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 June 30, 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 (§232.405 of this chapter)

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 August 15, 2018, there were 31,973,790 common units outstanding.

ATLAS ENERGY GROUP, LLC

INDEX TO ANNUAL REPORT

ON FORM 10-Q

TABLE OF CONTENTS

		Page
PART 1. FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Condensed Consolidated Balance Sheets as of June 30, 2018 and December 31, 2017	4
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2018 and 2017	5
	Condensed Consolidated Statement of Changes in Unitholders’ Equity for the Six Months Ended June 30, 2018	6
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2018 and 2017	7
	Notes to Condensed Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	25
Item 4.	Controls and Procedures	26

PART II. OTHER INFORMATION
Item 1A	Risk Factors	26
Item 6.	Exhibits	27

SIGNATURES		28

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 incurrence of amounts of cancellation of indebtedness income;

•

the fact that our cash flow is substantially dependent on the ability of Titan and AGP to make distributions, but neither Titan nor AGP is currently paying distributions;

•

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

•

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

•

the accuracy of estimated natural gas and oil reserves;

•

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

•

the effects of unexpected operational events and drilling conditions, and other risks associated with drilling operations, including the ability to obtain adequate water;

•

impact fees and severance taxes;

•

the effects of intense competition in the natural gas and oil industry and the availability of drilling rigs, equipment and crews;

•

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;

•

expirations of undeveloped leasehold acreage;

•

exposure to new and existing litigation; and

•

development of alternative energy resources.

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)

		June 30,		December 31,
		2018		2017
ASSETS
Current assets:
Cash and cash equivalents	$	4,713		$	12,929
Accounts receivable		1,152			564
Prepaid expenses and other		125			160
Total current assets		5,990			13,653
Property, plant and equipment, net		69,098			65,293
Other assets, net		3,677			5,102
Total assets	$	78,765		$	84,048

LIABILITIES AND UNITHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable		763			332
Advances from affiliates		10,985			9,602
Current portion of derivative payable		646			497
Accrued liabilities		5,784			7,971
Current portion of long-term debt		90,050			79,350
Total current liabilities		108,228			97,752
Asset retirement obligations and other		648			1,968

Commitments and contingencies (Note 6)

Unitholders’ equity (deficit):
Common unitholders’ equity (deficit)		(97,468	)		(84,900	)
Warrants		1,868			1,868
		(95,600	)		(83,032	)
Non-controlling interests		65,489			67,360
Total unitholders’ equity (deficit)		(30,111	)		(15,672	)
Total liabilities and unitholders’ equity (deficit)	$	78,765		$	84,048

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							Six Months Ended
	June 30,							June 30,
	2018				2017			2018			2017
Revenues:
Natural gas revenue	$	65		$	77			$	101		$	178
Oil revenue	2,787					1,723			4,417			3,908
NGLs revenue	119				74				223			184
Gain (loss) on mark-to-market derivatives	(292		)		634				(578	)		1,391
Other, net	(36		)		141			11			863
Total revenues	2,643					2,649			4,174			6,524
Costs and expenses:
Gas and oil production	986				501			1,442				1,453
General and administrative	1,821					(107	)	3,556				1,678
Depreciation, depletion and amortization	1,724					886		2,699			1,998
Total costs and expenses	4,531					1,280		7,697				5,129
Operating income (loss)	(1,888		)		1,369				(3,523	)	1,395
Interest expense	(5,754		)			(4,794	)		(11,081	)		(9,723	)
Net loss	(7,642		)			(3,425	)		(14,604	)		(8,328	)
Net loss attributable to non-controlling interests	977					343			1,871			624
Net loss attributable to unitholders’ interests	$	(6,665	)	$	(3,082		)	$	(12,733	)	$	(7,704	)
Net loss attributable to unitholders per common unit (Note 2):
Basic and Diluted	$	(0.21	)	$	(0.10		)	$	(0.40	)	$	(0.28	)
Weighted average common units outstanding (Note 2):
Diluted	31,974					29,765			31,973			27,923

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)

	Common Unitholders’ Equity (Deficit)						Warrants					Non- Controlling			Total Unitholders’ Equity
	Units			Amount			Units		Amount			Interest			(Deficit)
Balance at December 31, 2017		31,973,122		$	(84,900	)		4,668,044	$	1,868		$	67,360		$	(15,672	)
Net issued and unissued units under incentive plan	668			165				—		—			—		165
Net loss		—		(12,733		)		—		—		(1,871		)	(14,604		)
Balance at June 30, 2018	31,973,790		$	(97,468		)		4,668,044	$	1,868	$	65,489			$	(30,111	)

See accompanying notes to condensed consolidated financial statements.

