10-Q

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 March 31, 2018

OR

☐ 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: 000-55603

Atlas Growth Partners, L.P.

(Exact name of registrant as specified in its charter)

Delaware	80-0906030
(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  ☒

The number of outstanding common limited partner units of the registrant on June 8, 2018 was 23,300,410.

ATLAS GROWTH PARTNERS, L.P.

INDEX TO ANNUAL REPORT

ON FORM 10-Q

TABLE OF CONTENTS

		PAGE
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Condensed Consolidated Balance Sheets as of March 31, 2018 and December 31, 2017	4
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2018 and 2017	5
	Condensed Consolidated Statement of Changes in Partners’ Capital for the Three Months Ended March 31, 2018	6
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 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	13
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	17
Item 4.	Controls and Procedures	17
PART II. OTHER INFORMATION
Item 6.	Exhibits	19
SIGNATURES		20

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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:

• the suspension of our primary offering efforts and our quarterly distribution;

• our ability to continue as a going concern;

• our business and investment strategy;

• our ability to make acquisitions and other investments in a timely manner on acceptable terms or at all;

• our ability to obtain long-term financing for our property acquisitions and drilling activities in a timely manner;

• the effect of general market, oil and gas market (including volatility of realized price for oil, natural gas and natural gas liquids), and economic and political conditions;

• uncertainties with respect to identified drilling locations and estimates of reserves;

• our ability to generate sufficient cash flows to make distributions to our unitholders;

• the degree and nature of our competition; and

• the availability of qualified personnel at our general partner and Atlas Energy Group, LLC.

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, 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.

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ATLAS GROWTH PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

	March 31,			December 31,
	2018			2017
ASSETS
Current assets:
Cash and cash equivalents	$	6,918		$	8,236
Accounts receivable		482			572
Advances to affiliates		129			—
Total current assets		7,529			8,808
Property, plant and equipment, net		68,963			65,293
Other assets, net		105			118
Total assets	$	76,597		$	74,219
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	483		$	332
Advances from affiliates		588			606
Current portion of derivative liability		579			497
Accrued well drilling and completion costs		3,311			—
Accrued liabilities		196			407
Total current liabilities		5,157			1,842
Asset retirement obligations and other		456			465
Commitments and contingencies (Note 5)
Partners’ Capital:
General partner’s interest		(2,630	)		(2,611	)
Common limited partners’ interests		70,478			71,387
Common limited partners’ warrants		3,136			3,136
Total partners’ capital		70,984			71,912
Total liabilities and partners’ capital	$	76,597		$	74,219

See accompanying notes to condensed consolidated financial statements.

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ATLAS GROWTH PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)

	Three Months Ended March 31,
	2018			2017
Revenues:
Natural gas revenue		36		$	101
Oil revenue		1,630			2,185
NGLs revenue		104			110
Gain (loss) on mark-to-market derivatives	(286		)		757
Total revenues	1,484				3,153
Costs and expenses:
Gas and oil production	456				952
General and administrative	124				198
General and administrative – affiliate	857				1,183
Depreciation, depletion and amortization	975				1,112
Total costs and expenses	2,412				3,445
Net loss	$	(928	)	$	(292	)
Allocation of net loss attributable to common limited    partners and the general partner:
Common limited partners’ interest	$	(909	)	$	(286	)
General partner’s interest	(19		)		(6	)
Net loss attributable to common limited partners per unit:
Basic and Diluted	$	(0.04	)	$	(0.01	)
Weighted average common limited partner units outstanding:
Basic and Diluted	23,300				23,300

See accompanying notes to condensed consolidated financial statements.

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ATLAS GROWTH PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

(in thousands, except unit data)

(Unaudited)

	General Partner’s Interest						Common Limited Partners’ Interests					Common Limited Partners’ Warrants				Total
	Class A Units		Amount				Units		Amount			Warrants		Amount			Partners’ Capital
Balance at December 31, 2017		100	$		(2,611	)		23,300,410	$	71,387			2,330,041	$	3,136	$	71,912
Net loss		—	(19			)	—		(909		)	—		—		(928		)
Balance at March 31, 2018		100	$	(2,630		)	23,300,410		$	70,478		2,330,041		$	3,136	$	70,984

See accompanying notes to condensed consolidated financial statements.

