Atlas Growth Partners 424B3 Prospectus supplement

Filed pursuant to Rule 424(b)(3)
Registration No. 333-207537

PROSPECTUS SUPPLEMENT NO. 3

(to Prospectus dated April 5, 2016)

ATLAS GROWTH PARTNERS, L.P.

Common Units Representing Limited Partner Interests

Minimum Offering: 100,000 Class A Common Units and Class T Common Units

Maximum Offering: 100,000,000 Class A Common Units and Class T Common Units

Warrants to Purchase Post-Listing Common Units Representing Limited Partner Interests

Distribution Reinvestment Plan: up to 21,505,376 Class A Common Units

Post-Listing Common Units Underlying the Warrants and to be Issued Upon Automatic Conversion of Class A and

Class T Common Units

This prospectus supplement is being filed to update and supplement information contained in the prospectus dated April 5, 2016 under the heading “Compensation” and with information contained in our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2016, filed with the Securities and Exchange Commission on August 8, 2016.

This prospectus supplement updates and supplements the information in the prospectus and is not complete without, and may not be delivered or utilized except in combination with, the prospectus, including any other amendments or supplements thereto. This prospectus supplement should be read in conjunction with the prospectus and if there is any inconsistency between the information in the prospectus and this prospectus supplement, you should rely on the information in this prospectus supplement.

Investing in our common units involves a high degree of risk. Before subscribing for common units you should carefully read the discussion of material risks of investing in our common units in “Suitability Standards” on page iii and in “Risk Factors” on page 28 of the prospectus.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus supplement is truthful or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus supplement is August 8, 2016

PROSPECTUS UPDATES

COMPENSATION

The following disclosure is hereby added following the “Direct costs (reimbursable to our general partner, ATLS or their affiliates” line item at the top of page 111 of the prospectus under the heading “—Compensation Related to the Organization of the Partnership and Offering of Units—Operational Stage”:


Type of Compensation	Method of Compensation	Estimated Dollar Amount
Indirect costs (reimbursable to our general partner, ATLS or their affiliates)	Our general partner shall be reimbursed by us on a monthly basis, or such other basis as our general partner may determine, for all administrative costs, so long as they are supportable as to the necessity thereof and the reasonableness of the amount charged and are supported by appropriate invoices or other documentation and, in addition, (i) all direct and indirect expenses it incurs or payments it makes on our behalf (including salary, bonus, incentive compensation, employee benefits and other amounts paid to any person, including affiliates of our general partner, to perform services for us or for our general partner in the discharge of its duties to us), (ii) compensation to, and expenses of, the directors of our general partner incurred in connection with the performance of services for us, and (iii) all other expenses allocable to us or otherwise incurred by our general partner in connection with managing and operating our business and affairs (including expenses allocated to our general partner by its affiliates). Our general partner shall determine the expenses that are allocable to us. Reimbursements pursuant to this subsection may be paid out of capital contributions and out of our revenues and shall be in addition to any reimbursement to our general partner as a result of indemnification.	Not determinable as of the date hereof; indirect general and administrative costs for the year ended December 31, 2015 totaled $12.7 million.

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2016

¨	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 or incorporation or organization)		(I.R.S. Employer Identification No.)
Park Place Corporate Center One 1000 Commerce Drive, Suite 400 Pittsburgh, Pennsylvania		15275
(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 x

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

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

Large accelerated filer	¨	Accelerated filer	¨

Non-accelerated filer	x (Do not check if smaller reporting company)	Smaller reporting company	¨

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

The number of outstanding common limited partner units of the registrant on August 4, 2016 was 23,300,410.

ATLAS GROWTH PARTNERS, L.P.

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

TABLE OF CONTENTS

		PAGE
PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)

	Condensed Consolidated Balance Sheets as of June 30, 2016 and December 31, 2015	4

	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2016 and 2015	5

	Condensed Consolidated Statement of Partners’ Capital for the Six Months Ended June 30, 2016	6

	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2016 and 2015	7

	Notes to Condensed Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	24

Item 4.	Controls and Procedures	25

PART II. OTHER INFORMATION

Item 6.	Exhibits	26

SIGNATURES		27

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,” “assume,” “believe,” “budget,” “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:

•

our use of the proceeds of our public offering, especially as it impacts our ability to fund the target distribution;

•

our business and investment strategy;

•

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

•

our ability to pay the full target distribution, or any distribution at all;

•

current credit market conditions and our ability to obtain long-term financing for our property acquisitions and drilling activities in a timely manner and on terms that are consistent with what we project when we invest in a property;

•

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

•

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;

•

the potential impact of Atlas Resource Partners, L.P.’s restructuring on us, including our ability to sell common units in our public offering; and

•

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

The forward-looking statements contained in this report reflect our beliefs, assumptions and expectations of our future performance, taking into account all information currently available to us. These beliefs, assumptions and expectations are subject to risks and uncertainties and can change as a result of many possible events or factors, not all of which are known to us. If a change occurs, our business, financial condition, liquidity and results of operations may vary materially from those expressed in our forward-looking statements. You should carefully consider these risks before you make an investment decision with respect to our common units.

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 “Risk Factors” in our prospectus for our public offering, as amended and supplemented and Part II, “Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2016. Given these risks and uncertainties, you are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this report are made only as of the date hereof. We do not undertake and specifically decline any obligation to update any such statements or to publicly announce the results of any revisions to any of these statements to reflect future events or developments.

ATLAS GROWTH PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

		June 30,			December 31,
		2016			2015
ASSETS
Current assets:
Cash and cash equivalents		$	15,761		$	23,321
Accounts receivable			2,356			2,353
Advances to affiliates			—			8,008
Current derivative assets			—			303
Prepaid expenses			7			7
Total current assets			18,124			33,992
Property, plant and equipment, net			117,398			125,286
Long-term derivative assets			—			109
Other assets, net			199			235
Total assets		$	135,721		$	159,622
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable		$	2,446		$	3,226
Advances from affiliates			2,903			—
Current portion of derivative liability			137			—
Accrued well drilling and completion costs			—			6,641
Accrued liabilities			213			199
Total current liabilities			5,699			10,066
Long-term derivative liability			163			—
Asset retirement obligations			176			169
Commitments and contingencies (Note 7)
Partners’ Capital:
General partner’s interest	��		(1,368	)		(1,031	)
Common limited partners’ interests			127,915			147,282
Common limited partners’ warrants			3,136			3,136
Total partners’ capital			129,683			149,387
Total liabilities and partners’ capital		$	135,721		$	159,622

See accompanying notes to condensed consolidated financial statements.

