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 ~~September~~March 3031, ~~2016~~2017




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

Commission file number 001-37412

PennTex Midstream Partners, LP

(Exact name of registrant as specified in its charter)



Delaware				47-1669563
(State or other jurisdiction of incorporation or organization)				(I.R.S. Employer Identification No.)

11931 Wickchester Lane, Suite 300Houston, Texas				77043
8111 Westchester Drive, Suite 600Dallas, Texas				75225
(Address of principal executive offices)				(Zip Code)
(832) 456-4000
(Registrant’s telephone number, including area code)
11931 Wickchester Lane, Suite 300Houston, Texas				77043
(Former address, if changed since last report.)				(Zip Code)

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 x No o

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the 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 o Accelerated filer o Non-accelerated filer x (Do not check if a smaller reporting company) Smaller reporting company o Emerging growth company x

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. x

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

As of ~~October~~May 241, ~~2016~~2017, the registrant had 20,~~184~~714,~~020~~256 common units and 20,000,000 subordinated units outstanding.

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PENNTEX MIDSTREAM PARTNERS, LP

TABLE OF CONTENTS

		Page
Glossary of Terms		i
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		iiiii
PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements
	Unaudited Consolidated Balance Sheet	1
	Unaudited Consolidated Statement of Operations	2
	Unaudited Consolidated Statement of Cash Flows	3
	Unaudited Consolidated Statement of Changes in Equity	4
	Notes to Unaudited Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	1812
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	2720
Item 4.	Controls and Procedures	2820
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	2921
Item 1A.	Risk Factors	2921
Item 5.	Other Information	2921
Item 6.	Exhibits	2921
SIGNATURE		3022

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GLOSSARY OF INDUSTRY AND OTHER COMMONLY-USED TERMS

AMI and Exclusivity Agreement: ~~the~~The Amended & Restated Area of Mutual Interest and Midstream Exclusivity Agreement dated as of April 14, 2015 among PennTex NLA Holdings, LLC, Range North Louisiana Operating, LLC and PennTex North Louisiana, LLC, as amended.

Bbl or barrel: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil, NGLs or other liquid hydrocarbons.

Bbl/d: Bbl per day.

Btu: British thermal units.

Cotton Valley formation: A prolific natural gas play spread across East Texas, northern Louisiana and southern Arkansas. This formation has been under development since the 1930s and is characterized by thick, multi-zone natural gas and oil reservoirs with well-known geologic characteristics and long-lived, predictable production profiles. The depth of the Cotton Valley formation is roughly 7,800 to 10,000 feet.

Energy Transfer: ETP and its affiliates other than the Partnership, including ETE and SXL.

EPA: U.S. Environmental Protection Agency.

ETC: Energy Transfer Company, the name assumed by La Grange Acquisition, L.P., a wholly owned subsidiary of ETP, for conducting business and shared services.

ETE: Energy Transfer Equity, L.P. (NYSE: ETE), a publicly traded Delaware limited partnership.

ETE GP: LE GP, LLC, the general partner of ETE.

ETP: Energy Transfer Partners, L.P. (NYSE: ETP), a publicly traded Delaware limited partnership controlled by ETE. ETP owns all of the membership interests in PennTex Development and directly and indirectly owns and controls the Partnership’s general partner.

ETP GP: Energy Transfer Partners GP, L.P., the general partner of ETP and which is indirectly owned and controlled by ETE.

ETP LLC: Energy Transfer Partners, L.L.C, the general partner of ETP GP and which is owned and controlled by ETE.

expansion capital expenditures: Cash expenditures incurred to construct or acquire new midstream infrastructure and to extend the useful lives of our assets, reduce costs, increase revenues or increase system throughput or capacity from current levels.

~~field~~FERC: ~~The~~U.S. ~~general~~Federal ~~area~~Energy ~~encompassed~~Regulatory ~~by one or more oil or gas reservoirs or pools that are located on a single geologic feature or are otherwise closely related to the same geologic feature (either structural or stratigraphic)~~Commission.

field: The general area encompassed by one or more oil or gas reservoirs or pools that are located on a single geologic feature, that are otherwise closely related to the same geologic feature (either structural or stratigraphic).

general partner: PennTex Midstream GP, LLC, the general partner of the Partnership.

hydrocarbon: An organic compound containing only carbon and hydrogen.

maintenance capital expenditures: Cash expenditures (including expenditures for the construction of new capital assets or the replacement or improvement of existing capital assets) made to maintain, over the long term, our operating capacity, throughput or revenue.

Mcf: One thousand cubic feet of natural gas.

MDth: A ~~dekatherm~~thousand dekatherms, which is a unit of energy equal to 10,000 therms or one billion Btus.

MDth/d: MDth per day.

Memorial Resource: Memorial Resource Development Corp. and its subsidiaries. Memorial Resource was a publicly traded independent exploration and production company and an affiliate of NGP prior to its acquisition by Range Resources in September 2016.

MMBtu: One million British thermal units.

MMcf: One million cubic feet of natural gas.

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MMcfe: One million cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbls of crude oil, condensate or natural gas liquids.

MMcf/d: One million cubic feet per day.

MMcfe/d: One million cubic feet equivalent per day.

natural gas: Hydrocarbon gas found in the earth, composed of methane, ethane, butane, propane and other gases.

NGLs: Natural gas liquids, which consist primarily of ethane, propane, isobutane, normal butane and natural gasoline.

NGP: Natural Gas Partners and its affiliated investment funds.

oil: Crude oil and condensate.

~~Terryville Complex~~Partnership: APennTex ~~natural~~Midstream ~~gas field located in and around Lincoln Parish~~Partners, ~~Louisiana~~LP ~~within the Cotton Valley formation. This field has been producing since 1954~~ and ~~provides~~its ~~multiple zones of highly productive, liquids-rich geology~~subsidiaries. ~~The Terryville Complex is characterized by high recoveries relative to drilling and completion costs and high initial production rates with high liquid yields.~~

PennTex Development: PennTex Midstream Partners, LLC, a wholly owned subsidiary of ETP.

PennTex Management: PennTex Midstream Management Company, LLC, a wholly owned subsidiary of PennTex Development.

Range Resources: Range Resources Corporation (NYSE: RRC), a publicly traded independent exploration and production company, and, unless the context otherwise requires, its subsidiaries. Range Resources became the Partnership’s primary customer as a result of its acquisition of Memorial Resource in September 2016.

rich natural gas: Gas having a heat content of greater than 1100 BTU.

SXL: Sunoco Logistics Partners L.P. (NYSE: SXL), a publicly traded Delaware limited partnership. SXL’s general partner is a consolidated subsidiary of, and is controlled by, ETP.

throughput: The volume of product transported or passing through a pipeline, plant, terminal or other facility.

iVernon Field: a natural gas field located in and around Jackson Parish, Louisiana within the Cotton Valley formation that offers economic stacked-pay drilling opportunities with high initial production rates.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Some of the information in this quarterly report may contain forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, ~~2015~~2016 (the “~~2015~~2016 Form 10-K”) and those set forth from time to time in our filings with the Securities and Exchange Commission (the “SEC”), which are available through our website at www.penntex.com and through the SEC’s website at www.sec.gov. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

• the status, timing and outcome of the transactions contemplated by the Contribution Agreement (as defined herein);

• events that may occur subsequent to the completion of the transactions contemplated by the Contribution Agreement, including events that directly impact our business;


•	our primary customer’s inability to successfully execute its drilling and development plan in northern Louisiana on a timely basis or at all;

• our ability to successfully implement our business strategy;

• realized natural gas, NGL and oil prices;

•competition, including from ETP, which owns our general partner and ~~government~~controls ~~regulations~~the Partnership;

•government regulations;

•actions taken by third-party producers, operators, processors and transporters;

•pending legal or environmental matters;

•costs of conducting our midstream operations;

•general economic conditions;

•credit markets;

•operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;

•uncertainty regarding our future operating results; and

•plans, objectives, expectations and intentions contained in this ~~quarterly~~ report that are not historical.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties incident to our midstream business, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility, inflation, environmental risks, drilling and completion and other operating risks, regulatory changes, the uncertainty inherent in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks referenced under “Risk Factors” in Item 1A of the ~~2015~~2016 Form 10-K.

Should one or more of the risks or uncertainties described in this quarterly 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 quarterly 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.

iii

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Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this quarterly report.

iiiv

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

PENNTEX MIDSTREAM PARTNERS, LP

UNAUDITED CONSOLIDATED BALANCE SHEET

(in thousands, except outstanding units)

	September 30, 2016			December 31, 2015
	March 31, 2017			December 31, 2016
Assets
Current assets:
Cash and cash equivalents	$	14,~~052~~490		$	78,~~760~~442
Accounts receivable	1317,~~133~~373			~~161~~15,225
Accounts receivable—related party	20			5,950
Other receivables	118			112
Other receivables	536			2,421
Materials and supplies	2,813			2,391
Materials and supplies	2,374			2,586
Prepaid and other current assets	275			371
Prepaid and other current assets	477			668
Total current assets	25,069			26,541
Total current assets	17,592			19,546
Property, plant and equipment, net	359,766			362,906
Property, plant and equipment, net	361,881			366,061
Intangible assets, net	19,767			20,064
Intangible assets, net	19,963			20,021
Total non-current assets	379,533			382,970
Total non-current assets	381,844			386,082
Total assets	$	404,602		$	409,511
Total assets	$	399,436		$	405,628
Liabilities
Current liabilities:
Accounts payable	$	~~578~~385		$	~~7,566~~224
Accounts payable—related party	~~650~~3,400			~~871~~626
Other current liabilities	43,~~369~~113			23,~~852~~198
Total current liabilities	56,~~597~~898			114,~~289~~048
Long-term debt, net	~~150~~152,~~136~~809			~~150~~163,~~699~~973
Other non-current liabilities	14,321			91
Deferred revenues	32,832			23,313
Total liabilities	170,054			162,079
Other non-current liabilities	90			90
Total liabilities	192,629			191,424
Equity
Partners’ equity:
Limited Partners:
Common units (20,184,020 and 20,000,000 units issued and outstanding as of September 30, 2016 and December 31, 2015, respectively)	220,664			226,386
Common units (20,714,256 units issued and outstanding as of March 31, 2017 and December 31, 2016)	215,712			218,821
Subordinated units (20,000,000 units issued and outstanding as of September 30, 2016 and December 31, 2015)	8,718			17,163
Subordinated units (20,000,000 units issued and outstanding as of March 31, 2017 and December 31, 2016)	(3,739		)	(734		)
General partner	—			—
Total equity	~~229~~211,~~382~~973			~~243~~218,~~549~~087
Total liabilities and equity	$	~~399~~404,~~436~~602		$	~~405~~409,~~628~~511

The accompanying notes are an integral part of these financial statements.

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PENNTEX MIDSTREAM PARTNERS, LP

UNAUDITED CONSOLIDATED STATEMENT OF OPERATIONS

(in thousands, except per unit amounts)

	Three months ended September 30,					Nine months ended September 30,
	Three months ended March 31,
	2016		2015			2016		2015
	2017		2016
Revenues	$	2217,~~184~~071	$	1117,~~225~~649		$	~~58,986~~	$	~~14,150~~
Operating expenses:
Cost of revenues	32,~~770~~688		12,~~610~~192			~~9,258~~		~~1,610~~
General and administrative expense	41,~~615~~672		3,~~625~~935			~~12,627~~		~~8,559~~
Operating and maintenance expense	21,~~857~~484		12,~~903~~619			~~7,860~~		~~3,363~~
Depreciation and amortization expense	3,~~390~~435		13,~~608~~346			~~10,117~~		~~2,665~~
Impairment of surplus assets	—		—			—		2,483
Taxes other than income taxes	281		227
Taxes other than income taxes	147		(2		)	600		135
Total operating expenses	9,560		12,319
Total operating expenses	14,779		8,744			40,462		18,815
Operating income	7,511		5,330
Operating income (loss)	7,405		2,481			18,524		(4,665		)
Interest expense, net	1,615		1,813
Interest expense, net	1,577		461			5,010		549
Net income	$	5,896	$	3,517
Net income (loss)	$	5,828	$	2,020		$	13,514	$	(5,214	)
Earnings per common unit:
Earnings per common unit: (Note 8)
Basic	$	0.14	$	0.12
Basic	$	0.16	$	0.09		$	0.41	$	0.08
Diluted	$	0.14	$	0.12
Diluted	$	0.16	$	0.09		$	0.41	$	0.08
Weighted average common and common equivalent units outstanding:
Weighted average common and common equivalent units outstanding:
Basic	20,714,256		20,000,000
Basic	20,184,020		20,000,000			20,075,644		20,000,000
Diluted	20,714,256		20,000,000
Diluted	20,184,020		20,000,000			20,075,644		20,000,000
Cash distribution declared per unit	$	0.2950	$	0.2750
Cash distribution declared per unit	$	0.2950	$	0.2750		$	0.8546	$	0.3415

The accompanying notes are an integral part of these financial statements.

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PENNTEX MIDSTREAM PARTNERS, LP

UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS

(in thousands)

	Nine months ended September 30,
	Three months ended March 31,
	2016			2015
	2017			2016
Operating activities
Net income (loss)	$	13,514		$	(5,214	)
Net income	$	5,896		$	3,517
Adjustments to reconcile net income (loss) to cash used in operating activities:
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	10,117			2,665
Depreciation and amortization expense	3,435			3,346
Accretion of debt discount	~~1,002~~336			~~541~~332
Equity-based compensation expense	~~3,935~~—			1,~~288~~151
Non-cash contribution for general and administrative expense	~~3,011~~—			1,~~908~~157
Non-cash impairment	—			2,483
Changes in deferred revenue, net	9,520			4,116
Changes in deferred revenue, net	13,818			416
Changes in operating assets and liabilities:
Accounts receivable	(122,~~972~~139		)	(~~255~~384		)
Accounts receivable - related party	~~5,930~~(9		)	(94,~~165~~401		)
Prepaid and other current assets	~~2,514~~(331		)	(2,~~514~~313		)
Accounts payable	~~(829~~161		)	(~~121~~444		)
Accounts payable - related party	852,773			~~(814~~227		)
Other liabilities	~~1,468~~(84		)	2812
Cash provided by (used in) operating activities	41,593			(8,780		)
Cash provided by operating activities	19,558			11,742
Investing activities
Property, plant and equipment expenditures	~~(11,607~~—		)	(~~202~~9,~~798~~386		)
Intangible assets expenditures	~~(503~~—		)	(~~9,526~~45		)
Cash used in investing activities	~~(12,110~~—		)	(~~212~~9,~~324~~431		)
Financing activities
Proceeds from long-term debt	~~52,000~~—			~~118~~14,~~000~~500
Payments on long-term debt	(5311,500		)	(6011,500		)
Payments for debt issuance costs	~~(65~~—		)	(~~4,662~~10		)
Proceeds from initial public offering	—			223,021
Distributions to unitholders	(12,010		)	(11,000		)
Contributions from predecessor’s members	—			103,750
Phantom units surrendered to pay taxes	—			(174		)
Distributions to predecessor’s members	—			(165,838		)
Cash used in financing activities	(23,510		)	(8,184		)
Distributions to unitholders	(34,013		)	(2,702		)
Net change in cash and cash equivalents	(3,952		)	(5,873		)
Phantom units surrendered to pay taxes	(613		)	—
Cash and cash equivalents—beginning of period	8,442			7,760
Costs of the Offering	—			(4,675		)
Cash and cash equivalents—end of period	$	4,490		$	1,887
Cash provided by (used in) financing activities	(36,191		)	206,394
Net change in cash and cash equivalents	(6,708		)	(14,710		)
Cash and cash equivalents—beginning of period	7,760			17,471
Cash and cash equivalents—end of period	$	1,052		$	2,761
Supplemental cash flows:
Interest paid, net of capitalized interest	$	41,~~543~~619		$	351,583

The accompanying notes are an integral part of these financial statements.