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ATLAS GROWTH PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Three Months Ended March 31,
	2018			2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(928	)	$	(292	)
Adjustments to reconcile net loss to net cash provided by    (used in) operating activities:
Depreciation, depletion and amortization		975			1,112
(Gains) losses on derivatives		237			(705	)
Amortization of deferred financing costs		13			13
Changes in operating assets and liabilities:
Accounts receivable, prepaid expenses and other		(65	)		18
Advances to/from affiliates		(147	)		488
Accounts payable and accrued liabilities		(1,178	)		(293	)
Net cash provided by (used in) operating activities		(1,093	)		341
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(225	)		—
Net cash used in investing activities		(225	)		—
CASH FLOWS FROM FINANCING ACTIVITIES:
Net cash provided by (used in) financing activities		—			—
Net change in cash and cash equivalents		(1,318	)		341
Cash and cash equivalents, beginning of year		8,236			8,586
Cash and cash equivalents, end of period	$	6,918		$	8,927

See accompanying notes to condensed consolidated financial statements.

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ATLAS GROWTH PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – BASIS OF PRESENTATION

We are 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. Our general partner, Atlas Growth Partners GP, LLC owns 100% of our general partner units (which are entitled to receive 2% of the cash distributed by us without any obligation to make further capital contributions) and all of the incentive distribution rights through which it manages and effectively controls us.

Atlas Energy Group, LLC (“ATLS”), a publicly traded Delaware limited liability company (OTCQB: ATLS), manages and controls us through its 2.1% limited partner interest in us and 80% member interest in our general partner. Current and former members of ATLS management own the remaining 20% member interest in our general partner.

In addition to its general and limited partner interest in us, ATLS also holds a Series A Preferred Share (which entitles it to receive 2% of distributions, subject to potential dilution in the event of future equity interests, and to appoint four of seven directors) in Titan Energy, LLC (“Titan”), an independent developer and producer of natural gas, crude oil and NGLs, with operations in basins across the United States, and a general and limited partner interest in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, which incubate new MLPs and invest in existing MLPs. At March 31, 2018, we had 23,300,410 common limited partner units issued and outstanding.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and the applicable rules and regulations of the Securities and Exchange Commission regarding interim financial reporting and include all adjustments that are necessary for a fair presentation of our consolidated results of operations, financial condition and cash flows for the periods shown, including normal, recurring accruals and other items. The condensed 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.

Principles of Consolidation

Our condensed consolidated financial statements include our accounts and the accounts of our wholly-owned subsidiaries. Transactions between us and other ATLS managed operations have been identified in the condensed consolidated financial statements as transactions between affiliates, where applicable. All intercompany transactions have been eliminated.

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, accruals for well drilling and completion costs, depletion and impairment of gas and oil properties, and fair value of derivative instruments. The oil and gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Actual results could differ from those estimates.

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.

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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 which mature throughout 2018.  The fair value of our commodity derivatives was a liability of $0.6 million as of March 31, 2018.

Segment Reporting

We derive revenue from our gas and oil production. These production facilities have been aggregated into one reportable segment because the facilities have similar long-term economic characteristics, products and types of customers.

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

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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.

Net Income (Loss) Per Common Unit

Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners, which is determined after the deduction of the general partner’s interest, by the weighted average number of common limited partner units outstanding during the period.

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

	Three Months Ended
	March 31,
	2018			2017
Net loss	$	(928	)	$	(292	)
Less: General partner’s interest		(19	)		(6	)
Net loss attributable to common limited partners	$	(909	)	$	(286	)

Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of common limited partner warrants, as calculated by the treasury stock method.

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

	Three Months Ended
	March 31,
	2018		2017
Weighted average number of common units – basic		23,300		23,300
Add effect of dilutive awards(1)		—		—
Weighted average number of common units – diluted		23,300		23,300

(1) For both the three months ended March 31, 2018 and 2017, 2,330,000 common limited partner warrants were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of units issuable upon the exercise of the warrants 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

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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.

NOTE 3 – PROPERTY, PLANT AND EQUIPMENT

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

	March 31, 2018			December 31, 2017
Natural gas and oil properties:
Proved properties	$	152,581		$	147,932
Support equipment and other		3,180			3,188
		155,761			151,120
Less – accumulated depreciation, depletion and amortization		(86,798	)		(85,827	)
	$	68,963		$	65,293

During the three months ended March 31, 2018, we recognized $4.4 million of non-cash investing activities capital expenditures, which were included within the changes in accounts payable and accrued liabilities on our condensed consolidated statements of cash flows. During the three months ended March 31, 2017, we did not have any non-cash investing activity capital expenditures.

