10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 __________________________________________________

FORM 10-Q

 __________________________________________________ 

(Mark One)

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

For the quarterly period ended June 30, 2018

OR

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

For the transition period from to

Commission file number: 001-36635

__________________________________________________

CNX MIDSTREAM PARTNERS LP

(Exact name of registrant as specified in its charter)

Delaware	47-1054194
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1000 CONSOL Energy Drive

Canonsburg, PA 15317-6506

(724) 485-4000

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)__________________________________________________

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, 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  x    Non-accelerated filer  o (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 August 2, 2018, CNX Midstream Partners LP had 63,638,165 common units outstanding.

TABLE OF CONTENTS
		Page
PART I FINANCIAL INFORMATION
ITEM 1.	Unaudited Consolidated Financial Statements
	Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2018 and 2017	3
	Consolidated Balance Sheets at June 30, 2018 and December 31, 2017	4
	Consolidated Statements of Partners’ Capital and Noncontrolling Interest for the Six Months Ended June 30, 2018	5
	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2018 and 2017	6
	Notes to Unaudited Consolidated Financial Statements	7
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	38
ITEM 4.	Controls and Procedures	38
PART II OTHER INFORMATION
ITEM 1.	Legal Proceedings	39
ITEM 1A.	Risk Factors	39
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39
ITEM 3.	Defaults upon Senior Securities	39
ITEM 4.	Mine Safety Disclosures	39
ITEM 5.	Other Information	39
ITEM 6.	Exhibits	40

PART I: FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

CNX MIDSTREAM PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(unaudited)

	Three Months Ended   June 30,					Six Months Ended   June 30,
	2018			2017		2018		2017
Revenue
Gathering revenue — related party	$	37,576		$	55,667	$	75,306	$	114,625
Gathering revenue — third party	23,438			867		49,577		867
Total Revenue	61,014			56,534		124,883		115,492
Expenses
Operating expense — related party	5,079			7,089		9,514		14,717
Operating expense — third party	7,406			5,957		15,874		12,590
General and administrative expense — related party	3,620			2,663		7,232		5,546
General and administrative expense — third party	2,319			1,033		4,868		2,225
(Gain) loss on asset sales	(254		)	3,241		2,501		3,914
Depreciation expense	5,443			5,675		11,299		11,346
Interest expense	7,119			1,124		9,608		2,162
Total Expense	30,732			26,782		60,896		52,500
Net Income	30,282			29,752		63,987		62,992
Less: Net income attributable to noncontrolling interest	277			761		6,135		3,934
Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP	$	30,005		$	28,991	$	57,852	$	59,058
Calculation of Limited Partner Interest in Net Income:
Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP	$	30,005		$	28,991	$	57,852	$	59,058
Less: General partner interest in net income, including incentive distribution rights	2,903			1,305		5,055		2,434
Limited partner interest in net income	$	27,102		$	27,686	$	52,797	$	56,624
Net income per limited partner unit - basic	$	0.43		$	0.44	$	0.83	$	0.89
Net income per limited partner unit - diluted	$	0.43		$	0.44	$	0.83	$	0.89
Limited partner units outstanding - basic	63,638			63,585		63,630		63,575
Limited partner unit outstanding - diluted	63,677			63,644		63,670		63,630
Cash distributions declared per unit (*)	$	0.3361		$	0.2922	$	0.6606	$	0.5743

(*) Represents the cash distributions declared during the month following the end of each respective quarterly period. See Note 15.

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

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CNX MIDSTREAM PARTNERS LP

CONSOLIDATED BALANCE SHEETS

(in thousands, except number of units)

(unaudited)

	June 30, 2018		December 31, 2017
ASSETS
Current Assets:
Cash	$	707	$	3,194
Receivables — related party (Note 6)	12,072		13,104
Receivables — third party (Note 6)	7,546		8,251
Other current assets	2,726		2,169
Total Current Assets	23,051		26,718
Property and Equipment (Note 7):
Property and equipment	864,611		972,841
Less — accumulated depreciation	72,098		73,563
Property and Equipment — Net	792,513		899,278
Other assets (Note 8)	3,494		593
TOTAL ASSETS	$	819,058	$	926,589
LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable and other accrued liabilities	$	38,327	$	23,602
Accounts payable — related party (Note 9)	3,211		2,376
Total Current Liabilities	41,538		25,978
Other Liabilities:
Revolving credit facility (Note 10)	11,000		149,500
Long-term debt (Note 11)	393,169		—
Total Liabilities	445,707		175,478
Partners’ Capital:
Common units (63,638,165 units issued and outstanding at June 30, 2018 and 63,588,152 units issued and outstanding at December 31, 2017)	295,405		389,427
General partner interest	8,893		4,328
Partners’ capital attributable to CNX Midstream Partners LP	304,298		393,755
Noncontrolling interest	69,053		357,356
Total Partners’ Capital	373,351		751,111
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	819,058	$	926,589

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

4

CNX MIDSTREAM PARTNERS LP

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST

(in thousands)

(unaudited)

	Partners’ Capital						Total
							Capital
	Limited			General			Attributable			Noncontrolling
	Partners			Partner			to Partners			Interest			Total
Balance at December 31, 2017	$	389,427		$	4,328		$	393,755		$	357,356		$	751,111
Net income	52,797			5,055			57,852			6,135			63,987
(Distributions to) contributions from general partner and noncontrolling interest holders, net	—			20			20			(3,525		)	(3,505		)
Quarterly distributions to unitholders	(40,574		)	(3,615		)	(44,189		)	—			(44,189		)
Acquisition of Shirley-Penns System	(153,587		)	—			(153,587		)	(111,413		)	(265,000		)
HG Energy Transaction	46,420			—			46,420			(179,500		)	(133,080		)
Noncash contribution of assets held by general partner	—			3,105			3,105			—			3,105
Unit-based compensation	1,269			—			1,269			—			1,269
Vested units withheld for unitholder taxes	(347		)	—			(347		)	—			(347		)
Balance at June 30, 2018	$	295,405		$	8,893		$	304,298		$	69,053		$	373,351

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

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CNX MIDSTREAM PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)

	Six Months Ended   June 30,
	2018			2017
Cash Flows from Operating Activities:
Net income	$	63,987		$	62,992
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation expense and amortization of debt issuance costs	11,872			11,430
Unit-based compensation	1,269			650
Loss on long-term asset sales	2,501			3,914
Other	387			167
Changes in assets and liabilities:
Receivables — related party	1,032			4,009
Receivables — third party	705			(867		)
Other current and non-current assets	108			3,574
Accounts payable and other accrued liabilities	12,824			(3,645		)
Accounts payable — related party	856			(5,790		)
Net Cash Provided by Operating Activities	95,541			76,434
Cash Flows from Investing Activities:
Capital expenditures	(41,587		)	(23,415		)
Proceeds from sale of assets	6,462			14,000
Net Cash Used in Investing Activities	(35,125		)	(9,415		)
Cash Flows from Financing Activities:
Distributions to general partner and noncontrolling interest holders, net	(3,505		)	(25,317		)
Vested units withheld for unitholder taxes	(347		)	(411		)
Quarterly distributions to unitholders	(44,189		)	(36,846		)
Net payments on unsecured $250.0 million credit facility	(149,500		)	(6,000		)
Net borrowings on secured $600.0 million credit facility	11,000			—
Proceeds from issuance of long-term debt, net of discount	394,000			—
Debt issuance costs	(5,362		)	—
Acquisition of Shirley-Penns System	(265,000		)	—
Net Cash Used in Financing Activities	(62,903		)	(68,574		)
Net Decrease in Cash	(2,487		)	(1,555		)
Cash at Beginning of Period	3,194			6,421
Cash at End of Period	$	707		$	4,866
Cash paid during the period for:
Interest	$	1,367		$	2,171

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

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CNX MIDSTREAM PARTNERS LP

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 — DESCRIPTION OF BUSINESS

CNX Midstream Partners LP (the “Partnership”, or “we”, “us”, or “our”) is a growth-oriented master limited partnership focused on the ownership, operation, development and acquisition of natural gas gathering and other midstream energy assets to service our customers’ production in the Marcellus Shale and Utica Shale in Pennsylvania and West Virginia. The Partnership’s assets include natural gas gathering pipelines and compression and dehydration facilities, as well as condensate gathering, collection, separation and stabilization facilities. The Partnership is managed by its general partner, CNX Midstream GP LLC (the “general partner”), a wholly owned subsidiary of CNX Gathering LLC (“CNX Gathering”). As a result of the January 3, 2018 transaction discussed below, CNX Gathering is a wholly owned subsidiary of CNX Resources Corporation (NYSE: CNX) (“CNX”). The Partnership was formed in May 2014 as a joint venture between CNX and Noble Energy, Inc (“Noble Energy”).

On January 3, 2018, CNX Gas Company LLC (“CNX Gas”), a Virginia limited liability company, acquired Noble Energy’s 50% membership interest in CNX Gathering for cash consideration of $305.0 million and the mutual release of all outstanding claims between the parties (the “General Partner Transaction”). As a result of the General Partner Transaction, CNX owns 100% of the membership interest in CNX Gathering and is the sole sponsor of the Partnership. Accordingly, we may refer to CNX as the “Sponsor” throughout this Quarterly Report on Form 10-Q.

Following the General Partner Transaction, Noble Energy owned 21,692,198 common units representing limited partner interests in the Partnership (the “Retained Units”). However, in connection with Noble Energy’s announcement of its intention to divest of the Retained Units over the next few years, Noble Energy executed an underwritten public offering of 7,475,000 of its Retained Units on June 29, 2018. The Partnership did not receive any proceeds as a result of the June 29, 2018 sale of Retained Units. At June 30, 2018, Noble Energy continues to own 14,217,198 common units. See Note 5–Related Party Transactions for additional information.

Description of Business

Prior to May 3, 2018, our midstream operations consisted of three operating segments that we refer to as our “Anchor Systems,” “Growth Systems” and “Additional Systems” based on their relative current cash flows, growth profiles, capital expenditure requirements and the timing of their development.

• Our Anchor Systems, in which the Partnership owns a 100% controlling interest, include our most developed midstream systems that generate the largest portion of our current cash flows, which includes our four primary midstream systems (the McQuay System, the Majorsville System, the Mamont System and the Shirley-Penns System) and related assets.

• Our Growth Systems were primarily located in the dry gas regions of our dedicated acreage in central West Virginia that were generally in earlier phases of development than our other systems and required substantial future expansion capital expenditures to materially increase production. As a result of the HG Energy Transaction described below, the Partnership distributed its ownership interests in the Growth Systems assets to CNX Gathering, which subsequently transferred these assets to HG Energy.

• Our Additional Systems currently include several gathering systems primarily located in the wet gas regions of our dedicated acreage (current activity is primarily located within the Pittsburgh Airport area) that we expect will require lower levels of expansion capital investment relative to our Growth Systems. The substantial majority of capital investment on these systems would be funded by CNX in proportion to CNX Gathering’s 95% retained ownership interest. As a result of the HG Energy Transaction described below, the Partnership distributed its ownership interests in the Moundsville area assets to CNX Gathering, which subsequently transferred these assets to HG Energy.

In order to maintain operational flexibility, our operations are conducted through, and our operating assets are owned by, our operating subsidiaries. However, neither we nor our operating subsidiaries have any employees. Our general partner has the sole responsibility for providing the personnel necessary to conduct our operations, whether through directly hiring employees or by obtaining the services of others, which may include personnel of CNX as provided through contractual relationships with the Partnership. All of the personnel that conduct our business are employed or contracted by our general partner and its affiliates, including our Sponsor, but we sometimes refer to these individuals as our employees because they provide services directly to us. See Note 5–Related Party Transactions for additional information.

Transactions with our Sponsor and HG Energy

On May 3, 2018, we announced the consummation of a strategic transaction and amended our gas gathering agreement (“GGA”) with our Sponsor that provides for the following (collectively, the “CNX Transactions”):

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• Dedication to the Partnership of approximately 16,100 additional Utica acres in our Anchor Systems;

• Commitment to develop 40 additional wells in the Anchor Systems by 2023, subject to the terms of the GGA;

• Contribution to the Anchor Systems of a 20” high pressure pipeline in addition to a one-time payment to us of approximately $2.0 million in cash; and

• Distribution of our 5% interest in the Growth Systems and related assets as well as our 5% interest in the Moundsville midstream assets, which were a part of the Additional Systems, to CNX Gathering, which subsequently transferred these assets to HG Energy.

On May 3, 2018, we also announced a strategic transaction with HG Energy II Appalachia, LLC (“HG Energy”), pursuant to which we agreed to amend our GGA with HG Energy to provide for the following (collectively, the “HG Energy Transaction”):

• Release from dedication of approximately 18,000 acres, net to the Partnership, which was comprised of approximately 275,000 acres (or approximately 14,000 acres, net to the Partnership) within the Growth and Additional Systems and approximately 4,200 scattered acres located in the Anchor Systems;

• Removal of our obligation to provide gathering services or make capital investments in the Growth Systems or in the Moundsville area of the Additional Systems; and

• Commitment by HG Energy to develop 12 additional wells in the Anchor Systems by 2021, subject to the terms of the HG Energy GGA.

Following the CNX and HG Energy Transactions, the aggregate number of well commitments in the Anchor Systems to the Partnership by CNX and HG Energy, collectively, increased from 140 wells over the course of the next five years to 192 wells. The non-cash distribution of our interests in these assets to CNX Gathering resulted in a reduction to property and equipment, net of $133.1 million, a reduction in noncontrolling interests of $179.5 million and an increase to partners’ capital of $46.4 million. At June 30, 2018, the Partnership has no remaining interests in the Growth Systems or the Moundsville area assets that were historically included within the Additional Systems.

Acquisition of Shirley-Penns System

At December 31, 2017, CNX Gathering owned a 95% noncontrolling interest, while the Partnership owned the remaining 5% controlling interest, in the Additional Systems, which owned the gathering system and related assets commonly referred to as the Shirley-Penns System (the “Shirley-Penns System”),

On March 16, 2018, the Partnership acquired the remaining 95% interest in the Shirley-Penns System, pursuant to which the Additional Systems transferred its interest in the Shirley-Penns System on a pro rata basis to CNX Gathering and the Partnership in accordance with each transferee’s respective ownership interest in the Additional Systems. Following such transfer, CNX Gathering sold its aggregate interest in the Shirley-Penns System, which now resides in the Anchor Systems, in exchange for cash consideration in the amount of $265.0 million (the “Shirley-Penns Acquisition”). The Partnership funded the Shirley-Penns Acquisition with a portion of the proceeds from the issuance of 6.5% senior notes due 2026 (the “Senior Notes”). See Note 11–Long-Term Debt for additional information.

At June 30, 2018, the Partnership owns a 100% controlling interest in the Shirley-Penns System. The Additional Systems continue to hold gathering systems in which the Partnership owns a 5% controlling interest.

Noble Energy Sale of Upstream Assets

On June 28, 2017, Noble Energy sold its upstream assets in northern West Virginia and southern Pennsylvania to HG Energy, effectively making HG Energy the new shipper on the dedicated acreage that was previously owned by Noble Energy (the “Noble Energy Asset Sale”). The Partnership currently gathers the natural gas and condensate volumes produced by HG Energy on our dedicated acreage under the terms of our GGA with Noble Energy, which was assigned to HG Energy upon consummation of the Noble Energy Asset Sale. In connection with the aforementioned HG Energy Transaction, the GGA was amended and certain acreage was released from dedication to the Partnership.

NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Use of Estimates

The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and various disclosures. Actual results could differ from those estimates, which are evaluated on an ongoing basis, utilizing historical experience and other methods considered reasonable under the particular circumstances. Although these estimates are based on management’s best available knowledge at the time, changes in facts and circumstances or discovery of new facts or circumstances may result in revised estimates and actual results may differ from these estimates. Effects on the Partnership’s business, financial position and results of operations resulting from revisions to estimates are recognized when the

8

facts that give rise to the revision become known. In the opinion of management, all adjustments considered necessary for a fair presentation of the accompanying consolidated financial statements have been included.

The balance sheet at December 31, 2017 has been derived from the audited financial statements at that date but does not include all of the information and footnotes required by GAAP for complete financial statements.

Principles of Consolidation

During the periods presented in this Quarterly Report on Form 10-Q, the consolidated financial statements include the accounts of the Partnership and all of its controlled subsidiaries, including 100% of each of the Anchor Systems, Growth Systems and Additional Systems. Although the Partnership has less than a 100% economic interest in the Growth and Additional Systems, each was consolidated fully with the results of the Partnership. However, after adjusting for noncontrolling interests, net income attributable to general and limited partner ownership interests in the Partnership reflects only that portion of net income that is attributable to the Partnership’s unitholders. The Partnership distributed its interests in the Growth Systems and the Moundsville area of the Additional Systems in connection with the HG Energy Transaction.

Transactions between the Partnership and CNX have been identified in the consolidated financial statements as transactions between related parties and are disclosed in Note 5–Related Party Transactions.

Jumpstart Our Business Startups Act (“JOBS Act”)

Under the JOBS Act, for as long as the Partnership remains an “emerging growth company” as defined in the JOBS Act, we may take advantage of certain exemptions from the Securities and Exchange Commission’s (“SEC”) reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being required to provide an auditor’s attestation report on management’s assessment of the effectiveness of its system of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in our periodic reports, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and seeking unitholder approval of any golden parachute payments not previously approved.