ATLAS GROWTH PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Revenues:
Gas and oil production	$	3,385		$	1,817		$	6,486		$	4,128
Gain (loss) on mark-to-market derivatives	(826		)		48		(493		)		48
Total revenues	2,559				1,865		5,993				4,176
Costs and expenses:
Gas and oil production	718				484		1,532				975
General and administrative	114				196		215				430
General and administrative – affiliate	2,589				2,563		5,177				6,907
Depreciation, depletion and amortization	3,299				782		7,526				2,247
Total costs and expenses	6,720				4,025		14,450				10,559
Net loss	$	(4,161	)	$	(2,160	)	$	(8,457	)	$	(6,383	)
Allocation of net loss attributable to common limited partners and the general partner:
Common limited partners’ interest	$	(4,077	)	$	(2,116	)	$	(8,286	)	$	(6,255	)
General partner’s interest	(84		)		(44	)	(171		)		(128	)
Net loss attributable to common limited partners and the general partner	$	(4,161	)	$	(2,160	)	$	(8,457	)	$	(6,383	)
Net loss attributable to common limited partners per unit:
Basic and Diluted	$	(0.18	)	$	(0.14	)	$	(0.36	)	$	(0.45	)
Weighted average common limited partner units outstanding:
Basic and Diluted	23,300				15,114		23,300				13,792

See accompanying notes to condensed consolidated financial statements.

ATLAS GROWTH PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(in thousands, except unit data)

(Unaudited)

	General Partner’s Interest					Common Limited Partners’ Interests					Common Limited Partners’ Warrants				Total Partners’ Capital
	Class A Units		Amount			Units		Amount			Warrants		Amount
Balance at December 31, 2015		100	$	(1,031	)		23,300,410	$	147,282			2,330,041	$	3,136	$	149,387
Issuance of units, net of offering costs		—		—			—	(2,926		)		—		—	(2,926		)
Distributions paid		—	(166		)		—	(8,155		)		—		—	(8,321		)
Net loss		—	(171		)		—	(8,286		)		—		—	(8,457		)
Balance at June 30, 2016	100		$	(1,368	)	23,300,410		$	127,915		2,330,041		$	3,136	$	129,683

See accompanying notes to condensed consolidated financial statements.

ATLAS GROWTH PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

		Six Months Ended June 30,
		2016		2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(8,457	)	$	(6,383	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		7,526			2,247
(Gains) loss on derivatives		508			(48	)
Amortization of deferred financing costs		36			—
Changes in operating assets and liabilities:
Accounts receivable, prepaid expenses and other		201			(537	)
Advances to/from affiliates		10,911			(6,967	)
Accounts payable and accrued liabilities		(711	)		718
Net cash provided by (used in) operating activities		10,014			(10,970	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(6,327	)		(13,118	)
Net cash paid for acquisitions		—			(44,489	)
Net cash used in investing activities		(6,327	)		(57,607	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from issuance of common limited partner units and warrants		(2,926	)		47,011
Distributions paid to unitholders		(8,321	)		(3,894	)
Deferred capital contributions		—			19,649
Deferred financing costs and other		—			(9	)
Net cash provided by (used in) financing activities		(11,247	)		62,757
Net change in cash and cash equivalents		(7,560	)		(5,820	)
Cash and cash equivalents, beginning of year		23,321			33,405
Cash and cash equivalents, end of period	$	15,761		$	27,585

See accompanying notes to condensed consolidated financial statements.

ATLAS GROWTH PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 – BASIS OF PRESENTATION

We are a Delaware limited partnership and an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”) with operations primarily focused in the Eagle Ford Shale in south Texas. Our general partner, Atlas Growth Partners GP, LLC (“AGP GP”) owns 100% of the general partner Class A units and all of the incentive distribution rights through which it manages and effectively controls us. Unless the context otherwise requires, references to “Atlas Growth Partners, L.P.,” “Atlas Growth Partners,” “the Partnership,” “we,” “us,” “our” and “our company”, refer to Atlas Growth Partners, L.P. and our consolidated subsidiaries.

At June 30, 2016, Atlas Energy Group, LLC (“ATLS” or “Atlas Energy”), a publicly traded Delaware limited liability company (OTC: ATLS) that manages and controls us through its general partner interest and through the terms of the partnership agreement, owned a 2.1% limited partner interest in us and 80.0% of AGP GP’s general partner Class A units, which are entitled to receive 2% of the cash distributed by us without any obligation to make further capital contributions (see Note 9). Current and former members of ATLS management own the remaining 20% interest in AGP GP’s general partner Class A units.

In addition to its general and limited partner interest in us, ATLS also holds general and limited partner interests in Atlas Resource Partners, L.P. (“ARP”), a publicly traded Delaware master-limited partnership (OTC: ARPJ) and an independent developer and producer of natural gas, oil and NGLs, with operations in basins across the United States, and in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, which incubate new MLPs and invest in existing MLPs.

To date, we have funded our operations through the private placement of 23,300,410 of our common limited partner units at a purchase price of $10.00 per unit which ended June 30, 2015 (the “Private Placement Offering”). The common units are a class of limited partner interests in us. The holders of common units are entitled to participate in partnership distributions, exercise the rights or privileges available to them, have limited voting rights and have limited liability, all as outlined in the partnership agreement.

Our registration statement on Form S-1 (Registration Number: 333-207537) was declared effective by the Securities and Exchange Commission on April 5, 2016. We are offering in the aggregate up to 100,000,000 Class A common units and Class T common units, each representing limited partner interests in us, pursuant to a primary offering on a "best efforts" basis. We must receive minimum offering proceeds of $1.0 million to break escrow, and the maximum offering proceeds of the primary offering may not exceed $1.0 billion. The Class A common units will be sold for a cash purchase price of $10.00 and the Class T common units will be sold for a cash purchase price of $9.60, with the remaining $0.40 constituting the Class T common unitholders' deferred payment obligation to us. We are also offering up to 21,505,376 Class A common units at $9.30 per unit pursuant to a distribution reinvestment plan.

The accompanying condensed consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2015 was derived from audited financial statements, have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission and are presented in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in our Form S-1. It is suggested that these condensed financial statements be read in conjunction with the financial statements and the notes thereto included in our Form S-1. In management’s opinion, all adjustments necessary for a fair presentation of our financial position, results of operations and cash flows for the periods disclosed have been made. The results of operations for the interim periods presented may not necessarily be indicative of the results of operations for the full year.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 operations have been identified in the condensed consolidated financial statements as transactions between affiliates, where applicable. All material 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, depreciation and amortization 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.

