EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Daniel C. Herz, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended March 31, 2017 of Titan Energy, LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ DANIEL C. HERZ

Daniel C. Herz

Chief Executive Officer of Titan Energy, LLC

May 15, 2017

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Jeffrey M. Slotterback, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended March 31, 2017 of Titan Energy, LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ JEFFREY M. SLOTTERBACK

Jeffrey M. Slotterback

Chief Financial Officer of Titan Energy, LLC

May 15, 2017

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Titan Energy, LLC (the “Company”) on Form 10-Q for the quarter ended March 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Daniel C. Herz, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ DANIEL C. HERZ

Daniel C. Herz

Chief Executive Officer of Titan Energy, LLC

May 15, 2017

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Titan Energy, LLC (the “Company”) on Form 10-Q for the quarter ended March 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jeffrey M. Slotterback, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ JEFFREY M. SLOTTERBACK

Jeffrey M. Slotterback

Chief Financial Officer of Titan Energy, LLC

May 15, 2017

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Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2017	May 11, 2017
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q1
Entity Registrant Name	Titan Energy, LLC
Entity Central Index Key	0001532750
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Trading Symbol	TTEN
Entity Common Stock, Units Outstanding		5,450,270

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 28,966	$ 24,446
Accounts receivable	27,786	33,728
Advances to affiliates	10,251	4,145
Subscriptions receivable		5,656
Prepaid expenses and other	19,408	18,125
Total current assets	86,411	86,100
Property, plant and equipment, net	780,930	784,723
Long-term derivative asset	1,227
Other assets, net	10,670	11,011
Total assets	879,238	881,834
Current liabilities:
Accounts payable	30,191	30,161
Liabilities associated with drilling contracts	5,787	10,656
Current portion of derivative liability	17,235	34,799
Accrued well drilling and completion costs	7,092	4,933
Accrued interest	1,643	1,789
Accrued liabilities	15,734	19,551
Current portion of long-term debt	701,602	694,810
Total current liabilities	779,284	796,699
Long-term derivative liability	163	14,615
Asset retirement obligations	77,159	75,347
Other long-term liabilities	2,238	2,114
Commitments and contingencies (Note 8)
Members’ Equity (Deficit):
Common shareholders’ equity (deficit)	20,001	(6,796)
Total members’ equity (deficit)	20,394	(6,941)
Total liabilities and members’ equity (deficit)	879,238	881,834
Preferred Series A
Members’ Equity (Deficit):
Series A Preferred member’s equity (deficit)	$ 393	$ (145)

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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Thousands, $ in Thousands		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Revenues:
Gas and oil production		$ 70,593
Drilling partnership management		10,050
Gain on mark-to-market derivatives		29,493
Total revenues		110,136
Costs and expenses:
Gas and oil production		29,987
Drilling partnership management		8,171
General and administrative		13,758
Depreciation, depletion and amortization		16,492
Total costs and expenses		68,408
Operating income		41,728
Interest expense	[1]	(13,985)
Other income (loss)	[1]	(654)
Income before income taxes		27,089
Income tax provision (benefit)	[1]	180
Net income		26,909
Net income attributable to common shareholders and Series A preferred member		26,909
Net income attributable to common limited partners and the general partner		26,371
Allocation of net income attributable to:
Series A Preferred member		538
Common shareholders		$ 26,371
Net income attributable to common shareholders per share / common limited partners per unit (Note 2):
Basic		$ 5.10
Diluted		$ 4.81
Weighted average shares / common limited partner units outstanding (Note 2):
Basic		5,170
Diluted		5,486
Predecessor
Revenues:
Gas and oil production			$ 48,492
Drilling partnership management			8,596
Gain on mark-to-market derivatives			46,120
Total revenues			103,208
Costs and expenses:
Gas and oil production			35,842
Drilling partnership management			6,283
General and administrative			17,077
Depreciation, depletion and amortization			30,045
Total costs and expenses			89,247
Operating income			13,961
Interest expense	[1]		(27,705)
Gain on early extinguishment of debt	[1]		26,498
Other income (loss)	[1]		9
Income before income taxes			12,763
Net income			12,763
Preferred member / limited partner dividends			(3,648)
Net income attributable to common limited partners and the general partner			9,115
Allocation of net income attributable to:
Common shareholders			9,115
Common limited partners’ interest			8,933
General partner’s interest			$ 182
Net income attributable to common shareholders per share / common limited partners per unit (Note 2):
Basic			$ 0.09
Diluted			$ 0.09
Weighted average shares / common limited partner units outstanding (Note 2):
Basic			102,403
Diluted			102,696

[1] General & administrative expenses, interest expense, gain on early extinguishment of debt, 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.

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME LOSS (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Net income	$ 26,909
Other comprehensive income (loss):
Comprehensive income attributable to common and preferred limited partners and the general partner	$ 26,909
Predecessor
Net income		$ 12,763
Other comprehensive income (loss):
Total other comprehensive income (loss)		(3,515)
Reclassification to net income of mark-to-market gains		(3,515)
Comprehensive income attributable to common and preferred limited partners and the general partner		$ 9,248

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CONDENSED CONSOLIDATED STATEMENT OF MEMBERS' EQUITY (DEFICIT) (Unaudited) - 3 months ended Mar. 31, 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	426	$ 426
Net income	26,909	26,371	$ 538
Balance at Mar. 31, 2017	$ 20,394	$ 20,001	$ 393
Balance (shares) at Mar. 31, 2017		5,447,787	1

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$ 26,909
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		16,492
Gain on derivatives		(23,158)
Other (income) loss		1,006
Non-cash compensation expense		426
Non-cash interest expense		6,654
Amortization of deferred financing costs and debt discount		655
Changes in operating assets and liabilities:
Accounts receivable, prepaid expenses and other		(6,875)
Accounts payable and accrued liabilities		(6,759)
Net cash provided by (used in) operating activities		15,350
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(10,444)
Net cash used in investing activities		(10,444)
CASH FLOWS FROM FINANCING ACTIVITIES:
Deferred financing costs, distribution equivalent rights and other		(386)
Net cash provided by (used in) financing activities		(386)
Net change in cash and cash equivalents		4,520
Cash and cash equivalents, beginning of period		24,446
Cash and cash equivalents, end of period		$ 28,966
Predecessor
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income			$ 12,763
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization			30,045
Gain on derivatives			(40,332)
Gain on extinguishment of debt	[1]		(26,498)
Other (income) loss			(9)
Non-cash compensation expense			(47)
Amortization of deferred financing costs and debt discount			4,101
Changes in operating assets and liabilities:
Accounts receivable, prepaid expenses and other			46,170
Accounts payable and accrued liabilities			(61,112)
Net cash provided by (used in) operating activities			(34,919)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures			(13,170)
Net cash used in investing activities			(13,170)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under revolving credit facility			135,000
Repayments under revolving credit facility			(55,000)
Senior note repurchases			(5,528)
Distributions paid to shareholders/unitholders			(8,246)
Net proceeds from issuance of common limited partner units			206
Deferred financing costs, distribution equivalent rights and other			(411)
Net cash provided by (used in) financing activities			66,021
Net change in cash and cash equivalents			17,932
Cash and cash equivalents, beginning of period			1,353
Cash and cash equivalents, end of period			$ 19,285

[1] General & administrative expenses, interest expense, gain on early extinguishment of debt, 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.