We may take advantage of the aforementioned reporting exemptions until September 30, 2019 or until we lose our status as an emerging growth company, which would happen if any of the following were to occur:

• we have more than $1.0 billion of revenues in the year ending December 31, 2018;

• the limited partner interests held by non-affiliates have a market value of more than $700 million as of June 30, 2018, which determination shall be made as of December 31, 2018; or

• we issue more than $1.0 billion of non-convertible debt over a three-year period.

Based on the above criteria, we will not be an emerging growth company for the year ending December 31, 2018, as the market value of limited partner interests held by non-affiliates was in excess of $700 million at June 30, 2018. Accordingly, among other things, we will be required to provide an auditor’s attestation report on management’s assessment of the effectiveness of its system of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act in our year ending December 31, 2018 Annual Report on Form 10-K.

Revenue Recognition

On January 1, 2018, the Partnership adopted Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers and all the related amendments (“new revenue standard”) using the modified retrospective method. We did not have a transition adjustment as a result of the adoption of the new revenue standard.

Revenues from contracts with customers

We record revenue when obligations under the terms of the contracts with our shippers are satisfied; generally this occurs on a daily basis as we gather gas at the wellhead. Revenue is measured as the amount of consideration we expect to receive in exchange for providing the natural gas gathering services.

Nature of performance obligations

At contract inception, we assess the services promised in our contracts with customers and identify a performance obligation for each promised service that is distinct. To identify the performance obligations, we consider all of the services promised in the contract, regardless of whether they are explicitly stated or are implied by customary business practices.

Our revenue is generated from natural gas gathering activities. The gas gathering services are interruptible in nature and include charges for the volume of gas actually gathered and do not guarantee access to the system. Volumetric-based fees relate to actual volumes gathered. In general, the interruptible gathering of each unit (MMBtu) of natural gas represents a separate

9

performance obligation. Payment terms for these contracts require payment within 25 days of the end of the calendar month in which the hydrocarbons are gathered.

Transaction price allocated to remaining performance obligations

The new revenue standard requires that we disclose the aggregate amount of transaction price that is allocated to performance obligations that have not yet been satisfied. However, the guidance provides certain practical expedients that limit this requirement.

Substantially all of our revenues are derived from contracts with CNX and HG Energy with terms of greater than one year. Under these contracts, the interruptible gathering of each unit of natural gas represents a separate performance obligation.

For revenue associated with the Shirley-Penns System, our only contract with terms that are greater than one year, the aggregate amount of the transaction price allocated to remaining performance obligations was $422.9 million at June 30, 2018. We expect to recognize revenue of $14.2 million and $28.8 million, respectively during the remainder of the years ending December 31, 2018 and December 31, 2019. The amount of revenue associated with this contract up to the minimum volume commitment (“MVC”) is fixed in nature, and volumes that we may gather above the MVC will be variable in nature. As of June 30, 2018, no future performance obligations exist relative to volumes to be gathered in excess of the MVC as the related volumes have not yet been nominated for gathering. Therefore, we have not disclosed the value of unsatisfied performance obligations for the variable aspect of this agreement, nor have we disclosed the value of other unsatisfied performance obligations that are variable in nature.

Prior-period performance obligations

We record revenue when obligations under the terms of the contracts with our shippers are satisfied; generally this occurs on a daily basis when we gather gas at the wellhead. In some cases, we are required to estimate the amount of natural gas that we have gathered during an accounting period and record any differences between our estimates and the actual units of natural gas that we gathered in the following month. We have existing internal controls for our revenue estimation process and related accruals; historically, any identified differences between our revenue estimates and actual revenue received have not been significant. For the quarters and six months ended June 30, 2018 and 2017, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

Disaggregation of revenue

See Note 13–Segment Information for additional information.

Contract balances

We invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our contracts with customers do not give rise to contract assets or liabilities under the new revenue standard. We also have no contract assets recognized from the costs.

See Note 6–Receivables for additional information.

Classification

The fees we charge our Sponsor and the fees we charged Noble Energy, prior to consummation of the Noble Energy Asset Sale, are recorded in gathering revenue — related party in our consolidated statements of operations. Following consummation of the Noble Energy Asset Sale, fees from midstream services we perform for HG Energy, and any other third party shipper, are recorded in gathering revenue — third party in our consolidated statements of operations.

Cash

Cash includes cash on hand and on deposit at banking institutions.

Receivables

Receivables are recorded at the invoiced amount and do not bear interest. When applicable, we reserve for specific accounts receivable when it is probable that all or a part of an outstanding balance will not be collected. Collectability is determined based on terms of sale, credit status of customers and various other circumstances. We regularly review collectability and establish or adjust the allowance as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.

There were no reserves for uncollectable amounts at June 30, 2018 or December 31, 2017.

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Fair Value Measurement

The Financial Accounting Standards Board (the “FASB”) Accounting Standards Codification (“ASC”) Topic 820, Fair Value Measurements and Disclosures, clarifies the definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., the initial recognition of asset retirement obligations and impairments of long‑lived assets). The fair value is the price that we estimate we would receive upon selling an asset or that we would pay to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize input to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1, that are observable for the asset or liability, either directly or indirectly.

The carrying values of our current assets and current liabilities approximate fair values due to their short maturities. The carrying value of our revolving credit facility approximates fair value as the facility bears interest at a variable, market rate that resets periodically.

We estimate the fair value of our long-term debt, which is not actively traded, using a standard industry income approach model that utilizes a discount rate based on market rates for other debt with similar remaining time to maturity and credit risk (Level 2). The estimated fair value of our long-term debt was approximately $388.0 million at June 30, 2018.

Property and Equipment

Property and equipment is recorded at cost upon acquisition and is depreciated on a straight-line basis over the assets’ estimated useful lives or over their lease terms. Expenditures which extend the useful lives of existing property and equipment are capitalized. When properties are retired or otherwise disposed, the related cost and accumulated depreciation are removed from the respective accounts and any profit or loss on disposition is recognized as a gain or loss.

We routinely assess whether impairment indicators arise during any given quarter and have processes in place to ensure that we become aware of such indicators. Impairment indicators include, but are not limited to, sustained decreases in commodity prices, a decline in customer well results and lower throughput forecasts, and increases in construction or operating costs. For such long-lived assets, impairment exists when the carrying amount of an asset or group of assets exceeds our estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset or group of assets. If the carrying amount of the long-lived asset(s) is not recoverable, based on the estimated future undiscounted cash flows, the impairment loss would be measured as the excess of the asset’s carrying amount over its estimated fair value. In the event that impairment indicators exist, we conduct an impairment test.

Fair value represents the estimated price between market participants to sell an asset in the principal or most advantageous market for the asset, based on assumptions a market participant would make. When warranted, management assesses the fair value of long-lived assets using commonly accepted techniques and may use more than one source in making such assessments. Sources used to determine fair value include, but are not limited to, recent third-party comparable sales, internally developed discounted cash flow analyses and analyses from outside advisors. Significant changes, such as the condition of an asset or management’s intent to utilize the asset, generally require management to reassess the cash flows related to long-lived assets. No property and equipment impairments were identified during the periods presented in the accompanying consolidated financial statements.

Environmental Matters

We are subject to various federal, state and local laws and regulations relating to the protection of the environment. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. At this time, we are unable to assess the timing and/or effect of potential liabilities related to greenhouse gas emissions or other environmental issues. As of June 30, 2018 and December 31, 2017, we had no material environmental matters that required the recognition of a separate liability or specific disclosure.

Asset Retirement Obligations

Our gathering pipelines and compressor stations have an indeterminate life. If properly maintained, they will operate for an indeterminate period as long as supply and demand for natural gas exists, which we expect for the foreseeable future. We are

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under no legal or contractual obligation to restore or dismantle our gathering system upon abandonment. Therefore, we have not recorded any liabilities for asset retirement obligations at June 30, 2018 or December 31, 2017.

Variable Interest Entities

Each of the Anchor, Growth and Additional Systems is a limited partnership (the “Limited Partnerships”) and a variable interest entity (“VIE”). These VIEs correspond with the manner in which we report our segment information in Note 13–Segment Information, which also includes information regarding the Partnership’s involvement with each of these VIEs and their relative contributions to our financial position, operating results and cash flows.

The Partnership fully consolidates each of the Limited Partnerships through its ownership of CNX Midstream Operating Company LLC (the “Operating Company”). The Operating Company, through its general partner ownership interest in each of the Limited Partnerships, is considered to be the primary beneficiary for accounting purposes and has the power to direct all substantive strategic and day-to-day operational decisions of the Limited Partnerships.

Equity Compensation

Equity compensation expense for all unit-based compensation awards is based on the grant date fair value estimated in accordance with the provisions of the Stock Compensation Topic of the FASB ASC. We recognize unit-based compensation costs on a straight-line basis over the requisite service period of an award, which is generally the same as the award’s vesting term. See Note 14–Long-Term Incentive Plan for additional information.

Income Taxes

We are treated as a partnership for federal and state income tax purposes, with each partner being separately taxed on its share of the Partnership’s taxable income. Accordingly, no provision for federal or state income taxes has been recorded in the Partnership’s consolidated financial statements for any period presented in the accompanying consolidated financial statements.

Reclassifications

Certain amounts in prior periods have been reclassified to conform to the current reporting classifications with no effect on previously reported net income or partners’ capital.

Recent Accounting Pronouncements

In February 2016, the FASB issued ASU 2016-02–Leases (Topic 842), which is intended to improve financial reporting about leasing transactions. The ASU will require organizations (“lessees”) that lease assets with terms of more than 12 months to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. Organizations that own the assets leased by lessees (“lessors”) will remain largely unchanged from current GAAP. In addition, the ASU will require disclosures to help investors and other financial statement users better understand the amount, timing and uncertainty of cash flows arising from leases. The effective date of this ASU is for fiscal years beginning after December 31, 2018 and interim periods within that year. We are currently finalizing a project plan, reviewing all existing leases and agreements that are covered under the standard, assessing the impact to our financial statements as well as planning for adoption and implementation of this standard, which includes assessing the impact on information systems and internal controls.

NOTE 3 — CASH DISTRIBUTIONS

Our partnership agreement requires that we distribute all of our available cash from operating surplus within 45 days after the end of each quarter to unitholders of record on the applicable record date, in accordance with the terms below.

Allocations of Available Cash from Operating Surplus and Incentive Distribution Rights

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner, as holder of our Incentive Distribution Rights (“IDRs”), and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit Target Amount.” IDRs represent the right to receive an increasing percentage, up to a maximum of 48% (which does not include the 2% general partner interest), of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels described in the table below have been achieved. All of the IDRs are currently held by our general partner, as defined in Note 1–Description of Business. Our general partner may transfer the IDRs separately from its general partner interest.

The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2% general partner interest and assume that our general partner has

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contributed any additional capital necessary to maintain its 2% general partner interest, our general partner has not transferred its IDRs and that there are no arrearages on common units.

			Marginal Percentage Interest in Distributions
Distribution Targets	Total Quarterly Distribution Per Unit Target Amount		Unitholders	General Partner (including IDRs)
Minimum Quarterly Distribution		$0.2125	98%	2%
First Target Distribution	Above $0.2125	up to $0.24438	98%	2%
Second Target Distribution	Above $0.24438	up to $0.26563	85%	15%
Third Target Distribution	Above $0.26563	up to $0.31875	75%	25%
Thereafter	Above $0.31875		50%	50%

Beginning with the distribution that was approved by the Board of Directors of the Partnership’s general partner (the “Board of Directors”) for the earnings period ended March 31, 2018, our quarterly distributions have been in excess of the maximum Third Target Distribution, or $0.31875.

Cash Distributions

The Board of Directors declared the following cash distributions to the Partnership’s common and subordinated unitholders (through September 30, 2017) and to the general partner for the periods presented:

(in thousands, except per unit information)
Quarters Ended	Total Quarterly Distribution Per Unit		Total Quarterly Cash Distribution		Date of Distribution
Year ended December 31, 2017
March 31	$	0.2821	$	18,842	May 15, 2017
June 30	0.2922		19,698		August 14, 2017
September 30	0.3025		20,573		November 14, 2017
December 31	0.3133		21,489		February 14, 2018
Year ending December 31, 2018
March 31	$	0.3245	$	22,700	May 15, 2018

See Note 4–Net Income per Limited Partner Unit and General Partner Interest for information regarding the conversion of subordinated units to common units on November 14, 2017. See Note 15–Subsequent Events for information regarding the distribution that was approved by the Board of Directors with respect to the quarter ended June 30, 2018.

NOTE 4 — NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST

We allocate net income between our general partner and limited partners using the two-class method, under which we allocate net income to our limited partners, our general partner and the holders of our IDRs in accordance with the terms of our partnership agreement. We also allocate any earnings in excess of distributions to our limited partners, our general partner and the holders of the IDRs in accordance with the terms of our partnership agreement. We allocate any distributions in excess of earnings for the period to our general partner and our limited partners based on their respective proportionate ownership interests in us, after taking into account distributions to be paid with respect to the IDRs, as set forth in our partnership agreement.

Conversion of subordinated units

From its inception through September 30, 2017, the Partnership paid equal distributions on common, subordinated and general partner units, excluding payments on the IDRs, which are paid in accordance with the table above. Upon payment of the cash distribution with respect to the quarter ended September 30, 2017, the financial requirements for the conversion of all subordinated units were satisfied. As a result, on November 15, 2017, all 29,163,121 subordinated units, which were owned

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entirely by CNX and Noble Energy, converted into common units on a one-for-one basis. The conversion did not impact the amount of the cash distribution paid or the total number of the Partnership’s outstanding units representing limited partner interests.

Historical earnings per unit

The Partnership calculates historical earnings per unit under the two-class method and allocates the earnings or losses of a transferred business before the date of a dropdown transaction entirely to the general partner. If applicable, the previously reported earnings per unit of the limited partners would not change as a result of a dropdown transaction.

Diluted net income per limited partner unit reflects the potential dilution that could occur if securities or agreements to issue common units, such as awards under the long-term incentive plan, were exercised, settled or converted into common units.  When it is determined that potential common units resulting from an award subject to performance or market conditions should be included in the diluted net income per limited partner unit calculation, the impact is calculated by applying the treasury stock method. There were 26,470 and 27,545 phantom units that were not included in the calculation for the three and six months ended June 30, 2018, respectively, because the effect would have been antidilutive. There were also 50,905 phantom units that were not included in the calculation for the three and six months ended June 30, 2017 because the effect would have been antidilutive. The following table illustrates the Partnership’s calculation of net income per unit for common and subordinated partner units:

	Three Months Ended June 30,				Six Months Ended   June 30,
(in thousands, except per unit information)	2018		2017		2018		2017
Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP	$	30,005	$	28,991	$	57,852	$	59,058
Less: General partner interest in net income, including incentive distribution rights	2,903		1,305		5,055		2,434
Limited partner interest in net income	$	27,102	$	27,686	$	52,797	$	56,624
Net income allocable to common units — basic and diluted	$	27,102	$	14,988	$	52,797	$	30,652
Net income allocable to subordinated units — basic and diluted	—		12,698		—		25,972
Limited partner interest in net income — basic and diluted	$	27,102	$	27,686	$	52,797	$	56,624
Weighted average limited partner units outstanding — Basic
Common units	63,638		34,422		63,630		34,412
Subordinated units	—		29,163		—		29,163
Total	63,638		63,585		63,630		63,575
Weighted average limited partner units outstanding — Diluted
Common units	63,677		34,481		63,670		34,467
Subordinated units	—		29,163		—		29,163
Total	63,677		63,644		63,670		63,630
Net income per limited partner unit — Basic
Common units	$	0.43	$	0.44	$	0.83	$	0.89
Subordinated units	—		0.44		—		0.89
Total	$	0.43	$	0.44	$	0.83	$	0.89
Net income per limited partner unit — Diluted
Common units	$	0.43	$	0.43	$	0.83	$	0.89
Subordinated units	—		0.44		—		0.89
Total	$	0.43	$	0.44	$	0.83	$	0.89

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NOTE 5 — RELATED PARTY TRANSACTIONS

In the ordinary course of business, we engage in related party transactions with CNX (and certain of its subsidiaries) and CNX Gathering, which include the fees we charge and revenues we receive under a fixed fee gathering agreement (including electrically-powered compression CNX reimburses to us) and our reimbursement of certain expenses to CNX under several agreements, discussed below. Related party revenues and related party expenses are presented as separate captions within our consolidated statements of operations for the three and six months ended June 30, 2018 and 2017. We also engaged in related party transactions with Noble Energy during the three and six months ended June 30, 2017, which primarily included the fees we charged and revenues we received under our fixed fee gathering agreement with Noble Energy.

During the six months ended June 30, 2018, the Partnership closed on the Shirley-Penns Acquisition for cash consideration in the amount of $265.0 million and on the CNX and HG Energy Transactions. See Note 1–Description of Business for additional information.