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PENNTEX MIDSTREAM PARTNERS, LP

UNAUDITED STATEMENT OF CHANGES IN EQUITY

(in thousands)

	Partnership
	GeneralPartner			CommonUnits			SubordinatedUnits			Total
	GeneralPartner			CommonUnits			SubordinatedUnits			PennTex NLAHoldings, LLC			MRD WHR LAMidstream LLC			Total
Balance at December 31, 2016	$	—		$	218,821		$	(734	)	$	218,087
Balance at January 1, 2015	$	—		$	—		$	—		$	95,984		$	(1,772	)	$	94,212
Distributions to unitholders	—			(6,110		)	(5,900		)	(12,010		)
Net income (loss)—January 1 to June 9, 2015 (prior to the Offering)	—			—			—			(4,177		)	(2,507		)	(6,684		)
Net income	—			3,001			2,895			5,896
Capital contributions from predecessor’s members	—			—			—			69,622			35,345			104,967
Balance at March 31, 2017	$	—		$	215,712		$	(3,739	)	$	211,973
Exchange for predecessor membership interests	—			7,689			18,968			(55,305		)	28,648			—
Proceeds from the Offering, net of costs	—			223,021			—			—			—			223,021
Costs of the Offering	—			(4,675		)	—									(4,675		)
Distributions to predecessor’s members	—			—			—			(106,124		)	(59,714		)	(165,838		)
Payments for distribution equivalents	—			(42		)	—			—			—			(42		)
Equity-based compensation expense	—			1,288			—			—			—			1,288
Non-cash contribution for general and administrative expenses	1,908			—			—			—			—			1,908
Distributions to unitholders	—			(1,330		)	(1,330		)	—			—			(2,660		)
Net income (loss) - June 9 to September 30, 2015	(1,908		)	1,689			$	1,689		—			$	—		1,470
Balance at September 30, 2015	$	—		$	227,640		$	19,327		$	—		$	—		$	246,967
Balance at December 31, 2015	$	—		$	226,386		$	17,163		$	—		$	—		$	243,549
Payments for distribution equivalents	—			(576		)	—			—			—			(576		)
Equity-based compensation expense	—			3,935			—			—			—			3,935
Phantom units surrendered to pay taxes	—			(613		)	—			—						(613		)
Non-cash contribution for general and administrative expenses	3,011			—			—			—			—			3,011
Distributions to unitholders	—			(16,746		)	(16,692		)	—			—			(33,438		)
Net income (loss)	(3,011		)	8,278			8,247			—			—			13,514
Balance at September 30, 2016	$	—		$	220,664		$	8,718		$	—		$	—		$	229,382

The accompanying notes are an integral part of these financial statements.

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PENNTEX MIDSTREAM PARTNERS, LP

NOTES TO THE UNAUDITED FINANCIAL STATEMENTS

1. Organization and Business Operations

Organization

PennTex Midstream Partners, LP (the “Partnership”) is a growth -oriented limited partnership ~~formed~~focused byon ~~PennTex Midstream Partners~~owning, ~~LLC (“PennTex Development”) to own~~operating, ~~operate~~acquiring and ~~develop~~developing midstream ~~assets.~~energy Oninfrastructure ~~June~~assets 9,in ~~2015,~~North ~~the~~America. ~~Partnership~~Our ~~completed~~sponsor, ~~its~~PennTex ~~initial~~Midstream ~~public~~Partners, ~~offering~~LLC (~~the~~ “~~Offering~~PennTex Development”) ~~of 11~~,~~250,000~~ ~~common~~was ~~units~~formed ~~representing~~by ~~limited~~members ~~partner interests at a price~~ of ~~$20.00~~its ~~per~~original ~~unit,~~management team and ~~the~~Natural ~~Partnership~~Gas ~~subsequently~~Partners ~~sold~~(“NGP”) ~~644,462~~in ~~common~~2014 ~~units pursuant~~ to ~~the~~develop ~~partial~~a ~~exercise of the underwriters’ over~~multi-~~allotment~~basin ~~option.~~midstream ~~The~~growth ~~Partnership’s~~platform ~~common~~initially ~~units~~in ~~trade~~partnership onwith ~~the~~oil ~~NASDAQ~~and ~~Global~~natural ~~Select~~gas ~~Market~~producers ~~under~~affiliated ~~the~~with ~~symbol “PTXP~~NGP.”

~~PennTex~~On ~~Development~~November ~~was~~1, ~~formed~~2016, byEnergy ~~members~~Transfer ofPartners, ~~its~~L.P. ~~management~~(“Energy ~~team~~Transfer”) acquired from NGP and ~~Natural~~certain ~~Gas~~other ~~Partners~~contributors (~~“NGP”~~i) toall ~~develop~~of ~~multi-basin~~the ~~midstream~~outstanding ~~growth~~membership ~~platforms~~interests ~~focused~~in onPennTex ~~organic~~Development, ~~growth~~(ii) ~~projects~~6,301,596 incommon ~~partnership~~units ~~with~~and ~~oil~~20,000,000 ~~and~~subordinated ~~natural~~units ~~gas~~collectively ~~producers~~representing approximately 64.6% Onof ~~March 17,~~the ~~2014,~~outstanding ~~PennTex~~limited ~~NLA~~partner ~~Holdings,~~interests ~~LLC~~in the Partnership, a(iii) all of ~~wholly-owned~~the ~~subsidiary~~outstanding ofmembership ~~PennTex~~interests ~~Development~~in ~~(“PennTex~~the ~~NLA”~~Partnership’s general partner and (iv), 100% ~~entered~~of ~~into~~the Partnership’s incentive distribution rights. As a ~~joint~~result ~~venture~~of such transaction, ~~PennTex~~ETP ~~North~~controls ~~Louisiana,~~the ~~LLC~~Partnership. ~~(“PennTex~~During ~~Operating”),~~the ~~with~~three ~~MRD~~months ~~WHR~~ended LAMarch ~~Midstream~~31, ~~LLC~~2017, Energy Transfer purchased an ~~affiliate~~additional of400,000 ~~NGP~~common ~~(“MRD~~units, ~~WHR~~on ~~LA”)~~the open market, increasing their total investment to ~~develop~~65.6% of the ~~Partnership’s~~outstanding ~~initial~~limited ~~assets.~~partner interests in the Partnership.

In ~~connection~~April ~~with~~2017, ~~the~~Energy ~~closing~~Transfer ofmerged ~~the~~with ~~Offering~~a ~~(and~~subsidiary ~~giving effect to the partial exercise~~ of ~~the~~Sunoco ~~underwriters’~~Logistics ~~over-allotment~~Partners ~~option), PennTex NLA and MRD WHR LA contributed their respective 62~~L.~~5% and 37~~P.5%, ~~membership~~at ~~interests~~which intime ~~PennTex~~Energy ~~Operating~~Transfer tochanged ~~the~~its ~~Partnership~~name infrom ~~exchange~~“Energy ~~for~~Transfer ~~cash~~Partners, ~~common units and subordinated units~~L.P.” ~~PennTex NLA subsequently distributed all of the cash, common units and subordinated units it received~~ to ~~PennTex~~“Energy ~~Development. As of September 30~~Transfer, ~~2016,~~LP” ~~PennTex Development holds 3,262,019 common units~~ and ~~12,500,000~~Sunoco ~~subordinated~~Logistics ~~units~~Partners ~~in the Partnership~~L.P. ~~Additionally,~~changed inits ~~connection~~name ~~with~~to ~~the~~“Energy ~~closing~~Transfer ~~of the Offering~~Partners, ~~the Partnership issued 92~~L.~~5% and 7~~P.5%” ofReferences ~~its~~to ~~incentive distributions rights (~~“~~IDRs~~Energy Transfer”) refer to ~~PennTex~~the ~~Development~~entity ~~and~~named ~~MRD~~Energy ~~WHR~~Transfer LAPartners, ~~respectively, and PennTex Development conveyed a 7~~L.5%P. ~~interest~~prior into the ~~Partnership’s~~close ~~general~~of ~~partner (~~the ~~“general~~merger ~~partner”)~~and ~~to MRD WHR LA. MRD WHR LA subsequently distributed~~ the ~~IDRs~~combined ~~and~~entity ~~interests~~subsequent into the ~~general partner to its members~~merger.

On October 25, 2016, the Partnership announced that PennTex Development had entered into a Contribution Agreement (the “Contribution Agreement”) with certain affiliates of NGP, certain other contributors and Energy Transfer Partners, L.P. (“Energy Transfer”). Pursuant to, and subject to the terms and conditions of, the Contribution Agreement, Energy Transfer has agreed to acquire (i) 100% of the membership interests in PennTex Development; (ii) 6,301,596 common units representing limited partner interests in the Partnership and 20,000,000 subordinated units representing limited partner interests in the Partnership; (iii) 100% of the membership interests in the general partner; and (iv) 100% of the Partnership’s incentive distribution rights.

The transactions contemplated by the Contribution Agreement are expected to close during the fourth quarter of 2016, subject to customary closing conditions. Upon the completion of the transactions contemplated by the Contribution Agreement, Energy Transfer will own the general partner of, and will control, the Partnership, and will own approximately 65% of the outstanding limited partner interests in the Partnership.

Business

The Partnership’s initial assets are located in ~~the~~northern ~~Terryville~~Louisiana ~~Complex~~and were developed in ~~northern~~two ~~Louisiana~~phases. ~~and~~The ~~consist~~first phase of adevelopment, ~~rich~~referred ~~natural~~to ~~gas~~as ~~gathering~~Phase ~~system~~I, ~~two~~was ~~cryogenic~~completed ~~natural~~in ~~gas~~May ~~processing~~2015 ~~plants~~and ~~with~~includes athe ~~combined~~Lincoln ~~design~~Parish ~~capacity~~plant, ~~of 400~~ a 200 MMcf/d design-capacity, cryogenic natural gas processing plant, and ~~residue~~related natural gas gathering and ~~NGL~~residue gas transportation pipelines. The ~~Partnership’s~~second ~~assets~~phase ~~were~~of development, referred to as Phase II, was completed in September 2015 and includes the Mt. InOlive ~~addition~~plant, toa 200 MMcf/d ~~these~~design-capacity, ~~assets~~cryogenic natural gas processing plant, an NGL transportation pipeline and additions to the residue gas pipeline. The Partnership constructed additional gathering facilities in 2016 and expects to pursue other opportunities for organic development and growth as producers in the region continue to increase production.

Range Louisiana Operating LLC (“RRC Operating”), formerly known as MRD Operating LLC, is the Partnership’s primary customer. On September 16, 2016, Range Resources Corporation (“Range Resources”) completed its previously announced acquisition of Memorial Resource Development Corp. (“Memorial Resource”), and RRC Operating became a wholly owned subsidiary of Range Resources. Prior to the completion of the acquisition, RRC Operating was a wholly owned subsidiary of Memorial Resource, an affiliate of NGP, and was a related party of the Partnership. In connection with the acquisition, MRD Operating LLC changed its name to Range Louisiana Operating LLC. As of September 16, 2016, RRC Operating ceased to be a related party.

The Partnership operates and manages the business as one reportable segment. The accompanying unaudited consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business.

2. Summary of Significant Accounting Policies

Basis of Presentation

The accompanying unaudited consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (“GAAP”) for interim financial information and with the requirements of Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, these statements include all adjustments (consisting of only normal recurring accruals, unless otherwise disclosed in this quarterly report) necessary for their fair presentation. The accompanying unaudited interim consolidated financial statements do not include all notes that would be included in the Partnership’s annual financial statements and therefore should be read in conjunction with the historical audited financial statements of PennTex Operating and the footnotes thereto included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2016 (the “2016 Form 10-K”).

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NOTES TO FINANCIAL STATEMENTS

corporate 2expenses related to executive oversight, accounting, treasury, tax, legal and procurement and information technology. ~~Summary~~These allocations are based primarily on specific identification of ~~Significant~~time ~~Accounting~~and/or ~~Policies~~activities associated with pre-construction, construction and operating activities, employee headcount or capital expenditures. Management believes the assumptions underlying the financial statements, including the assumptions regarding allocating general and administrative expenses from PennTex Development, are reasonable. General and administrative expenses allocated to the Partnership for which the Partnership will reimburse PennTex Development are reflected as a payable due to a related party.

Basis of Presentation

The statement of operations included in the accompanying unaudited consolidated financial statements also includes expense allocations for certain partnership functions performed by PennTex Development, including allocations of general corporate expenses related to executive oversight, accounting, treasury, tax, legal and procurement and information technology. These allocations are based primarily on specific identification of time and/or activities associated with pre-construction, construction and operating activities, employee headcount or capital expenditures. Management believes the assumptions underlying the financial statements, including the assumptions regarding allocating general and administrative expenses from PennTex Development, are reasonable. General and administrative expenses allocated to the Partnership for which the Partnership will reimburse PennTex Development are reflected as a payable due to a related party.

These financial statements include the results of operations for PennTex Operating prior to the closing of the Offering on June 9, 2015. As PennTex Operating was under common control with the Partnership prior to the Offering and the Partnership acquired all of the membership interests of PennTex Operating in connection with the closing of the Offering, the contributed assets and liabilities of PennTex Operating were recorded in the consolidated financial statements of the Partnership at historical cost. Prior to the contribution, the Partnership had no operations and nominal assets and liabilities.