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Organization

3 Months Ended

Mar. 31, 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. We sponsor and manage tax-advantaged investment partnerships (the “Drilling Partnerships”), in which we coinvest, to finance a portion of our natural gas, crude oil and NGL production activities. 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 March 31, 2017, we had 5,447,787 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 4 – 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 4 – 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.

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Basis of Presentation and Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2017

Accounting Policies [Abstract]

Basis of Presentation and Summary of Significant Accounting Policies

NOTE 2 – BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

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 (“ASC 852”).

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 segment information on the condensed consolidated statement of operations and segment footnote disclosures.  See Note 10 for additional information.

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.

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

Our Predecessor had historically funded its operations, acquisitions and cash distributions primarily through cash flows generated from its operations, amounts available under its credit facilities and equity and debt offerings. Since the Plan Effective Date, we have funded our operations through cash flows generated from our operations. 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 have continued to decline and remain low in 2017. These lower commodity prices have negatively impacted our revenues, earnings and cash flows. Sustained low commodity prices could have a material and adverse effect on our liquidity position. In addition, challenges with our ability to raise capital through our Drilling Partnerships, either as a result of downturn in commodity prices or other difficulties affecting the fundraising channel, have negatively impacted our ability to remain in compliance with the covenants under our credit facilities.

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 $701.6 million of outstanding indebtedness under our credit facilities, which is net of $1.9 million of deferred financing costs, as current portion of long term debt, net within our condensed consolidated balance sheet as of March 31, 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 in an attempt to ameliorate some of our liquidity concerns. The amendment provides 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 4 – Debt for further information regarding the specific amended terms and provisions). In addition, we expect that we will sell a significant amount of non-core assets in the near future to comply with the requirements of our First Lien Credit Facility amendment and to attempt to enhance our liquidity.

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 are 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.  

Even following this amendment, 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.

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 are 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.

  We continually monitor the capital markets and our capital structure and may make changes to our capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, 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. In addition, we expect that we will sell a significant amount of non-core assets in the near future to comply with the requirements of our First Lien Credit Facility amendment and to attempt to enhance our liquidity.

We cannot assure you that we would be able to implement the above actions, if necessary, on commercially reasonable terms, or at all, in a manner that would 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 would allow us to meet our debt obligations and capital requirements.

Appalachia Divestiture

On May 4, 2017, we entered into a definitive agreement to sell our conventional Appalachia and Marcellus assets to Diversified Gas & Oil, PLC, for $84.2 million. The transaction includes 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”). In 2016, the Appalachian Assets generated approximately 30 MMcfepd of net production (92% gas, 8% liquids). We will retain our Utica Shale position, Indiana assets and West Virginia CBM assets in the region.  The transaction is subject to customary closing conditions, has an effective date of April 1, 2017 and is expected to close in June 2017. The net proceeds will be used to repay a portion of outstanding borrowings under our First Lien Credit Facility. The transaction will significantly improve our First Lien Credit Facility metrics and is expected to fulfill our borrowing base step down to $360 million, which is scheduled to occur on August 31, 2017.

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 and fair value of derivative instruments. 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.

Income Taxes

Our effective tax rate for the three months ended March 31, 2017 was 0.6%, which represents 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.

Successor’s Net Income Attributable to Common Shareholders Per Share

Our 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. Our 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.

The following table is a reconciliation of our 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 March 31,
	2017
Weighted average number of common shares - basic (1)		5,170
Add dilutive effect of share based awards at end of period		316
Weighted average number of common shares - diluted		5,486

(1) For the period presented, 278,000 restricted common shares outstanding were excluded from the basic weighted average number of common shares because they were not vested.

Predecessor’s Net Income Per Common Unit

The following is a reconciliation of net income allocated to our Predecessor’s common limited partners for purposes of calculating net income attributable to our Predecessor’s common limited partners per unit (in thousands, except unit data):

	Predecessor
	Three Months ended March 31, 2016
Net income	$	12,763
Preferred limited partner dividends		(3,648	)
Net income attributable to common limited partners and the general partner		9,115
Less: General partner’s interest		182
Net income attributable to common limited partners		8,933
Less: Net income attributable to participating securities – phantom units		25
Net income utilized in the calculation of net income attributable to common limited partners per unit – Basic		8,908
Plus: Convertible preferred limited partner dividends(1)		—
Net income utilized in the calculation of net loss attributable to common limited partners per unit – Diluted	$	8,908

(1) For the period presented, distributions on our Predecessor’s Class C convertible preferred units wereexcluded, because the inclusion of such preferred distributions would have been anti-dilutive.

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 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
	Three Months Ended March 31,
	2016
Weighted average number of common limited partner units—basic		102,403
Add effect of dilutive incentive awards		293
Add effect of dilutive convertible preferred limited partner units(1)		—
Weighted average number of common limited partner units—diluted		102,696

(1) For the period 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. The updated accounting guidance provides companies with alternative methods of adoption. We are evaluating the impact of this updated accounting guidance on our condensed consolidated financial statements, and based on the continuing evaluation of our revenue streams, this accounting guidance is not expected to have a material impact on our net income (loss). This accounting guidance will require that our revenue recognition policy disclosures include further detail regarding our performance obligations as to the nature, amount, timing, and estimates of revenue and cash flows generated from our contracts with customers. We are still in the process of determining whether or not we will use the retrospective method or the modified retrospective approach to implementation.

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Property, Plant and Equipment

3 Months Ended

Mar. 31, 2017

Property Plant And Equipment [Abstract]

Property, Plant and Equipment

NOTE 3 – PROPERTY, PLANT AND EQUIPMENT

The following is a summary of property, plant and equipment at the dates indicated (in thousands):

	March 31, 2017			December 31, 2016
Natural gas and oil properties:
Proved properties	$	728,139		$	717,839
Unproved properties		74,434			74,434
Support equipment and other		14,701			14,180
Total natural gas and oil properties		817,274			806,453
Less – accumulated depreciation, depletion and amortization		(36,344	)		(21,730	)
	$	780,930		$	784,723

During the Successor three months ended March 31, 2017 and the Predecessor three months ended March 31, 2016, we recognized $1.8 million and $18.7 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 months ended March 31, 2017 and the Predecessor three months ended March 31, 2016, was 7.7% and 6.7%, respectively. The aggregate amount of interest capitalized during the Successor three months ended March 31, 2017 and the Predecessor three months ended March 31, 2016 was $0.1 million and $2.4 million, respectively.

For the Successor three months ended March 31, 2017 and the Predecessor three months ended March 31, 2016, we recorded $1.9 million and $1.7 million, respectively, of accretion expense related to our and our Predecessor’s asset retirement obligations within depreciation, depletion and amortization in our and our Predecessor’s condensed consolidated statements of operations. For the Predecessor three months ended March 31, 2016, our Predecessor incurred liabilities of $2.8 million in asset retirement obligations in its condensed consolidated balance sheet due to the consolidation of some of its Drilling Partnerships.