Operating expense and general and administrative expense – related party are derived from CNX in the three and six months ended June 30, 2018 and from CNX and Noble Energy in the three and six months ended June 30, 2017 and consisted of the following:

	Three Months Ended   June 30,				Six Months Ended   June 30,
(in thousands)	2018		2017		2018		2017
Operational services — CNX	$	3,257	$	2,999	$	6,092	$	6,187
Electrical compression	1,822		4,090		3,422		8,530
Total Operating Expense — Related Party	$	5,079	$	7,089	$	9,514	$	14,717
CNX	$	3,620	$	2,530	$	7,232	$	5,241
Noble Energy	—		133		—		305
Total General and Administrative Expense — Related Party	$	3,620	$	2,663	$	7,232	$	5,546

In addition to the aforementioned transactions, throughout the six months ended June 30, 2018 and 2017, CNX and Noble Energy, through their ownership of CNX Gathering in the applicable periods, also regularly reimbursed the Partnership for capital expenditures, initially funded by the Partnership, in proportion to CNX Gathering's noncontrolling ownership interests in the Growth and Additional Systems. We also distributed to CNX and Noble Energy amounts related to their noncontrolling ownership interest, in the applicable periods, in the earnings of the Growth and Additional Systems as well as proceeds from sales of any assets in which CNX and Noble Energy had ownership interests through their membership in CNX Gathering. This activity is recorded in the caption “Distributions to general partner and noncontrolling interest holders, net” in the consolidated statements of partners' capital and noncontrolling interest and of cash flows.

Operational Services Agreement

On September 30, 2014, the date of the closing of the initial public offering of our common units (our “IPO”), we entered into an operational services agreement with CNX. On December 1, 2016, in connection with a transaction under which CNX and Noble Energy separated their Marcellus Shale area of mutual interest into two separate operating areas, the operational services agreement was amended and restated. Under the amended and restated operational services agreement, CNX continues to provide certain operational services to us in support of our gathering pipelines and dehydration, treating and compressor stations and facilities, including routine and emergency maintenance and repair services, routine operational activities, routine administrative services, construction and related services and such other services as we and CNX may mutually agree upon from time to time. CNX prepares and submits for our approval a maintenance, operating and capital budget on an annual basis. CNX submits actual expenditures for reimbursement on a monthly basis, and we reimburse CNX for any direct third-party costs incurred by CNX in providing these services.

Omnibus Agreement

On September 30, 2014, we entered into an omnibus agreement with CNX, CNX Gathering and our general partner that addresses the following matters:

• our payment of an annually-determined administrative support fee (approximately $1.9 million for the year ending December 31, 2018) for the provision of certain services by CNX and its affiliates, including executive costs;

• our obligation to reimburse CNX for all other direct or allocated costs and expenses incurred by CNX in providing general and administrative services (which reimbursement is in addition to certain expenses of our general partner and its affiliates that are reimbursed under our partnership agreement);

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• our right of first offer to acquire (i) CNX Gathering’s retained interests in our Additional Systems, (ii) CNX Gathering’s other ancillary midstream assets and (iii) any additional midstream assets that CNX Gathering develops; and

• an indemnity from CNX Gathering for liabilities associated with the use, ownership or operation of our assets, including environmental liabilities, to the extent relating to the period of time prior to the closing of the IPO; and our obligation to indemnify CNX Gathering for events and conditions associated with the use, ownership or operation of our assets that occur after the closing of the IPO, including environmental liabilities.

So long as CNX Gathering controls our general partner, the omnibus agreement will remain in full force and effect. If CNX Gathering ceases to control our general partner, either party may terminate the omnibus agreement, provided that the indemnification obligations will remain in full force and effect in accordance with their terms.

Gathering Agreements

2018 Gathering Agreements and Amendments

On January 3, 2018, we entered into the Second Amended and Restated GGA, which is a 20-year, fixed-fee gathering agreement with CNX Gas that amended and restated the previous gathering agreement with CNX Gas in its entirety. Although the fees for services we provide in the Marcellus Shale for existing wells that were covered under the prior agreement (discussed below) remain unchanged in the new agreement, the Second Amended and Restated GGA also dedicates an additional 63,000 of acreage in the Utica Shale in and around the McQuay area and Wadestown area and introduces the following gas gathering and compression rates:

• Gas Gathering:

◦ McQuay area Utica - a fee of $0.225 per MMBtu; and

◦ Wadestown Marcellus and Utica - a fee of $0.35 per MMBtu.

• Compression:

◦ For areas not benefitting from system expansion pursuant to the Second Amended and Restated GGA, compression services are included in the base fees; and

◦ In the McQuay and Wadestown areas, for wells turned in line beginning January 1, 2018 and beyond, we will receive additional fees of $0.065 per MMBtu for Tier 1 pressure services (maximum receipt point of pressure of 600 psi) and $0.130 per MMBtu for Tier 2 pressure services (maximum receipt point of pressure of 300 psi).

The Second Amended and Restated GGA also commits CNX Gas to drill the following numbers of wells in the McQuay area within the Anchor Systems, provided that if 125 wells have been drilled and completed in the Marcellus Shale, then the remainder of such planned wells must be drilled in the Utica Shale. To the extent the requisite number of wells are not drilled and completed by CNX Gas in a given period, we will be entitled to a deficiency payment per shortfall well as set out in the parenthetical below:

• January 1, 2018 to December 31, 2018 - 30 wells (deficiency payment of $3.5 million per well)

• January 1, 2019 to April 30, 2020 - 40 wells (deficiency payment of $3.5 million per well)

• May 1, 2020 to April 30, 2021 - 40 wells (deficiency payment of $2.0 million per well)

• May 1, 2021 to April 30, 2022 - 30 wells (deficiency payment of $2.0 million per well)

In the event that CNX Gas drills wells and completes a number of wells in excess of the number of wells required to be drilled and completed in such period, (i) the number of excess wells drilled and completed during such period will be applied to the minimum well requirement in the succeeding period or (ii) to the extent CNX Gas was required to make deficiency payments for shortfalls in the preceding period, CNX Gas may elect to cause the Partnership to pay a refund in an amount equal to (x) the number of excess wells drilled and completed during the period, multiplied by (y) the deficiency payment paid per well during the period in which the shortfall occurred.

On March 16, 2018, in connection with the Shirley-Penns Acquisition, we amended the Second Amended and Restated GGA to add a minimum volume commitment (“MVC”) on volumes associated with the Shirley-Penns System through December 31, 2031. The MVC commits CNX Gas to pay the Partnership the wet gas fee under the gas gathering agreement for all natural gas we gather up to a specified amount per day through December 31, 2031.

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We expect to recognize at least the following amounts or revenue throughout the term of the MVC:

	Revenue under MVC (in millions)
Remainder of year ending December 31, 2018	$	14.2
Year ending December 31, 2019	28.8
Year ending December 31, 2020	34.7
Year ending December 31, 2021	40.8
Year ending December 31, 2022	47.8
Remainder of term	256.6
Total revenue to be recognized under Shirley-Penns contract through December 31, 2031	$	422.9

For all natural gas the Partnership gathers in excess of the MVC, the Partnership will receive a fee of $0.35 per MMBtu in 2018, which will escalate by 2.5% on an annual basis beginning January 1, 2019.

On May 2, 2018, we completed a series of transactions with our Sponsor, which we refer to as the CNX Transaction, pursuant to which we amended the Second Amended and Restated GGA. The amended agreement commits CNX Gas to drill and complete an additional 40 wells in the Majorsville/Mamont area within the Anchor Systems through 2023. To the extent the requisite number of wells are not drilled and completed by CNX Gas in a given period, we will be entitled to a deficiency payment per shortfall well as set out in the parenthetical below:

•July 1, 2018 to December 31, 2020 -  15 wells (deficiency payment of $2.8 million per well)

•January 1, 2021 - December 31, 2023 - 25 wells (deficiency payment of $2.8 million per well)

Gathering Agreements Prior to 2018

On December 1, 2016, we entered into new fixed-fee gathering agreements with Noble Energy and CNX Gas that replaced the gathering agreements that had been in place since our IPO. Our gathering agreement with Noble Energy was assigned to HG Energy upon consummation of the Noble Energy Asset Sale effective June 28, 2017. The terms of the agreement remain unchanged following the assignment, except as it relates to HG Energy’s inability to, without the Partnership’s consent, release dedicated acreage in connection with a transfer of such acreage free of the dedication to us, and exercise other initial shipper rights provided under the gathering agreement.

HG Energy is currently not a related party of the Partnership; accordingly, the focus of the following disclosure is on current and historical related party transactions, which do not include transactions with HG Energy. Our fees for gathering services, throughout 2018, are based on the type and scope of the midstream services we provide, summarized as follows:

• For the services we provide with respect to natural gas from the Marcellus Shale formation that does not require downstream processing, or dry gas, we will receive a fee of $0.431 per MMBtu.

• For the services we provide with respect to natural gas from the Marcellus Shale formation that requires downstream processing, or wet gas, we will receive:

◦ a fee of $0.296 per MMBtu in the Moundsville area (Marshall County, West Virginia) and in the Pittsburgh International Airport area; and

◦ a fee of $0.593 per MMBtu for all other areas in the dedication area.

• For the services we provide with respect to natural gas from the Utica Shale formation, we will receive a weighted average rate of $0.16 per MMBtu.

• Our fees for condensate services will be $5.38 per Bbl in the Majorsville area and $2.693 per Bbl in the Moundsville area.

Each of the foregoing fees escalates by 2.5% on January 1 on an annual basis, through and including the final calendar year of the initial term. Commencing on January 1, 2035, and as of January 1 thereafter, each of the applicable fees will be adjusted pursuant to the percentage change in CPI-U, but such fees will never escalate or decrease by more than 3%. Notwithstanding the foregoing, from time to time, CNX Gas and HG Energy may request rate reductions under certain circumstances, which are reviewed by the board of directors of our general partner, with oversight, as our board of directors deems necessary, from our conflicts committee. No rate reduction arrangements were active at June 30, 2018.

We gather, compress, dehydrate and deliver all of CNX Gas’ dedicated natural gas in the Marcellus Shale on a first-priority basis and gather, inject, stabilize and store all of CNX Gas’ dedicated condensate on a first-priority basis, with the

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exception that until December 1, 2018, CNX Gas will receive first-priority service in our Majorsville system with respect to a certain volume of production (revised bi-annually) and any excess production will receive second-priority service.

CNX Gas provides us with quarterly updates on its drilling and development operations, which include detailed descriptions of the drilling plans, production details and well locations for periods that range from up to 24-48 months, as well as more general development plans that may extend as far as ten years. In addition, we regularly meet with CNX Gas to discuss our current plans to timely construct the necessary facilities to be able to provide midstream services to them on our dedicated acreage. In the event that we do not perform our obligations under a gathering agreement, CNX Gas will be entitled to certain rights and procedural remedies thereunder, including the temporary and/or permanent release from dedication discussed below and indemnification from us.

There are no restrictions under our gathering agreements on the ability of CNX Gas to transfer acreage in the right of first offer (“ROFO”) area, and any such transfer of acreage in the ROFO area will not be subject to our right of first offer. 

Upon completion of its 20-year term in 2037, our gathering agreement with CNX Gas will continue in effect from year to year until such time as the agreement is terminated by either us or CNX Gas on or before 180 days prior written notice.

Registration Rights Agreement

On January 3, 2018, in connection with the closing of the General Partner Transaction, the Partnership entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with Noble Energy relating to the registered resale of common units that Noble Energy acquired in connection with the IPO and upon conversion of subordinated units representing limited partner interests in the Partnership (collectively, the “Registrable Securities”).

Pursuant to the Registration Rights Agreement, the Partnership was required to prepare and file a registration statement, or amend an existing registration statement, for the registered resale of the Registrable Securities. Such registration statement was made effective March 26, 2018.

In certain circumstances, and subject to customary qualifications and limitations, Noble Energy has piggyback registration rights on offerings of common units initiated by the Partnership and other holders of common units. Noble also has the right to request that the Partnership initiate up to four Demand Underwritten Offerings (as defined in the Registration Rights Agreement) of Registrable Securities, subject to certain limitations described in the Registration Rights Agreement. The Registration Rights Agreement will terminate no later than March 26, 2021, which is the third anniversary of the date on which the registration statement became effective.

Under the terms of the Registration Rights Agreement, Noble Energy executed an underwritten public offering of 7,475,000 of its common units in the Partnership on June 29, 2018. See Note 1–Description of Business for additional information.

NOTE 6 — RECEIVABLES

Receivables consisted of the following:

(in thousands)	June 30, 2018		December 31, 2017
Receivables - related party
CNX	$	12,072	$	12,801
CNX Gathering	—		303
Receivables - related party	$	12,072	$	13,104
Receivables - third party	7,546		8,251
Total receivables	$	19,618	$	21,355

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NOTE 7 — PROPERTY AND EQUIPMENT

Property and equipment consisted of the following:

(in thousands)	June 30, 2018		December 31, 2017		Estimated Useful Lives in Years
Land	$	47,975	$	76,130	N/A
Gathering equipment	570,603		662,595		25 — 40
Compression equipment	176,652		180,038		30 — 40
Processing equipment	30,979		30,979		40
Assets under construction	38,402		23,099		N/A
Total Property and Equipment	$	864,611	$	972,841
Less: Accumulated depreciation
Gathering equipment	$	50,744	$	53,544
Compression equipment	15,808		14,886
Processing equipment	5,546		5,133
Total Accumulated Depreciation	$	72,098	$	73,563
Property and Equipment, Net	$	792,513	$	899,278

NOTE 8 — OTHER ASSETS

Other assets consisted of the following:

(in thousands)	June 30, 2018		December 31, 2017
Pipe stock	$	—	$	392
Financing fees	3,219		122
Other	275		79
Total Other Assets	$	3,494	$	593

On March 8, 2018, the Partnership entered into a $600.0 million secured revolving credit facility. In connection with the new credit facility, the Partnership recorded approximately $4.4 million in deferred financing fees, of which approximately $0.9 million is classified as a current asset. See Note 10–Revolving Credit Facility.

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NOTE 9 — ACCOUNTS PAYABLE —RELATED PARTY

Related party payables consisted of the following:

(in thousands)	June 30, 2018		December 31, 2017
CNX Resources:
Expense reimbursements	$	1,148	$	780
Capital expenditures reimbursements	—		83
General and administrative services	2,055		1,458
Total due to CNX Resources	3,203		2,321
Noble Energy:
General and administrative services	—		55
Total due to Noble Energy	—		55
CNX Gathering LLC:
Capital expenditures reimbursement	8		—
Total due to CNX Gathering LLC	8		—
Total Accounts Payable — Related Party	$	3,211	$	2,376

NOTE 10 — REVOLVING CREDIT FACILITY

On March 8, 2018, we entered into a $600.0 million secured revolving credit facility with an accordion feature that allows, subject to certain terms and conditions, the Partnership to increase the available borrowings under the facility by up to an additional $250.0 million. The new revolving credit facility matures on March 8, 2023 and replaced the prior $250.0 million revolving credit facility, which was unsecured. The available borrowing capacity under the new revolving credit facility is limited by certain financial covenants pertaining to leverage and interest coverage ratios as defined in the revolving credit facility agreement.

Borrowings under the new revolving credit facility bear interest at our option at either:

• the base rate, which is the highest of (i) the federal funds open rate plus 0.50%, (ii) PNC Bank, N.A.’s prime rate, and (iii) the one-month LIBOR rate plus 1.0%, in each case, plus a margin ranging from 0.75% to 1.75%; or

• the LIBOR rate, which is the LIBOR rate plus a margin ranging from 1.75% to 2.75%.

Interest on base rate loans is payable on the first business day of each calendar quarter. Interest on LIBOR loans is payable on the last day of each interest period or, in the case of interest periods longer than three months, every three months. The unused portion of our revolving credit facility is subject to a commitment fee ranging from 0.375% to 0.500% per annum depending on our most recent consolidated leverage ratio.

The facility includes restrictions on the ability of the Partnership, its subsidiary guarantors and certain of its non-guarantor, non-wholly-owned subsidiaries, except in certain circumstances, to: (i) create, incur, assume or suffer to exist indebtedness; (ii) create or permit to exist liens on their properties; (iii) prepay certain indebtedness unless there is no default or event of default under the facility; (iv) make or pay any dividends or distributions in excess of certain amounts; (v) merge with or into another person, liquidate or dissolve; or acquire all or substantially all of the assets of any going concern or going line of business or acquire all or a substantial portion of another person’s assets; (vi) make particular investments and loans; (vii) sell, transfer, convey, assign or dispose of its assets or properties other than in the ordinary course of business and other select instances; (viii) deal with any affiliate except in the ordinary course of business on terms no less favorable to the Partnership than it would otherwise receive in an arm’s length transaction; and (ix) amend in any material manner its certificate of incorporation, bylaws, or other organizational documents without giving prior notice to the lenders and, in some cases, obtaining the consent of the lenders. The agreement also contains customary events of default, including, but not limited to, a cross-default to certain other debt, breaches of representations and warranties, change of control events and breaches of covenants. The obligations under the revolving credit facility agreement are secured by the Partnership’s economic interests in each of the Limited Partnerships and all of the assets of the Anchor Systems.