Use of Estimates

The financial statements have been prepared in conformity with GAAP, which requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the balance sheet date, the reported amounts of expense and disclosure of contingencies. This includes estimates made in the assessment of potential impairment of long-lived assets and estimates used to calculate allocation of expenses from PennTex Development. The Partnership’s valuation methodology for assessing impairment requires management to make judgments and assumptions based on historical experience and to rely on projections of future operating performance. Although management believes these estimates are reasonable, actual results could differ from such estimates.

Revenue Recognition

The Partnership earns revenue from gathering, processing and transportation services provided to its customers. Revenue is recognized when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or service obligations have been fulfilled, (iii) the price is fixed or determinable and (iv) collectability is reasonably assured. For commercial agreements that provide for specified minimum volume commitments and variable rates, the Partnership recognizes revenue based on a weighted average rate over the term of the agreements.

Deferred Revenue

The Partnership’s processing agreement with RRC Operating requires RRC Operating to pay a fee based on the volume of gas actually processed, subject to a cumulative minimum volume commitment that is measured as of the end of each quarterly period. To the extent that RRC Operating has not delivered the applicable cumulative minimum volume commitment as of the end of a quarterly period, RRC Operating is required to pay a deficiency fee to the Partnership. The amount paid to the Partnership as a deficiency fee is characterized as unearned revenue. The Partnership invoices RRC Operating based upon the applicable rates specified in the processing agreement for the services provided and recognizes revenue based on a weighted average rate over the term of the agreement. The excess of the fees invoiced under the processing agreement compared to the fees recognized as revenue are characterized as unearned revenue. Unearned revenue is reported as deferred revenue ~~and~~on ~~included in other non-current liabilities in~~ the Consolidated Balance Sheet.

Deferred revenue is recognized as revenue once all contingencies or potential performance obligations associated with the related volumes have either been satisfied or expired. As of ~~September~~March 3031, ~~2016~~2017, the Partnership had deferred revenue ~~included in other non-current liabilities~~ of $1432.38 million, of which $69.25 million was generated during the three months ended March 31, 2017. As of December 31, 2016, the Partnership had $23.3 million deferred revenue.

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NOTES TO FINANCIAL STATEMENTS

September 30, 2016. See Note 9 “Commitments and Contingencies” for further discussion of the RRC Operating processing agreement. As of December 31, 2015, the Partnership had no deferred revenue.

Accounting Policies

The accounting policies followed by the Partnership are set forth in Note 2—Summary of Significant Accounting Policies in the ~~2015~~2016 Form 10-K. The accompanying unaudited consolidated financial statements include all of the Partnership’s accounts and the accounts of its subsidiaries. There were no significant changes to the Partnership’s accounting policies during the three months ended ~~September~~March 3031, ~~2016~~2017.

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) amended its guidance on revenue recognition. The core principle of those accounting standards updates (“ASU”) is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with earlier adoption permitted for interim and annual periods beginning after December 15, 2016. This guidance may be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership anticipates adopting this guidance in ~~fiscal~~the first quarter of 2018 and is currently evaluating the impact on its consolidated financial statements.The Partnership plans to apply the modified retrospective method. The Partnership is currently evaluating the impact of this pronouncement on its consolidated financial statements.

In February 2016, the FASB issued authoritative guidance that requires the balance sheet recognition of lease assets and lease liabilities by lessees for leases previously classified as operating leases under prior GAAP. The lease assets recognized in the balance sheet will represent a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The lease liability recognized in the balance sheet will represent the lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis. The Partnership will be required to adopt the new standard in annual and interim periods beginning January 1, 2019. Lessees and lessors will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date, and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. The Partnership is continuing to evaluate the new standard but has not yet determined the appropriate methodology for implementing the new standard or the expected impact adoption will have on its consolidated financial statements.

In March 2016, the FASB issued authoritative guidance to simplify the accounting for equity-based payments awarded to employees. This guidance is effective for interim and annual periods beginning after December 15, 2016, with earlier adoption permitted. The Partnership adopted this guidance effective as of April 1, 2016, and the adoption had no material impact on the consolidated financial statements.6

In August 2016, the FASB issued authoritative guidance to reduce the diversity of reporting on statements of cash flows. This guidance is effective for annual periods beginning after December 15, 2017, with earlier adoption permitted. The Partnership is evaluating the impact on its consolidated statement of cash flows.

In April 2015, the FASB issued authoritative guidance that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the debt liability rather than as an asset. This guidance is effective for interim and annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, with earlier adoption permitted. In August 2015, the FASB issued guidance that further clarifies the measurement of debt issuance costs related to line-of-credit arrangements. This guidance was adopted and applied retrospectively to each prior reporting period presented in this quarterly report and resulted in an increase in the debt issuance costs and a corresponding decrease in long-term debt, net, and eliminating the debt issuance costs, in each case as presented in the Consolidated Balance Sheet. The amount that was reclassified in the prior period was $1.4 million.

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NOTES TO FINANCIAL STATEMENTS

3the balance sheet will represent a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. ~~Identifiable~~The ~~Intangible~~lease ~~Assets~~liability recognized in the balance sheet will represent the lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis. The Partnership will be required to adopt the new standard in annual and interim periods beginning January 1, 2019. Lessees and lessors will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date, and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. The Partnership is continuing to evaluate the new standard but has not yet determined the appropriate methodology for implementing the new standard or the expected impact adoption will have on its consolidated financial statements.

~~Identifiable~~In ~~intangible~~August ~~assets~~2016, ~~which~~the ~~are~~FASB ~~subject~~issued authoritative guidance to ~~amortization,~~reduce ~~consist~~the diversity of ~~the~~reporting ~~following~~on (statements of cash flows. This amendment is intended to reduce diversity in ~~thousands):~~practice as to how certain cash receipts and cash payments are presented and classified in the statement of cash flows by providing guidance for several specific cash flow issues. This guidance becomes effective for fiscal years beginning after December 15, 2017 and, therefore, the Partnership will adopt this pronouncement January 1, 2018. The Partnership is currently evaluating the impact of this pronouncement on its consolidated financial statements.

	September 30, 2016
	Useful Lives(in years)	Gross CarryingAmount		AccumulatedAmortization		Net
Rights-of-way	30	$	20,828	$	865	$	19,963
Total		$	20,828	$	865	$	19,963

3. Long-term Debt

The Partnership’s debt obligations consisted of the following (in thousands) as of the below dates:

	December 31, 2015
	March 31, 2017				December 31, 2016
	Useful Lives(in years)		Gross CarryingAmount				AccumulatedAmortization		Net
$275 million MLP revolving credit facility	$	156,500			$	168,000
Rights-of-way	30		$	20,373			$	352	$	20,021
Unamortized debt issuance costs	(3,691		)		(4,027		)
Total			$	20,373			$	352	$	20,021
Total long-term debt	$	152,809			$	163,973

Amortization expense for the three months ended September 30, 2016 and 2015 was $0.2 million and $0.1 million, respectively. Amortization expense for the nine months ended September 30, 2016 and 2015 was $0.5 million and $0.2 million, respectively.

4. Property, Plant and Equipment

Property, plant and equipment consists of the following (in thousands):

	Useful Lives(in years)	September 30, 2016			December 31, 2015
Gathering, processing and transportation	30	$	372,073		$	366,910
Vehicles	5	644			572
Hardware and software	5 to 7	180			148
Other	3 to 7	2,233			1,963
Land	N/A	1,666			1,666
Total		376,796			371,259
Less accumulated depreciation		(15,348		)	(5,742		)
Net of accumulated depreciation		361,448			365,517
Construction in progress		433			544
Property, plant and equipment		$	361,881		$	366,061

Depreciation expense for the three months ended September 30, 2016 and 2015 was $3.2 million and $1.5 million, respectively. Depreciation expense for the nine months ended September 30, 2016 and 2015 was $9.6 million and $2.5 million, respectively.

For the three and nine months ended September 30, 2016, no interest expense was capitalized. For the three and nine months ended September 30, 2015, $1.1 million and $2.5 million, respectively, of interest expense related to the construction of the Partnership’s assets was capitalized and included in property, plant and equipment.

5. Long-term Debt

	September 30, 2016			December 31, 2015
$275 million MLP revolving credit facility	$	154,500		$	156,000
Unamortized debt discount costs	(4,364		)	(5,301		)
Total long-term debt	$	150,136		$	150,699

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NOTES TO FINANCIAL STATEMENTS

$275 million MLP revolving credit facility

On December 19, 2014, the Partnership entered into a senior secured revolving credit facility with Royal Bank of Canada, as administrative agent, and a syndicate of lenders that became effective ~~upon~~in ~~the~~June ~~closing~~2015 ~~of the Offering~~ and matures on December 19, 2019 (the “MLP revolving credit facility”). The agreement provides for a $275 million credit commitment that is expandable up to $400 million under certain conditions. The funds have been used for general purposes, including the funding of capital expenditures. The Partnership’s assets are pledged as collateral for this credit facility.

The MLP revolving credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict the Partnership’s ability to incur or guarantee additional debt, incur certain liens on assets, dispose of assets, make certain distributions (including distributions from available cash, if a default or event of default under the credit agreement then exists or would result from making such a distribution), change the nature of the Partnership’s business, engage in certain mergers or make certain investments and acquisitions, enter into non-arms-length transactions with affiliates and designate certain subsidiaries of the Partnership as “Unrestricted Subsidiaries” for purposes of the credit agreement. Currently, no subsidiaries have been designated as Unrestricted Subsidiaries. The Partnership is required to comply with a minimum consolidated interest coverage ratio of 2.50x and a maximum consolidated leverage ratio of 4.75x with respect to the fiscal quarter ending ~~September~~March 3031, ~~2016~~2017.

As of ~~September~~March 3031, ~~2016~~2017, the Partnership had $~~119~~117.5 million of available borrowing capacity under the MLP revolving credit facility. As of ~~September~~March 3031, ~~2016~~2017, the Partnership was in compliance with the covenants under the MLP revolving credit facility.

The borrowed amounts are subject to interest based upon the current consolidated total leverage ratio at the time of the borrowing. At the Partnership’s discretion it can borrow utilizing either Eurodollar loans or Alternate Base Rate (“ABR”) loans. Interest on Eurodollar loans is based on the LIBOR plus an applicable margin that varies between 2.0% and 3.25% based on the consolidated total leverage ratio. Interest on ABR loans is equal to the greatest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus 1.5% and (c) the Adjusted LIBOR for a one-month interest period on such day plus 1.0% and plus an applicable margin that varies between 1.00% and 2.25% based on the consolidated total leverage ratio. The unused portion of the credit facility is subject to a commitment fee, which is 0.375% multiplied by the amount of the unused commitment. As of ~~September~~March 3031, ~~2016~~2017, the weighted average interest rate on outstanding borrowings was 2.8%. The fair value of the long-term debt approximates the carrying amount because the interest rate is variable and reflective of market rates.

Total borrowing capacity	$	275,000
Less: Outstanding borrowings	154,500
Less: Letters of credit issued	1,000
Available borrowing capacity	$	119,500

The Partnership capitalized debt origination fees of $6.4 million associated with the MLP revolving credit facility and the OpCo revolving credit facility described below, which are included on the Consolidated Balance Sheet as a contra long-term debt. These amounts reflect $1.4 million of debt issuance costs that were presented as a reduction of long-term debt based upon adoption of the applicable FASB guidance described in Note 2. These fees will be amortized over the life of the MLP revolving credit facility. The Partnership had unamortized debt discount costs of $4.4 million and $5.3 million as of September 30, 2016 and December 31, 2015, respectively.

6. Equity-Based Awards

PennTex Midstream Partners, LP 2015 Long-Term Incentive Plan

In connection with the Offering, the board of directors (the “Board”) of the Partnership’s general partner adopted the PennTex Midstream Partners, LP 2015 Long-Term Incentive Plan (“LTIP”) pursuant to which awards in the form of unrestricted units, restricted units, equity participation units, options, unit appreciation rights, phantom units or distribution equivalent rights may be granted to employees, consultants and directors of the general partner and its affiliates who perform services for or on behalf of the Partnership or its affiliates. Award amounts, vesting requirements and other terms are determined by the Board at the time of each grant.

The LTIP limits the number of units that may be delivered pursuant to vested awards to 3,200,000 common units. LTIP awards that are subsequently canceled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be

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PENNTEX MIDSTREAM PARTNERS, LP

NOTES TO FINANCIAL STATEMENTS

The following table sets forth the outstanding borrowings, letters of credit issued and available borrowing capacity under the MLP revolving credit facility as of March 31, 2017 (in thousands):

available for delivery pursuant to other awards. The LTIP is administered by the Board or a committee thereof, which is referred to as the plan administrator.



Total borrowing capacity	$	275,000
Less: Outstanding borrowings	156,500
Less: Letters of credit issued	1,000
Available borrowing capacity	$	117,500

~~The plan administrator may terminate or amend the LTIP at any time with respect to any units for which a grant has not yet been made~~4. ~~The~~Partnership ~~plan~~and ~~administrator~~Equity also has the right to alter or amend the LTIP or any part of the plan from time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of a participant without the consent of such participant. The LTIP will expire upon termination by the plan administrator.Distributions

Phantom Units Granted

In June 2016, the Partnership granted an aggregate of 361,159 phantom units with a vesting period of three years and corresponding distribution equivalent rights (“DERs”) to employees and officers of the general partner and its affiliates. In connection with the completion of the Offering in June 2015, the Partnership granted an aggregate of 620,200 phantom units with a vesting period of three years and corresponding DERS to employees and officers of the general partner and its affiliates . A phantom unit entitles the grantee to receive a common unit upon the vesting date. Each phantom unit was granted in tandem with a corresponding DER that allows the holder to receive, for each phantom unit held, cash equal to any cash distribution paid on a common unit between the grant date and the date that the phantom units are settled or forfeited. The total value at grant date was $5.8 million and $12.2 million for the 2016 and 2015 grants, respectively, of which the Partnership recorded compensation expense of $1.5 million and $3.6 million during the three and nine months ended September 30, 2016, respectively. The Partnership recorded compensation expense of $1.0 million and $1.2 million related to the 2015 LTIP grants to employees during the three and nine months ended September 30, 2015, respectively. As of September 30, 2016, the Partnership had $11.9 million of unrecognized expense related to these LTIP grants. During the nine months ended September 30, 2016, 209,040 phantom units vested, and the Partnership withheld 40,020 of such phantom units to cover withholding taxes of $0.6 million for employees.