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Debt

3 Months Ended

Mar. 31, 2017

Debt Disclosure [Abstract]

Debt

NOTE 4 – DEBT

Total debt consists of the following at the dates indicated (in thousands):

	March 31,			December 31,
	2017			2016
First Lien Credit Facility	$	435,809		$	435,809
Second Lien Credit Facility		267,676			261,022
Deferred financing costs, net of accumulated amortization of $335 and $172, respectively		(1,883	)		(2,021	)
Total debt, net		701,602			694,810
Less current maturities		(701,602	)		(694,810)
Total long-term debt, net	$	—		$	—

Cash Interest. Total cash payments for interest by us for the Successor three months ended March 31, 2017 and the Predecessor three months ended March 31, 2016, were $6.9 million and $41.2 million, respectively.

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:

• 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 March 31, 2017, the weighted average interest rate on outstanding borrowings under the First Lien Credit Facility was 5.0%.

• 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 (the “First Lien Credit Facility Amendment”) to the First Lien Credit Facility with Wells Fargo, as administrative agent, and the lenders party thereto. Pursuant to the First Lien Credit Facility 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 are 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 First Lien Credit Facility Amendment confirms the conforming and non-conforming tranches of the borrowing base at $410 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 $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 will be required to be reduced to $10 million by November 1, 2017. In addition, we will be 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.

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:

• 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 will use 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 are 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.

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Derivative Instruments

3 Months Ended

Mar. 31, 2017

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivative Instruments

NOTE 5 – 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.

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 March 31,
	2017			2016
Portion of settlements associated with gains (losses) previously recognized within accumulated other comprehensive income, net of prior year offsets(1)	$	—		$	3,515
Portion of settlements attributable to subsequent mark to market gains (losses)(2)	(3,749		)		45,193
Total cash settlements on commodity derivative contracts	$	(3,749	)	$	48,708
Gains recognized on cash settlement(2)	$	6,335		$	5,788
Gains recognized on open derivative contracts(2)	23,158				40,332
Gains on mark-to-market derivatives	$	29,493		$	46,120

(1) Recognized in gas and oil production revenue.

(2) 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 March 31, 2017	Gross Amounts Recognized			Gross Amounts Offset			Net Amount Presented
Current portion of derivative assets	$	632		$	(632	)	$	—
Long-term portion of derivative assets		3,200		(1,973		)		1,227
Total derivative assets	$	3,832		$	(2,605	)	$	1,227
Current portion of derivative liabilities	$	(17,867	)	$	632		$	(17,235	)
Long-term portion of derivative liabilities	(2,136		)	1,973			(163		)
Total derivative liabilities	$	(20,003	)	$	2,605		$	(17,398	)
Offsetting Derivatives as of December 31, 2016
Current portion of derivative assets	$	7		$	(7	)	$	—
Long-term portion of derivative assets		819			(819	)		—
Total derivative assets	$	826		$	(826	)	$	—
Current portion of derivative liabilities	$	(34,806	)	$	7		$	(34,799	)
Long-term portion of derivative liabilities		(15,434	)		819			(14,615	)
Total derivative liabilities	$	(50,240	)	$	826		$	(49,414	)

At March 31, 2017, we had the following commodity derivatives instruments:

Type	Production Period Ending December 31,	Volumes(1)		Average Fixed Price(2)		Fair Value Liability			Total Type
						(in thousands)(2)			(in thousands)
Natural Gas – Fixed Price Swaps	2017	38,759,800	(3)	$	3.140	$	(6,373	)
	2018	47,559,300		$	2.959	$	(3,437	)
									$	(9,810	)
Crude Oil – Fixed Price Swaps	2017	891,500	(3)	$	46.971	$	(4,121	)
	2018	1,011,100		$	49.544	$	(2,240	)
									$	(6,361	)
						Total net liabilities			$	(16,171	)

(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 nine months of 2017 beginning April 1, 2017.

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Fair Value of Financial Instruments

3 Months Ended

Mar. 31, 2017

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments

NOTE 6 – 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 March 31, 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 March 31, 2017	Level 1		Level 2			Level 3		Total
Assets, gross
Commodity swaps	$	—	$	3,832		$	—	$	3,832
Total derivative assets, gross		—	3,832				—	3,832
Liabilities, gross
Commodity swaps		—		(20,003	)		—		(20,003	)
Total derivative liabilities, gross		—		(20,003	)		—		(20,003	)
Total derivatives, fair value, net	$	—	$	(16,171	)	$	—	$	(16,171	)

Derivatives, Fair Value, as of December 31, 2016	Level 1		Level 2			Level 3		Total
Assets, gross
Commodity swaps	$	—	$	826		$	—	$	826
Total derivative assets, gross		—		826			—		826
Liabilities, gross
Commodity swaps	$	—		(50,240	)		—		(50,240	)
Total derivative liabilities, gross		—		(50,240	)		—		(50,240	)
Total derivatives, fair value, net		—	$	(49,414	)	$	—	$	(49,414	)

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 March 31, 2017, which consists of our First Lien Credit Facility and Second Lien Credit Facility, approximated carrying value of $703.5 million. At March 31, 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.

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Certain Relationships and Related Party Transactions

3 Months Ended

Mar. 31, 2017

Related Party Transactions [Abstract]

Certain Relationships and Related Party Transactions

NOTE 7 – 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 March 31, 2017 and December 31, 2016, we had receivables of $8.9 million and $3.3 million, respectively, from ATLS related to the timing of funding cash accounts related to general and administrative expenses, such as payroll and benefits, which was recorded in advances to/from 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.

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.

As of March 31, 2017 and December 31, 2016, we had trade receivables of $0.2 million and $0.3 million, respectively, from certain of the Drilling Partnerships, which were recorded in accounts receivable in our condensed consolidated balance sheets.  As of March 31, 2017 and December 31, 2016, we had trade payables of $5.0 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 March 31, 2017 and December 31, 2016, we had receivables of $1.3 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.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2017

Commitments And Contingencies Disclosure [Abstract]

Commitments and Contingencies

NOTE 8 – COMMITMENTS AND CONTINGENCIES

Drilling Partnership Commitments

As of March 31, 2017, we are committed to expend approximately $11.2 million, principally on 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 March 31, 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.

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Predecessor Cash Distributions

3 Months Ended

Mar. 31, 2017

Predecessor

Predecessor Cash Distributions

NOTE 9 – 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 three months ended March 31, 2016, our Predecessor paid three monthly cash distributions totaling approximately $3.8 million to its common limited partners ($0.0125 per unit per month); $1.9 million to its Preferred Class C limited partners ($0.17 per unit per month); and $0.1 million to its General Partner Class A holder ($0.0125 per unit per month).

During the Predecessor three months ended March 31, 2016, our Predecessor paid a distribution of $2.2 million to its Class D Preferred limited partners ($0.5390625 per unit) for the period October 15, 2015 through January 14, 2016. During the Predecessor three months ended March 31, 2016, our Predecessor paid a distribution of $0.2 million to its Class E Preferred limited partners ($0.671875 per unit) for the period October 15, 2015 through January 14, 2016.