ATLAS ENERGY GROUP, LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

		Six Months Ended June 30,
		2018		2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(14,604	)	$	(8,328	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		2,699			1,998
(Gain) loss on derivatives		442			(1,130	)
Amortization of deferred financing costs and debt discount		428			281
Non-cash compensation expense		165			(1,407	)
Paid-in-kind interest		10,351			8,952
Equity income in unconsolidated companies		—			(863	)
Distributions received from unconsolidated companies		92			805
Changes in operating assets and liabilities:
Accounts receivable, prepaid expenses and other		(857	)		(106	)
Advances to/from affiliates		1,383			2,338
Accounts payable and accrued liabilities		(2,234	)		(3,316	)
Net cash used in operating activities		(2,135	)		(776	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(6,027	)		—
Net cash used in investing activities		(6,027	)		—
CASH FLOWS FROM FINANCING ACTIVITIES:
Deferred financing costs and other		(54	)		(12	)
Net cash used in financing activities		(54	)		(12	)
Net change in cash and cash equivalents		(8,216	)		(788	)
Cash and cash equivalents, beginning of year		12,929			12,009
Cash and cash equivalents, end of period	$	4,713		$	11,221

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 (OTCQB: ATLS) Delaware limited liability company formed in October 2011.

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

•

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

•

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

•

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

•

A 2% preferred membership interest in Titan Energy, LLC (“Titan”), an independent developer and producer of natural gas, crude oil and NGL with operations in basins across the United States. 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.

At June 30, 2018, we had 31,973,790 common units issued and outstanding.

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 2017.

We determined that AGP is a variable interest entity (“VIE”) based on AGP’s partnership agreement; our power, as the general partner, to direct the activities that most significantly impact AGP’s economic performance; and our ownership of AGP’s incentive distribution rights. Accordingly, we consolidated the financial statements of AGP into our condensed consolidated financial statements. AGP’s operating results and asset balances are presented separately in Note 7 – Operating Segment Information. As the general partner for AGP, we have unlimited liability for the obligations of 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.

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 minimal or no 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 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. We continue to face significant liquidity issues and are currently considering, and are likely to make, changes to our capital structure to maintain sufficient liquidity, meet our debt obligations and manage and strengthen our balance sheet. Without a further extension from our lenders or other significant transaction or capital infusion, we do not expect to have sufficient liquidity to repay our first lien credit agreement at September 30, 2018, and as a result, there is substantial doubt regarding our ability to continue as a going concern.

The 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 $90.1 million of outstanding indebtedness under our credit agreements, which is net of $0.5 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 June 30, 2018.

We continually monitor capital markets and may make changes to our capital structure 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. 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.

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 and our investment in Lightfoot. The oil and natural gas industry principally conducts 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 may 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 in the current period 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 June 30,				Six Months Ended June 30,
		2018		2017		2018			2017
Gains (losses) recognized on cash settlement	$	4		$	78	$	(136	)	$	261
Changes in fair value on open derivative contracts		(296	)		556		(442	)		1,130
Gain (loss) on mark-to-market derivatives	$	(292	)	$	634	$	(578	)	$	1,391

As of June 30, 2018, we had commodity derivatives for 36,200 barrels at an average fixed price of $52.61 which mature throughout the remainder of 2018. The fair value of our commodity derivatives was a liability of $0.6 million as of June 30, 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 the delivery of each unit 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 with contract terms of one year or less, though generally subject to customary evergreen clauses pursuant to which these contracts typically automatically renew under the same terms and conditions. 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 our right to 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 $1.2 million and $0.6 million at June 30, 2018 and December 31, 2017, respectively.

Equity Method Investments

Investment in Titan. 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.

At June 30, 2018, we had a 2% Series A Preferred interest in Titan. As of June 30, 2018 and December 31, 2017, the net carrying amount of our investment in Titan was zero. During the three months ended June 30, 2018 and 2017, we recognized zero and $0.3 million, respectively, within other revenues, net on our condensed consolidated statements of operations. During the six months ended June 30, 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 June 30, 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.

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

In December 2017, Lightfoot closed on a portion of the Proposed Transaction which resulted in a net distribution to us of $21.6 million. We used the net proceeds to pay down $21.6 million of our first lien credit agreement.

The remaining part of the Proposed Transaction was subject to the closing of the purchase by Zenith of a 5.51646 % interest (and, subject to certain conditions, an additional 4.16154% interest) in Gulf LNG Holdings Group, LLC (“Gulf LNG”), which owns a liquefied natural gas regasification and storage facility in Pascagoula, Mississippi, from LCP LNG Holdings, LLC, a subsidiary of Lightfoot L.P. (“LCP’). In July 2018, an arbitration panel rejected a Gulf LNG customer contract, and therefore Zenith will not proceed with the remaining part of the Proposed Transaction. Accordingly, we will not receive any further proceeds from the Proposed Transaction.