In June 2016, the Partnership issued 27,222 phantom units with a vesting period of one year and corresponding DERs to the three independent directors of the general partner. The total value of those grants at the grant date was $0.4 million. In 2015, the Partnership granted 15,000 phantom units with a vesting period of approximately one year and corresponding DERs to the three independent directors of the general partner. The total value of those three grants at the grant dates was $0.3 million. As of September 30, 2016, these units were fully vested. During the three and nine months ended September 30, 2016, the Partnership recorded $0.1 million and $0.3 million, respectively, of compensation expense related to these grants, with $0.3 million of unrecognized expense as of September 30, 2016. During the three and nine months ended September 30, 2015, the Partnership recorded $40 thousand and $46 thousand, respectively, of compensation expense related to the 2015 LTIP grants to directors.

The following table summarizes the changes in the phantom units outstanding for the nine months ended September 30, 2016:

	Nine months ended September 30, 2016
	Units	Weighted Average Grant DateFair Value		Weighted Average Remaining Vesting Period
Beginning of period	635,200	$	19.63	1.4 years
Granted	388,381	$	16.09	1.6 years
Vested	224,040	$	19.55	—
Forfeited	12,913	$	18.16	—
End of period	786,628	$	17.92	1.4 years

7. Partnership and Equity Distributions

Quarterly Distribution

The First Amended and Restated Agreement of Limited Partnership of the Partnership (the “Partnership Agreement”) provides for a minimum quarterly distribution of $0.2750 per unit for each quarter, or $1.10 per unit on an annualized basis. On ~~October~~April 2526, ~~2016~~2017, the Partnership announced a distribution of $0.2950 per unit for the ~~third~~first quarter of ~~2016~~2017. This distribution will be paid on ~~November~~May 1412, ~~2016~~2017 to unitholders of record on ~~November~~May 75, ~~2016~~2017.

The Partnership Agreement requires that distributions for each quarter will be paid to the extent there is sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to the general partner and its affiliates5. ~~The~~Earnings ~~Partnership’s~~per ~~ability to pay the minimum quarterly distribution is subject to various restrictions and other factors.~~ Unit

10The following table illustrates the Partnership’s calculation of net income per unit for the three months ended March 31, 2017:



	Three months ended March 31,
	2017			2016
	(in thousands, except unit and per unit amounts)
Net income	$	5,896		$	3,517
Less: Net loss attributable to general partner	—			(1,157		)
Net income attributable to the Partnership	5,896			4,674
Less:
Payments for distribution equivalents ⁽²⁾	—			174
Limited partners’ distribution declared on common units⁽¹⁾	6,110			5,501
Limited partners’ distribution declared on subordinated units⁽¹⁾	5,900			5,500
Distribution in excess of net income attributable to the Partnership	(6,114		)	(6,501		)
Distribution in excess of net income attributable to equity-based awards	—			(101		)
Distribution in excess of net income attributable to partners	$	(6,114	)	$	(6,400	)

⁽¹⁾Distribution declared on April 26, 2017, attributable to the first quarter of 2017.

⁽²⁾Represents Distribution Equivalent Rights (the “DERs”) paid in respect of phantom units.

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PENNTEX MIDSTREAM PARTNERS, LP

NOTES TO FINANCIAL STATEMENTS

The Partnership Agreement generally provides for distributions of cash each quarter during the subordination period in the following manner:



	General Partner		Limited Partners— Common Units			Limited Partners— Subordinated Units			Total
	(in thousands, except unit and per unit amounts)
Three Months Ended March 31, 2017
Net income attributable to the limited partner unitholders:
Distribution declared⁽¹⁾	$	—	$	6,110		$	5,900		$	12,010
Distribution in excess of net income attributable to partners	—		(3,111		)	(3,003		)	(6,114		)
Net income attributable to limited partners	$	—	$	2,999		$	2,897		$	5,896

Weighted average common units outstanding:
Basic	—		20,714,256			20,000,000			40,714,256
Diluted	—		20,714,256			20,000,000			40,714,256

Net income per common unit:
Basic			$	0.14		$	0.14
Diluted			$	0.14		$	0.14

•(1)Distribution ~~first~~declared on April 26, 2017 attributable to the ~~holders~~period ofindicated; ~~common~~includes ~~units,~~distribution ~~until~~to ~~each~~be ~~common~~paid ~~unit~~in ~~has~~respect ~~received~~of ~~the~~common ~~minimum~~units ~~quarterly~~issued ~~distribution~~and outstanding as of ~~$0.2750~~the ~~plus~~distribution ~~any~~record ~~arrearages~~date ~~from~~of ~~prior~~May 5, ~~quarters;~~2017.

• second, to the holders of subordinated units, until each subordinated unit has received the minimum quarterly distribution of $0.2750; and



	General Partner		Limited Partners— Common Units			Limited Partners— Subordinated Units			Total
	(in thousands, except unit and per unit amounts)
Three months ended March 30, 2016
Net income attributable to the limited partner unitholders:
Distribution declared	$	—	$	5,500		$	5,500		$	11,000
Distribution in excess of net income attributable to partners	—		(3,200		)	(3,200		)	(6,400		)
Net income attributable to partners	$	—	$	2,300		$	2,300		$	4,600

Weighted average common units outstanding:
Basic	—		20,000,000			20,000,000			40,000,000
Diluted	—		20,000,000			20,000,000			40,000,000

Net income per common unit:
Basic			$	0.12		$	0.12
Diluted			$	0.12		$	0.12

•6. ~~third,~~Commitments ~~to the holders of common units~~ and ~~subordinated units, pro rata, until each has received a distribution of $0.3163.~~Contingencies

If cash distributions to the unitholders exceed $0.3163 per common unit and subordinated unit in any quarter, the unitholders and the holders of the IDRs will receive distributions according to the following percentage allocations:

Total Quarterly Distribution	Marginal Percentage Interest in Distributions
Target Amount	Unitholders		IDRs
above $0.3163 up to $0.3438	85	%	15	%
above $0.3438 up to $0.4125	75	%	25	%
above $0.4125	50	%	50	%

Subordinated Units

The Partnership has 20,000,000 subordinated units outstanding, of which PennTex Development owns 12,500,000 subordinated units. The principal difference between the common units and subordinated units is that, for any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution from operating surplus until the common units have received the minimum quarterly distribution from operating surplus for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages. When the subordination period ends, all of the subordinated units will convert into an equal number of common units.

Except as described below, the subordination period began on the closing date of the Offering (June 9, 2015) and extends until the first business day following the distribution of available cash in respect of any quarter beginning after September 30, 2018, provided the following tests are met:

• distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded $1.10 (the annualized minimum quarterly distribution), for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

• the adjusted operating surplus generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of $1.10 (the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units during those periods on a fully diluted basis; and

• there are no arrearages in payment of the minimum quarterly distribution on the common units.

Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day following the distribution of available cash in respect of any quarter, beginning with the quarter ending September 30, 2016, provided the following tests are met:

• distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded $1.65 (150% of the annualized minimum quarterly distribution), plus the related distributions on the incentive distribution rights, for the four-quarter period immediately preceding that date;

• the adjusted operating surplus generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of (1) $1.65 (150% of the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units during that period on a fully diluted basis and (2) the corresponding distributions on the incentive distribution rights; and

• there are no arrearages in payment of the minimum quarterly distributions on the common units.

To the extent there is cash available for distribution from operating surplus in any future quarter during the subordination period in excess of the amount necessary to pay the minimum quarterly distribution to holders of the common units, the Partnership will use this excess cash to pay any distribution arrearages on common units related to prior quarters before any

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PENNTEX MIDSTREAM PARTNERS, LP

NOTES TO FINANCIAL STATEMENTS

cash distribution is made to holders of subordinated units. If the Partnership does not pay the minimum quarterly distribution on the common units for any quarter following the subordination period, the common unitholders will not be entitled to receive such arrearage payments.

8. Earnings per Unit

The Partnership’s net income is allocated to the limited partners, including the holders of the subordinated units, in accordance with their respective ownership percentages. The Partnership’s net income allocated to the limited partners excludes incentive distributions and expenses incurred by the general partner and its affiliates on behalf of the Partnership that are not required to be reimbursed by the Partnership. These expenses are allocated solely to the general partner because the Partnership is not required to reimburse the general partner for these expenses. Accordingly, these expenses are disregarded in determining the limited partners’ share in earnings of the Partnership.

The Partnership computes earnings per unit using the two-class method for master limited partnerships as prescribed in the guidance Accounting Standards Codification (“ASC”) 260. The two-class method requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic earnings per unit. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the Partnership Agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.

The Partnership calculates net income available to limited partners based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner and limited partners in accordance with the contractual terms of the Partnership Agreement and as further prescribed in the guidance in ASC 260 under the two-class method.

The two-class method does not impact the overall net income or other financial results; however, in periods in which aggregate net income exceeds the aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of the aggregate earnings, as if distributed, is allocated to the incentive distribution rights, even though the Partnership makes distributions on the basis of available cash and not earnings. In periods in which the aggregate net income does not exceed the aggregate distributions for such period, the two-class method does not have any impact on the calculation of earnings per limited partner unit.

Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted average number of units outstanding during each period. Diluted earnings per unit reflects the potential dilution of common equivalent units that could occur if common equivalent units are converted into common units.

As the Offering was completed on June 9, 2015, no income from the period from January 1, 2015 to June 9, 2015 is allocated to the common and subordinated units issued on June 9, 2015, and all income for such period was allocated to the general partner or predecessor operations.

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PENNTEX MIDSTREAM PARTNERS, LP

NOTES TO FINANCIAL STATEMENTS

The following table illustrates the Partnership’s calculation of net income per unit for the three and nine months ended September 30, 2016:

	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016		2015 (1)
	(in thousands, except unit and per unit amounts)
Net income (loss)	$	5,828		$	2,020		13,514		(5,214	)
Less: Net loss attributable to general partner	(613		)	(1,500		)	(3,011	)	(8,592	)
Net income attributable to the Partnership	6,441			3,520			16,525		3,378
Less:
General partner’s distribution	—			—			—		—
Distribution declared on IDRs	—			—			—		—
Payments for distribution equivalents (2)(3)	232			172			633		215
Limited partners’ distribution declared on common units(2)	5,954			5,500			17,199		6,830
Limited partners’ distribution declared on subordinated units(2)	5,900			5,500			17,092		6,830
Distribution in excess of net income attributable to the Partnership	(5,645		)	(7,652		)	(18,399	)	(10,497	)
Distribution in excess of net income attributable to equity-based awards	(107		)	(119		)	(349	)	(163	)
Distribution in excess of net income attributable to limited partners	$	(5,538	)	$	(7,533	)	(18,050	)	(10,334	)

(1)For periods prior to the Offering on June 9, 2015, no net income is attributable to the Partnership.

(2)Distribution declared on October 19, 2016, attributable to the third quarter of 2016.

(3)Represents DERs to be paid in respect of phantom units.

	GeneralPartner		Limited Partners—Common Units			LimitedPartners—SubordinatedUnits			Total
	(in thousands, except unit and per unit amounts)
Three Months Ended September 30, 2016
Net income (loss) attributable to the limited partner unitholders:
Distribution declared(1)	$	—	$	5,954		$	5,900		$	11,854
Distribution less than (in excess of) net income attributable to the Partnership	—		(2,782		)	(2,756		)	(5,538		)
Net income attributable to limited partners	$	—	$	3,172		$	3,144		$	6,316
Weighted average common units outstanding:
Basic	—		20,184,020			20,000,000			40,184,020
Diluted	—		20,184,020			20,000,000			40,184,020
Net income per common unit:
Basic			$	0.16		$	0.16
Diluted			$	0.16		$	0.16

(1)Distribution declared on October 19, 2016 attributable to the period indicated; includes distribution to be paid in respect of common units issued and outstanding as of the distribution record date of November 7, 2016.

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PENNTEX MIDSTREAM PARTNERS, LP

NOTES TO FINANCIAL STATEMENTS

	GeneralPartner		Limited Partners—Common Units			LimitedPartners—SubordinatedUnits			Total
	(in thousands, except unit and per unit amounts)
Three months ended September 30, 2015
Net income (loss) attributable to the limited partner unitholders:
Distribution declared	$	—	$	5,500		$	5,500		$	11,000
Distribution in excess of net income attributable to the Partnership	—		(3,766		)	(3,767		)	(7,533		)
Net loss attributable to the partnership	$	—	$	1,734		$	1,733		$	3,467
Weighted average common units outstanding:
Basic	—		20,000,000			20,000,000			40,000,000
Diluted	—		20,000,000			20,000,000			40,000,000
Net income per common unit:
Basic			$	0.09		$	0.09
Diluted			$	0.09		$	0.09

	GeneralPartner		Limited Partners—Common Units			LimitedPartners—SubordinatedUnits			Total
	(in thousands, except unit and per unit amounts)
Nine months ended September 30, 2016
Net income (loss) attributable to the limited partner unitholders:
Distribution declared(1)	$	—	$	17,199		$	17,092		$	34,291
Distribution in excess of net income attributable to the Partnership	—		(9,063		)	(8,987		)	(18,050		)
Net income attributable to the partnership	$	—	$	8,136		$	8,105		$	16,241
Weighted average common units outstanding:
Basic	—		20,075,644			20,000,000			40,075,644
Diluted	—		20,075,644			20,000,000			40,075,644
Net income per common unit:
Basic			$	0.41		$	0.41
Diluted			$	0.41		$	0.41

(1)Distribution declared attributable to the periods indicated; includes distribution declared on October 19, 2016 to be paid in respect of common units issued and outstanding as of the distribution record date of November 7, 2016.

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PENNTEX MIDSTREAM PARTNERS, LP

NOTES TO FINANCIAL STATEMENTS

	GeneralPartner		Limited Partners—Common Units			LimitedPartners—SubordinatedUnits			Total
	(in thousands, except unit and per unit amounts)
Nine months ended September 30, 2015
Net income (loss) attributable to the limited partner unitholders:
Distribution declared	$	—	$	6,830		$	6,830		$	13,660
Distribution in excess of net income attributable to the Partnership	—		(5,167		)	(5,167		)	(10,334		)
Net loss attributable to the partnership	$	—	$	1,663		$	1,663		$	3,326
Weighted average common units outstanding:
Basic	—		20,000,000			20,000,000			40,000,000
Diluted	—		20,000,000			20,000,000			40,000,000
Net income per common unit:
Basic			$	0.08		$	0.08
Diluted			$	0.08		$	0.08

9. Commitments and Contingencies

Contractual Commitments

Commercial Agreements with RRC Operating

The Partnership has entered into 15-year processing, gathering and residue gas and NGL transportation agreements with RRC Operating. The processing agreement contains a specified daily minimum volume threshold for RRC Operating, which increased to 460,000 MMBtu/d effective July 1, 2016. On July 1, 2026, RRC Operating’s daily minimum volume threshold will decrease to 345,000 MMBtu/d through May 31, 2030, and will then decrease to 115,000 MMBtu/d effective June 1, 2030 through the remainder of the initial term ending October 1, 2030. Any volumes of gas delivered up to the applicable daily minimum volume threshold are charged the firm fixed-commitment fee and any volumes delivered in excess of such threshold are charged the interruptible-service fixed fee. RRC Operating must pay a deficiency payment based on the firm-commitment fixed fee with respect to a particular quarterly period if the cumulative minimum volume commitment as of the end of such period exceeds the sum of (i) the cumulative volumes processed under the processing agreement as of the end of such period plus (ii) volumes corresponding to deficiency payments incurred prior to such period. RRC Operating may utilize these deficiency payments as a credit for fees owed to the Partnership only to the extent it has delivered the total minimum volume commitment under the processing agreement within the initial 15-year term of the agreement. Additionally, all volumes delivered by RRC Operating in excess of the minimum volume commitment in a quarterly period apply against and reduce, on a one-for-one basis, the cumulative minimum volume commitment used to calculate deficiency payments for future quarterly periods. The processing agreement also requires RRC Operating to reimburse a portion of the Partnership’s electricity expenses for electric compression at the processing plants.

