options, in connection with our commodity price risk management activities. We do not apply hedge accounting to any of our derivative instruments. As a result, gains and losses associated with derivative instruments are recognized in earnings. We enter into commodity future option contracts to achieve more predictable cash flows by hedging our exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Stock 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. NGL fixed price swaps are priced based on a WTI crude oil index, while ethane, propane, butane and iso butane contracts are priced based on the respective Mt. Belvieu price. These contracts were recorded at their fair values. Pursuant to the Restructuring Support Agreement, our Predecessor completed the sale of substantially all of its commodity hedge positions on July 25, 2016 and July 26, 2016 and used the proceeds to repay $233.5 million of borrowings outstanding under the Predecessor’s first lien credit facility. The following table summarizes the commodity derivative activity and presentation in our condensed consolidated statements of operations for the periods indicated (in thousands): Successor Predecessor Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017 Period from September 1, 2016 through September 30, 2016 Period from July 1, 2016 through August 31, 2016 Period from January 1, 2016 through August 31, 2016 Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets (1)(2) $ — $ — $ — $ 1,461 $ 10,387 Portion of settlements attributable to subsequent mark to market gains (losses) (2) 1,666 (2,309 ) 191 3,440 80,604 Total cash settlements on commodity derivative contracts (2) $ 1,666 $ (2,309 ) $ 191 $ 4,901 $ 90,991 Gains (losses) recognized on cash settlement (3) $ 195 $ 20,409 $ (43 ) $ 9,381 $ (9,444 ) Gains (losses) recognized on open derivative contracts (3) (4,263 ) 16,516 (2,036 ) (7,028 ) (13,804 ) Gains (losses) on mark-to-market derivatives $ (4,068 ) $ 36,925 $ (2,079 ) $ 2,353 $ (23,248 ) (1) Recognized in gas and oil production revenue. (2) The Predecessor periods presented exclude the effects of the $214.9 million and the $20.4 million allocated to discontinued operations (see Note 3), net of $8.2 million in hedge monetization fees, paid directly to the First Lien Credit Facility lenders upon the sale of substantially all of our Predecessor’s commodity hedge positions on July 25, 2016 and July 26, 2016. The $8.2 million in hedge monetization fees was not allocated to discontinued operations as this was recorded in reorganization items, net on the condensed consolidated statements of operations. (3) Recognized in gain (loss) on mark-to-market derivatives. The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities included on our condensed consolidated balance sheets for the periods indicated (in thousands): Offsetting Derivatives as of September 30, 2017 Gross Amounts Recognized Gross Amounts Offset Net Amount Presented Current portion of derivative assets $ 2,038 $ (2,006 ) $ 32 Long-term portion of derivative assets 168 (168 ) — Total derivative assets $ 2,206 $ (2,174 ) $ 32 Current portion of derivative liabilities $ (5,635 ) $ 2,006 $ (3,629 ) Long-term portion of derivative liabilities (1,064 ) 168 (896 ) Total derivative liabilities $ (6,699 ) $ 2,174 $ (4,525 ) Offsetting Derivatives as of December 31, 2016 Current portion of derivative assets $ 7 $ (7 ) $ — Long-term portion of derivative assets 677 (677 ) — Total derivative assets $ 684 $ (684 ) $ — Current portion of derivative liabilities $ (30,526 ) $ 7 $ (30,519 ) Long-term portion of derivative liabilities (13,885 ) 677 (13,208 ) Total derivative liabilities $ (44,411 ) $ 684 $ (43,727 ) At September 30, 2017, we had the following commodity derivatives instruments: Type Production Period Ending December 31, Volumes (1) Average Fixed Price (2) Fair Value Asset / (Liability) Total Type (in thousands) (2) (in thousands) Natural Gas – Fixed Price Swaps 2017 (3) 12,919,900 $ 3.140 $ 693 2018 43,947,300 $ 2.959 $ (3,458 ) $ (2,765 ) Crude Oil – Fixed Price Swaps 2017 (3) 196,500 $ 47.441 $ (766 ) 2018 588,500 $ 50.286 $ (936 ) 2019 73,000 50.630 (26 ) $ (1,728 ) Total net liability $ (4,493 ) (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 are based on forward NYMEX natural gas prices, as applicable. Fair value of crude oil fixed price swaps are based on forward West Texas Intermediate (“WTI”) index crude oil prices, as applicable. (3) The production volumes for 2017 include the remaining three months of 2017 beginning October 1, 2017 .

Fair Value of Financial Instrum

Fair Value of Financial Instruments	9 Months Ended
	Sep. 30, 2017
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	NOTE 7 – FAIR VALUE OF FINANCIAL INSTRUMENTS Assets and Liabilities Measured on a Recurring Basis We use a market approach fair value methodology to value our outstanding derivative contracts. The fair value of a financial instrument depends on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. We separate the fair value of our financial instruments into the three level hierarchy (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. As of September 30, 2017 and December 31, 2016, all of our derivative financial instruments were classified as Level 2. Information for financial instruments measured at fair value were as follows (in thousands): Derivatives, Fair Value, as of September 30, 2017 Level 1 Level 2 Level 3 Total Assets, gross Commodity swaps $ — $ 2,206 $ — $ 2,206 Total derivative assets, gross — 2,206 — 2,206 Liabilities, gross Commodity swaps — (6,699 ) — (6,699 ) Total derivative liabilities, gross — (6,699 ) — (6,699 ) Total derivatives, fair value, net $ — $ (4,493 ) $ — $ (4,493 ) Derivatives, Fair Value, as of December 31, 2016 Level 1 Level 2 Level 3 Total Assets, gross Commodity swaps $ — $ 684 $ — $ 684 Total derivative assets, gross — 684 — 684 Liabilities, gross Commodity swaps — (44,411 ) — (44,411 ) Total derivative liabilities, gross — (44,411 ) — (44,411 ) Total derivatives, fair value, net $ — $ (43,727 ) $ — $ (43,727 ) Other Financial Instruments Our other current assets and liabilities on our condensed consolidated balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1. The estimated fair value of our long-term debt at September 30, 2017, which consists of our First Lien Credit Facility and Second Lien Credit Facility, approximated carrying value of $539.8 million. At September 30, 2017, the carrying value of outstanding borrowings under our First Lien Credit Facility, which bears interest at variable interest rates, approximated estimated fair value. The estimated fair value of our Second Lien Credit Facility was based upon the market approach and calculated using yields of our Second Lien Credit Facility as provided by financial institutions and thus were categorized as Level 3 values. Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis We estimated the fair value less estimated costs to sell of our remaining Appalachia Assets and Rangely Assets held for sale (see Note 3) based on the respective negotiated purchase prices that were derived from discounted cash flow models, which considered the estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, the respective natural gas, oil and natural gas liquids forward price curves, external estimates of recovery values, and other market multiples. These estimates of fair value are Level 3 measurements as they are based on unobservable inputs. Our Predecessor’s management estimated the fair values of natural gas and oil properties transferred to our Predecessor upon consolidation of certain Drilling Partnerships (see Note 8) based on a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, our Predecessor’s future operating and development costs of the assets, the respective natural gas, oil and natural gas liquids forward price curves and estimated salvage values using our historical experience and external estimates of recovery values. These estimates of fair value were Level 3 measurements as they were based on unobservable inputs. Our Predecessor’s management estimated the fair value of asset retirement obligations transferred to our Predecessor upon consolidation of certain Drilling Partnerships (see Note 8) based on discounted cash flow projections using our Predecessor’s historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future considering inflation rates, federal and state regulatory requirements, and our Predecessor’s assumed credit-adjusted risk-free interest rate. These estimates of fair value were Level 3 measurements as they were based on unobservable inputs. We estimated the fair value of our enterprise value and reorganizational value of assets and liabilities upon our emergence from bankruptcy through fresh-start accounting (see Note 2) utilizing the discounted cash flow method for both our gas and oil production business and our partnership management business based on the financial projections in our disclosure statement. The resulting fair value of our equity was used to value shares issued under our incentive plan. These estimates of fair value are Level 3 measurements as they are based on unobservable inputs.

Certain Relationships and Relat

Certain Relationships and Related Party Transactions	9 Months Ended
	Sep. 30, 2017
Related Party Transactions [Abstract]
Certain Relationships and Related Party Transactions	NOTE 8 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS Relationship with ATLS . Except for our named executive officers, we do not directly employ any persons to manage or operate our business. These functions are provided by employees of ATLS and/or its affiliates. As of September 30, 2017, we had a $1.8 million payable to ATLS for payroll and benefit costs related to ATLS employees managing and operating our business, which was recorded as a current liability within advances from affiliates on our condensed consolidated balance sheet. As of September 30, 2017 we reclassified $15.1 million of receivables from ATLS originating prior to our Chapter 11 Filings to non-current due to the uncertainty of collecting this balance within the next twelve months, which was recorded within non-current advances to affiliates on our condensed consolidated balance sheet. As of December 31, 2016, we had net receivables of $3.3 million from ATLS related to the timing of funding cash accounts related to general and administrative expenses, such as payroll and benefits, and amounts originating prior to our Chapter 11 Filings, which was recorded as a net current asset within in advances to affiliates in our condensed consolidated balance sheets. Relationship with Drilling Partnerships . We conduct certain activities through, and a portion of our revenues are attributable to, sponsorship of the Drilling Partnerships. We serve as general partner and operator of the Drilling Partnerships and assume customary rights and obligations for the Drilling Partnerships. As the general partner, we are liable for the Drilling Partnerships’ liabilities and can be liable to limited partners of the Drilling Partnerships if we breach our responsibilities with respect to the operations of the Drilling Partnerships. We are 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. On June 30, 2017, in connection with the completion of the sale of the majority of the Appalachian Assets, we delegated the operational activities to an affiliate of Diversified for all the Drilling Partnerships’ natural gas and oil wells in Pennsylvania and Tennessee. In March 2016, our Predecessor transferred $36.7 million of investor capital raised and $13.3 million of accrued well drilling and completion costs incurred by our Predecessor to the Atlas Eagle Ford 2015 L.P. private drilling partnership for activities directly related to their program. In June 2016, our Predecessor transferred $3.8 million of funds to certain of the Drilling Partnerships that were projected to make monthly or quarterly distributions to their limited partners over the next several months and/or quarters to ensure accessible distribution funding coverage in accordance with the respective Drilling Partnerships’ operations and partnership agreements in the event that our Predecessor experienced a prolonged restructuring period as our Predecessor performed all administrative and management functions for the Drilling Partnerships. During the Predecessor period from January 1, 2016 to August 31, 2016, our Predecessor recorded $7.2 million and $12.4 million of gas and oil properties and asset retirement obligations, respectively, transferred to our Predecessor as a result of certain Drilling Partnership consolidations. The gas and oil properties and asset retirement obligations were recorded at their fair values on the respective dates of the Drilling Partnerships’ consolidation and transfer to our Predecessor (see Note 7) and resulted in a non-cash loss of $6.1 million, net of consolidation and transfer adjustments, for the Predecessor period from January 1, 2016 through August 31, 2016, which was recorded in net income (loss) from discontinued operations in the consolidated statements of operations. During the Predecessor periods from July 1, 2016 to August 31, 2016 and from January 1, 2016 to August 31, 2016, we recognized a $10.9 million provision for losses on Drilling Partnership receivables related to the write down of certain receivables to their estimated net realizable values, which is recorded in loss from discontinued operations on our consolidated statement of operations. As of December 31, 2016, we had trade receivables of $0.1 million from certain of the Drilling Partnerships, which were recorded in accounts receivable in our condensed consolidated balance sheet. As of September 30, 2017 and December 31, 2016, we had trade payables of $3.2 million and $5.6 million, respectively, to certain of the Drilling Partnerships, which were recorded in accounts payable in our condensed consolidated balance sheets. Relationship with AGP . At the direction of ATLS, we charge direct costs, such as salaries and wages, and allocate indirect costs, such as rent and other general and administrative costs, to AGP based on the number of ATLS employees who devoted time to AGP’s activities. As of September 30, 2017 and December 31, 2016, we had receivables of $0.1 million and $0.8 million, respectively, from AGP related to AGP’s direct costs and indirect cost allocation, which was recorded in advances to affiliates in our condensed consolidated balance sheets. Other Relationships . We have other related party transactions with regard to certain funds advised and sub-advised by GSO Capital Partners LP and its affiliates (“GSO”) as GSO funds are majority lenders under our Second Lien Credit Facility and GSO funds hold an excess of ten-percent of our common shares.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2017
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	NOTE 9 – COMMITMENTS AND CONTINGENCIES Drilling Partnership Commitments As of September 30, 2017, we are committed to expend approximately $2.8 million, principally on a new enterprise resource planning system and drilling and completion expenditures. Environmental Matters We and our subsidiaries are subject to various federal, state and local laws and regulations relating to the protection of the environment. We have established procedures for the ongoing evaluation of our and our subsidiaries’ operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. We and our subsidiaries maintain insurance which may cover in whole or in part certain environmental expenditures. We and our subsidiaries had no environmental matters requiring specific disclosure or requiring the recognition of a liability as of September 30, 2017 and December 31, 2016. Legal Proceedings We are party to various routine legal proceedings arising out of the ordinary course of our business. We believe that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.

