UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~September~~March 3031, ~~2017~~2018

☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 001-36725

Atlas Energy Group, LLC

(Exact name of registrant as specified in its charter)

Delaware		45-3741247
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

425 Houston Street, Suite 300 Fort Worth, TX		76102
(Address of principal executive offices)		(Zip code)

Registrant’s telephone number, including area code: (412) 489-0006

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T ~~during the preceding 12 months~~ (or§232.405 ~~for~~of ~~such~~this ~~shorter period that the registrant was required to submit and post such files~~chapter)~~. Yes ☒ No ☐~~

during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer”, “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☐	Accelerated filer	☐	Non-accelerated filer	☒	Smaller reporting company	☐

						Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

As of ~~November~~June 138, ~~2017~~2018, there were 31,973,~~122~~518 common units outstanding.

ATLAS ENERGY GROUP, LLC

INDEX TO ~~QUARTERLY~~ANNUAL REPORT

ON FORM 10-Q

TABLE OF CONTENTS

		~~Page~~	Page
PART 1. FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Condensed Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016	5
	Condensed Consolidated Balance Sheets as of March 31, 2018 and December 31, 2017		5
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2017 and 2016	6
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2018 and 2017		6
	Condensed Consolidated Statements of Comprehensive Loss for the Three and Nine Months Ended September 30, 2017 and 2016	7
	Condensed Consolidated Statement of Changes in Unitholders’ Equity for the Three Months Ended March 31, 2018		7
	Condensed Consolidated Statement of Changes in Unitholders’ Equity for the Nine Months Ended September 30, 2017	8
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2018 and 2017		8
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2017 and 2016	9
	Notes to Condensed Consolidated Financial Statements		9
	Notes to Condensed Consolidated Financial Statements	10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		20
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		25
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	42
Item 4.	Controls and Procedures		26
Item 4.	Controls and Procedures	43
PART II. OTHER INFORMATION
PART II. OTHER INFORMATION
Item 1A	Risk Factors		26
Item 1A.	Risk Factors	43
Item 6.	Exhibits		27
Item 6.	Exhibits	44
SIGNATURES			28
SIGNATURES		45

FORWARD-LOOKING STATEMENTS

The matters discussed within this report include forward-looking statements. These statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “should,” or “will,” or the negative thereof or other variations thereon or comparable terminology. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this report are forward-looking statements. We have based these forward-looking statements on our current expectations, assumptions, estimates and projections. While we believe these expectations, assumptions, estimates and projections are reasonable, such forward-looking statements are only predictions and involve known and unknown risks and uncertainties, many of which are beyond our control. These and other important factors may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements. Some of the key factors that could cause actual results to differ from our expectations include:

• actions that we may take in connection with our liquidity needs, including the ~~issuance~~incurrence of ~~equity~~amounts ~~or the incurrence~~ of cancellation of indebtedness income;

• the fact that our cash flow is substantially dependent on the ability of Titan ~~Energy, LLC (“Titan”)~~ and ~~Atlas Growth Partners, L.P. (“~~AGP”) to make distributions, but neither Titan nor AGP is currently paying distributions;

•

the demand for natural gas, oil, NGLs and condensate;

• the price volatility of natural gas, oil, NGLs, and condensate;

•

economic conditions and instability in the financial markets;

• the impact of our common units being quoted on the ~~OTCQX~~OTCQB Market and not listed on a national securities exchange;

• changes in the market price of our common units;

•

future financial and operating results;

•

economic conditions and instability in the financial markets;

• success in efficiently developing and exploiting our reserves and ~~economically finding or acquiring additional recoverable reserves and~~ meeting substantial capital investment needs;

•

the accuracy of estimated natural gas and oil reserves;

•

the financial and accounting impact of hedging transactions;

•

potential changes in tax laws and environmental and other regulations that may affect our business;

•

the ability to obtain adequate water to conduct drilling and production operations, and to dispose of the water used in and generated by these operations, at a reasonable cost and within applicable environmental rules;

•

the effects of unexpected operational events and drilling conditions, and other risks associated with drilling operations;

•

impact fees and severance taxes;

•

the effects of intense competition in the natural gas and oil industry;

•

general market, labor and economic conditions and related uncertainties;

•

the ability to retain certain key employees and customers;

•

dependence on the gathering and transportation facilities of third parties;

•

the availability of drilling rigs, equipment and crews;

•

expirations of undeveloped leasehold acreage;

• exposure to ~~new~~financial and ~~existing~~other ~~litigation~~liabilities of the managing general partners of the investment partnerships;

• ~~development~~exposure ofto ~~alternative~~new ~~energy~~and ~~resources~~existing litigation; and

• ~~our~~development ~~ability~~of toalternative beenergy ~~treated as a partnership for U~~resources.~~S. federal income tax purposes.~~

Other factors that could cause actual results to differ from those implied by the forward-looking statements in this report are more fully described under “Item 1A: Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016. Given these risks and uncertainties, you are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this report are made only as of the date hereof. We do not undertake and specifically decline any obligation to update any such statements or to publicly announce the results of any revisions to any of these statements to reflect future events or developments.

Other factors that could cause actual results to differ from those implied by the forward-looking statements in this report are more fully described under Part II-- Item 1A “Risk Factors” of this report and Part I—Item 1A “Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2017. Given these risks and uncertainties, you are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this report are made only as of the date hereof. We do not undertake and specifically decline any obligation to update any such statements or to publicly announce the results of any revisions to any of these statements to reflect future events or developments.

Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS ENERGY GROUP, LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

	September 30,			December 31,
		March 31,		December 31,
	2017			2016
		2018		2017
ASSETS
Current assets:
Cash and cash equivalents	$	178,~~603~~783		$	12,~~009~~929
Accounts receivable		~~608~~481			~~835~~564
Current derivative assets		68			—
Advances to affiliates		129			-
Prepaid expenses and other		~~184~~76			40160
Total current assets		189,~~463~~469			1213,~~884~~653
Property, plant and equipment, net		6668,~~054~~963			6865,~~899~~293
Long-term derivative assets		18			—
Other assets, net		3,771			5,102
Other assets, net		20,895			23,293
Total assets	$	82,203		$	84,048
Total assets	$	105,430		$	105,076
LIABILITIES AND UNITHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable		~~378~~483			~~890~~332
Advances from affiliates		1311,~~400~~114			49,~~147~~602
Current portion of derivative payable		—579			~~284~~497
Accrued interest		31			28
Accrued liabilities		7,304			7,971
Accrued liabilities		8,465			12,050
Current portion of long-term debt		84,467			79,350
Current portion of long-term debt		95,491			81,100
Total current liabilities		103,947			97,752
Total current liabilities		117,765			98,499
Asset retirement obligations and other		640			1,968
Long-term derivative liability		—			280
Commitments and contingencies (Note 6)
Asset retirement obligations and other		2,967			4,863
Commitments and contingencies (Note 8)
Unitholders’ equity (deficit):
Common unitholders’ equity (deficit)		(8590,~~676~~718	)		(~~115~~84,~~734~~900	)
Series A preferred equity		—			45,148
Warrants		1,868			1,868
		(83,808	)		(68,718	)
		(88,850	)		(83,032	)
Non-controlling interests		6866,~~506~~466			7067,~~152~~360
Total unitholders’ equity (deficit)		(1522,~~302~~384	)		1(15,~~434~~672	)
Total liabilities and unitholders’ equity (deficit)	$	~~105~~82,~~430~~203		$	~~105~~84,~~076~~048

See accompanying notes to condensed consolidated financial statements.

ATLAS ENERGY GROUP, LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)

	Three Months Ended						~~Nine Months Ended~~
	September 30,						September 30,
	March 31,
		2017		2016			2017			2016
	2018			2017
Revenues:
Gas and oil production	$	1,731		$	21,045		$	6,001		$	127,420
Natural gas revenue	$	36		$	101
ARP Drilling Partnerships management		—			11,568			—			25,009
Oil revenue	1,630				2,185
Gain (loss) on mark-to-market derivatives		(449	)		9,449			942			(18,188	)
NGLs revenue	104			110
Other, net		16			175			879			1,045
Gain (loss) on mark-to-market derivatives	(286		)	757
Total revenues		1,298			42,237			7,822			135,286
Other, net	47			722
Costs and expenses:
Total revenues	1,531				3,875
Gas and oil production		476			9,228			1,929			77,454
Costs and expenses:
ARP Drilling Partnerships management		—			9,536			—			18,331
Gas and oil production	456			952
General and administrative	1,735	~~1,860~~			31,~~864~~785			~~3,538~~			~~53,779~~
Depreciation, depletion and amortization	975	~~825~~			121,~~358~~112			~~2,823~~			~~78,937~~
Total costs and expenses	3,166	~~3,161~~			343,~~986~~849			~~8,290~~			~~228,501~~
Operating income (loss)	(1,635	~~(1,863~~	)	26	~~7,251~~			~~(468~~	)		~~(93,215~~	)
Interest expense	(5,327	~~(5,478~~	)		(134,~~712~~929	)		~~(15,201~~	)		~~(79,004~~	)
Gain (loss) on early extinguishment of debt, net		—			—			—			20,418
Net loss	(6,962		)		(4,903	)
Reorganization items, net		—			(21,649	)		—			(21,649	)
Net loss attributable to non-controlling interests	894				281
Gain on deconsolidation of Atlas Resource Partners, L.P.		—			46,951			—			46,951
Net loss attributable to unitholders’ interests	$	(6,068	)	$	(4,622	)
Other loss		—			(5,273	)		—			(11,922	)
Net loss attributable to unitholders per common unit (Note 2):
Net income (loss)		(7,341	)		13,568			(15,669	)		(138,421	)
Basic	$	(0.19	)	$	(0.18	)
Preferred unitholders’ dividends		—		—				—			(339	)
Diluted	$	(0.19	)	$	(0.18	)
Net loss attributable to non-controlling interests		1,022			23,619			1,646			132,916
Weighted average common units outstanding (Note 2):
Net income (loss) attributable to unitholders’ interests	$	(6,319	)	$	37,187		$	(14,023	)	$	(5,844	)
Basic	31,973				26,062
Net income (loss) attributable to unitholders per common unit (Note 2):
Diluted	31,973				26,062
Basic	$	(0.20	)	$	1.41		$	(0.48	)	$	(0.22	)
Diluted	$	(0.20	)	$	1.00		$	(0.48	)	$	(0.22	)
Weighted average common units outstanding (Note 2):
Basic		31,973			26,038			29,288			26,032
Diluted		31,973			36,828			29,288			26,032

See accompanying notes to condensed consolidated financial statements.

ATLAS ENERGY GROUP, LLC

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017				2016		2017				2016
Net income (loss)	$	(7,341	)	$	13,568		$	(15,669	)	$	(138,421	)
Other comprehensive loss:
Derivative instruments designated as cash flow hedges:
Reclassification to mark-to-market gains		—			(1,470	)		—			(10,540	)
Reclassification to gain on deconsolidation of Atlas Resource Partners, L.P..		—			(1,949	)		—			(1,949	)
Total other comprehensive loss		—			(3,419	)		—			(12,489	)
Comprehensive income (loss)		(7,341	)		10,149			(15,669	)		(150,910	)
Comprehensive loss attributable to non-controlling interests		1,022			24,765			1,646			141,121
Comprehensive income (loss) attributable to unitholders’ interest	$	(6,319	)	$	34,914		$	(14,023	)	$	(9,789	)

See accompanying notes to condensed consolidated financial statements.

ATLAS ENERGY GROUP, LLC

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN UNITHOLDERS’ EQUITY (DEFICIT)

(in thousands, except unit data)

(Unaudited)

	Series A Preferred Equity						Common Unitholders’ Equity (Deficit)					Warrants						Non- Controlling			Total Unitholders’ Equity
	Common Unitholders’ Equity (Deficit)						Warrants					Non- Controlling			Total Unitholders’ Equity
	Units			Amount			Units		Amount			~~Units~~Interest			~~Amount~~(Deficit)			~~Interest~~			~~(Deficit)~~
Balance at December 31, 2016		1,805,858		$	45,148			26,044,592	$	(115,734	)		4,668,044		$	1,868		$	70,152		$	1,434
Balance at December 31, 2017		31,973,122		$	(84,900	)		4,668,044	$	1,868		$	67,360		$	(15,672	)
Issuance of units		85,760			2,144			—		(2,144	)		—			—			—			—
Net issued and unissued units under incentive plan	396			250				—		—			—		250
Net issued and unissued units under incentive plan		—			—			17,226		(1,067	)		—			—			—			(1,067	)
Net loss		—		(6,068		)		—		—		(894		)	(6,962		)
Conversion of Series A preferred units		(1,891,618	)		(47,292	)		5,911,304		47,292			—			—			—			—
Balance at March 31, 2018	31,973,518			$ (90,718		)		4,668,044	$	1,868		$ 66,466			$	(22,384	)
Net loss		—			—			—		(14,023	)		—			—			(1,646	)		(15,669	)
Balance at September 30, 2017		—		$	—			31,973,122	$	(85,676	)		4,668,044		$	1,868		$	68,506		$	(15,302	)

See accompanying notes to condensed consolidated financial statements.

ATLAS ENERGY GROUP, LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Nine Months Ended September 30,
		Three Months Ended March 31,
	2017			2016
		2018		2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(156,~~669~~962	)	$	(~~138~~4,~~421~~903	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		~~2,823~~975			781,~~937~~112
Gain on early extinguishment of debts, net		—			(20,418	)
(Gain) loss on derivatives		237			(705	)
(Gain) loss on derivatives		(453	)		342
Amortization of deferred financing costs and debt discount		212			374
Amortization of deferred financing costs and debt discount		488			15,245
Non-cash compensation expense		250			359
Non-cash compensation expense		(1,067	)		4,603
Paid-in-kind interest		4,972			4,303
Paid-in-kind interest		13,983			7,574
Equity income in unconsolidated companies		—			(722	)
Other loss		—			11,922
Distributions received from unconsolidated companies		—			404
Non cash gain on deconsolidation of ARP		—			(46,951	)
Distributions paid to non-controlling interests		—			(20,844	)
Equity income in unconsolidated companies		(879	)		(837	)
Distributions received from unconsolidated companies		1,187			1,372
Changes in operating assets and liabilities:
Monetization of ARP’s derivatives		—			243,552
Accounts receivable, prepaid expenses and other		11			(4	)
Accounts receivable, prepaid expenses and other		30			65,055
Advances to/from affiliates		1,383			6,106
Advances to/from affiliates		9,253			15,562
Accounts payable and accrued liabilities		(4,945	)		(6,409	)
Accounts payable and accrued liabilities		(4,060	)		(40,104	)
Net cash used in operating activities		(3,867	)		(85	)
Net cash provided by operating activities		5,636			176,589
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		—(225	)		~~(27,730~~—	)
Other		—			769
Net cash used in investing activities		(225	)		—
Net cash used in investing activities		—			(26,961	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments under term loan facilities		—			(4,250	)
Deferred financing costs, distribution equivalent rights and other		(54	)		(8	)
Borrowings under ARP’s revolving credit facility		—			135,000
Net cash used in financing activities		(54	)		(8	)
Repayments under ARP’s revolving credit facility		—			(291,191	)
Net change in cash and cash equivalents		(4,146	)		(93	)
ARP senior note repurchases		—			(5,528	)
Cash and cash equivalents, beginning of year		12,929			12,009
Net proceeds from issuance of our subsidiaries’ units to the public		—			1,746
Cash and cash equivalents, end of period	$	8,783		$	11,916
Dividends to preferred unitholders		—			(1,015	)
Deferred financing costs, distribution equivalent rights and other		(42	)		(4,137	)
Net cash used in financing activities		(42	)		(169,375	)
Net change in cash and cash equivalents		5,594			(19,747	)
Cash and cash equivalents, beginning of year		12,009			31,214
Cash and cash equivalents, end of period	$	17,603		$	11,467

See accompanying notes to condensed consolidated financial statements.

ATLAS ENERGY GROUP, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1—ORGANIZATION

We are a publicly traded (~~OTCQX~~OTCQB: ATLS) Delaware limited liability company formed in October 2011. Unless the context otherwise requires, references to “Atlas Energy Group, LLC,” “the Company,” “we,” “us,” “our” and “our company,” refer to Atlas Energy Group, LLC, and our consolidated subsidiaries.

Our operations primarily consist of our ownership interests in the following:

• Commencing September 1, 2016, Titan Energy, LLC (“Titan”), an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”) with operations in basins across the United States but primarily focused on the horizontal development of resource potential from the Eagle Ford Shale in South Texas. Titan Energy Management, LLC, our wholly owned subsidiary (“Titan Management”), holds the Series A Preferred Share of Titan, which entitles us to receive 2% of the aggregate of distributions paid to shareholders (as if we held 2% of Titan’s members’ equity, subject to potential dilution in the event of future equity interests) and to appoint four of seven directors. Titan sponsors and manages tax-advantaged investment partnerships (the “Drilling Partnerships”), in which it coinvests, to finance a portion of its natural gas, crude oil and NGL production activities. As discussed further below, Titan is the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”);

• Through August 31, 2016, 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 23.3% limited partner interest in ARP. As discussed further below, ARP was the predecessor to the business and operations of Titan;

•

All of the incentive distribution rights, an 80.0% general partner interest and a 2.1% limited partner interest in Atlas Growth Partners, L.P. (“AGP”), a Delaware limited partnership and an independent developer and producer of natural gas, crude oil and NGLs with operations primarily focused in the Eagle Ford Shale in South Texas;

• A 12.0% limited partner interest in Lightfoot Capital Partners, L.P. (“Lightfoot L.P.”) and a 15.9% general partner interest in Lightfoot Capital Partners GP, LLC (“Lightfoot G.P.” and together with Lightfoot L.P., “Lightfoot”), the general partner of Lightfoot L.P., an entity for which Jonathan Cohen, Executive Chairman of the Company’s board of directors, is the Chairman of the board of directors. Lightfoot focuses its investments primarily on incubating new MLPs and providing capital to existing MLPs in need of additional equity or structured debt. ~~On August 29, 2017, Lightfoot announced a proposed sale transaction.~~ See Note 2 for further disclosures regarding Lightfoot; ~~and~~

• A membership interest in the founder shares of Osprey Sponsor, LLC (“Osprey Sponsor”) received in August 2017. Osprey Sponsor is the sponsor of Osprey Energy Acquisition Corp (“Osprey”). We received our membership interest in recognition of potential utilization, if any, of our office space, advisory services and personnel by Osprey. See Note 2 for further disclosures regarding Osprey and Osprey Sponsor.; and

At• ~~September~~A 302% preferred membership interest in Titan Energy, ~~2017~~LLC (“Titan”), wean ~~had~~independent 31developer and producer of natural gas,~~973~~ crude oil and NGL with operations in basins across the United States. Titan Energy Management,~~122~~ ~~common~~LLC, ~~units~~our ~~issued~~wholly owned subsidiary (“Titan Management”), holds the Series A Preferred Share of Titan, which entitles us to receive 2% of the aggregate of distributions paid to shareholders (as if we held 2% of Titan’s members’ equity, subject to potential dilution in the event of future equity interests) and ~~outstanding.~~to appoint four of seven directors.

~~ARP~~At ~~Restructuring~~March ~~and~~31, ~~Emergence~~2018, ~~from~~we ~~Chapter~~had 1131,973,518 ~~Proceedings~~common units issued and outstanding.

On July 25, 2016, we, solely with respect to certain sections thereof, along with ARP and certain of its subsidiaries, entered into a Restructuring Support Agreement (the “Restructuring Support Agreement”) with certain of ARP’s and such subsidiaries’ lenders (the “Restructuring Support Parties”) to support ARP’s restructuring pursuant to a pre-packaged plan of reorganization (the “Plan”).

On July 27, 2016, ARP and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”) in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court,” and the cases commenced thereby, the “Chapter 11 Filings”). The cases commenced thereby were jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.”

On August 26, 2016, an order confirming the Plan was entered by the Bankruptcy Court. On September 1, 2016, (the “Plan Effective Date”), pursuant to the Plan, the following occurred:

• ARP’s first lien lenders received cash payment of all obligations owed to them by ARP pursuant to the senior secured revolving credit facility (other than $440 million of principal and face amount of letters of credit) and became lenders under Titan’s first lien exit facility credit agreement, composed of a $410 million conforming reserve-based tranche and a $30 million non-conforming tranche.

• ARP’s second lien lenders received a pro rata share of Titan’s second lien exit facility credit agreement with an aggregate principal amount of $252.5 million. In addition, ARP’s second lien lenders received a pro rata share of 10% of Titan’s common shares, subject to dilution by a management incentive plan.

• ARP’s senior note holders, in exchange for 100% of the $668 million aggregate principal amount of senior notes outstanding plus accrued but unpaid interest as of the commencement of the Chapter 11 Filings, received 90% of Titan’s common shares, subject to dilution by a management incentive plan.

• All of ARP’s preferred limited partnership units and common limited partnership units were cancelled without the receipt of any consideration or recovery.