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In addition, the Partnership is obligated to maintain at the end of each fiscal quarter:

• a maximum total leverage ratio of no greater than between 4.75 to 1.00 ranging to no greater than 5.50 to 1.00 in certain circumstances;

• a maximum secured leverage ratio of no greater than 3.50 to 1.00; and

• a minimum interest coverage ratio of no less than 2.50 to 1.00;

The Partnership was in compliance with all financial covenants at June 30, 2018.

On June 30, 2018, the Partnership’s balance on the revolving credit facility was $11.0 million at an interest rate of 4.09%. After giving effect to the limitations on available capacity described in the revolving credit facility agreement, we estimate that the Partnership had approximately $494.0 million available for borrowing at June 30, 2018.

At December 31, 2017, the outstanding balance on the then-effective revolving credit facility was $149.5 million at an interest rate of 3.11%.

NOTE 11 — LONG-TERM DEBT

On March 16, 2018, the Partnership, together with its wholly owned subsidiary CNX Midstream Finance Corp (“Finance Corp”), (collectively, the “Issuers”), completed a private offering of $400.0 million in 6.5% senior notes due 2026 (the “Senior Notes”), with related guarantees (the “Guarantees”) and received net proceeds of approximately $393.0 million, after deducting the initial purchasers’ discount and commissions and estimated offering expenses, which are recorded in our consolidated balance sheet as a reduction to the principal amount. Proceeds from the Senior Notes offering were primarily used to fund the Shirley-Penns Acquisition and repay existing indebtedness under our prior $250.0 million unsecured revolving credit facility. The Senior Notes mature on March 15, 2026 and accrue interest at a rate of 6.5% per year, which is payable semi-annually in arrears on March 15 and September 15, beginning September 15, 2018. There are no principal payment requirements on the Senior Notes prior to maturity.

As of the dates presented below, the Partnership had long-term debt of:

	June 30, 2018		December 31, 2017
Senior Notes due March 2026 at 6.5%	$	400,000	$	—
Less: Unamortized debt issuance costs	1,081		—
Less: Unamortized bond discount	5,750		—
Long-term debt	$	393,169	$	—

The Senior Notes and Guarantees were issued pursuant to an indenture (the “Indenture”), dated March 16, 2018, among the Partnership, Finance Corp, the guarantors party thereto (the “Guarantors”) and UMB Bank, N.A., as trustee (the “Trustee”). The Senior Notes rank equally in right of payment with all of the Issuers’ existing and future senior indebtedness and senior to any subordinated indebtedness that the Issuers’ may incur. The Guarantees rank equally in right of payment to all of the Guarantors’ existing and future senior indebtedness.

The Issuers may redeem all or part of the Senior Notes at redemption prices ranging from 104.875% beginning March 15, 2021 to 100.0% beginning March 15, 2024. Prior to March 15, 2021, the Issuers may on one or more occasions redeem up to 35.0% of the principal amount of the Senior Notes with an amount of cash not greater than the amount of the net cash proceeds from one or more equity offerings at a redemption price of 106.50%. At any time or from time to time prior to March 15, 2021, the Issuers may also redeem all or a part of the Senior Notes, at a redemption price equal to 100.0% of the principal amount thereof plus the Applicable Premium, as defined in the Indenture, plus accrued and unpaid interest.

If the Partnership experiences certain kinds of changes of control, holders of the Senior Notes will be entitled to require the Partnership to repurchase all or any part of that holder’s Senior Notes pursuant to an offer on the terms set forth in the Indenture. The Partnership will offer to make a cash payment equal to 101.0% of the aggregate principal amount of the Senior Notes repurchased plus accrued and unpaid interest on the Senior Notes repurchased to, but not including, the date of purchase, subject to the rights of holders of the Senior Notes on the relevant record date to receive interest due on the relevant interest payment date.

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NOTE 12 — COMMITMENTS AND CONTINGENCIES

Litigation

The Partnership may become involved in certain legal proceedings from time to time, and where appropriate, we have accrued our estimate of the probable costs for the resolution of these claims. The Partnership believes that the ultimate outcome of any matter currently pending against the Partnership will not materially affect the Partnership’s business, financial condition, results of operations, liquidity or ability to make distributions.

Leases

We have entered into various non-cancelable operating leases, primarily related to compression facilities. Future minimum lease payments under operating leases as of June 30, 2018 are as follows:

(in thousands)	Minimum Lease Payments
Period from July 1, 2018 through December 31, 2018	$	1,023
Year ending December 31, 2019	1,627
Year ending December 31, 2020	1,042
	$	3,692

Rental expense under operating leases was $2.0 million and $1.9 million for the three months ended June 30, 2018 and 2017, respectively. Rental expense under operating leases was $4.1 million and $3.8 million for the six months ended June 30, 2018 and 2017, respectively. These expenses are included within operating expense - third party on our consolidated statement of operations.

NOTE 13 — SEGMENT INFORMATION

Operating segments are the revenue-producing components of a company for which separate financial information is produced internally and is subject to evaluation by the chief operating decision maker in deciding how to allocate resources. Prior to the CNX and HG Energy Transaction, the Partnership had three operating segments, which also represented its reportable segments - the Anchor Systems, Growth Systems and Additional Systems, each of which does business entirely within the United States of America. See Note 1–Description of Business for additional information.

During the first quarter of 2018, the Partnership, through its 100% interest in the Anchor Systems, completed the Shirley-Penns Acquisition. Prior to March 16, 2018, the Partnership held a 5% controlling interest in the earnings and throughput related to the Shirley-Penns System; accordingly, until March 16, 2018, results attributable to limited and general partners of the Partnership reflect a 5% interest in the Shirley-Penns System. Results net to the Partnership include activity related to the Shirley-Penns Acquisition beginning March 16, 2018. However, in accordance with ASC 280 - Segment Reporting, information is reported in the tables below, for comparability purposes, as if the Shirley-Penns Acquisition occurred on January 1, 2017.

In connection with the HG Energy Transaction, the Partnership distributed its 5% interest in the Growth Systems and related assets as well as its 5% interest in the Moundsville midstream assets, which were previously a part of the Additional Systems, to CNX Gathering, which transferred these assets to HG Energy. Because the Growth Systems and Moundsville area of the Additional Systems had activity for all of 2017 and through May 2, 2018, we will continue to present consistent segment information with regards to this transaction throughout the year ending December 31, 2018 for comparative purposes.

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Segment results for the periods presented were as follows:

	Three Months Ended June 30,					Six Months Ended June 30,
(in thousands)	2018		2017			2018		2017
Gathering Revenue:
Anchor Systems	$	56,584	$	50,195		$	112,774	$	102,894
Growth Systems	668		2,018			2,572		4,243
Additional Systems	3,762		4,321			9,537		8,355
Total Gathering Revenue	$	61,014	$	56,534		$	124,883	$	115,492
Net Income (Loss):
Anchor Systems	$	29,991	$	30,764		$	63,134	$	62,380
Growth Systems	186		506			379		453
Additional Systems	105		(1,518		)	474		159
Total Net Income	$	30,282	$	29,752		$	63,987	$	62,992
Depreciation Expense:
Anchor Systems	$	4,733	$	4,201		$	9,203	$	8,397
Growth Systems	195		543			748		1,088
Additional Systems	515		931			1,348		1,861
Total Depreciation Expense	$	5,443	$	5,675		$	11,299	$	11,346
Capital Expenditures for Segment Assets:
Anchor Systems	$	24,502	$	11,841		$	38,290	$	22,374
Growth Systems	42		382			120		821
Additional Systems	1,071		—			3,177		220
Total Capital Expenditures	$	25,615	$	12,223		$	41,587	$	23,415

Segment assets as of the dates presented were as follows:

(in thousands)	June 30, 2018		December 31, 2017
Segment Assets
Anchor Systems	$	737,152	$	694,942
Growth Systems	—		92,659
Additional Systems	81,906		138,988
Total Segment Assets	$	819,058	$	926,589

NOTE 14 — LONG-TERM INCENTIVE PLAN

Under the CNX Midstream Partners LP 2014 Long-Term Incentive Plan (our “LTIP”), our general partner may issue long-term equity-based awards to directors, officers and employees of the general partner or its affiliates, or to any consultants, affiliates of our general partner or other individuals who perform services on behalf of the Partnership. The Partnership is responsible for the cost of awards granted under the LTIP, which limits the number of units that may be delivered pursuant to vested awards to 5.8 million common units, subject to proportionate adjustment in the event of unit splits and similar events. Common units subject to awards that are canceled, forfeited, withheld to satisfy tax withholding obligations or otherwise terminated without delivery of the common units will be available for delivery pursuant to other awards.

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The following table presents phantom unit activity during the six month period ended June 30, 2018:

	Number of Units	Weighted Average Grant Date Fair Value
Total awarded and unvested at December 31, 2017	134,153	$	16.40
Granted	132,933	19.14
Vested	(70,872)	16.65
Forfeited	(17,639)	16.25
Total awarded and unvested at June 30, 2018	178,575	$	18.30

The Partnership accounts for phantom units as equity awards and records compensation expense on a straight line basis over the vesting period based on the fair value of the awards at their grant dates. Awards granted to independent directors vest over a period of one year, and awards granted to certain officers and employees of the general partner vest 33% per year over a period of three years.

The Partnership recognized $0.7 million and $0.4 million of compensation expense related to phantom units for the three months ended June 30, 2018 and 2017, respectively, and $1.3 million and $0.7 million for the six months ended June 30, 2018 and 2017, respectively, which was included in general and administrative expense - related party in the consolidated statements of operations.

At June 30, 2018, the unrecognized compensation related to all outstanding awards was $2.4 million, which is expected to be recognized over the following two years.

NOTE 15 — SUBSEQUENT EVENTS

On July 27, 2018, the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders with respect to the second quarter of 2018 of $0.3361 per common unit. The cash distribution will be paid on August 14, 2018 to unitholders of record at the close of business on August 7, 2018.

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

You should read the following discussion of the financial condition and results of operations of CNX Midstream Partners LP in conjunction with the historical and unaudited interim consolidated financial statements and notes to the consolidated financial statements. Among other things, those historical unaudited interim consolidated financial statements include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those discussed in such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those identified under “forward-looking statements” below and those discussed in the section entitled “Risk Factors” in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2017 and in our Quarterly Report on Form 10-Q, filed subsequent to that Annual Report on Form 10-K. In this Item 2, all references to “we,” us,” “our,” the “Partnership,” “CNXM,” or similar terms refer to CNX Midstream Partners LP and its subsidiaries.

Executive Overview

We are a growth-oriented master limited partnership focused on the ownership, operation, development and acquisition of natural gas gathering and other midstream energy assets to service our customers’ production in the Marcellus Shale and Utica Shale in Pennsylvania and West Virginia. Our assets include natural gas gathering pipelines and compression and dehydration facilities, as well as condensate gathering, collection, separation and stabilization facilities. We are managed by our general partner, CNX Midstream GP LLC (our “general partner”), which is a wholly owned subsidiary of CNX Gathering LLC (“CNX Gathering”). CNX Gathering is a wholly owned subsidiary of CNX Resources Corporation (NYSE: CNX) (“CNX” or “CNX Resources”).

We were formed in May 2014 as a joint venture between CNX and Noble Energy, Inc. (NYSE: NBL) (“Noble Energy”).

Year to Date and Second Quarter Highlights

CNX Resources’ Acquisition of General Partner

On January 3, 2018, CNX Gas Company LLC (“CNX Gas”), an indirect wholly owned subsidiary of CNX, acquired from NBL Midstream, LLC (“NBL Midstream”), a wholly owned subsidiary of Noble Energy, NBL Midstream’s 50% interest in CNX Gathering for cash consideration of $305.0 million and the mutual release of all outstanding claims between the parties (the “General Partner Transaction”).

As a result of the Transaction, CNX became our sole Sponsor.

Acquisition of Shirley-Penns System

At December 31, 2017, CNX Gathering owned a 95% noncontrolling interest in DevCo III LP (which we refer to as the “Additional Systems”), which owned the gathering system and related assets commonly referred to as the Shirley-Penns System (the “Shirley-Penns System”), while the Partnership owned the remaining 5% controlling interest in the Additional Systems.

On March 16, 2018, the Partnership acquired the remaining 95% interest in the Shirley-Penns System, pursuant to which DevCo III LP transferred its interest in the Shirley-Penns System on a pro rata basis to CNX Gathering and the Partnership in accordance with each transferee’s respective ownership interest in DevCo III LP. Following such transfer, CNX Gathering sold its aggregate interest in the Shirley-Penns System to DevCo I LP (which we refer to as the “Anchor Systems”) in exchange for cash consideration in the amount of $265.0 million (the “Shirley-Penns Acquisition”). The Partnership funded the Shirley-Penns Acquisition with a portion of the proceeds from the issuance of 6.5% senior notes due 2026 (the “Senior Notes”).

In connection with the Shirley-Penns Acquisition, we amended our January 3, 2018 gathering agreement with CNX Gas to add a minimum volume commitment (“MVC”) on volumes associated with the Shirley-Penns system through December 31, 2031. The MVC commits CNX Gas to pay the Partnership the wet gas fee under the gas gathering agreement (with a 2.5% annual escalation factor) for all natural gas we gather up to a specified amount per day through December 31, 2031. For all natural gas the Partnership gathers in excess of the MVC, the Partnership will receive a fee of $0.35 per MMBtu in 2018, which will escalate by 2.5% on an annual basis beginning January 1, 2019.

Transactions with our Sponsor and HG Energy

On May 2, 2018, our Sponsor closed on a transaction with HG Energy and in connection therewith we closed on transactions with our Sponsor and HG Energy (collectively the “CNX and HG Energy Transactions”). These strategic transactions included the amendment of our gas gathering agreements (“GGAs”) with both CNX and HG Energy. Management believes these transactions strengthen our asset portfolio and outlook, the key terms of which are outlined below:

• The transactions provide for the additional dedication of 16,100 additional Utica acres in the Anchor Systems by our Sponsor and the release from dedication of approximately 18,000 acres, net to the Partnership, which was comprised

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of approximately 275,000 acres (or approximately 14,000 acres, net to the Partnership) within the Growth and Additional Systems and approximately 4,200 scattered acres located in the Anchor Systems;

• The transactions increase minimum well commitments, with our Sponsor committing to develop 40 additional wells in the Anchor Systems by 2023 and HG Energy committing to develop 12 additional wells in the Anchor Systems by 2021, in each case, subject to the applicable GGAs;

• Our Sponsor contributed to the Partnership’s Anchor Systems a 20” high-pressure pipeline as well as $2.0 million in cash;

• In exchange for the incremental Utica acreage dedication, minimum well commitments, and high-pressure pipeline with third-party revenue, we distributed our 5% controlling interest in the midstream assets of the Growth Systems and the Moundsville midstream assets located within the Additional Systems, to affiliates of our Sponsor, which it subsequently transferred to HG Energy, and released acreage from dedication discussed above; and

• The transaction with HG Energy also includes an amended GGA in the Anchor Systems, which we believe provides us with more control over operating strategies and expansion in the Anchor Systems. In addition, we will no longer be obligated to provide gathering services or make capital investments in the Growth Systems and the Moundsville midstream assets.

Following the CNX and HG Energy Transactions, the aggregate number of well commitments to the Partnership by CNX and HG Energy, collectively, within the Anchor Systems increased from 140 well connections over the course of the next five years to 192 well connections. HG Energy continues to be one of our significant customers, and we will continue to gather its existing production as well as the production from its aforementioned 12 commitment wells in the Anchor Systems, when brought online, at gathering fees pursuant to the applicable gathering agreement. See Item 1. Consolidated Financial Statements, Note 1–Description of Business for additional information.

Following the CNX and HG Energy Transactions, our GGAs with CNX and HG Energy include acreage dedications of approximately 348,000 aggregate net acres, subject to the release provisions set forth therein.

Financial Highlights

The Partnership continued its solid financial performance in the quarter ended June 30, 2018. Comparative results net to the Partnership, with the exception of operating cash flows, which is shown on a gross consolidated basis, were as follows for the quarters ended June 30, 2018 and 2017, respectively:

• Net income of $30.0 million as compared to $29.0 million;

• Cash provided by operating activities of $53.7 million as compared to $42.3 million;

• Adjusted EBITDA (non-GAAP) of $41.3 million as compared to $34.4 million; and

• Distributable cash flow (non-GAAP) of $31.6 million as compared to $29.6 million.

Consistent with each of the last ten consecutive quarters, the current quarter’s cash provided by operating activities exceeded the sum of capital expenditures ($25.6 million), distributions to unitholders ($22.7 million) and interest paid ($0.2 million).

For a discussion of why the above metrics are important to management, and how the non-GAAP financial measures reconcile to their nearest comparable financial measures prepared in accordance with accounting principles generally accepted in the United States (“GAAP”), see “Non-GAAP Financial Measures” on page 33 of this Quarterly Report on Form 10-Q.

Quarterly Cash Distribution

The Partnership declared a cash distribution to its unitholders of $0.3361 per unit on July 27, 2018, which was 3.6% higher than the first quarter 2018 distribution of $0.3245 per unit and 15% higher than the second quarter 2017 distribution of $0.2922 per unit.

Factors Affecting the Comparability of Our Financial Results

Our results of operations, net to the Partnership, include 100% of the Shirley-Penns System beginning on March 16, 2018, the date the Shirley-Penns Acquisition was consummated. However, our results of operations for the six months ended June 30, 2017 and for the days in the current six month period prior to March 16, 2018, net to the Partnership, include only 5% of the earnings of the Shirley-Penns System.