During the three months ended June 30, 2018 and 2017, we recognized equity method income of $5.7 million and $0.3 million, respectively, within other revenues, net on our condensed consolidated statements of operations. During the six months ended June 30, 2018 and 2017, we recognized equity method income of $5.7 million and $0.5 million, respectively, within other revenues, net on our condensed consolidated statements of operations. The $5.7 million of equity method income recognized during the three and six months ended June 30, 2018 included $5.6 million of equity method income resulting from Lightfoot’s accounting for the Proposed Transaction in the fourth quarter of 2017, which was recorded in our condensed consolidated statements of operations on a two quarter lag. During the three and six months ended June 30, 2018, we recognized $5.7 million of other than temporary impairment on our equity method investment in Lightfoot within other revenues, net on our condensed consolidated statements of operations, due to an arbitration panel rejecting a Gulf LNG customer contract, which will significantly reduce Lightfoot’s future equity method income to us. During the three months ended June 30, 2018 and 2017, we received cash distributions from Lightfoot of approximately $0.1 million and $0.4 million, respectively. During the six months ended June 30, 2018 and 2017, we received cash distributions from Lightfoot of approximately $0.1 million and $0.8 million, respectively. As of June 30, 2018 and December 31, 2017, the net carrying amount of our investment in Lightfoot was zero.

Interest in Joliet Terminal

In connection with the closing of the first portion of Lightfoot’s Proposed Transaction in December 2017, we acquired a 1.8% ownership interest in Zenith Energy Terminals Joliet Holdings, LLC (“Joliet Terminal”) for $3.3 million, which is included within other assets, net, on our condensed consolidated balance sheets as of June 30, 2018 and December 31, 2017. Our investment in Joliet Terminal is classified as a nonmarketable equity security without a readily determinable fair value and is recorded at cost, less impairment, if any, in accordance with the accounting guidance measurement alternative. If an observable event occurs, we would estimate the fair value of our investment based on Level 2 inputs that could be derived from observable price changes of similar securities adjusted for insignificant differences in rights and obligations, and the changes in value would be recorded in other revenues, net on our condensed consolidated statement of operations.

Interest in Osprey Sponsor

At June 30, 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.

Pursuant to the Osprey Sponsor limited liability company agreement, owners of the founder shares agree to (i) vote their shares in favor of approving a business combination, (ii) waive their redemption rights in connection with the consummation of a business combination, and (iii) waive their rights to liquidating distributions from the trust account if Osprey fails to consummate a business combination. In addition, Osprey Sponsor has agreed to not to transfer, assign or sell any of the founder shares until the earlier of (i) one year after the date of the consummation of a business combination, or (ii) the date on which the last sales price of Osprey’s common stock equals or exceeds $12.00 per share (as adjusted for stock splits, stock dividends, reorganizations and recapitalizations) for any 20 trading days within any 30-trading day period commencing 150 days after a business combination, or earlier, in each case, if subsequent to a business combination, Osprey consummates a subsequent liquidation, merger, stock exchange, reorganization or other similar transaction which results in all of Osprey’s stockholders having the right to exchange their common stock for cash, securities or other property.

On June 4, 2018, Osprey entered into a definitive agreement to acquire the assets of Royal Resources (“Royal”), an entity owned by funds managed by Blackstone Energy Partners and Blackstone Capital Partners (“Blackstone”), (the “Business Combination”). The acquired Royal assets represent the entirety of Blackstone’s mineral interests in the Eagle Ford Shale. The combined company will be named Falcon Minerals Corporation and will be led by Osprey’s management team. Blackstone will retain a significant ownership stake at closing representing approximately 47% of outstanding common stock. Under the terms of the Business Combination, the obligations of the parties to consummate the transactions are subject to a number of customary conditions, including, among others, the receipt of required approvals of Osprey’s stockholders of the Business Combination. We will recognize the fair value of our investment in Osprey upon closing of the Business Combination and conversion of our Osprey Sponsor founder shares into Class A shares of Osprey.

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 June 30, 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 June 30, 2018. During the three and six months ended June 30, 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 June 30, 2018 and December 31, 2017, we reflected $0.2 million and $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 $0.2 million and $1.5 million, respectively, as of those same dates, within asset retirement obligations and other on our condensed consolidated balance sheets. During the three months ended June 30, 2018 and 2017, we distributed zero and $2.1 million, respectively, to certain executives related to the rabbi trust. During the six months ended June 30, 2018 and 2017, we distributed $1.3 million and $2.1 million, respectively, to certain executives related to the rabbi trust.