NOTE 4 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Relationship with ATLS. We do not directly employ any persons to manage or operate our business. These functions are provided by employees of ATLS and/or its affiliates, including Titan. Our general partner receives an annual management fee in connection with its management of us equivalent to 1% of capital contributions per annum.  During each of the three months ended March 31, 2018 and 2017, we paid a management fee of $0.6 million. Other indirect costs, such as rent for offices, are allocated by Titan at the direction of ATLS based on the number of its employees who devoted their time to activities on our behalf. We reimburse ATLS at cost for direct costs incurred on our behalf. We reimburse all necessary and reasonable costs allocated to us by ATLS. All of the costs paid or payable to ATLS and our general partner discussed above were included in general and administrative expenses – affiliate in the condensed consolidated statements of operations. As of each March 31, 2018 and December 31, 2017, we had payables to ATLS of $0.6 million, related to the management fee, direct costs and allocated indirect costs, which were recorded in advances from affiliates in the condensed consolidated balance sheets.

Relationship with Titan. At the direction of ATLS, we reimburse Titan for direct costs, such as salaries and wages, charged to us based on ATLS employees who incurred time to activities on our behalf and indirect costs, such as rent and other general and administrative costs, allocated to us based on the number of ATLS employees who devoted their time to activities on our behalf. As of March 31, 2018 and December 31, 2017, we had a $0.1 million receivable from Titan and $0.1 million payable 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.

NOTE 5 – COMMITMENTS AND CONTINGENCIES

General Commitments

As of March 31, 2018, certain of our executives are parties to employment agreements with ATLS or Titan that provide compensation and certain other benefits. The agreements provide for severance payments under certain circumstances.

As of March 31, 2018, we did not have any commitments related to our drilling and completion and capital expenditures.

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Legal Proceedings

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

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ITEM 2: MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

BUSINESS OVERVIEW

We are 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. Our general partner, Atlas Growth Partners GP, LLC owns 100% of our general partner units (which are entitled to receive 2% of the cash distributed by us without any obligation to make further capital contributions) and all of the incentive distribution rights through which it manages and effectively controls us.

Atlas Energy Group, LLC (“ATLS”), a publicly traded Delaware limited liability company (OTCQB: ATLS), manages and controls us through its 2.1% limited partner interest in us and 80% member interest in our general partner. Current and former members of ATLS management own the remaining 20% member interest in our general partner.

MANAGEMENT OVERVIEW AND OUTLOOK

Since our inception in 2013, we have developed into a company with a core position in the Eagle Ford Shale in South Texas generating stable cash flows, despite a significant decline in oil and natural gas prices.  While the energy markets continue to be marked by volatility, we are focused on refining our operations to reduce expenses.  As of March 31, 2018, we have $6.9 million of cash on our balance sheet and no long-term debt.

We deployed $0.2 million of cash on hand during the quarter and $6.3 million subsequently to drill and complete one Eagle Ford Shale well that turned in-line during May 2018. The well is expected to significantly increase our production and provide substantial cash flow. With this additional well, we have enhanced ability to generate positive cash flow from our operations, grow our 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.

While we manage the company on a daily basis to optimize operating results, we also continue to explore ways to strategically grow and transform the company. Quarterly, we consider our ability to make distributions to unitholders; however, based on the company’s financial position and cash flows, we have not yet elected to resume making distributions following the suspension of distributions in November 2016. We continue to explore opportunities to drill additional wells across our Eagle Ford Shale locations.  Our ability to convert our locations into cash-flowing wells may be improved by raising additional capital.  We continue to evaluate the most attractive way to accelerate growth of our portfolio and drive value to all of our equity holders.  We will continue to vigorously pursue all options to maximize returns to our investors.

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 the first quarter of 2018, the natural gas, oil and natural gas liquids commodity price markets were 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.

Our future gas and oil reserves, production, cash flow, our ability to make payments on our obligations and our ability to make distributions to our unitholders, depend on our success in producing our current reserves efficiently, developing our 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.

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RESULTS OF OPERATIONS

Gas and Oil Production

Production Profile. 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 92% of our production volumes and 96% of 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 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)		—	—

⁽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 volumes per day for the periods indicated:

	Three Months Ended March 31,
	2018	2017
Total production volumes per day: (1)
Natural gas (Boed)	44		59
Oil (Bpd)	279		485
NGLs (Bpd)	49		60
Total (Boed)	372		604
Total production volumes: (1)
Natural gas (MBoe)	4		5
Oil (MBbls)	25		44
NGLs (MBbls)	4		5
Total (MBoe)	34		54

(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 oil. The following table presents our production revenues, average sales prices for our natural gas, oil, and

14

natural gas liquids production, and gas and oil production costs, along with our average production costs, which include lease operating expenses, taxes, and transportation and compression costs, for the periods indicated:

	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

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.