• ARP transferred all of its assets and operations to Titan as a new holding company and ARP dissolved. As a result, Titan became the successor issuer to ARP for purposes of and pursuant to Rule 12g-3 of the Securities Exchange Act of 1934, as amended.

• Titan Management received a Series A Preferred Share of Titan, which entitles Titan Management to receive 2% of the aggregate of distributions paid to shareholders (as if it held 2% of Titan’s members’ equity, subject to potential dilution in the event of future equity interests) and to appoint four of seven directors and certain other rights. Four of the seven initial members of the board of directors of Titan are designated by Titan Management (the “Titan Class A Directors”). For so long as Titan Management holds such preferred share, the Titan Class A Directors will be appointed by a majority of the Titan Class A Directors then in office. Titan has a continuing right to purchase the preferred share at fair market value (as determined pursuant to the methodology provided for in Titan’s limited liability company agreement), subject to the receipt of certain approvals, including the holders of at least 67% of the outstanding common shares of Titan unaffiliated with Titan Management voting in favor of the exercise of the right to purchase the preferred share.

We were not a party to ARP’s Restructuring. We remain controlled by the same ownership group and management team and thus, ARP’s Restructuring did not have a material impact on the ability of management to operate us or our other businesses.

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

Basis of Presentation and Principles of Consolidation

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 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~~2017.

We determined that ~~ARP (through the Plan Effective Date, as discussed further below) and~~ AGP ~~are~~is a variable interest ~~entities~~entity (“~~VIEs~~VIE”) based on ~~their~~AGP’s ~~respective~~ partnership ~~agreements,~~agreement; our power, as the general partner, to direct the activities that most significantly impact ~~each~~AGP’s ~~of their respective~~ economic performance,; and our ownership of ~~each~~AGP’s ~~of their respective~~ incentive distribution rights. Accordingly, we consolidated the financial statements of ~~ARP (until the date of ARP’s Chapter 11 Filings, as discussed further below) and~~ AGP into our condensed consolidated financial statements. Our consolidated ~~VIEs~~VIE’s operating results and asset balances are presented separately in Note 107 – Operating Segment Information. As the general partner for ~~both ARP (through the Plan Effective Date) and~~ AGP, we have unlimited liability for the obligations of ~~ARP (through the Plan Effective Date) and~~ AGP except for those contractual obligations that are expressly made without recourse to the general partner. The non-controlling interest in AGP is reflected as (income) loss attributable to non-controlling interests in the condensed consolidated statements of operations and as a component of unitholders’ equity on the condensed consolidated balance sheets. All intercompany transactions have been eliminated.

119

recourse to the general partner. The non-controlling interests in ARP (through the date of ARP’s Chapter 11 Filings, as discussed further below) and AGP are reflected as (income) loss attributable to non-controlling interests in the condensed consolidated statements of operations and as a component of unitholders’ equity on the condensed consolidated balance sheets. All material intercompany transactions have been eliminated.

In connection with ARP’s Chapter 11 Filings on July 27, 2016, we deconsolidated ARP’s financial statements from our condensed consolidated financial statements, as we no longer had the power to direct the activities that most significantly impacted ARP’s economic performance; however, we retained the ability to exercise significant influence over the operating and financial decisions of ARP and therefore applied the equity method of accounting for our investment in ARP up to the Plan Effective Date. As a result of these changes, our condensed consolidated financial statements subsequent to ARP’s Chapter 11 Filings will not be comparable to our condensed consolidated financial statements prior to ARP’s Chapter 11 Filings. Our financial results for future periods following the application of equity method accounting will be different from historical trends and the differences may be material.

Certain reclassifications have been made to our condensed consolidated financial statements for the prior year periods to conform to classifications used in the current year, specifically related to ARP’s Drilling Partnerships management, which includes all of ARP’s managing and operating activities specific to ARP’s Drilling Partnerships including well construction and completion, administration and oversight, well services and gathering and processing. We previously presented these revenue and expense items separately; however, due to the deconsolidation of ARP on the date of the Chapter 11 Filings, we have aggregated these items to be presented as one combined revenue item and one combined expense item. As a result of this change, we have restated our prior year condensed consolidated statements of operations to conform to our current presentation.

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 ARP has an interest through the date of ARP’s Chapter 11 Filings. Such interests generally approximated 30%. Our condensed consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of the Drilling Partnerships through the date of ARP’s Chapter 11 Filings. Rather, ARP calculated these items specific to its own economics through the date of ARP’s Chapter 11 Filings.

On the Plan Effective Date, we determined that Titan is a VIE based on its limited liability company agreement and the delegation of management and omnibus agreements between Titan and Titan Management, which provide us the power to direct activities that most significantly impact Titan’s economic performance, but we do not have a controlling financial interest. As a result, we do not consolidate Titan but rather apply the equity method of accounting as we have the ability to exercise significant influence over Titan’s operating and financial decisions.

Liquidity, Capital Resources, and Ability to Continue as a Going Concern

Our primary sources of liquidity are cash distributions received with respect to our ownership interests in AGP, Lightfoot, and Titan and AGP’s annual management fee. However, neither Titan nor AGP are currently paying distributions. In addition, Lightfoot completed a portion of its sale transaction that will result in significantly lower quarterly distributions to us. Our primary cash requirements, in addition to normal operating expenses, are for debt service and capital expenditures, which we expect to fund through operating cash flow, and cash distributions received. Accordingly, our sources of liquidity are currently not sufficient to satisfy ~~our~~the obligations under our credit agreements.

The significant risks and uncertainties related to our primary sources of liquidity raise substantial doubt about our ability to continue as a going concern. IfWe wecontinue ~~are unable~~ to ~~remain~~face insignificant ~~compliance~~liquidity ~~with~~issues ~~the~~and ~~covenants~~are ~~under~~currently ~~our~~considering, ~~credit~~and ~~agreements~~are ~~(as~~likely ~~described~~to ~~in Note 4)~~make, ~~absent~~changes ~~relief~~to ~~from~~ our ~~lenders,~~capital westructure ~~maybe be forced~~ to ~~repay~~maintain orsufficient ~~refinance such indebtedness. Upon the occurrence of an event of default~~liquidity, ~~the~~meet ~~lenders under~~ our ~~credit~~debt ~~agreements~~obligations ~~could~~and ~~elect~~manage ~~to declare all amounts outstanding immediately due~~ and ~~payable~~strengthen ~~and~~our ~~could~~balance ~~terminate~~sheet. Without ~~all~~a ~~commitments~~further toextension ~~extend~~from ~~further~~our ~~credit.~~lenders Ifor another ~~event~~significant oftransaction ~~default~~or ~~occurs~~capital infusion, we ~~will~~do not expect to have sufficient liquidity to repay ~~all~~our offirst ~~our~~lien ~~outstanding~~credit ~~indebtedness~~agreement at June 30, 2018, and as a result, there ~~would~~is be substantial doubt regarding our ability to continue as a going concern.

OnThe ~~September~~amounts ~~29,~~outstanding ~~2017,~~under ~~we entered into an agreement with~~ our ~~lenders to extend the maturity date of our first lien~~ credit ~~agreement~~agreements ~~from~~were ~~September~~classified ~~30,~~as ~~2017~~current toliabilities ~~December~~as ~~29,~~both ~~2017. In~~obligations ~~addition~~are ~~to the $41.2 million of indebtedness~~ due onwithin ~~December~~one ~~29,~~year ~~2017,~~from ~~we classified~~ the ~~remaining~~balance ~~$55.4~~sheet ~~million of outstanding indebtedness under our credit agreements as a current liability, based on the uncertainty regarding future covenant compliance~~date. In total, we have $9584.5 million of outstanding indebtedness under our credit agreements, which is net of $0.96 million of debt discounts and $0.1 million of deferred financing costs, as current portion of long term debt, net on our condensed consolidated balance sheet as of ~~September~~March 3031, ~~2017~~2018.

We continually monitor capital markets and may make changes to our capital structures from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening the balance sheet, meeting debt service obligations and/or achieving cost efficiency. For example, we could pursue options such as refinancing or reorganizing our indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address our liquidity concerns and high debt levels. There is no certainty that we will be able to implement any such options, and we cannot provide any assurances that any refinancing or changes to our debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for our stakeholders, including cancellation of debt income (“CODI”) which would be directly allocated to our unitholders and reported on such unitholders’ separate returns. It is possible additional adjustments to our strategic plan and outlook may occur based on market conditions and our needs at that time, which could include selling assets or seeking additional partners to develop our assets.

Our condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. Our condensed consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If we cannot continue as a going concern, adjustments to the carrying values and classification of our assets and liabilities and the reported amounts of income and expenses could be required and could be material.

Atlas Growth Partners – Liquidity, Capital Resources, and Ability to Continue as a Going Concern

AGP has historically funded its operations, acquisitions and cash distributions primarily through cash generated from operations and financing activities, including its private placement offering completed in 2015. AGP’s future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and continue to remain low in 2017. These lower commodity prices have negatively impacted AGP’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on AGP’s liquidity position.

On November 2, 2016, AGP decided to suspend its current primary offering efforts in light of new regulations and the challenging fund raising environment until such time as market participants have had an opportunity to ascertain the impact of such issues. In addition, AGP’s board of directors suspended its quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order to retain its cash flow. Accordingly, these decisions raise substantial doubt about AGP’s ability to continue as a going concern. Management determined that substantial doubt is alleviated through management’s plans to reduce AGP’s general and administrative expenses, the majority of which represent allocations from us.

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 the fair value of derivative instruments. The ~~oil~~natural ~~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.

Derivative Instruments

We enter into certain financial contracts to manage our exposure to movement in commodity prices. The derivative instruments recorded in the condensed consolidated balance sheets are measured as either an asset or liability at fair value. Changes in the fair value of derivative instruments are recognized currently within gain (loss) on mark-to-market derivatives in our condensed consolidated statements of operations.

We use a market approach fair value methodology to value the assets and liabilities for our outstanding derivative instruments. We manage and report derivative assets and liabilities on the basis of our exposure to market risks and credit risks by counterparty. Commodity derivative instruments are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. These derivative values were calculated by utilizing commodity indices, quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument.

The following table summarizes the commodity derivative activity for the period indicated (in thousands):

		Three Months Ended March 31,
		2018		2017
Gains (losses) recognized on cash settlement	$	(49	)	$	52
Changes in fair value on open derivative contracts		(237	)		705
Gain (loss) on mark-to-market derivatives	$	(286	)	$	757

As of March 31, 2018, we had commodity derivatives for 74,500 barrels at an average fixed price of $52.51. The fair value of our commodity derivatives was a liability of $0.6 million as of March 31, 2018.

Revenue Recognition

On January 1, 2018, we adopted ASU No. 2014–09, Revenue from Contracts with Customers (“new revenue standard”), using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. The adoption of the new revenue standard did not have a material impact on our condensed consolidated financial statements and no cumulative effect adjustment was recorded to beginning unitholder equity. As a result of adopting the new revenue standard, we disaggregated our revenues by product type on our condensed consolidated statements of operations for all periods presented.

Oil, Natural Gas, and NGL Revenues

Our revenues are derived from the sale of oil, natural gas, and NGLs, which is recognized in the period that the performance obligations are satisfied. We generally consider the delivery of each unit (Bbl or MMBtu) to be separately identifiable and represents a distinct performance obligation that is satisfied at a point-in-time once control of the product has been transferred to the customer upon delivery to an agreed upon delivery point. Transfer of control typically occurs when the products are delivered to the purchaser, and title has transferred. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration we expect to receive in exchange for those products. Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction, and that are collected by us from a customer, are excluded from revenue. Payment is generally received one month after the sale has occurred.

Our oil production is primarily sold under market-sensitive contracts that are typically priced at a differential to the New York Mercantile Exchange (“NYMEX”) price or at purchaser posted prices for the producing area. For oil contracts, we generally record sales based on the net amount received.

Our natural gas production is primarily sold under market-sensitive contracts that are typically priced at a differential to the published natural gas index price for the producing area due to the natural gas quality and the proximity to major consuming markets. For natural gas contracts, we generally record wet gas sales (which consists of natural gas and NGLs based on end products after processing) at the wellhead or inlet of the plant as revenues net of transportation, gathering and processing expenses if the processor is the customer and there is no redelivery of commodities to us at the tailgate of the plant. Conversely, we generally record residual natural gas and NGL sales at the tailgate of the plant on a gross basis along with the associated transportation, gathering and processing expenses if the processor is a service provider and there is redelivery of commodities to us at the tailgate of the plant. All facts and circumstances of an arrangement are considered and judgment is often required in making this determination.

Transaction Price Allocated to Remaining Performance Obligations

A significant number of our product sales are short-term in nature generally through evergreen contracts with contract terms of one year or less. These contracts typically automatically renew under the same provisions. For those contracts, we have utilized the practical expedient allowed in the new revenue standard that exempts us from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For product sales that have a contract term greater than one year, we have utilized the practical expedient that exempts us from disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Currently, our product sales that have a contractual term greater than one year have no long-term fixed consideration.

Contract Balances

Under our sales contracts, customers are invoiced once performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities. Accounts receivable attributable to our revenue contracts with customers was $0.5 million and $0.6 million at March 31, 2018 and December 31, 2017, respectively.

Equity Method Investments

Investment in Titan. AtTitan ~~September~~is ~~30, 2017, we had~~ a 2%VIE ~~Series~~based Aon ~~Preferred~~its ~~interest~~limited inliability ~~Titan.~~company Weagreement ~~account~~and ~~for our investment under~~ the ~~equity~~delegation ~~method~~ of ~~accounting~~management ~~due~~and toomnibus ~~our~~agreements ~~ability~~between ~~to exercise significant influence over~~ Titan’s ~~operating~~ and ~~financial decisions. As of September 30, 2017 and December 31, 2016, the net carrying amount of our investment in~~ Titan ~~was $0.2 million and zero~~Management, ~~respectively,~~ which ~~was~~provide ~~included~~us ~~in other assets, net on our condensed consolidated balance sheets. During~~ the ~~three~~power ~~and~~to ~~nine~~direct ~~months~~activities ~~ended~~that ~~September~~most ~~30,~~significantly ~~2017~~impact ~~and~~Titan’s ~~for~~economic ~~the period from the Plan Effective Date to September 30~~performance, ~~2016,~~but we ~~recognized~~do ~~equity~~not ~~method~~have ~~loss~~a ofcontrolling ~~$0.3~~financial ~~million, equity method income of $0~~interest.2 ~~million,~~As ~~and~~a ~~equity method loss of $0.2 million~~result, ~~respectively,~~we ~~within~~do ~~other,~~not ~~net~~consolidate onTitan ~~our~~but ~~condensed~~rather ~~consolidated~~apply ~~statements of operations. On~~ the ~~Plan Effective Date, we recorded our~~ equity method ~~investment~~ of ~~Titan~~accounting atas ~~fair~~we ~~value~~have ofthe ~~$0.6~~ability ~~million,~~to ~~which~~exercise ~~was~~significant ~~recorded~~influence inover ~~gain~~Titan’s onoperating ~~deconsolidation of ARP on our condensed consolidated statements of operations for each of the three~~ and ~~nine~~financial ~~months ended September 30, 2016~~decisions.

13At March 31, 2018, we had a 2% Series A Preferred interest in Titan. As of March 31, 2018 and December 31, 2017, the net carrying amount of our investment in Titan was zero. During the three months ended March 31, 2018 and 2017, we recognized equity income of zero and $0.5 million, respectively, within other revenues, net on our condensed consolidated statements of operations.

Investment in Lightfoot. At ~~September~~March 3031, ~~2017~~2018, we had an approximate 12.0% interest in Lightfoot L.P. and an approximate 15.9% interest in Lightfoot G.P., the general partner of Lightfoot L.P. We account for our investment in Lightfoot under the equity method of accounting due to our ability to exercise significant influence over Lightfoot’s operating and financial decisions. As of ~~September~~March 3031, ~~2017~~2018 and December 31, ~~2016~~2017, the net carrying amount of our investment in Lightfoot was ~~$18~~zero.3 ~~million and $18.7 million, respectively, which was included in other assets, net on our condensed consolidated balance sheets.~~ During the three months ended ~~September~~March 3031, ~~2017~~2018 and ~~2016~~2017, we recognized equity ~~method~~ income of ~~$0.2~~zero ~~million~~ and $0.12 million, respectively, within other revenues, net on our condensed consolidated statements of operations. For the nine months ended September 30, 2017 and 2016, we recognized equity method income of $0.7 million and $0.8 million, respectively, within other, net on our condensed consolidated statement of operations. During the three months ended ~~September~~March 3031, ~~2017~~2018 and ~~2016~~2017, we received ~~net~~ cash distributions of approximately ~~$0.4~~zero ~~million~~ and $0.~~5 million, respectively. For the nine months ended September 30, 2017 and 2016, we received net cash distributions of approximately $1.2 million and $1.~~4 million, respectively.

On August 29, 2017, Lightfoot G.P., Lightfoot L.P. and Lightfoot’s subsidiary, Arc Logistics Partners LP (NYSE: ARCX) (“Arc Logistics”), ~~announced that they~~ entered into a Purchase Agreement and Plan of Merger (the “Merger Agreement”) with Zenith Energy U.S., L.P. (together with its affiliates, “Zenith”), a portfolio company of Warburg Pincus, pursuant to which Zenith will acquire Arc Logistics GP LLC (“Arc GP”), the general partner of Arc Logistics (the “GP Transfer”), and all of the outstanding common units of Arc Logistics (the “Merger” and, together with the GP Transfer, the “Proposed Transaction”). Under the terms of the Merger Agreement, Lightfoot L.P. will receive $14.50 per common unit of Arc Logistics in cash for the approximately 5.2 million common units held by it. Lightfoot G.P. will receive $94.5 million for 100% of the membership interests in Arc GP. ~~We anticipate receiving net proceeds of approximately $21.2 million.~~

~~The~~In ~~completion~~December ~~of the Proposed Transaction is subject to a number of closing conditions~~2017, ~~including,~~Lightfoot ~~among~~closed ~~others,~~on ~~approval by~~ a ~~majority~~portion of the ~~outstanding~~Proposed ~~Arc~~Transaction ~~Logistics~~which ~~common~~resulted ~~unitholders~~in ~~and~~a ~~the~~net ~~expiration~~distribution ofto ~~the~~us ~~waiting period under the Hart-Scott-Rodino Antitrust Improvements Act~~ of ~~1976, as amended~~$21.6 ~~Lightfoot, the owner of Arc GP and approximately 26~~million.8% We ofused the ~~outstanding~~net ~~common~~proceeds ~~units of Arc Logistics, has executed an agreement~~ to ~~vote~~pay indown ~~support of the Proposed Transaction~~$21.6 ~~Additionally,~~million ~~the Proposed Transaction is subject to (i) the closing~~ of ~~the~~our ~~purchase~~first bylien ~~Zenith~~credit and Lightfoot from EFS Midstream Holdings LLC of certain of the interests in Arc Terminals Joliet Holdings, LLC, which indirectly owns, among other things, a crude oil unloading facility and a 4-mile crude oil pipeline in Joliet, Illinois, and (ii) the closing of the purchase by Zenith of a 5agreement.~~51646 %~~ interest (and, subject to certain conditions, an additional 4.16154% interest) in Gulf LNG Holdings Group, LLC (“Gulf LNG”), which owns a liquefied natural gas regasification and storage facility in Pascagoula, Mississippi, from LCP LNG Holdings, LLC, a subsidiary of Lightfoot L.P. (“LCP’).

As a result of Lightfoot’s purchase of certain interests in Arc Terminals Joliet Holdings, LLC, we are expected to own 1.8% in Arc Terminals Joliet Holdings, LLC. We anticipate receiving net proceeds of approximately $3.0 million from LCP selling its interest in Gulf LNG, which is subject to certain closing conditions. 12

The remaining part of the Proposed Transaction is ~~not~~ subject to the closing of the purchase by Zenith of a ~~financing~~5.51646 % ~~condition~~interest (and, ~~closing~~subject isto ~~targeted~~certain atconditions, ~~the~~an ~~end~~additional of4.16154% ~~the~~interest) ~~fourth~~in ~~quarter~~Gulf ofLNG ~~2017~~Holdings orGroup, ~~early~~LLC (“Gulf LNG”), which owns a liquefied natural gas regasification and storage facility in ~~the~~Pascagoula, ~~first~~Mississippi, ~~quarter~~from LCP LNG Holdings, LLC, a subsidiary of ~~2018~~Lightfoot L.P. (“LCP’). We anticipate ~~that~~receiving ~~the~~ net proceeds of approximately $3.0 million from LCP selling its interest in Gulf LNG, which is targeted to close in the ~~Proposed~~second ~~Transaction~~quarter ~~will~~of be2018, ~~used~~and we anticipate using the net proceeds to ~~repay~~pay ~~borrowings~~down ~~under~~a portion of our first lien credit agreement.