Predecessor Cash Distributions

Predecessor Cash Distributions	9 Months Ended
	Sep. 30, 2017
Predecessor
Predecessor Cash Distributions	NOTE 10 – PREDECESSOR CASH DISTRIBUTIONS Our Predecessor had a monthly cash distribution program whereby it distributed all of its available cash (as defined in its partnership agreement) for that month to its unitholders within 45 days from the month end. If our Predecessor’s common unit distributions in any quarter exceed specified target levels, ATLS received between 13% and 48% of such distributions in excess of the specified target levels. During the Predecessor period from January 1, 2016 through August 31, 2016, our Predecessor paid four monthly cash distributions totaling $5.1 million to its common limited partners ($0.0125 per unit per month); $2.5 million to its Preferred Class C limited partners ($0.0125 per unit per month); and $0.2 million to its General Partner Class A holder ($0.0125 per unit per month). During the Predecessor period from January 1, 2016 through August 31, 2016, our Predecessor paid two distributions totaling $4.4 million to its Class D Preferred limited partners ($0.5390625 per unit) for the period October 15, 2015 through April 14, 2016 671875 per unit) October 15, 2015 through April 14, 2016

Operating Segment Information

Operating Segment Information	9 Months Ended
	Sep. 30, 2017
Segment Reporting [Abstract]
Operating Segment Information	NOTE 11 – OPERATING SEGMENT INFORMATION Our operations include two reportable operating segments: gas and oil production and Drilling Partnership management. The Drilling Partnership management segment includes all of our managing and operating activities specific to the Drilling Partnerships including well construction and completion, administration and oversight, well services, and gathering and processing. These operating segments reflect the way we manage our operations and make business decisions. We previously presented three reportable operating segments; however, due to the decline in investor capital funds raised in recent years, anticipated lower levels of future investor capital fund raise, and the consolidation of certain historical Drilling Partnerships in 2016, we aggregated our well construction and completion segment with our other partnership management segment to report all of our Drilling Partnership management activities in one combined segment as they do not meet the quantitative threshold for reporting individual segment information. As a result of this change, we have restated our prior year condensed consolidated statements of operations and segment footnote disclosures to conform to our current presentation. Operating segment data for the periods indicated were as follows (in thousands): Successor Predecessor Three Months Ended September 30, 2017 Period September 1 through 30, 2016 Period July 1 through August 31, 2016 Gas and oil production: Gas and oil production revenues (1) $ 43,356 $ 15,182 $ 38,643 Gas and oil production costs (21,633 ) (9,854 ) (18,577 ) Depreciation, depletion and amortization (11,646 ) (4,882 ) (14,723 ) Loss on divestiture (5,177 ) — — Segment income $ 4,900 $ 446 $ 5,343 Drilling partnership management: (2) Drilling partnership management r evenues $ 1,997 $ 2,074 $ 18,778 Drilling partnership management expenses (248 ) (1,266 ) (16,121 ) Depreciation, depletion and amortization expense (288 ) (270 ) (5,862 ) Segment income (loss) $ 1,461 $ 538 $ (3,205 ) Reconciliation of segment income (loss) to net loss: Segment income (loss): Gas and oil production $ 4,900 $ 446 $ 5,343 Drilling partnership management (2) 1,461 538 (3,205 ) Total segment income 6,361 984 2,138 General and administrative expenses (3) (10,142 ) (4,530 ) (5,128 ) Interest expense (3) (15,268 ) (3,470 ) (14,087 ) Gain (loss) on asset sales and disposal (3) (82 ) 5 (18 ) Reorganization items, net (3) — (353 ) (16,614 ) Other income (loss) (3) (777 ) — (3,063 ) Income tax (provision) benefit (3) 202 — — Net loss $ (19,706 ) $ (7,364 ) $ (36,772 ) Reconciliation of segment revenues to total revenues: Gas and oil production (1) $ 43,356 $ 15,182 $ 38,643 Drilling partnership management 1,997 2,074 18,778 Total revenues $ 45,353 $ 17,256 $ 57,421 Capital expenditures: Gas and oil production $ 4,279 $ 5,464 $ 5,529 Drilling partnership management — (115 ) 496 Corporate and other 325 18 49 Total capital expenditures $ 4,604 $ 5,367 $ 6,074 Successor Predecessor Nine Months Ended September 30, 2017 Period September 1 through 30, 2016 Period January 1 through August 31, 2016 Gas and oil production: Gas and oil production revenues (1) $ 197,855 $ 15,182 $ 105,829 Gas and oil production costs (74,355 ) (9,854 ) (80,988 ) Depreciation, depletion and amortization (37,455 ) (4,882 ) (62,142 ) Loss on divestiture (43,369 ) — — Segment income (loss) $ 42,676 $ 446 $ (37,301 ) Drilling partnership management: (2) Drilling partnership management r evenues $ 17,387 $ 2,074 $ 24,446 Drilling partnership management expenses (10,026 ) (1,266 ) (17,427 ) Depreciation, depletion and amortization expense (947 ) (270 ) (11,130 ) Segment income (loss) $ 6,414 $ 538 $ (4,111 ) Reconciliation of segment income (loss) to net loss: Segment income (loss): Gas and oil production (1) $ 42,676 $ 446 $ (37,301 ) Drilling partnership management 6,414 538 (4,111 ) Total segment income (loss) 49,090 984 (41,412 ) General and administrative expenses (3) (32,961 ) (4,530 ) (41,038 ) Interest expense (3) (41,816 ) (3,470 ) (71,059 ) Gain on early extinguishment of debt (3) — — 26,498 Gain (loss) on asset sales and disposal (3) 25 5 (551 ) Reorganization items, net (3) — (353 ) (16,614 ) Other income (loss) (3) (925 ) — (3,063 ) Income tax (provision) benefit (3) 11,503 — — Net loss $ (15,084 ) $ (7,364 ) $ (147,239 ) Reconciliation of segment revenues to total revenues: Gas and oil production (1) $ 197,855 $ 15,182 $ 105,829 Drilling partnership management 17,387 2,074 24,446 Total revenues $ 215,242 $ 17,256 $ 130,275 Capital expenditures: Gas and oil production $ 36,191 $ 5,464 $ 22,684 Drilling partnership management 521 (115 ) 2,046 Corporate and other 527 18 164 Total capital expenditures $ 37,239 $ 5,367 $ 24,894 (1) Includes gain (loss) on mark-to-market derivatives. The Predecessor period from January 1, 2016 through August 31, 2016 includes a $23.2 million loss on mark-to-market derivatives related to increases in commodity future prices relative to our commodity fixed price swaps. (2) Includes revenues and expenses from our Drilling Partnership management activities, including well construction and completion, well services, gathering and processing, administration and oversight that do not meet the quantitative threshold for reporting individual segment information. (3) General and administrative expenses, interest expense, gain on early extinguishment of debt, gain (loss) on asset sales and disposal, reorganization items, net,, other income (loss) and income tax (provision) benefit have not been allocated to reportable segments as it would be impracticable to reasonably do so for the periods presented. September 30, 2017 December 31, 2016 Balance sheet: Total assets: Gas and oil production $ 556,607 $ 703,243 Drilling partnership management 5,476 11,786 Corporate and other (1) 43,342 44,129 Assets held for sale — 122,676 Total assets $ 605,425 $ 881,834 (1) Corporate and other primarily consists of cash and cash equivalents, advances to affiliates and other assets, net, which have not been allocated to reportable segments.