Accrued Liabilities

We had $5.1 million and $6.6 million of accrued payroll and benefit items at June 30, 2018 and December 31, 2017, respectively, which were included within accrued liabilities on our condensed consolidated balance sheets.

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 June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Net loss	$	(7,642	)	$	(3,425	)	$	(14,604	)	$	(8,328	)
Preferred unitholders’ dividends		—			—			—			—
Loss attributable to non-controlling interests		977			343			1,871			624
Net loss attributable to common unitholders		(6,665	)		(3,082	)		(12,733	)		(7,704	)
Less: Net income attributable to participating securities – phantom units⁽¹⁾		—			—			—			—
Net loss utilized in the calculation of net loss attributable to common unitholders per unit – diluted	$	(6,665	)	$	(3,082	)	$	(12,733	)	$	(7,704	)

(1)

Net income (loss) attributable to common unitholders for the net income (loss) attributable to common unitholders per unit calculation is net income (loss) attributable to common unitholders, less income allocable to participating securities. For the three months ended June 30, 2018 and 2017, net loss attributable to common unitholder’s ownership interest was not allocated to 11,000 and 34,000 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. For the six months ended June 30, 2018 and 2017, net loss attributable to common unitholder’s ownership interest was not allocated to 12,000 and 106,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity.

Diluted net income (loss) attributable to common unitholders per unit is calculated by dividing net income (loss) attributable to common unitholders, less income allocable to participating securities, by the sum of the weighted average number of common unitholder units outstanding and the dilutive effect of unit option awards and convertible preferred units, as calculated by the treasury stock or if converted methods, as applicable. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of our long-term incentive plan.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Weighted average number of common units—basic	31,974			29,765		31,973		27,923
Add effect of dilutive incentive awards⁽¹⁾		—		—		—		—
Add effect of dilutive convertible preferred units and warrants⁽²⁾		—		—		—		—
Weighted average number of common units—diluted	31,974			29,765		31,973		27,923

(1)

For the three months ended June 30, 2018 and 2017, approximately 1,124,000 and 3,143,000 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. For the six months ended June 30, 2018 and 2017, approximately 1,699,000 and 3,311,000 phantom units, respectively, were excluded from the computation of diluted net income (loss) attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive.

(2)

For the three and six months ended June 30, 2018 and 2017, our warrants issued in connection with the second lien credit agreement were excluded from the computation of diluted earnings attributable to common unitholders per unit because the inclusion of such warrants would have been anti-dilutive. For the three and six months ended June 30, 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 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 January 2016, the FASB updated the accounting guidance related to the recognition and measurement of financial assets and financial liabilities. The updated accounting guidance, among other things, requires that all nonconsolidated equity investments, except those accounted for under the equity method, be measured at fair value and that the changes in fair value be recognized in net income. The accounting guidance requires nonmarketable equity securities to be recorded at cost and adjusted to fair value at each reporting period. However, the guidance allows for a measurement alternative, which is to record the investments at cost, less impairment, if any, and subsequently adjust for observable price changes of identical or similar investments of the same issuer. We adopted the new accounting guidance on January 1, 2018 and applied the measurement alternative to our interest in Joliet Terminal as there is not a readily determinable fair value for our investment.

NOTE 3—PROPERTY, PLANT AND EQUIPMENT

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

	June 30, 2018			December 31, 2017
Natural gas and oil properties:
Proved properties	$	154,192		$	147,932
Support equipment and other		3,424			3,188
		157,616			151,120
Less – accumulated depreciation, depletion and amortization		(88,518	)		(85,827	)
	$	69,098		$	65,293

During the six months ended June 30, 2018, we recognized $0.1 million of non-cash investing activities capital expenditures, which were included within the changes in accounts payable and accrued liabilities on our condensed consolidated statement of cash flows. As of June 30, 2017, we did not have any non-cash investing activity capital expenditures.

NOTE 4—DEBT

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

	June 30,			December 31,
	2018			2017
First Lien Credit Agreement	$	21,828		$	20,666
Second Lien Credit Agreement	68,741				59,552
Debt discount, net of accumulated amortization of $1,400 and $1,090	(467		)		(778	)
Deferred financing costs, net of accumulated amortization of $2,796 and $2,704, respectively	(52		)		(90	)
Total debt, net	90,050				79,350
Less current maturities	(90,050		)		(79,350	)
Total long-term debt, net	$	—		$	—

The estimated fair value of our debt at June 30, 2018 approximated its carrying value of $90.1 million, which consisted of credit agreements that bear interest at variable rates and are categorized as Level 1 values.