Our 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.

OTHER REVENUES AND EXPENSES

	Three Months Ended March 31,
	2018			2017
	(in thousands)
Other Revenues
Gain (loss) on mark-to-market derivatives	$	(286	)	$	757
Other Expenses
General and administrative	$	981		$	1,381
Depreciation, depletion and amortization		975			1,112

Gain (Loss) on Mark-to-Market Derivatives. We recognize changes in fair value of derivatives immediately within gain on mark-to-market derivatives on our condensed consolidated statements of operations. The recognized losses and gains during the three months ended March 31, 2018 and 2017 were due to changes in commodity futures prices relative to our derivative positions as of the respective prior year end.

General and Administrative Expenses. The decrease in general and administrative expenses for the current period as compared to the prior period was due to a $0.4 million decrease in salaries, wages and other corporate activity costs allocated to us as a result of lower corporate activities.

15

Depreciation, Depletion and Amortization. The decrease in depreciation, depletion and amortization for the current period as compared to the prior period was due to a $0.1 million decrease in our depletion expense resulting from lower production volumes.

LIQUIDITY AND CAPITAL RESOURCES

General

We fund our operations through cash generated from operations. Our future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas remain volatile but have improved during 2017 and the first quarter of 2018 as compared to prior years.

As of March 31, 2018, we have $6.9 million of cash on our balance sheet and no long-term debt.

Cash Flows

	Three Months Ended March 31,
	2018			2017
		(in thousands)
Net cash provided by (used in) operating activities	$	(1,093	)	$	341
Net cash used in investing activities		(225	)		—
Net cash used in financing activities		—			—

Three Months Ended March 31, 2018 Compared with the Three Months Ended March 31, 2017

Cash Flows from Operating Activities:

The change in cash flows provided by (used in) operating activities compared with the prior period was due to:

• an increase of $0.6 million net cash used in advances to affiliates related to the direct costs and indirect for operating activities and timing of funding of cash accounts; and

• an increase of $0.8 million net cash provided by operating activities for cash receipts and disbursements attributable to our normal monthly operating cycle for gas and oil production revenues, and collections net of payments for royalties, lease operating 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 $0.2 million in capital expenditures related to our development activities as we began drilling in Q1 2018.

Capital Requirements

During the three months ended March 31, 2018, our capital expenditures were approximately $0.2 million, related to our well drilling and completion costs. As of March 31, 2018, we had $3.3 million in accrued liabilities for our drilling and completion and capital expenditures.

16

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 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 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 March 31, 2019. Only the potential impact of hypothetical assumptions was analyzed. The analysis does not consider other possible effects that could impact our business.

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 net loss for the twelve-month period ending March 31, 2019 of $0.6 million.

Realized pricing of natural gas, oil, and natural gas liquids production is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas, oil and natural gas liquids production. Pricing for natural gas, oil and natural gas liquids production has been volatile and unpredictable for many years.

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

Crude Oil – Fixed Price Swaps

Production Period Ending December 31,	Volumes(1)		Average Fixed Price
2018(2)		74,500	$	52.510

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

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

ITEM 4: CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

17

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 ineffective as of March 31, 2018, because we were unable to timely file this Quarterly Report on Form 10-Q due to resource constraints.

Changes in Internal Control over Financial 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 internal control over financial reporting and where appropriate, made changes to these controls to address related system functionality and potential gaps.

Other than the 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.

18

PART II

ITEM 6: EXHIBITS

Exhibit No.	Description
3.1	Certificate of Limited Partnership of Atlas Growth Partners, L.P. (incorporated by reference to the registration statement on Form S-1 (File No. 333-207537) filed on October 21, 2015).
3.2	First Amended and Restated Limited Partnership Agreement of Atlas Growth Partners, L.P. (incorporated by reference to our Current Report on Form 8-K filed on April 6, 2016).
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(1)
101.SCH*	XBRL Schema Document(1)
101.CAL*	XBRL Calculation Linkbase Document(1)
101.LAB*	XBRL Label Linkbase Document(1)
101.PRE*	XBRL Presentation Linkbase Document(1)
101.DEF*	XBRL Definition Linkbase Document(1)

* Filed herewith

(1) 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.”

19

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 GROWTH PARTNERS, L.P.