Basis of Presentation and Sum18

Basis of Presentation and Summary of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2017
Basis of Presentation	Basis of Presentation The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and the applicable rules and regulations of the Securities and Exchange Commission regarding interim financial reporting and include all adjustments that are necessary for a fair presentation of our consolidated results of operations, financial condition and cash flows for the periods shown, including normal, recurring accruals and other items. The consolidated results of operations for the interim periods presented are not necessarily indicative of results for the full year. The year-end condensed consolidated balance sheet was derived from audited financial statements but does not include all disclosures required by U.S. GAAP. For a more complete discussion of our accounting policies and certain other information, refer to our consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016. In connection with the Chapter 11 Filings, we were subject to the provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852 Reorganizations Upon emergence from bankruptcy on the Plan Effective Date, we adopted fresh-start accounting in accordance with ASC 852. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Plan Effective Date, which differed materially from the recorded values of ARP’s assets and liabilities. As a result, our condensed consolidated statement of operations subsequent to the Plan Effective Date is not comparable to ARP’s condensed consolidated statement of operations prior to the Plan Effective Date. Our condensed consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented on or after the Plan Effective Date and dates prior. Our financial results for future periods following the application of fresh-start accounting will be different from historical trends and the differences may be material. References to “Successor” relate to the Company on and subsequent to the Plan Effective Date. References to “Predecessor” refer to the Company prior to the Plan Effective Date. The condensed consolidated financial statements of the Successor have been prepared assuming that the Company will continue as a going concern and contemplate the realization of assets and the satisfaction of liabilities in the normal course of business.
Reclassifications	Reclassifications Certain reclassifications have been made to our condensed consolidated financial statements for the prior year periods to conform to classifications used in the current year, specifically related to our discontinued operations (see Note 3) and our segment information on the condensed consolidated statement of operations and segment footnote disclosures (see Note 11).
Principles of Consolidation	Principles of Consolidation Our condensed consolidated financial statements include our accounts and the accounts of our wholly-owned subsidiaries. Transactions between us and other ATLS managed operations have been identified in the condensed consolidated financial statements as transactions between affiliates, where applicable. All material intercompany transactions have been eliminated. We sponsored and continue to manage tax-advantaged investment partnerships (the “Drilling Partnerships”), in which we coinvested, to finance a portion of our natural gas, crude oil and NGL production activities. In accordance with established practice in the oil and gas industry, our condensed 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 we have an interest. Such interests generally approximate 10-30%. Our condensed consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of the Drilling Partnerships. Rather, we calculate these items specific to our own economics.
Liquidity and Capital Resources and Ability to Continue as Going Concern	Liquidity and Capital Resources and Ability to Continue as a Going Concern Since the Plan Effective Date, we have funded our operations through cash flows generated from our operations and cash on hand. We currently do not have the capacity to access additional liquidity from our First Lien Credit Facility and our ability to access public equity and debt markets may be limited. Our 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 continue to remain low in 2017. These lower commodity prices have negatively impacted our revenues, earnings and cash flows, which has negatively impacted our ability to remain in compliance with the covenants under our credit facilities. Sustained low commodity prices could have a material and adverse effect on our liquidity position. Even following the amendments described below, we continue to face liquidity issues and are currently considering, and are likely to make, changes to our capital structure to maintain sufficient liquidity, meet our debt obligations and manage and strengthen our balance sheet. If we are not able to enter into further amendments with our lenders prior to the expiration of the standstill period, we may be forced to seek further options as described below. We were not in compliance with certain of the financial covenants under our credit facilities as of December 31, 2016, as well as the requirement to deliver audited financial statements without a going concern qualification. As a result of the amendment referenced below, our financial covenants will not be tested again until the quarter ending December 31, 2017. We do not currently have sufficient liquidity to repay all of our outstanding indebtedness, and as a result, there is substantial doubt regarding our ability to continue as a going concern. We have classified $538.1 million of outstanding indebtedness under our credit facilities, which is net of $1.7 million of deferred financing costs, as current portion of long term debt, net within our condensed consolidated balance sheet as of September 30, 2017, based on the occurrence of the event of default, the lenders under our credit facilities, as applicable, could elect to declare all amounts outstanding immediately due and payable and the lenders could terminate all commitments to extend further credit. On April 19, 2017, we entered into an amendment to our First Lien Credit Facility (which has been superseded by subsequent amendments as described further below). This amendment provided for, among other things, waivers of our non-compliance, increases in certain financial covenant ratios and scheduled decreases in our borrowing base (refer to Note 5 – Debt for further information regarding the specific amended terms and provisions). As part of our overall business strategy, we have continued to execute on our sales of non-core assets, which has included the sale of our Appalachia and Rangely operations. The proceeds of the consummated asset sales were used to repay borrowings under our First Lien Credit Facility. Our strategy is to continue to sell non-core assets to reduce our leverage position, which will also help us to comply with the requirements of our First Lien Credit Facility amendments. In addition to the amendments to the financial ratio covenants, the First Lien Credit Facility lenders waived certain defaults by us with respect to the fourth quarter of 2016, including compliance with the ratios of Total Debt to EBITDA and First Lien Debt to EBITDA, as well as our obligation to deliver financial statements without a “going concern” qualification. The First Lien Credit Facility lenders’ waivers were subject to revocation in certain circumstances, including the exercise of remedies by junior lenders (including pursuant to our Second Lien Credit Facility), the failure to extend the standstill period under the intercreditor agreement at least 15 business days prior to its expiration, and the occurrence of additional events of default under the First Lien Credit Facility. On April 21, 2017, the lenders under the our Second Lien Credit Facility delivered a notice of events of default and reservation of rights, pursuant to which they noticed events of default related to financial covenants and the failure to deliver financial statements without a “going concern” qualification. The delivery of such notice began the 180-day standstill period under the intercreditor agreement, during which the lenders under the Second Lien Credit Facility were prevented from pursuing remedies against the collateral securing our obligations under the Second Lien Credit Facility. The lenders have not accelerated the payment of amounts outstanding under the Second Lien Credit Facility. On May 4, 2017, we entered into a definitive agreement to sell our conventional Appalachia and Marcellus assets to Diversified Gas & Oil, PLC (“Diversified”) for $84.2 million. The transaction included the sale of approximately 8,400 oil and gas wells across Pennsylvania, Ohio, Tennessee, New York and West Virginia, along with the associated infrastructure (the “Appalachian Assets”). We retained our Utica Shale position, Indiana assets and West Virginia CBM assets in the region. On June 30, 2017, we completed a majority of the Appalachian Assets sale for net cash proceeds of $65.6 million, which included customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under our First Lien Credit Facility. On June 12, 2017, we entered into a definitive agreement to sell our 25% interest in Rangely Field to an affiliate of Merit Energy Company, LLC for $105 million. Rangely is a CO 2 2 On September 27, 2017, the lenders under our Second Lien Credit Facility entered into a letter agreement with us and the lenders under our First Lien Credit Facility (the “Extension Letter”) (which has been superseded by subsequent amendments as described further below). Pursuant to the Extension Letter, the Second Lien Credit Facility lenders agreed to extend the 180-day standstill period under the intercreditor agreement (during which the lenders under the Second Lien Credit Facility were prevented from pursuing remedies against the collateral securing the Company’s obligations under the Second Lien Credit Facility) by an additional 35 days from October 18, 2017 to November 22, 2017. In addition, the extension of the standstill period extends the waiver of certain defaults under the First Lien Credit Facility, which terminates 15 business days prior to the expiration of the standstill period. The parties agreed to extend the standstill period to provide the Company with additional time to negotiate proposed amendments to each of the First Lien Credit Facility and the Second Lien Credit Facility. On September 29, 2017, we completed the remainder of the Appalachia Assets sale for additional cash proceeds of $10.4 million, all of which was used to repay a portion of outstanding borrowings under our First Lien Credit Facility. On November 6, 2017, we entered into a fourth amendment to our First Lien Credit Facility. The fourth amendment has an effective date of October 31, 2017 and confirms the conforming and non-conforming tranches of the borrowing base at $228.7 million and $30 million, respectively, but requires us to take actions (which can include asset sales and equity offerings) to reduce the conforming tranche of the borrowing base to $190 million by December 8, 2017 and to $150 million by August 31, 2018. The maturity date of the non-conforming tranche of the borrowing base was confirmed as May 1, 2018. We are required to use proceeds from asset sales to make prepayments. In addition to the requirements above, the First Lien Credit Facility lenders also agreed to a limited waiver of certain existing defaults with respect to financial covenants, required repayments of borrowings and other related matters. The waiver terminates upon the earliest of (i) December 8, 2017, (ii) the occurrence of additional events of default under the First Lien Credit Facility and (iii) the exercise of remedies under our Second Lien Credit Facility. Pursuant to the fourth amendment, we are required to hedge at least 50% and 80% of our 2019 projected proved developed producing production by December 31, 2017 and March 31, 2018, respectively. In connection with, and as a condition to, the effectiveness of the fourth amendment to our First Lien Credit Facility, the lenders under our Second Lien Credit Facility agreed to extend the standstill period under the intercreditor agreement (during which the lenders under the Second Lien Credit Facility are prevented from pursuing remedies against the collateral securing our obligations under the Second Lien Credit Facility) until December 29, 2017. We continually review and may make changes to our capital structure from time to time, with the goal of strengthening our balance sheet and meeting our debt service obligations. We could pursue options such as refinancing, restructuring or reorganizing our indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address our liquidity concerns and high debt levels. We are evaluating various options, but there is no certainty that we will be able to implement any such options, and we cannot provide any assurances that any refinancing or changes in our debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for our stakeholders. We cannot assure you that we will be able to implement the above actions, if necessary, on commercially reasonable terms, or at all, in a manner that will be permitted under the terms of our debt instruments or in a manner that does not negatively impact the price of our securities. Additionally, there can be no assurance that the above actions will allow us to meet our debt obligations and capital requirements.
Use of Estimates	Use of Estimates The preparation of our condensed 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 consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. Our condensed consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion of gas and oil properties, fair value of derivative instruments, and the fair value of assets held for sale. The oil and 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.
Assets Held For Sale	Assets Held For Sale Assets are classified as held for sale when we commit to a plan to sell the assets and there is reasonable certainty the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less estimated costs to sell. Any subsequent changes to the fair value less estimated costs to sell impact the measurement of assets held for sale, with any gain or loss reflected in the loss on divestitures line item in our condensed consolidated statements of operations. See Note 3 for additional disclosures regarding assets held for sale.
Discontinued Operations	Discontinued Operations A disposal of a component of our entity is classified as discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on our operations and financial results. For components classified as discontinued operations, the balance sheet amounts and results of operations are reclassified from their historical presentation to assets and liabilities held for sale on the condensed consolidated balance sheet and to net income (loss) from discontinued operations on the condensed consolidated statement of operations for all periods presented. The gains or losses associated with these divested components are recorded in net income (loss) from discontinued operations on the condensed consolidated statement of operations. See Note 3 for additional disclosures regarding discontinued operations.
Predecessor's Reorganization Items, Net	Predecessor’s Reorganization Items, Net Incremental costs incurred as a result of the Chapter 11 Filings, net gain on settlement of liabilities subject to compromise and reorganization adjustments, and net impact of fresh start adjustments are classified as “Reorganization items, net” in the Predecessor’s condensed consolidated statement of operations. The following table summarizes the reorganization items: Professional fees and other $ (33,065) Accelerated amortization of deferred financing costs (9,565) Net gain on reorganization adjustments 361,479 Net loss on fresh start adjustments (335,463) Total reorganization items, net $ (16,614)
Income Taxes	Income Taxes Our effective tax rates for the Successor three and nine months ended September 30, 2017 were 1.27% and 0.74%, respectively, which represent our expected Texas Franchise Tax liability. Our income tax provision differs from the provision computed by applying the U.S. Federal statutory corporate income tax rate of 35% primarily due to the valuation allowance on our deferred tax assets. For the Successor three and nine months ended September 30, 2017, we recognized a provision for income taxes of $0.2 million and $11.5 million, respectively, in net income (loss) from discontinued operations on our condensed consolidated statement of operations. For the Successor three and nine months ended September 30, 2017, we recognized a corresponding income tax benefit of $0.2 million and $11.5 million, respectively, in net income (loss) from continuing operations on our condensed consolidated statement of operations, which represents a direct offset of the provision for income taxes included within our discontinued operations.
Incentive Plan	Successor’s Management Incentive Plan Pursuant to the Titan Energy, LLC Management Incentive Plan (the “MIP”) plan, participants are allowed to withhold or surrender shares for the payment of taxes. These shares are available for re-issuance under the MIP. For the three months ended September 30, 2017, 91,710 shares under the MIP became unrestricted. Of these shares, 42,251 were withheld for taxes, which resulted in $0.2 million recognized in our consolidated statement of changes in members’ equity. For the nine months ended September 30, 2017, 91,710 shares under the MIP became unrestricted and 37,324 shares were granted and vested immediately. Of these shares, 57,562 were withheld for taxes, which resulted in $0.3 million recognized in our consolidated statement of changes in members’ equity. For the Successor period September 1, 2016 through September 30, 2016, 138,750 shares were granted and vested immediately.
Successor’s Net Income Attributable to Common Shareholders Per Share	Successor’s Net Income Attributable to Common Shareholders Per Share The Successor’s basic net income attributable to common shareholders per share is computed by dividing net income attributable to our common shareholders by the weighted-average number of common shares outstanding, excluding any unvested restricted shares, for the period. The Successor’s diluted net income attributable to common shareholders per share is similarly calculated except that the common shares outstanding for the period are increased using the treasury stock method to reflect the potential dilution that could occur if outstanding share based awards were vested at the end of the applicable period. Anti-dilutive shares represent potentially dilutive securities that are excluded from the computation of diluted net income attributable to common shareholders per share as their impact would be anti-dilutive. We determine if potentially dilutive shares are anti-dilutive based on their impact to net income (loss) from continuing operations. The following is a reconciliation of net income attributable to our Successor’s common shareholders for purposes of calculating net income attributable to our Successor’s common shareholders per share (in thousands): Successor Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017 Period from September 1, 2016 through September 30, 2016 Net loss from continuing operations $ (19,706 ) $ (15,084 ) $ (7,364 ) Less: Series A Preferred member interest in loss from continuing operations (394 ) (302 ) (147 ) Net loss from continuing operations utilized in the calculation of net loss attributable to common shareholders per share $ (19,312 ) $ (14,782 ) $ (7,217 ) Net income (loss) from discontinued operations $ 2,156 $ 20,945 $ (167 ) Less: Series A Preferred member interest in net income (loss) from discontinued operations 43 419 (4 ) Net income (loss) from discontinued operations utilized in the calculation of net income (loss) attributable to common shareholders per share $ 2,113 $ 20,526 $ (163 ) The following table is a reconciliation of the Successor’s basic and diluted weighted average number of common shares used to calculate basic and diluted net income attributable to common shareholders per share (in thousands): Successor Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017 Period from September 1, 2016 through September 30, 2016 Weighted average number of common shares - basic (1) 5,208 5,186 5,139 Add dilutive effect of share based awards at end of period (2) — — — Weighted average number of common shares - diluted 5,208 5,186 5,139 (1) For the three and nine months ended September 30, 2017, 186,000 and 278,000 restricted common shares outstanding, respectively, were excluded from the calculation of basic weighted average number of common shares because they were not vested. For the Successor period from September 1, 2016 through September 30, 2016, 278,000 restricted common shares outstanding were excluded from the calculation of basic weighted average number of common shares because they were not vested. (2) We determine if potentially dilutive shares are anti-dilutive based on their impact to net income (loss) from continuing operations. Since all of the periods presented resulted in net loss from continuing operations attributable to common shareholders, potentially dilutive shares were excluded because their inclusion would have been anti-dilutive.
Predecessor's Net Income Per Common Unit	Predecessor’s Net Income (Loss) Per Common Unit The following is a reconciliation of net income (loss) allocated to our Predecessor’s common limited partners for purposes of calculating net income (loss) attributable to our Predecessor’s common limited partners per unit (in thousands): Predecessor Period From July 1 through August 31, 2016 Period From January 1 through August 31, 2016 Net loss from continuing operations $ (36,772 ) $ (147,239 ) Preferred limited partner dividends — (4,013 ) Net loss from continuing operations attributable to common limited partners and the general partner (36,772 ) (151,252 ) Less: General partner’s interest in net loss from continuing operations (736 ) (3,025 ) Net loss from continuing operations attributable to common limited partners (36,036 ) (148,227 ) Less: Net income from continuing operations attributable to participating securities – phantom units — — Net loss from continuing operations utilized in the calculation of net loss attributable to common limited partners per unit – Basic (36,036 ) (148,227 ) Plus: Convertible preferred limited partner dividends (1) — — Net loss from continuing operations utilized in the calculation of net loss attributable to common limited partners per unit – Diluted $ (36,036 ) $ (148,227 ) Net loss from discontinued operations attributable to common limited partners and the general partner $ (11,852 ) $ (30,191 ) Less: General partner’s interest in net loss from discontinued operations (237 ) (604 ) Net loss from discontinued operations attributable to common limited partners (11,615 ) (29,587 ) Less: Net income from discontinued operations attributable to participating securities – phantom units — — Net loss from discontinued operations utilized in the calculation of net loss attributable to common limited partners per unit – Basic (11,615 ) (29,587 ) Plus: Convertible preferred limited partner dividends (1) — — Net loss from discontinued operations utilized in the calculation of net loss attributable to common limited partners per unit – Diluted $ (11,615 ) $ (29,587 ) (1) For the periods presented, distributions on our Predecessor’s Class C convertible preferred units were The following table sets forth the reconciliation of our Predecessor’s weighted average number of common limited partner units used to compute basic net income (loss) attributable to our Predecessor’s common limited partners per unit with those used to compute diluted net income attributable to our Predecessor’s common limited partners per unit (in thousands): Predecessor Period From July 1 through August 31, 2016 Period From January 1 through August 31, 2016 Weighted average number of common limited partner units—basic 104,366 102,912 Add effect of dilutive incentive awards (1) — — Add effect of dilutive convertible preferred limited partner units (2) — — Weighted average number of common limited partner units—diluted 104,366 102,912 (1) For the Predecessor periods from July 1, 2016 through August 31, 2016 and from January 1, 2016 through August 31, 2016, 247,000 and 274,000 phantom units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. (2) For the periods presented, potential common limited partner units issuable upon (a) conversion of our Predecessor’s Class C preferred units and (b) exercise of the common unit warrants issued with our Predecessor’s Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. As our Predecessor’s Class D and Class E preferred units were convertible only upon a change of control event, they were not considered dilutive securities for earnings per unit purposes.
Recently Issued Accounting Standards	Recently Issued Accounting Standards In February 2016, the 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 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. We have made progress on our contract reviews and documentation.
Predecessor
Incentive Plan	Predecessor’s 2012 Long-Term Incentive Plan On May 12, 2016, due to the income tax ramifications of the potential options our Predecessor was considering, our Predecessor’s 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 August 31, 2016. The delayed vesting schedule did not have a significant impact on the compensation expense recorded in general and administrative expenses on the condensed consolidated statement of operations for the Predecessor period from January 1, 2016 through August 31, 2016 or our Predecessor’s remaining unrecognized compensation expense related to such awards. As a result of the Chapter 11 Filings, our Predecessor’s 2012 LTIP phantom units were cancelled. The remaining unrecognized compensation cost of $0.8 million was recognized upon the cancellation and was recorded in general and administrative expenses on the condensed consolidated statement of operations for the Predecessor period from July 1, 2016 through August 31, 2016.