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Operating Segment Information

3 Months Ended

Mar. 31, 2017

Segment Reporting [Abstract]

Operating Segment Information

NOTE 10 – 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 March 31,
	2017			2016
Gas and oil production: (1)
Gas and oil production revenues	$	100,086		$	94,612
Gas and oil production costs		(29,987	)		(35,842	)
Depreciation, depletion and amortization		(16,013	)		(26,580	)
Segment income	$	54,086		$	32,190
Drilling partnership management:(2)
Drilling partnership management revenues	$	10,050		$	8,596
Drilling partnership management expenses		(8,171	)		(6,283	)
Depreciation, depletion and amortization		(479	)		(3,465	)
Segment income (loss)	$	1,400		$	(1,152	)
Reconciliation of segment income (loss) to net loss:
Segment income (loss):
Gas and oil production	$	54,086		$	32,190
Drilling partnership management (2)	1,400				(1,152	)
Total segment income (loss)		55,486			31,038
General and administrative expenses(3)		(13,758	)		(17,077	)
Interest expense(3)		(13,985	)		(27,705	)
Gain on early extinguishment of debt(3)		—			26,498
Other income (loss)(3)	(654		)		9
Income tax (provision) benefit(3)		(180	)		—
Net income	$	26,909		$	12,763
Reconciliation of segment revenues to total revenues:
Gas and oil production	$	100,086		$	94,612
Drilling partnership management	10,050				8,596
Total revenues	$	110,136		$	103,208
Capital expenditures:
Gas and oil production	$	9,913		$	11,945
Drilling partnership management	420				1,134
Corporate and other	111				91
Total capital expenditures	$	10,444		$	13,170

(1) Includes gain on mark-to-market derivatives.

(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 & administrative expenses, interest expense, gain on early extinguishment of debt, 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.

	March 31, 2017		December 31, 2016
Balance sheet:
Total assets:
Gas and oil production	$	811,895	$	819,454
Drilling partnership management	12,540			18,182
Corporate and other(1)	54,803			44,198
Total assets	$	879,238	$	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.

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Subsequent Events

3 Months Ended

Mar. 31, 2017

Subsequent Events [Abstract]

Subsequent Events

NOTE 11 – SUBSEQUENT EVENTS

Appalachia Divestiture. On May 4, 2017, we entered into a definitive agreement to sell our conventional Appalachia and Marcellus assets to Diversified Gas & Oil, PLC, for $84.2 million. The net proceeds will be used to repay a portion of outstanding borrowings under our First Lien Credit Facility. The transaction will significantly improve our First Lien Credit Facility metrics and is expected to fulfill our borrowing base step down to $360 million, which is scheduled to occur on August 31, 2017 (see Note 2).

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

3 Months Ended

Mar. 31, 2017

Accounting Policies [Abstract]

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 (“ASC 852”).

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 segment information on the condensed consolidated statement of operations and segment footnote disclosures.  See Note 10 for additional information.

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.

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

Liquidity and Capital Resources

Our Predecessor had historically funded its operations, acquisitions and cash distributions primarily through cash flows generated from its operations, amounts available under its credit facilities and equity and debt offerings. Since the Plan Effective Date, we have funded our operations through cash flows generated from our operations. 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 have continued to decline and remain low in 2017. These lower commodity prices have negatively impacted our revenues, earnings and cash flows. Sustained low commodity prices could have a material and adverse effect on our liquidity position. In addition, challenges with our ability to raise capital through our Drilling Partnerships, either as a result of downturn in commodity prices or other difficulties affecting the fundraising channel, have negatively impacted our ability to remain in compliance with the covenants under our credit facilities.

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 $701.6 million of outstanding indebtedness under our credit facilities, which is net of $1.9 million of deferred financing costs, as current portion of long term debt, net within our condensed consolidated balance sheet as of March 31, 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 in an attempt to ameliorate some of our liquidity concerns. The amendment provides 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 4 – Debt for further information regarding the specific amended terms and provisions). In addition, we expect that we will sell a significant amount of non-core assets in the near future to comply with the requirements of our First Lien Credit Facility amendment and to attempt to enhance our liquidity.

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 are 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.  

Even following this amendment, 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.

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 are 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.

  We continually monitor the capital markets and our capital structure and may make changes to our capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, 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. In addition, we expect that we will sell a significant amount of non-core assets in the near future to comply with the requirements of our First Lien Credit Facility amendment and to attempt to enhance our liquidity.

We cannot assure you that we would be able to implement the above actions, if necessary, on commercially reasonable terms, or at all, in a manner that would 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 would allow us to meet our debt obligations and capital requirements.

Appalachia Divestiture

Appalachia Divestiture

On May 4, 2017, we entered into a definitive agreement to sell our conventional Appalachia and Marcellus assets to Diversified Gas & Oil, PLC, for $84.2 million. The transaction includes 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”). In 2016, the Appalachian Assets generated approximately 30 MMcfepd of net production (92% gas, 8% liquids). We will retain our Utica Shale position, Indiana assets and West Virginia CBM assets in the region.  The transaction is subject to customary closing conditions, has an effective date of April 1, 2017 and is expected to close in June 2017. The net proceeds will be used to repay a portion of outstanding borrowings under our First Lien Credit Facility. The transaction will significantly improve our First Lien Credit Facility metrics and is expected to fulfill our borrowing base step down to $360 million, which is scheduled to occur on August 31, 2017.

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 and fair value of derivative instruments. 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.

Income Taxes

Income Taxes

Our effective tax rate for the three months ended March 31, 2017 was 0.6%, which represents 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.

Successor’s Net Income Attributable to Common Shareholders Per Share

Successor’s Net Income Attributable to Common Shareholders Per Share

Our 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. Our 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.

The following table is a reconciliation of our 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 March 31,
	2017
Weighted average number of common shares - basic (1)		5,170
Add dilutive effect of share based awards at end of period		316
Weighted average number of common shares - diluted		5,486

(1) For the period presented, 278,000 restricted common shares outstanding were excluded from the basic weighted average number of common shares because they were not vested.

Predecessor's Net Income Per Common Unit

Predecessor’s Net Income Per Common Unit

The following is a reconciliation of net income allocated to our Predecessor’s common limited partners for purposes of calculating net income attributable to our Predecessor’s common limited partners per unit (in thousands, except unit data):

	Predecessor
	Three Months ended March 31, 2016
Net income	$	12,763
Preferred limited partner dividends		(3,648	)
Net income attributable to common limited partners and the general partner		9,115
Less: General partner’s interest		182
Net income attributable to common limited partners		8,933
Less: Net income attributable to participating securities – phantom units		25
Net income utilized in the calculation of net income attributable to common limited partners per unit – Basic		8,908
Plus: Convertible preferred limited partner dividends(1)		—
Net income utilized in the calculation of net loss attributable to common limited partners per unit – Diluted	$	8,908

(1) For the period presented, distributions on our Predecessor’s Class C convertible preferred units wereexcluded, because the inclusion of such preferred distributions would have been anti-dilutive.