By: Atlas Growth Partners GP, LLC, its General Partner

Date: June 11, 2018	By:	/s/ EDWARD E. COHEN
		Edward E. Cohen Chairman of the Board and Chief Executive Officer
Date: June 11, 2018	By:	/s/ JEFFREY M. SLOTTERBACK
		Jeffrey M. Slotterback Chief Financial Officer
Date: June 11, 2018	By:	/s/ MATTHEW J. FINKBEINER
		Matthew J. Finkbeiner Chief Accounting Officer

20

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Edward E. Cohen, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended March 31, 2018 of Atlas Growth Partners, L.P.;

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

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

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

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

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

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

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

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

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

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

/s/ EDWARD E. COHEN

Edward E. Cohen

Chief Executive Officer

June 11, 2018

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Jeffrey M. Slotterback, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended March 31, 2018 of Atlas Growth Partners, L.P.;

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

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

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

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

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

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

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

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

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

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

/s/ JEFFREY M. SLOTTERBACK

Jeffrey M. Slotterback

Chief Financial Officer

June 11, 2018

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Atlas Growth Partners, L.P. (the “Partnership”) on Form 10-Q for the quarter ended March 31, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Edward E. Cohen, Chief Executive Officer of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

/s/ EDWARD E. COHEN

Edward E. Cohen

Chief Executive Officer

June 11, 2018

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Atlas Growth Partners, L.P. (the “Partnership”) on Form 10-Q for the quarter ended March 31, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jeffrey M. Slotterback, Chief Financial Officer of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

/s/ JEFFREY M. SLOTTERBACK

Jeffrey M. Slotterback

Chief Financial Officer

June 11, 2018

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2018	Jun. 08, 2018
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q1
Entity Registrant Name	Atlas Growth Partners, L.P.
Entity Central Index Key	0001572702
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Units Outstanding		23,300,410
Trading Symbol	AGP

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 6,918	$ 8,236
Accounts receivable	482	572
Advances to affiliates	129
Total current assets	7,529	8,808
Property, plant and equipment, net	68,963	65,293
Other assets, net	105	118
Total assets	76,597	74,219
Current liabilities:
Accounts payable	483	332
Advances from affiliates	588	606
Current portion of derivative liability	579	497
Accrued well drilling and completion costs	3,311
Accrued liabilities	196	407
Total current liabilities	5,157	1,842
Asset retirement obligations and other	456	465
Commitments and contingencies (Note 5)
Partners’ Capital:
General partner’s interest	(2,630)	(2,611)
Common limited partners’ interests	70,478	71,387
Common limited partners’ warrants	3,136	3,136
Total partners’ capital	70,984	71,912
Total liabilities and partners’ capital	$ 76,597	$ 74,219

XML

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenues:
Gain (loss) on mark-to-market derivatives	$ (286)	$ 757
Total revenues	1,484	3,153
Costs and expenses:
Gas and oil production	456	952
General and administrative	124	198
General and administrative – affiliate	857	1,183
Depreciation, depletion and amortization	975	1,112
Total costs and expenses	2,412	3,445
Net loss	(928)	(292)
Allocation of net loss attributable to common limited partners and the general partner:
Common limited partners’ interest	(909)	(286)
General partner’s interest	$ (19)	$ (6)
Net loss attributable to common limited partners per unit:
Basic and Diluted	$ (0.04)	$ (0.01)
Weighted average common limited partner units outstanding:
Basic and Diluted	23,300	23,300
Natural Gas
Revenues:
Revenues	$ 36	$ 101
Oil
Revenues:
Revenues	1,630	2,185
NGLs
Revenues:
Revenues	$ 104	$ 110

XML

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL (Unaudited) - 3 months ended Mar. 31, 2018 - USD ($) $ in Thousands	Total	General Partner's Interest General Class A	Common Limited Partners' Interests	Common Limited Partners' Warrants
Balance at Dec. 31, 2017	$ 71,912	$ (2,611)	$ 71,387	$ 3,136
Balance (units) at Dec. 31, 2017		100	23,300,410	2,330,041
Net loss	(928)	$ (19)	$ (909)
Balance at Mar. 31, 2018	$ 70,984	$ (2,630)	$ 70,478	$ 3,136
Balance (units) at Mar. 31, 2018		100	23,300,410	2,330,041

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$ (928)	$ (292)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	975	1,112
(Gains) losses on derivatives	237	(705)
Amortization of deferred financing costs	13	13
Changes in operating assets and liabilities:
Accounts receivable, prepaid expenses and other	(65)	18
Advances to/from affiliates	(147)	488
Accounts payable and accrued liabilities	(1,178)	(293)
Net cash provided by (used in) operating activities	(1,093)	341
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(225)
Net cash used in investing activities	(225)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net cash provided by (used in) financing activities	0	0
Net change in cash and cash equivalents	(1,318)	341
Cash and cash equivalents, beginning of year	8,236	8,586
Cash and cash equivalents, end of period	$ 6,918	$ 8,927

