Atlas Growth Partners 10Q 2017 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2017

☐	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 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 August 14, 2017 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, 2017 and December 31, 2016	4

	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2017 and 2016	5

	Condensed Consolidated Statement of Changes in Partners’ Capital for the Six Months Ended June 30, 2017	6

	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2017 and 2016	7

	Notes to Condensed Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	19

Item 4.	Controls and Procedures	19

PART II. OTHER INFORMATION

Item 6.	Exhibits	20

SIGNATURES		21

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 continued suspension of our primary offering efforts and our quarterly distribution;

•

our ability to continue as a going concern;

•

our ability to generate and use of the proceeds of our public offering;

•

our business and investment strategy;

•

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

•

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; 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, 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.

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.

ATLAS GROWTH PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

	June 30, 2017			December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	8,127		$	8,586
Accounts receivable		637			846
Current derivative assets	533				—
Total current assets	9,297				9,432
Property, plant and equipment, net	66,875				68,899
Long-term derivative assets	140				—
Other assets, net	142				169
Total assets	$	76,454		$	78,500
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	679		$	890
Advances from affiliates	793				1,355
Current portion of derivative liability	—				284
Accrued liabilities	173				241
Total current liabilities	1,645				2,770
Long-term derivative liability	—				280
Asset retirement obligations and other	649				641
Commitments and contingencies (Note 7)
Partners’ Capital:
General partner’s interest		(2,566	)		(2,553	)
Common limited partners’ interests	73,590				74,226
Common limited partners’ warrants	3,136				3,136
Total partners’ capital	74,160				74,809
Total liabilities and partners’ capital	$	76,454		$	78,500

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,
	2017			2016				2017			2016
Revenues:
Gas and oil production	$	1,874		$	3,385		$	4,270		$	6,486
Gain (loss) on mark-to-market derivatives	634				(826	)		1,391			(493	)
Total revenues	2,508				2,559			5,661			5,993
Costs and expenses:
Gas and oil production	501				718			1,453			1,532
General and administrative	296				114			493			215
General and administrative – affiliate	1,182				2,589			2,366			5,177
Depreciation, depletion and amortization	886				3,299			1,998			7,526
Total costs and expenses	2,865				6,720			6,310			14,450
Net loss	$	(357	)	$	(4,161	)	$	(649	)	$	(8,457	)
Allocation of net loss attributable to common limited partners and the general partner:
Common limited partners’ interest	$	(350	)	$	(4,077	)	$	(636	)	$	(8,286	)
General partner’s interest	(7		)		(84	)		(13	)		(171	)
Net loss attributable to common limited partners per unit:
Basic and Diluted	$	(0.02	)	$	(0.18	)	$	(0.03	)	$	(0.36	)
Weighted average common limited partner units outstanding:
Basic and Diluted	23,300				23,300			23,300			23,300

See accompanying notes to condensed consolidated financial statements.

ATLAS GROWTH PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN 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, 2016		100	$	(2,553	)		23,300,410	$	74,226			2,330,041	$	3,136	$	74,809
Net loss	—		(13		)	—		(636		)	—		—		(649		)
Balance at June 30, 2017	100		$	(2,566	)		23,300,410	$	73,590		2,330,041		$	3,136	$	74,160

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,
	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(649	)	$	(8,457	)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Depreciation, depletion and amortization	1,998				7,526
(Gain) loss on derivatives	(1,130		)		508
Amortization of deferred financing costs	27				36
Changes in operating assets and liabilities:
Accounts receivable, prepaid expenses and other	102				201
Advances to/from affiliates	(562		)		10,911
Accounts payable and accrued liabilities	(245		)		(711	)
Net cash (used in) provided by operating activities	(459		)		10,014
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	—				(6,327	)
Net cash used in investing activities	—				(6,327	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from issuance of common limited partner units and warrants	—				(2,926	)
Distributions paid to unitholders	—				(8,321	)
Net cash used in financing activities	—				(11,247	)
Net change in cash and cash equivalents	(459		)		(7,560	)
Cash and cash equivalents, beginning of year	8,586				23,321
Cash and cash equivalents, end of period	$	8,127		$	15,761

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 (“NGLs”) 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 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. 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.

Atlas Energy Group, LLC (“ATLS”), a publicly traded Delaware limited liability company (OTCQX: ATLS), manages and controls us through its 2.1% limited partner interest in us and 80.0% member interest in AGP GP. Current and former members of ATLS management own the remaining 20% member interest in AGP GP.

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. Titan is the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”).

At June 30, 2017, we had 23,300,410 common limited partner units issued and outstanding.