Basis of Presentation and Sum19

Basis of Presentation and Summary of Significant Accounting Policies (Tables)	9 Months Ended
	Sep. 30, 2017
Summary of Reorganization Items	The following table summarizes the reorganization items: Professional fees and other $ (33,065) Accelerated amortization of deferred financing costs (9,565) Net gain on reorganization adjustments 361,479 Net loss on fresh start adjustments (335,463) Total reorganization items, net $ (16,614)
Reconciliation of Net Income (Loss)	The following is a reconciliation of net income attributable to our Successor’s common shareholders for purposes of calculating net income attributable to our Successor’s common shareholders per share (in thousands): Successor Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017 Period from September 1, 2016 through September 30, 2016 Net loss from continuing operations $ (19,706 ) $ (15,084 ) $ (7,364 ) Less: Series A Preferred member interest in loss from continuing operations (394 ) (302 ) (147 ) Net loss from continuing operations utilized in the calculation of net loss attributable to common shareholders per share $ (19,312 ) $ (14,782 ) $ (7,217 ) Net income (loss) from discontinued operations $ 2,156 $ 20,945 $ (167 ) Less: Series A Preferred member interest in net income (loss) from discontinued operations 43 419 (4 ) Net income (loss) from discontinued operations utilized in the calculation of net income (loss) attributable to common shareholders per share $ 2,113 $ 20,526 $ (163 ) The following is a reconciliation of net income (loss) allocated to our Predecessor’s common limited partners for purposes of calculating net income (loss) attributable to our Predecessor’s common limited partners per unit (in thousands): Predecessor Period From July 1 through August 31, 2016 Period From January 1 through August 31, 2016 Net loss from continuing operations $ (36,772 ) $ (147,239 ) Preferred limited partner dividends — (4,013 ) Net loss from continuing operations attributable to common limited partners and the general partner (36,772 ) (151,252 ) Less: General partner’s interest in net loss from continuing operations (736 ) (3,025 ) Net loss from continuing operations attributable to common limited partners (36,036 ) (148,227 ) Less: Net income from continuing operations attributable to participating securities – phantom units — — Net loss from continuing operations utilized in the calculation of net loss attributable to common limited partners per unit – Basic (36,036 ) (148,227 ) Plus: Convertible preferred limited partner dividends (1) — — Net loss from continuing operations utilized in the calculation of net loss attributable to common limited partners per unit – Diluted $ (36,036 ) $ (148,227 ) Net loss from discontinued operations attributable to common limited partners and the general partner $ (11,852 ) $ (30,191 ) Less: General partner’s interest in net loss from discontinued operations (237 ) (604 ) Net loss from discontinued operations attributable to common limited partners (11,615 ) (29,587 ) Less: Net income from discontinued operations attributable to participating securities – phantom units — — Net loss from discontinued operations utilized in the calculation of net loss attributable to common limited partners per unit – Basic (11,615 ) (29,587 ) Plus: Convertible preferred limited partner dividends (1) — — Net loss from discontinued operations utilized in the calculation of net loss attributable to common limited partners per unit – Diluted $ (11,615 ) $ (29,587 ) (1) For the periods presented, distributions on our Predecessor’s Class C convertible preferred units were
Reconciliation of Weighted Average Number of Common Shares / Common Limited Partner Units	The following table is a reconciliation of the Successor’s basic and diluted weighted average number of common shares used to calculate basic and diluted net income attributable to common shareholders per share (in thousands): Successor Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017 Period from September 1, 2016 through September 30, 2016 Weighted average number of common shares - basic (1) 5,208 5,186 5,139 Add dilutive effect of share based awards at end of period (2) — — — Weighted average number of common shares - diluted 5,208 5,186 5,139 (1) For the three and nine months ended September 30, 2017, 186,000 and 278,000 restricted common shares outstanding, respectively, were excluded from the calculation of basic weighted average number of common shares because they were not vested. For the Successor period from September 1, 2016 through September 30, 2016, 278,000 restricted common shares outstanding were excluded from the calculation of basic weighted average number of common shares because they were not vested. (2) We determine if potentially dilutive shares are anti-dilutive based on their impact to net income (loss) from continuing operations. Since all of the periods presented resulted in net loss from continuing operations attributable to common shareholders, potentially dilutive shares were excluded because their inclusion would have been anti-dilutive.
Predecessor
Reconciliation of Weighted Average Number of Common Shares / Common Limited Partner Units	The following table sets forth the reconciliation of our Predecessor’s weighted average number of common limited partner units used to compute basic net income (loss) attributable to our Predecessor’s common limited partners per unit with those used to compute diluted net income attributable to our Predecessor’s common limited partners per unit (in thousands): Predecessor Period From July 1 through August 31, 2016 Period From January 1 through August 31, 2016 Weighted average number of common limited partner units—basic 104,366 102,912 Add effect of dilutive incentive awards (1) — — Add effect of dilutive convertible preferred limited partner units (2) — — Weighted average number of common limited partner units—diluted 104,366 102,912 (1) For the Predecessor periods from July 1, 2016 through August 31, 2016 and from January 1, 2016 through August 31, 2016, 247,000 and 274,000 phantom units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. (2) For the periods presented, potential common limited partner units issuable upon (a) conversion of our Predecessor’s Class C preferred units and (b) exercise of the common unit warrants issued with our Predecessor’s Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. As our Predecessor’s Class D and Class E preferred units were convertible only upon a change of control event, they were not considered dilutive securities for earnings per unit purposes.

Discontinued Operations and D20

Discontinued Operations and Divestitures (Tables)	9 Months Ended
	Sep. 30, 2017
Appalachia
Schedule of Major Classes of Line Items Included Within Net Income (Loss) and Major Classes of Assets and Liabilities from Discontinued Operations	The following table reconciles the major classes of line items from the discontinued operations of the Appalachian Assets included within net income (loss) from discontinued operations, in thousands: Successor Predecessor Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017 Period From September 1 to September 30, 2016 Period From July 1 to August 31, 2016 Period From January 1 to August 31, 2016 Revenues: Gas and oil production $ 288 $ 21,213 $ 1,197 $ 2,917 $ 10,037 Drilling partnership management — 5,114 1,320 3,621 12,100 Gain (loss) on mark-to-market derivatives — 4,955 750 875 (667 ) Total revenues 288 31,282 3,267 7,413 21,470 Costs and expenses: Gas and oil production $ 924 $ 9,091 $ 760 $ 1,454 $ 6,244 Drilling partnership management 597 5,824 1,074 2,312 9,801 Depreciation, depletion and amortization — 4,842 869 2,693 9,059 General and administrative 298 4,378 395 12,044 16,974 Gain on sale of assets (4,319 ) (32,921 ) (4 ) (50 ) (72 ) Impairment on assets held for sale — 4,272 — — — Interest expense 115 2,769 340 842 3,529 Other (income) loss 541 541 — (30 ) 6,126 Total costs and expenses $ (1,844 ) $ (1,204 ) $ 3,434 $ 19,265 $ 51,661 Income (loss) from discontinued operations before income taxes 2,132 32,486 (167 ) (11,852 ) (30,191 ) Income tax provision (benefit) (24 ) 11,541 — — — Net income (loss) from discontinued operations $ 2,156 $ 20,945 $ (167 ) $ (11,852 ) $ (30,191 ) The following table details the major classes of assets and liabilities of the Appalachian Assets discontinued operations classified as held for sale for the prior period presented, in thousands: December 31, 2016 Current assets: Accounts receivable $ 7,254 Prepaid expenses and other 1,017 Total current assets 8,271 Property, plant and equipment, net 113,956 Other assets 449 Total non-current assets 114,405 Total assets classified as held for sale $ 122,676 Current liabilities: Accounts payable $ 2,516 Current portion of derivative liability 4,279 Accrued liabilities and other 2,666 Total current liabilities 9,461 Long-term derivative liability 1,407 Asset retirement obligations 60,316 Other long-term liabilities 682 Total non-current liabilities 62,405 Total liabilities classified as held for sale $ 71,866
Rangely
Schedule of Major Classes of Line Items Included Within Net Income (Loss) and Major Classes of Assets and Liabilities from Discontinued Operations	Successor Predecessor Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017 Period From September 1 to September 30, 2016 Period From July 1 to August 31, 2016 Period From January 1 to August 31, 2016 Income (loss) before income taxes (1) $ (4,292 ) $ (38,379 ) $ 532 $ 1,253 $ 2,011 (1) Income (loss) before income taxes reflects gas and oil production revenues less gas and oil production expenses, general and administrative expenses, depletion, depreciation, and amortization expenses for all periods presented. The Successor three and nine months ended September 30, 2017 include $5.2 million of loss on asset sale resulting from the closing of the Rangely Asset sale. The Successor nine months ended September 30, 2017 also includes $38.2 million loss on divestiture resulting from the carrying value of the Rangely Assets exceeding the fair value less costs to sell as disclosed above.

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	9 Months Ended
	Sep. 30, 2017
Property Plant And Equipment [Abstract]
Property, Plant and Equipment	The following is a summary of property, plant and equipment at the dates indicated (in thousands): September 30, 2017 December 31, 2016 Natural gas and oil properties: Proved properties $ 519,147 $ 608,901 Unproved properties 52,767 73,057 Support equipment and other 8,690 8,081 Total natural gas and oil properties 580,604 690,039 Less – accumulated depreciation, depletion and amortization (53,207 ) (19,270 ) Total property, plant and equipment, net $ 527,397 $ 670,769

Debt (Tables)

Debt (Tables)	9 Months Ended
	Sep. 30, 2017
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments	Total debt consists of the following at the dates indicated (in thousands): September 30, December 31, 2017 2016 First Lien Credit Facility $ 256,273 $ 435,809 Second Lien Credit Facility 283,523 261,022 Deferred financing costs, net of accumulated amortization of $686 and $172, respectively (1,711 ) (2,021 ) Total debt, net 538,085 694,810 Less current maturities (538,085 ) (694,810 ) Total long-term debt, net $ — $ —

Derivative Instruments (Tables)

Derivative Instruments (Tables)	9 Months Ended
	Sep. 30, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Summary of Cash Settlement on Commodity Derivatives and Presentation in Partnership's Consolidated Statements of Operations	The following table summarizes the commodity derivative activity and presentation in our condensed consolidated statements of operations for the periods indicated (in thousands): Successor Predecessor Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017 Period from September 1, 2016 through September 30, 2016 Period from July 1, 2016 through August 31, 2016 Period from January 1, 2016 through August 31, 2016 Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets (1)(2) $ — $ — $ — $ 1,461 $ 10,387 Portion of settlements attributable to subsequent mark to market gains (losses) (2) 1,666 (2,309 ) 191 3,440 80,604 Total cash settlements on commodity derivative contracts (2) $ 1,666 $ (2,309 ) $ 191 $ 4,901 $ 90,991 Gains (losses) recognized on cash settlement (3) $ 195 $ 20,409 $ (43 ) $ 9,381 $ (9,444 ) Gains (losses) recognized on open derivative contracts (3) (4,263 ) 16,516 (2,036 ) (7,028 ) (13,804 ) Gains (losses) on mark-to-market derivatives $ (4,068 ) $ 36,925 $ (2,079 ) $ 2,353 $ (23,248 ) (1) Recognized in gas and oil production revenue. (2) The Predecessor periods presented exclude the effects of the $214.9 million and the $20.4 million allocated to discontinued operations (see Note 3), net of $8.2 million in hedge monetization fees, paid directly to the First Lien Credit Facility lenders upon the sale of substantially all of our Predecessor’s commodity hedge positions on July 25, 2016 and July 26, 2016. The $8.2 million in hedge monetization fees was not allocated to discontinued operations as this was recorded in reorganization items, net on the condensed consolidated statements of operations. (3) Recognized in gain (loss) on mark-to-market derivatives.
Fair Values of the Partnership's Derivative Instruments Table	The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities included on our condensed consolidated balance sheets for the periods indicated (in thousands): Offsetting Derivatives as of September 30, 2017 Gross Amounts Recognized Gross Amounts Offset Net Amount Presented Current portion of derivative assets $ 2,038 $ (2,006 ) $ 32 Long-term portion of derivative assets 168 (168 ) — Total derivative assets $ 2,206 $ (2,174 ) $ 32 Current portion of derivative liabilities $ (5,635 ) $ 2,006 $ (3,629 ) Long-term portion of derivative liabilities (1,064 ) 168 (896 ) Total derivative liabilities $ (6,699 ) $ 2,174 $ (4,525 ) Offsetting Derivatives as of December 31, 2016 Current portion of derivative assets $ 7 $ (7 ) $ — Long-term portion of derivative assets 677 (677 ) — Total derivative assets $ 684 $ (684 ) $ — Current portion of derivative liabilities $ (30,526 ) $ 7 $ (30,519 ) Long-term portion of derivative liabilities (13,885 ) 677 (13,208 ) Total derivative liabilities $ (44,411 ) $ 684 $ (43,727 )
Commodity Derivative Instruments by Type Table	At September 30, 2017, we had the following commodity derivatives instruments: Type Production Period Ending December 31, Volumes (1) Average Fixed Price (2) Fair Value Asset / (Liability) Total Type (in thousands) (2) (in thousands) Natural Gas – Fixed Price Swaps 2017 (3) 12,919,900 $ 3.140 $ 693 2018 43,947,300 $ 2.959 $ (3,458 ) $ (2,765 ) Crude Oil – Fixed Price Swaps 2017 (3) 196,500 $ 47.441 $ (766 ) 2018 588,500 $ 50.286 $ (936 ) 2019 73,000 50.630 (26 ) $ (1,728 ) Total net liability $ (4,493 ) (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 are based on forward NYMEX natural gas prices, as applicable. Fair value of crude oil fixed price swaps are based on forward West Texas Intermediate (“WTI”) index crude oil prices, as applicable. (3) The production volumes for 2017 include the remaining three months of 2017 beginning October 1, 2017 .