XML

Basis of Presentation

3 Months Ended

Mar. 31, 2018

Organization Consolidation And Presentation Of Financial Statements [Abstract]

Basis of Presentation

NOTE 1 – BASIS OF PRESENTATION

We are 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. Our general partner, Atlas Growth Partners GP, LLC owns 100% of our general partner units (which are entitled to receive 2% of the cash distributed by us without any obligation to make further capital contributions) and all of the incentive distribution rights through which it manages and effectively controls us.

Atlas Energy Group, LLC (“ATLS”), a publicly traded Delaware limited liability company (OTCQB: ATLS), manages and controls us through its 2.1% limited partner interest in us and 80% member interest in our general partner. Current and former members of ATLS management own the remaining 20% member interest in our general partner.

In addition to its general and limited partner interest in us, ATLS also holds a Series A Preferred Share (which entitles it to receive 2% of distributions, subject to potential dilution in the event of future equity interests, and to appoint four of seven directors) in Titan Energy, LLC (“Titan”), an independent developer and producer of natural gas, crude oil and NGLs, with operations in basins across the United States, and a general and limited partner interest in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, which incubate new MLPs and invest in existing MLPs. At March 31, 2018, we had 23,300,410 common limited partner units issued and outstanding.

XML

Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2018

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and the applicable rules and regulations of the Securities and Exchange Commission regarding interim financial reporting and include all adjustments that are necessary for a fair presentation of our consolidated results of operations, financial condition and cash flows for the periods shown, including normal, recurring accruals and other items. The condensed 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.

Principles of Consolidation

Our condensed consolidated financial statements include our accounts and the accounts of our wholly-owned subsidiaries. Transactions between us and other ATLS managed operations have been identified in the condensed consolidated financial statements as transactions between affiliates, where applicable. All intercompany transactions have been eliminated.

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, accruals for well drilling and completion costs, depletion and impairment of gas and oil properties, and fair value of derivative instruments. The oil and gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Actual results could differ from those estimates.

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 which mature throughout 2018.  The fair value of our commodity derivatives was a liability of $0.6 million as of March 31, 2018.

Segment Reporting

We derive revenue from our gas and oil production. These production facilities have been aggregated into one reportable segment because the facilities have similar long-term economic characteristics, products and types of customers.

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.

Net Income (Loss) Per Common Unit

Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners, which is determined after the deduction of the general partner’s interest, by the weighted average number of common limited partner units outstanding during the period.

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

	Three Months Ended
	March 31,
	2018			2017
Net loss	$	(928	)	$	(292	)
Less: General partner’s interest		(19	)		(6	)
Net loss attributable to common limited partners	$	(909	)	$	(286	)

Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of common limited partner warrants, as calculated by the treasury stock method.

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

	Three Months Ended
	March 31,
	2018		2017
Weighted average number of common units – basic		23,300		23,300
Add effect of dilutive awards(1)		—		—
Weighted average number of common units – diluted		23,300		23,300

(1) For both the three months ended March 31, 2018 and 2017, 2,330,000 common limited partner warrants were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of units issuable upon the exercise of the warrants 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.

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Property, Plant and Equipment

3 Months Ended

Mar. 31, 2018

Property Plant And Equipment [Abstract]

Property, Plant and Equipment

NOTE 3 – PROPERTY, PLANT AND EQUIPMENT

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

	March 31, 2018			December 31, 2017
Natural gas and oil properties:
Proved properties	$	152,581		$	147,932
Support equipment and other		3,180			3,188
		155,761			151,120
Less – accumulated depreciation, depletion and amortization		(86,798	)		(85,827	)
	$	68,963		$	65,293

During the three months ended March 31, 2018, we recognized $4.4 million of non-cash investing activities capital expenditures, which were included within the changes in accounts payable and accrued liabilities on our condensed consolidated statements of cash flows. During the three months ended March 31, 2017, we did not have any non-cash investing activity capital expenditures.