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and the applicable rules and regulations of the Securities Exchange Commission regarding interim financial reporting and include all adjustments that are necessary for a fair presentation of our consolidated results of operations, financial condition and cash flows for the periods shown, including normal, recurring accruals and other items. The consolidated results of operations for the interim periods presented are not necessarily indicative of results for the full year. The year-end condensed consolidated balance sheet was derived from audited financial statements but does not include all disclosures required by U.S. GAAP. For a more complete discussion of our accounting policies and certain other information, refer to our consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016.

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

Liquidity and Capital Resources

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 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 continue to remain low in 2017. 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.

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

Cash Distributions

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). On November 2, 2016, our Board of Directors determined to suspend our quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order retain our cash flow and reinvest in our business and assets.

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 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,
	2017			2016			2017			2016
Net loss	$	(357	)	$	(4,161	)	$	(649	)	$	(8,457	)
Less: General partner’s interest		7			84			13			171
Net loss attributable to common limited partners	$	(350	)	$	(4,077	)	$	(636	)	$	(8,286	)

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 June 30,				Six Months Ended June 30,
	2017		2016			2017		2016
Weighted average number of common units – basic		23,300		23,300			23,300		23,300
Add effect of dilutive awards⁽¹⁾		—		—			—		—
Weighted average number of common units – diluted		23,300		23,300			23,300		23,300

(1)

For both the three and six months ended June 30, 2017 and 2016, 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.

In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. We intend to adopt the new standard using the modified retrospective method, which is expected to have an immaterial impact to our financial statements. The accounting guidance will require that our revenue recognition policy disclosures include further detail regarding our performance obligations as to the nature, amount, timing, and estimates of revenue and cash flows generated from our contracts with customers.

NOTE 3– PROPERTY, PLANT AND EQUIPMENT

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

	June 30, 2017			December 31, 2016
Natural gas and oil properties:
Proved properties		84,619			84,631
Unproved properties		63,325			63,314
Support equipment and other		3,188			3,188
		151,132			151,133
Less – accumulated depreciation, depletion and amortization		(84,257	)		(82,234	)
	$	66,875		$	68,899

As of June 30, 2017, we did not have any non-cash investing activity capital expenditures. During the six months ended June 30, 2016, we recognized $0.1 million of non-cash investing activities capital expenditures, which were included within the changes in accounts payable and accrued liabilities on our condensed consolidated statement of cash flows.

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 assets of $0.7 million and net derivative liabilities of $0.6 million on our condensed consolidated balance sheets at June 30, 2017 and December 31, 2016, respectively.

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

	Three Months Ended June 30,					Six Months Ended June 30,
	2017		2016			2017		2016
Gain (loss) recognized on cash settlement	$	78	$	(131	)	$	261	$	15
Gain (loss) on open derivative contracts		556		(695	)		1,130		(508		)
Gain (loss) on mark-to-market derivatives	$	634	$	(826	)	$	1,391	$		(493	)

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 dates indicated (in thousands):

Offsetting Derivatives as of June 30, 2017	Gross Amounts Recognized			Gross Amounts Offset			Net Amount Presented
Current portion of derivative assets	$	548		$	(15	)	$	533
Long-term portion of derivative assets		140			—			140
Total derivative assets	$	688		$	(15	)	$	673
Current portion of derivative liabilities	$	(15)		$	15		$	—
Long-term portion of derivative liabilities		—			—			—
Total derivative liabilities	$	(15)		$	15		$	—

Offsetting Derivatives as of December 31, 2016
Current portion of derivative assets	$	97		$	(97	)	$	—
Long-term portion of derivative assets		—			—			—
Total derivative assets	$	97		$	(97	)	$	—
Current portion of derivative liabilities	$	(381	)	$	97		$	(284	)
Long-term portion of derivative liabilities		(280	)		—			(280	)
Total derivative liabilities	$	(661	)	$	97		$	(564	)

As of June 30, 2017, we had the following commodity derivatives:

Crude Oil – Fixed Price Swaps

Production Period Ending December 31,	Volumes⁽¹⁾	Average Fixed Price⁽¹⁾		Fair Value Asset
				(in thousands)⁽²⁾
2017⁽³⁾	52,800	$	53.416	$	362
2018	74,500	$	52.510		311
			Net assets	$	673

(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 2017 include the remaining six months of 2017 beginning July 1, 2017.

NOTE 5 – FAIR VALUE OF FINANCIAL INSTRUMENTS

Assets and Liabilities Measured on a Recurring Basis

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

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

	Level 1		Level 2			Level 3		Total
As of June 30, 2017
Assets, gross
Commodity swaps	$	—	$	688		$	—	$	688
Total derivative assets, gross		—		688			—		688
Liabilities, gross
Commodity swaps		—		(15	)		—		(15	)
Total derivative liabilities, gross		—		(15	)		—		(15	)
Total derivatives, fair value, net	$	—	$	673		$	—	$	673
As of December 31, 2016
Assets, gross
Commodity swaps	$	—	$	97		$	—	$	97
Total derivative assets, gross		—		97			—		97
Liabilities, gross
Commodity swaps		—		(661	)		—		(661	)
Total derivative liabilities, gross		—		(661	)		—		(661	)
Total derivatives, fair value, net	$	—	$	(564	)	$	—	$	(564	)

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.