InInterest ~~accordance with accounting standards related to the presentation of long-lived assets to be classified as held for sale, we continue to classify Lightfoot as held and used~~ in ~~our~~Joliet condensed financial statements and will continue to do so until the various closing conditions have been satisfied, including approval by a majority of the outstanding Arc Logistics common unitholders and the expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.Terminal

~~Investment~~In inconnection ~~ARP.~~with Asthe aclosing ~~result~~ of ~~deconsolidating~~the ~~ARP~~first ~~and~~portion ~~recording~~of ~~our~~Lightfoot’s ~~equity~~Proposed ~~method~~Transaction ~~investment~~ in ~~ARP~~December a2017, ~~fair~~we ~~value~~acquired ofa ~~zero~~1.8% onownership ~~the~~interest ~~date~~in ofZenith ~~the~~Energy ~~Chapter~~Terminals 11Joliet ~~Filings~~Holdings, weLLC ~~recognized~~(“Joliet aTerminal”) for $463.43 million ~~non-cash gain~~, which is ~~recorded~~included inwithin ~~gain~~other onassets, ~~deconsolidation~~net, ~~of ARP~~ on our condensed ~~combined~~ consolidated ~~statements~~balance ofsheets ~~operations~~as ~~for~~of ~~the~~March ~~three~~31, 2018 and ~~nine~~December ~~months ended September 30~~31, ~~2016,~~2017. ~~and~~Our ~~includes~~investment ain ~~$61.7~~Joliet ~~million~~Terminal ~~gain~~is ~~related~~classified toas ~~the~~a ~~remeasurement~~nonmarketable ofequity ~~our~~security ~~retained~~without ~~noncontrolling~~a ~~investment~~readily todeterminable fair value~~. During~~ ~~the~~and ~~period~~is ~~after~~recorded ~~the~~at ~~Chapter~~cost, 11less ~~Filings~~impairment, ~~through~~if ~~August 31~~any, ~~2016,~~in ~~ARP~~accordance ~~generated~~with athe ~~net~~accounting ~~loss~~guidance ~~and~~measurement ~~therefore~~alternative. If wean ~~did~~observable ~~not~~event ~~record~~occurs, ~~any~~we ~~equity~~would ~~method~~estimate ~~income/(loss)~~the ~~based~~fair onvalue of our ~~25%~~investment ~~proportionate~~based ~~share~~on ~~because~~Level ~~such~~2 ~~loss~~inputs ~~exceeded~~that ~~our~~could ~~investment. Due~~be toderived ~~the~~from ~~cancellation~~observable price changes of ~~ARP’s~~similar ~~preferred~~securities ~~limited~~adjusted ~~partnership~~for ~~units~~insignificant ~~and~~differences ~~common~~in ~~limited~~rights ~~partnership~~and ~~units~~obligations ~~without~~and the ~~receipt~~changes ofin ~~any~~value ~~consideration~~would orbe ~~recovery~~recorded onin ~~the~~other ~~Plan Effective Date~~revenues, wenet noon ~~longer~~our ~~hold~~condensed anconsolidated ~~equity~~statement ~~method~~of ~~investment in ARP~~operations.

Interest in Osprey Sponsor

14At March 31, 2018, we have a membership interest in Osprey Sponsor, which is the sponsor of Osprey. We received our membership interest in recognition of potential utilization, if any, of our office space, advisory services and personnel by Osprey. On July 26, 2017, Osprey, for which certain of our executives, namely Jonathan Cohen, Edward Cohen and Daniel Herz, serve as CEO, Executive Chairman and President, respectively, consummated its initial public offering. Osprey was formed for the purpose of acquiring, through a merger, capital stock exchange, asset acquisition, stock purchase, reorganization, or other similar business transaction, one or more operating businesses or assets. The initial public offering, including the overallotment exercised by the underwriters, generated net proceeds of $275 million through the issuance of 27.5 million units, which were contributed to a trust account and are intended to be applied generally toward consummating a business combination. Our membership interest in Osprey Sponsor is an allocation of 1,250,000 founder shares, consisting of 1,250,000 shares of Class B common stock of Osprey that are automatically convertible into Class A common stock of Osprey upon the consummation of a business combination on a one-for-one basis. Additionally, another 125,000 founder shares have been allocated to our employees other than Messrs. Cohen, Cohen and Herz.

AtPursuant ~~September~~to ~~30,~~the ~~2017,~~Osprey weSponsor ~~have~~limited aliability ~~membership~~company ~~interest in Osprey Sponsor~~agreement, ~~which~~owners isof the ~~sponsor~~founder ofshares ~~Osprey.~~agree Weto ~~received~~(i) ~~our~~vote ~~membership~~their ~~interest~~shares in ~~recognition~~favor of ~~potential~~approving ~~utilization,~~a ifbusiness ~~any~~combination, of(ii) ~~our~~waive ~~office~~their ~~space,~~redemption ~~advisory~~rights ~~services~~in ~~and~~connection ~~personnel~~with bythe ~~Osprey.~~consummation ~~On July 26, 2017, Osprey, for which certain~~ of ~~our~~a ~~executives,~~business ~~namely Jonathan Cohen~~combination, ~~Edward Cohen~~ and ~~Daniel~~(iii) ~~Herz,~~waive ~~serve~~their asrights ~~CEO,~~to ~~Executive~~liquidating ~~Chairman~~distributions ~~and~~from ~~President,~~the ~~respectively,~~trust ~~consummated~~account ~~its~~if ~~initial public offering.~~ Osprey ~~was~~fails ~~formed~~to ~~for~~consummate ~~the~~a ~~purpose~~business ofcombination. ~~acquiring,~~In ~~through a merger~~addition, ~~capital~~Osprey ~~stock~~Sponsor ~~exchange,~~has ~~asset~~agreed ~~acquisition,~~to ~~stock~~not ~~purchase,~~to ~~reorganization~~transfer, assign or ~~other~~sell ~~similar~~any ~~business~~of ~~transaction,~~the ~~one~~founder orshares ~~more~~until ~~operating~~the ~~businesses~~earlier orof ~~assets~~ (ai) ~~“Business~~one ~~Combination”)~~year ~~that~~after ~~Osprey~~the ~~has~~date ~~not~~of ~~yet~~the ~~identified.~~consummation ~~The~~of ~~initial~~a ~~public~~business ~~offering~~combination, ~~including~~or (ii) the ~~overallotment~~date ~~exercised~~on bywhich the ~~underwriters,~~last ~~generated~~sales ~~net~~price ~~proceeds~~ of ~~$275~~Osprey’s ~~million~~common ~~through~~stock ~~the~~equals ~~issuance~~or ofexceeds 27$12.500 ~~million~~per ~~units,~~share ~~which~~(as ~~were~~adjusted ~~contributed~~for tostock asplits, ~~trust~~stock ~~account~~dividends, reorganizations and ~~are~~recapitalizations) ~~intended~~for toany be20 ~~applied~~trading ~~generally~~days ~~toward~~within ~~consummating~~any a30-trading ~~Business~~day ~~Combination.~~period ~~Our~~commencing ~~membership~~150 ~~interest~~days inafter ~~Osprey~~a ~~Sponsor~~business ~~is an allocation of 1~~combination,~~250,000~~ ~~founder~~or ~~shares~~earlier, ~~consisting~~in ofeach 1case,~~250,000~~ ~~shares~~if ofsubsequent ~~Class~~to Ba ~~common~~business ~~stock~~combination, of Osprey ~~that~~consummates ~~are~~a ~~automatically~~subsequent ~~convertible~~liquidation, ~~into~~merger, ~~Class A common~~ stock ofexchange, ~~Osprey~~reorganization ~~upon~~or ~~the~~other ~~consummation~~similar oftransaction awhich ~~Business~~results ~~Combination~~in onall aof ~~one-for-one~~Osprey’s ~~basis.~~stockholders ~~Additionally,~~having ~~another~~the ~~125,000~~right ~~founder shares have been allocated~~ to ~~our~~exchange ~~employees~~their ~~other~~common ~~than~~stock ~~Messrs.~~for ~~Cohen~~cash, ~~Cohen~~securities ~~and~~or ~~Herz~~other property.

~~Pursuant~~On toJune ~~the~~4, 2018, Osprey ~~Sponsor~~entered ~~limited~~into ~~liability~~a ~~company~~definitive agreement, ~~owners~~to ofacquire the ~~founder~~assets ~~shares~~of ~~agree~~Royal toResources (i“Royal”), ~~vote~~an ~~their~~entity ~~shares~~owned inby ~~favor~~funds ofmanaged ~~approving~~by aBlackstone ~~Business~~Energy ~~Combination,~~Partners ~~(ii)~~and ~~waive~~Blackstone ~~their~~Capital ~~redemption~~Partners ~~rights~~(“Blackstone”), ~~in connection with~~ (the ~~consummation~~“Business ofCombination”). aThe ~~Business~~acquired ~~Combination,~~Royal ~~and~~assets ~~(iii)~~represent ~~waive~~the ~~their~~entirety ~~rights~~of toBlackstone’s ~~liquidating~~mineral ~~distributions~~interests ~~from~~in the ~~trust~~Eagle ~~account~~Ford ifShale. ~~Osprey~~The ~~fails~~combined tocompany ~~consummate~~will abe ~~Business~~named ~~Combination.~~Falcon InMinerals ~~addition,~~Corporation ~~Osprey~~and ~~Sponsor~~will ~~has~~be ~~agreed~~led toby ~~not~~Osprey’s tomanagement ~~transfer,~~team. Blackstone ~~assign~~will orretain ~~sell~~a ~~any~~significant ofownership ~~the~~stake ~~founder~~at ~~shares~~closing ~~until~~representing ~~the~~approximately ~~earlier~~47% of ~~(i)~~outstanding ~~one~~common ~~year~~stock. ~~after~~Under the ~~date~~terms of the ~~consummation of a~~ Business Combination, ~~or (ii)~~ the ~~date~~obligations onof ~~which~~ the ~~last~~parties ~~sales~~to ~~price~~consummate ofthe ~~Osprey’s~~transactions ~~common~~are ~~stock~~subject ~~equals~~to ora ~~exceeds~~number ~~$12.00~~of ~~per~~customary ~~share~~conditions, ~~(as adjusted for stock splits~~including, ~~stock~~among ~~dividends~~others, ~~reorganizations~~the ~~and~~receipt ~~recapitalizations)~~of ~~for~~required ~~any~~approvals 20of ~~trading~~Osprey’s ~~days~~stockholders ~~within~~of ~~any~~the ~~30-trading~~Business ~~day~~Combination. ~~period~~We ~~commencing~~will ~~150~~recognize ~~days~~the ~~after~~fair avalue ~~Business~~of ~~Combination,~~our orinvestment ~~earlier,~~ in ~~each~~Osprey ~~case,~~upon ifclosing ~~subsequent~~of tothe a Business Combination, ~~Osprey~~and ~~consummates~~conversion aof ~~subsequent~~our ~~liquidation,~~Osprey ~~merger,~~Sponsor ~~stock~~founder ~~exchange,~~shares ~~reorganization~~into orClass ~~other~~A ~~similar~~shares ~~transaction which results in all~~ of Osprey~~’s stockholders having the right to exchange their common stock for cash, securities or other property~~.

We have determined that Osprey Sponsor is a VIE based on its limited liability company agreement. Through our direct interest and indirectly through the interests of our related parties, we have certain characteristics of a controlling financial interest and the power to direct activities that most significantly impact Osprey Sponsor’s economic performance; however, we are not the primary beneficiary. As a result, we do not consolidate Osprey Sponsor but rather apply the equity method of accounting as we, through our direct interest and indirectly through the interests of our related parties, have the ability to exercise significant influence over Osprey Sponsor’s operating and financial decisions. As of September 30, 2017, the net carrying amount of our interest in Osprey Sponsor was zero as our membership interest was received in recognition of potential utilization, if any, of our office space, advisory services and personnel by Osprey, and we have provided a nominal amount of services to Osprey as of September 30, 2017. During the three and nine months ended September 30, 2017, we did not recognize any equity method income as Osprey Sponsor has no operations.

1513

ability to exercise significant influence over Osprey Sponsor’s operating and financial decisions. As of March 31, 2018 and December 31, 2017, the net carrying amount of our interest in Osprey Sponsor was zero as our membership interest was received in recognition of potential utilization, if any, of our office space, advisory services and personnel by Osprey, and we have provided a nominal amount of services to Osprey as of March 31, 2018. During the three months ended March 31, 2018, we did not recognize any equity method income as Osprey Sponsor has no operations.

Rabbi Trust

In 2011, we established an excess 401(k) plan relating to certain executives. In connection with the plan, we established a “rabbi” trust for the contributed amounts. At ~~September~~March 3031, ~~2017~~2018 and December 31, ~~2016~~2017, we reflected $20.32 million and $4.1.5 million, respectively, related to the value of the rabbi trust within other assets, net on our condensed consolidated balance sheets, and recorded corresponding liabilities of $20.32 million and $4.1.5 million, respectively, as of those same dates, within asset retirement obligations and other on our condensed consolidated balance sheets. During the ~~nine~~three months ended ~~September~~March 3031, ~~2017~~2018 and ~~2016~~2017, we distributed $2.1.3 million and $2.31 million, respectively, to certain executives related to the rabbi trust.

Accrued Liabilities

We had $73.7 million and $106.6 million of accrued payroll and benefit items at ~~September~~March 3031, ~~2017~~2018 and December 31, ~~2016~~2017, respectively, which were included within accrued liabilities on our condensed consolidated balance sheets.

Share Based Compensation Plans

For the nine months ended September 30, 2017, 764,900 phantom units under the 2015 Long-Term Incentive Plan (“2015 LTIP”) were forfeited, primarily due to Titan’s completion of the majority of the sale of its Appalachian assets and reductions in workforce, which resulted in a $2.4 million reversal of previously recognized stock compensation expense recorded in general and administrative expenses on our condensed consolidated statements of operation for the nine months ended September 30, 2017.

Conversion of Series A Preferred Units

On May 5, 2017, the holders of all 1.9 million of our outstanding Series A Preferred Units elected to convert their units into 5.9 million common units.

Net Income (Loss) Per Common Unit

Basic net income (loss) attributable to common unitholders per unit is computed by dividing net income (loss) attributable to common unitholders, which is determined after the deduction of net income attributable to participating securities and the preferred unitholders’ interests, if applicable, by the weighted average number of common units outstanding during the period.

Unvested unit-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities. A portion of our phantom unit awards, which consist of common units issuable under the terms of our long-term incentive plans and incentive compensation agreements, contain non-forfeitable rights to distribution equivalents. The participation rights result in a non-contingent transfer of value each time we declare a distribution or distribution equivalent right during the award’s vesting period. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. As such, the net income utilized in the calculation of net income (loss) per unit must be after the allocation of only net income to the phantom units on a pro-rata basis.

The following is a reconciliation of net income (loss) allocated to the common unitholders for purposes of calculating net income (loss) attributable to common unitholders per unit (in thousands):

	Three Months Ended September 30						Nine Months Ended September 30
	Three Months Ended March 31,
		2017		2016				2017		2016
	2018			2017
Net income (loss)	$	(7,341	)	$	13,568		$	(15,669	)	$	(138,421	)
Net loss	$	(6,962	)	$	(4,903	)
Preferred unitholders’ dividends		—		—	—			—			~~(339~~	)
Loss attributable to non-controlling interests		~~1,022~~894			~~23,619~~281			~~1,646~~			~~132,916~~
Net income (loss) attributable to common unitholders		(6,319	)		37,187			(14,023	)		(5,844	)
Net loss attributable to common unitholders		(6,068	)		(4,622	)
Less: Net income attributable to participating securities – phantom units(1)		—			~~(496~~—	)		—			—
Net income (loss) utilized in the calculation of net loss attributable to common unitholders per unit – diluted(1)	$	(6,319	)	$	36,691		$	(14,023	)	$	(5,844	)
Net loss utilized in the calculation of net loss attributable to common unitholders per unit – diluted	$	(6,068	)	$	(4,622	)

(1) ~~For~~Net ~~the~~income ~~three months ended September 30, 2017, net~~ (loss) attributable to common ~~unitholder’s~~unitholders ~~ownership~~for ~~interest~~the ~~was~~net ~~not~~income ~~allocated~~(loss) attributable to ~~approximately~~common ~~34,000~~unitholders ~~phantom~~per ~~units,~~unit ~~because~~calculation ~~the~~is ~~contractual~~net ~~terms~~income of(loss) ~~the~~attributable ~~phantom~~to ~~units~~common asunitholders, ~~participating~~less ~~securities~~income doallocable ~~not require the holders~~ to ~~share~~participating ~~in the losses of the entity~~securities. For the ~~nine~~three months ended ~~September~~March 3031, ~~2017~~2018 and ~~2016~~2017, net loss attributable to common unitholder’s ownership interest was not allocated to ~~approximately 82~~12,000 and ~~322~~178,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity.

Diluted net income (loss) attributable to common unitholders per unit is calculated by dividing net income (loss) attributable to common unitholders, less income allocable to participating securities, by the sum of the weighted average

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number of common unitholder units outstanding and the dilutive effect of unit option awards and convertible preferred units, as calculated by the treasury stock or if converted methods, as applicable. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of our long-term incentive plan.

The following table sets forth the reconciliation of our weighted average number of common units used to compute basic net loss attributable to common unitholders per unit with those used to compute diluted net loss attributable to common unitholders per unit (in thousands):

	Three Months Ended September 30				Nine Months Ended September 30
	Three Months Ended March 31,
		2017		2016		2017	2016
	2018		2017
Weighted average number of common units—basic	31,973	~~31,973~~		26,~~038~~062		~~29,288~~	~~26,032~~
Add effect of dilutive incentive awards(1)		—		~~2,490~~—		—	—
Add effect of dilutive convertible preferred units and warrants(2)		—		~~8,300~~—		—	—
Weighted average number of common units—diluted	31,973	~~31,973~~		3626,~~828~~062		~~29,288~~	~~26,032~~

(1) For the three months ended ~~September~~March 3031, 2018 and 2017, approximately 2,~~926~~299,000 phantom units were excluded from the computation of diluted net income (loss) attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive. For the nine months ended September 30, 2017, and ~~2016, approximately~~ 3,~~195~~521,000 ~~and 2,623,000~~ phantom units, respectively, were excluded from the computation of diluted net income (loss) attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive.

(2) For ~~each of~~ the three ~~and nine~~ months ended ~~September~~March 3031, ~~2017,~~2018 and ~~the nine months ended September 30~~2017, ~~2016,~~ our warrants issued in connection with the ~~Second~~second ~~Lien~~lien ~~Credit~~credit ~~Agreement~~agreement were excluded from the computation of diluted earnings attributable to common unitholders per unit because the inclusion of such warrants ~~and units~~ would have been anti-dilutive. For ~~each of~~ the three ~~and nine~~ months ended ~~September~~March 3031, ~~2016~~2017, our convertible Series A Preferred Units were excluded from the computation of diluted earnings attributable to common unitholders per unit, because the inclusion of such ~~warrants and~~ units would have been anti-dilutive.

Recently Issued Accounting Standards

In February 2016, the Financial Accounting Standards Board (“FASB”) updated the accounting guidance related to leases. The updated accounting guidance requires lessees to recognize a lease asset and liability at the commencement date of all leases (with the exception of short-term leases), initially measured at the present value of the lease payments. The updated guidance is effective for us as of January 1, 2019 and requires a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest period presented. We are currently in the process of determining the impact that the updated accounting guidance will have on our condensed consolidated financial statements.

In ~~May~~January ~~2014~~2016, the FASB updated the accounting guidance related to ~~revenue~~the recognition. ~~The~~and ~~updated~~measurement ~~accounting~~of ~~guidance~~financial ~~provides~~assets aand ~~single, contract-based revenue recognition model to help improve~~ financial ~~reporting~~liabilities. byThe ~~providing~~updated ~~clearer~~accounting guidance, onamong ~~when~~other ~~an entity should recognize revenue~~things, ~~and~~requires bythat ~~reducing~~all ~~the~~nonconsolidated ~~number~~equity ofinvestments, ~~standards~~except tothose ~~which~~accounted anfor ~~entity~~under ~~has~~the toequity ~~refer.~~method, Inbe ~~July~~measured ~~2015,~~at ~~the~~fair ~~FASB~~value ~~voted~~and tothat ~~defer~~ the ~~effective~~changes ~~date~~in byfair ~~one~~value ~~year~~be torecognized ~~December 15,~~in ~~2017~~net ~~for~~income. ~~annual~~The ~~reporting~~accounting ~~periods~~guidance ~~beginning~~requires ~~after~~nonmarketable ~~that~~equity ~~date.~~securities Weto ~~have~~be ~~made~~recorded ~~progress~~at oncost ~~our contract reviews~~ and ~~documentation.~~adjusted ~~Substantially~~to ~~all~~fair ofvalue ~~our~~at ~~revenue~~each isreporting ~~earned~~period. ~~pursuant~~However, tothe ~~agreements~~guidance ~~under~~allows ~~which~~for wea ~~have~~measurement ~~currently interpreted one performance obligation~~alternative, which is ~~satisfied at a point-in-time. We are currently unable~~ to ~~reasonably~~record ~~estimate~~ the ~~expected~~investments ~~financial~~at ~~statement~~cost, ~~impact;~~less ~~however~~impairment, weif doany, ~~not~~and ~~believe~~subsequently ~~the~~adjust ~~new~~for ~~accounting~~observable ~~guidance~~price ~~will~~changes ~~have~~of aidentical ~~material~~or ~~impact~~similar oninvestments ~~our financial position, results~~ of ~~operations~~the orsame ~~cash flows~~issuer. We ~~intend~~adopted ~~to adopt~~ the new accounting guidance ~~using~~on ~~the~~January 1, ~~modified~~2018 ~~retrospective~~and ~~method.~~applied ~~The~~the ~~new~~measurement ~~accounting~~alternative ~~guidance~~to ~~will require that~~ our ~~revenue~~interest ~~recognition~~in ~~policy~~Joliet ~~disclosures~~Terminal ~~include further detail regarding our performance obligations~~ as tothere ~~the~~is ~~nature,~~not ~~amount,~~a ~~timing,~~readily ~~and~~determinable ~~estimates~~fair ofvalue ~~revenue~~for ~~and cash flows generated from~~ our ~~contracts with customers~~investment.