On May 2, 2018, the CNX and HG Energy Transactions were consummated. Accordingly, as of this date, the Partnership has no remaining interest in the Growth Systems or in the Moundsville area of the Additional Systems. Total revenues associated with the Growth Systems and the Moundsville area were approximately $5.0 million during the three months ended March 31, 2018 and approximately $6.6 million during 2018 through the date of the CNX and HG Energy Transactions.

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Results of Operations

Quarter Ended June 30, 2018 Compared to the Quarter Ended June 30, 2017

	Quarter Ended June 30,
	2018			2017		Change ($)			Change (%)
	($ in thousands)
Revenue
Gathering revenue — related party	$	37,576		$	55,667	$	(18,091	)	(32.5	)%
Gathering revenue — third party	23,438			867		22,571			2,603.3	%
Total Revenue	61,014			56,534		4,480			7.9	%
Expenses
Operating expense — related party	5,079			7,089		(2,010		)	(28.4	)%
Operating expense — third party	7,406			5,957		1,449			24.3	%
General and administrative expense — related party	3,620			2,663		957			35.9	%
General and administrative expense — third party	2,319			1,033		1,286			124.5	%
(Gain) loss on asset sales	(254		)	3,241		(3,495		)	(107.8	)%
Depreciation expense	5,443			5,675		(232		)	(4.1	)%
Interest expense	7,119			1,124		5,995			533.4	%
Total Expense	30,732			26,782		3,950			14.7	%
Net Income	$	30,282		$	29,752	$	530		1.8	%
Less: Net income attributable to noncontrolling interest	277			761		(484		)	(63.6	)%
Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP	$	30,005		$	28,991	$	1,014		3.5	%

Operating Statistics - Gathered Volumes for the Quarter Ended June 30, 2018

	Anchor	Growth	Additional	TOTAL
Dry Gas (BBtu/d) (**)	667	15	9	691
Wet Gas (BBtu/d) (**)	530	1	121	652
Condensate (MMcfe/d)	3	—	5	8
Total Gathered Volumes (*)	1,200	16	135	1,351

Operating Statistics - Gathered Volumes for the Quarter Ended June 30, 2017

	Anchor	Growth	Additional	TOTAL
Dry Gas (BBtu/d) (**)	589	47	11	647
Wet Gas (BBtu/d) (**)	437	4	126	567
Condensate (MMcfe/d)	6	—	3	9
Total Gathered Volumes (*)	1,032	51	140	1,223

(*)On March 16, 2018, the Partnership, through its 100% interest in the Anchor Systems, consummated the Shirley-Penns Acquisition. Prior to March 16, 2018, the Partnership held a 5% controlling interest in the earnings and production related to the Shirley-Penns System. However, in accordance with ASC 280 - Segment Reporting, information is reported in the tables above, for comparability purposes, as if the Shirley-Penns Acquisition occurred on January 1, 2017. See “Acquisition of Shirley-Penns System” above.

(**) Classification as dry or wet is based upon the shipping destination of the related volumes. Because our customers have the option to ship a portion of their natural gas to destinations associated with either our wet system or our dry system, due to any number of factors, volumes may be classified as “wet” in one period and as “dry” in the comparative period. Although there were no such instances in the periods presented above, this remains a possibility in future periods.

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Revenue    

Our revenue typically increases or decreases as our customers’ production on our dedicated acreage increases or decreases. Since we charge a higher fee for natural gas that is shipped through our wet system than through our dry system, our revenue can also be impacted by the relative mix of gathered volumes by area, which may vary dependent upon our customers’ elections as to where to deliver their produced volumes, which may change dynamically depending on the most current commodity prices at the time of shipment.

Total revenue increased 7.9% to approximately $61.0 million for the three months ended June 30, 2018 compared to approximately $56.5 million for the three months ended June 30, 2017, while gathered volumes increased 10.5% in the current quarter compared to the prior year quarter. The volume increase was primarily due to an 85 BBtu/d increase in wet natural gas gathered when compared to the prior year quarter, which was primarily the result of increased production within the Shirley-Penns System. Increases in gathered volumes were partially offset by decreases related to volumes no longer gathered pursuant to the HG Energy Transaction, which accounted for a $1.2 million reduction in total revenues in the current quarter compared to the prior year quarter.

During the quarter ended June 30, 2018, HG Energy accounted for substantially all of our third party revenues. During the quarter ended June 30, 2017, substantially all of our revenues were derived from CNX and Noble Energy. Noble Energy was one of our Sponsors prior to the General Partner Transaction.

Operating Expense

Total operating expenses were approximately $12.5 million in the current quarter compared to approximately $13.0 million in the prior year quarter. Included in total operating expense was electrically-powered compression expense of $4.2 million for the three months ended June 30, 2018 compared to $4.1 million for the three months ended June 30, 2017, which was reimbursed by our customers pursuant to our gas gathering agreements. After adjusting for the electrically-powered compression expense reimbursement, operating expenses decreased by approximately 6.8% in the current quarter compared to the prior year quarter, primarily as a result of continued adherence to operating cost control measures implemented by our operations team over the past few years.

General and Administrative Expense

General and administrative expense is comprised of direct charges for the management and operation of our assets. Total general and administrative expense was approximately $5.9 million in the current quarter compared to approximately $3.7 million in the prior quarter. The quarter over quarter increase primarily related to increased legal and other professional costs incurred in connection with the HG Energy Transaction, with the majority of the remainder of the increase resulting from several non-recurring items that are not individually significant.

(Gain) Loss on Asset Sales

During the three months ended June 30, 2018, we sold a portion of our pipe stock to an unrelated third party for an amount that was above its carrying value. The sale of pipe stock resulted in a gain of $0.3 million. The pipe stock was previously within the Growth Systems; accordingly, the net impact to earnings attributable to general and limited partners’ ownership interests in the Partnership was not significant.

During the three months ended June 30, 2017, the Partnership sold property and equipment with a carrying value of $17.4 million to CNX Gas for $14.0 million in cash proceeds, which resulted in a loss of $3.4 million. The assets that were sold were previously within the Additional Systems; accordingly, the net impact to earnings attributable to general and limited partners' ownership interests in the Partnership was approximately $0.2 million.

Depreciation Expense    

Depreciation expense is recognized on gathering and other equipment on a straight-line basis, with useful lives ranging from 25 years to 40 years. Total depreciation expense was approximately $5.4 million in the three months ended June 30, 2018 compared to approximately $5.7 million in the three months ended June 30, 2017. The decrease in depreciation expense was primarily attributable to the HG Energy Transaction, pursuant to which we distributed our interests in the Growth Systems and the Moundsville midstream assets in the Additional Systems to CNX Gathering, an affiliate of our Sponsor, which subsequently transferred these assets to HG Energy.

Interest Expense 

Interest expense is comprised of interest on the outstanding balance under our senior notes due 2026 and revolving credit facility. Interest expense was approximately $7.1 million for the three months ended June 30, 2018 compared to approximately $1.1 million for the three months ended June 30, 2017. The increase in interest expense was primarily due to the interest associated with the Senior Notes, which did not exist in the prior year quarter.

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

	Six Months Ended June 30,
	2018		2017		Change ($)			Change (%)
	($ in thousands)
Revenue
Gathering revenue — related party	$	75,306	$	114,625	$	(39,319	)	(34.3	)%
Gathering revenue — third party	49,577		867		48,710			5,618.2	%
Total Revenue	124,883		115,492		9,391			8.1	%
Expenses
Operating expense — related party	9,514		14,717		(5,203		)	(35.4	)%
Operating expense — third party	15,874		12,590		3,284			26.1	%
General and administrative expense — related party	7,232		5,546		1,686			30.4	%
General and administrative expense — third party	4,868		2,225		2,643			118.8	%
Loss on asset sales	2,501		3,914		(1,413		)	(36.1	)%
Depreciation expense	11,299		11,346		(47		)	(0.4	)%
Interest expense	9,608		2,162		7,446			344.4	%
Total Expense	60,896		52,500		8,396			16.0	%
Net Income	$	63,987	$	62,992	$	995		1.6	%
Less: Net income attributable to noncontrolling interest	6,135		3,934		2,201			55.9	%
Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP	$	57,852	$	59,058	$	(1,206	)	(2.0	)%

Operating Statistics - Gathered Volumes for the Six Months Ended June 30, 2018

	Anchor	Growth	Additional	TOTAL
Dry Gas (BBtu/d) (**)	652	29	16	697
Wet Gas (BBtu/d) (**)	538	2	141	681
Condensate (MMcfe/d)	4	—	13	17
Total Gathered Volumes (*)	1,194	31	170	1,395

Operating Statistics - Gathered Volumes for the Six Months Ended June 30, 2017

	Anchor	Growth	Additional	TOTAL
Dry Gas (BBtu/d) (**)	625	50	20	695
Wet Gas (BBtu/d) (**)	440	4	111	555
Condensate (MMcfe/d)	5	—	3	8
Total Gathered Volumes (*)	1,070	54	134	1,258

(*)On March 16, 2018, the Partnership, through its 100% interest in the Anchor Systems, consummated the Shirley-Penns Acquisition. Prior to March 16, 2018, the Partnership held a 5% controlling interest in the earnings and production related to the Shirley-Penns System. However, in accordance with ASC 280 - Segment Reporting, information is reported in the tables above, for comparability purposes, as if the Shirley-Penns Acquisition occurred on January 1, 2017. See “Acquisition of Shirley-Penns System” above.

(**) Classification as dry or wet is based upon the shipping destination of the related volumes. Because our customers have the option to ship a portion of their natural gas to destinations associated with either our wet system or our dry system, due to any number of factors, volumes may be classified as “wet” in one period and as “dry” in the comparative period. Although there were no such instances in the periods presented above, this remains a possibility in future periods.

Revenue    

Our revenue typically increases or decreases as our customers’ production on our dedicated acreage increases or decreases. Since we charge a higher fee for natural gas that is shipped through our wet system than through our dry system, our revenue can also be impacted by the relative mix of gathered volumes by area, which may vary dependent upon our customers’

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elections as to where to deliver their produced volumes, which may change dynamically depending on the most current commodity prices at the time of shipment.

Total revenue increased approximately 8.1% to $124.9 million for the six months ended June 30, 2018 compared to approximately $115.5 million for the six months ended June 30, 2017, while gathered volumes increased approximately 10.9% in the current six month period compared to the prior year period. The volume increase was primarily due to a 125 BBtu/d increase in wet natural gas gathered when compared to the prior year period, which was primarily the result of increased production within the Shirley-Penns System.

During the six months ended June 30, 2018, HG Energy accounted for substantially all of our third party revenues. During the six months ended June 30, 2017, substantially all of our total revenues were derived from CNX and Noble Energy. Noble Energy was one of our Sponsors prior to the General Partner Transaction.

Operating Expense

Total operating expenses were approximately $25.4 million for the six months ended June 30, 2018 compared to approximately $27.3 million for the six months ended June 30, 2017. Included in total operating expense was electrically-powered compression expense of $8.0 million for the six months ended June 30, 2018 compared to $8.6 million for the six months ended June 30, 2017, which was reimbursed by our customers pursuant to our GGAs. After adjusting for the electrically-powered compression expense reimbursement, operating expenses decreased by approximately 7.0% in the current six month period compared to the prior year period, primarily as a result of continued adherence to operating cost control measures implemented by our operations team over the past few years.

General and Administrative Expense

General and administrative expense is comprised of direct charges for the management and operation of our assets. Total general and administrative expense was approximately $12.1 million in the current six month period compared to approximately $7.8 million in the prior year period, or an increase of $4.3 million. The increase is primarily related to costs incurred in connection with the Shirley-Penns Acquisition and HG Energy Transaction, with the majority of the remainder of the increase resulting from several non-recurring items that are not individually significant.

Loss on Asset Sales

During the six month period ended June 30, 2018, the Partnership sold property and equipment with a carrying value of $8.6 million to an unrelated third party for $5.8 million in cash proceeds. Our sale of midstream assets resulted in a loss of $2.8 million. The assets that were sold were previously within the Additional Systems; accordingly, the net impact to earnings attributable to general and limited partners’ ownership interests in the Partnership was approximately $0.1 million.

Additionally, during the six months ended June 30, 2018, we sold a portion of our pipe stock to an unrelated third party for an amount that was above its carrying value.  The sale of pipe stock resulted in a gain of $0.3 million. The pipe stock was previously within the Growth Systems; accordingly, the net impact to earnings attributable to general and limited partners’ ownership interests in the Partnership was not significant.

During the six months ended June 30, 2017, the Partnership sold property and equipment with a carrying value of $17.4 million to CNX Gas for $14.0 million in cash proceeds, which resulted in a loss of $3.4 million. The assets sold were previously within the Additional Systems; accordingly, the net impact to earnings attributable to general and limited partners' ownership interests in the Partnership was approximately $0.2 million.

In addition, we also sold a significant portion of our pipe stock to an unrelated third party for approximately $0.5 million below its carrying value during the six months ended June 30, 2017.

Depreciation Expense    

Depreciation expense is recognized on gathering and other equipment on a straight-line basis, with useful lives ranging from 25 years to 40 years. Total depreciation expense was approximately $11.3 million in the six months ended June 30, 2018 and 2017.

Interest Expense 

Interest expense is comprised of interest on the outstanding balance under our senior notes due 2026 and revolving credit facility. Interest expense was approximately $9.6 million for the six months ended June 30, 2018 compared to approximately $2.2 million for the six months ended June 30, 2017. The increase in interest expense is primarily due to the interest related to our Senior Notes, which did not exist in the prior year period.

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Non-GAAP Financial Measures

EBITDA and Adjusted EBITDA

We define EBITDA as net income (loss) before net interest expense, depreciation and amortization, and Adjusted EBITDA as EBITDA adjusted for non-cash items which should not be included in the calculation of distributable cash flow. EBITDA and Adjusted EBITDA are used as supplemental financial measures by management and by external users of our financial statements, such as investors, industry analysts, lenders and ratings agencies, to assess:

• our operating performance as compared to those of other companies in the midstream energy industry, without regard to financing methods, historical cost basis or capital structure;

• the ability of our assets to generate sufficient cash flow to make distributions to our partners;

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

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

We believe that the presentation of EBITDA and Adjusted EBITDA provides information that is useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to EBITDA and Adjusted EBITDA are net income and net cash provided by operating activities. EBITDA and Adjusted EBITDA should not be considered alternatives to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA and Adjusted EBITDA exclude some, but not all, items that affect net income or net cash, and these measures may vary from those of other companies. As a result, EBITDA and Adjusted EBITDA as presented below may not be comparable to similarly titled measures of other companies.

Distributable Cash Flow

We define distributable cash flow as Adjusted EBITDA less net income attributable to noncontrolling interest, cash interest and maintenance capital expenditures, each net to the Partnership. Distributable cash flow does not reflect changes in working capital balances.

Distributable cash flow is used as a supplemental financial measure by management and by external users of our financial statements, such as investors, industry analysts, lenders and ratings agencies, to assess:

• the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions to our unitholders; and

• the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

We believe that the presentation of distributable cash flow in this Quarterly Report on Form 10-Q provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to distributable cash flow are net income and net cash provided by operating activities. Distributable cash flow should not be considered an alternative to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Distributable cash flow excludes some, but not all, items that affect net income or net cash, and these measures may vary from those of other companies. As a result, our distributable cash flow may not be comparable to similarly titled measures that other companies may use.

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The following table presents a reconciliation of the non-GAAP measures of EBITDA, Adjusted EBITDA and distributable cash flow to the most directly comparable GAAP financial measures of net income and net cash provided by operating activities.

	Three Months Ended   June 30,						Six Months Ended   June 30,
(in thousands)	2018			2017			2018			2017
Net Income	$	30,282		$	29,752		$	63,987		$	62,992
Depreciation expense	5,443			5,675			11,299			11,346
Interest expense	7,119			1,124			9,608			2,162
EBITDA	42,844			36,551			84,894			76,500
Non-cash unit-based compensation expense	690			367			1,269			650
(Gain) Loss on asset sales	(254		)	3,241			2,501			3,914
Adjusted EBITDA	43,280			40,159			88,664			81,064
Less:
Net income attributable to noncontrolling interest	277			761			6,135			3,934
Depreciation expense attributable to noncontrolling interest	674			1,833			2,339			3,663
Other expenses attributable to noncontrolling interest	1,224			112			1,660			194
(Gain) Loss on asset sales attributable to noncontrolling interest	(242		)	3,079			2,375			3,718
Adjusted EBITDA attributable to General and Limited Partner ownership interest in CNX Midstream Partners LP	$	41,347		$	34,374		$	76,155		$	69,555
Less: cash interest, net to the Partnership	5,573			1,079			7,588			2,079
Less: maintenance capital expenditures, net to the Partnership	4,125			3,715			7,708			7,596
Distributable Cash Flow	$	31,649		$	29,580		$	60,859		$	59,880
Net Cash Provided by Operating Activities	$	53,674		$	42,258		$	95,541		$	76,434
Interest expense	7,119			1,124			9,608			2,162
(Gain) Loss on asset sales	(254		)	3,241			2,501			3,914
Other, including changes in working capital	(17,259		)	(6,464		)	(18,986		)	(1,446		)
Adjusted EBITDA	43,280			40,159			88,664			81,064
Less:
Net income attributable to noncontrolling interest	277			761			6,135			3,934
Depreciation expense attributable to noncontrolling interest	674			1,833			2,339			3,663
Other expenses attributable to noncontrolling interest	1,224			112			1,660			194
(Gain) Loss on asset sales attributable to noncontrolling interest	(242		)	3,079			2,375			3,718
Adjusted EBITDA attributable to General and Limited Partner ownership interest in CNX Midstream Partners LP	$	41,347		$	34,374		$	76,155		$	69,555
Less: cash interest, net to the Partnership	5,573			1,079			7,588			2,079
Less: maintenance capital expenditures, net to the Partnership	4,125			3,715			7,708			7,596
Distributable Cash Flow	$	31,649		$	29,580		$	60,859		$	59,880

Distributable cash flow is a non-GAAP measure that is net to the Partnership. The $2.1 million and $1.0 million increases in distributable cash flow in the three and six months ended June 30, 2018, respectively, compared to the 2017 periods were primarily attributable to the impact of the Shirley-Penns Acquisition, which was partially offset by an increase in interest expense associated with the issuance of the Senior Notes.