Liquidity and Capital Resources

We have historically funded our operations, acquisitions and cash distributions primarily through cash generated from operations and financing activities, including the Private Placement Offering completed in 2015. Our future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2016. These lower commodity prices have negatively impacted our revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on our liquidity position.

ARP Restructuring and Chapter 11 Bankruptcy Proceedings

On July 25, 2016, ARP and certain of its subsidiaries and ATLS, solely with respect to certain sections thereof, entered into a restructuring support agreement with ARP’s lenders (the “Restructuring Support Agreement”) for a prepackaged restructuring that will reduce debt on its balance sheet and position ARP for the future (the “Restructuring”). We and ARP are affiliates through the ownership by our common parent, ATLS. ARP’s Restructuring is expected to be completed before the end of the third quarter of 2016, after which ARP should emerge from Chapter 11, backed by its stakeholders, committed to investing capital to develop its exploration and production assets, as well as its tax-advantaged drilling partnership program.

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

We are not a party to the Restructuring Support Agreement, and the ARP Restructuring is not expected to materially impact us.

The ARP Restructuring is not expected to materailly impact ATLS or its ownership interest in us, including ATLS’s control of our general partner, AGP GP. The debt structure of ATLS was recently modified, and ATLS is not a party to the ARP Restructuring. ATLS remains controlled by the same ownership group and management team and thus, the ARP Restructuring is not expected to have a material impact on the ability of management to operate us or the other ATLS businesses.

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.

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 general partner’s interest in net income (loss) is calculated on a quarterly basis based upon our Class A units and incentive distributions to be distributed for the quarter (see Note 9), with a priority allocation of net income to the general partner’s incentive distributions, if any, in accordance with the Partnership Agreement, and the remaining net income (loss) allocated with respect to the general partner’s and limited partners’ ownership interests.

We present net income (loss) per unit under the two-class method, which considers whether the incentive distributions represent a participating security. The two-class method considers whether the Partnership Agreement contains any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under the Partnership Agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. Under the two-class method, our management believes the Partnership Agreement contractually limits cash distributions to available cash; therefore, undistributed earnings are not allocated to the incentive distribution rights.

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 June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Net loss	$	(4,161	)	$	(2,160	)	$	(8,457	)	$	(6,383	)
Less: General partner’s interest		84			44			171			128
Net loss attributable to common limited partners	$	(4,077	)	$	(2,116	)	$	(8,286	)	$	(6,255	)

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 June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Weighted average number of common units – basic		23,300		15,114		23,300		13,792
Add effect of dilutive awards⁽¹⁾		—		—		—		—
Weighted average number of common units – diluted		23,300		15,114		23,300		13,792

(1)

For the three months ended June 30, 2016 and 2015, approximately 2,330,000 and 1,511,000 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. For the six months ended June 30, 2016 and 2015, approximately 2,330,000 and 1,379,000 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

As stated in our Form S-1, we qualify for emerging growth company status; however, we do not elect this exemption in relation to accounting standards.

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

In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued and provide footnote disclosures, if necessary. We adopted this

accounting guidance on January 1, 2016, and provided enhanced disclosures, as applicable, within our condensed consolidated financial statements.

In May 2014, the FASB issued an accounting standards update related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. This update is effective for annual reporting periods beginning after December 15, 2017. We are currently in process of determining the impact that the update will have on our condensed consolidated financial statements and our method of adoption.

NOTE 3 – PROPERTY, PLANT AND EQUIPMENT

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

	June 30, 2016			December 31, 2015			Estimated Useful Lives in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	65,998		$	65,791
Pre-development costs		683			515
Wells and related equipment		80,647			81,469
Total proved properties		147,328			147,775
Unproved properties		—			—
Total natural gas and oil properties		147,328			147,775
Pipelines, processing and compression facilities and other		3,073			2,995		15-20
		150,401			150,770
Less – accumulated depreciation, depletion and amortization		(33,003	)		(25,484	)
	$	117,398		$	125,286

During the six months ended June 30, 2016 and 2015, we recognized $0.1 million and $0.6 million, respectively, of non-cash property, plant and equipment additions, which were included within the changes in accounts payable and accrued liabilities on our condensed consolidated statements of cash flows.

For the three months ended June 30, 2016 and 2015, we recorded $7,000 and $4,000, respectively, of accretion expense related to our asset retirement obligations within in depreciation, depletion and amortization in our condensed consolidated statements of operations. For the six months ended June 30, 2016 and 2015, we recorded $11,000 and $7,000, respectively, of accretion expense related to our asset retirement obligations within in depreciation, depletion and amortization in our condensed consolidated statements of operations.

NOTE 4 – DERIVATIVE INSTRUMENTS

We use swaps in connection with our commodity price risk management activities. We do not apply hedge accounting to any of our derivative instruments. As a result, gains and losses associated with derivative instruments are recognized as gains on mark-to-market derivatives on our condensed consolidated statements of operations.

We enter into commodity future option contracts to achieve more predictable cash flows by hedging our exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. Natural gas liquids fixed price swaps are priced based on a WTI crude oil index, while other natural gas liquids contracts are based on an OPIS Mt. Belvieu index.

We recorded net derivative liabilities of $0.3 million and net derivative assets of $0.4 million on our condensed consolidated balance sheets at June 30, 2016 and December 31, 2015, respectively.

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

	Three Months Ended June 30,					Six Months Ended June 30,
	2016			2015		2016			2015
Gains (losses) recognized on cash settlement	$	(131	)	$	—	$	15		$	—
Changes in fair value on open derivative contracts		(695	)		48		(508	)		48
Gain (loss) on mark-to-market derivatives	$	(826	)	$	48	$	(493	)	$	48

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

Offsetting Derivatives as of June 30, 2016	Gross Amounts Recognized			Gross Amounts Offset			Net Amount Presented
Current portion of derivative assets	$	183		$	(183	)	$	—
Long-term portion of derivative assets		55			(55	)		—
Total derivative assets	$	238		$	(238	)	$	—
Current portion of derivative liabilities	$	(320	)	$	183		$	(137	)
Long-term portion of derivative liabilities		(218	)		55			(163	)
Total derivative liabilities	$	(538	)	$	238		$	(300	)

Offsetting Derivatives as of December 31, 2015
Current portion of derivative assets	$	399		$	(96	)	$	303
Long-term portion of derivative assets		162			(53	)		109
Total derivative assets	$	561		$	(149	)	$	412
Current portion of derivative liabilities	$	(96	)	$	96		$	—
Long-term portion of derivative liabilities		(53	)		53			—
Total derivative liabilities	$	(149	)	$	149		$	—

As of June 30, 2016, we had the following commodity derivatives:

Crude Oil – Fixed Price Swaps

Production Period Ending December 31,	Volumes⁽¹⁾		Average Fixed Price⁽¹⁾		Fair Value Liability
					(in thousands)⁽²⁾
2016⁽³⁾	31,600	$	46.350	$	(95	)
2017	37,100	$	49.968		(79	)
2018	26,500	$	48.850		(126	)
			Net liabilities	$	(300	)

(1)

Volumes for crude oil are stated in barrels.