NOTE 3—PROPERTY, PLANT AND EQUIPMENT

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

	September 30,				December 31,
	March 31, 2018			December 31, 2017
	2017				2016
Natural gas and oil properties:
Natural gas and oil properties:
Proved properties	$	152,581		$	147,932
Proved properties	$	84,619			$	84,631
Support equipment and other		3,180			3,188
Unproved properties		63,325				63,314
		155,761			151,120
Support equipment and other		3,188				3,188
Less – accumulated depreciation, depletion and amortization		(86,798	)		(85,827	)
Total natural gas and oil properties		151,132				151,133
	$	68,963		$	65,293
Less – accumulated depreciation, depletion and amortization		(85,078	)			(82,234	)
	$	66,054			$	68,899

As of September 30, 2017, we did not have any non-cash investing activity capital expenditures. During the nine months ended September 30, 2016, we recognized $20.6 million of non-cash investing activities capital expenditures, which were reflected within the changes in accounts payable and accrued liabilities on our condensed consolidated statement of cash flows. 15

WeDuring ~~capitalized~~the ~~interest~~three onmonths ~~ARP’s~~ended ~~borrowed~~March ~~funds~~31, ~~related~~2018, towe ~~capital~~recognized ~~projects~~$4.4 ~~only~~million ~~for~~of ~~periods~~non-cash ~~that~~investing activities ~~were~~capital inexpenditures, ~~progress~~which towere ~~bring~~included ~~these~~within ~~projects~~the tochanges ~~their~~in ~~intended~~accounts ~~use.~~payable ~~The~~and ~~weighted~~accrued ~~average~~liabilities ~~interest rates used to capitalize interest~~ on ~~combined~~our ~~borrowed~~condensed ~~funds~~consolidated bystatements ~~ARP~~of ~~were~~cash 6flows.3% ~~and~~As ~~6.6%~~of ~~for~~March ~~the three and nine months ended September 30~~31, ~~2016~~2017, ~~respectively.~~we ~~The~~did ~~aggregate~~not ~~amount~~have ofany ~~interest~~non-cash ~~capitalized~~investing byactivity ~~ARP~~capital ~~was $0~~expenditures.~~6 million and $5.4 million for the three and nine months ended September 30, 2016, respectively.~~

For the three and nine months ended September 30, 2016, we recorded $0.6 million and $4.0 million, respectively, of ARP’s accretion expense related to asset retirement obligations within depreciation, depletion and amortization in our condensed consolidated statements of operations.

NOTE 4—DEBT

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

	September 30,			December 31,
	March 31,			December 31,
	2017			2016
	2018			2017
First Lien Credit Agreement	$	4121,~~172~~232		$	3720,~~962~~666
Second Lien Credit Agreement	63,958	~~55,366~~			4459,~~593~~552
Debt discount, net of accumulated amortization of $934 and $623		(934	)		(1,244	)
Debt discount, net of accumulated amortization of $1,245 and $1,090	(622		)		(778	)
Deferred financing costs, net of accumulated amortization of $2,677 and $2,538, respectively		(113	)		(211	)
Deferred financing costs, net of accumulated amortization of $2,747 and $2,704, respectively	(101		)		(90	)
Total debt, net	84,467	~~95,491~~			8179,~~100~~350
Less current maturities	(84,467	~~(95,491~~	)		(8179,~~100~~350	)
Total long-term debt, net	$	—		$	—

~~Cash~~The ~~Interest.~~estimated ~~Cash~~fair ~~payments~~value ~~for~~of ~~interest~~our ~~were~~debt ~~$0.3~~at ~~million~~March ~~and~~31, ~~$0.2~~2018 ~~million~~approximated ~~for~~its ~~the~~carrying ~~three~~value ~~months~~of ~~ended~~$84.6 ~~September 30~~million, ~~2017~~which ~~and~~consisted ~~2016,~~of ~~respectively,~~credit ~~and~~agreements ~~$0.7~~that ~~million~~bear ~~and~~interest ~~$55.6~~at ~~million~~variable ~~for~~rates ~~the~~and ~~nine~~are ~~months~~categorized ~~ended~~as ~~September~~Level ~~30,~~1 ~~2017 and 2016, respectively~~values.

Cash Interest. Cash payments for interest were $0.2 million and $0.2 million for the three months ended March 31, 2018 and 2017, respectively.

Credit Agreements

First Lien Credit Agreement. OnOur ~~March~~first 30lien credit agreement with Riverstone Credit Partners, ~~2016~~L.P., weas administrative agent (“Riverstone”), ~~together~~and ~~with~~the ~~New~~lenders ~~Atlas~~(the ~~Holdings,~~“Lenders”) ~~LLC~~from time to time party thereto (the “~~Borrower~~First Lien Credit Agreement”), was scheduled to mature on September 30, 2017. Between September 29, 2017 and ~~Atlas~~April ~~Lightfoot~~26, ~~LLC~~2018, we entered into a ~~third~~series ~~amendment~~of (amendments to extend the ~~“Third~~maturity ~~Amendment”)~~of our First Lien Credit Agreement to ~~our~~June ~~credit~~30, ~~agreement~~2018. The ~~with~~First ~~Riverstone~~Lien Credit ~~Partners,~~Agreement Lhas an applicable cash interest rate margin for ABR Loans and Eurodollar Loans of 0.P50% and 1.50%, asrespectively, ~~administrative~~and ~~agent~~an ~~(“Riverstone”),~~11% ~~and~~interest ~~the~~rate ~~lenders~~payable (in-kind through an increase in the ~~“Lenders”)~~outstanding ~~from~~principal. ~~time~~As toof ~~time~~March ~~party~~31, ~~thereto~~2018, (we were not in compliance with the “financial covenants required by the First Lien Credit Agreement”).

18Second Lien Credit Agreement. Our second lien credit agreement with Riverstone and the Lenders (the “Second Lien Credit Agreement”) matures on March 30, 2019 and has an unamortized discount of $0.6 million as of March 31, 2018, related to the 4,668,044 warrants issued in connection with the Second Lien Credit Agreement. Borrowings under the Second Lien Credit Agreement bear interest at a rate of 30%, payable in-kind through an increase in the outstanding principal. As of March 31, 2018, we were not in compliance with the financial covenants required by the Second Lien Credit Agreement.

The outstanding loans under the First Lien Credit Agreement were bifurcated between the existing First Lien Credit Agreement and the new Second Lien Credit Agreement (defined below), with $35.0 million and $35.8 million (including $2.4 million in deemed prepayment premium) in borrowings outstanding, respectively. As a result of these transactions, we recognized $6.1 million as a loss on early extinguishment of debt, consisting of the $2.4 million prepayment penalty and $3.7 million of accelerated amortization of deferring financing costs, on our condensed consolidated statement of operations for the nine months ended September 30, 2016. The Third Amendment amended the First Lien Credit Agreement to, among other things:

• provide the ability for us and the Borrower to enter into the new Second Lien Credit Agreement (defined below);

• shorten the maturity date of the First Lien Credit Agreement to September 30, 2017, subject to an optional extension to September 30, 2018 by the Borrower, assuming certain conditions are met, including a First Lien Leverage Ratio (as defined in the First Lien Credit Agreement) of not more than 6:00 to 1:00 and a 5% extension fee. On September 29, 2017, we entered into a further amendment to extend the maturity date of our First Lien Credit Agreement to December 29, 2017;

• modify the applicable cash interest rate margin for ABR Loans and Eurodollar Loans to 0.50% and 1.50%, respectively, and add a pay-in-kind interest payment of 11% of the principal balance per annum;

• allow the Borrower to make mandatory pre-payments under the First Lien Credit Agreement or the new Second Lien Credit Agreement, in its discretion, and add additional mandatory pre-payment events, including a monthly cash sweep for balances in excess of $4 million;

• provide that the First Lien Credit Agreement may be prepaid without premium;

• replace the existing financial covenants with (i) the requirement that we maintain a minimum of $2 million in EBITDA on a trailing twelve-month basis, beginning with the quarter ending June 30, 2016, and (ii) the incorporation into the First Lien Credit Agreement of the financial covenants included in ARP’s credit agreement, beginning with the quarter ending June 30, 2016;

• prohibit the payment of cash distributions on our common and preferred units;

• require the receipt of quarterly distributions from Atlas Growth Partners, GP, LLC and Lightfoot; and

• add a cross-default provision for defaults by ARP.

On October 6, 2016, we entered into a fourth amendment to the First Lien Credit Agreement with Riverstone and the Lenders, effective as of September 1, 2016, that makes conforming changes to reflect the status of Titan as the successor to ARP following the consummation of the Chapter 11 Filings and also removed the financial covenants and related cross-defaults that had previously been incorporated from ARP’s credit agreement.

Second Lien Credit Agreement. Also on March 30, 2016, we and the Borrower entered into a new second lien credit agreement (the “Second Lien Credit Agreement”) with Riverstone and the Lenders. As described above, $35.8 million of the indebtedness previously outstanding under the First Lien Credit Agreement was moved under the Second Lien Credit Agreement. The Second Lien Credit Agreement also has an unamortized discount of $0.9 million as of September 30, 2017, related to the 4,668,044 warrants issued in connection with the Second Lien Credit Agreement.

The Second Lien Credit Agreement matures on March 30, 2019, subject to an optional extension (the “Extension Option”) to March 30, 2020, assuming certain conditions are met, including a Total Leverage Ratio (as defined in the Second Lien Credit Agreement) of not more than 6:00 to 1:00 and a 5% extension fee. Borrowings under the Second Lien Credit Agreement are secured on a second priority basis by security interests in the same collateral that secures borrowings under the First Lien Credit Agreement.

Borrowings under the Second Lien Credit Agreement bear interest at a rate of 30%, payable in-kind through an increase in the outstanding principal. If the First Lien Credit Agreement is repaid in full prior to March 30, 2018, the rate will be reduced to 20%. If the Extension Option is exercised, the rate will again be increased to 30%. If our market capitalization is greater than $75 million, we can issue common units in lieu of increasing the principal to satisfy the interest obligation.

The Borrower may prepay the borrowings under the Second Lien Credit Agreement without premium at any time. The Second Lien Credit Agreement includes the same mandatory prepayment events as the First Lien Credit Agreement, subject to the Borrower’s discretion to prepay either the First Lien Credit Agreement or the Second Lien Credit Agreement.

The Second Lien Credit Agreement contains the same negative and affirmative covenants and events of default as the First Lien Credit Agreement, including customary covenants that limit the Borrower’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from the distribution, merge into or consolidate with other persons, enter into swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions. In addition, the Second Lien Credit Agreement requires that we maintain an Asset Coverage Ratio (as defined in the Second Lien Credit Agreement) of not less than 2.00 to 1.00 as of September 30, 2017 and each fiscal quarter ending thereafter.

In connection with the First Lien Credit Agreement and Second Lien Credit Agreement, the lenders thereunder continued their syndicated participation in the underlying loans consistent with the original term loan facilities and therefore certain of the Company’s current and former officers participated in approximately 12% of the loan syndication and warrants and a foundation affiliated with a 5% or more unitholder participated in approximately 12% of the loan syndication.

OnThe ~~October~~amounts 6,outstanding ~~2016,~~under weour ~~entered~~First ~~into~~Lien aCredit ~~first~~Agreement ~~amendment~~and ~~to the~~ Second Lien Credit Agreement ~~with~~were ~~Riverstone~~classified ~~and~~as ~~the~~current ~~Lenders,~~liabilities ~~effective~~ as ofboth ~~September~~obligations 1,are ~~2016,~~due ~~that~~within ~~makes~~one ~~conforming~~year ~~changes~~from tothe ~~reflect~~balance ~~the~~sheet ~~status~~date. In total, we have $84.5 million of ~~Titan~~outstanding asindebtedness ~~the~~under ~~successor~~our tocredit ~~ARP~~agreements, ~~following~~which ~~the~~is ~~consummation~~net of ~~the~~$0.6 ~~Chapter~~million 11of ~~Filings~~debt discounts and ~~also~~$0.1 ~~removes~~million ~~the~~of ~~financial~~deferred ~~covenants~~financing ~~and~~costs, ~~related~~as ~~cross-defaults~~current ~~that~~portion ~~had~~of ~~previously~~long ~~been~~term ~~incorporated~~debt, ~~from~~net ~~ARP’s~~on ~~credit~~our ~~agreement~~condensed consolidated balance sheet as of March 31, 2018.

In addition to the $41.2 million of amounts outstanding under our First Lien Credit Agreement due on December 29, 2017, we classified the $55.4 million of amounts outstanding our Second Lien Credit Agreement as a current liability, based on the uncertainty regarding future covenant compliance. In total, we have $95.5 million of outstanding indebtedness under our credit agreements, which is net of $0.9 million of debt discounts and $0.1 million of deferred financing costs, as current portion of long term debt, net on our condensed consolidated balance sheet as of September 30, 2017.16

NOTE 5—~~DERIVATIVE~~CERTAIN ~~INSTRUMENTS~~RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

WeRelationship ~~use~~with Titan. Other than its named executive officers, Titan does not directly employ any persons to manage or operate its business. These functions were provided by employees of us and/or our affiliates. On September 1, 2016, Titan entered into a ~~number~~Delegation of ~~different~~Management ~~derivative~~Agreement ~~instruments~~(the “Delegation Agreement”) with Titan Management, ~~principally~~our ~~swaps~~wholly owned subsidiary. Pursuant to the Delegation Agreement, Titan has delegated to Titan Management all of Titan’s rights and ~~options~~powers to manage and control the business and affairs of Titan Energy Operating, inLLC ~~connection~~(“Titan Operating”), a wholly owned subsidiary of Titan. However, Titan’s board of directors retains management and control over certain non-delegated duties. In addition, Titan also entered into an Omnibus Agreement (the “Omnibus Agreement”) dated September 1, 2016 with Titan Management, Atlas Energy Resource Services, Inc. (“AERS”), our ~~commodity~~wholly ~~price~~owned ~~risk~~subsidiary, ~~management~~and ~~activities~~Titan Operating. WePursuant doto ~~not~~the ~~apply~~Omnibus ~~hedge~~Agreement, Titan Management and AERS will provide Titan and Titan Operating with certain financial, legal, accounting, tax advisory, financial advisory and engineering services (including cash management services) and Titan and Titan Operating will reimburse Titan Management and AERS for their direct and allocable indirect expenses incurred in connection with the provision of the services, subject to ~~any~~certain approval rights in favor of ~~our~~Titan’s ~~derivative~~Conflicts ~~instruments~~Committee. As aof ~~result~~March 31, ~~gains~~2018 and ~~losses~~December ~~associated~~31, ~~with~~2017, ~~derivative~~we ~~instruments~~had ~~are~~payables ~~recognized~~of $11.1 million and $9.6 million to Titan related to the timing of funding cash accounts related to general and administrative expenses, such as payroll and benefits, which was recorded in ~~earnings~~advances from affiliates in our condensed consolidated balance sheets.

WeRelationship ~~enter~~with ~~into~~AGP. ~~commodity~~AGP ~~future~~does ~~option~~not ~~contracts~~directly employ any persons to ~~achieve~~manage ~~more~~or ~~predictable~~operate ~~cash~~its ~~flows~~business. byThese ~~hedging~~functions ~~our~~are ~~exposure~~provided toby ~~changes~~employees inof ~~commodity~~us ~~prices.~~and/or Atour ~~any~~affiliates. ~~point~~Atlas inGrowth ~~time~~Partners, ~~such~~GP, ~~contracts~~LLC ~~may~~(“AGP ~~include~~GP”) ~~regulated~~receives ~~New~~an ~~York~~annual ~~Mercantile~~management ~~Exchange~~fee ~~(“NYMEX”)~~in ~~futures~~connection ~~and~~with ~~options~~its ~~contracts~~management ~~and~~of ~~non-regulated~~AGP ~~over-the-counter~~equivalent ~~futures~~to ~~contracts~~1% ~~with~~of ~~qualified~~capital ~~counterparties~~contributions per annum. ~~NYMEX~~During ~~contracts~~each ~~are~~of ~~generally~~the ~~settled~~three ~~with~~months ~~offsetting~~ended ~~positions~~March 31, ~~but~~2018 ~~may~~and be2017, ~~settled~~AGP bypaid ~~the~~a ~~physical~~management ~~delivery~~fee of ~~the~~$0.6 ~~commodity~~million. ~~Crude~~We ~~oil~~charge ~~contracts~~direct ~~are~~costs, ~~based~~such onas asalary ~~West~~and ~~Texas~~wages, ~~Intermediate~~and ~~(“WTI”)~~allocate ~~index.~~indirect ~~Natural~~costs, ~~gas~~such ~~liquids~~as ~~fixed~~rent ~~price~~for ~~swaps~~offices, ~~are~~to ~~priced~~AGP based on athe ~~WTI~~number ~~crude~~of ~~oil~~its ~~index,~~employees ~~while~~who ~~ethane,~~devoted ~~propane,~~their ~~butane~~time ~~and~~to ~~iso~~activities ~~butane~~on ~~contracts~~its ~~are~~behalf. ~~based~~AGP onreimburses ~~the~~us ~~respective~~at ~~Mt.~~cost ~~Belvieu~~for ~~price~~direct costs incurred on its behalf. ~~These~~AGP ~~contracts~~reimburses ~~were~~all ~~recorded~~necessary atand ~~fair~~reasonable ~~value~~indirect costs allocated by the general partner.

20Relationship with Lightfoot. Jonathan Cohen, Executive Chairman of the Company’s board of directors, is the Chairman of the board of directors of Lightfoot G.P. As part of the relationship, we assumed the obligations under an agreement pursuant to which Messrs. Cohen receives compensation in recognition of his role continued service as chair of Lightfoot G.P. Pursuant to the agreement, Messrs. Cohen receives an amount equal to 10% of the distributions that we receive from the Lightfoot entities, excluding amounts that constitute a return of capital to us. During the three months ended March 31, 2018 and 2017, Messrs and Cohen received compensation in accordance with the above agreement of zero and $0.1 million, respectively.

OnRelationship ~~the~~with ~~date~~Osprey ofSponsor. ~~the~~We ~~Chapter~~received 11our ~~Filings~~membership interest in Osprey Sponsor in recognition of potential utilization, weif ~~deconsolidated~~any, ~~ARP~~of ~~for~~our ~~financial~~office ~~reporting~~space, ~~purposes~~advisory ~~(see~~services ~~Note~~and ~~2).~~personnel ~~The~~by ~~following~~Osprey, ~~table~~for ~~summarizes~~which ~~the~~we ~~commodity~~will ~~derivative~~be ~~activity~~reimbursed ~~and~~at ~~presentation~~cost. inWe ~~our~~have ~~condensed~~provided ~~consolidated~~a ~~statement~~nominal amount of ~~operations~~services ~~for~~to ~~the~~Osprey ~~periods~~as ~~indicated~~of ~~(in~~March ~~thousands):~~31, 2018.

	Three Months Ended September 30,							Nine Months Ended September 30,
		2017			2016			2017		2016
Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets(1)	$	—		$	1,470		$	—	$	10,540
Portion of settlements attributable to subsequent mark—to—market gains(2)		137			3,610			292		88,875
Total cash settlements on commodity derivative contracts	$	137		$	5,080		$	292	$	99,415
Gain (loss) recognized on cash settlement(3)	$	(53	)	$	9,510		$	489	$	(17,846	)
Gain (loss) recognized on open derivative contracts(3)		(396	)		(61	)		453		(342	)
Gain (loss) on mark-to-market derivatives	$	(449	)	$	9,449		$	942	$	(18,188	)

AGP’s Relationship with Titan. At our direction, AGP reimburses Titan for direct costs, such as salaries and wages, charged to AGP based on our employees who incurred time to activities on AGP’s behalf and indirect costs, such as rent and other general and administrative costs, allocated to AGP based on the number of our employees who devoted their time to activities on AGP’s behalf. As of March 31, 2018 and December 31, 2017, AGP had a receivable of $0.1 million from Titan and a payable of $0.1 million to Titan, respectively, related to the direct costs, indirect cost allocation, and timing of funding of cash accounts for operating activities, which was recorded in advances to/from affiliates in the condensed consolidated balance sheets.