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 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
	Three Months Ended March 31,
	2016
Weighted average number of common limited partner units—basic		102,403
Add effect of dilutive incentive awards		293
Add effect of dilutive convertible preferred limited partner units(1)		—
Weighted average number of common limited partner units—diluted		102,696

(1) For the period 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. The updated accounting guidance provides companies with alternative methods of adoption. We are evaluating the impact of this updated accounting guidance on our condensed consolidated financial statements, and based on the continuing evaluation of our revenue streams, this accounting guidance is not expected to have a material impact on our net income (loss). This accounting guidance will require that our revenue recognition policy disclosures include further detail regarding our performance obligations as to the nature, amount, timing, and estimates of revenue and cash flows generated from our contracts with customers. We are still in the process of determining whether or not we will use the retrospective method or the modified retrospective approach to implementation.

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Basis of Presentation and Summary of Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2017

Reconciliation of Weighted Average Number of Common Shares / Common Limited Partner Units

The following table is a reconciliation of our 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 March 31,
	2017
Weighted average number of common shares - basic (1)		5,170
Add dilutive effect of share based awards at end of period		316
Weighted average number of common shares - diluted		5,486

(1) For the period presented, 278,000 restricted common shares outstanding were excluded from the basic weighted average number of common shares because they were not vested.

Reconciliation of Net Income

The following is a reconciliation of net income allocated to our Predecessor’s common limited partners for purposes of calculating net income attributable to our Predecessor’s common limited partners per unit (in thousands, except unit data):

	Predecessor
	Three Months ended March 31, 2016
Net income	$	12,763
Preferred limited partner dividends		(3,648	)
Net income attributable to common limited partners and the general partner		9,115
Less: General partner’s interest		182
Net income attributable to common limited partners		8,933
Less: Net income attributable to participating securities – phantom units		25
Net income utilized in the calculation of net income attributable to common limited partners per unit – Basic		8,908
Plus: Convertible preferred limited partner dividends(1)		—
Net income utilized in the calculation of net loss attributable to common limited partners per unit – Diluted	$	8,908

(1) For the period presented, distributions on our Predecessor’s Class C convertible preferred units wereexcluded, because the inclusion of such preferred distributions 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 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
	Three Months Ended March 31,
	2016
Weighted average number of common limited partner units—basic		102,403
Add effect of dilutive incentive awards		293
Add effect of dilutive convertible preferred limited partner units(1)		—
Weighted average number of common limited partner units—diluted		102,696

(1) For the period 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.

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Property, Plant and Equipment (Tables)

3 Months Ended

Mar. 31, 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):

	March 31, 2017			December 31, 2016
Natural gas and oil properties:
Proved properties	$	728,139		$	717,839
Unproved properties		74,434			74,434
Support equipment and other		14,701			14,180
Total natural gas and oil properties		817,274			806,453
Less – accumulated depreciation, depletion and amortization		(36,344	)		(21,730	)
	$	780,930		$	784,723

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Debt (Tables)

3 Months Ended

Mar. 31, 2017

Debt Disclosure [Abstract]

Schedule of Long-term Debt Instruments

Total debt consists of the following at the dates indicated (in thousands):

	March 31,			December 31,
	2017			2016
First Lien Credit Facility	$	435,809		$	435,809
Second Lien Credit Facility		267,676			261,022
Deferred financing costs, net of accumulated amortization of $335 and $172, respectively		(1,883	)		(2,021	)
Total debt, net		701,602			694,810
Less current maturities		(701,602	)		(694,810)
Total long-term debt, net	$	—		$	—

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Derivative Instruments (Tables)

3 Months Ended

Mar. 31, 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 March 31,
	2017			2016
Portion of settlements associated with gains (losses) previously recognized within accumulated other comprehensive income, net of prior year offsets(1)	$	—		$	3,515
Portion of settlements attributable to subsequent mark to market gains (losses)(2)	(3,749		)		45,193
Total cash settlements on commodity derivative contracts	$	(3,749	)	$	48,708
Gains recognized on cash settlement(2)	$	6,335		$	5,788
Gains recognized on open derivative contracts(2)	23,158				40,332
Gains on mark-to-market derivatives	$	29,493		$	46,120

(1) Recognized in gas and oil production revenue.

(2) 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 March 31, 2017	Gross Amounts Recognized			Gross Amounts Offset			Net Amount Presented
Current portion of derivative assets	$	632		$	(632	)	$	—
Long-term portion of derivative assets		3,200		(1,973		)		1,227
Total derivative assets	$	3,832		$	(2,605	)	$	1,227
Current portion of derivative liabilities	$	(17,867	)	$	632		$	(17,235	)
Long-term portion of derivative liabilities	(2,136		)	1,973			(163		)
Total derivative liabilities	$	(20,003	)	$	2,605		$	(17,398	)
Offsetting Derivatives as of December 31, 2016
Current portion of derivative assets	$	7		$	(7	)	$	—
Long-term portion of derivative assets		819			(819	)		—
Total derivative assets	$	826		$	(826	)	$	—
Current portion of derivative liabilities	$	(34,806	)	$	7		$	(34,799	)
Long-term portion of derivative liabilities		(15,434	)		819			(14,615	)
Total derivative liabilities	$	(50,240	)	$	826		$	(49,414	)

Commodity Derivative Instruments by Type Table

At March 31, 2017, we had the following commodity derivatives instruments:

Type	Production Period Ending December 31,	Volumes(1)		Average Fixed Price(2)		Fair Value Liability			Total Type
						(in thousands)(2)			(in thousands)
Natural Gas – Fixed Price Swaps	2017	38,759,800	(3)	$	3.140	$	(6,373	)
	2018	47,559,300		$	2.959	$	(3,437	)
									$	(9,810	)
Crude Oil – Fixed Price Swaps	2017	891,500	(3)	$	46.971	$	(4,121	)
	2018	1,011,100		$	49.544	$	(2,240	)
									$	(6,361	)
						Total net liabilities			$	(16,171	)

(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 nine months of 2017 beginning April 1, 2017.