The gathering agreement provides for the gathering of RRC Operating’s processable natural gas for delivery to the Partnership’s processing plants (or a third party as described below). The gathering agreement initially provides for a firm capacity reservation payment and a usage fee that is subject to a minimum volume commitment. For the period from June 1, 2015 through November 30, 2019, (i) the firm capacity reservation payment is based on a daily capacity of 460,000 MMBtu/d, calculated monthly, and (ii) the usage fee is based on volumes delivered into the gathering system, subject to a deficiency fee based on a specified minimum volume commitment that is calculated and paid on an annual basis. The specified minimum gathering volume commitment equals RRC Operating’s then applicable daily minimum volume threshold under the processing agreement (excluding any optional increases by RRC Operating). Accordingly, the specified minimum gathering volume commitment will not be less than 115,000 MMBtu/d nor more than 460,000 MMBtu/d. Beginning December 1, 2019 through the end of the gathering agreement term, all volumes will be subject to a usage fee, subject to the deficiency fee and minimum volume commitment described above, and no firm capacity reservation payment will apply. The gathering agreement also provides for the delivery of RRC Operating’s rich natural gas, on an interruptible basis, to facilities operated by a third party for a specified usage fee. 9

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PENNTEX MIDSTREAM PARTNERS, LP

NOTES TO FINANCIAL STATEMENTS

through the remainder of the initial term ending October 1, 2030. Any volumes of gas delivered up to the applicable daily minimum volume threshold are charged the firm fixed-commitment fee and any volumes delivered in excess of such threshold are charged the interruptible-service fixed fee. RRC Operating must pay a deficiency payment based on the firm-commitment fixed fee with respect to a particular quarterly period if the cumulative minimum volume commitment as of the end of such period exceeds the sum of (i) the cumulative volumes processed under the processing agreement as of the end of such period plus (ii) volumes corresponding to deficiency payments incurred prior to such period. RRC Operating may utilize these deficiency payments as a credit for fees owed to the Partnership only to the extent it has delivered the total minimum volume commitment under the processing agreement within the initial 15-year term of the agreement. Additionally, all volumes delivered by RRC Operating in excess of the minimum volume commitment in a quarterly period apply against and reduce, on a one-for-one basis, the cumulative minimum volume commitment used to calculate deficiency payments for future quarterly periods. The processing agreement also requires RRC Operating to reimburse a portion of the Partnership’s electricity expenses for electric compression at the processing plants.

The residue gas and NGL transportation agreements provide for the transportation of residue gas and NGLs produced at the Partnership’s processing plants to downstream markets. RRC Operating pays a usage fee for all volumes transported under the residue gas and NGL transportation agreements and also pays a monthly fee for priority firm service under the gas transportation agreement. Both transportation agreements include a plant tailgate dedication pursuant to which all of RRC Operating’s residue gas and NGLs produced from the Partnership’s processing plants are delivered for transportation on the Partnership’s residue gas and NGL pipelines.

Services and Secondment Agreement

The Partnership is party to a 10-year services and secondment agreement with the general partner, PennTex Development and PennTex Midstream Management Company, LLC (“PennTex Management”) pursuant to which PennTex Management and PennTex Development provide operational, general and administrative services to the Partnership. ~~See Note 10 “Related-Party Transactions”.~~

Guarantees or Other Support

The Partnership has letters of credit outstanding that are backed by the MLP revolving credit facility as collateral support.

Legal Proceedings

The Partnership may from time to time be involved as a party to various legal proceedings that are incidental to the ordinary course of business. The Partnership regularly analyzes current information and, as necessary, will provide accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management, as of ~~September~~March 3031, ~~2016~~2017, there are no pending legal matters that would have a material impact on the results of operations, financial position or cash flows.

107. Related-Party Transactions

Commercial Contracts

The Partnership has entered into commercial agreements with RRC Operating (formerly MRD Operating LLC) for the gathering, processing and transportation of natural gas and NGLs (see Note 9 “Commitments and Contingencies”). The gathering agreement and the residue gas transportation agreement are expected to remain in effect until June 1, 2030, and the processing agreement and the NGL transportation agreement are expected to remain in effect until October 1, 2030. As of September 16, 2016, RRC Operating is no longer a related party. In addition, the Partnership has entered into an agreement with WildHorse Resources II LLC (“WHR II”), pursuant to which the Partnership provides gathering and/or processing and transportation services to WHR II on an interruptible basis. WHR II is an affiliate of NGP and is therefore a related party to the Partnership.

For the three months ended September 30, 2016 and 2015, the Partnership had revenue of $17.0 million and $11.2 million, respectively, from related-party commercial agreements. For the nine months ended September 30, 2016 and 2015, the Partnership had revenue of $51.9 million and $14.1 million, respectively, from related-party commercial agreements. As of September 30, 2016 and December 31, 2015, the Partnership had accounts receivable from related parties on the Consolidated Balance Sheet of $20.2 thousand and $5.9 million, respectively.

Operational, General and Administrative Services

The Partnership does not have employees, and the officers of the general partner, ~~who are also officers of PennTex Development,~~ manage the operations and activities of the Partnership. All operational, general and administrative responsibilities are performed by employees of ~~PennTex~~Energy ~~Management~~Transfer pursuant to the services and secondment agreement and for which the Partnership reimburses or pays a specified administrative fee to ~~PennTex~~Energy ~~Management~~Transfer, which is settled in cash monthly. The administrative fee was $250,000 per month during the first six months of the year ~~ending~~ended December 31, 2016 and iswas $333,333 per month during the last six months of the year ~~ending~~ended December 31, 2016. Beginning January 1, 2017, the administrative fee is subject to renegotiation. The Partnership is also required to reimburse PennTex Development and its affiliates for all other direct or allocated costs and expenses incurred by them on the Partnership’s behalf under the services and secondment agreement.

In addition, the Partnership is allocated additional general and administrative expenses to the extent that the administrative fee paid under the services and secondment agreement is less than the Partnership’s share of PennTex Development’s overall general and administrative expenses, which allocation is not payable in cash and is recorded as a non-cash general and administrative expense of the Partnership. The non-cash general and administrative expense is recorded as a non-cash contribution to the Partnership by the general partner. The Partnership’s allocated general and administrative expenses and operating and maintenance expenses consist of the following (in thousands):10

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PENNTEX MIDSTREAM PARTNERS, LP

NOTES TO FINANCIAL STATEMENTS

	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
Allocated general and administrative expenses:
Cash	$	1,000	$	250	$	2,500	$	3,842
Non-cash	613		1,500		3,011		1,908
Operating and maintenance expenses	1,336		1,002		3,765		2,236
Total	$	2,949	$	2,752	$	9,276	$	7,986

December 31, 2016. Beginning January 1, 2017, the administrative fee is subject to renegotiation. Beginning January 1, 2017, the administrative fee is $338,000 per month. The Partnership is also required to reimburse PennTex Development and its affiliates for all other direct or allocated costs and expenses incurred by them on the Partnership’s behalf under the services and secondment agreement.

~~The~~In addition, the Partnership ~~had~~is ~~outstanding~~allocated ~~accounts~~additional ~~payable~~general and administrative expenses to the extent that the administrative fee paid under the services and secondment agreement is less than the Partnership’s share of PennTex Development’s ofoverall ~~$0.7~~general ~~million~~and administrative expenses, which allocation is not payable in cash and ~~$0.5~~is ~~million~~recorded as a non-cash general and administrative expense of ~~September 30,~~the ~~2016~~Partnership. The non-cash general and ~~December~~administrative ~~31,~~expense ~~2015,~~is ~~respectively~~recorded as a non-cash contribution to the Partnership by the general partner. The Partnership’s allocated general and administrative expenses and operating and maintenance expenses consist of the following (in thousands):

11. Concentrations of Risk



	Three months ended March 31,
	2017		2016
Allocated general and administrative expenses:
Cash	$	1,000	$	750
Non-cash	—		1,157
Operating and maintenance expenses	730		1,152
Total	$	1,730	$	3,059

The Partnership had outstanding accounts payable to affiliates of $3.4 million and $0.6 million as of March 31, 2017 and December 31, 2016, respectively.

8. Concentrations of Risk

Financial instruments that potentially subject the Partnership to concentrations of credit risk consist of cash and cash equivalents and accounts receivable. The Partnership maintains cash in bank deposit accounts that, at times, may exceed federally insured limits. The Partnership has not experienced any losses in such accounts to date and does not believe it is exposed to any significant risk.

Accounts receivable are from natural gas producers for which the Partnership will gather, process and transport natural gas and transport natural gas liquids. This industry concentration has the potential to impact the Partnership’s overall exposure to credit risk, either positively or negatively, in that the Partnership’s customers may be similarly affected by changes in economic, industry or other conditions. Management monitors the creditworthiness of counterparties.

AsThe ~~discussed in Note 9 Commitments and Contingencies, the~~ Partnership has entered into long-term commercial agreements with RRC Operating. RRC Operating accounted for 9486% and ~~100~~97% of the Partnership’s total revenues for the three ~~and nine~~ months ended ~~September~~March 3031, ~~2016~~2017 and ~~2015~~2016, respectively. The Partnership is potentially exposed to concentration of business and credit risk primarily through the Partnership’s commercial agreements with RRC Operating. Management monitors the creditworthiness of RRC Operating, and the Partnership has not experienced any collectability issues with RRC Operating.

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

The following discussion and analysis should be read in conjunction with the historical financial statements and related notes included in Part I, Item 1 of this quarterly report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Please read “Cautionary Statement Regarding Forward-Looking Statements” on page ii of this quarterly report Also, please read the risk factors and other cautionary statements described under “Risk Factors” in Item 1A of the Partnership’s Annual Report on Form 10-K for the year ended December 31, ~~2015~~2016 (the “~~2015~~2016 Form 10-K”)included elsewhere in this report. We do not undertake any obligation to update any forward-looking statements except as otherwise required by applicable law.

The historical financial statements included in this quarterly report reflect the results of operations of PennTex North Louisiana, LLC, which we refer to as our predecessor. Our predecessor was formed on March 17, 2014. In connection with the closing of our initial public offering on June 9, 2015, PennTex North Louisiana, LLC became our wholly-owned subsidiary. References in this quarterly report to “predecessor,” “we,” “our,” “us” or like terms, when referring to periods prior to June 9, 2015, refer to PennTex North Louisiana, LLC. References to “the Partnership,” “we,” “our,” “us” or like terms, when referring to periods after June 9, 2015, refer to PennTex Midstream Partners, LP and its subsidiaries, including PennTex North Louisiana, LLC.

Overview

We are a growth-oriented limited partnership focused on owning, operating, acquiring and developing midstream energy infrastructure assets in North America. Our sponsor, ~~with~~PennTex anDevelopment, ~~initial~~was ~~focus~~formed by members of its original management team and by NGP in ~~northern~~2014 ~~Louisiana~~to develop a multi-basin midstream growth platform initially in partnership with oil and natural gas producers affiliated with NGP.

WeOn ~~own~~November ~~and~~1, ~~operate~~2016, ~~midstream~~ETP ~~gathering,~~acquired ~~processing~~from NGP and ~~transportation~~certain ~~assets~~other incontributors ~~northern~~(i) ~~Louisiana.~~all ~~Our~~of ~~assets~~the ~~consist~~outstanding ofmembership ainterests ~~natural~~in ~~gas~~PennTex ~~gathering~~Development, ~~pipeline~~(ii) 6,301,596 common ~~two~~units ~~200~~and ~~MMcf/d~~20,000,000 ~~design-capacity~~subordinated ~~cryogenic~~units ~~natural~~collectively ~~gas~~representing ~~processing~~approximately ~~plants~~65% (of the ~~Lincoln~~outstanding ~~Parish~~limited ~~plant~~partner ~~and~~interests in the ~~Mt.~~Partnership, ~~Olive plant~~(iii) all of ~~and~~the ~~residue~~outstanding ~~gas~~membership ~~and~~interests ~~NGL~~in ~~transportation~~our ~~pipelines.~~general ~~Our~~partner ~~assets~~and ~~were~~(iv) all of ~~constructed~~the inPartnership’s ~~two~~incentive ~~phases~~distribution rights. ~~Phase~~As I,a ~~which~~result ~~included~~of ~~the~~such ~~gathering pipeline~~transaction, ~~the~~ETP ~~Lincoln~~owns ~~Parish~~our ~~plant~~general partner and acontrols ~~1-mile~~the ~~segment~~Partnership. ofDuring the ~~residue~~three ~~gas~~months ~~pipeline,~~ended ~~was~~March ~~completed~~31, in2017, ~~May~~Energy ~~2015.~~Transfer ~~Phase~~purchased IIan ~~included~~additional ~~the~~400,000 ~~Mt.~~common ~~Olive~~units ~~plant,~~on the ~~NGL~~open ~~pipeline~~market, ~~and~~increasing atheir ~~14-mile~~total ~~segment~~investment to 66% of the ~~residue~~outstanding ~~gas~~limited ~~pipeline~~partner ~~and~~interests ~~was completed~~ in ~~September~~the ~~2015~~Partnership.

In April 2017, Energy Transfer merged with a subsidiary of Sunoco Logistics Partners L.P., at which time Energy Transfer changed its name from “Energy Transfer Partners, L.P.” to “Energy Transfer, LP” and Sunoco Logistics Partners L.P. changed its name to “Energy Transfer Partners, L.P.” References to “Energy Transfer” refer to the entity named Energy Transfer Partners, L.P. prior to the close of the merger and the combined entity subsequent to the merger.