Cash Interest. Cash payments for interest were $0.3 million and $0.2 million for the six months ended June 30, 2018 and 2017, respectively.

Credit Agreements

First Lien Credit Agreement. Our first lien 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”), was scheduled to mature on September 30, 2017. Between September 29, 2017 and July 10, 2018, we entered into a series of amendments to extend the maturity of our First Lien Credit Agreement to September 30, 2018. The First Lien Credit Agreement has an applicable cash interest rate margin for ABR Loans and Eurodollar Loans of 0.50% and 1.50%, respectively, and an 11% interest rate payable in-kind through an increase in the outstanding principal. As of June 30, 2018, we were not in compliance with the financial covenants required by the First Lien Credit Agreement.

Second 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 $0.5 million as of June 30, 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 June 30, 2018, we were not in compliance with the financial covenants required by the Second Lien Credit Agreement.

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.

The amounts outstanding under our First Lien Credit Agreement and Second Lien Credit Agreement were classified as current liabilities as both obligations are due within one year from the balance sheet date. In total, we have $90.1 million of outstanding indebtedness under our credit agreements, which is net of $0.5 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 June 30, 2018.

NOTE 5—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

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 June 30, 2018 and December 31, 2017, we had a net payable to Titan of $9.5 million and $9.6 million, respectively, 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. The $9.5 million and $9.6 million net payables to Titan include a $15.1 million amount originating prior to Titan’s Chapter 11 Filings of which there is uncertainty regarding the timing and amount of payment, if any, to Titan.

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 both of the three months ended June 30, 2018 and 2017, AGP paid a management fee of $0.6 million. During both of the six months ended June 30, 2018 and 2017, AGP paid a management fee of $1.1 million. We charge direct costs, such as salary and wages, and allocate indirect costs, such as rent for offices, to AGP based on the number of its employees who devoted their time to activities on its behalf. AGP reimburses us at cost for direct costs incurred on its behalf. AGP reimburses all necessary and reasonable indirect costs allocated by the general partner.

Relationship with Lightfoot. Jonathan Cohen, Executive Chairman of the Company’s board of directors, is the Chairman of the board of directors of Lightfoot G.P. As part of the relationship, we assumed the obligations under an agreement pursuant to which Messrs. Cohen receives compensation in recognition of his role continued service as chair of Lightfoot G.P. Pursuant to the agreement, Messrs. Cohen receives an amount equal to 10% of the distributions that we receive from the Lightfoot entities, excluding amounts that constitute a return of capital to us. During the three months ended June 30, 2018 and 2017, Messrs and Cohen received compensation in accordance with the above agreement of zero and $0.1 million, respectively. During the six months ended June 30, 2018 and 2017, Messrs and Cohen received compensation in accordance with the above agreement of zero and $0.1 million, respectively.

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 June 30, 2018.

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 June 30, 2018 and December 31, 2017, AGP had payables to Titan of $1.4 million and $0.1 million, respectively, related to the direct costs, indirect cost allocation, and timing of funding of cash accounts for reimbursement of operating activities and capital expenditures, which were 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 (see Note 4) and our general partner and limited partner interest in Lightfoot (see Notes 1 and 2).

NOTE 6—COMMITMENTS AND CONTINGENCIES

Legal Proceedings

We are parties to various routine legal proceedings arising in 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 June 30, 2018 or December 31, 2017.

NOTE 7—OPERATING SEGMENT INFORMATION

Our operations include two reportable operating segments: 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 June 30,						Six Month Ended June 30,
	2018			2017			2018			2017
Atlas Growth Partners:
Revenues⁽¹⁾	$	2,679		$	2,508		$	4,163		$	5,661
Operating costs and expenses		(1,970	)		(1,979	)		(3,407	)		(4,312	)
Depreciation, depletion and amortization expense		(1,724	)		(886	)		(2,699	)		(1,998	)
Segment loss	$	(1,015	)	$	(357	)	$	(1,943	)	$	(649	)
Corporate and other:
Revenues	$	(36	)	$	141			11			863
General and administrative		(837	)		1,585			(1,591	)		1,181
Interest expense		(5,754	)		(4,794	)		(11,081	)		(9,723	)
Segment loss	$	(6,627	)	$	(3,068	)	$	(12,661	)	$	(7,679	)
Reconciliation of segment loss to net loss:
Segment loss:
Atlas Growth Partners		(1,015	)		(357	)		(1,943	)		(649	)
Corporate and other		(6,627	)		(3,068	)		(12,661	)		(7,679	)
Net loss	$	(7,642	)	$	(3,425	)	$	(14,604	)	$	(8,328	)
Reconciliation of segment revenues to total revenues:
Segment revenues:
Atlas Growth Partners		2,679			2,508			4,163			5,661
Corporate and other		(36	)		141			11			863
Total revenues	$	2,643		$	2,649		$	4,174		$	6,524
Capital expenditures:
Atlas Growth Partners		5,802			—			6,027			—
Total capital expenditures	$	5,802		$	—		$	6,027		$	—