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Fair Value of Financial Instruments (Tables)

3 Months Ended

Mar. 31, 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 March 31, 2017	Level 1		Level 2			Level 3		Total
Assets, gross
Commodity swaps	$	—	$	3,832		$	—	$	3,832
Total derivative assets, gross		—	3,832				—	3,832
Liabilities, gross
Commodity swaps		—		(20,003	)		—		(20,003	)
Total derivative liabilities, gross		—		(20,003	)		—		(20,003	)
Total derivatives, fair value, net	$	—	$	(16,171	)	$	—	$	(16,171	)

Derivatives, Fair Value, as of December 31, 2016	Level 1		Level 2			Level 3		Total
Assets, gross
Commodity swaps	$	—	$	826		$	—	$	826
Total derivative assets, gross		—		826			—		826
Liabilities, gross
Commodity swaps	$	—		(50,240	)		—		(50,240	)
Total derivative liabilities, gross		—		(50,240	)		—		(50,240	)
Total derivatives, fair value, net		—	$	(49,414	)	$	—	$	(49,414	)

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Operating Segment Information (Tables)

3 Months Ended

Mar. 31, 2017

Segment Reporting [Abstract]

Operating Segment Data

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 March 31,
	2017			2016
Gas and oil production: (1)
Gas and oil production revenues	$	100,086		$	94,612
Gas and oil production costs		(29,987	)		(35,842	)
Depreciation, depletion and amortization		(16,013	)		(26,580	)
Segment income	$	54,086		$	32,190
Drilling partnership management:(2)
Drilling partnership management revenues	$	10,050		$	8,596
Drilling partnership management expenses		(8,171	)		(6,283	)
Depreciation, depletion and amortization		(479	)		(3,465	)
Segment income (loss)	$	1,400		$	(1,152	)
Reconciliation of segment income (loss) to net loss:
Segment income (loss):
Gas and oil production	$	54,086		$	32,190
Drilling partnership management (2)	1,400				(1,152	)
Total segment income (loss)		55,486			31,038
General and administrative expenses(3)		(13,758	)		(17,077	)
Interest expense(3)		(13,985	)		(27,705	)
Gain on early extinguishment of debt(3)		—			26,498
Other income (loss)(3)	(654		)		9
Income tax (provision) benefit(3)		(180	)		—
Net income	$	26,909		$	12,763
Reconciliation of segment revenues to total revenues:
Gas and oil production	$	100,086		$	94,612
Drilling partnership management	10,050				8,596
Total revenues	$	110,136		$	103,208
Capital expenditures:
Gas and oil production	$	9,913		$	11,945
Drilling partnership management	420				1,134
Corporate and other	111				91
Total capital expenditures	$	10,444		$	13,170

(1) Includes gain on mark-to-market derivatives.

(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 & administrative expenses, interest expense, gain on early extinguishment of debt, 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.

	March 31, 2017		December 31, 2016
Balance sheet:
Total assets:
Gas and oil production	$	811,895	$	819,454
Drilling partnership management	12,540			18,182
Corporate and other(1)	54,803			44,198
Total assets	$	879,238	$	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.

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Organization (Narrative) (Details) - USD ($)	Sep. 01, 2016	Mar. 31, 2017
Organization [Line Items]
Common shares issued		5,447,787
Common shares outstanding		5,447,787
Minimum
Organization [Line Items]
Percentage of common stock voting rights	67.00%
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
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

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Basis of Presentation and Summary of Significant Accounting Policies (Narrative) (Details)		3 Months Ended	12 Months Ended
	May 04, 2017 USD ($) Wells	Mar. 31, 2017 USD ($)	Dec. 31, 2016 USD ($) MMcfe	Sep. 01, 2016 USD ($)
Summary Of Significant Accounting Policies [Line Items]
Substantial Doubt about Going Concern, Conditions or Events		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 $701.6 million of outstanding indebtedness under our credit facilities, which is net of $1.9 million of deferred financing costs, as current portion of long term debt, net within our condensed consolidated balance sheet as of March 31, 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		$ 1,883,000	$ 2,021,000
U.S. Federal statutory tax rate		35.00%
Texas
Summary Of Significant Accounting Policies [Line Items]
Effective tax rate		0.60%
Appalachia and Marcellus
Summary Of Significant Accounting Policies [Line Items]
Net production | MMcfe			30
Percentage of net gas produced			92.00%
Percentage of net liquids produced			8.00%
Appalachia and Marcellus | Subsequent Event
Summary Of Significant Accounting Policies [Line Items]
Sale of assets	$ 84,200,000
Number of oil and gas wells sold | Wells	8,400
First Lien Credit Facility
Summary Of Significant Accounting Policies [Line Items]
Step down in borrowing base				$ 440,000,000
First Lien Credit Facility | Appalachia and Marcellus | Subsequent Event
Summary Of Significant Accounting Policies [Line Items]
Step down in borrowing base	$ 360,000,000
Credit Facilities
Summary Of Significant Accounting Policies [Line Items]
Outstanding indebtedness		$ 701,600,000
Deferred financing costs		$ 1,900,000
Minimum
Summary Of Significant Accounting Policies [Line Items]
Pro-rata share in Drilling Partnerships		10.00%
Maximum
Summary Of Significant Accounting Policies [Line Items]
Pro-rata share in Drilling Partnerships		30.00%

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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	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Weighted average number of common shares / common limited partner units - basic	5,170
Add dilutive effect of share based awards at end of period	316
Weighted average number of common shares / common limited partner units - diluted	5,486
Predecessor
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Weighted average number of common shares / common limited partner units - basic		102,403
Add effect of dilutive incentive awards		293
Weighted average number of common shares / common limited partner units - diluted		102,696

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Basis of Presentation and Summary of Significant Accounting Policies (Reconciliation of Weighted Average Number Of Common Shares / Common Limited Partner Units) (Parenthetical) (Details)	3 Months Ended
	Mar. 31, 2017 shares
Restricted Common Shares
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Antidilutive securities excluded from basic weighted average number of common shares	278,000

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Basis of Presentation and Summary of Significant Accounting Policies (Schedule of Net Income Reconciliation) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Earnings Per Share Basic [Line Items]
Net income	$ 26,909
Net income attributable to common limited partners and the general partner	$ 26,371
Predecessor
Earnings Per Share Basic [Line Items]
Net income		$ 12,763
Preferred member / limited partner dividends		(3,648)
Net income attributable to common limited partners and the general partner		9,115
Less: General partner’s interest		182
Net income attributable to common limited partners		8,933
Less: Net income attributable to participating securities – phantom units		25
Net income utilized in the calculation of net income attributable to common limited partners per unit – Basic		8,908
Net income utilized in the calculation of net loss attributable to common limited partners per unit – Diluted		$ 8,908

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Property, Plant and Equipment (Summary of Property, Plant and Equipment) (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Property Plant And Equipment [Abstract]
Proved properties	$ 728,139	$ 717,839
Unproved properties	74,434	74,434
Support equipment and other	14,701	14,180
Total natural gas and oil properties	817,274	806,453
Less – accumulated depreciation, depletion and amortization	(36,344)	(21,730)
Property, plant and equipment, Net, Total	$ 780,930	$ 784,723

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Property, Plant and Equipment (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Property Plant And Equipment [Line Items]
Non-cash investing activities capital expenditures, reflected within the changes in accounts payable and accrued liabilities	$ 1.8
Weighted Average Interest Rate Used To Capitalize Interest	7.70%
Interest Costs Capitalized	$ 0.1
Depreciation depletion and amortization
Property Plant And Equipment [Line Items]
Accretion expense in asset retirement obligations	$ 1.9
Predecessor
Property Plant And Equipment [Line Items]
Non-cash investing activities capital expenditures, reflected within the changes in accounts payable and accrued liabilities		$ 18.7
Weighted Average Interest Rate Used To Capitalize Interest		6.70%
Interest Costs Capitalized		$ 2.4
Liabilities incurred in asset retirement obligations		2.8
Predecessor | Depreciation depletion and amortization
Property Plant And Equipment [Line Items]
Accretion expense in asset retirement obligations		$ 1.7