(2)

Fair value of crude oil fixed price swaps are based on forward WTI crude oil prices, as applicable.

(3)

The production volumes for 2016 include the remaining six months of 2016 beginning July 1, 2016.

On May 1, 2015, we entered into a secured credit facility agreement with a syndicate of banks. As of June 30, 2016, the lenders under the credit facility have no commitment to lend to us under the credit facility, but we and our subsidiaries have the ability to enter into derivative contracts to manage our exposure to commodity price movements which will benefit from the collateral securing the credit facility. Obligations under the credit facility are secured by mortgages on our oil and gas properties and first priority security interest in substantially all of our assets. The credit facility may be amended in the future if we and the lenders agree to increase the borrowing base and the lenders’ commitments thereunder. The secured credit facility agreement contains covenants that limit our and our subsidiaries’ ability to incur indebtedness, grant liens, make loans or investments, make distributions, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions, including a sale of all

or substantially all of our assets. We were in compliance with these covenants as of June 30, 2016. In addition, our credit facility includes customary events of default, including failure to timely pay, breach of covenants, bankruptcy, cross-default with other material indebtedness (including obligations under swap agreements in excess of any agreed upon threshold amount), and change of control provisions.

NOTE 5 – FAIR VALUE OF FINANCIAL INSTRUMENTS

We use a market approach fair value methodology to value our outstanding derivative contracts. The fair value of a financial instrument depends on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. We separate the fair value of our financial instruments into the three level hierarchy (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. As of June 30, 2016 and December 31, 2015, all of our derivative financial instruments were classified as Level 2.

Information for financial instruments measured at fair value at June 30, 2016 and December 31, 2015 was as follows (in thousands):

	Level 1		Level 2			Level 3		Total
As of June 30, 2016
Assets, gross
Commodity swaps	$	—	$	238		$	—	$	238
Total derivative assets, gross		—		238			—		238
Liabilities, gross
Commodity swaps		—		(538	)		—		(538	)
Total derivative liabilities, gross		—		(538	)		—		(538	)
Total derivatives, fair value, net	$	—	$	(300	)	$	—	$	(300	)
As of December 31, 2015
Assets, gross
Commodity swaps	$	—	$	561		$	—	$	561
Total derivative assets, gross		—		561			—		561
Liabilities, gross
Commodity swaps		—		(149	)		—		(149	)
Total derivative liabilities, gross		—		(149	)		—		(149	)
Total derivatives, fair value, net	$	—	$	412		$	—	$	412

Other Financial Instruments

Our other current assets and liabilities on our condensed consolidated balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1.

The fair value of the warrants associated with the issuance of common limited partner units in 2015 (see Note 8) was measured using a Black-Scholes pricing model which is based on Level 3 inputs including an exercise price of $10.00, discount rate of 0.5%, an expected term of 1.5 years, expected dividend yield of 7.0% and estimated volatility rate of 50%. The volatility rate used was consistent with that of ARP. The estimated fair value per warrant was $1.47, which includes a $0.37 liquidity adjustment. There were no warrants issued for the three and six months ended June 30, 2016.

NOTE 6 – 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. AGP GP receives an annual management fee in connection with its management of us equivalent to 1% of capital contributions per annum. During the three months ended June 30, 2016 and 2015, we paid approximately $0.6 million and $0.3 million, respectively, related to this management fee. During the six months ended June 30, 2016 and 2015, we paid approximately $1.1 million and $0.6 million, respectively, related to this management fee. We were required to pay AGP GP an amount equal to any actual, out-of-pocket expenses related to the Private Placement Offering and the formation and financing of us, including legal costs incurred by AGP GP, which payments were approximately 2% of the gross proceeds of the Private Placement Offering. Other indirect costs, such as rent for offices, are

allocated by ARP 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 AGP GP discussed above were included in general and administrative expenses – affiliate in the condensed consolidated statements of operations. As of June 30, 2016 and December 31, 2015, we had payables to ATLS of $0.5 million and $0.7 million, respectively, related to the management fee, direct costs and allocated indirect costs, which was recorded in advances from affiliates in the condensed consolidated balance sheets.

Relationship with ARP. At the direction of ATLS, we reimburse ARP 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. In addition, Anthem Securities, Inc. (“Anthem”), our affiliate and a wholly owned subsidiary of ARP, acted as dealer manager for our Private Placement Offering, which was completed in June 2015. As the dealer manager, Anthem received compensation from us equal to a maximum of 12% of the gross proceeds of the Private Placement Offering as selling commissions, marketing efforts, and other issuance costs. We recorded $10.1 million and $12.3 million of costs to Anthem within common limited partners’ interests on our condensed consolidated statements of partners’ capital for the three and six months ended June 30, 2015, respectively. As the Private Placement Offering concluded on June 30, 2015, no costs were included on our condensed consolidation statement of partners’ capital for the three and six months ended June 30, 2016, respectively. Anthem is currently acting as the dealer manager for our issuance and sale in a continuous offering of up to a maximum agreement amount of 100,000,000 common units representing limited partner interests in us as further described in our registration statement on Form S-1. We will pay Anthem (1) compensation equal to 3.00% of the gross proceeds of the offering (Anthem may reallow up to 1.50% of gross offering proceeds it receives as dealer manager fees to participating broker-dealers, but expects to reallow 1.25% of gross offering proceeds to participating broker-dealers); (2) 7.00% and 3.00% of aggregate gross proceeds from the sale of Class A common units and Class T common units, respectively, as sales commissions; (3) with respect to Class T common units, a distribution and unitholder servicing fee in the aggregate amount of 4.00% of the gross proceeds from the sale of Class T common units, which distribution and unitholder servicing fee will be withheld from cash distributions otherwise payable to the purchasers of Class T common units at a rate of $0.025 per quarter per unit. As of June 30, 2016 and December 31, 2015, we had a $2.4 million payable and $8.7 million receivable, respectively, to/from ARP related to the direct costs, indirect cost allocation, dealer manager costs and timing of funding of cash accounts, which was recorded in advances to/from affiliates in the condensed consolidated balance sheets.