		June 30,	December 31,
		2018	2017
Balance sheet:
Total assets:
Atlas Growth Partners	$	73,695	$	74,219
Corporate and other		5,070		9,829
Total assets	$	78,765	$	84,048

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

ITEM 2:

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

OVERVIEW

We are a publicly traded (OTCQB: ATLS) Delaware limited liability company formed in October 2011.

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 “Item 1: Financial Statements – Note 2” for further disclosures regarding Lightfoot;

•

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

•

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 minimal or no 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 September 2018. Accordingly, our sources of liquidity are currently not sufficient to satisfy our obligations under our credit agreements.

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 assets

RECENT DEVELOPMENTS

AGP Eagle Ford Drilling. AGP deployed $6 million of cash through the second quarter and $0.8 million thereafter to drill and complete one Eagle Ford Shale well that turned in-line during May 2018. The well is expected to significantly increase AGP’s production and provide substantial cash flow. With this additional well, AGP will have enhanced ability to generate positive cash flow from its operations, 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.

FINANCIAL PRESENTATION

Our condensed consolidated financial statements contain our accounts and those of our condensed consolidated subsidiaries as of June 30, 2018. We determined that AGP is a variable interest entity (“VIE”) based on AGP’s partnership agreement; our power, as the general partner, to direct the activities that most significantly impact AGP’s economic performance; and our ownership of AGP’s incentive distribution rights. Accordingly, we consolidated the financial statements of AGP into our condensed consolidated financial statements. As the general partner for AGP, we have unlimited liability for the obligations of 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.

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 AGP, adjusted for non-controlling interests in AGP.

GENERAL TRENDS AND OUTLOOK

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

Throughout 2017 and 2018, the natural gas, oil and natural gas liquids commodity price markets have been marked by volatility. While we anticipate high levels of exploration and production activities over the long-term in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments in the development of new natural gas, oil and NGL reserves. The economics of drilling new oil wells across our acreage position in the Eagle Ford Shale in South Texas have improved substantially over the last twelve months, driven by both a rise in oil prices, as well as significant advancements in drilling and completion technology.

AGP’s future gas and oil reserves, production, cash flow, ability to make payments on our obligations and our ability to make distributions to their unitholders, depend on its success in producing our current reserves efficiently, developing its existing acreage and acquiring additional proved reserves economically. We 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. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. To the extent we would not have access to sufficient capital, our ability to drill and acquire more reserves would be negatively impacted.

RESULTS OF OPERATIONS

Gas and Oil Production

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 South Texas, an oil-rich area, in which we acquired acreage in November 2014, where we derive over 96% of our production volumes and 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.

The 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:

	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018	2017

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

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

⁽²⁾	Wells turned in line refers to wells that have been drilled, completed and connected to a gathering system.

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 June 30,				Six Months Ended June 30,
		2018	2017		2018	2017
Total production volumes per day:⁽¹⁾
Natural gas (Boed)		52		50	48	54
Oil (Bpd)		450		401	365	443
NGLs (Bpd)		57		52	53	56
Total (Boed)		559		503	466	553
Total production volumes:⁽¹⁾
Natural gas (MBoe)		5		5	9	10
Oil (MBbls)		41		36	66	80
NGLs (MBbls)		5		5	10	10
Total (MBoe)		51		46	84	100

(1)

“Bbls” and “Bpd” represent barrels and barrels per day. “Boe” and “Boed” represent barrels of oil equivalent and barrels of oil equivalent per day.

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 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 June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Production revenues (in thousands):
Natural gas revenue	$	65	$	77	$	101	$	178
Oil revenue		2,787		1,723		4,417		3,908
NGLs revenue		119		74		223		184
Total production revenues	$	2,971	$	1,874	$	4,741	$	4,270
Average sales price, unhedged:
Natural gas (per Mcf)	$	2.27	$	2.85	$	1.93	$	3.02
Oil (per Bbl)	$	68.08	$	47.25	$	66.87	$	48.76
NGLs (per Bbl)	$	22.83	$	15.63	$	23.17	$	18.25

Total Gas and Oil Costs (in thousands)	$	986	$	501	$	1,442	$	1,453

Gas and Oil Production costs (per Boe):
Lease operating expenses	$	15.26	$	7.61	$	13.19	$	11.17
Production taxes		3.53		3.33		3.47		3.02
Transportation and compression		0.16		—		0.18		0.34
	$	18.95	$	10.94	$	16.84	$	14.53