We currently provide natural gas gathering and processing and residue gas and NGL transportation services to producers focused on the Cotton Valley formation in northern Louisiana. Our assets primarily consist of natural gas gathering pipeline, two 200 MMcf/d design-capacity cryogenic natural gas processing plants and residue gas and NGL transportation pipelines. Our primary customer is Range Resources, which completed its acquisition of Memorial Resource in September 2016. Prior to its acquisition by Range Resources, Memorial Resource was an affiliate of NGP and was our primary customer. In addition to providing midstream services to our primary customer with our existing assets, we pursue other opportunities for organic development and growth as producers in our region continue to develop their acreage.

Our assets are supported by long term, fee-based commercial agreements with Range Resources, including gathering and processing agreements that contain minimum volume commitments. Under the AMI and Exclusivity Agreement, we also have the exclusive right to develop, own and operate midstream assets and to provide midstream services to support Range Resources’ growing production in northern Louisiana (other than production subject to existing third-party commitments or other arrangements to which we consent).

Our Operations

We generate asubstantially ~~majority~~all of our revenues pursuant to long-term, fee-based commercial agreements with Range Resources Corporation (“Range Resources”). Our gathering and processing agreements with Range Resources contain minimum volume commitments, our gathering agreement contains firm capacity reservation payments and our residue gas and NGL transportation agreements contain plant tailgate dedications for natural gas processed at our processing plants. We believe these commercial agreements provide long-term stability to our business. In addition, pursuant to the AMI and Exclusivity Agreement, we have the exclusive right to provide midstream services to support Range Resources’ current and future production on its operated acreage within northern Louisiana (other than production subject to existing third-party commitments or other arrangements to which we consent). Our assets are designed to accommodate projected future production growth of Range Resources and to allow us to pursue volumes from third parties.

OnBecause ~~September~~we ~~16,~~do ~~2016~~not take ownership of the natural gas and NGLs that we gather, process and transport under our agreements with Range Resources, ~~completed~~we ~~its~~generally ~~previously~~do ~~announced~~not ~~acquisition~~have ofdirect ~~Memorial~~exposure ~~Resource~~to ~~Development~~fluctuations ~~Corp~~in commodity prices. WeHowever, dowe ~~not~~have ~~expect~~indirect ~~the~~exposure ~~merger~~to commodity prices in that persistently low commodity prices may cause Range Resources or other customers to ~~have~~delay adrilling ~~material~~or ~~impact~~shut-in production, which would reduce the volumes of natural gas available for gathering, processing and transporting on our ~~business~~systems. In addition, we take title to and resell NGLs that we process pursuant to

Because we do not take ownership of the natural gas and NGLs that we gather, process and transport under our agreements with Range Resources, we generally do not have direct exposure to fluctuations in commodity prices. However, we have indirect exposure to commodity prices in that persistently low commodity prices may cause Range Resources or other customers to delay drilling or shut-in production, which would reduce the volumes of natural gas available for gathering, processing and transporting on our systems. In addition, we take title to and resell NGLs that we process pursuant to interruptible processing agreements with two other customers, which results in some direct commodity price exposure. However, because these are interruptible agreements, we are not obligated to process any specified natural gas volumes and we are not required to purchase any NGLs under these agreements. The revenues and costs of revenue from these interruptible agreements represent an insignificant amount of our total reported revenues and costs of revenue.12

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interruptible processing agreements with other customers, which results in some direct commodity price exposure. However, because these are interruptible agreements, we are not obligated to process any specified natural gas volumes and we are not required to purchase any NGLs under the agreement.

Please read “Quantitative and Qualitative Disclosures About Market Risk” in Item 3 of this quarterly report.

How We Evaluate Our Operations

Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and liquidity and review these measurements on at least a monthly basis for consistency and trend analysis. These metrics include (i) contract mix and volumes, (ii) operating costs and expenses and (iii) Adjusted EBITDA and distributable cash flow. We manage our business and analyze our results of operations as a single business segment.

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(iii) Adjusted EBITDA and distributable cash flow. We manage our business and analyze our results of operations as a single business segment.

Contract Mix and Volumes

Our results are driven primarily by fees assessed for volumes of natural gas that we gather and process and volumes of residue gas and NGLs that we transport for our customers. In order to limit our direct exposure to commodity price volatility, where possible, we have and will continue to seek to enter into multi-year, fee-based contracts. If market conditions do not allow us to enter into fee-based contracts, we may enter into contracts that expose us to commodity price volatility. Additionally, we seek to enter into contracts containing firm volume commitments or similar arrangements to provide revenue certainty for our assets, particularly in the context of making investment decisions for new midstream infrastructure. To the extent our contracts contain usage-based fees, our results will depend on actual throughput volumes.

Our current contracts with Range Resources contain minimum volume commitments for natural gas processing, firm capacity reservation fees for natural gas gathering and interruptible fees for volumes in excess of those minimum and firm commitments, as applicable, and usage fees for residue gas and NGL transportation. Although these contracts are entirely fee-based and accordingly limit our commodity price exposure, the volume of natural gas that we gather, process or transport depends on successful drilling and production activity in northern Louisiana, and we generally expect the level of drilling and production to positively correlate with long-term trends in commodity prices.

Operating Costs and Expenses

The primary components of our operating costs and expenses that we evaluate include operations and maintenance and general and administrative. Our general and administrative expenses reflected in our historical financial statements largely reflect costs during a period of construction and development in a privately-held partnership. We have incurred additional operating costs and expenses following the completion of our assets and due to additional general and administrative costs and expenses incurred as a result of being a publicly traded partnership.

Operations and Maintenance Expense

Operations and maintenance expense consists primarily of utilities and power costs, employee, contract services and material and supply costs, whether directly incurred by us or incurred by our general partner and billed to us. Changes in operating conditions and changes in regulation can impact maintenance requirements and affect the timing and amount of our operating costs and expenditures.

General and Administrative Expense

In our historical financial statements, general and administrative ~~expense included various direct and indirect cost allocations from PennTex Development. Following the completion of our initial public offering (the “Offering”), our general and administrative~~ expenses consist primarily of: (i) ~~similar~~ direct and indirect costs for which we reimburse our general partner, PennTex Development and its affiliates pursuant to the services and secondment agreement among us, our general partner, PennTex Development and PennTex Management and (ii) other expenses attributable to our status as a publicly traded partnership, such as expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with maintaining compliance with applicable NASDAQ listing requirements; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance expenses and director compensation.

Adjusted EBITDA and Distributable Cash Flow

We use Adjusted EBITDA and distributable cash flow to assess the ability of our assets to generate cash sufficient to pay interest costs, support indebtedness and make cash distributions. We define Adjusted EBITDA as net income, plus interest expense, income taxes, depreciation and amortization, changes in deferred revenue, equity-based compensation expense, non-cash general and administrative expenses, non-cash loss (income) related to derivative instruments and impairments on long-term assets. We define distributable cash flow as Adjusted EBITDA, less cash interest expense related to operating activities, net of interest income, income taxes paid and maintenance capital expenditures, and distribution equivalents paid in cash. Distributable cash flow does not reflect changes in working capital balances.

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Adjusted EBITDA and distributable cash flow are non-GAAP supplemental financial measures that our management uses, and external users of our financial statements, such as investors, commercial banks, research analysts and others, may use, to assess:

•the ability of our business to generate sufficient cash flow to make distributions to our unitholders;

•our ability to incur and service debt and fund capital expenditures;

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•the financial performance as compared to other publicly traded companies in the midstream energy industry, without regard to historical cost basis or, in the case of Adjusted EBITDA, financing methods; and

•the viability of acquisitions and other capital expenditure projects and the returns on investment of various expansion and growth opportunities.

The GAAP liquidity measure most directly comparable to Adjusted EBITDA and distributable cash flow is net cash provided by operating activities. We believe that the presentation of Adjusted EBITDA and distributable cash flow provides information useful to investors in assessing our financial condition and results of operations. Adjusted EBITDA and distributable cash flow should not be considered alternatives to net income, operating income, cash flows from operations or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and distributable cash flow have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities. Additionally, because Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

~~Factors Impacting the Comparability of Our Financial Results~~14

The following factors may affect the comparability of our historical results of operations as well as the comparability of our historical results to future results:

Construction of Our Assets

From the inception of our predecessor in March 2014 until September 2015, our activities consisted mainly of constructing our assets. A portion of our gathering pipeline was completed in December 2014, and the Lincoln Parish plant, our residue gas pipeline and the remaining portions of our gathering pipeline were completed in May 2015. Our remaining assets were completed in September 2015.

Revenues

Prior to the completion of our Phase I assets in May 2015, we earned only limited revenues from our gathering pipeline. Following the completion of our assets in May and September 2015 and the commencement of our commercial agreements with Range Resources, our financial results reflect our full range of midstream services. For the three and nine months ended September 30, 2016, our financial results reflect a full three and nine months of operations of our assets compared to the three and nine months ended September 30, 2015, which includes only gathering revenues and four full months of operating one processing plant. Additionally, our future revenues will fluctuate based on the throughput volumes of natural gas and NGLs delivered by our customers in a given period.

General and Administrative Expenses

Our predecessor’s general and administrative expenses included charges for the management and operation of our business and certain expenses allocated for general corporate services, such as finance, accounting and legal services. These expenses were charged or allocated to our predecessor based on the nature of the expenses and our predecessor’s proportionate share of employee time and capital expenditures. Following the closing of the Offering, PennTex Midstream Partners, LLC (“PennTex Development”) charges us directly for the management and operation of our business. General and administrative expenses reflect additional costs and expenses incurred as a result of being a fully operational publicly traded partnership as described above, which are not reflected in our financial statements for periods prior to the Offering.

Financing

Prior to the completion of our Phase I assets in May 2015, our operations did not produce significant revenue, and all financing required for the construction of our assets was received from members’ capital contributions or from borrowings incurred under our predecessor’s $60 million revolving credit facility. In connection with the Offering, we repaid in full and terminated our predecessor’s $60 million revolving credit facility and our $275 million revolving credit facility became effective. The $275 million revolving credit facility is available for general partnership purposes, including working capital, capital expenditures and acquisitions.

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Results of Operations

The following provides a summary of our results of operations for the periods indicated:

	Three months ended September 30,					Nine months ended September 30,
	Three months ended March 31,
	2016		2015			2016		2015
	2017		2016
	(in thousands)
Revenue	$	2217,~~184~~071	$	1117,~~225~~649		$	~~58,986~~	$	~~14,150~~
Operating expenses:
Cost of revenues	32,~~770~~688		12,~~610~~192			~~9,258~~		~~1,610~~
General and administrative expense	41,~~615~~672		3,~~625~~935			~~12,627~~		~~8,559~~
Operating and maintenance expense	21,~~857~~484		12,~~903~~619			~~7,860~~		~~3,363~~
Depreciation and amortization expense	3,~~390~~435		13,~~608~~346			~~10,117~~		~~2,665~~
Impairment of surplus assets	—		—			—		2,483
Taxes other than income taxes	281		227
Taxes other than income taxes	147		(2		)	600		135
Total operating expenses	9,560		12,319
Total operating expenses	14,779		8,744			40,462		18,815
Operating income	$	7,511	$	5,330
Operating income (loss)	$	7,405	$	2,481		$	18,524	$	(4,665	)
Adjusted EBITDA (1)	$	20,466	$	15,100
Adjusted EBITDA (1)	$	18,772	$	6,224		$	49,405	$	3,785
Operating Data:
Operating Data:
Gathering (MDth/d)	265		308
Gathering (MDth/d)	334		182			315		77
Processing (MDth/d)	235		276
Processing (MDth/d)(2)	309		176			284		129
Transportation (MDth/d)	204		243
Transportation (MDth/d)(3)	266		160			248		116
NGL transportation (Bbls/d)	9,656		9,740
NGL transportation (Bbls/d)(4)	13		—			11		—

⁽¹⁾ For a discussion of the non-GAAP financial measure Adjusted EBITDA, including a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Non-GAAP Financial Measures” below.

~~(2)~~Three ~~The Lincoln Parish plant commenced operations on May 15, 2015; as a result, operating data for the nine~~ months ended ~~September~~March 3031, ~~2015~~2017 ~~includes~~compared ~~approximately~~to ~~139 days of operations. The Mt. Olive plant commenced operations on September 12, 2015; as a result, operating data for~~ the three ~~and nine~~ months ended ~~September~~March 3031, ~~2015~~2016 ~~includes approximately 19 days of operations.~~

~~(3)~~For ~~Our~~the ~~residue~~three ~~gas~~months ~~pipeline~~ended ~~commenced~~March ~~operations on May 15~~31, ~~2015;~~2017 asand ~~a result~~2016, ~~operating~~we ~~data~~recorded ~~for~~revenue ~~the~~of ~~nine~~$17.1 ~~months~~million ~~ended~~and ~~September~~$17.6 30million, ~~2015~~respectively, which includes ~~approximately~~$ ~~139~~1.1 ~~days~~million ofand ~~operations~~$1.9 ~~Additional~~million ~~residue~~for ~~gas~~electric ~~pipelines~~compression ~~commenced~~reimbursement, ~~operations~~respectively. onWe ~~September~~generated ~~12,~~this ~~2015;~~revenue asby aproviding ~~result~~gathering, ~~operating~~processing, ~~data for the three~~ and ~~nine~~transportation ~~months~~services ~~ended~~to ~~September 30, 2015 includes approximately 19 days of operations from these pipelines~~customers.

~~(4)~~Range ~~Our~~Resources’s ~~NGL~~cumulative ~~pipeline~~processing ~~commenced~~volumes ~~commercial~~through ~~operations~~the onthree ~~October~~months 1ended March 31, ~~2015;~~2017 asand 2016 were below the applicable minimum processing commitment under the processing agreement. As a result, nowe ~~operating~~recorded ~~data~~deficiency ispayment ~~included~~of ~~for~~$9.2 million and $3.1 million, respectively, attributable to undelivered volumes during such period. As of March 31, 2017 and 2016, non-current liabilities on our balance sheet reflects deferred revenues of $32.8 million and $4.1 million, respectively, which includes the ~~three~~deficiency payment and ~~nine~~processing ~~months~~fees ~~ended~~incurred ~~September~~by Range Resources in excess of the weighted average processing fee over the duration of the processing agreement. All of the amounts included in deferred revenue as of March 31, 2017 have been billed and collected as of April 30, ~~2015~~2017.

~~Three~~Deferred ~~months~~revenue ~~ended~~is ~~September~~recognized ~~30,~~as ~~2016~~revenue ~~compared~~once all contingencies or potential performance obligations associated with the related volumes have either been satisfied or expired. Range Resources may use deficiency payments paid under the processing agreement to offset future processing fees to the ~~three~~extent ~~months~~that ~~ended~~Range ~~September~~Resources 30delivers the total minimum processing volume under the processing agreement prior to October 1, ~~2015~~2030.