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Liquidity and Capital Resources

Liquidity and Financing Arrangements

We have historically satisfied our working capital requirements, funded capital expenditures, acquisitions and debt service obligations, and made cash distributions with cash generated from operations and borrowings under our revolving credit facility. If necessary, we may issue additional equity or debt securities to fund future growth. We believe that cash generated from these sources will continue to be sufficient to meet these needs in the future.

Cash Flows

Net cash provided by or used in operating activities, investing activities and financing activities were as follows for the periods presented:

	Six Months Ended June 30,
(in millions)	2018			2017			Change
Net cash provided by operating activities	$	95.5		$	76.4		$	19.1
Net cash used in investing activities	$	(35.1	)	$	(9.4	)	$	(25.7	)
Net cash used in financing activities	$	(62.9	)	$	(68.6	)	$	5.7

Net cash provided by operating activities increased approximately $19.1 million for the six months ended June 30, 2018 compared to the six months ended June 30, 2017. The Partnership's consolidated earnings before interest, loss on asset sales, and depreciation increased by $6.6 million in the current year period compared to the prior year period, accounting for part of the increase. Accrued but unpaid interest related to the Senior Notes also had a positive impact of $7.6 million on operating cash flow. The remainder of the increase was the result of working capital adjustments, none of which were individually significant.

Net cash used in investing activities increased compared to the prior year period primarily due to increased capital spending in 2018 relative to 2017, which we expected. Partially offsetting a $18.2 million increase in capital spending compared to the prior year period were sales of long-term assets; however, there was a reduction in the total proceeds from the sale of long-term assets in the current six month period compared to the prior year period, accounting for the remainder of the increase in net cash used in investing activities.

Net cash used in financing activities decreased by approximately $5.7 million in the six month period ended June 30, 2018 compared to the prior year period, despite quarterly distributions to unitholders increasing by approximately $7.3 million in the current year period. The decrease in net cash used in financing activities compared to the prior year period was primarily the result of a decrease in cash remitted to our Sponsor(s) representing their portion of earnings in the Anchor, Growth and Additional Systems. See Item 1. Consolidated Financial Statements, Note 5–Related Party for additional information. In addition, the activities described under Indebtedness below also affected net cash from financing activities, but were not material on a net cash basis.

Indebtedness

Revolving Credit Facility

On March 8, 2018, we entered into a $600.0 million secured revolving credit facility with an accordion feature that allows, subject to certain terms and conditions, the Partnership to increase the available borrowings under the facility by up to an additional $250.0 million. The new revolving credit facility matures on March 8, 2023 and replaced the prior $250.0 million revolving credit facility, which was unsecured. The available borrowing capacity under the revolving credit facility is limited by certain financial covenants pertaining to leverage and interest coverage ratios as defined in the revolving credit facility agreement.

Borrowings under the new revolving credit facility bear interest at our option at either:

• the base rate, which is the highest of (i) the federal funds open rate plus 0.50%, (ii) PNC Bank, N.A.’s prime rate, and (iii) the one-month LIBOR rate plus 1.0%, in each case, plus a margin ranging from 0.75% to 1.75%; or

• the LIBOR rate, which is the LIBOR rate plus a margin ranging from 1.75% to 2.75%.

We incurred a total of $1.3 million in interest expense related to both revolving credit facilities (not including amortization of revolver fees) during the six months ended June 30, 2018.

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As of June 30, 2018, we had an outstanding balance on our new revolving credit facility of $11.0 million. After giving effect to the limitations on available capacity described in the revolving credit facility agreement, we estimate that we had $494.0 million available for borrowing at June 30, 2018.

For additional information on our revolving credit facility, see Item 1. Consolidated Financial Statements, Note 10–Revolving Credit Facility, which is incorporated herein by reference.

Senior Notes due 2026

On March 16, 2018, the Partnership completed a private offering of $400.0 million in 6.500% senior notes due 2026 (the “Senior Notes”), and received net proceeds of approximately $393.0 million, after deducting the initial purchasers’ discount and commissions and estimated offering expenses, which are recorded in our consolidated balance sheet as a reduction to the principal amount. Proceeds from the Senior Notes offering were primarily used to fund the Shirley-Penns Acquisition and repay existing indebtedness under our revolving credit facility.

The Senior Notes mature on March 15, 2026 and accrue interest at a rate of 6.500% per year, which is payable semi-annually in arrears on March 15 and September 15, beginning September 15, 2018. We incurred $7.6 million of interest expense (not including amortization of capitalized bond issue costs) on the Senior Notes during the six months ended June 30, 2018.

For additional information regarding our Senior Notes, see Item 1. Consolidated Financial Statements, Note 11–Long-Term Debt, which is incorporated herein by reference.

Capital Expenditures

The midstream energy business is capital intensive and requires maintenance of existing gathering systems and other midstream assets and facilities, as well as the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Our partnership agreement requires that we categorize our capital expenditures as either:

• Maintenance capital expenditures, which are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long term, our operating capacity, operating income or revenue. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines, to maintain equipment reliability, integrity and safety and to comply with environmental laws and regulations. In addition, we designate a portion of our capital expenditures to connect new wells to maintain gathering throughput as maintenance capital to the extent such capital expenditures are necessary to maintain, over the long term, our operating capacity, operating income or revenue; or

• Expansion capital expenditures, which are cash expenditures to construct new midstream infrastructure and those expenditures incurred in order to extend the useful lives of our assets, reduce costs, increase revenues or increase system throughput or capacity from current levels, including well connections that increase existing system throughput. Examples of expansion capital expenditures include the construction, development or acquisition of additional gathering pipelines and compressor stations, in each case to the extent such capital expenditures are expected to expand our operating capacity, operating income or revenue. In the future, if we make acquisitions that increase system throughput or capacity, the associated capital expenditures may also be considered expansion capital expenditures.

Capital Expenditures for the Six Months Ended June 30, 2018

	Anchor		Growth			Additional		TOTAL
Capital Investment
Maintenance capital	$	8,033	$	218		$	1,115	$	9,366
Expansion capital	30,257		(98		)	2,062		32,221
Total Capital Investment	$	38,290	$	120		$	3,177	$	41,587
Capital Investment Net to the Partnership
Maintenance capital	$	8,033	$	11		$	56	$	8,100
Expansion capital	30,257		(5		)	103		30,355
Total Capital Investment Net to the Partnership	$	38,290	$	6		$	159	$	38,455

We anticipate that we will continue to make expansion capital expenditures in the future. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives.

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We expect that any significant future expansion capital expenditures will be funded by borrowings under our revolving credit facility and/or the issuance of debt and equity securities.

Cash Distributions

Under our current cash distribution policy, we intend to pay a minimum quarterly distribution of $0.2125 per unit, which equates to an aggregate distribution of approximately $13.8 million per quarter, or approximately $55.2 million per year, based on the general partner interest and the number of common units outstanding as of June 30, 2018.  However, we do not have a legal or contractual obligation to pay distributions quarterly or on any other basis at our minimum quarterly distribution rate or at any other rate. Under our cash distribution policy, the decision to make a distribution as well as the amount of any distribution is determined by our general partner, taking into consideration the terms of the partnership agreement.

On July 27, 2018, the board of directors of our general partner declared a cash distribution to our unitholders of $0.3361 per common unit with respect to quarter ended June 30, 2018. The cash distribution will be paid on August 14, 2018 to unitholders of record as of the close of business on August 7, 2018.

For additional information on our cash distribution policy, see Item 1. Consolidated Financial Statements, Note 3–Cash Distributions, which is incorporated herein by reference.

Insurance Program

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

Off-Balance Sheet Arrangements

We do not maintain any off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources which are not disclosed in the notes to the unaudited consolidated financial statements of this Quarterly Report on Form 10-Q.

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Contractual Obligations

For a discussion of total debt outstanding under our revolving credit facility, see Item 1. Consolidated Financial Statements, Note 10–Revolving Credit Facility and for the total long-term debt outstanding under our Senior Notes see Note 11–Long-Term Debt, which is incorporated herein by reference.

Critical Accounting Policies

For a description of the Partnership’s accounting policies and any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements, see Item 1. Consolidated Financial Statements, Note 2–Significant Accounting Policies–Recent Accounting Pronouncements, which is incorporated herein by reference.  The application of the Partnership’s accounting policies may require management to make judgments and estimates about the amounts reflected in the Consolidated Financial Statements. If applicable, management uses historical experience and all available information to make these estimates and judgments. Different amounts could be reported using different assumptions and estimates.

As of June 30, 2018, the Partnership did not have any accounting policies that we deemed to be critical or that would require significant judgment.

Forward-Looking Statements

This report contains forward-looking statements. Statements that are predictive in nature, that depend upon or refer to future events or conditions or that include the words “believe,” “expect,” “anticipate,” “intend,” “estimate,” “will” and other expressions that are predictions of or indicate future events and trends and that do not relate to historical matters identify forward-looking statements. Our forward-looking statements include statements about our business strategy, our industry, our future profitability, our expected capital expenditures and the impact of such expenditures on our performance, the costs of being a publicly traded partnership and our capital programs.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. You are cautioned not to place undue reliance on any forward-looking statements, as these statements involve risks, uncertainties and other factors that could cause our actual future outcomes to differ materially from those set forth in such 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:

• our reliance on our customers, including our Sponsor;

• the effects of changes in market prices of natural gas, NGLs and crude oil on our customers’ drilling and development plans on our dedicated acreage and the volumes of natural gas and condensate that are produced on our dedicated acreage;

• changes in our customers’ drilling and development plans in the Marcellus Shale and Utica Shale;

• our customers’ ability to meet their drilling and development plans in the Marcellus Shale and Utica Shale;

• the demand for natural gas and condensate gathering services;

• changes in general economic conditions;

• competitive conditions in our industry;

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

• our ability to successfully implement our business plan;

• our ability to complete internal growth projects on time and on budget;

• the price and availability of debt and equity financing;

• the availability and price of oil and natural gas to the consumer compared to the price of alternative and competing fuels;

• competition from the same and alternative energy sources;

• energy efficiency and technology trends;

• operating hazards and other risks incidental to our midstream services;

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

• interest rates;

• labor relations;

• defaults by our customers under our gathering agreements;

• changes in availability and cost of capital;

• changes in our tax status;

• the effect of existing and future laws and government regulations;

• the effects of future litigation; and

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• certain factors discussed elsewhere in this report.

You should not place undue reliance on our forward-looking statements. Although forward-looking statements reflect our good faith beliefs at the time they are made, forward-looking statements involve known and unknown risks, uncertainties and other factors, including the factors described under “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2017, and in our other Quarterly Reports on Form 10-Q filed with respect to the year ending December 31, 2018, which may cause our actual results, performance or achievements to differ materially from anticipated future results, performance or achievements expressed or implied by such forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changed circumstances or otherwise, unless required by law.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

We generate substantially all of our revenues pursuant to fee-based gathering agreements under which we are paid based on the volumes that we gather and compress, rather than the underlying value of the commodity. Consequently, our existing operations and cash flows do not have significant direct exposure to commodity price risk. However, the producers that are customers of our midstream services are exposed to commodity price risk, and an extended reduction in commodity prices could adversely impact the production volumes available for our midstream services in the future. Although we intend to enter into fee-based gathering agreements with existing or new customers in the future, our efforts to negotiate such terms may not be successful.

In the future, we may acquire or develop additional midstream assets in a manner that increases our exposure to commodity price risk. Such exposure to the volatility of natural gas, NGL and crude oil prices could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders.

Interest Rate Risk

We maintain a $600.0 million secured revolving credit facility and pay interest at a variable rate. Assuming the June 30, 2018 outstanding balance on our revolving credit facility of $11.0 million was outstanding for the entire year, an increase of one percentage point in the interest rates would have resulted in an increase to interest expense of $0.1 million. Accordingly, our results of operations, cash flows and financial condition, all of which affect our ability to make cash distributions to our unitholders, could be materially adversely affected by significant increases in interest rates.

Credit Risk

We are subject to credit risk due to the concentration of receivables from our two most significant customers, CNX and HG Energy, for gas gathering services. We generally do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us, or their insolvency or liquidation, may adversely affect our financial results.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of management of our general partner, including the principal executive officer and principal financial officer of our general partner, an evaluation of the Partnership’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (“Exchange Act”)) was conducted as of the end of the period covered by this Quarterly Report on Form 10-Q.  Based upon this evaluation, the chief executive officer and chief financial officer of our general partner have concluded that the Partnership’s disclosure controls and procedures were effective as of the end of the period covered by this Quarterly Report on Form 10-Q.

Changes in Internal Control over Financial Reporting

There were no changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the second quarter of 2018 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

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PART II: OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Refer to Part I, Item 1. Consolidated Financial Statements, Note 12–Commitments and Contingencies, which is incorporated herein by reference.

ITEM 1A. RISK FACTORS

Information regarding risk factors is discussed in Item 1A, “Risk Factors” of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2017 and in our other Quarterly Report on Form 10-Q for the quarter ended March 31, 2018. These risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may adversely affect our business, financial condition, cash flows or results of operations.

There have been no material changes from the risk factors previously disclosed by the Partnership.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Not applicable.

ITEM 3.     DEFAULTS UPON SENIOR SECURITIES

Not applicable.

ITEM 4.     MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5.     OTHER INFORMATION

On March 16, 2018, in connection with the Shirley-Penns Acquisition, we entered into Amendment No. 1 (“Amendment No. 1”) to our January 3, 2018 gathering agreement with CNX Gas (the “CNX Gas GGA”) to add a minimum volume commitment (“MVC”) on volumes associated with the Shirley-Penns system through December 31, 2031. The MVC commits CNX Gas to pay the Partnership the wet gas rate under the CNX Gas GGA for all natural gas we gather up to a specified amount per day through December 31, 2031.

On May 2, 2018, we entered into the Second Amendment (“Amendment No. 2”) to the CNX Gas GGA to, among other things, increase the MVC under the CNX Gas GGA to include volumes associated with the Majorsville Area, which consists of acreage located in Greene and Washington Counties, Pennsylvania and Marshall County, West Virginia.

On May 15, 2018, we entered into the Third Amendment (“Amendment No. 3”) to the CNX Gas GGA to, among other things, authorize the Partnership to enroll and participate in certain demand response programs for the benefit of CNX Gas in order to lower CNX Gas’ electricity costs related to the services that we provide under the CNX Gas GGA.

The foregoing descriptions of Amendment No. 1, Amendment No. 2 and Amendment No. 3 are each qualified in their entirety by reference to the full text of the respective amendment, a copy of each of which is filed with this Quarterly Report on Form 10-Q as Exhibit 10.1, Exhibit 10.2 and Exhibit 10.3, respectively, and the full text of the CNX Gas GGA, a copy of which is filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, filed on January 3, 2018.

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ITEM 6. EXHIBITS

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number	Exhibit	Filing Date
10.1†	First Amendment to the Second Amended and Restated Gathering Agreement, entered into on and as of March 16, 2018, by and between CNX Gas Company LLC and Gatherer (as defined in the Original Agreement), filed herewith.
10.2†	Second Amendment to the Second Amended and Restated Gathering Agreement, entered into on and as of May 2, 2018, by and between CNX Gas Company LLC and Gatherer (as defined in the Original Agreement), filed herewith.
10.3†	Third Amendment to the Second Amended and Restated Gathering Agreement, entered into on and as of May 15, 2018, by and between CNX Gas Company LLC and Gatherer (as defined in the Original Agreement), filed herewith.
31.1†	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934
31.2†	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934
32.1‡	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350
32.2‡	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350
101.INS†	XBRL Instance Document.
101.SCH†	XBRL Taxonomy Extension Schema Document.
101.CAL†	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF†	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB†	XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE†	XBRL Taxonomy Extension Presentation Linkbase Document.

* Incorporated by reference into this Quarterly Report on Form 10-Q as indicated.

^† Filed herewith.

^‡ Furnished herewith.

40

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on August 2, 2018.