Fair Value of Financial Instr24

Fair Value of Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2017
Fair Value Disclosures [Abstract]
Schedule of Financial Instruments at Fair Value	Information for financial instruments measured at fair value were as follows (in thousands): Derivatives, Fair Value, as of September 30, 2017 Level 1 Level 2 Level 3 Total Assets, gross Commodity swaps $ — $ 2,206 $ — $ 2,206 Total derivative assets, gross — 2,206 — 2,206 Liabilities, gross Commodity swaps — (6,699 ) — (6,699 ) Total derivative liabilities, gross — (6,699 ) — (6,699 ) Total derivatives, fair value, net $ — $ (4,493 ) $ — $ (4,493 ) Derivatives, Fair Value, as of December 31, 2016 Level 1 Level 2 Level 3 Total Assets, gross Commodity swaps $ — $ 684 $ — $ 684 Total derivative assets, gross — 684 — 684 Liabilities, gross Commodity swaps — (44,411 ) — (44,411 ) Total derivative liabilities, gross — (44,411 ) — (44,411 ) Total derivatives, fair value, net $ — $ (43,727 ) $ — $ (43,727 )

Operating Segment Information (

Operating Segment Information (Tables)	9 Months Ended
	Sep. 30, 2017
Segment Reporting [Abstract]
Operating Segment Data	Operating segment data for the periods indicated were as follows (in thousands): Successor Predecessor Three Months Ended September 30, 2017 Period September 1 through 30, 2016 Period July 1 through August 31, 2016 Gas and oil production: Gas and oil production revenues (1) $ 43,356 $ 15,182 $ 38,643 Gas and oil production costs (21,633 ) (9,854 ) (18,577 ) Depreciation, depletion and amortization (11,646 ) (4,882 ) (14,723 ) Loss on divestiture (5,177 ) — — Segment income $ 4,900 $ 446 $ 5,343 Drilling partnership management: (2) Drilling partnership management r evenues $ 1,997 $ 2,074 $ 18,778 Drilling partnership management expenses (248 ) (1,266 ) (16,121 ) Depreciation, depletion and amortization expense (288 ) (270 ) (5,862 ) Segment income (loss) $ 1,461 $ 538 $ (3,205 ) Reconciliation of segment income (loss) to net loss: Segment income (loss): Gas and oil production $ 4,900 $ 446 $ 5,343 Drilling partnership management (2) 1,461 538 (3,205 ) Total segment income 6,361 984 2,138 General and administrative expenses (3) (10,142 ) (4,530 ) (5,128 ) Interest expense (3) (15,268 ) (3,470 ) (14,087 ) Gain (loss) on asset sales and disposal (3) (82 ) 5 (18 ) Reorganization items, net (3) — (353 ) (16,614 ) Other income (loss) (3) (777 ) — (3,063 ) Income tax (provision) benefit (3) 202 — — Net loss $ (19,706 ) $ (7,364 ) $ (36,772 ) Reconciliation of segment revenues to total revenues: Gas and oil production (1) $ 43,356 $ 15,182 $ 38,643 Drilling partnership management 1,997 2,074 18,778 Total revenues $ 45,353 $ 17,256 $ 57,421 Capital expenditures: Gas and oil production $ 4,279 $ 5,464 $ 5,529 Drilling partnership management — (115 ) 496 Corporate and other 325 18 49 Total capital expenditures $ 4,604 $ 5,367 $ 6,074 Successor Predecessor Nine Months Ended September 30, 2017 Period September 1 through 30, 2016 Period January 1 through August 31, 2016 Gas and oil production: Gas and oil production revenues (1) $ 197,855 $ 15,182 $ 105,829 Gas and oil production costs (74,355 ) (9,854 ) (80,988 ) Depreciation, depletion and amortization (37,455 ) (4,882 ) (62,142 ) Loss on divestiture (43,369 ) — — Segment income (loss) $ 42,676 $ 446 $ (37,301 ) Drilling partnership management: (2) Drilling partnership management r evenues $ 17,387 $ 2,074 $ 24,446 Drilling partnership management expenses (10,026 ) (1,266 ) (17,427 ) Depreciation, depletion and amortization expense (947 ) (270 ) (11,130 ) Segment income (loss) $ 6,414 $ 538 $ (4,111 ) Reconciliation of segment income (loss) to net loss: Segment income (loss): Gas and oil production (1) $ 42,676 $ 446 $ (37,301 ) Drilling partnership management 6,414 538 (4,111 ) Total segment income (loss) 49,090 984 (41,412 ) General and administrative expenses (3) (32,961 ) (4,530 ) (41,038 ) Interest expense (3) (41,816 ) (3,470 ) (71,059 ) Gain on early extinguishment of debt (3) — — 26,498 Gain (loss) on asset sales and disposal (3) 25 5 (551 ) Reorganization items, net (3) — (353 ) (16,614 ) Other income (loss) (3) (925 ) — (3,063 ) Income tax (provision) benefit (3) 11,503 — — Net loss $ (15,084 ) $ (7,364 ) $ (147,239 ) Reconciliation of segment revenues to total revenues: Gas and oil production (1) $ 197,855 $ 15,182 $ 105,829 Drilling partnership management 17,387 2,074 24,446 Total revenues $ 215,242 $ 17,256 $ 130,275 Capital expenditures: Gas and oil production $ 36,191 $ 5,464 $ 22,684 Drilling partnership management 521 (115 ) 2,046 Corporate and other 527 18 164 Total capital expenditures $ 37,239 $ 5,367 $ 24,894 (1) Includes gain (loss) on mark-to-market derivatives. The Predecessor period from January 1, 2016 through August 31, 2016 includes a $23.2 million loss on mark-to-market derivatives related to increases in commodity future prices relative to our commodity fixed price swaps. (2) Includes revenues and expenses from our Drilling Partnership management activities, including well construction and completion, well services, gathering and processing, administration and oversight that do not meet the quantitative threshold for reporting individual segment information. (3) General and administrative expenses, interest expense, gain on early extinguishment of debt, gain (loss) on asset sales and disposal, reorganization items, net,, other income (loss) and income tax (provision) benefit have not been allocated to reportable segments as it would be impracticable to reasonably do so for the periods presented. September 30, 2017 December 31, 2016 Balance sheet: Total assets: Gas and oil production $ 556,607 $ 703,243 Drilling partnership management 5,476 11,786 Corporate and other (1) 43,342 44,129 Assets held for sale — 122,676 Total assets $ 605,425 $ 881,834 (1) Corporate and other primarily consists of cash and cash equivalents, advances to affiliates and other assets, net, which have not been allocated to reportable segments.

Organization (Narrative) (Detai

Organization (Narrative) (Details) - USD ($)	Sep. 02, 2016	Sep. 30, 2017	Sep. 01, 2016
Organization [Line Items]
Common shares issued		5,427,547
Common shares outstanding		5,427,547
First Lien Credit Facility
Organization [Line Items]
Line of credit facility maximum borrowing capacity			$ 440,000,000
Revolving Credit Facility Conforming Tranche | First Lien Credit Facility
Organization [Line Items]
Line of credit facility maximum borrowing capacity			410,000,000
Revolving Credit Facility Nonconforming Tranche | First Lien Credit Facility
Organization [Line Items]
Line of credit facility maximum borrowing capacity			$ 30,000,000
Minimum
Organization [Line Items]
Percentage of common stock voting rights			67.00%
Titan Energy Management, LLC | Series A Preferred Members' Equity
Organization [Line Items]
Percentage of preferred share		2.00%
Atlas Resource Partners, L.P.
Organization [Line Items]
Percentage of senior notes outstanding			100.00%
Senior Notes			$ 668,000,000
Percentage of common equity interest			90.00%
Atlas Resource Partners, L.P. | Second Lien Term Loan
Organization [Line Items]
Line of credit facility maximum borrowing capacity			$ 252,500,000
Percentage of common equity interest	10.00%
Atlas Resource Partners, L.P. | First Lien Credit Facility
Organization [Line Items]
Line of credit facility maximum borrowing capacity			440,000,000
Atlas Resource Partners, L.P. | Revolving Credit Facility Conforming Tranche | First Lien Credit Facility
Organization [Line Items]
Line of credit facility maximum borrowing capacity			410,000,000
Atlas Resource Partners, L.P. | Revolving Credit Facility Nonconforming Tranche | First Lien Credit Facility
Organization [Line Items]
Line of credit facility maximum borrowing capacity			$ 30,000,000

Basis of Presentation and Sum27

Basis of Presentation and Summary of Significant Accounting Policies (Narrative) (Details)

Nov. 06, 2017USD ($)

Sep. 29, 2017USD ($)

Aug. 07, 2017USD ($)

Jun. 30, 2017USD ($)

Jun. 30, 2017USD ($)

Jun. 12, 2017USD ($)

May 04, 2017USD ($)Wells

Sep. 02, 2016

May 12, 2016shares

Sep. 30, 2016USD ($)shares

Aug. 31, 2016USD ($)

Sep. 30, 2017USD ($)shares

Aug. 31, 2016USD ($)

Sep. 30, 2017USD ($)shares

Aug. 31, 2018USD ($)

Mar. 31, 2018

Dec. 31, 2017

Dec. 08, 2017USD ($)

Oct. 31, 2017USD ($)

Dec. 31, 2016USD ($)

Sep. 01, 2016USD ($)

Summary Of Significant Accounting Policies [Line Items]

Substantial Doubt about Going Concern, Conditions or Events

Since the Plan Effective Date, we have funded our operations through cash flows generated from our operations and cash on hand. We currently do not have the capacity to access additional liquidity from our First Lien Credit Facility and our ability to access public equity and debt markets may be limited. Our 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 continue to remain low in 2017. These lower commodity prices have negatively impacted our revenues, earnings and cash flows, which has negatively impacted our ability to remain in compliance with the covenants under our credit facilities. Sustained low commodity prices could have a material and adverse effect on our liquidity position. Even following the amendments described below, we continue to face liquidity issues and are currently considering, and are likely to make, changes to our capital structure to maintain sufficient liquidity, meet our debt obligations and manage and strengthen our balance sheet. If we are not able to enter into further amendments with our lenders prior to the expiration of the standstill period, we may be forced to seek further options as described below. We were not in compliance with certain of the financial covenants under our credit facilities as of December 31, 2016, as well as the requirement to deliver audited financial statements without a going concern qualification. As a result of the amendment referenced below, our financial covenants will not be tested again until the quarter ending December 31, 2017. We do not currently have sufficient liquidity to repay all of our outstanding indebtedness, and as a result, there is substantial doubt regarding our ability to continue as a going concern. We have classified $538.1 million of outstanding indebtedness under our credit facilities, which is net of $1.7 million of deferred financing costs, as current portion of long term debt, net within our condensed consolidated balance sheet as of September 30, 2017, based on the occurrence of the event of default, the lenders under our credit facilities, as applicable, could elect to declare all amounts outstanding immediately due and payable and the lenders could terminate all commitments to extend further credit.

Deferred financing costs

$ 1,711,000

$ 1,711,000

$ 2,021,000

Description of assets held for sale

Assets are classified as held for sale when we commit to a plan to sell the assets and there is reasonable certainty the sale will take place within one year.

U.S. Federal statutory tax rate

35.00%

Income tax provision (benefit)

$ 200,000

$ 11,500,000

Non-cash compensation expense

$ 68,000

$ 1,019,000

Share Based Compensation | Management Incentive Plan

Summary Of Significant Accounting Policies [Line Items]

Share based compensation shares changed to unrestricted | shares

91,710

91,710

Shares withheld for taxes | shares

42,251

57,562

Recognized adjustments related to tax withholding

$ 200,000

$ 300,000

Share based compensation shares granted and vested | shares

138,750

37,324

Texas

Summary Of Significant Accounting Policies [Line Items]

Effective tax rate

1.27%

0.74%

Successor

Summary Of Significant Accounting Policies [Line Items]

Income tax provision (benefit)

$ 200,000

$ 11,500,000

Predecessor

Summary Of Significant Accounting Policies [Line Items]

Non-cash compensation expense

$ 1,167,000

Predecessor | Phantom Units | General and Administrative Expense

Summary Of Significant Accounting Policies [Line Items]

Non-cash compensation expense

$ 800,000

Predecessor | Phantom Units | Board of Directors

Summary Of Significant Accounting Policies [Line Items]

Granted (in units) | shares

110,000

First Lien Credit Facility

Summary Of Significant Accounting Policies [Line Items]

Line of credit facility maximum borrowing capacity

$ 440,000,000

First Lien Credit Facility | Revolving Credit Facility Conforming Tranche

Summary Of Significant Accounting Policies [Line Items]

Line of credit facility maximum borrowing capacity

410,000,000

First Lien Credit Facility | Revolving Credit Facility Conforming Tranche | Subsequent Event

Summary Of Significant Accounting Policies [Line Items]

Line of credit facility maximum borrowing capacity

$ 228,700,000

$ 228,700,000

First Lien Credit Facility | Revolving Credit Facility Conforming Tranche | Scenario, Forecast

Summary Of Significant Accounting Policies [Line Items]

Line of credit facility maximum borrowing capacity

$ 150,000,000

$ 190,000,000

First Lien Credit Facility | Revolving Credit Facility Nonconforming Tranche

Summary Of Significant Accounting Policies [Line Items]

Line of credit facility maximum borrowing capacity

30,000,000

First Lien Credit Facility | Revolving Credit Facility Nonconforming Tranche | Subsequent Event

Summary Of Significant Accounting Policies [Line Items]

Line of credit facility maximum borrowing capacity

$ 30,000,000

$ 30,000,000

Line of credit facility, borrowing base maturity date

May 1, 2018

Second Lien Credit Facility

Summary Of Significant Accounting Policies [Line Items]

Line of credit facility maximum borrowing capacity

$ 252,500,000

Extension letter description

Pursuant to the Extension Letter, the Second Lien Credit Facility lenders agreed to extend the 180-day standstill period under the intercreditor agreement (during which the lenders under the Second Lien Credit Facility were prevented from pursuing remedies against the collateral securing the Company’s obligations under the Second Lien Credit Facility) by an additional 35 days from October 18, 2017 to November 22, 2017. In addition, the extension of the standstill period extends the waiver of certain defaults under the First Lien Credit Facility, which terminates 15 business days prior to the expiration of the standstill period.