Other Relationships. We have other related party transactions with regard to our First Lien Credit Agreement and Second Lien Credit Agreement (1see Note 4) ~~Recognized~~and inour ~~gas~~general partner and ~~oil~~limited ~~production~~partner ~~revenue~~interest in Lightfoot (see Notes 1 and 2).

(2) Excludes the effects of the $235.3 million, net of $8.2 million in ARP’s hedge monetization fees, paid directly to ARP’s First Lien Credit Facility lenders upon the sale of substantially all of ARP’s commodity hedge positions on July 25, 2016 and July 26, 2016.17

~~(3)~~NOTE ~~Recognized~~6—COMMITMENTS inAND ~~gain (loss) on mark-to-market derivatives.~~CONTINGENCIES

The following table summarizes the gross fair values of AGP’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our condensed consolidated balance sheets as of the dates indicated (in thousands):

Offsetting Derivatives as of September 30, 2017	Gross Amounts Recognized			Gross Amounts Offset			Net Amount Presented
Current portion of derivative assets	$	170		$	(102	)	$	68
Long-term portion of derivative assets		33			(15	)		18
Total derivative assets	$	203		$	(117	)	$	86
Current portion of derivative liabilities	$	(102	)	$	102		$	—
Long-term portion of derivative liabilities		(15	)		15			—
Total derivative liabilities	$	(117	)	$	117		$	—
Offsetting Derivatives as of December 31, 2016
Current portion of derivative assets	$	97		$	(97	)	$	—
Long-term portion of derivative assets		—			—			—
Total derivative assets	$	97		$	(97	)	$	—
Current portion of derivative liabilities	$	(381	)	$	97		$	(284	)
Long-term portion of derivative liabilities		(280	)		—			(280	)
Total derivative liabilities	$	(661	)	$	97		$	(564	)

At September 30, 2017, AGP had the following commodity derivatives:

Type	Production Period Ending December 31,	Volumes(1)	Average Fixed Price(1)		Fair Value Asset
					(in thousands)(2)
Crude Oil – Fixed Price Swaps	2017(3)	26,100	$	53.517	$	46
	2018	74,500	$	52.510	$	40
				AGP’s net assets		86

(1) Volumes for crude oil are stated in barrels.

(2) Fair value of crude oil fixed price swaps are based on forward West Texas Intermediate (“WTI”) crude oil prices, as applicable.

(3) The production volumes for 2017 include the remaining three months of 2017 beginning October 1, 2017.

NOTE 6—FAIR VALUE OF FINANCIAL INSTRUMENTS

Assets and Liabilities Measured at Fair Value on a Recurring Basis

We use a market approach fair value methodology to value our outstanding derivative contracts and financial instruments. The fair value of a financial instrument depends on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. We separate the fair value of our financial instruments into the three level hierarchy (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. As of September 30, 2017 and December 31, 2016, all of our derivative financial instruments were classified as Level 2.

Information for our financial instruments measured at fair value were as follows (in thousands):

	Level 1		Level 2			Level 3		Total
As of September 30, 2017
Assets, gross
Rabbi trust	$	2,312	$	—		$	—	$	2,312
AGP Commodity swaps		—		203			—		203
Total assets, gross		2,312		203			—		2,515
Liabilities, gross
AGP Commodity swaps		—		(117	)		—		(117	)
Total derivative liabilities, gross		—		(117	)		—		(117	)
Total assets, fair value, net	$	2,312	$	86		$	—	$	2,398
As of December 31, 2016
Assets, gross
Rabbi trust	$	4,208	$	—		$	—	$	4,208
AGP Commodity swaps		—		97			—		97
Total assets, gross		4,208		97			—		4,305
Liabilities, gross
AGP Commodity swaps		—		(661	)		—		(661	)
Total derivative liabilities, gross	$	—		(661	)		—		(661	)
Total assets, fair value, net	$	4,208	$	(564	)	$	—	$	3,644

Other Financial Instruments

Our other current assets and liabilities on our 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 debt at September 30, 2017 approximated its carrying value of $96.5 million, which consisted of our First Lien Credit Agreement and Second Lien Credit Agreement that bear interest at variable rates and are categorized as Level 1 values.

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

Management estimated the fair values of ARP’s natural gas and oil properties transferred to ARP in June 2016 upon consolidation of certain Drilling Partnerships (see Note 7) based on a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, ARP’s future operating and development costs of the assets, the respective natural gas, oil and natural gas liquids forward price curves, and estimated salvage values using ARP’s historical experience and external estimates of recovery values. These estimates of fair value were Level 3 measurements as they were based on unobservable inputs.

Management estimated the fair value of asset retirement obligations transferred to ARP in June 2016 upon consolidation of certain Drilling Partnerships (see Note 7) based on discounted cash flow projections using ARP’s historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future considering inflation rates, federal and state regulatory requirements, and ARP’s assumed credit-adjusted risk-free interest rate. These estimates of fair value were Level 3 measurements as they were based on unobservable inputs.

Management estimated the fair value of our equity method investment in ARP based on market data including ARP’s unit price and announcement of restructuring, which are Level 1 measurements as they are based on observable inputs. Management estimated the fair value of our equity method investment in Titan based on its estimated enterprise value and reorganizational value of assets and liabilities upon emergence from bankruptcy through fresh-start accounting utilizing the discounted cash flow method for both its gas and oil production business and its partnership management business based on the financial projections in ARP’s disclosure statement. The resulting fair value of Titan’s equity was used to value our equity method investment. These estimates of fair value are Level 3 measurements as they are based on unobservable inputs.

NOTE 7—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Relationship with ARP. ARP did not directly employ any persons to manage or operate its business. These functions were provided by employees of us and/or our affiliates. On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2).

Relationship with Titan. Other than its named executive officers, Titan does not directly employ any persons to manage or operate its business. These functions were provided by employees of us and/or our affiliates. On September 1, 2016, Titan entered into a Delegation of Management Agreement (the “Delegation Agreement”) with Titan Management, our wholly owned subsidiary. Pursuant to the Delegation Agreement, Titan has delegated to Titan Management all of Titan’s rights and powers to manage and control the business and affairs of Titan Energy Operating, LLC (“Titan Operating”), a wholly owned subsidiary of Titan. However, Titan’s board of directors retains management and control over certain non-delegated duties. In addition, Titan also entered into an Omnibus Agreement (the “Omnibus Agreement”) dated September 1, 2016 with Titan Management, Atlas Energy Resource Services, Inc. (“AERS”), our wholly owned subsidiary, and Titan Operating. Pursuant to the Omnibus Agreement, Titan Management and AERS will provide Titan and Titan Operating with certain financial, legal, accounting, tax advisory, financial advisory and engineering services (including cash management services) and Titan and Titan Operating will reimburse Titan Management and AERS for their direct and allocable indirect expenses incurred in connection with the provision of the services, subject to certain approval rights in favor of Titan’s Conflicts Committee. As of September 30, 2017 and December 31, 2016, we had payables of $13.3 million and $3.3 million to Titan related to the timing of funding cash accounts related to general and administrative expenses, such as payroll and benefits, which was recorded in advances from affiliates in our condensed consolidated balance sheets.

Relationship with AGP. AGP does not directly employ any persons to manage or operate its business. These functions are provided by employees of us and/or our affiliates. Atlas Growth Partners, GP, LLC (“AGP GP”) receives an annual management fee in connection with its management of AGP equivalent to 1% of capital contributions per annum. During each of the three months ended September 30, 2017 and 2016, AGP paid a management fee of $0.6 million, and during each of the nine months ended September 30, 2017 and 2016, AGP paid a management fee of $1.7 million. We charge direct costs, such as salary and wages, and allocate indirect costs, such as rent for offices, to AGP by us based on the number of its employees who devoted their time to activities on its behalf. AGP reimburses us at cost for direct costs incurred on its behalf. AGP reimburses all necessary and reasonable indirect costs allocated by the general partner.

Relationship with Osprey Sponsor. We received our membership interest in Osprey Sponsor in recognition of potential utilization, if any, of our office space, advisory services and personnel by Osprey, for which we will be reimbursed at cost. We have provided a nominal amount of services to Osprey as of September 30, 2017.

Relationship with Drilling Partnerships. ARP conducted certain activities through, and a portion of its revenues were attributable to, sponsorship of the Drilling Partnerships. Through the Plan Effective Date, ARP served as the ultimate general partner and operator of the Drilling Partnerships and assumed customary rights and obligations for the Drilling Partnerships. As the ultimate general partner, ARP was liable for the Drilling Partnerships’ liabilities and could have been liable to limited partners of the Drilling Partnerships if it breached its responsibilities with respect to the operations of the Drilling Partnerships. ARP was entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Drilling Partnership’s revenue and costs and expenses according to the respective partnership agreements.

In March 2016, ARP transferred $36.7 million of investor capital raised and $13.3 million of accrued well drilling and completion costs incurred by ARP to the Atlas Eagle Ford 2015 L.P. private drilling partnership for activities directly related to their program. In June 2016, ARP transferred $5.2 million of funds to certain of the Drilling Partnerships that were projected to make monthly or quarterly distributions to their limited partners over the next several months and/or quarter to ensure accessible distribution funding coverage in accordance with the respective Drilling Partnerships’ operations and partnership agreements in the event ARP experienced a prolonged restructuring period as ARP performed all administrative and management functions for the Drilling Partnerships.

During the quarter ended June 30, 2016, ARP recorded $7.2 million and $12.4 million of gas and oil properties and asset retirement obligations, respectively, transferred to ARP as a result of certain Drilling Partnership liquidations. The gas and oil properties and asset retirement obligations were recorded at their fair values on the respective dates of the Drilling Partnerships’ liquidation and transfer to ARP (see Note 6) and resulted in a non-cash loss of $6.2 million, net of liquidation and transfer adjustments, for the three and nine months ended September 30, 2016, which was recorded in other income/(loss) in the condensed consolidated statements of operations.

AGP’s Relationship with Titan. At our direction, AGP reimburses Titan for direct costs, such as salaries and wages, charged to AGP based on our employees who incurred time to activities on AGP’s behalf and indirect costs, such as rent and other general and administrative costs, allocated to AGP based on the number of our employees who devoted their time to activities on AGP’s behalf. As of September 30, 2017 and December 31, 2016, AGP had payables of $0.1 million and $0.8 million, respectively to Titan related to the direct costs, indirect cost allocation, and timing of funding of cash accounts, which was recorded in advances from affiliates in the condensed consolidated balance sheets.

Other Relationships. We have other related party transactions with regard to our First Lien Credit Agreement and Second Lien Credit Agreement (see Note 4), our Series A preferred units and our general partner and limited partner interest in Lightfoot (see Notes 1 and 2).

NOTE 8—COMMITMENTS AND CONTINGENCIES

Legal Proceedings

We are parties to various routine legal proceedings arising out of the ordinary course of business. Our management and our subsidiaries believe that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations.

Environmental Matters

We are subject to various federal, state and local laws and regulations relating to the protection of the environment. We have established procedures for the ongoing evaluation of our and our subsidiaries’ operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. We maintain insurance which may cover in whole or in part certain environmental expenditures. We had no environmental matters requiring specific disclosure or requiring the recognition of a liability as of ~~September~~March 3031, ~~2017~~2018 and December 31, ~~2016~~2017.

NOTE 97—~~CASH~~OPERATING ~~DISTRIBUTIONS~~SEGMENT INFORMATION

Our ~~Cash~~operations ~~Distributions.~~include Wetwo ~~have~~reportable aoperating ~~cash~~segments: ~~distribution~~AGP ~~policy~~and ~~under~~corporate ~~which~~and weother. ~~distribute,~~These ~~within~~operating 50segments ~~days~~reflected ~~following~~ the ~~end~~way ofwe ~~each~~managed ~~calendar~~our ~~quarter,~~operations ~~all~~and ofmade ~~our~~business ~~available~~decisions. ~~cash~~Corporate ~~(as~~and ~~defined~~other inincludes our ~~limited~~equity ~~liability~~investments ~~company~~in ~~agreement)~~Lightfoot ~~for~~(see ~~that~~Note ~~quarter~~2) toand ~~our~~Titan ~~unitholders.~~(see ~~However~~Note 2), as awell ~~result~~as ofour ~~the~~general ~~First~~and ~~Lien~~administrative ~~Credit~~and ~~Agreement~~interest ~~and~~expenses. ~~Second~~Operating ~~Lien~~segment ~~Credit~~data ~~Agreement~~for ~~entered~~the ~~into~~periods onindicated ~~March~~were ~~30,~~as ~~2016~~follows (~~see~~in ~~Note 4~~thousands)~~, we are prohibited from paying cash distributions on our units. Prior to these amendments,~~ :

	Three Months Ended March 31,
	2018			2017
Atlas Growth Partners:
Revenues⁽¹⁾	$	1,484		$	3,153
Operating costs and expenses		(1,437	)		(2,333	)
Depreciation, depletion and amortization expense		(975	)		(1,112	)
Segment loss	$	(928	)	$	(292	)
Corporate and other:
Revenues	$	47		$	722
General and administrative		(754	)		(404	)
Interest expense		(5,327	)		(4,929	)
Segment loss	$	(6,034	)	$	(4,611	)
Reconciliation of segment loss to net loss:
Segment loss:
Atlas Growth Partners		(928	)		(292	)
Corporate and other		(6,034	)		(4,611	)
Net loss	$	(6,962	)	$	(4,903	)
Reconciliation of segment revenues to total revenues:
Segment revenues:
Atlas Growth Partners		1,484			3,153
Corporate and other		47			722
Total revenues	$	1,531		$	3,875
Capital expenditures:
Atlas Growth Partners		225			—
Total capital expenditures	$	225		$	—

~~during the nine months ended September 30, 2016, we paid a distribution of $1.0 million to our Class A preferred unitholders.~~ 18

ARP Cash Distributions. ARP had a monthly cash distribution program whereby ARP distributed all of its available cash (as defined in the partnership agreement) for that month to its unitholders within 45 days from the month end. If ARP’s common unit distributions in any quarter exceeded specified target levels, we received between 13% and 48% of such distributions in excess of the specified target levels.

		March 31,	December 31,
		2018	2017
Balance sheet:
Total assets:
Atlas Growth Partners	$	76,597	$	74,219
Corporate and other		5,606		9,829
Total assets	$	82,203	$	84,048

During the nine months ended September 30, 2016, ARP paid four monthly cash distributions totaling $5.1 million to common limited partners ($0.0125 per unit per month); $2.5 million to Preferred Class C limited partners ($0.0125 per unit per month); and $0.2 million to the General Partner Class A holder ($0.0125 per unit per month).

During the nine months ended September 30, 2016, ARP paid two distributions totaling $4.4 million to Class D Preferred units ($0.5390625 per unit) for the period October 15, 2015 through April 14, 2016.

During the nine months ended September 30, 2016, ARP paid two distributions totaling $0.3 million to Class E Preferred units ($0.671875 per unit) for the period October 15, 2015 through April 14, 2016.

AGP Cash Distributions. During the nine months ended September 30, 2016, AGP paid a distribution of $12.2 million to common limited partners ($0.1750 per unit per quarter) and $0.3 million to the general partner’s Class A units ($0.1750 per unit per quarter). On November 2, 2016, AGP’s Board of Directors determined to suspend its quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order to retain its cash flow.

NOTE 10—OPERATING SEGMENT INFORMATION

Our operations included three reportable operating segments: ARP (through the date of the Chapter 11 Filings), AGP, and corporate and other. These operating segments reflected the way we managed our operations and made business decisions. Corporate and other includes our equity investments in Lightfoot (see Note 2) and Titan (see Note 2), as well as our general and administrative and interest expenses. Operating segment data for the periods indicated were as follows (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017				2016		2017				2016
Atlas Resource Partners:
Revenues(1)	$	—		$	39,198		$	—		$	125,582
Operating costs and expenses		—			(18,391	)		—			(134,718	)
Depreciation, depletion and amortization expense		—			(8,460	)		—			(67,513	)
Interest expense		—			(9,224	)		—			(68,883	)
Gain on early extinguishment of debt		—			—			—			26,498
Reorganization items, net		—			(21,649	)		—			(21,649	)
Other income (loss)		—			24			—			(6,625	)
Segment loss	$	—		$	(18,502	)	$	—		$	(147,308	)
Atlas Growth Partners:
Revenues(1)	$	1,282		$	2,918		$	6,943		$	8,911
Operating costs and expenses		(1,518	)		(3,274	)		(5,830	)		(10,198	)
Depreciation, depletion and amortization expense		(825	)		(3,898	)		(2,823	)		(11,424	)
Other loss		—			(5,297	)		—			(5,297	)
Segment loss	$	(1,061	)	$	(9,551	)	$	(1,710	)	$	(18,008	)
Corporate and other:
Revenues	$	16		$	121		$	879		$	793
General and administrative(2)		(818	)		(963	)		363			(4,648	)
Interest expense		(5,478	)		(4,488	)		(15,201	)		(10,121	)
Loss on early extinguishment of debt		—			—			—			(6,080	)
Gain on deconsolidation of Atlas Resource Partners, L.P.		—			46,951			—			46,951
Segment income (loss)	$	(6,280	)	$	41,621		$	(13,959	)	$	26,895
Reconciliation of segment income (loss) to net loss:
Segment income (loss):
Atlas Resource Partners	$	—		$	(18,502	)	$	—		$	(147,308	)
Atlas Growth Partners		(1,061	)		(9,551	)		(1,710	)		(18,008	)
Corporate and other		(6,280	)		41,621			(13,959	)		26,895
Net income (loss)	$	(7,341	)	$	13,568		$	(15,669	)	$	(138,421	)
Reconciliation of segment revenues to total revenues:
Segment revenues:
Atlas Resource Partners(1)	$	—		$	39,198		$	—		$	125,582
Atlas Growth Partners(1)		1,282			2,918			6,943			8,911
Corporate and other		16			121			879			793
Total revenues	$	1,298		$	42,237		$	7,822		$	135,286
Capital expenditures:
Atlas Resource Partners	$	—		$	2,335		$	—		$	21,155
Atlas Growth Partners		—			248			—			6,575
Total capital expenditures	$	—		$	2,583		$	—		$	27,730

	September 30,		December 31,
	2017		2016
Balance sheet:
Total assets:
Atlas Growth Partners	$	74,976	$	78,500
Corporate and other		30,454		26,576
Total assets	$	105,430	$	105,076

1)	Revenues include respective portions of gains (losses) on mark—to—market derivatives.

2) As disclosed in Note 2, for the nine months ended September 30, 2017, 764,900 phantom units under the 2015 LTIP were forfeited, primarily due to Titan’s completion of the majority of the sale of its Appalachian assets and reductions in workforce, which resulted in a $2.4 million reversal of previously recognized stock compensation expense recorded in general and administrative expenses on our condensed consolidated statements of operations for the nine months ended September 30, 2017.19

ITEM 2:

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~BUSINESS~~ OVERVIEW

Our operations primarily consisted of our ownership interests in the following:

•

• A 12.0% limited partner interest in Lightfoot Capital Partners, L.P. (“Lightfoot L.P.”) and a 15.9% general partner interest in Lightfoot Capital Partners GP, LLC (“Lightfoot G.P.” and together with Lightfoot L.P., “Lightfoot”), the general partner of Lightfoot L.P., an entity for which Jonathan Cohen, Executive Chairman of the Company’s board of directors, is the Chairman of the board of directors. Lightfoot focuses its investments primarily on incubating new MLPs and providing capital to existing MLPs in need of additional equity or structured debt. On August 29, 2017, Lightfoot announced a proposed sale transaction. Please see “~~Recent~~Item ~~Developments—Lightfoot~~1: ~~Transaction~~Financial Statements – Note 2” for further disclosures regarding Lightfoot; ~~and~~

• A membership interest in the founder shares of Osprey Sponsor, LLC (“Osprey Sponsor”) received in August 2017. Osprey Sponsor is the sponsor of Osprey Energy Acquisition Corp (“Osprey”). We received our membership interest in recognition of potential utilization, if any, of our office space, advisory services and personnel by Osprey. Please see “~~Recent~~Item ~~Developments~~1: –Financial ~~Osprey~~Statements ~~Sponsor~~– ~~Interest~~Note 2” for further disclosures regarding Osprey.;

~~Our~~• ~~cash~~A ~~flows~~2% ~~and~~preferred ~~liquidity~~membership ~~are~~interest ~~substantially~~in ~~dependent~~Titan ~~upon~~Energy, ~~AGP’s~~LLC ~~annual~~(“Titan”), ~~management~~an ~~fee~~independent developer and ~~distributions~~producer ~~from~~of ~~AGP,~~natural ~~Lightfoot~~gas, ~~and~~crude ~~Titan.~~oil ~~Neither~~and ~~AGP~~NGL ~~nor~~with ~~Titan~~operations ~~are~~in ~~currently~~basins ~~paying~~across ~~distributions. Though we consolidate~~ the ~~operations~~United ofStates. ~~AGP~~Titan ~~(and,~~Energy ~~prior to July 27~~Management, ~~2016~~LLC, weour ~~consolidated~~wholly ~~the~~owned ~~operations~~subsidiary of(“Titan ~~ARP~~Management”) ~~for financial reporting purposes~~, ~~AGP’s~~holds ~~annual~~the ~~management~~Series ~~fee~~A ~~and~~Preferred ~~distributions~~Share ~~from~~of ~~Lightfoot~~Titan, ~~are~~which ~~currently~~entitles ~~our~~us ~~only sources of liquidity~~ to ~~satisfy~~receive ~~our~~2% ~~obligations~~of ~~under our credit agreements. In addition,~~ the ~~obligations~~aggregate ~~under~~of ~~our~~distributions ~~first~~paid ~~lien~~to ~~credit~~shareholders ~~agreement~~(as ~~mature~~if ~~in September 2017. As a result,~~ we ~~continue~~held to2% ~~face~~of ~~significant~~Titan’s ~~liquidity~~members’ ~~issues and are currently considering~~equity, ~~and~~subject ~~are likely~~ to ~~make,~~potential ~~changes~~dilution toin ~~our~~the ~~capital~~event ~~structure~~of tofuture ~~maintain~~equity ~~sufficient~~interests) ~~liquidity, meet our debt obligations~~ and ~~strengthen our balance sheet. Please see “Liquidity and Ability~~ to ~~Continue~~appoint asfour aof ~~Going~~seven ~~Concern” for additional disclosures~~directors.