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Certain Relationships and Related Party Transactions

3 Months Ended

Mar. 31, 2018

Related Party Transactions [Abstract]

Certain Relationships and Related Party Transactions

NOTE 4 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Relationship with ATLS. We do not directly employ any persons to manage or operate our business. These functions are provided by employees of ATLS and/or its affiliates, including Titan. Our general partner receives an annual management fee in connection with its management of us equivalent to 1% of capital contributions per annum.  During each of the three months ended March 31, 2018 and 2017, we paid a management fee of $0.6 million. Other indirect costs, such as rent for offices, are allocated by Titan at the direction of ATLS based on the number of its employees who devoted their time to activities on our behalf. We reimburse ATLS at cost for direct costs incurred on our behalf. We reimburse all necessary and reasonable costs allocated to us by ATLS. All of the costs paid or payable to ATLS and our general partner discussed above were included in general and administrative expenses – affiliate in the condensed consolidated statements of operations. As of each March 31, 2018 and December 31, 2017, we had payables to ATLS of $0.6 million, related to the management fee, direct costs and allocated indirect costs, which were recorded in advances from affiliates in the condensed consolidated balance sheets.

Relationship with Titan. At the direction of ATLS, we reimburse Titan for direct costs, such as salaries and wages, charged to us based on ATLS employees who incurred time to activities on our behalf and indirect costs, such as rent and other general and administrative costs, allocated to us based on the number of ATLS employees who devoted their time to activities on our behalf. As of March 31, 2018 and December 31, 2017, we had a $0.1 million receivable from Titan and $0.1 million payable 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.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2018

Commitments And Contingencies Disclosure [Abstract]

Commitments and Contingencies

NOTE 5 – COMMITMENTS AND CONTINGENCIES

General Commitments

As of March 31, 2018, certain of our executives are parties to employment agreements with ATLS or Titan that provide compensation and certain other benefits. The agreements provide for severance payments under certain circumstances.

As of March 31, 2018, we did not have any commitments related to our drilling and completion and capital expenditures.

Legal Proceedings

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

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Summary of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2018

Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and the applicable rules and regulations of the Securities and Exchange Commission regarding interim financial reporting and include all adjustments that are necessary for a fair presentation of our consolidated results of operations, financial condition and cash flows for the periods shown, including normal, recurring accruals and other items. The condensed 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.

Principles of Consolidation

Principles of Consolidation

Our condensed consolidated financial statements include our accounts and the accounts of our wholly-owned subsidiaries. Transactions between us and other ATLS managed operations have been identified in the condensed consolidated financial statements as transactions between affiliates, where applicable. All intercompany transactions have been eliminated.

Use of Estimates

Use of Estimates

The preparation of our condensed consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of our condensed consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. Our condensed consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, accruals for well drilling and completion costs, depletion and impairment of gas and oil properties, and fair value of derivative instruments. The oil and gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Actual results could differ from those estimates.

Derivative Instruments

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 which mature throughout 2018.  The fair value of our commodity derivatives was a liability of $0.6 million as of March 31, 2018.

Segment Reporting

Segment Reporting

We derive revenue from our gas and oil production. These production facilities have been aggregated into one reportable segment because the facilities have similar long-term economic characteristics, products and types of customers.

Revenue Recognition

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.

Net Income (Loss) Per Common Unit

Net Income (Loss) Per Common Unit

Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners, which is determined after the deduction of the general partner’s interest, by the weighted average number of common limited partner units outstanding during the period.

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

	Three Months Ended
	March 31,
	2018			2017
Net loss	$	(928	)	$	(292	)
Less: General partner’s interest		(19	)		(6	)
Net loss attributable to common limited partners	$	(909	)	$	(286	)

Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of common limited partner warrants, as calculated by the treasury stock method.

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

	Three Months Ended
	March 31,
	2018		2017
Weighted average number of common units – basic		23,300		23,300
Add effect of dilutive awards(1)		—		—
Weighted average number of common units – diluted		23,300		23,300

(1) For both the three months ended March 31, 2018 and 2017, 2,330,000 common limited partner warrants were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of units issuable upon the exercise of the warrants would have been anti-dilutive.

Recently Issued Accounting Standards

Recently Issued Accounting Standards

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

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Summary of Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2018

Accounting Policies [Abstract]

Summary of Commodity Derivative Activity [Table Text Block]

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

Schedule of Net Loss Reconciliation [Table Text Block]

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

	Three Months Ended
	March 31,
	2018			2017
Net loss	$	(928	)	$	(292	)
Less: General partner’s interest		(19	)		(6	)
Net loss attributable to common limited partners	$	(909	)	$	(286	)

Reconciliation of Weighted Average Number of Common Units [Table Text Block]

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

	Three Months Ended
	March 31,
	2018		2017
Weighted average number of common units – basic		23,300		23,300
Add effect of dilutive awards(1)		—		—
Weighted average number of common units – diluted		23,300		23,300