CNX MIDSTREAM PARTNERS LP
By:	CNX MIDSTREAM GP, LLC, its general partner
By:	/S/ NICHOLAS J. DEIULIIS
	Nicholas J. DeIuliis
	Chief Executive Officer and Chairman of the Board (Duly Authorized Officer and Principal Executive Officer)
By:	/S/ DONALD W. RUSH
	Donald W. Rush
	Chief Financial Officer and Director (Duly Authorized Officer and Principal Financial Officer)
By:	/S/ BRIAN R. RICH
	Brian R. Rich
	Chief Accounting Officer (Duly Authorized Officer and Principal Accounting Officer)

41

EX-10.1

Execution Version

FIRST AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT

This FIRST AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT (as the same may be amended from time to time in accordance herewith, this “Amendment”) is made and effective on and as of this 16^th day of March, 2018 (the “Execution Date”), by and between CNX Gas Company LLC, a Virginia limited liability company (“Shipper”), and Gatherer (as defined in the Original Agreement). Shipper and Gatherer are sometimes together referred to in this Amendment as the “Parties” and individually as a “Party.”

RECITALS:

A.Shipper and Gatherer entered into that certain Second Amended and Restated Gathering Agreement dated January 3, 2018 (the “Original Execution Date”, and such agreement, as amended, the “Original Agreement”).

B.CNX Midstream Partners LP, a Delaware limited partnership, CNX Midstream DevCo I LP, a Delaware limited partnership (“DevCo I LP”), CNX Midstream DevCo III LP, a Delaware limited partnership (“DevCo III LP”), and CNX Gathering LLC, a Delaware limited liability company, have entered into that certain Purchase and Sale Agreement, dated as of February 7, 2018, pursuant to which DevCo I will acquire certain assets currently held by DevCo III in the Shirley Penns Area (the “Purchase”).

C.In connection with the consummation of the Purchase, the Parties now desire to amend the Original Agreement in accordance with the terms and conditions of this Amendment.

AGREEMENTS:

NOW, THEREFORE, in consideration of the mutual agreements, covenants, and conditions in this Amendment contained, Gatherer and Shipper hereby agree as follows:

1. New Definitions. The following definitions shall be inserted into Section 1.1 of the Original Agreement in the appropriate place, accounting for alphabetical order:

“Adjusted Quarterly Shirley Penns Gas Volume Deliveries” means, for any Quarter, the sum of the following for such Quarter:

(i)    the Dedicated Gas received at Receipt Points on the Shirley Penns System during such Quarter; and

(ii)    any Dedicated Gas made available for Tender at a Receipt Point on the Shirley Penns System that was not accepted by Gatherer, unless Gatherer was expressly excused from providing Gas Services for such Dedicated Gas pursuant to the terms and conditions of this Agreement.

“Base Shirley Penns Fee” has the meaning given to it in Exhibit B-13(b).

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US-DOCS\99618598.2

“Pennsboro Sub Area” means the area identified on the Shirley Penns Map as the “Pennsboro Sub Area.”

“Quarterly Shirley Penns Gas Volume Commitment” means, with respect to any Quarter during the Shirley Penns MVC Period, the product of the number of Days in such Quarter multiplied by the applicable daily volume commitment set forth on Exhibit B-13(c); provided that, in the event that any Force Majeure occurs during any Quarter, the Quarterly Shirley Penns Gas Volume Commitment with respect to such Quarter shall be reduced by an amount equal to the volumes of Dedicated Gas made available for Tender at a Receipt Point on the Shirley Penns System that were not accepted by Gatherer as a result of such event of Force Majeure.

“Shirley Penns Credit” means, for any Month, the quotient obtained by dividing (i) the lesser of (A) the amount of the Shirley Penns Gas Deficiency Payment Bank as of end of the previous Quarter and (B) the product of (I) the Shirley Penns Gas Surplus for the previous Quarter and (II) the Gas Gathering Fee applicable during such Month for Gas Services provided for Dedicated Gas on the Shirley Penns System, by (ii) three.

“Shirley Penns Cumulative Gas Deficiency” has the meaning given to it in Section 3.2(h)(i).

“Shirley Penns Gas Deficiency Payment” has the meaning given to it in Section 3.2(h)(i).

“Shirley Penns Gas Deficiency Payment Bank” means, as of the end of any Quarter, the sum of the Shirley Penns Gas Deficiency Payments for each Quarter since January 1, 2018, less the amount of Shirley Penns Credits applied pursuant to Section 3.2(h) towards Gas Gathering Fees otherwise payable Producer.

“Shirley Penns Gas Surplus” has the meaning given to it in Section 3.2(h)(ii).

“Shirley Penns Map” means the map set forth on Exhibit B-13(a), attached to, and made a part of, this Agreement.

“Shirley Penns MVC Period” means the period beginning on (and including) January 1, 2018 and ending on (and including) December 31, 2031.

“Shirley Penns Pressure Service” means, with respect to each Receipt Point on the Shirley Penns System and as of any Day, provision of sufficient compression by Gatherer to receive Dedicated Production delivered at such Receipt Point such that Gatherer maintains an Average Pressure at such Receipt Point during each Day of not greater than the applicable Shirley Penns Required Pressure for such Receipt Point as of such Day.

“Shirley Penns Quarterly Gas Deficiency” has the meaning given to it in Section 3.2(h)(i).

“Shirley Penns Required Pressure” means, (i) with respect to each Receipt Point on the Shirley Penns System that is located in the Shirley Sub Area, the sum of the required pressure as specified on Exhibit P based on Shipper’s volumetric throughput on such portion of the Shirley Penns System plus 175 Psig and (ii) with respect to each Receipt Point on the Shirley Penns System

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that is located in the Pennsboro Sub Area, the sum of the required pressure as specified on Exhibit P based on Shipper’s volumetric throughput on such portion of the Shirley Penns System plus 260 Psig.

“Shirley Sub Area” means the area identified on the Shirley Penns Map as the “Shirley Sub Area.”

2. Revised Definitions.

(a) The definition of “Compression Services” in Section 1.1 of the Original Agreement shall be replaced in its entirety with the following:

“Compression Services” means compression services provided on an applicable Individual System in order to: (a) with respect to Execution Date Compression Receipt Points, provide Existing Pressure Service, unless Gatherer is excused from providing Existing Pressure Service for such Execution Date Compression Receipt Points under Section 6.4(b); (b) with respect to those Receipt Points at which Gatherer is to provide Tier 1 Pressure Service as set forth in Sections 6.4(e), 6.4(f) and 6.4(g), provide such Tier 1 Pressure Service; (c) with respect to those Receipt Points at which Gatherer is to provide Tier 2 Pressure Service as set forth in Sections 6.4(e), 6.4(f) and 6.4(g) provide such Tier 2 Pressure Service, and (d) with respect to Receipt Points on the Shirley Penns System, provide Shirley Penns Pressure Service, in each case in accordance with the terms of this Agreement. For the avoidance of doubt, the services described in subsections (a), (b), (c) and (d) of this definition are the only Compression Services that Gatherer is obligated to provide under this Agreement.

(b) The definition of “Condensate Services” in Section 1.1 of the Original Agreement shall be replaced in its entirety with the following:

“Condensate Services” means, (a) with respect to the Majorsville System: (i) the receipt of Dedicated Liquid Condensate at the Majorsville System’s Receipt Point; (ii) the collection, injection, gathering and stabilization of such Liquid Condensate; (iii) the handling, storage, loading, and re-delivery at the applicable Majorsville System Delivery Point of such Liquid Condensate for Shipper’s account; and (iv) the other services to be performed by Gatherer in respect of such Liquid Condensate as set forth in this Agreement, all in accordance with the terms of this Agreement; (b) with respect to the ACAA System: (i) the receipt of Dedicated Liquid Condensate at the Receipt Points on the ACAA System; and (ii) the gathering and redelivery of such Liquid Condensate at the applicable ACAA System Delivery Point all in accordance with the terms of this Agreement; and (c) with respect to the Shirley Penns System (i) the receipt of Dedicated Liquid Condensate at the Receipt Points on the Shirley Penns System; (ii) the collection, injection, gathering and stabilization of such Liquid Condensate; (iii) the handling, storage, loading, and re-delivery at the applicable Shirley Penns System Delivery Point of such Liquid Condensate for Shipper’s account; and (iv) the other services to be performed by Gatherer in respect of such Liquid Condensate as set forth in this Agreement, all in accordance with the terms of this Agreement. For the avoidance of doubt, Gatherer has no obligation to provide Liquid Condensate Services at any Individual Systems other than the Majorsville System, the ACAA System and the Shirley Penns System.

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(c) The definition of “Dedicated Liquid Condensate” in Section 1.1 of the Original Agreement shall be replaced in its entirety with the following:

“Dedicated Liquid Condensate” means (a) Liquid Condensate produced from the Dedicated Properties and located in the ACAA Area, the Majorsville Area and/or the Shirley Penns Area and (b) Third Party Liquid Condensate under the Control of Shipper and/or its Affiliate(s) produced from Wells and Planned Wells operated by Shipper or any of its Affiliates in the ACAA Area, the Majorsville Area and/or the Shirley Penns Area.

(d)    The definition of “Liquid Condensate” in Section 1.1 of the Original Agreement shall be replaced in its entirety with the following:

“Liquid Condensate” means liquid hydrocarbons separated (mechanically or otherwise) from Gas at or near a well pad upstream of a receipt point on the ACAA System, the Majorsville System or the Shirley Penns System, as applicable, and injected into such Individual System by Shipper (or another shipper) at a receipt point on such Individual System.

(e)    The definition of “Tender” in Section 1.1 of the Original Agreement shall be replaced in its entirety with the following:

“Tender” means (a) with respect to Gas, the act of Shipper’s making Gas available or causing Gas to be made available to an Individual System at a Receipt Point on such Individual System and (b) with respect to Liquid Condensate, the act of Shipper’s injection or causing the Liquid Condensate to be injected into an Individual System at a Receipt Point on such Individual System; provided Liquid Condensate will only be Tendered at Receipt Points on those Individual Systems where Gatherer is providing Condensate Services (i.e., the ACAA System, the Majorsville System and the Shirley Penns System). “Tendered” shall have the correlative meaning.

3. Dedication of Shirley Penns Liquid Condensate.

(a) Sections 2.1(a) and 2.1(b) of the Original Agreement shall be replaced in their entireties with the following:

(a)    exclusively dedicates to this Agreement the Dedicated Properties and commits to deliver to Gatherer under this Agreement, as and when produced, all of the (i) Gas owned by Shipper and/or its Affiliates produced during the Term from the Dedicated Properties, (ii) Liquid Condensate owned by Shipper and/or its Affiliates produced during the Term from the Dedicated Properties that are located in the ACAA Area, the Majorsville Area and/or the Shirley Penns Area (and not any other Dedicated Properties) and (iii) Gas owned by Shipper and/or its Affiliates produced during the Term from the Legacy Wells;

(b)    commits to deliver to Gatherer under this Agreement, as and when produced (i) all of the Third Party Gas under the Control of Shipper and/or its Affiliates produced during the Term from Wells (whether now existing or hereafter drilled) now or hereafter operated by Shipper or any of its Affiliates, (ii) all of the Third Party Liquid Condensate under the Control of Shipper and/or its Affiliates produced during the Term from Wells

4

(whether now existing or hereafter drilled) now or hereafter operated by Shipper or any of its Affiliates located in the ACAA Area, the Majorsville Area and/or the Shirley Penns Area (and not any other Dedicated Properties) and (iii) all of the Third Party Gas under the Control of Shipper produced during the Term from the Legacy Wells; and

(b) The last sentence of Section 3.7 of the Original Agreement shall be replaced in its entirety with the following:

In addition, Gatherer shall use commercially reasonable efforts to include the requirements of the first three (3) sentences of this Section 3.7 in its agreements with other shippers with respect to Liquid Condensate to be gathered on the ACAA System, the Majorsville System and the Shirley Penns System (provided that Gatherer shall not be required to make any payments to any third party in the pursuit of the satisfaction of such obligation), shall use commercially reasonable efforts to enforce such requirements in all such agreement(s), and shall maintain records regarding all such Third Party Liquid Condensate measurements and allocations for a period of at least 24 Months.

(c) The last sentence of Section 4.3 of the Original Agreement shall be replaced in its entirety with the following:

Shipper shall have the right to Tender to Gatherer for Gathering Services under this Agreement, at then-existing Receipt Points, Gas and/or Liquid Condensate other than Dedicated Production; provided that, (a) any such Gas and/or Liquid Condensate shall not be entitled to Priority One Service or Priority Two Service but rather shall be provided Gathering Services on an Interruptible Basis only (though all such Gas and Liquid Condensate, once received into a Receipt Point, shall be treated as Dedicated Production for all other purposes of this Agreement other than curtailment), and (b) any such Liquid Condensate can only be Tendered to Receipt Points on the ACAA System, the Majorsville System and the Shirley Penns System.

(d) The last sentence of Section 5.1(b) of the Original Agreement shall be replaced in its entirety with the following:

For the avoidance of doubt, the ACAA System, the Majorsville System and the Shirley Penns System are the only Individual Systems which shall gather Dedicated Liquid Condensate.

(e) The last sentence of Section 1.4(i) of Exhibit A to the Original Agreement shall be replaced in its entirety with the following:

Shipper shall instead deliver Liquid Condensate, on those Individual Systems providing Condensate Services (i.e., the ACAA System, the Majorsville System and the Shirley Penns System), through the Measurement Devices

5

for Liquid Condensate, in accordance with the provisions of Section 3.7of the Agreement.

(f) Sections 1.8(c) and 1.8(d) of Exhibit A to the Original Agreement shall be replaced in their entireties with the following:

(c)    Liquid Condensate (including Dedicated Liquid Condensate) and Drip Condensate on those Individual Systems providing Condensate Services (i.e., the ACAA System, the Majorsville System and the Shirley Penns System) shall be allocated as follows: The volumes of Liquid Condensate (including Dedicated Liquid Condensate) and Drip Condensate delivered at the Delivery Points for the Individual System, as determined by the applicable Downstream Pipeline or trucking company receiving such Liquid Condensate (including Dedicated Liquid Condensate) and/or Drip Condensate at such Delivery Point, shall be allocated to each receipt point (including Receipt Points) on the Individual System based on the volumes of Liquid Condensate (including Dedicated Liquid Condensate) and Drip Condensate received at each receipt point as a percentage of all volumes of Liquid Condensate (including Dedicated Liquid Condensate) and Drip Condensate received at all receipt points on such Individual System, subject to any adjustments made by Gatherer in good faith to more accurately allocate such Liquid Condensate (including Dedicated Liquid Condensate) and Drip Condensate.

(d)    Drip Condensate on all Individual Systems other than the ACAA System, the Majorsville System and the Shirley Penns System, shall be allocated as follows: The volumes of Drip Condensate delivered at the Delivery Points for an Individual System, as determined by the applicable Downstream Pipeline (if any) or trucking company receiving such Drip Condensate at such Delivery Point, shall be allocated to each receipt point (including Receipt Points) on the Individual System based on the hexanes plus liquid hydrocarbon content and volume of the Gas received at such receipt point as a percentage of the hexanes plus liquid hydrocarbon content and volume of all Gas received at all receipt points on such Individual System, subject to any adjustments made in good faith to more accurately allocation all such Drip Condensate.

4. Limitation on Dedication of Shirley Penns Liquid Condensate. Section 2.4(f) of the Original Agreement shall be replaced in its entirety with the following:

(f)    to retain and not deliver to the applicable Individual System (i) all Dedicated Liquid Condensate that is in excess of the amount of Liquid Condensate with Priority One Service that is capable of being gathered, and, as applicable, collected, stored and/or stabilized in the facilities comprising the applicable Individual System (i.e., the ACAA System, the Majorsville System or the Shirley Penns System); (ii) all Dedicated Liquid Condensate that is caught prior to delivery at the Receipt Points on the ACAA System, the Majorsville System or the Shirley Penns System during flowback operations with respect to any Well or otherwise related to mechanical failures of liquid separation on the Well Pad (provided that Shipper shall use commercially reasonable efforts to mitigate any such mechanical failures that occur); and (iii) all Dedicated Liquid Condensate that is extracted at the Well Pad prior to delivery at the Receipt Points in the ACAA System, the Majorsville

6

System or the Shirley Penns System as a result of the inability of the applicable Individual System to provide Condensate Services for such Dedicated Liquid Condensate (including inability of the Shirley Penns System due to a lack of sufficient capacity at the Shirley Station);

5. Shirley Penns Minimum Volume Commitment. The following text shall be inserted immediately after Section 3.2(g) in the Original Agreement as Section 3.2(h):

(h)    Shirley Penns Minimum Volume Commitment.