NOTE 7 – COMMITMENTS AND CONTINGENCIES

General Commitments

As of June 30, 2016, certain of our executives are parties to employment agreements with ATLS that provide compensation and certain other benefits. The agreements provide for severance payments under certain circumstances.

As of June 30, 2016, 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.

NOTE 8 – ISSUANCES OF UNITS

Under the terms of our initial offering, we offered in a private placement $500.0 million of our common limited partner units. The termination date of the Private Placement Offering was December 31, 2014, subject to two 90 day extensions to the extent that we had not sold $500.0 million of common units at any extension date. We exercised each of such extensions. Under the terms of the offering, an investor received, for no additional consideration, warrants to purchase additional common units in an amount equal to 10% of the common units purchased by such investor. The warrants are exercisable at a price of $10.00 per common unit being purchased and may be exercised from and after the warrant date (generally, the date upon which we give the holder notice of a liquidity event) until the expiration date (generally, the date that is one day prior to the liquidity event or, if the liquidity event is a listing on a national securities exchange, 30 days after the liquidity event occurs). Under the warrant, a liquidity event is defined as either (i) a listing of the common units on a national securities exchange, (ii) a business combination with or into an existing publicly-traded entity, or (iii) a sale of all or substantially all of our assets.

Through the completion of our Private Placement Offering on June 30, 2015, we issued approximately $233.0 million, or 23,300,410 of our common limited partner units, in exchange for proceeds to us, net of dealer manager fees and commissions and expenses, of $203.4 million. ATLS purchased 500,010 common units for $5.0 million during the offering. In connection with the issuance of common limited partner units, unitholders received 2,330,041 warrants to purchase our common units at an exercise price of $10.00 per unit.

During the six months ended June 30, 2015, we sold an aggregate of 5,956,400 common limited partner units at a gross offering price of $10.00 per unit. In connection with the issuance of common limited partner units, unitholders received 595,640 warrants to purchase our common limited partner units at an exercise price of $10.00 per unit.

NOTE 9 – CASH DISTRIBUTIONS

We have a cash distribution policy under which we distribute to holders of common units and Class A units on a quarterly basis a target distribution of $0.175 per unit, or $0.70 per unit per year, to the extent we have sufficient available cash after establishing appropriate reserves and paying fees and expenses, including reimbursements of expenses to the general partner and its affiliates. Distributions are generally paid within 45 days of the end of the quarter to unitholders of record on the applicable record date. Unitholders are entitled to receive distributions from us beginning with the quarter following the quarter in which we first admit them as limited partners.

During the six months ended June 30, 2016, we paid a distribution of $8.2 million to common limited partners ($0.1750 per unit per quarter) and $0.2 million to the general partner’s Class A units ($0.1750 per unit per quarter). During the six months ended June 30, 2015, we paid a distribution of $3.8 million to common limited partners ($0.1750 per unit per quarter) and $0.1 million to the general partner’s Class A units ($0.1750 per unit per quarter).

NOTE 10 – SUBSEQUENT EVENTS

Cash Distributions. On August 3, 2016, we declared a quarterly distribution of $0.1750 per common unit for the quarter ended June 30, 2016. The $4.2 million distribution, including $0.1 million to our general partner, will be paid on August 12, 2016 to unitholders of record at the close of business on June 30, 2016.

ITEM 2:

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

BUSINESS OVERVIEW

At June 30, 2016, Atlas Energy Group, LLC (“ATLS” or “Atlas Energy”), a publicly traded Delaware limited liability company (OTC: ATLS) that manages and controls us through its general partner interest and through the terms of the partnership agreement, owned a 2.1% limited partner interest in us and 80% of AGP GP’s general partner Class A units, which are entitled to receive 2% of the cash distributed without any obligation to make further capital contributions. Current and former members of ATLS management own the remaining 20% interest in AGP GP’s general partner Class A units.

FINANCIAL PRESENTATION

Our consolidated balance sheets at June 30, 2016 and December 31, 2015, and the consolidated statements of operations for the three and six months ended June 30, 2016 and 2015 include our accounts and our wholly-owned subsidiaries. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the consolidated balance sheets and related consolidated statements of operations. Actual balances and results could be different from those estimates. All significant intercompany transactions and balances have been eliminated in the consolidation of the financial statements.

RECENT DEVELOPMENTS

ARP Restructuring and Chapter 11 Bankruptcy Proceedings

We are not a party to the Restructuring Support Agreement, and the ARP Restructuring is not expected to materially impact us.

The ARP Restructuring is not expected to materially impact ATLS or its ownership interest in us, including ATLS’s control of our general partner, AGP GP. The debt structure of ATLS was recently modified, and ATLS is not a party to the ARP Restructuring. ATLS remains controlled by the same ownership group and management team and thus, the ARP Restructuring is not expected to have a material impact on the ability of management to operate us or the other ATLS businesses.

Effective Registration Statement. Our registration statement on Form S-1 (Registration Number: 333-207537) was declared effective by the Securities and Exchange Commission on April 5, 2016. We are offering in the aggregate up to 100,000,000 Class A common units and Class T common units, each representing limited partner interests in us, pursuant to a primary offering on a "best efforts" basis. We must receive minimum offering proceeds of $1.0 million to break escrow, and the maximum offering proceeds of the primary offering may not exceed $1.0 billion. The Class A common units will be sold for a cash purchase price of $10.00 and the Class T common units will be sold for a cash purchase price of $9.60, with the remaining

$0.40 constituting the Class T common unitholders' deferred payment obligation to us. We are also offering up to 21,505,376 Class A common units at $9.30 per unit pursuant to a distribution reinvestment plan.

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 about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

The natural gas, oil and natural gas liquids commodity price markets have suffered significant declines since the fourth quarter of 2014 through the second quarter of 2016. The causes of these declines are based on a number of factors, including, but not limited to, a significant increase in natural gas, oil and NGL production. While we anticipate continued 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.

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, including ATLS, 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.