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Property, Plant and Equipment (Tables)

3 Months Ended

Mar. 31, 2018

Property Plant And Equipment [Abstract]

Summary of Property, Plant and Equipment

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

	March 31, 2018			December 31, 2017
Natural gas and oil properties:
Proved properties	$	152,581		$	147,932
Support equipment and other		3,180			3,188
		155,761			151,120
Less – accumulated depreciation, depletion and amortization		(86,798	)		(85,827	)
	$	68,963		$	65,293

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Basis of Presentation - Additional Information (Details)	3 Months Ended
	Mar. 31, 2018 shares
Common Limited Partners' Interests
Basis Of Presentation [Line Items]
Common units, issued	23,300,410
Common units, outstanding	23,300,410
Atlas Growth Partners GP, LLC
Basis Of Presentation [Line Items]
General partner ownership interest	100.00%
Percentage of cash distribution	2.00%
ATLS
Basis Of Presentation [Line Items]
General partner ownership interest	80.00%
Common limited partner ownership interest	2.10%
General partners remaining ownership interest	20.00%
ATLS | Titan Energy, LLC | Series A Preferred Share
Basis Of Presentation [Line Items]
Percentage of cash distribution	2.00%

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Summary of Significant Accounting Policies (Summary of Commodity Derivative Activity) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Accounting Policies [Abstract]
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

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Summary of Significant Accounting Policies - Additional Information (Details)	3 Months Ended
	Mar. 31, 2018 USD ($) bbl Segment $ / bbl	Jan. 01, 2018 USD ($)	Dec. 31, 2017 USD ($)
Significant Accounting Policies [Line Items]
Number of reportable segments | Segment	1
Cumulative effect adjustment	$ 70,984,000		$ 71,912,000
Accounts receivable to revenue contracts with customers	$ 500,000		$ 600,000
ASU No. 2014-09 | Cumulative Effect Adoption 606
Significant Accounting Policies [Line Items]
Cumulative effect adjustment		$ 0
Commodity Derivatives
Significant Accounting Policies [Line Items]
Commodity derivatives, Volume | bbl	74,500
Average fixed price | $ / bbl	52.51
Fair value of commodity derivatives liability	$ 600,000

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Summary of Significant Accounting Policies (Schedule of Net Loss Reconciliation) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Accounting Policies [Abstract]
Net loss	$ (928)	$ (292)
Less: General partner’s interest	(19)	(6)
Net loss attributable to common limited partners	$ (909)	$ (286)

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Summary of Significant Accounting Policies (Reconciliation of Weighted Average Number of Common Units) (Details) - shares		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Accounting Policies [Abstract]
Weighted average number of common units – basic		23,300,000	23,300,000
Add effect of dilutive awards	[1]	0	0
Weighted average number of common units – diluted		23,300,000	23,300,000
Antidilutive securities excluded from computation of diluted net income (loss) attributable to common limited partners outstanding units		2,330,000	2,330,000

[1] For both the three months ended March 31, 2018 and 2017, 2,330,000 common limited partner warrants were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of units issuable upon the exercise of the warrants would have been anti-dilutive.

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Property, Plant and Equipment (Summary of Property, Plant and Equipment) (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Property Plant And Equipment [Abstract]
Proved properties	$ 152,581	$ 147,932
Support equipment and other	3,180	3,188
Total gross property, plant and equipment	155,761	151,120
Less – accumulated depreciation, depletion and amortization	(86,798)	(85,827)
Property, plant and equipment, Net, Total	$ 68,963	$ 65,293

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Property, Plant and Equipment - Additional Information (Details) - USD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Property Plant And Equipment [Abstract]
Non-cash investing activities capital expenditures	$ 4,400,000	$ 0

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Certain Relationships and Related Party Transactions - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Related Party Transaction [Line Items]
Accounts payable	$ 588		$ 606
Relationship with General Partner
Related Party Transaction [Line Items]
Percentage of capital contribution	1.00%	1.00%
Payment for management fee	$ 600	$ 600
Relationship with ATLS
Related Party Transaction [Line Items]
Accounts payable	600		600
Affiliated Entity | ATLS
Related Party Transaction [Line Items]
Accounts receivable	$ 100
Accounts payable			$ 100

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Commitments and Contingencies - Additional Information (Details) - USD ($)	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Commitments And Contingencies Disclosure [Abstract]
Long-term purchase commitment, amount	$ 0
Accrual for environmental loss contingencies	$ 0	$ 0