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Debt (Schedule of Total Debt Outstanding) (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Deferred financing costs, net of accumulated amortization of $335 and $172, respectively	$ (1,883)	$ (2,021)
Total debt, net	701,602	694,810
Less current maturities	(701,602)	(694,810)
First Lien Credit Facility
Debt Instrument [Line Items]
Credit Facility	435,809	435,809
Second Lien Credit Facility
Debt Instrument [Line Items]
Credit Facility	$ 267,676	$ 261,022

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Debt (Schedule of Total Debt Outstanding) (Parenthetical) (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Debt Disclosure [Abstract]
Accumulated amortization	$ 335	$ 172

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Debt (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Debt Instrument [Line Items]
Cash Payments For Interest On Debt	$ 6.9
Predecessor
Debt Instrument [Line Items]
Cash Payments For Interest On Debt		$ 41.2

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Debt (First Lien Credit Facility) (Details) - USD ($)		3 Months Ended
	Apr. 19, 2017	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Mar. 31, 2017	Nov. 01, 2017	Oct. 01, 2017	Aug. 31, 2017	Sep. 01, 2016
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						5.00%
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 March 31, 2017, the weighted average interest rate on outstanding borrowings under the First Lien Credit Facility was 5.0%.
First Lien Credit Facility | Minimum
Line Of Credit Facility [Line Items]
Percentage of commodity hedges covering						80.00%
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 Nonconforming Tranche
Line Of Credit Facility [Line Items]
Line of credit facility maximum borrowing capacity										$ 30,000,000
First Lien Facility Amendment | Subsequent Event
Line Of Credit Facility [Line Items]
Lenders’ waivers description	The First Lien Credit Facility lenders’ waivers are 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
First Lien Facility Amendment | Revolving Credit Facility Conforming Tranche | Scenario, Forecast
Line Of Credit Facility [Line Items]
Line of credit facility maximum borrowing capacity								$ 190,000,000	$ 330,000,000
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 | Scenario, Forecast
Line Of Credit Facility [Line Items]
Line of credit facility maximum borrowing capacity							$ 10,000,000

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Debt (Second Lien Credit Facility) (Details) - Second Lien Credit Facility - USD ($)			3 Months Ended
	Apr. 21, 2017	Sep. 01, 2016	Mar. 31, 2017
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
Subsequent Event
Line Of Credit Facility [Line Items]
Delivery notice period	180 days
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 01, 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%

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Derivative Instruments (Summary of Cash Settlement on Commodity Derivatives and Presentation in Partnership's Condensed Consolidated Statements of Operations) (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Portion of settlements attributable to subsequent mark to market gains (losses)	[1]	$ (3,749)
Total cash settlements on commodity derivative contracts		(3,749)
Gains recognized on cash settlement	[1]	6,335
Gains recognized on open derivative contracts	[1]	23,158
Gains on mark-to-market derivatives		$ 29,493
Predecessor
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Portion of settlements associated with gains (losses) previously recognized within accumulated other comprehensive income, net of prior year offsets	[2]		$ 3,515
Portion of settlements attributable to subsequent mark to market gains (losses)	[1]		45,193
Total cash settlements on commodity derivative contracts			48,708
Gains recognized on cash settlement	[1]		5,788
Gains recognized on open derivative contracts	[1]		40,332
Gains on mark-to-market derivatives			$ 46,120

[1] Recognized in gain (loss) on mark-to-market derivatives.

[2] Recognized in gas and oil production revenue.

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Derivative Instruments (Fair Values of the Partnership's Derivative Instruments Table) (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets	$ 3,832	$ 826
Gross Amounts Recognized, Liabilities	(20,003)	(50,240)
Current portion of derivative liabilities
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Liabilities	(17,867)	(34,806)
Gross Amounts Offset, Liabilities	632	7
Net Amount Presented, Liabilities	(17,235)	(34,799)
Long-term portion of derivative liabilities
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Liabilities	(2,136)	(15,434)
Gross Amounts Offset, Liabilities	1,973	819
Net Amount Presented, Liabilities	(163)	(14,615)
Total derivative liabilities
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Liabilities	(20,003)	(50,240)
Gross Amounts Offset, Liabilities	2,605	826
Net Amount Presented, Liabilities	(17,398)	(49,414)
Current portion of derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets	632	7
Gross Amounts Offset, Assets	(632)	(7)
Long-term portion of derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets	3,200	819
Gross Amounts Offset, Assets	(1,973)	(819)
Net Amount Presented, Assets	1,227
Total derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets	3,832	826
Gross Amounts Offset, Assets	(2,605)	$ (826)
Net Amount Presented, Assets	$ 1,227

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Derivative Instruments (Commodity Derivative Instruments by Type Table) (Details) $ in Thousands	Mar. 31, 2017 USD ($) MMBTU bbl $ / MMBTU $ / bbl
Derivatives Fair Value [Line Items]
Fair Value Liability	$ (16,171)
Natural Gas - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Liability	(9,810)
Crude Oil - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Liability	$ (6,361)
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	38,759,800	[1],[2]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	3.140	[3]
Fair Value Liability	$ (6,373)	[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	47,559,300	[2]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	2.959	[3]
Fair Value Liability	$ (3,437)	[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 | bbl	891,500	[1],[2]
Derivative, Swap Type, Average Fixed Price | $ / bbl	46.971	[3]
Fair Value Liability	$ (4,121)	[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 | bbl	1,011,100	[2]
Derivative, Swap Type, Average Fixed Price | $ / bbl	49.544	[3]
Fair Value Liability	$ (2,240)	[3]

[1] The production volumes for 2017 include the remaining nine months of 2017 beginning April 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.

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Fair Value of Financial Instruments (Schedule of Financial Instruments at Fair Value) (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Fair Value Option Qualitative Disclosures Related To Election [Line Items]
Assets, gross	$ 3,832	$ 826
Liabilities, gross	(20,003)	(50,240)
Total derivatives, fair value, net	(16,171)	(49,414)
Level 2
Fair Value Option Qualitative Disclosures Related To Election [Line Items]
Assets, gross	3,832	826
Liabilities, gross	(20,003)	(50,240)
Total derivatives, fair value, net	(16,171)	(49,414)
Commodity Swaps
Fair Value Option Qualitative Disclosures Related To Election [Line Items]
Assets, gross	3,832	826
Liabilities, gross	(20,003)	(50,240)
Commodity Swaps | Level 2
Fair Value Option Qualitative Disclosures Related To Election [Line Items]
Assets, gross	3,832	826
Liabilities, gross	$ (20,003)	$ (50,240)

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Fair Value of Financial Instruments - Additional Information (Details) $ in Millions	Mar. 31, 2017 USD ($)
First and Second Lien Credit Facility
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Long-term debt, carrying amount	$ 703.5