RESULTS OF OPERATIONS

Gas and Oil Production

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

the Eagle Ford Shale in southern Texas, an oil-rich area, in which we acquired acreage in November 2014;

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

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

There were no gross or net dry wells drilled during the periods presented below. The following table presents the number of wells we drilled and the number of wells we turned in line, both gross and net during the periods indicated:

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Gross wells drilled⁽¹⁾:
Eagle Ford		—		—		—		—
Marble Falls		—		—		—		—
Mississippi Lime		—		—		—		—
Total		—		—		—		—
Net wells drilled⁽¹⁾:
Eagle Ford		—		—		—		—
Marble Falls		—		—		—		—
Mississippi Lime		—		—		—		—
Total		—		—		—		—
Gross wells turned in line⁽²⁾:
Eagle Ford		—		2		2		2
Marble Falls		—		—		—		—
Mississippi Lime		—		—		—		—
Total		—		2		2		2
Net wells turned in line⁽²⁾:
Eagle Ford		—		2		2		2
Marble Falls		—		—		—		—
Mississippi Lime		—		—		—		—
Total		—		2		2		2

⁽¹⁾	There were no exploratory wells drilled during the three and six months ended June 30, 2016 and 2015.

⁽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 three and six months ended June 30, 2016 and 2015:

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Production volumes per day:⁽¹⁾
Eagle Ford:
Natural gas (Mcfd)		282		31		278		59
Oil (Bpd)		847		271		983		352
NGLs (Bpd)		59		6		58		13
Total (Mcfed)		5,715		1,694		6,523		2,250
Marble Falls:
Natural gas (Mcfd)		110		404		156		489
Oil (Bpd)		4		44		10		46
NGLs (Bpd)		14		52		20		63
Total (Mcfed)		219		979		340		1,146
Mississippi Lime:
Natural gas (Mcfd)		22		46		23		56
Oil (Bpd)		3		5		3		7
NGLs (Bpd)		2		3		2		4
Total (Mcfed)		47		100		48		121
Total production volumes per day:⁽¹⁾
Natural gas (Mcfd)		414		481		457		604
Oil (Bpd)		853		320		996		405
NGLs (Bpd)		75		62		80		81
Total (Mcfed)		5,982		2,773		6,910		3,516
Total production volumes:⁽¹⁾
Natural gas (MMcf)		38		44		83		109
Oil (000’s Bbls)		78		29		181		73
NGLs (000’s Bbls)		7		6		15		14
Total (MMcfe)		544		252		1,258		636

⁽¹⁾	Oil and NGLs are converted to gas equivalent basis at the rate of one barrel of oil or NGLs to six Mcf of natural gas. This ratio is an estimate of the equivalent energy content of the products and does not necessarily reflect their relative economic value.

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 and average sales prices for our natural gas, oil, and natural gas liquids production for the three and six months ended June 30, 2016 and 2015 along with our average production costs, which include lease operating expenses, taxes, and transportation and compression costs, in each of the reported periods:

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Production revenues (in thousands):⁽¹⁾
Natural gas revenue	$	74	$	114	$	161	$	291
Oil revenue		3,220		1,631		6,154		3,646
NGLs revenue		91		72		171		191
Total revenues	$	3,385	$	1,817	$	6,486	$	4,128
Average sales price:
Natural gas (per Mcf):⁽²⁾
Total realized price, after hedge	$	1.97	$	2.61	$	1.94	$	2.66
Total realized price, before hedge	$	1.97	$	2.61	$	1.94	$	2.66
Oil (per Bbl):⁽²⁾
Total realized price, after hedge⁽³⁾	$	41.25	$	56.01	$	35.17	$	49.79
Total realized price, before hedge	$	41.48	$	55.84	$	33.96	$	49.72
NGLs (per Bbl):⁽²⁾
Total realized price, after hedge	$	13.39	$	12.76	$	11.77	$	13.06
Total realized price, before hedge	$	13.39	$	12.76	$	11.77	$	13.06
Production costs (per Mcfe):⁽²⁾
Eagle Ford:
Lease operating expenses	$	0.84	$	0.64	$	0.78	$	0.54
Production taxes		0.29		0.41		0.24		0.36
Transportation and compression		0.11		0.12		0.10		0.06
	$	1.24	$	1.17	$	1.12	$	0.95
Marble Falls:
Lease operating expenses	$	1.70	$	2.93	$	2.12	$	2.31
Production taxes		0.50		0.29		0.37		0.29
Transportation and compression		—		—		—		—
	$	2.21	$	3.22	$	2.49	$	2.60
Mississippi Lime:
Lease operating expenses	$	6.09	$	1.43	$	5.17	$	1.60
Production taxes		—		0.11		—		0.09
Transportation and compression		0.23		0.33		0.34		0.46
	$	6.32	$	1.88	$	5.52	$	2.15
Total production costs:
Lease operating expenses	$	0.91	$	1.47	$	0.87	$	1.15
Production taxes		0.30		0.36		0.25		0.33
Transportation and compression		0.11		0.09		0.10		0.05
	$	1.32	$	1.92	$	1.22	$	1.53

⁽¹⁾

Production revenues exclude the impact of our commodity derivative cash settlements because we do not apply hedge accounting (see “Item 1. Financial Statements – Note 4”). Production revenue excludes the impact of $0.2 million and approximately $5,000 of cash settlements for the three months ended June 30, 2016 and 2015, respectively, on our oil derivative contracts, and $0.2 million and approximately $5,000 of cash settlements for the six months ended June 30, 2016 and 2015, respectively, on our oil derivative contracts.

⁽²⁾	“Mcf” represents thousand cubic feet; “Mcfe” represents thousand cubic feet equivalents; and “Bbl” represents barrels.

⁽³⁾

Includes the impact of $0.2 million and $0.2 million of cash settlements for the three and six months ended June 30, 2016 on our oil derivative contracts, respectively. Includes the impact of approximately $5,000 of cash settlements for the three and six months ended June 30, 2015 on our oil derivative contracts.

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in thousands)				(in thousands)
Gas and oil production revenues	$	3,385	$	1,817	$	6,486	$	4,128
Gas and oil production costs	$	718	$	484	$	1,532	$	975
Total production costs per Mcfe	$	1.32	$	1.92	$	1.22	$	1.53

The increase in gas and oil production revenues for the three months ended June 30, 2016 as compared to the prior year period consisted of a $1.9 million increase attributable to production from our Eagle Ford operations, partially offset by a $0.3 million decrease attributable to our Marble Falls operations. The increase in gas and oil production revenues for the six months ended June 30, 2016 as compared to the prior year period consisted of a $3.3 million increase attributable to production from our Eagle Ford operations, partially offset by a $0.7 million decrease attributable to our Marble Falls operations and a $0.1 million decrease attributable to our Mississippi Lime operations.

The increase in gas and oil production expenses for the three months ended June 30, 2016 as compared to the prior year period primarily consisted of a $0.5 million increase attributable to our Eagle Ford operations, partially offset by a decrease of $0.2 million attributable to our Marble Falls operations. Total production costs per Mcfe decreased for the three months ended June 30, 2016 as compared to the prior year period primarily as a result of the decrease in our gas and oil production in Marble Falls and the addition of production in the Eagle Ford Shale, which has lower production costs per Mcfe.