~~For~~As ~~the three months ended September 30, 2016, we recorded revenue~~ of ~~$22.2 million~~March 31, ~~which~~2017 ~~includes $2.9 million for electric compression reimbursement. We generated this revenue by providing gathering, processing~~ and ~~transportation services to customers. For the three months ended September 30~~2016, ~~2015,~~Range weResources’s ~~recorded~~cumulative ~~revenue~~processing ofvolumes ~~$11.2~~were ~~million.~~below ~~The increase in our revenue primarily reflects a full quarter of operations for two plants for~~ the ~~three~~applicable ~~months~~minimum ~~ended~~processing ~~September~~commitment ~~30,~~by ~~2016~~75,988 asMDth ~~compared to a full quarter of operations for one plant~~ and 197,153 ~~days of operations of a second plant for the three months ended September 30~~MDth, ~~2015~~respectively.

~~Range~~For ~~Resources’ cumulative processing volumes as of September 30, 2016 were below~~ the ~~applicable~~three ~~minimum~~months ~~processing~~ended ~~commitment~~March ~~under the processing agreement. As a result~~31, we2017 ~~recorded~~compared ~~a deficiency payment of $5.9 million attributable~~ to ~~undelivered volumes during~~ the three months ended ~~September~~March 3031, 2016., Asour oftotal ~~September 30,~~general ~~2016,~~and ~~non-current~~administrative ~~liabilities~~expenses onand ~~our~~operating ~~balance~~and ~~sheet~~maintenance ~~includes~~expenses ~~deferred~~decreased ~~revenues~~approximately of $142.3 million, ~~which includes the deficiency payment~~ and ~~processing~~$1.1 ~~fees~~million, ~~incurred~~respectively, byprimarily ~~Range~~due ~~Resources~~to inefficiencies ~~excess~~realized offollowing ~~the~~Energy ~~weighted~~Transfer’s ~~average~~acquisition ~~processing fee over the duration~~ of ~~the~~our ~~processing~~general ~~agreement determined in accordance with GAAP, and of which $6~~partner.~~2 million relates to the three months ended September 30, 2016.~~

21For the three months ended March 31, 2017 and 2016, our cost of revenues consists of approximately $2.3 million and $2.0 million of electric compression expense, respectively.

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AsOur ofAdjusted ~~September 30,~~EBITDA ~~2016,~~increased ~~Range~~by ~~Resources’~~$5.4 ~~cumulative~~million ~~processing~~and ~~volumes~~distributable ~~were~~cash ~~below~~flow ~~the~~increased ~~applicable~~by ~~minimum~~$5.9 ~~processing~~million ~~commitment~~during bythe ~~30,588~~three ~~MDth,~~months ofended ~~which~~March 1531,~~450~~ ~~MDth~~2017 ~~relate~~as compared to ~~undelivered processing volumes during~~ the three months ended ~~September~~March 3031, 2016. These increases are primarily due to an increase in deferred revenue of $5.4 million, which is due to a higher minimum volume commitment.

For the three months ended September 30, 2016, our total general and administrative expenses and operating and maintenance expenses increased by approximately $1.9 million compared to the three months ended September 30, 2015, which primarily reflects the operation of our full suite of assets. The increase in general and administrative expenses reflects additional expenses incurred as a result of being a publicly traded company and includes compensation expense of $1.2 million for phantom units grants for the three months ended September 30, 2016 compared to $0.8 million for the three months ended September 30, 2015. Operating and maintenance expenses for the three months ended September 30, 2016 includes compensation expense of $0.3 million for phantom units grants for the three months ended September 30, 2016 and $0.3 million for the three months ended September 30, 2015. For the three months ended September 30, 2016, our cost of revenues consists of approximately $3.0 million of electric compression expense.

We incurred depreciation and amortization expense of $3.4 million and $1.6 million during the three months ended September 30, 2016 and 2015, respectively. The increase in these expenses for the three months ended September 30, 2016 reflects operations through the entire period as compared to partial-period operations during three months ended September 30, 2015 following the completion of our assets in May and September 2015.

Nine months ended September 30, 2016 compared to the nine months ended September 30, 2015

For the nine months ended September 30, 2016, we recorded revenue of $59.0 million, which includes $7.2 million for electric compression reimbursement. We generated this revenue by providing gathering, processing, and transportation services to customers. For the nine months ended September 30, 2015, we recorded revenue of $14.2 million. The increase in our revenue primarily reflects three full quarters of operations for the nine months ended September 30, 2016, as compared to approximately four months of operations following the completion of our first plant in May 2015 and 19 days of operations for our second plant in September 2015 for the nine months ended September 30, 2015.

We recorded deficiency payments of $12.4 million attributable to undelivered volumes during the nine months ended September 30, 2016. As of September 30, 2016, non-current liabilities on our balance sheet includes deferred revenues of $14.3 million, all of which was recorded in the nine months ended September 30, 2016.

As of September 30, 2016, Range Resources’ cumulative processing volumes were below the applicable minimum processing commitment by 30,588 MDth, all of which relate to undelivered processing volumes during the nine months ended September 30, 2016.

For the nine months ended September 30, 2016 compared to the nine months ended September 30, 2015, our total general and administrative expenses and operating and maintenance expenses increased approximately $8.6 million, which primarily reflects the operation of our full suite of assets, including expanded operations following the completion of the Mt. Olive plant, the NGL pipeline and a 14-mile segment of the residue gas pipeline in September 2015. The increase in general and administrative expenses primarily reflects additional expenses incurred as a result of being a publicly traded company and includes compensation expenses of $3.1 million for phantom units grants for the nine months ended September 30, 2016 compared to $1.0 million for the nine months ended September 30, 2015. Operating and maintenance expenses for the nine months ended September 30, 2016 includes compensation expense of $0.9 million for phantom units grants compared to $0.3 million for the nine months ended September 30, 2015. For the nine months ended September 30, 2016, our cost of revenues consists of approximately $7.6 million of electric compression expense.

We incurred depreciation and amortization expense of $10.1 million and $2.7 million during the nine months ended September 30, 2016 and 2015, respectively. The increase in these expenses for the nine months ended September 30, 2016 reflects the operation of our assets following their completion in May and September 2015 as compared to only the initial portion of our gathering system being operational during most of the nine months ended September 30, 2015.

Liquidity and Capital Resources

Overview

Our ability to finance our operations, fund capital expenditures, pay cash distributions to unitholders and satisfy our indebtedness obligations depends on our ability to generate cash flow in the future. Our ability to generate cash flow is subject to a number of factors, some of which are beyond our control. Please read “Risk Factors” in Item 1A of the ~~2015~~2016 Form 10-K.

Our primary sources of liquidity following the Offering have been borrowings under our $275 million revolving credit facility and cash generated from our operations. We also expect that any future issuance of equity and debt securities will provide additional sources of liquidity.

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We expect to distribute all of our available cash to unitholders in accordance with the terms of our partnership agreement. We believe that cash on hand, cash generated from operations and availability under our revolving credit facility will be adequate to meet our operating needs, our planned short-term capital and debt service requirements and our planned cash distributions to unitholders. We believe that future internal growth projects or potential acquisitions will be funded primarily through borrowings under our revolving credit facility or through issuances of debt and equity securities.

Management believes that our anticipated cash flows from operations and available borrowings under our revolving credit facility will be sufficient to meet our liquidity needs for the next twelve months.

Revolving Credit Facility

Our $275 million senior secured revolving credit facility became effective upon completion of the Offering. The revolving credit facility contains an accordion feature that allows us to expand the facility up to $400 million in certain circumstances. The revolving credit facility contains various affirmative and negative covenants and restrictive provisions that limit our ability (as well as the ability of our subsidiaries) to, among other things:


•	incur or guarantee additional debt, including certain hedging obligations;


•	make certain investments and acquisitions;


•	incur certain liens or permit them to exist;


•	alter our lines of business;


•	enter into certain types of transactions with affiliates;


•	merge or consolidate with another company; and


•	transfer, sell or otherwise dispose of assets.

In addition, our revolving credit facility restricts our ability to make distributions on, or redeem or repurchase, our equity interests, except for distributions of available cash so long as, both at the time of the distribution and after giving effect to the distribution, no default exists under the revolving credit facility. Our revolving credit facility also requires us to maintain certain financial covenants. As of ~~September~~March 3031, ~~2016~~2017, we were in compliance with the covenants under our revolving credit facility.

Our revolving credit facility contains customary events of default for facilities of this nature, including:


•	events of default resulting from our failure or the failure of any guarantors to comply with covenants and financial ratios;


•	the occurrence of a change of control;


•	the institution of insolvency or similar proceedings against us or any guarantor; and


•	the occurrence of a default under any other material indebtedness we or any guarantor may have.

Upon the occurrence and during the continuation of an event of default, subject to the terms and conditions of our revolving credit facility, our lenders may declare any outstanding principal of our revolving credit facility debt, together with accrued and unpaid interest, to be immediately due and payable and exercise other remedies.

Since its effectiveness, we have used the revolving credit facility for capital expenditures required for the construction of our assets and to pay a portion of our distribution to unitholders for the second and third quarters of 2015. We expect to use the revolving credit facility to fund capital expenditures, acquisitions and certain of our working capital needs and for other general partnership purposes in the future. 16

As of September 30, 2016, we had $154.5 million drawn under our revolving credit facility and had $1.0 million of letters of credit outstanding, resulting in $119.5 million of additional available borrowing capacity.

Working Capital

Working capital is the amount by which our current assets exceed our current liabilities. As of September 30, 2016, our working capital increased to $12.0 million from $8.3 million as of December 31, 2015. Prior to completion of our assets in September 2015, our working capital requirements were primarily driven by the changes in accounts payable related to the construction of our assets and affiliated accounts payable related to services provided by our general partner and, following the commencement of operations in May 2015, changes in accounts payable and accounts receivable due to the timing of collections from our customers. Following the completion of our assets in September 2015, our working capital requirements have been primarily driven by changes in accounts payable along with changes in accounts receivable due to the timing of

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~~collections~~As ~~from~~of ~~our~~March 31, ~~customers~~2017, ~~and~~we ~~payments~~had ~~to suppliers~~$156.5 Amillion ~~material~~drawn ~~adverse change in operations or available financing~~ under our revolving credit facility ~~could~~and ~~impact~~had ~~our~~$1.0 ~~ability~~million toof ~~fund~~letters ~~our~~of ~~requirements~~credit ~~for~~outstanding, ~~liquidity~~resulting ~~and~~in ~~capital~~$117.5 ~~resources~~million of additional available borrowing capacity.

Working Capital

Working capital is the amount by which our current assets exceed our current liabilities. As of March 31, 2017, our working capital decreased to $18.2 million from $22.5 million as of December 31, 2016. Our working capital requirements were primarily driven by changes in accounts payable and accounts receivable due to the timing of collections from our customers. Our working capital requirements have been primarily driven by changes in accounts payable along with changes in accounts receivable due to the timing of collections from our customers and payments to suppliers. A material adverse change in operations or available financing under our revolving credit facility could impact our ability to fund our requirements for liquidity and capital resources.

Historical Cash Flow

All of the following discussions relate to the ~~nine~~three months ended ~~September~~March 3031, ~~2016~~2017. The following table and discussion presents a summary of our cash flow for the periods indicated:

	Nine months ended September 30,
	Three months ended March 31,
	2016			2015
	2017			2016
	(in thousand)
	(in thousands)
Net cash provided by (used in):
Operating activities	$	4119,~~593~~558		$	(811,~~780~~742	)
Investing activities	$	~~(12,110~~—	)	$	(~~212~~9,~~324~~431	)
Financing activities	$	(3623,~~191~~510	)	$	~~206~~(8,~~394~~184	)

Operating Activities.

Cash flows provided by operating activities were $4119.6 million for the ~~nine~~three months ended ~~September~~March 3031, ~~2016~~2017 compared to $811.87 million of cash flows used in operating activities for the ~~nine~~three months ended ~~September~~March 3031, ~~2015~~2016.

We had net income of $~~13.~~5.9 million for the ~~nine~~three months ended ~~September~~March 3031, ~~2016~~2017 compared to ~~a net loss of~~ $53.25 million for the ~~nine~~three months ended ~~September~~March 3031, ~~2015~~2016. Net income for the ~~nine~~three months ended ~~September~~March 3031, ~~2016~~2017 ~~reflects~~increased ~~nine~~over ~~months~~the ~~of operations from our assets. The~~ net ~~loss~~income for the three ~~nine~~ months ended ~~September~~March 3031, ~~2015~~2016 ~~was~~is primarily attributable to lower general and administrative expenses ~~allocated~~as towell usas ~~from~~lower ~~PennTex~~operating ~~Development,~~and ~~which~~maintenance ~~managed our predecessor’s activities, during the construction of our assets~~expenses. We generated net cash of $139.85 million for the ~~nine~~three months ended ~~September~~March 3031, ~~2016~~2017 due to the differences in our billing activities as compared to our revenue recognized, which was $5.4 million higher than the three months ended March 31, 2016 which is primarily attributable to the larger minimum volumes in the respective periods, per our processing agreements..

The components of working capital that had the most significant impact on operating cash flow during the current period were accounts receivable, accounts payable and other current ~~assets~~liabilities.

Investing Activities.

~~Cash~~There were no cash flows used infor investing ~~activities~~for ~~were~~the ~~$12.1~~three ~~million~~months ended March 31, 2017 and $~~212~~9.34 million for the ~~nine~~three months ended ~~September~~March 3031, 2016 ~~and 2015, respectively~~. During the ~~nine~~three months ended ~~September~~March 3031, 2016, cash flows used in investing activities were used to expand and improve the effectiveness and efficiency of our assets~~, as compared to cash flows used during the nine months ended September 30, 2015, which were used primarily for expansion capital expenditures in connection with the construction of our initial assets~~.

Financing Activities.

During the ~~nine~~three months ended ~~September~~March 3031, ~~2016~~2017, cash flows used in financing activities consist of ~~borrowings and~~ repayments under our revolving credit facility and distributions to unitholders. During the ~~nine~~three months ended ~~September~~March 3031, ~~2015~~2016, we ~~completed~~borrowed ~~the~~and ~~Offering~~made ~~and~~repayments ~~used~~under ~~the~~our ~~net~~revolving ~~proceeds~~credit offacility ~~$223.0~~and ~~million~~made distributions to ~~repay~~our inunitholders. ~~full~~Borrowings from our ~~predecessor’s~~ revolving credit facility, ~~make~~represent ~~cash~~our ~~distributions~~main tosource ~~the predecessor’s members and fund a portion~~ of ~~our~~funding ~~capital~~other ~~expenditures.~~than operations.