Line of credit facility, borrowing base maturity date

Feb. 23, 2020

Appalachia and Marcellus

Summary Of Significant Accounting Policies [Line Items]

Sale of assets

$ 84,200,000

Number of oil and gas wells sold | Wells

8,400

Appalachia and Marcellus | First Lien Credit Facility

Summary Of Significant Accounting Policies [Line Items]

Sale of assets

$ 65,600,000

$ 65,600,000

Additional cash proceeds from sale of assets

$ 10,400,000

Rangely Field

Summary Of Significant Accounting Policies [Line Items]

Sale of assets

$ 103,500,000

Percentage of ownership interest sold

25.00%

Consideration for sale of assets

$ 105,000,000

Rangely Field | First Lien Credit Facility

Summary Of Significant Accounting Policies [Line Items]

Line of credit facility maximum borrowing capacity

$ 360,000,000

Raven Ridge Pipeline

Summary Of Significant Accounting Policies [Line Items]

Percentage of ownership interest sold

22.00%

Appalachia

Summary Of Significant Accounting Policies [Line Items]

Income tax provision (benefit)

(24,000)

$ 11,541,000

Appalachia | First Lien Credit Facility

Summary Of Significant Accounting Policies [Line Items]

Additional cash proceeds from sale of assets

$ 10,400,000

Credit Facilities

Summary Of Significant Accounting Policies [Line Items]

Outstanding indebtedness

538,100,000

538,100,000

Deferred financing costs

$ 1,700,000

$ 1,700,000

Minimum

Summary Of Significant Accounting Policies [Line Items]

Pro-rata share in Drilling Partnerships

10.00%

Minimum | Predecessor | Phantom Units

Summary Of Significant Accounting Policies [Line Items]

Vesting date

May 15, 2016

Minimum | First Lien Credit Facility

Summary Of Significant Accounting Policies [Line Items]

Percentage of commodity hedges covering

80.00%

80.00%

Minimum | First Lien Credit Facility | Scenario, Forecast

Summary Of Significant Accounting Policies [Line Items]

Percentage of commodity hedges covering

80.00%

50.00%

Maximum

Summary Of Significant Accounting Policies [Line Items]

Pro-rata share in Drilling Partnerships

30.00%

Maximum | Predecessor | Phantom Units

Summary Of Significant Accounting Policies [Line Items]

Vesting date

Aug. 31, 2016

Basis of Presentation and Sum28

Basis of Presentation and Summary of Significant Accounting Policies (Summary of Reorganization Items Net) (Details) - USD ($) $ in Thousands		1 Months Ended	2 Months Ended	8 Months Ended
		Sep. 30, 2016	Aug. 31, 2016	Aug. 31, 2016
Reorganizations [Abstract]
Total reorganization items, net	[1]	$ (353)
Predecessor
Reorganizations [Abstract]
Professional fees and other				$ (33,065)
Accelerated amortization of deferred financing costs				(9,565)
Net gain on reorganization adjustments				361,479
Net loss on fresh start adjustments				(335,463)
Total reorganization items, net	[1]		$ (16,614)	$ (16,614)
[1]	General and administrative expenses, interest expense, gain on early extinguishment of debt, gain (loss) on asset sales and disposal, reorganization items, net,, other income (loss) and income tax (provision) benefit have not been allocated to reportable segments as it would be impracticable to reasonably do so for the periods presented.

Basis of Presentation and Sum29

Basis of Presentation and Summary of Significant Accounting Policies (Schedule of Net Income (Loss) Reconciliation) (Details) - USD ($) $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended	8 Months Ended	9 Months Ended
	Sep. 30, 2016	Aug. 31, 2016	Sep. 30, 2017	Aug. 31, 2016	Sep. 30, 2017
Earnings Per Share Basic [Line Items]
Net loss from continuing operations	$ (7,364)		$ (19,706)		$ (15,084)
Net loss from continuing operations utilized in the calculation of net loss attributable to common shareholders per share	(7,217)		(19,312)		(14,782)
Net income (loss) from discontinued operations	(167)		2,156		20,945
Net income (loss) from discontinued operations utilized in the calculation of net income (loss) attributable to common shareholders per share	(163)		2,113		20,526
Predecessor
Earnings Per Share Basic [Line Items]
Net loss from continuing operations		$ (36,772)		$ (147,239)
Preferred limited partner dividends				(4,013)
Net loss from continuing operations utilized in the calculation of net loss attributable to common shareholders per share		(36,772)		(151,252)
Less: General partner’s interest in net loss from continuing operations		(736)		(3,025)
Net loss from continuing operations attributable to common limited partners		(36,036)		(148,227)
Net loss from continuing operations utilized in the calculation of net loss attributable to common limited partners per unit – Basic		(36,036)		(148,227)
Net loss from continuing operations utilized in the calculation of net loss attributable to common limited partners per unit – Diluted		(36,036)		(148,227)
Net income (loss) from discontinued operations		(11,852)		(30,191)
Net income (loss) from discontinued operations utilized in the calculation of net income (loss) attributable to common shareholders per share		(11,852)		(30,191)
Less: General partner’s interest in net loss from discontinued operations		(237)		(604)
Net loss from discontinued operations attributable to common limited partners		(11,615)		(29,587)
Net loss from discontinued operations utilized in the calculation of net loss attributable to common limited partners per unit – Basic		(11,615)		(29,587)
Net loss from discontinued operations utilized in the calculation of net loss attributable to common limited partners per unit – Diluted		$ (11,615)		$ (29,587)
Series A Preferred Members' Equity
Earnings Per Share Basic [Line Items]
Less: Series A Preferred member interest in loss from continuing operations	(147)		(394)		(302)
Less: Series A Preferred member interest in net income (loss) from discontinued operations	$ (4)		$ 43		$ 419

Basis of Presentation and Sum30

Basis of Presentation and Summary of Significant Accounting Policies (Reconciliation of Weighted Average Number Of Common Shares / Common Limited Partner Units) (Details) - shares shares in Thousands	1 Months Ended	2 Months Ended	3 Months Ended	8 Months Ended	9 Months Ended
	Sep. 30, 2016	Aug. 31, 2016	Sep. 30, 2017	Aug. 31, 2016	Sep. 30, 2017
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Weighted average number of common shares / common limited partner units - basic	5,139		5,208		5,186
Weighted average number of common shares / common limited partner units - diluted	5,139		5,208		5,186
Predecessor
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Weighted average number of common shares / common limited partner units - basic		104,366		102,912
Weighted average number of common shares / common limited partner units - diluted		104,366		102,912

Basis of Presentation and Sum31

Basis of Presentation and Summary of Significant Accounting Policies (Reconciliation of Weighted Average Number Of Common Shares / Common Limited Partner Units) (Parenthetical) (Details) - shares	1 Months Ended	2 Months Ended	3 Months Ended	8 Months Ended	9 Months Ended
	Sep. 30, 2016	Aug. 31, 2016	Sep. 30, 2017	Aug. 31, 2016	Sep. 30, 2017
Restricted Common Shares
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of basic weighted average number of common shares / diluted earnings attributable to common limited partners outstanding units			186,000		278,000
Restricted Common Shares | Successor
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of basic weighted average number of common shares / diluted earnings attributable to common limited partners outstanding units	278,000
Phantom Units | Predecessor
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of basic weighted average number of common shares / diluted earnings attributable to common limited partners outstanding units		247,000		274,000

Discontinued Operations and D32

Discontinued Operations and Divestitures (Narrative) (Details) - USD ($) $ in Thousands	Sep. 29, 2017	Aug. 07, 2017	Jun. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2017
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Net cash proceeds from sale of assets						$ 109,073
Loss on sale of asset				$ (5)		347
Appalachia and Marcellus | First Lien Credit Facility
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Net cash proceeds from sale of assets			$ 65,600
Additional cash proceeds from sale of assets	$ 10,400
Appalachia
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Impairment charges recognized in net income (loss) from discontinued operations						4,300
Appalachia | First Lien Credit Facility
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Additional cash proceeds from sale of assets	$ 10,400
Rangely
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Assets sale for net cash proceeds		$ 103,500
Impairment that recognized in loss on divesture						38,200
Loss on sale of asset					$ 5,200	$ 5,200

Discontinued Operations and D33

Discontinued Operations and Divestitures (Schedule of Major Classes of Line Items Included Within Net Income (Loss) and Major Classes of Assets and Liabilities from Discontinued Operations) (Details) - USD ($) $ in Thousands		1 Months Ended	2 Months Ended	3 Months Ended	8 Months Ended	9 Months Ended
		Sep. 30, 2016	Aug. 31, 2016	Sep. 30, 2017	Aug. 31, 2016	Sep. 30, 2017	Dec. 31, 2016
Costs and expenses:
Gain on sale of assets				$ 5,177		$ 43,369
Income tax provision (benefit)				200		11,500
Current assets:
Total current assets							$ 8,271
Total non-current assets							114,405
Current liabilities:
Total current liabilities							9,461
Total non-current liabilities							62,405
Appalachia
Revenues:
Gas and oil production		$ 1,197		288		21,213
Drilling partnership management		1,320				5,114
Gain (loss) on mark-to-market derivatives		750				4,955
Total revenues		3,267		288		31,282
Costs and expenses:
Gas and oil production		760		924		9,091
Drilling partnership management		1,074		597		5,824
Depreciation, depletion and amortization		869				4,842
General and administrative		395		298		4,378
Gain on sale of assets		(4)		(4,319)		(32,921)
Impairment on assets held for sale						4,272
Interest expense		340		115		2,769
Other (income) loss				541		541
Total costs and expenses		3,434		(1,844)		(1,204)
Income (loss) from discontinued operations before income taxes		(167)		2,132		32,486
Income tax provision (benefit)				(24)		11,541
Net income (loss) from discontinued operations		(167)		2,156		20,945
Current assets:
Accounts receivable							7,254
Prepaid expenses and other							1,017
Total current assets							8,271
Property, plant and equipment, net							113,956
Other assets							449
Total non-current assets							114,405
Total assets classified as held for sale							122,676
Current liabilities:
Accounts payable							2,516
Current portion of derivative liability							4,279
Accrued liabilities and other							2,666
Total current liabilities							9,461
Long-term derivative liability							1,407
Asset retirement obligations							60,316
Other long-term liabilities							682
Total non-current liabilities							62,405
Total liabilities classified as held for sale							$ 71,866
Appalachia | Predecessor
Revenues:
Gas and oil production			$ 2,917		$ 10,037
Drilling partnership management			3,621		12,100
Gain (loss) on mark-to-market derivatives			875		(667)
Total revenues			7,413		21,470
Costs and expenses:
Gas and oil production			1,454		6,244
Drilling partnership management			2,312		9,801
Depreciation, depletion and amortization			2,693		9,059
General and administrative			12,044		16,974
Gain on sale of assets			(50)		(72)
Interest expense			842		3,529
Other (income) loss			(30)		6,126
Total costs and expenses			19,265		51,661
Income (loss) from discontinued operations before income taxes			(11,852)		(30,191)
Net income (loss) from discontinued operations			(11,852)		(30,191)
Rangely
Costs and expenses:
Gain on sale of assets						38,200
Income (loss) from discontinued operations before income taxes	[1]	$ 532		$ (4,292)		$ (38,379)
Rangely | Predecessor
Costs and expenses:
Income (loss) from discontinued operations before income taxes	[1]		$ 1,253		$ 2,011
[1]	Income (loss) before income taxes reflects gas and oil production revenues less gas and oil production expenses, general and administrative expenses, depletion, depreciation, and amortization expenses for all periods presented. The Successor three and nine months ended September 30, 2017 include $5.2 million of loss on asset sale resulting from the closing of the Rangely Asset sale. The Successor nine months ended September 30, 2017 also includes $38.2 million loss on divestiture resulting from the carrying value of the Rangely Assets exceeding the fair value less costs to sell as disclosed above.

Discontinued Operations and D34

Discontinued Operations and Divestitures (Schedule of Major Classes of Line Items Included Within Net Income (Loss) and Major Classes of Assets and Liabilities from Discontinued Operations) (Parenthetical) (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2017
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Loss on sale of asset	$ (5)		$ 347
Loss on divestiture		$ 5,177	43,369
Rangely
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Loss on sale of asset		$ 5,200	5,200
Loss on divestiture			$ 38,200

Property, Plant and Equipment35

Property, Plant and Equipment (Summary of Property, Plant and Equipment) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Property Plant And Equipment [Abstract]
Proved properties	$ 519,147	$ 608,901
Unproved properties	52,767	73,057
Support equipment and other	8,690	8,081
Total natural gas and oil properties	580,604	690,039
Less – accumulated depreciation, depletion and amortization	(53,207)	(19,270)
Total property, plant and equipment, net	$ 527,397	$ 670,769

Property, Plant and Equipment36

Property, Plant and Equipment (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended	2 Months Ended	3 Months Ended	8 Months Ended	9 Months Ended
	Sep. 30, 2016	Aug. 31, 2016	Sep. 30, 2017	Aug. 31, 2016	Sep. 30, 2017
Property Plant And Equipment [Line Items]
Non-cash investing activities capital expenditures, reflected within the changes in accounts payable and accrued liabilities	$ 3.5				$ 0.7
Weighted Average Interest Rate Used To Capitalize Interest	7.60%		9.50%		8.40%
Interest Costs Capitalized	$ 0.7		$ 0.2		$ 0.4
Depreciation depletion and amortization
Property Plant And Equipment [Line Items]
Accretion expense in asset retirement obligations	$ 0.5		$ 0.4		$ 1.1
Predecessor
Property Plant And Equipment [Line Items]
Non-cash investing activities capital expenditures, reflected within the changes in accounts payable and accrued liabilities				$ 19.6
Weighted Average Interest Rate Used To Capitalize Interest		6.00%		6.50%
Interest Costs Capitalized		$ 1.7		$ 6.5
Predecessor | Depreciation depletion and amortization
Property Plant And Equipment [Line Items]
Accretion expense in asset retirement obligations		$ 1.3		$ 4.6

Debt (Schedule of Total Debt Ou

Debt (Schedule of Total Debt Outstanding) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Deferred financing costs, net of accumulated amortization of $686 and $172, respectively	$ (1,711)	$ (2,021)
Total debt, net	538,085	694,810
Less current maturities	(538,085)	(694,810)
First Lien Credit Facility
Debt Instrument [Line Items]
Credit Facility	256,273	435,809
Second Lien Credit Facility
Debt Instrument [Line Items]
Credit Facility	$ 283,523	$ 261,022

Debt (Schedule of Total Debt 38

Debt (Schedule of Total Debt Outstanding) (Parenthetical) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Debt Disclosure [Abstract]
Accumulated amortization	$ 686	$ 172

Debt (Narrative) (Details)

Debt (Narrative) (Details) - USD ($)	1 Months Ended	2 Months Ended	3 Months Ended	8 Months Ended	9 Months Ended
	Sep. 30, 2016	Aug. 31, 2016	Sep. 30, 2017	Aug. 31, 2016	Sep. 30, 2017
Debt Instrument [Line Items]
Cash Payments For Interest On Debt	$ 500,000		$ 7,300,000		$ 21,200,000
Predecessor
Debt Instrument [Line Items]
Cash Payments For Interest On Debt		$ 0		$ 53,700,000

Debt (First Lien Credit Facilit

Debt (First Lien Credit Facility) (Details) - USD ($)

Sep. 29, 2017

Aug. 07, 2017

Jun. 30, 2017

Jun. 30, 2017

May 04, 2017

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Sep. 30, 2017

Aug. 31, 2018

Dec. 31, 2017

Dec. 08, 2017

Nov. 06, 2017

Nov. 01, 2017

Oct. 31, 2017

Oct. 01, 2017

Aug. 31, 2017

Sep. 01, 2016

Appalachia and Marcellus

Line Of Credit Facility [Line Items]

Sale of assets

$ 84,200,000

Rangely

Line Of Credit Facility [Line Items]

Sale of assets

$ 103,500,000

First Lien Credit Facility

Line Of Credit Facility [Line Items]

Line of credit facility maximum borrowing capacity

$ 440,000,000

Fee on the unused portion of the borrowing base

0.50%

Line of credit facility, weighted average interest rate

5.20%

Line of credit facility interest rate description

Borrowings bear interest at our election at either LIBOR plus an applicable margin between 3.00% and 4.00% per annum or the “alternate base rate” plus an applicable margin between 2.00% and 3.00% per annum, which fluctuates based on utilization. We are also required to pay a fee of 0.50% per annum on the unused portion of the borrowing base. At September 30, 2017, the weighted average interest rate on outstanding borrowings under the First Lien Credit Facility was 5.0XX%.