ARP Restructuring and Emergence from Chapter 11 Proceedings

On July 25, 2016, we, solely with respect to certain sections thereof, along with ARP and certain of its subsidiaries, entered into a Restructuring Support Agreement (the “Restructuring Support Agreement”) with certain of ARP’s and their subsidiaries’ lenders (the “Restructuring Support Parties”) to support ARP’s restructuring pursuant to a pre-packaged plan of reorganization (the “Plan”).

On July 27, 2016, ARP and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 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:

• All of ARP’s preferred limited partnership units and common limited partnership units were cancelled without the receipt of any consideration or recovery.

• Titan Management, our wholly owned subsidiary, 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 Titan’s 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. Titan has 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.

LIQUIDITY AND ABILITY TO CONTINUE AS A GOING CONCERN

Our primary sources of liquidity are cash distributions received with respect to our ownership interests in AGP, Lightfoot, and Titan and AGP’s annual management fee. However, neither Titan nor AGP is currently paying distributions. In addition, Lightfoot completed a portion of its sale transaction that will result in significantly lower quarterly distributions to us. Our primary cash requirements, in addition to normal operating expenses, are for debt service and capital expenditures. In addition, the obligations under our first lien credit agreement mature in ~~December~~June ~~2017~~2018. Accordingly, our sources of liquidity are currently not sufficient to satisfy our obligations under our credit agreements.

The significant risks and uncertainties related to our primary sources of liquidity raise substantial doubt about our ability to continue as a going concern. IfWe wecontinue ~~are unable~~ to ~~remain~~face insignificant ~~compliance~~liquidity ~~with~~issues ~~the~~and ~~covenants~~are ~~under~~currently ~~our credit agreements~~considering, ~~absent~~and ~~relief~~are ~~from~~likely ~~our~~to ~~lenders~~make, wechanges ~~may be forced~~ to ~~repay~~our orcapital ~~refinance~~structure ~~such~~to ~~indebtedness.~~maintain ~~Upon~~sufficient ~~the occurrence of an event of default~~liquidity, ~~the~~meet ~~lenders under~~ our ~~credit~~debt ~~agreements~~obligations ~~could~~and ~~elect~~manage ~~to declare all amounts outstanding immediately due~~ and ~~payable~~strengthen ~~and~~our ~~could~~balance ~~terminate~~sheet. Without ~~all~~a ~~commitments~~further toextension ~~extend~~from ~~further~~our ~~credit.~~lenders Ifor another ~~event~~significant oftransaction ~~default~~or ~~occurs~~capital infusion, we ~~will~~do not expect to have sufficient liquidity to repay ~~all~~our offirst ~~our~~lien ~~outstanding~~credit ~~indebtedness~~agreement at June 30, 2018, and as a result, there ~~would~~is be substantial doubt regarding our ability to continue as a going concern.

29The amounts outstanding under our credit agreements were classified as current liabilities as both obligations are due within one year from the balance sheet date. In total, we have $84.5 million of outstanding indebtedness under our credit agreements, which is net of $0.6 million of debt discounts and $0.1 million of deferred financing costs, as current portion of long term debt, net on our condensed consolidated balance sheet as of March 31, 2018.

OnWe ~~September~~continually ~~29,~~monitor ~~2017,~~capital wemarkets ~~entered~~and ~~into~~may anmake ~~agreement~~changes ~~with~~from ~~our~~time ~~lenders~~ to ~~extend~~time ~~the~~to ~~maturity~~our ~~date~~capital ofstructures, ~~our~~with ~~first~~the ~~lien~~goal ~~credit~~of ~~agreement~~maintaining ~~from~~financial ~~September 30~~flexibility, ~~2017~~preserving toor ~~December~~improving 29liquidity, ~~2017.~~strengthening Inthe ~~addition~~balance tosheet, ~~the~~meeting ~~$41.2~~debt ~~million~~service ofobligations ~~indebtedness~~and/or ~~due~~achieving oncost ~~December~~efficiency. ~~29,~~For ~~2017~~example, we ~~classified~~could ~~the~~pursue ~~remaining~~options ~~$55.4~~such ~~million~~as ofrefinancing ~~outstanding~~or ~~indebtedness~~reorganizing ~~under~~ our ~~credit~~indebtedness ~~agreements~~or ascapital astructure ~~current~~or ~~liability,~~seek ~~based~~to onraise ~~the~~additional ~~uncertainty~~capital ~~regarding~~through ~~future~~debt ~~covenant~~or ~~compliance.~~equity Infinancing ~~total,~~to weaddress ~~have $95.5 million of outstanding indebtedness under~~ our ~~credit~~liquidity ~~agreements,~~concerns ~~which~~and ishigh ~~net of $0.9 million of~~ debt ~~discounts and $0~~levels.1 ~~million~~There ofis ~~deferred~~no ~~financing~~certainty ~~costs,~~that aswe ~~current~~will ~~portion~~be ofable ~~long~~to ~~term~~implement ~~debt,~~any ~~net~~such ~~within our condensed consolidated balance sheet as of September 30~~options, ~~2017.~~

We continually monitor capital markets and may make changes from time to time to our capital structures, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening the balance sheet, meeting debt service obligations and/or achieving cost efficiency. For example, we could pursue options such as refinancing or reorganizing our indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address our liquidity concerns and high debt levels. There is no certainty that we will be able to implement any such options, and we cannot provide any assurances that any refinancing or changes to our debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for our stakeholders, including cancellation of debt income (“CODI”) which would be directly allocated to our unitholders and reported on such unitholders’ separate returns. It is possible additional adjustments to our strategic plan and outlook may occur based on market conditions and our needs at that time, which could include selling assets or seeking additional partners to develop our assets20

and we cannot provide any assurances that any refinancing or changes to our debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for our stakeholders, including cancellation of debt income (“CODI”) which would be directly allocated to our unitholders and reported on such unitholders’ separate returns. It is possible additional adjustments to our strategic plan and outlook may occur based on market conditions and our needs at that time, which could include selling assets or seeking additional partners to develop our assets

RECENT DEVELOPMENTS

~~Credit~~AGP ~~Agreement~~Eagle ~~Maturity~~Ford ~~Date~~Drilling. ~~Extension~~AGP deployed $0.2 Onmillion ~~September~~of ~~29,~~cash ~~2017,~~on wehand ~~entered~~during ~~into~~the anquarter ~~agreement~~and ~~with~~$6.3 ~~our~~million ~~lenders~~subsequently to ~~extend~~drill ~~the~~and ~~maturity~~complete ~~date~~one ofEagle ~~our~~Ford ~~first~~Shale ~~lien~~well ~~credit~~that ~~agreement~~turned ~~from~~in-line ~~September~~during 30May 2018. The well is expected to significantly increase AGP’s production and provide substantial cash flow. With this additional well, ~~2017~~AGP will have enhanced ability to ~~December~~generate 29positive cash flow from its operations, ~~2017~~grow its cash balance, and take advantage of opportunities to drill new Eagle Ford Shale wells or take on other strategic initiatives and transactions should favorable conditions arise.

Lightfoot Transaction. On August 29, 2017, Lightfoot G.P. and Lightfoot L.P. and Lightfoot’s subsidiary, Arc Logistics Partners LP (NYSE: ARCX) (“Arc Logistics”), announced that they entered into a Purchase Agreement and Plan of Merger (the “Merger Agreement”) with Zenith Energy U.S., L.P. (together with its affiliates, “Zenith”), a portfolio company of Warburg Pincus, pursuant to which Zenith will acquire Arc Logistics GP LLC (“Arc GP”), the general partner of the Arc Logistics (the “GP Transfer”), and all of the outstanding common units of Arc Logistics (the “Merger” and, together with the GP Transfer, the “Proposed Transaction”) Under the terms of the Merger Agreement, LCP LP will receive $14.50 per common unit of Arc Logistics in cash for the approximately 5.2 million common units held by it. LCP GP will receive $94.5 million for 100% of the membership interests in Arc GP. We anticipate receiving net proceeds of approximately $21.2 million.

The completion of the Proposed Transaction is subject to a number of closing conditions, including, among others, approval by a majority of the outstanding Arc Logistics common unitholders and the expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. Lightfoot, the owner of Arc GP and approximately 26.8% of the outstanding common units of Arc Logistics, has executed an agreement to vote in support of the Proposed Transaction. Additionally, the Proposed Transaction is subject to (i) the closing of the purchase by Zenith and Lightfoot from EFS Midstream Holdings LLC of certain of the interests in Arc Terminals Joliet Holdings, LLC, which indirectly owns, among other things, a crude oil unloading facility and a 4-mile crude oil pipeline in Joliet, Illinois, and (ii) the closing of the purchase by Zenith of a 5.51646 % interest (and, subject to certain conditions, an additional 4.16154% interest) in Gulf LNG Holdings Group, LLC (“Gulf LNG”), which owns a liquefied natural gas regasification and storage facility in Pascagoula, Mississippi, from LCP LNG Holdings, LLC, a subsidiary of Lightfoot L.P. (“LCP”).

The Proposed Transaction is not subject to a financing condition and closing is targeted at the end of the fourth quarter of 2017 or early in the first quarter of 2018. We anticipate that the net proceeds from the Proposed Transaction will be used to repay borrowings under our first lien credit agreement. The Proposed Transaction may result in capital gains that would be

allocated to our unitholders and reported on such unitholders’ separate returns (see Item 1A – Risk Factors for additional information).

In accordance with accounting standards related to the presentation of long-lived assets to be classified as held for sale, we continue to classify Lightfoot as held and used in our condensed financial statements and will continue to do so until the various closing conditions have been satisfied, including approval by a majority of the outstanding Arc Logistics common unitholders and the expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.

Osprey Sponsor Interest. In August 2017, we received a membership interest in Osprey Sponsor, which is the sponsor of Osprey. We received our membership interest in recognition of potential utilization, if any, of our office space, advisory services and personnel by Osprey. On July 26, 2017, Osprey, for which certain of our executives, namely Jonathan Cohen, Edward Cohen, and Daniel Herz serve as CEO, Executive Chairman, and President, respectively consummated its initial public offering. Osprey was formed for the purpose of acquiring, through a merger, capital stock exchange, asset acquisition, stock purchase, reorganization, or other similar business transaction, one or more operating businesses or assets (a “Business Combination”) that Osprey has not yet identified. The initial public offering, including the overallotment exercised by the underwriters, generated net proceeds of $275 million through the issuance of 27.5 million units, which were contributed to a trust account and are intended to be applied generally toward consummating a Business Combination. Our membership interest in Osprey Sponsor is an allocation of 1,250,000 founder shares, consisting of 1,250,000 shares of Class B common stock of Osprey that are automatically convertible into Class A common stock of Osprey upon the consummation of a Business Combination on a one-for-one basis. Additionally, another 125,000 founder shares have been allocated to our employees other than Messrs. Cohen, Cohen and Herz.

FINANCIAL PRESENTATION

Our condensed consolidated financial statements contain our accounts and those of our condensed consolidated subsidiaries as of ~~September~~March 3031, ~~2017~~2018. We determined that ~~ARP (through the Plan Effective Date, as discussed further below) and~~ AGP ~~are~~is a variable interest ~~entities~~entity (“~~VIEs~~VIE”) based on ~~their~~AGP’s ~~respective~~ partnership ~~agreements,~~agreement; our power, as the general partner, to direct the activities that most significantly impact ~~each~~AGP’s ~~of their respective~~ economic performance,; and our ownership of ~~each~~AGP’s ~~of their respective~~ incentive distribution rights. Accordingly, we consolidated the financial statements of ~~ARP (until the date of ARP’s Chapter 11 Filings, as discussed further below) and~~ AGP into our condensed consolidated financial statements. As the general partner for ~~both ARP (through the Plan Effective Date) and~~ AGP, we have unlimited liability for the obligations of ~~ARP (through the Plan Effective Date) and~~ AGP except for those contractual obligations that are expressly made without recourse to the general partner. The non-controlling ~~interests~~interest in ~~ARP (through the date of ARP’s Chapter 11 Filings, as discussed further below) and~~ AGP ~~are~~is reflected as (income) loss attributable to non-controlling interests in the condensed consolidated statements of operations and as a component of unitholders’ equity on the condensed consolidated balance sheets. All ~~material~~ intercompany transactions have been eliminated.

InThroughout ~~connection~~this ~~with ARP’s Chapter 11 Filings on July 27~~section, ~~2016,~~when we ~~deconsolidated~~refer ~~ARP’s~~to ~~financial statements from~~ “our” condensed consolidated financial statements, as we noare ~~longer~~referring ~~had the power~~ to ~~direct~~ the ~~activities~~condensed ~~that~~consolidated ~~most~~results ~~significantly~~for ~~impacted ARP’s economic performance; however~~us, weour ~~retained~~wholly-owned ~~the~~subsidiaries ~~ability to exercise significant influence over the operating~~ and ~~financial decisions of ARP and therefore applied~~ the ~~equity~~consolidated ~~method~~results ofAGP, ~~accounting~~adjusted for ~~our~~non-controlling ~~investment~~interests in ~~ARP up to the Plan Effective Date~~AGP. As a result of these changes, our condensed consolidated financial statements subsequent to ARP’s Chapter 11 Filings will not be comparable to our condensed consolidated financial statements prior to ARP’s Chapter 11 Filings. Our financial results for future periods following the application of equity method accounting will be different from historical trends and the differences may be material.

potential utilization, if any, of our office space, advisory services and personnel by Osprey, and we have provided a nominal amount of services to Osprey as of September 30, 2017. During the three and nine months ended September 30, 2017, we did not recognize any equity method income as Osprey Sponsor has no operations.

Throughout this section, when we refer to “our” condensed consolidated financial statements, we are referring to the condensed consolidated results for us, our wholly-owned subsidiaries and the consolidated results of ARP (as applicable) and AGP, adjusted for non-controlling interests in ARP and AGP.

GENERAL TRENDS AND OUTLOOK

We expect our ~~and~~business ~~our subsidiaries’ businesses~~ to be affected by ~~the following~~ key trends in natural gas and oil production markets. Our expectations are based on assumptions made by us and ~~our subsidiaries and~~ information currently available to us. To the extent our underlying assumptions ~~about~~ or interpretations of available information prove to be incorrect, our ~~and our subsidiaries’~~ actual results may vary materially from our expected results.

~~The~~Throughout 2017 and the first quarter of 2018, the natural gas, oil and natural gas liquids commodity price markets ~~have~~were ~~suffered~~marked ~~significant~~by ~~declines~~volatility. ~~since~~While ~~the~~we ~~fourth~~anticipate ~~quarter~~high levels of ~~2014~~exploration and ~~continue~~production toactivities ~~remain~~over ~~low~~the long-term in ~~2017.~~the ~~The~~areas ~~causes~~in ofwhich ~~these~~we ~~declines~~operate, ~~are~~fluctuations ~~based~~in onenergy aprices ~~number~~can ofgreatly ~~factors,~~affect ~~including,~~production ~~but~~rates ~~not~~and ~~limited~~investments ~~to,~~in athe ~~significant~~development ~~increase~~of innew natural gas, oil and NGL ~~production~~reserves. ~~While~~The weeconomics ~~anticipate continued high levels~~ of ~~exploration~~drilling ~~and~~new ~~production~~oil ~~activities~~wells ~~over~~across the ~~long-term~~our acreage position in the ~~areas~~Eagle Ford Shale in ~~which~~South weTexas ~~operate,~~have ~~fluctuations~~improved insubstantially ~~energy~~over ~~prices~~the ~~can~~last ~~greatly~~twelve ~~affect~~months, ~~production~~driven ~~rates~~by ~~and~~both ~~investments~~a rise in ~~the~~oil ~~development~~prices, ofas ~~new~~well ~~natural~~as ~~gas,~~significant ~~oil~~advancements in drilling and ~~NGL~~completion ~~reserves~~technology.

~~Our subsidiaries~~AGP’s future gas and oil reserves, production, cash flow, ~~the~~ ability to make payments on ~~debts~~our obligations and ~~the~~our ability to make distributions to their unitholders, ~~including AGP’s ability to make distributions to us,~~ depend on ~~our~~its ~~subsidiaries’~~ success in producing our current reserves efficiently, developing its existing acreage and acquiring additional proved reserves economically. ~~Our~~We ~~subsidiaries~~ face the challenge of natural production declines and volatile natural gas, oil and NGL prices. As initial reservoir pressures are depleted, natural gas and oil production from particular wells decrease. ~~Our~~We ~~subsidiaries~~ attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than ~~produced~~we produce. To the extent ~~our~~we ~~subsidiaries~~would do not have access to sufficient capital, our ~~subsidiaries’~~ ability to drill and acquire more reserves ~~will~~would be negatively impacted.

~~For additional information, please see “Liquidity and Ability to Continue as a Going Concern.”~~21

RESULTS OF OPERATIONS

Gas and Oil Production

We deconsolidated ARP for financial reporting purposes as of the date of the Chapter 11 Filings and therefore our 2016 condensed consolidated financial statements will not be comparable to our 2017 condensed consolidated financial statements.

Production Profile. Currently, our gas and oil production revenues and expenses consist of our gas and oil production activities derived from our wells drilled in the Eagle Ford, Marble Falls and Mississippi Lime plays. We have established production positions in the following operating areas:

• the Eagle Ford Shale in ~~southern~~South Texas, an oil-rich area, in which we acquired acreage in November 2014, ~~represents~~where we derive over ~~ninety~~92% ~~percent~~of our production volumes and 96% of our ~~operations~~revenues;

• the Marble Falls play in the Fort Worth Basin in northern Texas, in which we own acreage and producing wells, which contains liquids rich natural gas and oil;, and;

•

the Mississippi Lime play in northwestern Oklahoma, an oil and NGL-rich area.

32The following table presents the number of wells we drilled and the number of wells we turned in line, both gross and net during the periods indicated:

The following table presents the number of wells our subsidiaries drilled and the number of wells our subsidiaries turned in line, both gross and for our respective interests, during the periods indicated:

	Three Months Ended March 31,
	2018		2017

Gross wells drilled⁽¹⁾		1		—
Net wells drilled⁽¹⁾		1		—
Gross wells turned in line⁽²⁾		—		—
Net wells turned in line⁽²⁾		—		—

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2017(1)	2016(1)	2017(1)	2016(1)
Gross wells drilled(4)	—	—	—	—
Net wells drilled(2)	—	—	—	—
Gross wells turned in line(3)	—	—	—		2
Net wells turned in line(2)(3)	—	—	—		2

⁽¹⁾	There were no exploratory wells drilled during each of the periods presented.

(12) WeWells ~~deconsolidated~~turned ~~ARP~~in ~~for~~line ~~financial~~refers ~~reporting purposes as of July 27, 2016 (the date of ARP’s Chapter 11 Filings) and therefore our 2016 results will not be comparable~~ to ~~our~~wells ~~2017~~that ~~results. In addition, ARP did not~~ have ~~any~~been ~~gross or net wells~~ drilled ~~or turned in line~~, ~~did~~completed ~~not drill any exploratory wells,~~ and ~~did~~connected ~~not~~to ~~have~~a ~~any~~gathering ~~gross or net dry wells within its operating areas during the periods presented~~system.

(2) Includes AGP’s percentage interest in the wells in which it has a direct ownership interest.

(3) Wells turned in line refers to wells that have been drilled, completed, and connected to a gathering system.