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, including Titan. AGP GP 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 June 30, 2017 and 2016, we paid a management fee of $0.6 million and during each of the six months ended June 30, 2017 and 2016 we paid a management fee of $1.1 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 AGP GP discussed above were included in general and administrative expenses – affiliate in the condensed consolidated statements of operations. As of each of June 30, 2017 and December 31, 2016, we had payables to ATLS of $0.6 million 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 Titan/ARP. At the direction of ATLS, we reimburse Titan/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. As of June 30, 2017 and December 31, 2016, we had payables to Titan of $0.2 million and $0.8 million, respectively, related to the direct costs, indirect cost allocation, and timing of funding of cash accounts, which was recorded in advances from affiliates in the condensed consolidated balance sheets.

NOTE 7 – COMMITMENTS AND CONTINGENCIES

General Commitments

As of June 30, 2017, 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 June 30, 2017, 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 June 30, 2017 and December 31, 2016.

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 (“AGP GP”) 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 (OTCQX: ATLS), manages and controls us through its 2.1% limited partner interest in us and 80% member interest in AGP GP. Current and former members of ATLS management own the remaining 20% member interest in AGP GP.

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 and continue to remain low in 2017. 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.

For additional information, please see “—Liquidity and Capital Resources.”

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, represents over ninety percent of our operations;

•

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.

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,
	2017		2016		2017		2016
Gross wells drilled⁽¹⁾		—		—		—		—
Net wells drilled⁽¹⁾		—		—		—		—
Gross wells turned in line⁽²⁾		—		—		—		2
Net wells turned in line⁽²⁾		—		—		—		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 June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Total production volumes per day:⁽¹⁾
Natural gas (Mcfd)		297		414		325		457
Oil (Bpd)		401		853		443		996
NGLs (Bpd)		52		75		56		80
Total (Mcfed)		3,014		5,982		3,316		6,910
Total production volumes:⁽¹⁾
Natural gas (MMcf)		27		38		59		83
Oil (MBbls)		36		78		80		181
NGLs (MBbls)		5		7		10		15
Total (MMcfe)		274		544		600		1,258

⁽¹⁾

“MMcf” represents million cubic feet; “MMcfe” represent million cubic feet equivalents; “Mcfd” represents thousand cubic feet per day; “Mcfed” represents thousand cubic feet equivalents per day; and “Bbls” and “Bpd” represent barrels and barrels per day. Barrels are converted to Mcfe using the ratio of approximately 6 Mcf to one barrel.

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

	Three Months Ended June 30,					Six Months Ended June 30,
	2017		2016			2017		2016
Production revenues (in thousands):
Natural gas revenue	$	77	$	74	$	178	$	161
Oil revenue	1,723			3,220		3,908		6,154
NGLs revenue	74			91		184		171
Total revenues	$	1,874	$	3,385	$	4,270	$	6,486
Average sales price:
Natural gas (per Mcf):
Total realized price, after hedge	$	2.85	$	1.97	$	3.02	$	1.94
Total realized price, before hedge	$	2.85	$	1.97	$	3.02	$	1.94
Oil (per Bbl):
Total realized price, after hedge⁽¹⁾	$	50.84	$	41.25	$	50.70	$	35.17
Total realized price, before hedge	$	47.25	$	41.48	$	48.76	$	33.96
NGLs (per Bbl):
Total realized price, after hedge	$	15.63	$	13.39	$	18.25	$	11.77
Total realized price, before hedge	$	15.63	$	13.39	$	18.25	$	11.77
Total Production costs (per Mcfe):
Lease operating expenses	$	1.27	$	0.91	$	1.86	$	0.87
Production taxes	0.55			0.30		0.50		0.25
Transportation and compression	—			0.11		0.06		0.10
Total production costs per Mcfe	$	1.82	$	1.32	$	2.42	$	2 1.22

⁽¹⁾

Includes the impact of cash settlements on commodity derivative contracts of $0.1 million cash receipts for the three months ended June 30, 2017 and $0.2 million of cash receipts for each of the six months ended June 30, 2017 and 2016 on our commodity derivative contracts. For the three months ended June 30, 2016 there was a nominal effect to cash settlements on our commodity derivative contracts.

	Three Months Ended June 30,					Six Months Ended June 30,
(in thousands)	2017		2016			2017		2016
Gas and oil production revenues	$	1,874	$	3,385	$	4,270	$	6,486
Gas and oil production costs	$	501	$	718	$	1,453	$	1,532

Our gas and oil production revenues were lower in the current quarter due to a $1.5 million decrease attributable to production from our Eagle Ford operations, primarily related to lower volumes as a result of natural production decline in the current period.