First Lien Credit Facility | Appalachia and Marcellus

Line Of Credit Facility [Line Items]

Sale of assets

$ 65,600,000

$ 65,600,000

Additional cash proceeds from sale of assets

$ 10,400,000

First Lien Credit Facility | Rangely

Line Of Credit Facility [Line Items]

Line of credit facility maximum borrowing capacity

$ 360,000,000

First Lien Credit Facility | Minimum

Line Of Credit Facility [Line Items]

Percentage of commodity hedges covering

80.00%

First Lien Credit Facility | Minimum | Scenario, Forecast

Line Of Credit Facility [Line Items]

Percentage of commodity hedges covering

80.00%

50.00%

First Lien Credit Facility | London Interbank Offered Rate (LIBOR) | Minimum

Line Of Credit Facility [Line Items]

Applicable margin rate

3.00%

First Lien Credit Facility | London Interbank Offered Rate (LIBOR) | Maximum

Line Of Credit Facility [Line Items]

Applicable margin rate

4.00%

First Lien Credit Facility | Alternate Base Rate | Minimum

Line Of Credit Facility [Line Items]

Applicable margin rate

2.00%

First Lien Credit Facility | Alternate Base Rate | Maximum

Line Of Credit Facility [Line Items]

Applicable margin rate

3.00%

First Lien Credit Facility | Revolving Credit Facility Conforming Tranche

Line Of Credit Facility [Line Items]

Line of credit facility maximum borrowing capacity

410,000,000

First Lien Credit Facility | Revolving Credit Facility Conforming Tranche | Subsequent Event

Line Of Credit Facility [Line Items]

Line of credit facility maximum borrowing capacity

$ 228,700,000

$ 228,700,000

First Lien Credit Facility | Revolving Credit Facility Conforming Tranche | Scenario, Forecast

Line Of Credit Facility [Line Items]

Line of credit facility maximum borrowing capacity

$ 150,000,000

$ 190,000,000

First Lien Credit Facility | Revolving Credit Facility Nonconforming Tranche

Line Of Credit Facility [Line Items]

Line of credit facility maximum borrowing capacity

$ 30,000,000

First Lien Credit Facility | Revolving Credit Facility Nonconforming Tranche | Subsequent Event

Line Of Credit Facility [Line Items]

Line of credit facility maximum borrowing capacity

$ 30,000,000

$ 30,000,000

First Lien Facility Amendment

Line Of Credit Facility [Line Items]

Lenders’ waivers description

The First Lien Credit Facility lenders’ waivers were subject to revocation in certain circumstances, including the exercise of remedies by junior lenders (including pursuant to our second lien credit facility), the failure to extend the 180-day standstill period under the intercreditor agreement at least 15 business days prior to its expiration, and the occurrence of additional events of default under the First Lien Credit Facility.

First Lien Facility Amendment | Maximum | Scenario, Forecast

Line Of Credit Facility [Line Items]

Total Debt to EBITDA

5.50%

5.50%

5.50%

5.50%

Ratio of First Lien Debt to EBITDA

4.00%

4.00%

4.00%

4.00%

First Lien Facility Amendment | Maximum | After December 31, 2018 (Thereafter)

Line Of Credit Facility [Line Items]

Total Debt to EBITDA

5.00%

Ratio of First Lien Debt to EBITDA

3.50%

First Lien Facility Amendment | Revolving Credit Facility Conforming Tranche

Line Of Credit Facility [Line Items]

Line of credit facility maximum borrowing capacity

$ 410,000,000

$ 330,000,000

First Lien Facility Amendment | Revolving Credit Facility Conforming Tranche | Subsequent Event

Line Of Credit Facility [Line Items]

Line of credit facility maximum borrowing capacity

$ 190,000,000

First Lien Facility Amendment | Revolving Credit Facility Nonconforming Tranche

Line Of Credit Facility [Line Items]

Line of credit facility maximum borrowing capacity

$ 30,000,000

First Lien Facility Amendment | Revolving Credit Facility Nonconforming Tranche | Subsequent Event

Line Of Credit Facility [Line Items]

Line of credit facility maximum borrowing capacity

$ 10,000,000

Debt (Second Lien Credit Facili

Debt (Second Lien Credit Facility) (Details) - Second Lien Credit Facility - USD ($)	Apr. 21, 2017	Sep. 02, 2016	Sep. 30, 2017	Sep. 01, 2016
Line Of Credit Facility [Line Items]
Line of credit facility maximum borrowing capacity				$ 252,500,000
Line of Credit Facility, Expiration Date		Feb. 23, 2020
Percentage of interest expense paid in cash				2.00%
Variable interest rate, period		15 months
Delivery notice period	180 days
Extension letter description			Pursuant to the Extension Letter, the Second Lien Credit Facility lenders agreed to extend the 180-day standstill period under the intercreditor agreement (during which the lenders under the Second Lien Credit Facility were prevented from pursuing remedies against the collateral securing the Company’s obligations under the Second Lien Credit Facility) by an additional 35 days from October 18, 2017 to November 22, 2017. In addition, the extension of the standstill period extends the waiver of certain defaults under the First Lien Credit Facility, which terminates 15 business days prior to the expiration of the standstill period.
Prior to February 23, 2017
Line Of Credit Facility [Line Items]
Percentage of principal amount prepaid		4.50%
After February 23, 2017 and Prior to February 23, 2018
Line Of Credit Facility [Line Items]
Percentage of principal amount prepaid		2.25%
After February 23, 2018
Line Of Credit Facility [Line Items]
Percentage of principal amount prepaid		0.00%
London Interbank Offered Rate (LIBOR)
Line Of Credit Facility [Line Items]
Applicable margin rate		9.00%
Maximum
Line Of Credit Facility [Line Items]
Interest payable date			May 1, 2017
Maximum | Prior to December 31, 2017
Line Of Credit Facility [Line Items]
Leverage ratio			5.50%
Maximum | December 31, 2017 Thereafter
Line Of Credit Facility [Line Items]
Leverage ratio			5.00%
Minimum
Line Of Credit Facility [Line Items]
EBITDA to interest expense ratio			2.50%
Required Current Assets to Current Liabilities ratio			1.00%

Derivative Instruments (Narrati

Derivative Instruments (Narrative) (Details) - USD ($)	Jul. 27, 2016	Aug. 31, 2016	Sep. 30, 2017
Derivative Instruments Gain Loss [Line Items]
Repayment of outstanding borrowings			$ 179,536,000
Predecessor
Derivative Instruments Gain Loss [Line Items]
Repayment of outstanding borrowings		$ 291,191,000
Predecessor | Predecessor's First Lien Credit Facility
Derivative Instruments Gain Loss [Line Items]
Repayment of outstanding borrowings	$ 233,500,000

Derivative Instruments (Summary

Derivative Instruments (Summary of Cash Settlement on Commodity Derivatives and Presentation in Partnership's Condensed Consolidated Statements of Operations) (Details) - USD ($) $ in Thousands		1 Months Ended		2 Months Ended	3 Months Ended	8 Months Ended	9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Aug. 31, 2016	Sep. 30, 2017	Aug. 31, 2016	Sep. 30, 2017
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Portion of settlements attributable to subsequent mark to market gains (losses)	[1]	$ 191			$ 1,666		$ (2,309)
Total cash settlements on commodity derivative contracts	[1]	191			1,666		(2,309)
Gains (losses) recognized on cash settlement	[2]	(43)			195		20,409
Gains (losses) recognized on open derivative contracts	[2]	(2,036)			(4,263)		16,516
Gains (losses) on mark-to-market derivatives		$ (2,079)	$ (2,079)		$ (4,068)		$ 36,925
Predecessor
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets	[1],[3]			$ 1,461		$ 10,387
Portion of settlements attributable to subsequent mark to market gains (losses)	[1]			3,440		80,604
Total cash settlements on commodity derivative contracts	[1]			4,901		90,991
Gains (losses) recognized on cash settlement	[2]			9,381		(9,444)
Gains (losses) recognized on open derivative contracts	[2]			(7,028)		(13,804)
Gains (losses) on mark-to-market derivatives				$ 2,353		$ (23,248)
[1]	The Predecessor periods presented exclude the effects of the $214.9 million and the $20.4 million allocated to discontinued operations (see Note 3), net of $8.2 million in hedge monetization fees, paid directly to the First Lien Credit Facility lenders upon the sale of substantially all of our Predecessor’s commodity hedge positions on July 25, 2016 and July 26, 2016. The $8.2 million in hedge monetization fees was not allocated to discontinued operations as this was recorded in reorganization items, net on the condensed consolidated statements of operations.
[2]	Recognized in gain (loss) on mark-to-market derivatives.
[3]	Recognized in gas and oil production revenue.

Derivative Instruments (Summa44

Derivative Instruments (Summary of Cash Settlement on Commodity Derivatives and Presentation in Partnership's Condensed Consolidated Statements of Operations) (Parenthetical) (Details) - Predecessor - First Lien Credit Facility $ in Millions	Jul. 27, 2016USD ($)
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Effect of hedge monetization fees paid	$ 214.9
Net of hedge monetization fees paid	8.2
Discontinued Operations
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Effect of hedge monetization fees paid	$ 20.4

Derivative Instruments (Fair Va

Derivative Instruments (Fair Values of the Partnership's Derivative Instruments Table) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets	$ 2,206	$ 684
Gross Amounts Recognized, Liabilities	(6,699)	(44,411)
Current portion of derivative liabilities
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Liabilities	(5,635)	(30,526)
Gross Amounts Offset, Liabilities	2,006	7
Net Amount Presented, Liabilities	(3,629)	(30,519)
Long-term portion of derivative liabilities
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Liabilities	(1,064)	(13,885)
Gross Amounts Offset, Liabilities	168	677
Net Amount Presented, Liabilities	(896)	(13,208)
Total derivative liabilities
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Liabilities	(6,699)	(44,411)
Gross Amounts Offset, Liabilities	2,174	684
Net Amount Presented, Liabilities	(4,525)	(43,727)
Current portion of derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets	2,038	7
Gross Amounts Offset, Assets	(2,006)	(7)
Net Amount Presented, Assets	32
Long-term portion of derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets	168	677
Gross Amounts Offset, Assets	(168)	(677)
Total derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets	2,206	684
Gross Amounts Offset, Assets	(2,174)	$ (684)
Net Amount Presented, Assets	$ 32

Derivative Instruments (Commodi

Derivative Instruments (Commodity Derivative Instruments by Type Table) (Details) $ in Thousands	Sep. 30, 2017USD ($)MMBTU$ / MMBTU
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	$ (4,493)
Natural Gas - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	(2,765)
Crude Oil - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	$ (1,728)
Designated as Hedging Instrument | Natural Gas - Fixed Price Swaps Production Period Ending December 31, 2017
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	12,919,900	[1],[2]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	3.140	[1],[3]
Fair Value Asset / (Liability)	$ 693	[1],[3]
Designated as Hedging Instrument | Natural Gas - Fixed Price Swaps Production Period Ending December 31, 2018
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	43,947,300	[2]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	2.959	[3]
Fair Value Asset / (Liability)	$ (3,458)	[3]
Designated as Hedging Instrument | Crude Oil - Fixed Price Swaps Production Period Ending December 31, 2017
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	196,500	[1],[2]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	47.441	[1],[3]
Fair Value Asset / (Liability)	$ (766)	[1],[3]
Designated as Hedging Instrument | Crude Oil - Fixed Price Swaps Production Period Ending December 31, 2018
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	588,500	[2]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	50.286	[3]
Fair Value Asset / (Liability)	$ (936)	[3]
Designated as Hedging Instrument | Crude Oil - Fixed Price Swaps Production Period Ending December 31, 2019
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	73,000	[2]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	50.630	[3]
Fair Value Asset / (Liability)	$ (26)	[3]
[1]	The production volumes for 2017 include the remaining three months of 2017 beginning October 1, 2017.
[2]	Volumes for natural gas are stated in million British Thermal Units. Volumes for crude oil are stated in barrels.
[3]	Fair value for natural gas fixed price swaps are based on forward NYMEX natural gas prices, as applicable. Fair value of crude oil fixed price swaps are based on forward West Texas Intermediate (“WTI”) index crude oil prices, as applicable.