(4) AGP did not drill any exploratory wells and did not have any gross or net dry wells within its operating areas during the periods presented.

Production Volumes. The following table presents total net natural gas, crude oil and NGL production volumes and production per day for the periods indicated:

	Three Months Ended			Nine Months Ended
	Three Months Ended March 31,
	September 30,			September 30,
		2018		2017
	2017		2016	2017		2016
Total production volumes per day: (1)
Production:(1)
Natural gas (Boed)		44			59
Atlas Resource Partners: (2)
Oil (Bpd)		279			485
Natural gas (MMcf)	—		4,836	—			39,360
NGLs (Bpd)		49			60
Oil (MBbls)	—		106	—			900
Total (Boed)		372			604
NGLs (MBbls)	—		56	—			487
Total production volumes: (1)
Total (MMcfe)	—		5,807	—			47,682
Natural gas (MBoe)		4			5
Atlas Growth Partners:
Oil (MBbls)		25			44
Natural gas (MMcf)	27		39	86			122
NGLs (MBbls)		4			5
Oil (MBbls)	33		61	113			242
Total (MBoe)		34			54
NGLs (MBbls)	5		7	15			21
Total (MMcfe)	255		445	856			1,702
Total production: (2)
Natural gas (MMcf)	27		4,874	86			39,482
Oil (MBbls)	33		166	113			1,141
NGLs (MBbls)	5		63	15			509
Total (MMcfe)	255		6,252	856			49,384
Production per day:(1)
Atlas Resource Partners: (2)
Natural gas (Mcfd)	—		52,561	—			143,650
Oil (Bpd)	—		1,148	—			3,284
NGLs (Bpd)	—		612	—			1,778
Total (Mcfed)	—		63,122	—			174,021
Atlas Growth Partners:
Natural gas (Mcfd)	299		422	316			445
Oil (Bpd)	359		661	415			883
NGLs (Bpd)	52		75	55			78
Total (Mcfed)	2,770		4,833	3,134			6,213
Total production per day: (2)
Natural gas (Mcfd)	299		52,983	316			144,095
Oil (Bpd)	359		1,809	415			4,167
NGLs (Bpd)	52		687	55			1,856
Total (Mcfed)	2,770		67,955	3,134			180,234

(1) ~~Production~~“Bbls” ~~quantities~~and ~~consist~~“Bpd” ofrepresent ~~the~~barrels ~~sum~~and ofbarrels ~~(i)~~per ~~the~~day. ~~proportionate~~“Boe” ~~share of production from wells in which our subsidiaries have a direct interest, based on the proportionate net revenue interest in such wells,~~ and ~~(ii)~~“Boed” ~~ARP’s~~represent ~~proportionate~~barrels ~~share~~ of ~~production~~oil ~~from~~equivalent ~~wells owned by the Drilling Partnerships in which it has an interest, based on ARP’s equity interest in each such Drilling Partnership~~ and ~~based~~barrels onof ~~each~~oil ~~Drilling~~equivalent ~~Partnership’s~~per ~~proportionate net revenue interest in these wells~~day.

~~(2) We deconsolidated ARP for financial reporting purposes as of July 27, 2016 (the date of ARP’s Chapter 11 Filings) and therefore our 2016 results will not be comparable to our 2017 results.~~22

34Production Revenues, Prices and Costs. Production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas and oil. The following table presents production revenues and average sales prices for AGP’s natural gas, oil, and NGLs production for each of the periods indicated, along with average production costs, which include lease operating expenses, taxes, and transportation and compression costs, in each of the reported periods:

Production Revenues, Prices and Costs. Production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas and oil. The following table presents production revenues and average sales prices for AGP’s and ARP’s natural gas, oil, and NGLs production for each of the periods indicated, along with average production costs, which include lease operating expenses, taxes, and transportation and compression costs, in each of the reported periods:

	Three Months Ended March 31,
	2018		2017
Production revenues (in thousands):
Natural gas revenue	$	36	$	101
Oil revenue		1,630		2,185
NGLs revenue		104		110
Total production revenues	$	1,770	$	2,396
Average sales price, unhedged:
Natural gas (per Mcf)	$	1.53	$	3.19
Oil (per Bbl)	$	64.88	$	50.00
NGLs (per Bbl)	$	23.45	$	20.21

Total Gas and Oil Costs (in thousands)	$	456	$	952

Gas and Oil Production costs (per Boe):
Lease operating expenses	$	10.03	$	14.13
Production taxes		3.37		2.76
Transportation and compression		0.21		0.62
	$	13.62	$	17.51

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2017		2016		2017		2016
Production revenues (in thousands):
Atlas Resource Partners: (1)
Natural gas revenue	$	—	$	15,146	$	—	$	74,320
Oil revenue	—			2,358	—			38,628
NGLs revenue	—			749	—			5,194
Total revenues	$	—	$	18,253	$	—	$	118,142
Atlas Growth Partners:
Natural gas revenue	$	74	$	108	$	252	$	269
Oil revenue	1,559			2,586	5,467			8,740
NGLs revenue	98			98	282			269
Total revenues	$	1,731	$	2,792	$	6,001	$	9,278
Total production revenues: (1)
Natural gas revenue	$	74		15,254	$	252	$	74,589
Oil revenue	1,559			4,944,	5,467			47,368
NGLs revenue	98			847	282			5,463
Total revenues	$	1,731	$	21,045	$	6,001	$	127,420
Average sales price:
Atlas Resource Partners: (1)
Natural gas (per Mcf)
Total realized price, after hedge(2)(3)	$	—	$	3.55	$	—	$	3.47
Total realized price, before hedge(2)	$	—	$	2.50	$	—	$	1.83
Oil (per Bbl):
Total realized price, after hedge(3)	$	—	$	42.34	$	—	$	74.75
Total realized price, before hedge	$	—	$	42.34	$	—	$	36.31
NGLs (per Bbl):
Total realized price(3)	$	—	$	13.30	$	—	$	10.66
Atlas Growth Partners:
Natural gas (per Mcf):
Total realized price	$	2.69	$	2.78	$	2.92	$	2.20
Oil (per Bbl):
Total realized price, after hedge(3)	$	51.30	$	42.80	$	50.88	$	37.09
Total realized price, before hedge	$	47.16	$	42.56	$	48.30	$	36.12
NGLs (per Bbl):
Total realized price	$	20.30		14.28	$	18.79	$	12.58
Production costs (per Mcfe):
Atlas Resource Partners: (1)
Lease operating expenses(4)	$	—	$	1.13	$	—	$	1.20
Production taxes		—		0.23		—	0.19
Transportation and compression		—		0.19		—	0.23
Total production costs per Mcfe	$	—	$	1.55	$	—	$	1.62
Atlas Growth Partners:
Lease operating expenses	$	1.33	$	0.79	$	1.70	$	0.85

Our gas and oil production revenues were lower in the current period as compared to the prior period due to a $1.0 million decrease attributable to natural production declines partially offset by a $0.4 million increase due to higher oil average sales prices.

35Our gas and oil production costs were lower in the current period as compared to the prior period due to a $0.4 million decrease in production costs resulting from lower volumes and a $0.1 million decrease in property tax expense due to lower county assessments.

Production taxes	0.48			0.30		0.50	0.26
Transportation and compression	0.05			0.14		0.05	0.11
Total production costs per Mcfe	$	1.86	$	1.23	$	2.25	$	1.22
Total production costs: (1)
Lease operating expenses(4)	$	1.33	$	1.11	$	1.70	$	1.18
Production taxes		0.48		0.23		0.50	0.19
Transportation and compression		0.05		0.19		0.05	0.23
Total production costs per Mcfe	$	1.86	$	1.53	$	2.25	$	1.60

(1) We deconsolidated ARP for financial reporting purposes as of July 27, 2016 (the date of ARP’s Chapter 11 Filings) and therefore our 2016 results will not be comparable to our 2017 results.

(2) Excludes the impact of subordination of ARP’s production revenue to investor partners within its Drilling Partnerships for the three and nine months ended September 30, 2016. Including the effect of this subordination, ARP’s average realized gas sales price was $2.74 per Mcf ($3.95 per Mcf before the effects of financial hedging) and $3.41 per Mcf ($1.66 per Mcf before the effects of financial hedging) for the three and nine months ended September 30, 2016, respectively.

(3) Includes the impact of $0.1 million of cash settlements for the three months ended September 30, 2017 and 2016, respectively, and $0.3 million and $0.2 million for the nine months ended September 30, 2017 and 2016, on AGP’s oil derivative contracts which were entered into subsequent to our decision to discontinue hedge accounting beginning on January 1, 2015. Includes the impact of cash settlements on ARP’s commodity derivative contracts not previously included within accumulated other comprehensive income following ARP’s decision to de-designate hedges beginning on January 1, 2015. Cash settlements on ARP’s commodity derivative contracts excluded from production revenues consisted of $4.1 million for natural gas for the three months ended September 30, 2016, and $62.6 million for natural gas and $26.5 million for oil for the nine months ended September 30, 2016.

(4) Excludes the effects of ARP’s proportionate share of lease operating expenses associated with subordination of its production revenue to investor partners within its Drilling Partnerships for the three and nine months ended September 30, 2016. Including the effects of these costs, ARP’s total lease operating expenses per Mcfe were $1.07 per Mcfe ($1.49 per Mcfe for total production costs) and $1.16 per Mcfe ($1.58 per Mcfe for total production costs) for the three and nine months ended September 30, 2016, respectively. Including the effects of these costs, total lease operating expenses per Mcfe were $1.11 per Mcfe ($1.53 per Mcfe for total production costs) and $1.15 per Mcfe ($1.56 per Mcfe for total production costs) for the three and nine months ended September 30, 2016, respectively.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in thousands)						(in thousands)
Gas and oil production revenues	$	1,731		$	21,045		$	6,001		$	127,420
Gas and oil production costs	$	(476	)	$	(9,228	)	$	(1,929	)	$	(77,454	)

Our production revenues were lower in the current quarter as a result of a $18.3 million decrease in ARP’s revenues due to the deconsolidation of ARP as of July 27, 2016, which affects the comparability of the periods presented, and a $1.1 million decrease in AGP’s revenues attributable to production from AGP’s Eagle Ford operations, primarily related to lower oil volumes as a result of natural production decline in the current period.

Our production revenues were lower in the nine months ended September 30, 2017 as a result of a $118.1 million decrease in ARP’s revenues due to the deconsolidation of ARP as of July 27, 2016, which affects the comparability of the periods presented, and a $3.3 million decrease in AGP’s revenues attributable to production from AGP’s Eagle Ford operations, primarily related to two wells turned in line in the prior period resulting in lower volumes as a result of natural production decline in the current period.

Our production costs were lower in the current quarter as a result of a $8.7 million decrease in ARP’s gas and oil production costs due to the deconsolidation of ARP as of July 27, 2016, which affects the comparability of the periods presented, and a $0.1 million in decrease in AGP’s gas and oil production costs attributable to fewer wells turned in line in AGP’s Eagle Ford operations.

Our production costs were lower in the nine months ended September 30, 2017 as a result of a $75.4 million decrease in ARP’s gas and oil production costs due to the deconsolidation of ARP as of July 27, 2016, which affects the comparability of the periods presented, and a $0.2 million decrease in AGP’s gas and oil production costs attributable to fewer wells turned in line in AGP’s Eagle Ford operations.

ARP’s Drilling Partnership Management

The following table presents the amounts of revenues and the related costs associated with these revenues during the periods indicated (dollars in thousands). We deconsolidated ARP for financial reporting purposes as of the date of the

Chapter 11 Filings and therefore our 2016 condensed consolidated financial statements will not be comparable to our 2017 condensed consolidated financial statements.

	Three Months Ended September 30					Nine Months Ended September 30
	2017		2016			2017		2016
ARP’s Drilling Partnership management revenues	$	—	$	11,568		$	—	$	25,009
ARP’s Drilling Partnership management expenses		—		(9,536	)		—		(18,331	)
ARP’s Drilling Partnership management gross profit margin	$	—	$	2,032		$	—	$	6,678

Other Revenues and Expenses

	Three Months Ended September 30,						Nine Months Ended September 30,
	Three Months Ended March 31,
	2017			2016			2017			2016
	2018			2017
		(in thousands)						~~(in thousands)~~
Other Revenues
Gain (loss) on mark-to-market derivatives	$	(~~449)~~286	)	$	~~9,449~~757		$	~~942~~		$	~~(18,188~~	)
Other, net		1647			~~175~~722			~~879~~			~~1,045~~
Other Expenses
General and administrative:
Atlas Energy Group	$	~~818~~754		$	~~963~~404		$	~~(363~~	)	$	~~4,648~~
Atlas Growth Partners		~~1,042~~981			21,~~726~~381			~~3,901~~			~~8,118~~
Atlas Resource Partners		—			175			—			41,013
Total general and administrative	$	1,735		$	1,785
Total general and administrative	$	1,860		$	3,864		$	3,538		$	53,779
Depreciation, depletion and amortization	$	975		$	1,112
Depreciation, depletion and amortization:
Interest expense	$	5,327		$	4,929
Atlas Growth Partners	$	825		$	3,898		$	2,823		$	11,424
Loss attributable to non-controlling interests		894			281
Atlas Resource Partners		—			8,460			—			67,513
Total depreciation, depletion and amortization	$	825		$	12,358		$	2,823		$	78,937
Interest expense:
Atlas Energy Group	$	5,478		$	4,488		$	15,201		$	10,121
Atlas Resource Partners		—			9,224			—			68,883
Total interest expense	$	5,478		$	13,712		$	15,201		$	79,004
(Gain) loss on extinguishment of debts, net:
Atlas Energy Group	$	—		$	—		$	—		$	6,080
Atlas Resource Partners		—			—			—			(26,498	)
Total (gain) loss on extinguishment of debts, net	$	—		$	—		$	—		$	(20,418	)
Reorganization items, net – Atlas Resource Partners		—		$	21,649			—		$	21,649
Gain on deconsolidation of Atlas Resource Partners, L.P.		—			46,951			—			46,951
Other income (loss)								—
Atlas Growth Partners		—			5,297			—			5,297
Atlas Resource Partners		—			(24	)		—			6,625
Total other loss		—		$	5,273			—		$	11,922
Loss attributable to non-controlling interests		1,022			23,619			1,646			132,916

Gain (Loss) on Mark-to-Market Derivatives. We recognize changes in ~~the~~ fair value of derivatives immediately within gain (loss) on mark-to-market derivatives on our condensed consolidated statements of operations. The recognized losses during the three and nine months ended September 30, 2017 were due to changes in commodity futures prices relative to our derivative positions as of the respective prior period end. In addition, we deconsolidated ARP as of July 27, 2016, which resulted in a decrease of $9.3 million and an increase of $17.8 million from the three and nine months ended September 30, 2017, respectively, and affects the comparability of the periods presented.

Other, net. Our other, net revenues were lower in the current quarter and nine months ended September 30, 2017 as a result of a decrease in equity method income related to our 2% Series A Preferred interest in Titan. 23

37the three months ended March 31, 2018 and the recognized gains during the three months ended March 31, 2017 were due to changes in commodity futures prices relative to our derivative positions as of the respective prior year end.

~~General~~Other, ~~and Administrative~~net. Our ~~$0.1~~other, ~~million~~net ~~decrease~~revenues inwere ~~general~~lower ~~and administrative expenses~~ in the current quarter ~~was~~as ~~due~~a toresult of a $0.5 million decrease in ~~stock~~equity ~~compensation~~method ~~expense~~income related to ~~the~~our ~~forfeiture~~2% ofSeries ~~employee~~A ~~awards~~Preferred ~~due~~interest toin Titan’s ~~completion of the majority of the sale of its Appalachian assets~~ and ~~reductions in workforce, partially offset by~~ a $0.2 million ~~increase in salaries and wages and a $0.2 million increase in other corporate activities. ARP’s $0.2 million~~ decrease in ~~general~~equity ~~and~~method ~~administrative~~income ~~expenses~~related ~~in the current quarter was due~~ to our ~~deconsolidation~~interest ~~of ARP as of July 27, 2016, which affects the comparability of the periods presented. AGP’s decrease~~ in ~~general and administrative expenses in the current quarter was due to a $1~~Lightfoot.7 million decrease in salaries, wages and other corporate activity costs allocated by us to AGP as a result of the suspension of AGP’s current primary offering efforts and AGP’s management’s plan to reduce general and administrative expenses.

General and Administrative. Our $5.0.3 million ~~decrease~~increase in general and administrative expenses in the ~~nine~~current ~~months~~quarter ~~ended September 30, 2017,~~ was due to a $4.6 million decrease in stock compensation expense related to the forfeiture of employee awards due to Titan’s completion of the majority of sale of its Appalachian assets and reductions in workforce, a $0.74 million ~~decrease~~increase in ~~non-recurring~~salaries ~~transaction costs,~~ and ~~a $0.1 million decrease in other corporate activities~~wages, partially offset by a $0.41 million ~~increase in salaries and wages. ARP’s $41.0 million~~ decrease in ~~general~~other ~~and~~corporate ~~administrative expenses in the nine months ended September 30, 2017 was due to our deconsolidation of ARP as of July 27, 2016, which affects the comparability of the periods presented~~costs. AGP’s decrease in general and administrative expenses infor the ~~nine~~current ~~months~~period ~~ended September 30, 2017~~ was due to a $40.24 million decrease in salaries, wages and other corporate activity costs allocated ~~by us~~ to AGP as a result of ~~the~~lower ~~suspension~~corporate ~~of AGP’s current primary offering efforts and AGP’s management’s plan to reduce general and administrative expenses~~activities.

Depreciation, Depletion and Amortization. ~~ARP’s~~The decrease in depreciation, depletion and amortization infor the current ~~quarter~~period ~~and~~as ~~the~~compared ~~nine months ended September 30, 2017 was due~~ to ~~our deconsolidation of ARP as of July 27, 2016, which affects~~ the ~~comparability~~prior ofperiod ~~the periods presented. AGP’s decrease in depreciation, depletion and amortization in the current quarter and the nine months ended September 30, 2017~~ was primarily due to ~~decreases~~a of $30.1 million ~~and~~decrease ~~$8.6 million, respectively,~~ in AGP’s depletion expense ~~due~~resulting tofrom ~~impairments of AGP’s proved oil and gas properties in its Eagle Ford operating area recorded in the fourth quarter of 2016, which were impaired due to~~ lower ~~forecasted~~production ~~commodity prices and timing of capital financing and deployment for the development of its undeveloped properties~~volumes.

Interest Expense. The increase in our interest expense in the current quarter ~~primarily~~ consisted of a $10.15 million increase of paid-in-kind interest on our credit agreements., ~~ARP’s~~partially offset by a $90.21 million decrease in cash interest ~~expense~~paid inon ~~the~~our ~~current~~first ~~quarter~~lien ~~was~~credit agreement due to ~~our~~a ~~deconsolidation~~lower ofprincipal ~~ARP~~balance asfrom ofthe ~~July~~pay ~~27,~~down ~~2016,~~in ~~which affects~~ the ~~comparability~~fourth ofquarter ~~the periods presented~~2017.

The increase in our interest expense in the nine months ended September 30, 2017 consisted of a $6.4 million increase of paid-in-kind interest on our credit agreements, partially offset by a $1.2 million decrease in interest on the original term loans with Riverstone and a $0.2 million decrease in amortization of our deferred financing costs. ARP’s $68.9 million decrease in interest expense in the nine months ended September 30, 2017 was due to our deconsolidation of ARP as of July 27, 2016, which affects the comparability of the periods presented.

Gain (Loss) on Early Extinguishment of Debt. The decrease in our loss on early extinguishment of debt in the nine months ended September 30, 2017 was due to $3.7 million of accelerated amortization of deferred financing costs and $2.4 million of prepayment penalties related to the restructuring of our original term loans with Riverstone in the first quarter of 2016. ARP’s $26.5 million decrease in gain on early extinguishment of debt was related to the repurchase of a portion of ARP’s senior notes in the first quarter of 2016.

Reorganization Items, Net. The $21.6 million in ARP’s reorganization items, net for the three and nine months ended September 30, 2016 represented incremental costs incurred as a result of ARP’s Chapter 11 Filings.

Gain on deconsolidation of Atlas Resource Partners, L.P. As a result of deconsolidating ARP and recording our equity method investment in ARP at a fair value of zero on the date of the Chapter 11 Filings, we recognized a $47.0 million non-cash gain, which is recorded in gain on deconsolidation of ARP on our condensed combined consolidated statements of operations for the three and nine months ended September 30, 2016.

Other loss. AGP’s $5.3 million loss for the three and nine months ended September 30, 2016 was due to AGP’s $5.3 million write-off of issuer costs related to its decision to suspend its primary offering efforts in light of new regulations and the challenging fund raising environment until such time as market participants have had an opportunity to ascertain the impact of such issues. ARP’s $6.6 million loss for the nine months ended September 30, 2016 represents a non-cash loss, net of consolidation and transfer adjustments, of certain Drilling Partnerships’ consolidation and transfer of oil and gas properties and asset retirement obligations to ARP during the period.