The increase in gas and oil production expenses for the six months ended June 30, 2016 as compared to the prior year period primarily consisted of a $0.9 million increase attributable to our Eagle Ford operations, partially offset by a decrease of $0.4 million attributable to our Marble Falls operations. Total production costs per Mcfe decreased for the six months ended June 30, 2016 as compared to the prior year period primarily as a result of the decrease in our gas and oil production in Marble Falls and the addition of production in the Eagle Ford Shale, which has lower production costs per Mcfe.

OTHER REVENUES AND EXPENSES

	Three Months Ended June 30,					Six Months Ended June 30,
	2016			2015		2016			2015
		(in thousands)					(in thousands)
Other Revenues
Gain (loss) on mark-to-market derivatives	$	(826	)	$	48	$	(493	)	$	48

Other Expenses
General and administrative	$	2,703		$	2,759	$	5,392		$	7,337
Depreciation, depletion and amortization		3,299			782		7,526			2,247

Gain (Loss) on Mark-to-Market Derivatives. We recognize changes in fair value of derivatives immediately within gain (loss) on mark-to-market derivatives on our condensed consolidated statements of operations. The recognized losses during the three and six months ended June 30, 2016 are related to the change in oil prices during the three and six months ended June 30, 2016 as compared to the prior year period.

General and Administrative Expenses. The decrease for the three months ended June 30, 2016 as compared to the prior year period was due to a $0.1 million decrease in other corporate activities. The decrease for the six months ended June 30, 2016 as compared to the prior year period was due to a $1.8 million decrease in salaries, wages and other corporate activity costs allocated to us by ATLS and ARP in connection with the completion of our private placement offering in June 2015.

Depreciation, Depletion and Amortization. The increase in depreciation, depletion and amortization for the three and six months ended June 30, 2016 was primarily due to a $2.5 million and a $5.2 million increase in our depletion expense as compared to the prior year period, respectively. The following table presents our depletion expense per Mcfe for our operations for the respective periods (in thousands, except per Mcfe data):

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Depletion expense:
Total	$	3,259		$	782		$	7,449		$	2,247
Depletion expense as a percentage of gas and oil production revenue		96	%		43	%		115	%		54	%

Depletion per Mcfe	$	5.99		$	3.10		$	5.92		$	3.53

The increases in depletion expense, depletion expenses as a percentage of gas and oil revenues and depletion expenses per Mcfe, were primarily due to an increase in our depletion expense associated with the expansion of our Eagle Ford operations, partially offset by a decrease in oil volumes from our Marble Falls operations.

LIQUIDITY AND CAPITAL RESOURCES

General

We have historically funded our operations, acquisitions and cash distributions primarily through cash generated from operations and financing activities, including our private placement offering completed in June 2015. Our future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2016. These lower commodity prices have negatively impacted our revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on our liquidity position.

Cash Flows— Six Months Ended June 30, 2016 Compared with the Six Months Ended June 30, 2015

	Six Months Ended June 30,
	2016			2015
Net cash provided by (used in) operating activities	$	10,014		$	(10,970	)
Net cash used in investing activities		(6,327	)		(57,607	)
Net cash (used in) provided by financing activities		(11,247	)		62,757

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

an increase in our advances from affiliates of $17.9 million related to the direct costs, indirect cost allocation, dealer manager costs for operating activities and timing of funding of cash accounts;

an increase in our gas and oil production revenues of $2.4 million primarily related to the expansion of our Eagle Ford operations; and

a decrease in our general and administrative expenses of $2.0 million related to a reduction in salaries, wages and other corporate activities due to the completion of the Private Placement Offering in June 2015.

The change in cash flows used in investing activities when compared with the comparable prior year period was primarily due to:

a decrease of $44.5 million in net cash paid for acquisitions related to the funding of our Eagle Ford asset acquisition in the first half of 2016; and

a decrease of $6.8 million in capital expenditures due to lower capital expenditures related to our drilling activities.

The change in cash flows (used in) provided by financing activities when compared with the comparable prior year period was primarily due to:

a decrease of $49.9 million in net proceeds from issuance of common limited partner units and $19.9 million in deferred capital contributions due to our Private Placement Offering funds raised in the first half of 2015; and

an increase of $4.4 million in distributions paid to unitholders due to an increase in the number of common units outstanding after the completion of our Private Placement Offering.

Capital Requirements

At June 30, 2016, our capital expenditures primarily relate to our well drilling and leasehold acquisition costs. The following table summarizes our total capital expenditures, excluding amounts paid for acquisitions, for the periods presented (in thousands):

Three Months Ended

June 30,

Six Months Ended

June 30,

2016

2015

2016

2015

Total capital expenditures

778

3,175

6,327

13,118

During the three months ended June 30, 2016, our total capital expenditures consisted primarily of $0.6 million for wells drilled compared with $3.0 million for the comparable prior year period and approximately $3,000 of leasehold acquisition costs compared with $0.2 million for the prior year comparable period.

During the six months ended June 30, 2016, our total capital expenditures consisted primarily of $6.0 million for wells drilled compared with $12.3 million for the comparable prior year period and $0.1 million of leasehold acquisition costs compared with $0.8 million for the prior year comparable period.

As of June 30, 2016, we did not have any commitments for our drilling and completion and capital expenditures, excluding acquisitions.

OFF BALANCE SHEET ARRANGEMENTS

As of June 30, 2016, we did not have any off-balance sheet commitment arrangements for our drilling and completion and capital expenditures, excluding acquisitions

CREDIT FACILITY

On May 1, 2015, we entered into a secured credit facility agreement with Wells Fargo. As of June 30, 2016, the lenders under the credit facility have no commitment to lend to us and we have a zero-dollar borrowing base under the credit facility, but we and our subsidiaries have the ability to enter into derivative contracts to manage our exposure to commodity price movements that will benefit from the collateral securing the credit facility. Obligations under the credit facility are secured by mortgages on our oil and gas properties and first priority security interest in substantially all of our assets. The credit facility may be amended in the future if we request a borrowing base redetermination and the lenders agree to establish the borrowing base and related commitments thereunder. We may request a borrowing base redetermination under our secured credit facility. We are in discussions with our lenders to set a borrowing base for our credit facility. If the borrowing base is redetermined to an amount greater than zero dollars, the credit facility would allow us to borrow in an amount up to the borrowing base, which is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semiannually by our lenders in their sole discretion. Once established, our borrowing base will be subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated oil and natural gas reserves, which takes into account the prevailing oil and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts. A future decline in commodity prices could result in a redetermination that lowers our borrowing base at that time and, in such case, we could be required to repay any indebtedness outstanding at that time in excess of the borrowing base. If we borrow under the credit facility and we are unable to repay any borrowings in excess of a decreased borrowing base, we would be in default and no longer able to make any distributions to our unitholders.