Borrowings from our revolving credit facility represent our main source of funding after the Offering. Prior to the Offering, our cash flows from financing activities consisted of member contributions and borrowings from our predecessor’s revolving credit facility. These amounts included both cash contributed to our predecessor and amounts PennTex Development expended on our behalf.

Distributions

Our minimum quarterly distribution is $0.2750 per unit, which corresponds to an aggregate distribution of $11.12 million per quarter and $44.28 million per year based on the common units and subordinated units outstanding as of ~~September~~March 3031, ~~2016~~2017. ~~The~~Following ~~following~~are ~~table~~distributions ~~shows~~declared ~~all~~and/or ofpaid ~~our~~by ~~distributions~~the Partnership subsequent to December 31, 2016:

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			Distributions					Distributionper LimitedPartner Unit
			CommonUnits	SubordinatedUnits	IncentiveDistributionRights
Three Months Ended	Date Paid/To Be Paid					Total
		(in thousands, except per unit amounts)
September 30, 2016(1)	November 14, 2016		$5,954	$5,900	$—	$	11,854	$	0.2950
March 31, 2017 (1)	May 12, 2017		$6,110	$5,900	$—	$	12,010	$	0.2950
June 30, 2016	August 12, 2016		$5,744	$5,692	$—	$	11,436	$	0.2846
December 31, 2016	February 14, 2017		$6,110	$5,900	$—	$	12,010	$	0.2950
March 31, 2016	May 13, 2016		$5,501	$5,500	$—	$	11,001	$	0.2750
December 31, 2015	February 12, 2016		$5,500	$5,500	$—	$	11,000	$	0.2750
September 30, 2015	November 13, 2015		$5,500	$5,500	$—	$	11,000	$	0.2750
June 30, 2015(2)	August 15, 2015		$1,330	$1,330	$—	$	2,660	$	0.0665

(1) On ~~October~~April 2526, ~~2016~~2017, the Partnership announced a distribution of $0.2950 per unit for the three months ended ~~September~~March 3031, ~~2016~~2017. The distribution will be paid on ~~November~~May 1412, ~~2016~~2017 to unitholders of record as of ~~November~~May 75, ~~2016~~2017.

(2) The distribution declared with respect to the quarter ended June 30, 2015 represented a prorated amount of our minimum quarterly distribution of $0.2750 per unit based on the number of days between the closing of the Offering on June 9, 2015 and June 30, 2015.

Capital Requirements

Our business is capital-intensive, requiring significant investment to maintain and improve existing assets. We categorize capital expenditures as either:

•maintenance capital expenditures, which include those expenditures made to maintain, over the long term, our operating capacity, throughput or revenue, including the replacement of system components and equipment that have become obsolete or have approached the end of their useful lives; or

•expansion capital expenditures, which include those expenditures incurred in order to construct or acquire new midstream infrastructure and to extend the useful lives of our assets, reduce costs, increase revenues or increase system throughput or capacity from current levels.

	Total		Less Than1 Year		1 to 3 Years		3 to 5 Years		More Than5 Years
	(in millions)
Revolving Credit Facility	$	154.5	$	—	$	—	$	154.5	$	—
Total	$	154.5	$	—	$	—	$	154.5	$	—

Non-GAAP Financial Measures

As described above in “—How We Evaluate our Operations—Adjusted EBITDA and Distributable Cash Flow,” we use Adjusted EBITDA and distributable cash flow to assess the ability of our assets to generate cash sufficient to pay interest costs, support indebtedness and make cash distributions. Additionally, Adjusted EBITDA is a financial measure reported to our lenders and used to determine compliance with certain of the financial covenants included in our revolving credit facility.

Adjusted EBITDA and distributable cash flow are non-GAAP financial measures. The GAAP liquidity measure most directly comparable to Adjusted EBITDA and distributable cash flow is net cash provided by operating activities. Adjusted EBITDA and distributable cash flow should not be considered as alternatives to the GAAP measures of net income (loss) or net cash provided by operating activities, as applicable. Adjusted EBITDA and distributable cash flow are not presentations made in accordance with GAAP and have important limitations as analytical tools because they include some, but not all, items that affect net income (loss) or net cash provided by operating activities, as applicable. You should not consider Adjusted EBITDA or distributable cash flow in isolation or as substitutes for analysis of results as reported under GAAP. Our definitions of Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies.

Adjusted EBITDA for the three and nine months ended September 30, 2015 includes the results of our predecessor’s operations for the period prior to the Offering on June 9, 2015. The following table reconcile Adjusted EBITDA to the most directly comparable GAAP financial and liquidity measures for the periods presented, and further reconciles Adjusted EBITDA 18

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Adjusted EBITDA for the three months ended March 31, 2016 includes the results of our predecessor’s operations for the period prior to the Offering on June 9, 2015. The following table reconcile Adjusted EBITDA to the most directly comparable GAAP financial and liquidity measures for the periods presented, and further reconciles Adjusted EBITDA for the three months ended March 31, 2017 and 2016 to distributable cash flow attributable to the Partnership:

	Three months ended September 30,						Nine months ended September 30,
	Three months ended March 31,
	2016			2015			2016		2015
	2017			2016
	(in thousands)
Reconciliation to Net Cash Provided by Operating Activities:
Net cash provided by operating activities	$	1419,~~949~~558		$	~~(345~~11,742	)	$	~~41,593~~	$	~~(8,780~~	)
Plus:
Cash interest expense related to operating activities	1,~~242~~280			~~302~~1,481			~~4,008~~		~~337~~
Changes in working capital	~~2,581~~(372		)	61,~~412~~877			~~3,804~~		~~12,556~~
Other	—			(145		)	—		(328		)
Adjusted EBITDA	20,466			15,100
Adjusted EBITDA	18,772			6,224			49,405		3,785
Less:
Less:
Cash interest expense related to operating activities	1,280			1,481
Predecessor Adjusted EBITDA	—			—			—		(3,494		)
Maintenance capital expenditures	—			158
Cash interest expense related to operating activities	1,242			302			4,008		337
Distribution equivalents paid in cash(1)	—			174
Maintenance capital expenditures	92			—			282		3
Distributable cash flow	$	19,186		$	13,287
Distribution equivalents paid in cash(1)	232			174			633		216
Distributable cash flow	$	17,206		$	5,748		$	44,482	$	6,723

⁽¹⁾ Represents distribution equivalent rights paid in cash in respect of the applicable period to the extent reflected as changes in equity.

The following table provides the calculation of Adjusted EBITDA as defined above:

	Three months ended September 30,						Nine months ended September 30,
		Three months ended March 31,
	2016			2015			2016		2015
		2017			2016
	~~(in thousands)~~	(in thousands)
Net income (loss)	$	5,828		$	2,020		$	13,514	$	(5,214	)
Net income		$	5,896		$	3,517
Add:
Interest expense, net	~~1,577~~	1,615		~~461~~	1,813		~~5,010~~		~~549~~
Depreciation and amortization expense	~~3,390~~	3,435		~~1,608~~	3,346		~~10,117~~		~~2,665~~
Changes to deferred revenue, net	~~5,790~~	9,520		~~(422~~	4,116	)	~~13,818~~		~~106~~
Equity-based compensation expense	~~1,574~~	—		~~1,057~~	1,151		~~3,935~~		~~1,288~~
Non-cash contribution for general and administrative expense	~~613~~	—		~~1,500~~	1,157		~~3,011~~		~~1,908~~
Non-cash impairment on long-term assets	—			—			—		2,483
Adjusted EBITDA		$	20,466		$	15,100
Adjusted EBITDA	$	18,772		$	6,224		$	49,405	$	3,785

Critical Accounting Policies and Estimates

Our significant accounting policies are described in Note 2 to the unaudited consolidated financial statements included elsewhere in this quarterly report. The preparation of our financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosure of contingent assets and liabilities. We disclosed certain critical accounting policies and estimates in our ~~2015~~2016 Form 10-K, and no significant changes have occurred since that time~~, except as discussed below~~.

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Revenue Recognition

We earn revenue from gathering, processing and transportation services we provide to natural gas producers. Revenue is recognized when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or service obligations have been fulfilled, (iii) the price is fixed or determinable and (iv) collectability is reasonably assured. For commercial agreements that contain specified minimum volume commitments and variable rates, we recognize revenue based on the volume weighted average rate over the term of the agreement.

Our processing agreement with Range Resources requires Range Resources to pay a fee based on the volume of gas actually processed, subject to cumulative minimum volume commitments determined with respect to each quarterly period. To the extent that, at the end of any quarterly period, Range Resources has not delivered the applicable cumulative minimum volume commitment, Range Resources is required to pay a deficiency fee on the undelivered volumes. The deficiency fee is characterized as unearned revenue. We invoice Range Resources based upon the applicable rates specified in the processing agreement corresponding to services provided. We recognize revenue based on a weighted average rate over the term of the agreement. The excess of the fees invoiced under the processing agreement compared to the fees recognized as revenue is characterized as unearned revenue. Unearned revenue is reported as deferred revenue and reflected in our balance sheet as other non-current liabilities. Deferred revenue is recognized as revenue once all contingencies or potential performance obligations associated with the related volumes have either been satisfied or expired.

Off-Balance Sheet Arrangements

As of ~~September~~March 3031, ~~2016~~2017, we did not have any off-balance sheet arrangements.

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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 risk. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.

Commodity Price Risk

All of our commercial contracts with Range Resources are 15-year, fee-based agreements, with no direct commodity price exposure to natural gas or NGLs. However, we are indirectly exposed through this customer’s economic decisions to develop and produce natural gas from which we receive revenues for providing gathering, processing and transportation services. Our contracts provide for minimum volume commitments, firm capacity reservation payments and plant tailgate dedications, which minimize our exposure to commodity price fluctuations. In addition, we take title to and resell NGLs that we process pursuant to processing agreements with other customers, which results in some direct commodity price exposure. However, because these are interruptible agreements, we are not obligated to process any specified volume of gas and we are not required to purchase any NGLs under the agreements. The revenues and costs of revenue from these interruptible agreements represent an insignificant amount of our total reported revenues and costs of revenue.

Interest Rate Risk

As described above, our $275 million revolving credit facility became effective upon completion of the Offering. As of ~~September~~March 3031, ~~2016~~2017, we had $~~154~~156.5 million of borrowings outstanding under the revolving credit facility. We currently do not hedge the interest on portions of our borrowings under the revolving credit facility, although we may do so from time-to-time in order to manage risks associated with floating interest rates. A 1% increase in the effective interest rate on our outstanding borrowings at ~~September~~March 3031, ~~2016~~2017 would result in an annual increase in our interest expense of approximately $1.56 million.

Credit Risk

We are exposed to credit risk. Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. For example, we are substantially dependent on Range Resources as our primary customer, and any event, whether in our area of operations or otherwise, that adversely affects Range Resources’ production, drilling and completion schedule, financial condition, leverage, market reputation, liquidity, results of operations or cash flows may adversely affect our revenues and cash available for distribution. Our contracts have provisions pursuant to which we have the right to request and receive from the customer adequate security support in the form of letters of credit, cash collateral, prepayments or guarantees.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this quarterly report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of ~~September~~March 3031, ~~2016~~2017 at the reasonable assurance level.

Changes in Internal Control Over Financial Reporting

~~There~~During ~~have~~the ~~been~~three nomonths ~~changes~~ended inMarch 31, 2017, our internal ~~control~~controls over financial reporting, ~~(as~~including ~~defined~~certain indisclosure ~~Rules~~controls ~~13a-15(f)~~ and ~~15d-15(f)~~corporate ~~under~~governance ~~the~~procedures, ~~Exchange~~have ~~Act)~~been ~~during~~impacted ~~the~~by ~~three~~changes ~~and~~made ~~nine~~to ~~months~~conform ~~ended~~to ~~September~~the 30existing controls of ETP, ~~2016~~the ~~that~~owner ~~have~~of ~~materially~~our ~~affected,~~general orpartner. None of these changes are ~~reasonably~~in ~~likely~~response to ~~materially~~any ~~affect,~~identified deficiency or weakness in our internal ~~control~~controls over financial reporting.

28There were no other changes that have materially affected, or are reasonably likely to affect, our internal controls over financial reporting.

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PART II OTHER INFORMATION

Item 1. Legal Proceedings

Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. However, we are not currently subject to any material litigation.

We maintain insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisers and brokers, believe are reasonable and prudent. We cannot, however, assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage or that these levels of insurance will be available in the future at economical prices.

Item 1A. Risk Factors

In addition to the other information set forth in this Quarterly Report on Form 10-Q, you should carefully consider the risk factors discussed under “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, ~~2015~~2016. There have been no material changes or updates to our risk factors previously disclosed in such annual report.

Item 5. Other Information

In August 2016, PennTex Development completed the previously announced sale of PennTex Permian, LLC (“Permian”) to a third party in accordance with the terms of the right of first offer previously delivered by PennTex Development to the board of directors of the General Partner with respect to such transactionNone. ~~As a result of such transaction, the Partnership no longer has a right of first offer on Permian.~~

Item 6. Exhibits

The exhibits required to be filed pursuant to the requirements of Item 601 of Regulation S-K are set forth in the Exhibit Index accompanying this Quarterly Report on Form 10-Q and are incorporated herein by reference.

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SIGNATURE

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

	PennTex Midstream Partners, LP
October 28, 2016	By:	PennTex Midstream GP, LLC, its general partner
May 4, 2017	By:	PennTex Midstream GP, LLC, its general partner
	By:	/s/ ~~Steven~~Thomas RE. ~~Jones~~Long
	Name:	~~Steven~~Thomas RE. ~~Jones~~Long
	Title:	~~Executive Vice President and~~ Chief Financial Officer
		(Principal Financial Officer)

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EXHIBIT INDEX



Exhibit Number		Description
3.1		Certificate of Limited Partnership of PennTex Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to PennTex Midstream Partners, LP’s registration statement on Form S-1, as amended (File No. 333-199020), initially filed with the Commission on September 30, 2014).

3.2		First Amended and Restated Agreement of Limited Partnership of PennTex Midstream Partners, LP, dated as of June 9, 2015 (incorporated by reference to Exhibit 3.1 to PennTex Midstream Partners, LP’s Current Report on Form 8-K filed with the Commission on June 9, 2015).

31.1*		Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.

31.2*		Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.

32.1**		Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.CAL*		XBRL Calculation Linkbase Document

101.DEF*		XBRL Definition Linkbase Document

101.INS*		XBRL Instance Document

101.LAB*		XBRL Labels Linkbase Document

101.PRE*		XBRL Presentation Linkbase Document

101.SCH*		XBRL Schema Document

* Filed as an exhibit to this Quarterly Report on Form 10-Q.

** Furnished as an exhibit to this Quarterly Report on Form 10-Q.

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