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Certain Relationships and Related Party Transactions (Narrative) (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016
Related Party Transaction [Line Items]
Accrued well drilling and completion costs	$ 7,092	$ 4,933
Relationship with ATLS
Related Party Transaction [Line Items]
Accounts receivable	8,900	3,300
Relationship with Drilling Partnerships
Related Party Transaction [Line Items]
Accounts receivable	200	300
Accounts payable	5,000	5,600
Relationship with Drilling Partnerships | Predecessor
Related Party Transaction [Line Items]
Capital raised from investors			$ 36,700
Accrued well drilling and completion costs			$ 13,300
Relationship with AGP
Related Party Transaction [Line Items]
Accounts receivable	$ 1,300	$ 800

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Commitments and Contingencies (Details) - USD ($)	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
Long-term purchase commitment, amount	$ 11,200,000
Accrual for Environmental Loss Contingencies	$ 0	$ 0

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Predecessor Cash Distributions - Additional Information (Details) - Predecessor - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Common Limited Partners' Interests
Distribution Made To Limited Partner [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid		$ 3.8
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		$ 1.9
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit		$ 0.17
Class A General Partner
Distribution Made To Limited Partner [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid		$ 0.1
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit		$ 0.0125
Class D Preferred Limited Partners | October 15, 2015 to January 14, 2016
Distribution Made To Limited Partner [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid		$ 2.2
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit		$ 0.5390625
Class E Preferred Limited Partners | October 15, 2015 to January 14, 2016
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		$ 0.671875
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%

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

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Operating Segment Information (Operating Segment Data) (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Segment Reporting Information [Line Items]
Gas and oil production		$ 70,593
Drilling partnership management		10,050
Gas and oil production costs		(29,987)
Drilling partnership management expenses		(8,171)
Depreciation, depletion and amortization		(16,492)
Segment income (loss)		55,486
Predecessor
Segment Reporting Information [Line Items]
Gas and oil production			$ 48,492
Drilling partnership management			8,596
Gas and oil production costs			(35,842)
Drilling partnership management expenses			(6,283)
Depreciation, depletion and amortization			(30,045)
Segment income (loss)			31,038
Gas And Oil Production
Segment Reporting Information [Line Items]
Gas and oil production	[1]	100,086
Gas and oil production costs	[1]	(29,987)
Depreciation, depletion and amortization	[1]	(16,013)
Segment income (loss)	[1]	54,086
Gas And Oil Production | Predecessor
Segment Reporting Information [Line Items]
Gas and oil production	[1]		94,612
Gas and oil production costs	[1]		(35,842)
Depreciation, depletion and amortization	[1]		(26,580)
Segment income (loss)	[1]		32,190
Drilling Partnership Management
Segment Reporting Information [Line Items]
Drilling partnership management	[2]	10,050
Drilling partnership management expenses	[2]	(8,171)
Depreciation, depletion and amortization	[2]	(479)
Segment income (loss)	[2]	$ 1,400
Drilling Partnership Management | Predecessor
Segment Reporting Information [Line Items]
Drilling partnership management	[2]		8,596
Drilling partnership management expenses	[2]		(6,283)
Depreciation, depletion and amortization	[2]		(3,465)
Segment income (loss)	[2]		$ (1,152)

[1] Includes gain on mark-to-market derivatives.

[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.

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Operating Segment Information (Reconciliation of Segment Income (loss) to Net Income (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Segment Reporting Information [Line Items]
Total segment income (loss)		$ 55,486
General and administrative expenses	[1]	(13,758)
Interest expense	[1]	(13,985)
Other income (loss)	[1]	(654)
Income tax (provision) benefit	[1]	(180)
Net income		26,909
Predecessor
Segment Reporting Information [Line Items]
Total segment income (loss)			$ 31,038
General and administrative expenses	[1]		(17,077)
Interest expense	[1]		(27,705)
Gain on early extinguishment of debt	[1]		26,498
Other income (loss)	[1]		9
Net income			12,763
Gas And Oil Production
Segment Reporting Information [Line Items]
Total segment income (loss)	[2]	54,086
Gas And Oil Production | Predecessor
Segment Reporting Information [Line Items]
Total segment income (loss)	[2]		32,190
Drilling Partnership Management
Segment Reporting Information [Line Items]
Total segment income (loss)	[3]	$ 1,400
Drilling Partnership Management | Predecessor
Segment Reporting Information [Line Items]
Total segment income (loss)	[3]		$ (1,152)

[1] General & administrative expenses, interest expense, gain on early extinguishment of debt, 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 on mark-to-market derivatives.

[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.

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Operating Segment Information (Reconciliation of Segment Revenues to Total Revenues) (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Segment Reporting Information [Line Items]
Gas and oil production		$ 70,593
Drilling partnership management		10,050
Total revenues		110,136
Predecessor
Segment Reporting Information [Line Items]
Gas and oil production			$ 48,492
Drilling partnership management			8,596
Total revenues			103,208
Gas And Oil Production
Segment Reporting Information [Line Items]
Gas and oil production	[1]	100,086
Gas And Oil Production | Predecessor
Segment Reporting Information [Line Items]
Gas and oil production	[1]		94,612
Drilling Partnership Management
Segment Reporting Information [Line Items]
Drilling partnership management	[2]	$ 10,050
Drilling Partnership Management | Predecessor
Segment Reporting Information [Line Items]
Drilling partnership management	[2]		$ 8,596

[1] Includes gain on mark-to-market derivatives.

[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.

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Operating Segment Information (Capital Expenditures) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Segment Reporting Information [Line Items]
Capital expenditures	$ 10,444
Predecessor
Segment Reporting Information [Line Items]
Capital expenditures		$ 13,170
Gas And Oil Production
Segment Reporting Information [Line Items]
Capital expenditures	9,913
Gas And Oil Production | Predecessor
Segment Reporting Information [Line Items]
Capital expenditures		11,945
Drilling Partnership Management
Segment Reporting Information [Line Items]
Capital expenditures	420
Drilling Partnership Management | Predecessor
Segment Reporting Information [Line Items]
Capital expenditures		1,134
Corporate and Other
Segment Reporting Information [Line Items]
Capital expenditures	$ 111
Corporate and Other | Predecessor
Segment Reporting Information [Line Items]
Capital expenditures		$ 91

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Operating Segment Information (Balance Sheet) (Details) - USD ($) $ in Thousands		Mar. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Total assets		$ 879,238	$ 881,834
Gas And Oil Production
Segment Reporting Information [Line Items]
Total assets		811,895	819,454
Drilling Partnership Management
Segment Reporting Information [Line Items]
Total assets		12,540	18,182
Corporate and Other
Segment Reporting Information [Line Items]
Total assets	[1]	$ 54,803	$ 44,198

[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.

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Subsequent Events (Narrative) (Details) - USD ($)	May 04, 2017	Sep. 01, 2016
Appalachia and Marcellus | Subsequent Event
Subsequent Event [Line Items]
Sale of assets	$ 84,200,000
First Lien Credit Facility
Subsequent Event [Line Items]
Step down in borrowing base		$ 440,000,000
First Lien Credit Facility | Appalachia and Marcellus | Subsequent Event
Subsequent Event [Line Items]
Step down in borrowing base	$ 360,000,000