Fair Value of Financial Instr47

Fair Value of Financial Instruments (Schedule of Financial Instruments at Fair Value) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Fair Value Option Qualitative Disclosures Related To Election [Line Items]
Assets, gross	$ 2,206	$ 684
Liabilities, gross	(6,699)	(44,411)
Total derivatives, fair value, net	(4,493)	(43,727)
Level 2
Fair Value Option Qualitative Disclosures Related To Election [Line Items]
Assets, gross	2,206	684
Liabilities, gross	(6,699)	(44,411)
Total derivatives, fair value, net	(4,493)	(43,727)
Commodity Swaps
Fair Value Option Qualitative Disclosures Related To Election [Line Items]
Assets, gross	2,206	684
Liabilities, gross	(6,699)	(44,411)
Commodity Swaps | Level 2
Fair Value Option Qualitative Disclosures Related To Election [Line Items]
Assets, gross	2,206	684
Liabilities, gross	$ (6,699)	$ (44,411)

Fair Value of Financial Instr48

Fair Value of Financial Instruments - Additional Information (Details) $ in Millions	Sep. 30, 2017USD ($)
First and Second Lien Credit Facility
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Long-term debt, carrying amount	$ 539.8

Certain Relationships and Rel49

Certain Relationships and Related Party Transactions (Narrative) (Details) - USD ($)	2 Months Ended	8 Months Ended
	Aug. 31, 2016	Aug. 31, 2016	Sep. 30, 2017	Dec. 31, 2016	Jun. 30, 2016	Mar. 31, 2016
Related Party Transaction [Line Items]
Advances from affiliates			$ 1,800,000
Non-current advances to affiliates			15,100,000
Accrued well drilling and completion costs			1,959,000	$ 4,933,000
Predecessor
Related Party Transaction [Line Items]
Provision for losses on Drilling Partnership receivables	$ 10,900,000	$ 10,900,000
ATLS
Related Party Transaction [Line Items]
Advances from affiliates			1,800,000
Non-current advances to affiliates			15,100,000
Net current receivables from affiliate				3,300,000
Relationship with Drilling Partnerships
Related Party Transaction [Line Items]
Accounts receivable			100,000	100,000
Accounts payable			3,200,000	5,600,000
Relationship with Drilling Partnerships | Predecessor
Related Party Transaction [Line Items]
Capital raised from investors						$ 36,700
Accrued well drilling and completion costs						$ 13,300
Cash transferred to partners					$ 3,800
Payments to acquire oil and gas properties	7,200	7,200
Asset retirement obligation	$ 12,400	12,400
Net income (loss) from discontinued operations		$ 6,100
Relationship with AGP
Related Party Transaction [Line Items]
Accounts receivable			$ 100,000	$ 800,000

Commitments and Contingencies (

Commitments and Contingencies (Details) - USD ($)	9 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
Long-term purchase commitment, amount	$ 2,800,000
Accrual for Environmental Loss Contingencies	$ 0	$ 0

Predecessor Cash Distributions

Predecessor Cash Distributions - Additional Information (Details) - Predecessor - USD ($) $ / shares in Units, $ in Millions	8 Months Ended	9 Months Ended
	Aug. 31, 2016	Sep. 30, 2017
Preferred Class D
Distribution Made To Limited Partner [Line Items]
Preferred Units Accrued Distributions	$ 3.4
Preferred Class E
Distribution Made To Limited Partner [Line Items]
Preferred Units Accrued Distributions	0.3
Common Limited Partners' Interests
Distribution Made To Limited Partner [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid	$ 5.1
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit	$ 0.0125
Class C Preferred Limited Partners
Distribution Made To Limited Partner [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid	$ 2.5
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit	$ 0.0125
Class A General Partner
Distribution Made To Limited Partner [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid	$ 0.2
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit	$ 0.0125
Class D Preferred Limited Partners | October 15, 2015 to April 14, 2016
Distribution Made To Limited Partner [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid	$ 4.4
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit	$ 0.5390625
Class E Preferred Limited Partners | October 15, 2015 to April 14, 2016
Distribution Made To Limited Partner [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid	$ 0.3
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit	$ 0.671875
Minimum
Distribution Made To Limited Partner [Line Items]
Percentage of Distributions in Excess of Targets		13.00%
Maximum
Distribution Made To Limited Partner [Line Items]
Percentage of Distributions in Excess of Targets		48.00%

Operating Segment Information52

Operating Segment Information (Narrative) (Details) - Segment	8 Months Ended	9 Months Ended
	Aug. 31, 2016	Sep. 30, 2017
Segment Reporting Information [Line Items]
Number of reportable operating segments		2
Predecessor
Segment Reporting Information [Line Items]
Number of reportable operating segments	3

Operating Segment Information53

Operating Segment Information (Operating Segment Data) (Details) - USD ($) $ in Thousands		1 Months Ended		2 Months Ended	3 Months Ended	8 Months Ended		9 Months Ended
		Sep. 30, 2016		Aug. 31, 2016	Sep. 30, 2017	Aug. 31, 2016		Sep. 30, 2017
Segment Reporting Information [Line Items]
Gas and oil production		$ 17,261			$ 47,424			$ 160,930
Drilling partnership management		2,074			1,997			17,387
Gas and oil production costs		(9,854)			(21,633)			(74,355)
Drilling partnership management expenses		(1,266)			(248)			(10,026)
Depreciation, depletion and amortization		(5,152)			(11,934)			(38,402)
Loss on divestiture					(5,177)			(43,369)
Segment income (loss)		984			6,361			49,090
Gas And Oil Production
Segment Reporting Information [Line Items]
Gas and oil production	[1]	15,182			43,356			197,855
Gas and oil production costs		(9,854)			(21,633)			(74,355)
Depreciation, depletion and amortization		(4,882)			(11,646)			(37,455)
Loss on divestiture					(5,177)			(43,369)
Segment income (loss)		446	[1]		4,900			42,676	[1]
Drilling Partnership Management
Segment Reporting Information [Line Items]
Drilling partnership management	[2]	2,074			1,997			17,387
Drilling partnership management expenses	[2]	(1,266)			(248)			(10,026)
Depreciation, depletion and amortization	[2]	(270)			(288)			(947)
Segment income (loss)	[2]	$ 538			$ 1,461			$ 6,414
Predecessor
Segment Reporting Information [Line Items]
Gas and oil production				$ 36,290		$ 129,077
Drilling partnership management				18,778		24,446
Gas and oil production costs				(18,577)		(80,988)
Drilling partnership management expenses				(16,121)		(17,427)
Depreciation, depletion and amortization				(20,585)		(73,272)
Segment income (loss)				2,138		(41,412)
Predecessor | Gas And Oil Production
Segment Reporting Information [Line Items]
Gas and oil production	[1]			38,643		105,829
Gas and oil production costs				(18,577)		(80,988)
Depreciation, depletion and amortization				(14,723)		(62,142)
Segment income (loss)				5,343		(37,301)	[1]
Predecessor | Drilling Partnership Management
Segment Reporting Information [Line Items]
Drilling partnership management	[2]			18,778		24,446
Drilling partnership management expenses	[2]			(16,121)		(17,427)
Depreciation, depletion and amortization	[2]			(5,862)		(11,130)
Segment income (loss)	[2]			$ (3,205)		$ (4,111)
[1]	Includes gain (loss) on mark-to-market derivatives. The Predecessor period from January 1, 2016 through August 31, 2016 includes a $23.2 million loss on mark-to-market derivatives related to increases in commodity future prices relative to our commodity fixed price swaps.
[2]	Includes revenues and expenses from our Drilling Partnership management activities, including well construction and completion, well services, gathering and processing, administration and oversight that do not meet the quantitative threshold for reporting individual segment information

Operating Segment Information54

Operating Segment Information (Reconciliation of Segment Income (loss) to Net Income (Details) - USD ($) $ in Thousands		1 Months Ended		2 Months Ended	3 Months Ended	8 Months Ended		9 Months Ended
		Sep. 30, 2016		Aug. 31, 2016	Sep. 30, 2017	Aug. 31, 2016		Sep. 30, 2017
Segment Reporting Information [Line Items]
Total segment income (loss)		$ 984			$ 6,361			$ 49,090
General and administrative expenses	[1]	(4,530)			(10,142)			(32,961)
Interest expense	[1]	(3,470)			(15,268)			(41,816)
Gain (loss) on asset sales and disposal	[1]	5			(82)			25
Reorganization items, net	[1]	(353)
Other income (loss)	[1]				(777)			(925)
Income tax (provision) benefit	[1]				202			11,503
Net loss from continuing operations		(7,364)			(19,706)			(15,084)
Predecessor
Segment Reporting Information [Line Items]
Total segment income (loss)				$ 2,138		$ (41,412)
General and administrative expenses	[1]			(5,128)		(41,038)
Interest expense	[1]			(14,087)		(71,059)
Gain on early extinguishment of debt	[1]					26,498
Gain (loss) on asset sales and disposal	[1]			(18)		(551)
Reorganization items, net	[1]			(16,614)		(16,614)
Other income (loss)	[1]			(3,063)		(3,063)
Net loss from continuing operations				(36,772)		(147,239)
Gas And Oil Production
Segment Reporting Information [Line Items]
Total segment income (loss)		446	[2]		4,900			42,676	[2]
Gas And Oil Production | Predecessor
Segment Reporting Information [Line Items]
Total segment income (loss)				5,343		(37,301)	[2]
Drilling Partnership Management
Segment Reporting Information [Line Items]
Total segment income (loss)	[3]	$ 538			$ 1,461			$ 6,414
Drilling Partnership Management | Predecessor
Segment Reporting Information [Line Items]
Total segment income (loss)	[3]			$ (3,205)		$ (4,111)
[1]	General and administrative expenses, interest expense, gain on early extinguishment of debt, gain (loss) on asset sales and disposal, reorganization items, net,, other income (loss) and income tax (provision) benefit have not been allocated to reportable segments as it would be impracticable to reasonably do so for the periods presented.
[2]	Includes gain (loss) on mark-to-market derivatives. The Predecessor period from January 1, 2016 through August 31, 2016 includes a $23.2 million loss on mark-to-market derivatives related to increases in commodity future prices relative to our commodity fixed price swaps.
[3]	Includes revenues and expenses from our Drilling Partnership management activities, including well construction and completion, well services, gathering and processing, administration and oversight that do not meet the quantitative threshold for reporting individual segment information

Operating Segment Information55

Operating Segment Information (Reconciliation of Segment Revenues to Total Revenues) (Details) - USD ($) $ in Thousands		1 Months Ended	2 Months Ended	3 Months Ended	8 Months Ended	9 Months Ended
		Sep. 30, 2016	Aug. 31, 2016	Sep. 30, 2017	Aug. 31, 2016	Sep. 30, 2017
Segment Reporting Information [Line Items]
Gas and oil production		$ 17,261		$ 47,424		$ 160,930
Drilling partnership management		2,074		1,997		17,387
Total revenues		17,256		45,353		215,242
Predecessor
Segment Reporting Information [Line Items]
Gas and oil production			$ 36,290		$ 129,077
Drilling partnership management			18,778		24,446
Total revenues			57,421		130,275
Gas And Oil Production
Segment Reporting Information [Line Items]
Gas and oil production	[1]	15,182		43,356		197,855
Gas And Oil Production | Predecessor
Segment Reporting Information [Line Items]
Gas and oil production	[1]		38,643		105,829
Drilling Partnership Management
Segment Reporting Information [Line Items]
Drilling partnership management	[2]	$ 2,074		$ 1,997		$ 17,387
Drilling Partnership Management | Predecessor
Segment Reporting Information [Line Items]
Drilling partnership management	[2]		$ 18,778		$ 24,446
[1]	Includes gain (loss) on mark-to-market derivatives. The Predecessor period from January 1, 2016 through August 31, 2016 includes a $23.2 million loss on mark-to-market derivatives related to increases in commodity future prices relative to our commodity fixed price swaps.
[2]	Includes revenues and expenses from our Drilling Partnership management activities, including well construction and completion, well services, gathering and processing, administration and oversight that do not meet the quantitative threshold for reporting individual segment information

Operating Segment Information56

Operating Segment Information (Capital Expenditures) (Details) - USD ($) $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended	8 Months Ended	9 Months Ended
	Sep. 30, 2016	Aug. 31, 2016	Sep. 30, 2017	Aug. 31, 2016	Sep. 30, 2017
Segment Reporting Information [Line Items]
Capital expenditures	$ 5,367		$ 4,604		$ 37,239
Predecessor
Segment Reporting Information [Line Items]
Capital expenditures		$ 6,074		$ 24,894
Gas And Oil Production
Segment Reporting Information [Line Items]
Capital expenditures	5,464		4,279		36,191
Gas And Oil Production | Predecessor
Segment Reporting Information [Line Items]
Capital expenditures		5,529		22,684
Drilling Partnership Management
Segment Reporting Information [Line Items]
Capital expenditures	(115)				521
Drilling Partnership Management | Predecessor
Segment Reporting Information [Line Items]
Capital expenditures		496		2,046
Corporate and Other
Segment Reporting Information [Line Items]
Capital expenditures	$ 18		$ 325		$ 527
Corporate and Other | Predecessor
Segment Reporting Information [Line Items]
Capital expenditures		$ 49		$ 164

Operating Segment Information57

Operating Segment Information (Parenthetical) (Details) - USD ($) $ in Thousands	1 Months Ended		2 Months Ended	3 Months Ended	8 Months Ended	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Aug. 31, 2016	Sep. 30, 2017	Aug. 31, 2016	Sep. 30, 2017
Segment Reporting Information [Line Items]
Gains (losses) on mark to market derivatives	$ 2,079	$ 2,079		$ 4,068		$ (36,925)
Predecessor
Segment Reporting Information [Line Items]
Gains (losses) on mark to market derivatives			$ (2,353)		$ 23,248

Operating Segment Information58

Operating Segment Information (Balance Sheet) (Details) - USD ($) $ in Thousands		Sep. 30, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Total assets		$ 605,425	$ 881,834
Gas And Oil Production
Segment Reporting Information [Line Items]
Total assets		556,607	703,243
Drilling Partnership Management
Segment Reporting Information [Line Items]
Total assets		5,476	11,786
Corporate and Other
Segment Reporting Information [Line Items]
Total assets	[1]	$ 43,342	44,129
Assets Held for Sale
Segment Reporting Information [Line Items]
Total assets			$ 122,676
[1]	Corporate and other primarily consists of cash and cash equivalents, advances to affiliates and other assets, net, which have not been allocated to reportable segments.