Loss Attributable to Non-Controlling Interests. The decrease in loss attributable to non-controlling interests in the current quarter and the nine months ended September 30, 2017 was primarily due to the deconsolidation of ARP as of July 27, 2016, which affects the comparability of the periods presented.

LIQUIDITY AND CAPITAL RESOURCES

See ~~the~~ “Liquidity and Ability to Continue as a Going Concern” section above for ~~discussion~~additional disclosures regarding ~~these~~our ~~matters~~liquidity and financial condition.

~~Atlas~~See ~~Growth~~“Item ~~Partners~~1: –Financials ~~Liquidity,~~Statements ~~Capital~~- ~~Resources,~~Note ~~and~~4” ~~Ability~~for todisclosures ~~Continue~~regarding asour acredit ~~Going~~agreements’ ~~Concern~~terms and provisions.

On November 2, 2016, AGP decided to suspend its current primary offering efforts in light of new regulations and the challenging fund raising environment until such time as market participants have had an opportunity to ascertain the impact of such issues. In addition, AGP’s board of directors suspended its quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order to retain its cash flow. Accordingly, these decisions raise substantial doubt about AGP’s ability to continue as a going concern. Management determined that substantial doubt is alleviated through management’s plans to reduce general and administrative expenses, the majority of which represent allocations from us.

Cash Flows

	Nine Months Ended September 30,
	Three Months Ended March 31,
	2017			2016
	2018			2017
Net cash provided by operating activities	$	5,636		$	176,589
	(in thousands)
Net cash used in investing activities		—			(26,961	)
Net cash used in operating activities	$	(3,867	)	$	(85	)
Net cash (used in) provided by financing activities		(42	)		(169,375	)
Net cash used in investing activities		(225	)		—
Net cash used in financing activities		(54	)		(8	)

~~Nine~~Three Months Ended ~~September~~March 3031, ~~2017~~2018 Compared with the ~~Nine~~Three Months Ended ~~September~~March 3031, ~~2016~~2017

We deconsolidated ARP for financial reporting purposes as of July 27, 2016 (the date of ARP’s Chapter 11 Filings) and therefore our 2017 cash flows will not be comparable to our 2016 cash flows.

Cash Flows From Operating Activities:

The change in cash flows used in operating activities compared with the prior year period was due to:

• aA decrease ~~from~~of ~~ARP’s~~ $~~243~~4.57 million ~~sale~~ of ~~substantially~~net ~~all~~cash ofprovided ~~its~~by ~~commodity~~advances ~~hedge~~to/from ~~positions~~affiliates onrelated ~~July~~to ~~25,~~direct ~~2016~~and indirect cost allocations and ~~July~~the ~~26,~~timing ~~2016~~of funding of cash accounts for operating activities and general and administrative expenses;

• a decrease of ~~$53.6 million of~~ cash ~~paid~~settlement ~~for~~receipts ~~interest related to ARP’s debts due to the deconsolidation~~ of ~~ARP~~$1.0 million on ~~the~~commodity ~~date~~derivative ofcontracts; ~~the~~partially ~~Chapter~~offset ~~11 Filings;~~by

• aan ~~decrease~~increase of $361.78 million ofnet ~~investor~~cash ~~capital~~provided ~~raised~~by ~~transferred~~operating byactivities ~~ARP~~for cash receipts and disbursements attributable to ~~the~~our ~~Atlas~~normal ~~Eagle~~monthly ~~Ford~~operating ~~2015~~cycle ~~L.P.~~for ~~private~~gas ~~drilling~~and ~~partnership~~oil production and collections net of payments for ~~activities~~our ~~directly~~royalties, ~~related~~lease tooperating ~~their~~expenses, ~~program~~gathering, inprocessing ~~March~~and oftransportation ~~2016;~~expenses, severance taxes, and general and administrative expenses.

• a decrease of $20.4 million in distributions paid to non-controlling interests; and

• a decrease of $1.8 million of cash paid for interest related to our credit agreements; partially offset by

• an increase of $82.9 million net cash provided by operating activities for cash receipts and disbursements attributable to our normal monthly operating cycle for gas and oil production and ARP’s Drilling partnership management revenue activities, and collections net of payments for our royalties, ARP’s Drilling partnership

management expense activities, lease operating expenses, gathering, processing and transportation expenses, severance taxes, and general and administrative expenses; and

• a decrease of cash settlement receipts of $99.1 million on commodity derivative contracts.

Cash Flows From Investing Activities:

The change in cash flows used in investing activities when compared with the comparable prior year period was primarily due to aan ~~decrease~~increase of $270.72 million in capital expenditures related to ~~ARP’s and~~ AGP’s drilling activities.

Cash Flows From Financing Activities:

The change in cash flows (used in) ~~provided by~~ financing activities compared with the prior year period was due to: an increase of approximately $46,000 in deferred financing costs and discounts.

• a net decrease of $161.7 million due to the deconsolidation of ARP;

• a $4.3 million decrease in net repayments on our original term loans with Riverstone;

• a decrease of $4.1 million in deferred financing costs and discounts;

• a decrease of $1.7 million in net proceeds primarily due to fees related to AGP’s public offering in 2016; and

• a decrease of $1.0 million in distributions paid to preferred unitholders primarily due to the suspension of distributions for the Series A preferred units in the first quarter of 2016.

Capital Requirements

AtDuring ~~September~~the 30three months ended March 31, ~~2017~~2018, ~~the~~our capital ~~requirements~~expenditures ofwere approximately $0.2 million, related to our ~~natural~~well ~~gas~~drilling and ~~oil~~completion ~~production~~costs. ~~primarily~~As ~~consist~~ of ~~expenditures~~March to31, ~~maintain~~2018, orwe ~~increase~~had ~~production~~$3.3 ~~margin~~million in ~~future~~accrued ~~periods,~~liabilities asfor ~~well~~our asdrilling ~~land, gathering~~ and ~~processing,~~completion and ~~other non-drilling~~ capital expenditures.

As of September 30, 2017, our subsidiaries did not have any commitments for drilling and completion and capital expenditures, excluding acquisitions.

OFF BALANCE SHEET ARRANGEMENTS

There have been no material changes to our off balance sheet arrangements from those disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, ~~2016~~2017.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

There have been no material changes to our contractual obligations and commercial commitments outside the ordinary course of our business from those disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, ~~2016~~2017.

CREDIT FACILITIES

As of September 30, 2017, we had not guaranteed any of our subsidiaries’ obligations or debt instruments.

Credit Agreements

First Lien Credit Agreement. On March 30, 2016, we, together with New Atlas Holdings, LLC (the “Borrower”) and Atlas Lightfoot, LLC, entered into a third amendment (the “Third Amendment”) to our credit agreement with Riverstone Credit Partners, L.P., as administrative agent (“Riverstone”), and the lenders (the “Lenders”) from time to time party thereto (the “First Lien Credit Agreement”).

the nine months ended September 30, 2016. The Third Amendment amended the First Lien Credit Agreement to, among other things:

• provide the ability for us and the Borrower to enter into the new Second Lien Credit Agreement (defined below);

• provide that the First Lien Credit Agreement may be prepaid without premium;

• prohibit the payment of cash distributions on our common and preferred units;

• require the receipt of quarterly distributions from Atlas Growth Partners, GP, LLC and Lightfoot; and

• add a cross-default provision for defaults by ARP.

On October 6, 2016, we entered into a fourth amendment to the First Lien Credit Agreement with Riverstone and the Lenders, effective as of September 1, 2016, that makes conforming changes to reflect the status of Titan as the successor to ARP following the consummation of the Chapter 11 Filings and also removes the financial covenants and related cross-defaults that had previously been incorporated from ARP’s credit agreement.

distribution, merge into or consolidate with other persons, enter into swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions. In addition, the Second Lien Credit Agreement requires that we maintain an Asset Coverage Ratio (as defined in the Second Lien Credit Agreement) of not less than 2.00 to 1.00 as of September 30, 2017 and each fiscal quarter ending thereafter.

In connection with the First Lien Credit Agreement and Second Lien Credit Agreement, the lenders thereunder continued their syndicated participation in the underlying loans consistent with the original term loan facilities (and therefore certain of the Company’s current and former officers participated in approximately 12% of the loan syndication and warrants and a foundation affiliated with a 5% or more unitholder participated in approximately 12% of the loan syndication.

On October 6, 2016, we entered into a first amendment to the Second Lien Credit Agreement with Riverstone and the Lenders, effective as of September 1, 2016, that makes conforming changes to reflect the status of Titan as the successor to ARP following the consummation of the Chapter 11 Filings and also removed the financial covenants and related cross-defaults that had previously been incorporated from ARP’s credit agreement.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

For a more complete discussion of the accounting policies and estimates that we have identified as critical in the preparation of our condensed consolidated financial statements, please refer to our Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the fiscal year ended December 31, ~~2016~~2017.

Recently Issued Accounting Standards

See ~~Note~~Item 21: toFinancials ~~our~~Statements ~~condensed~~- ~~consolidated~~Note ~~financial~~2” ~~statements~~ for additional information related to recently issued accounting standards.

ITEM 3:

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our and our subsidiaries’ potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and commodity prices. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we and our subsidiaries view and manage our ongoing market risk exposures. All of the market risk-sensitive instruments were entered into for purposes other than trading.

We are exposed to various market risks, principally changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We manage these risks through regular operating and financing activities and periodic use of derivative financial instruments such as forward contracts and swap agreements. The following analysis presents the effect on our results of operations, cash flows and financial position as if the hypothetical changes in market risk factors occurred on ~~September~~December 3031, 2017. Only the potential impact of hypothetical assumptions was analyzed. The analysis does not consider other possible effects that could impact our business.

Interest Rate Risk. As of ~~September~~March 3031, ~~2017~~2018, we had $9684.5 million of outstanding borrowings under our credit agreements. Holding all other variables constant, a hypothetical 100 basis-point or 1% change in variable interest rates would change our condensed consolidated interest expense for the year ending ~~September~~March 3031, ~~2018~~2019 by $1.0.9 million.

Commodity Price Risk. Holding all other variables constant, including the effect of commodity derivatives, a 10% change in average commodity prices would result in a change to our consolidated operating income for the year ending ~~September~~March 3031, ~~2018~~2019 of $0.36 million, net of non-controlling interests.

~~As of September 30, 2017, AGP had the following commodity derivatives:~~25

Type	Production Period Ending December 31,	Volumes(1)		Average Fixed Price(1)
Crude Oil – Fixed Price Swaps	2017(2)		26,100	$	53.517
	2018		74,500	$	52.510

As of March 31, 2018, AGP had the following commodity derivatives:

Production

Period Ending

December 31,

Volumes

Average

Fixed

Price

(Bbl)⁽¹⁾

(per Bbl)

2018⁽²⁾

74,500

52.510

(1)	Volumes for crude oil are stated in barrels.

(2) The production volumes for ~~2017~~2018 include the remaining ~~three~~nine months of ~~2017~~2018 beginning ~~October~~April 1, ~~2017~~2018.

ITEM 4:

CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

WeOur ~~maintain~~management, ~~disclosure~~with ~~controls~~the participation of our Chief Executive Officer (principal executive officer) and ~~procedures~~our ~~that~~Chief ~~are~~Financial ~~designed~~Officer to(principal ~~ensure~~financial officer) has evaluated the effectiveness of our disclosure controls and procedures in ensuring that the information required to be disclosed in ~~our~~reports that we file or submit under the Exchange Act ~~reports~~ is recorded, processed, summarized and reported within the time periods specified in the ~~Security and Exchange Commission~~SEC’s rules and forms, ~~and~~including ensuring that such information is accumulated and communicated to ~~our~~ management, (including ~~our~~the ~~Chief~~principal ~~Executive~~executive ~~Officer~~ and ~~Chief~~financial ~~Financial~~officers) ~~Officer,~~ as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

~~Under~~Based ~~the~~on ~~supervision~~such ofevaluation, our ~~Chief~~principal ~~Executive~~executive ~~Officer~~ and ~~Chief~~financial ~~Financial Officer and with the participation of our disclosure committee appointed by such~~ officers, we have ~~carried~~concluded ~~out~~that ansuch ~~evaluation of the effectiveness of our~~ disclosure controls and procedures aswere ofineffective ~~the~~as ~~end~~ of ~~the~~March ~~period covered by this report. Based upon that evaluation~~31, ~~our Chief Executive Officer and Chief Financial Officer concluded that~~2018, asbecause ofwe ~~September~~were ~~30,~~unable ~~2017,~~to ~~our~~timely ~~disclosure~~file ~~controls~~this ~~and~~Quarterly ~~procedures~~Report ~~were~~on ~~effective~~Form at10-Q ~~the~~due ~~reasonable~~to ~~assurance~~resource ~~level~~constraints.

~~There~~Changes ~~have been no changes~~ in ~~our~~Internal ~~internal~~Control ~~control~~ over ~~financial~~Financial ~~reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.~~ Reporting

Effective January 1, 2018, we implemented a new accounting system specific to the upstream oil and gas industry and, throughout the implementation, appropriately evaluated the impact of the system on our internal control over financial reporting and where appropriate, made changes to these controls to address related system functionality and potential gaps.

Other than above, there have been no changes in our internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II

ITEM 1A: RISK FACTORS

There have been no material changes to the Risk Factors disclosed in Part I – Item 1A “–Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, ~~2016~~2017 except as follows.

~~Unitholders~~We are ~~required~~substantially todependent ~~pay~~upon ~~taxes~~reimbursements onfrom ~~their~~Titan ~~share~~to offund ~~our~~significant ~~taxable~~general ~~income,~~and ~~including~~administrative ~~their share of ordinary income~~ and ~~capital~~other ~~gain~~expenses ~~upon~~that ~~dispositions~~we ofincur ~~properties~~on byits ~~us,~~behalf; ~~even if they do not receive~~ any ~~cash~~change ~~distributions~~in ~~from~~that ~~us.~~reimbursement Arelationship, ~~unitholder’s~~including ~~share~~due ofto ~~our~~potential ~~taxable~~restructuring ~~income,~~opportunities ~~gain,~~that ~~loss~~Titan ~~and~~is ~~deduction,~~currently ~~or specific items thereof~~exploring, may beadversely ~~substantially~~impact ~~different~~our ~~than~~results ~~the~~of ~~unitholder’s~~operations ~~interest~~and infinancial ~~our economic profits~~condition.

~~Our~~Pursuant ~~unitholders~~to ~~are~~the ~~required~~Delegation toof ~~pay~~Management ~~federal~~Agreement ~~income~~and ~~taxes~~Omnibus ~~and,~~Agreement we entered into with Titan upon its emergence from bankruptcy in ~~some~~September ~~cases~~2016, ~~state~~we operate Titan’s business on a day to day basis, and ~~local~~in ~~income~~exchange, ~~taxes~~Titan onreimburses ~~their~~us ~~share~~for ofexpenses incurred in connection with our ~~taxable~~provision ~~income~~of services, ~~whether~~which orreimbursement ~~not~~covers ~~they~~a ~~receive~~significant ~~any~~portion ~~cash~~of ~~distributions~~our ~~from~~aggregate uscompensation and other general and administrative expenses. ~~Our~~In ~~unitholders~~that ~~may~~fashion, ~~not~~we ~~receive~~rely ~~cash~~substantially ~~distributions~~on ~~from~~Titan to reimburse us ~~equal~~so tothat ~~their~~we ~~share~~can ofoperate our ~~taxable~~business ~~income~~and compensate our employees. Titan is currently exploring strategic alternatives or ~~even~~other ~~equal~~restructuring opportunities, which could potentially result in a change in our status as service provider to Titan or as employer of the ~~actual~~individuals ~~tax~~who ~~liability~~provide ~~that~~services ~~results~~for ~~from~~Titan. ~~their~~Any ~~share~~such ofchange may adversely and materially affect our ~~taxable~~results ~~income~~of operations and financial condition.

We and our subsidiaries may sell a portion of our properties and use the proceeds to pay down debt or acquire other properties rather than distributing the proceeds to our unitholders, and some or all of our unitholders may be allocated substantial taxable income with respect to that sale. A unitholder’s share of our taxable income upon a disposition of property by us may be ordinary income or capital gain or some combination thereof. Even where we dispose of properties that are capital assets, what otherwise would be capital gains may be recharacterized as ordinary income in order to “recapture” ordinary deductions that were previously allocated to that unitholder related to the same property.26

~~For~~PART example, the proposed “Lightfoot Transaction” as disclosed in “Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Recent Developments” section may result in capital gains that would be allocated to our unitholders. Some or all of our unitholders may be allocated amounts of such capital gains, and income tax liabilities arising therefrom may exceed cash distributions. The ultimate effect to each unitholder would depend on the unitholder’s individual tax position with respect to the units; however, taxable income allocations from us, including capital gains, increase a unitholder’s tax basis in their units. II

A unitholder’s share of our taxable income and gain (or specific items thereof) may be substantially greater than, or our tax losses and deductions (or specific items thereof) may be substantially less than, the unitholder’s interest in our economic profits. This may occur, for example, in the case of a unitholder who purchases units at a time when the value of our units or of one or more of our properties is relatively low or a unitholder who acquires units directly from us in exchange for property whose fair market value exceeds its tax basis at the time of the exchange. Cash distributions from us decrease a unitholder’s tax basis in its units, and the amount, if any, of excess distributions over a unitholder’s tax basis in its units will,

in effect, become taxable income to the unitholder, above and beyond the unitholder’s share of our taxable income and gain (or specific items thereof).

ITEM 6:

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

ExhibitNumber		Exhibit Description
Exhibit
Number
3.1		Third Amended and Restated Limited Liability Company Agreement of Atlas Energy Group, LLC, dated as of February 27, 2015 (incorporated by reference to our Current Report on Form 8-K filed March 2, 2015).
3.2		Amendment No. 1 to the Third Amended and Restated Limited Liability Company Agreement of Atlas Energy Group, LLC, dated as of February 27, 2015 (incorporated by reference to our Current Report on Form 8-K filed March 2, 2015).
3.3		Amendment No. 2 to the Third Amended and Restated Limited Liability Company Agreement of Atlas Energy Group, LLC, dated as of April 27, 2016 (incorporated by reference to our Current Report on Form 8-K filed April 29, 2016).
10.1		~~Letter~~Fifth Amendment to Credit Agreement, dated as of ~~September~~December 2928, 2017, among Atlas Energy Group, LLC, New Atlas Holdings, LLC, Atlas Lightfoot, LLC, Titan Energy Management, LLC, the lenders party thereto and Riverstone Credit Partners, L.P., as administrative agent (incorporated by reference to our Current Report on Form 8-K filed ~~October~~January 24, ~~2017~~2018).
10.2		Sixth Amendment to Credit Agreement, dated January 31, 2018, among Atlas Energy Group, LLC, New Atlas Holdings, LLC, Atlas Lightfoot, LLC, Titan Energy Management, LLC, the lenders party thereto and Riverstone Credit Partners, L.P., as administrative agent (incorporated by reference to our Current Report on Form 8-K filed February 6, 2018).
10.3		Seventh Amendment to Credit Agreement, dated March 15, 2018, among Atlas Energy Group, LLC, New Atlas Holdings, LLC, Atlas Lightfoot, LLC, Titan Energy Management, LLC, the lenders party thereto and Riverstone Credit Partners, L.P., as administrative agent (incorporated by reference to our Current Report on Form 8-K filed March 20, 2018).
31.1*		Rule 13(a)-14(a)/15(d)-14(a) Certification
31.2*		Rule 13(a)-14(a)/15(d)-14(a) Certification
32.1*		Section 1350 Certification
32.2*		Section 1350 Certification
101.INS**		XBRL Instance Document
101.INS*		XBRL Instance Document
101.SCH**		XBRL Schema Document
101.CAL**		XBRL Calculation Linkbase Document
101.LAB**		XBRL Label Linkbase Document
101.PRE**		XBRL Presentation Linkbase Document
101.DEF**		XBRL Definition Linkbase Document

*	Provided herewith.

**	Attached as Exhibit 101 to this report are documents formatted in XBRL (Extensible Business Reporting Language). The financial information contained in the XBRL-related documents is “unaudited” or “unreviewed.”

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	ATLAS ENERGY GROUP, LLC
Date: November 14, 2017	By:	/s/ EDWARD E. COHEN
Date: June 11, 2018	By:	/s/ EDWARD E. COHEN
		Edward E. Cohen Chief Executive Officer
		Edward E. Cohen
Date: November 14, 2017	By:	/s/ JEFFREY M. SLOTTERBACK
		Chief Executive Officer
		Jeffrey M. Slotterback Chief Financial Officer
Date: June 11, 2018	By:	/s/ JEFFREY M. SLOTTERBACK
Date: November 14, 2017	By:	/s/ MATTHEW J. FINKBEINER
		Jeffrey M. Slotterback
		Matthew J. Finkbeiner Chief Accounting Officer
		Chief Financial Officer
Date: June 11, 2018	By:	/s/ MATTHEW J. FINKBEINER
		Matthew J. Finkbeiner
		Chief Accounting Officer

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