Our gas and oil production revenues were lower in the six months ended June 30, 2017, due to a $2.2 million decrease attributable to production from our Eagle Ford operations, primarily related to two wells turned in line in the prior period resulting in lower volumes as a result of natural production decline in the current period.

Our gas and oil production costs were lower in the current quarter due to a $0.2 million decrease in maintenance, materials, and treating costs attributable to fewer wells turned in line in our Eagle Ford operations.

Our gas and oil production costs were lower in the six months ended June 30, 2017, due to a $0.1 million decrease in maintenance, materials, and treating costs attributable to fewer wells turned in line in our Eagle Ford operations.

OTHER REVENUES AND EXPENSES

	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands)	2017		2016				2017		2016

Other Revenues
Gain (loss) on mark-to-market derivatives	$	634	$	(826	)	$	1,391	$	(493	)

Other Expenses
General and administrative	$	1,478	$	2,703		$	2,859	$	5,392
Depreciation, depletion and amortization		886		3,299			1,998		7,526

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

General and Administrative Expenses. The decrease in general and administrative expenses in the current quarter and the six months ended June 30, 2017 was due to decreases of $1.2 million and $2.5 million, respectively, in salaries, wages and other corporate activity costs allocated to us by ATLS as a result of the suspension of our current primary offering efforts and management’s plan to reduce general and administrative expenses.

Depreciation, Depletion and Amortization. The decrease in depreciation, depletion and amortization in the current quarter and the six months ended June 30, 2017 was primarily due to decreases of $2.4 million and $5.5 million, respectively, in our depletion expense due to impairments of our proved oil and gas properties in our Eagle Ford operating area recorded in the fourth quarter of 2016, which were impaired due to lower forecasted commodity prices and timing of capital financing and deployment for the development of our undeveloped properties.

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 continue to remain low in 2017. 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,
		2017		2016
Net cash (used in) provided by operating activities	$	(459)	$	10,014
Net cash used in investing activities		—		(6,327	)
Net cash used in financing activities		—		(11,247	)

Six Months Ended June 30, 2017 Compared with the Six Months Ended June 30, 2016

Cash Flows from Operating Activities:

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

•

a decrease of $11.5 million net cash provided by advances from affiliates related to the direct costs, indirect cost allocation, dealer manager costs for operating activities and timing of funding of cash accounts; partially offset by

•

an increase of $0.9 million net cash provided by operating activities for cash receipts and disbursements attributable to our normal monthly operating cycle for gas and oil production 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 a decrease of $6.3 million in capital expenditures related to our drilling activities.

Cash Flows from Financing Activities:

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

•

a decrease of $8.3 million in distributions paid to unitholders due to the temporary suspension of our quarterly common unit distributions in order retain our cash flow and reinvest in our business and assets; and

•

a decrease of $2.9 million in net proceeds from issuance of common limited partner units primarily due to fees related to our primary offering efforts in 2016.

Capital Requirements

At June 30, 2017, the capital requirements of our natural gas and oil production primarily consist of expenditures to maintain or increase production margin in future periods, as well as land, gathering and processing, and other non-drilling capital expenditures. We did not have any capital expenditures during the six months ended June 30, 2017. As of June 30, 2017, we did not have any commitments for our drilling and completion and capital expenditures.

OFF BALANCE SHEET ARRANGEMENTS

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

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

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

CREDIT FACILITY

On May 1, 2015, we entered into a secured credit facility agreement with syndicate of banks. As of June 30, 2017, the lenders under the credit facility have no commitment to lend to us under the credit facility and we have a zero dollar borrowing base, 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 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, 2017. 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.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

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 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 as if the hypothetical changes in market risk factors occurred on June 30, 2017. 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 June 30, 2018 of $0.2 million.

As of June 30, 2017, 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⁾
2017⁽²⁾		52,800	$	53.416
2018		74,500	$	52.510

(1)“Bbl” represents barrels.

(2)The production volumes for 2017 include the remaining six months of 2017 beginning July 1, 2017.

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, 2017, 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		First Amended and Restated Limited Partnership Agreement of Atlas Growth Partners, L.P.⁽²⁾

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 14, 2017	By:	/s/ EDWARD E. COHEN
		Edward E. Cohen Chairman of the Board and Chief Executive Officer

Date: August 14, 2017	By:	/s/ JEFFREY M. SLOTTERBACK
		Jeffrey M. Slotterback Chief Financial Officer

Date: August 14, 2017	By:	/s/ MATTHEW J. FINKBEINER
		Matthew J. Finkbeiner Chief Accounting Officer

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	8th grade Good

Atlas Growth Partners (AGP) 10-Q2017 Q2 Quarterly report

Content analysis