In addition, our credit facility includes customary events of default, including failure to timely pay, breach of covenants, bankruptcy, cross-default with other material indebtedness (including obligations under swap agreements in excess of any agreed upon threshold amount), and change of control.

ISSUANCE OF UNITS

On April 5, 2016, we announced that the registration statement on Form S-1 (Registration Number: 333-207537) was declared effective by the Securities and Exchange Commission.

Under the terms of our initial offering, we offered in a private placement $500.0 million of our common limited partner units. The termination date of the private placement offering was December 31, 2014, subject to two 90 day extensions to the extent that we had not sold $500.0 million of common units at any extension date. We exercised each of such extensions. Under the terms of the offering, an investor received, for no additional consideration, warrants to purchase additional common units in an amount equal to 10% of the common units purchased by such investor. The warrants are exercisable at a price of $10.00 per common unit being purchased and may be exercised from and after the warrant date (generally, the date upon which we give the holder notice of a liquidity event) until the expiration date (generally, the date that is one day prior to the liquidity event or, if the liquidity event is a listing on a national securities exchange, 30 days after the liquidity event occurs). Under the warrant, a liquidity event is defined as either (i) a listing of the common units on a national securities exchange, (ii) a business combination with or into an existing publicly-traded entity, or (iii) a sale of all or substantially all of our assets.

Through the completion of our private placement offering on June 30, 2015, we issued approximately $233.0 million, or 23,300,410 of our common limited partner units, in exchange for proceeds to us, net of dealer manager fees and commissions and expenses, of $203.4 million. ATLS purchased 500,010 common units for $5.0 million during the offering. In connection with the issuance of common limited partner units, unitholders received 2,330,041 warrants to purchase our common units at an exercise price of $10.00 per unit.

During the six months ended June 30, 2015, we sold an aggregate of 5,956,400 of its common limited partner units at a gross offering price of $10.00 per unit. In connection with the issuance of common limited partner units, unitholders received 595,640 warrants to purchase our common limited partner units at an exercise price of $10.00 per unit.

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 Form S-1.

Recently Issued Accounting Standards

See Note 2 to our condensed consolidated financial statements for additional information related to recently issued accounting standards.

ITEM 3:

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our 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.

General

All of our assets and liabilities are denominated in U.S. dollars, and as a result, we do not have exposure to currency exchange risks.

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 June 30, 2016. Only the potential impact of hypothetical assumptions was analyzed. The analysis does not consider other possible effects that could impact our business.

Current market conditions elevate our concern over counterparty risks and may adversely affect the ability of these counterparties to fulfill their obligations to us, if any. The counterparties related to our commodity derivative contracts are

banking institutions or their affiliates, who also participate in ARP’s revolving credit facilities. The creditworthiness of our counterparties is monitored, and we currently believe them to be financially viable. We are not aware of any inability on the part of our counterparties to perform under their contracts and believe our exposure to non-performance is remote.

Commodity Price Risk. Our market risk exposures to commodities are due to the fluctuations in the commodity prices and the impact those price movements have on our financial results. To limit the exposure to changing commodity prices, we use financial derivative instruments, including financial swap and option instruments, to hedge portions of future production. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under these swap agreements, we receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. Option instruments are contractual agreements that grant the right, but not the obligation, to purchase or sell commodities at a fixed price for the relevant period.

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 June 30, 2017 of approximately $1.8 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 June 30, 2016, we had the following commodity derivatives:

Crude Oil – Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price
	(Bbl)⁽¹⁾		(per Bbl)⁽¹⁾
2016⁽²⁾		31,600	$	46.350
2017		37,100	$	49.968
2018		26,500	$	48.850

(1)“Bbl” represents barrels.

(2)The production volumes for 2016 include the remaining six months of 2016 beginning July 1, 2016.

ITEM 4:

CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of our Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of June 30, 2016, our disclosure controls and procedures were effective at the reasonable assurance level.

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

PART II

ITEM 6:

EXHIBITS

Exhibit No.		Description

3.1		Certificate of Limited Partnership of Atlas Growth Partners, L.P.⁽¹⁾

3.2		Partnership Agreement of Atlas Growth Partners, L.P., dated February 11, 2013⁽¹⁾

3.3		First Amended and Restated Limited Partnership Agreement of Atlas Growth Partners, L.P.⁽²⁾

3.4		Form of Second Amended and Restated Agreement of Limited Partnership of Atlas Growth Partners, L.P.⁽¹⁾

3.5		Certificate of Formation of Atlas Growth Partners GP, LLC⁽¹⁾

3.6		Amended and Restated Limited Liability Company Agreement of Atlas Growth Partners GP, LLC, dated as of November 26, 2013⁽¹⁾

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⁽³⁾

101.SCH		XBRL Schema Document⁽³⁾

101.CAL		XBRL Calculation Linkbase Document⁽³⁾

101.LAB		XBRL Label Linkbase Document⁽³⁾

101.PRE		XBRL Presentation Linkbase Document⁽³⁾

101.DEF		XBRL Definition Linkbase Document⁽³⁾

(1) Previously filed as an exhibit to registration statement on Form S-1 (File No. 333-207537) filed on October 21, 2015.

(2) Previously filed as an exhibit to Current Report on Form 8-K filed on April 6, 2016.

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

SIGNATURES

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


ATLAS GROWTH PARTNERS, L.P.

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


Date: August 8, 2016	By:	/s/ EDWARD E. COHEN
		Edward E. Cohen Chairman of the Board and Chief Executive Officer

Date: August 8, 2016	By:	/s/ JEFFREY M. SLOTTERBACK
		Jeffrey M. Slotterback Chief Financial Officer

Date: August 8, 2016	By:	/s/ MATTHEW J. FINKBEINER
		Matthew J. Finkbeiner Chief Accounting Officer

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 June 30, 2016 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)) 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)

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

(c)

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

August 8, 2016

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 June 30, 2016 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)) for the registrant and have:

(a)

(b)

(c)

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)

(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

August 8, 2016

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 June 30, 2016 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

August 8, 2016

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 June 30, 2016 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

August 8, 2016

Atlas Growth Partners (AGP) 424B3Prospectus supplement