Our gas and oil production revenues were higher in the current quarter as compared to the prior year period due to a $1.0 million increase related to production from an additional well turned in line during May 2018 and a $0.6 million increase due to higher realized average oil sales prices, partially offset by a $0.5 million decrease in production volumes from existing wells. Our gas and oil production revenues were higher in the six months ended June 30, 2018 as compared to the prior year period due to a $1.0 million increase related to production from an additional well turned in line during May 2018 and a $1.0 million increase due to higher realized oil average sales prices, partially offset by a $1.4 million decrease in oil production volumes from existing wells and a $0.1 million decrease in gas prices.

Our gas and oil production costs were higher in the current quarter due to a $0.4 million increase in production costs in the Eagle Ford Shale due to our well that turned in-line during May 2018.

Other Revenues and Expenses

	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
		(in thousands)					(in thousands)
Other Revenues
Gain (loss) on mark-to-market derivatives	$	(292	)	$	634		$	(578	)	$	1,391
Other, net		(36	)		141			11			863

Other Expenses
General and administrative:
Atlas Energy Group	$	837		$	(1,585	)	$	1,591		$	(1,181)
Atlas Growth Partners		984			1,478			1,965			2,859
Total general and administrative	$	1,821		$	(107	)	$	3,556		$	1,678
Depreciation, depletion and amortization	$	1,724		$	886		$	2,699		$	1,998
Interest expense	$	5,754		$	4,794		$	11,081		$	9,723
Loss attributable to non-controlling interests	$	977		$	343		$	1,871		$	624

Gain (Loss) on Mark-to-Market Derivatives. We recognize changes in fair value of derivatives immediately within gain (loss) on mark-to-market derivatives on our condensed consolidated statements of operations. The recognized gains/(losses) during the three and six months ended June 30, 2018 and 2017 were due to changes in commodity futures prices relative to our derivative positions as of the respective prior period end.

Other, net. Our other, net revenues were lower in the current quarter as a result of a $0.2 million decrease in equity method income related to our interest in Lightfoot, partially offset by a $0.1 million decrease in equity method loss related to our 2% Series A Preferred interest in Titan. Our other, net revenues were lower for the six months ended June 30, 2018 as compared to the prior year period as a result of a $0.5 million decrease in equity method income related to our interest in Lightfoot and a $0.4 million decrease in equity method income related to our 2% Series A Preferred interest in Titan.

General and Administrative. Our $2.4 million increase in general and administrative expenses in the current quarter was due to a $1.6 million increase in stock compensation expense due to the prior year period’s forfeiture of employee awards which reversed previously recognized expenses, due to Titan’s sale of its Appalachian assets and reductions in workforce, a $0.6 million increase in other corporate costs, and a $0.2 million increase in salaries, wages and benefits. AGP’s decrease in general and administrative expenses for the current period was due to a $0.5 million decrease in salaries, wages and other corporate activity costs allocated to AGP as a result of lower corporate activities.

Our $2.8 million increase in general and administrative expenses for the six months ended June 30, 2018 was due to a $1.6 million increase in stock compensation expense due to the prior year period’s forfeiture of employee awards which reversed previously recognized expense, due to Titan’s sale of its Appalachian assets and reductions in workforce, a $0.6 million increase in other corporate costs, and a $0.6 million increase in salaries, wages and benefits. AGP’s decrease in general and administrative expenses for the six months ended June 30, 2018 was due to a $0.9 million decrease in salaries, wages and other corporate activity costs allocated to AGP as a result of lower corporate activities.

Depreciation, Depletion and Amortization. The increase in depreciation, depletion and amortization for the current period and the six months ended June 30, 2018 as compared to the prior year periods was due to an $0.8 million and $0.7 million increase, respectively, in AGP’s depletion expense in the Eagle Ford Shale due to the additional well that turned in-line in May 2018.

Interest Expense. The increase in our interest expense in the current quarter consisted of a $0.7 million increase of paid-in-kind interest on our credit agreements and a $0.3 million increase in the amortization of our warrants partially offset by a $0.1 million decrease in cash interest paid on our first lien credit agreement due to a lower principal balance from the pay down in the fourth quarter of 2017. The increase in our interest expense for the six months ended June 30, 2018 as compared to the prior year period consisted of a $1.3 million increase of paid-in-kind interest on our credit agreements and a $0.2 million increase in the amortization of our warrants partially offset by a $0.1 million decrease in cash interest paid on our first lien credit agreement due to a lower principal balance from the pay down in the fourth quarter of 2017.

LIQUIDITY AND CAPITAL RESOURCES

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

See “Item 1: Financials Statements - Note 4” for disclosures regarding our credit agreements’ terms and provisions.

Cash Flows

	Six Months Ended June 30,
	2018			2017
	(in thousands)
Net cash used in operating activities	$	(2,135	)	$	(776	)
Net cash used in investing activities		(6,027	)		—
Net cash used in financing activities		(54	)		(12	)

Six Months Ended June 30, 2018 Compared with the Six Months Ended June 30, 2017

Cash Flows From Operating Activities:

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

•

A decrease of $1.0 million of net cash provided by advances to/from affiliates related to direct and indirect cost allocations and the timing of funding of cash accounts for reimbursement of general and administrative expenses, operating activities and capital expenditures; and

•

an increase of $0.6 million net cash used in operating activities related to cash settlement payments on our commodity derivative contracts; partially offset by

•

an increase of $0.2 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 collections net of payments for our royalties, lease operating expenses, gathering, processing and transportation expenses, severance taxes, and general and administrative expenses.

Cash Flows From Investing Activities:

The change in cash flows used in investing activities compared with the prior year period was due to an increase of $6.0 million in capital expenditures related to our development activities as we began drilling in the first quarter of 2018.

Cash Flows From Financing Activities:

The change in cash flows used in financing activities compared with the prior year period was due to an increase of approximately $42,000 in deferred financing costs and discounts.

Capital Requirements

During the six months ended June 30, 2018, our capital expenditures were approximately $6.0 million, related to our well drilling and completion costs. As of June 30, 2018, we had $0.1 million in accrued liabilities for our drilling and completion and capital expenditures.

The capital expenditures of our natural gas and oil production assets primarily consist of discretionary expenditures to maintain or increase production margin in future periods, as well as land, gathering and processing, and other non-drilling capital expenditures.

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, 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, 2017.

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, 2017.

Recently Issued Accounting Standards

See Item 1: Financials Statements - Note 2” 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 December 31, 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 June 30, 2018, we had $90.1 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 June 30, 2019 by $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 June 30, 2019 of $0.6 million, net of non-controlling interests.

As of June 30, 2018, AGP had the following commodity derivatives:

Crude Oil -- Fixed Price Swaps

Production

Period Ending

December 31,

Volumes

Average

Fixed

Price

(Bbl)⁽¹⁾

(per Bbl)

2018⁽²⁾

36,200

52.61

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

(2)	The production volumes for 2018 include the remaining six months of 2018 beginning July 1, 2018.

ITEM 4:

CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer (principal executive officer) and our Chief Financial Officer (principal financial officer) has evaluated the effectiveness of our disclosure controls and procedures in ensuring that the information required to be disclosed in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, including ensuring that such information is accumulated and communicated to management (including the principal executive and financial officers) as appropriate to allow timely decisions regarding required disclosure.

Based on such evaluation, our principal executive and financial officers have concluded that such disclosure controls and procedures were effective as of June 30, 2018.

Changes in Internal Control over Financial Reporting

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, 2017 except as follows.

We are substantially dependent upon reimbursements from Titan to fund significant general and administrative and other expenses that we incur on its behalf; any change in that reimbursement relationship, including due to potential restructuring opportunities that Titan is currently exploring, may adversely impact our results of operations and financial condition.

Pursuant to the Delegation of Management Agreement and Omnibus Agreement we entered into with Titan upon its emergence from bankruptcy in September 2016, we operate Titan’s business on a day to day basis, and in exchange, Titan reimburses us for expenses incurred in connection with our provision of services, which reimbursement covers a significant portion of our aggregate compensation and other general and administrative expenses. In that fashion, we rely substantially on Titan to reimburse us so that we can operate our business and compensate our employees. Titan is currently exploring strategic alternatives or other restructuring opportunities, which could potentially result in a change in our status as service provider to Titan or as employer of the individuals who provide services for Titan. Any such change may adversely and materially affect our results of operations and financial condition.

PART II

ITEM 6:

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

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		Eighth Amendment to Credit Agreement, dated as of April 26, 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 May 2, 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.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.”

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: August 17, 2018	By:	/s/ EDWARD E. COHEN
		Edward E. Cohen
		Chief Executive Officer

Date: August 17, 2018	By:	/s/ JEFFREY M. SLOTTERBACK
		Jeffrey M. Slotterback
		Chief Financial Officer

Date: August 17, 2018	By:	/s/ MATTHEW J. FINKBEINER
		Matthew J. Finkbeiner
		Chief Accounting Officer

Atlas Energy Group, LLC 10-Q