(i) For each Quarter during the Shirley Penns MVC Period, if at the end of any such Quarter, (A) the Quarterly Shirley Penns Gas Volume Commitment for such Quarter exceeds the Adjusted Quarterly Shirley Penns Gas Volume Deliveries for such Quarter (the amount of such excess, if any, the “Shirley Penns Quarterly Gas Deficiency” for such Quarter) and (B) aggregate Quarterly Shirley Penns Gas Volume Commitments for such Quarter and all prior Quarters since January 1, 2018 exceed the aggregate Adjusted Quarterly Shirley Penns Gas Volume Deliveries for such Quarter and all prior Quarters since January 1, 2018 (the amount of such excess, if any, the “Shirley Penns Cumulative Gas Deficiency” for such Quarter), Producer shall pay Gatherer an amount (the “Shirley Penns Gas Deficiency Payment” for such Quarter) equal to the product of (A) the lesser of the Shirley Penns Quarterly Gas Deficiency for such Quarter and the Shirley Penns Cumulative Gas Deficiency as of such Quarter and (B) the Gas Gathering Fee applicable during such Quarter for Gas Services provided for Dedicated Gas on the Shirley Penns System.

(ii) Notwithstanding anything to the contrary herein, at the end of any Quarter during the Shirley Penns MVC Period, in the event that (A) there is a positive balance in the Shirley Penns Gas Deficiency Payment Bank and (B) the Adjusted Quarterly Shirley Penns Gas Volume Deliveries for such Quarter exceed the Quarterly Shirley Penns Gas Volume Commitment for such Quarter (the amount of such excess, if any, the “Shirley Penns Gas Surplus” for such Quarter), Producer shall be entitled to credit against amounts otherwise payable by Producer hereunder for each of the three Months after such Quarter an amount, in the aggregate, equal to the Shirley Penns Credit for such Month.

6. Fee Adjustments for Failure to Provide Shirley Penns Pressure Service. Section 5.2(c) of the Original Agreement shall be replaced in its entirety with the following:

(c)    This Section 5.2(c) applies only to Dedicated Gas produced from Wells connected to Receipt Points with respect to which Gatherer is providing (or is obligated to provide) Existing Pressure Service, Tier 1 Pressure Service, Tier 2 Pressure Service or Shirley Penns Pressure Service pursuant to the provisions of this Agreement (all such Dedicated Gas herein the “Compression Obligation Gas”). After the first Day upon which Gatherer

7

is obligated to provide such Compression Services for Compression Obligation Gas received at the applicable Receipt Point receiving such Compression Obligation Gas (the “Compression Obligation Receipt Point”), if during any Day, the Average Pressure exceeds the Existing Required Pressure at a Compression Obligation Receipt Point for which Gatherer is providing Existing Pressure Service, six hundred (600) Psig at a Compression Obligation Receipt Point for which Gatherer is providing Tier 1 Pressure Service, three hundred (300) Psig at a Compression Obligation Receipt Point for which Gatherer is providing Tier 2 Pressure Service or the Average Pressure exceeds the applicable Shirley Penns Required Pressure at a Compression Obligation Receipt Point for which Gatherer is providing Shirley Penns Pressure Service (the “Target Pressure”), then (i) the applicable Gas Gathering Fee for Compression Obligation Gas received at such Compression Obligation Receipt Point shall be reduced for such Day based on the calculation of the Pressure Overage Percentage, as set forth in Exhibit I, and (ii) the applicable Compression Fee for Compression Obligation Gas received at such Compression Obligation Receipt Point shall be $0. The Gas Gathering Fee and Compression Fee reduction under this Section 5.2(c) constitutes the sole and exclusive remedy available to Shipper with respect to any failure by Gatherer to (i) cause the Average Pressure at any Compression Obligation Receipt Point to not exceed the Target Pressure for such Receipt Point, except as otherwise provided in Section 16.21, or (ii) commence the applicable Tier 1 Pressure Service or Tier 2 Pressure Service by the applicable Target Compression Date, except as otherwise provided in Section 16.21.

7. Shirley Penns Pressure Requirements.

(a)    Section 6.4(a) of the Original Agreement shall be replaced in its entirety with the following:

(a)Except for Execution Date Compression Receipt Points and Receipt Points on the McQuay System, on the Wadestown System and on the Shirley Penns System for which Gatherer is obligated hereunder to provide Compression Services, Gatherer shall receive Gas at each Receipt Point on each Individual System at Free Flow Pressure.

(b)    The following text shall be inserted immediately after Section 6.4(k) in the Original Agreement as Section 6.4(l):

(l) Shirley Penns Pressure Requirements. Notwithstanding anything to the contrary herein, unless Gatherer is otherwise obligated to provide Tier 1 Pressure Service or Tier 2 Pressure Service, as applicable, at any Receipt Point on the Shirley Penns System, Gatherer shall provide Shirley Penns Pressure Service for the Receipt Points on the Shirley Penns System.

8. Replacement of Exhibit B-13(a) (Shirley Penns Map). Exhibit B-13(a) to the Original Agreement shall be replaced in its entirety with Exhibit B-13(a) attached hereto.

9. Replacement of Exhibit B-13(b) (Shirley Penns Fees). Exhibit B-13(b) to the Original Agreement shall be replaced in its entirety with Exhibit B-13(b) attached hereto.

8

10. Addition of Exhibit B-13(c) (Shirley Penns Minimum Commitment Daily Volumes). Exhibit B-13(c) attached hereto shall be added to the Original Agreement.

11. Replacement of Exhibit M (Initial Well Development Schedule). Exhibit M to the Original Agreement shall be replaced in its entirety with Exhibit M attached hereto.

12. Replacement of Exhibit P (Compression Curves for Certain Systems). Exhibit P to the Original Agreement shall be replaced in its entirety with Exhibit P attached hereto.

13. Replacement of Exhibit R-1 (DevCo I Area). Exhibit R-1 to the Original Agreement shall be replaced in its entirety with Exhibit R-1 attached hereto.

14. Replacement of Exhibit R-3 (DevCo III Area). Exhibit R-3 to the Original Agreement shall be replaced in its entirety with Exhibit R-3 attached hereto.

15. Original Agreement. Except as modified herein, the Original Agreement remains in full force and effect in accordance with its terms.

16. Incorporation of Certain Terms. Capitalized terms used but not otherwise defined herein shall have the meanings ascribed to such terms in the Original Agreement. Sections 10.1 and 16.7 of the Original Agreement are incorporated by reference herein, mutatis mutandis.

[signature page follows]

9

Execution Version

IN WITNESS WHEREOF, the Parties hereto have executed this Amendment to be effective as of the Execution Date.

“Gatherer”

CNX MIDSTREAM DEVCO I LP

By: CNX Midstream DevCo I GP LLC, its general partner

By: /S/ Donald W. Rush    

Name: Donald W. Rush

Title: Chief Financial Officer

CNX MIDSTREAM DEVCO II LP

By: CNX Midstream DevCo II GP LLC, its general partner

By: /S/ Donald W. Rush    

Name: Donald W. Rush

Title: Chief Financial Officer

CNX MIDSTREAM DEVCO III LP

By: CNX Midstream DevCo III GP LLC, its general partner

By: /S/ Donald W. Rush    

Name: Donald W. Rush

Title: Chief Financial Officer

CNX MIDSTREAM OPERATING COMPANY, LLC

By: /S/ Donald W. Rush    

Name: Donald W. Rush

Title: Chief Financial Officer

Signature Page to First Amendment to

    Second Amended and Restated Gathering Agreement

“Shipper”

CNX GAS COMPANY LLC

By: /S/ Donald W. Rush    

Name: Donald W. Rush

Title: Senior Vice President and Chief Financial Officer

EXHIBIT A.

Signature Page to First Amendment to

    Second Amended and Restated Gathering Agreement

Execution Version

ATTACHED TO AND MADE PART OF THAT CERTAIN FIRST AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT BY AND BETWEEN CNX GAS COMPANY, LLC, AS SHIPPER, AND CNX MIDSTREAM DEV CO I, LP, CNX MIDSTREAM DEV CO II, LP, CNX MIDSTREAM DEV CO III, LP, AND CNX MIDSTREAM OPERATING COMPANY, LLC, COLLECTIVELY, AS GATHERER

EXHIBIT B-13(a)

SHIRLEY PENNS MAP

EXHIBIT B.See attached.

Exhibit B-13(a)

Execution Version

ATTACHED TO AND MADE PART OF THAT CERTAIN FIRST AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT BY AND BETWEEN CNX GAS COMPANY, LLC, AS SHIPPER, AND CNX MIDSTREAM DEV CO I, LP, CNX MIDSTREAM DEV CO II, LP, CNX MIDSTREAM DEV CO III, LP, AND CNX MIDSTREAM OPERATING COMPANY, LLC, COLLECTIVELY, AS GATHERER

EXHIBIT B-13(b)

SHIRLEY PENNS FEES

EXHIBIT C.See attached.

Exhibit B-13(b)

Execution Version

ATTACHED TO AND MADE PART OF THAT CERTAIN FIRST AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT BY AND BETWEEN CNX GAS COMPANY, LLC, AS SHIPPER, AND CNX MIDSTREAM DEV CO I, LP, CNX MIDSTREAM DEV CO II, LP, CNX MIDSTREAM DEV CO III, LP, AND CNX MIDSTREAM OPERATING COMPANY, LLC, COLLECTIVELY, AS GATHERER

EXHIBIT B-13(c)

SHIRLEY PENNS MINIMUM COMMITMENT DAILY VOLUMES

EXHIBIT D.See attached.

Exhibit B-13(c)

Execution Version

ATTACHED TO AND MADE PART OF THAT CERTAIN FIRST AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT BY AND BETWEEN CNX GAS COMPANY, LLC, AS SHIPPER, AND CNX MIDSTREAM DEV CO I, LP, CNX MIDSTREAM DEV CO II, LP, CNX MIDSTREAM DEV CO III, LP, AND CNX MIDSTREAM OPERATING COMPANY, LLC, COLLECTIVELY, AS GATHERER

EXHIBIT M

INITIAL WELL DEVELOPMENT SCHEDULE

EXHIBIT E.See attached.

Exhibit M-1

Execution Version

ATTACHED TO AND MADE PART OF THAT CERTAIN FIRST AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT BY AND BETWEEN CNX GAS COMPANY, LLC, AS SHIPPER, AND CNX MIDSTREAM DEV CO I, LP, CNX MIDSTREAM DEV CO II, LP, CNX MIDSTREAM DEV CO III, LP, AND CNX MIDSTREAM OPERATING COMPANY, LLC, COLLECTIVELY, AS GATHERER

EXHIBIT P

COMPRESSION CURVES FOR CERTAIN SYSTEMS

See attached.

Exhibit P-1

Execution Version

ATTACHED TO AND MADE PART OF THAT CERTAIN FIRST AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT BY AND BETWEEN CNX GAS COMPANY, LLC, AS SHIPPER, AND CNX MIDSTREAM DEV CO I, LP, CNX MIDSTREAM DEV CO II, LP, CNX MIDSTREAM DEV CO III, LP, AND CNX MIDSTREAM OPERATING COMPANY, LLC, COLLECTIVELY, AS GATHERER

EXHIBIT R-1

DEVCO I AREA

See attached.

Exhibit R-1

Execution Version

ATTACHED TO AND MADE PART OF THAT CERTAIN FIRST AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT BY AND BETWEEN CNX GAS COMPANY, LLC, AS SHIPPER, AND CNX MIDSTREAM DEV CO I, LP, CNX MIDSTREAM DEV CO II, LP, CNX MIDSTREAM DEV CO III, LP, AND CNX MIDSTREAM OPERATING COMPANY, LLC, COLLECTIVELY, AS GATHERER

EXHIBIT R-3

DEVCO III AREA

See attached.

Exhibit R-3

EX-10.2

Execution Version

SECOND AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT

This SECOND AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT (as the same may be amended from time to time in accordance herewith, this “Amendment”) is made and effective on and as of this 2nd day of May, 2018 (the “Execution Date”), by and between CNX Gas Company LLC, a Virginia limited liability company (“Shipper”), and Gatherer (as defined in the Original Agreement). Shipper and Gatherer are sometimes together referred to in this Amendment as the “Parties” and individually as a “Party.”

RECITALS:

A.Shipper and Gatherer entered into that certain Second Amended and Restated Gathering Agreement dated January 3, 2018 (the “Original Execution Date”, and such agreement, as amended by that certain First Amendment dated as of March 16, 2018, the “Original Agreement”).

B.Shipper and Gatherer have agreed to further amend the Original Agreement in order to reflect certain agreed revisions.

C.The Parties now desire to amend the Original Agreement in accordance with the terms and conditions of this Amendment.

AGREEMENTS:

NOW, THEREFORE, in consideration of the mutual agreements, covenants, and conditions in this Amendment contained, Gatherer and Shipper hereby agree as follows:

1. Certain Defined Terms. Section 1.1 of the Original Agreement is hereby amended to add the following defined terms, which shall be inserted in alphabetic order into the current definitions in Section 1.1 of the Original Agreement:

“BBtu” means one billion Btus.

“Majorsville/Mamont Credit” means $0.20/MMbtu, which amount is not subject to adjustment pursuant to Section 5.2.

“Majorsville/Mamont Development Costs” means, as of any time, the aggregate Capital Expenses incurred by Gatherer and its Affiliates either before or after the Execution Date in connection with the design, construction, installation, inspection, maintenance or monitoring of the Majorsville System and/or the Mamont System as of such time.

“Majorsville/Mamont Excess Well” means any Planned Well drilled and completed in the Majorsville/Mamont Minimum Well Area after Shipper has drilled and completed 40 Planned Wells in the Majorsville/Mamont Minimum Well Area that count towards the Majorsville/Mamont Minimum Well Requirement in the aggregate after July 1, 2018.

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US-DOCS\100242552.6

“Majorsville/Mamont Minimum Well Area” means the area described on the map on Exhibit B-18.

“Majorsville/Mamont Minimum Well Deficiency Obligation” has the meaning given to it in Section 3.2(h)(i).

“Majorsville/Mamont Minimum Well Period” has the meaning given to it in Section 3.2(h)(i).

“Majorsville/Mamont Minimum Well Requirement” has the meaning given to it in Section 3.2(h)(i).

“Majorsville/Mamont Surcharge” means $0.20/MMbtu, which amount is not subject to adjustment pursuant to Section 5.2.

“Utica Option Planned Well” has the meaning given to it in Section 3.1(i).

2. Utica Option Area Planned Wells. The following text shall be added as a new Section 3.1(i) immediately after Section 3.1(h) of the Original Agreement:

(i)    Notwithstanding anything to the contrary herein, each Development Report shall (a) identify each Planned Well to be located in the area identified on Exhibit B-1(b) as the “Option Area – Utica Formation” in either the Majorsville Area or the Mamont Area, and in either case, that is to be drilled and completed in the Utica Formation (a “Utica Option Planned Well”), and (b) provide all of the information that would be included with respect to such Utica Option Planned Well if such Utica Option Planned Well were included on Exhibit M. Within 45 days after its receipt of a Development Report identifying a new Utica Option Planned Well, Gatherer shall have the right but not the obligation to notify Shipper in writing that it elects not to provide Gathering Services for such Utica Option Planned Well. Gatherer’s failure to affirmatively notify Shipper in writing prior to the expiration of such period that it will not provide Gathering Services for such Utica Option Planned Well shall be deemed an election to provide Gathering Services for such Utica Option Planned Well. If Gatherer elects or is deemed to have elected to provide Gathering Services for such Utica Option Planned Well, such Utica Option Planned Well shall be deemed to be included on Exhibit M, provided that in no event shall the Target On-Line Date for such Utica Option Planned Well be earlier than the two year anniversary of the election of Gatherer to provide Gathering Services for such Utica Option Planned Well. Notwithstanding anything to the contrary herein, if Gatherer elects not to provide Gathering Services for any Utica Option Planned Well pursuant to this Section 3.2(i), such Utica Option Planned Well, the Dedicated Production from such Utica Option Planned Well, and the Dedicated Properties in the Drilling Unit applicable to such Utica Option Planned Well (but only as to the Utica Formation) shall be permanently released from dedication under this Agreement.

3. Change to Minimum Well Commitment.

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(A)    The caption of “Minimum Well Requirement” in Section 3.2(g) of the Original Agreement shall be replaced in its entirety with “Minimum Well Requirement (McQuay Area)”.

(B)    The phrase that states “for each such Planned Well which Shipper fails to drill and complete during such Year (the “Minimum Well Deficiency Obligation”)” immediately after the phrase “(the “Individual Well Deficiency Amount)” in the first sentence of 3.2(g)(i) shall be replaced in its entirety with the following:

for each such Planned Well which Shipper fails to drill and complete during such period (the “Minimum Well Deficiency Obligation”)”

(C)    The following text shall be inserted as a new Section 3.2(h) immediately after Section 3.2(g) of the Original Agreement:

(h)    Minimum Well Requirement (Majorsville/Mamont Minimum Well Area).

(i)In the event Shipper fails for any reason to drill and complete at least the following number of Planned Wells that are also Operated Wells and are not otherwise subject to a Conflicting Dedication in the Majorsville/Mamont Minimum Well Area during each period set forth in the table below (such minimum number of Planned Wells, herein the “Majorsville/Mamont Minimum Well Requirement” and each such period, a “Majorsville/Mamont Minimum Well Period”), then, for the Planned Wells which Shipper fails to drill and complete during such Majorsville/Mamont Minimum Well Period (the “Majorsville/Mamont Minimum Well Deficiency Obligation”), from and after the first Day after the expiration of such Majorsville/Mamont Minimum Well Period, Shipper shall pay to Gatherer the Majorsville/Mamont Surcharge on all quantities of Dedicated Gas receiving Gathering Services hereunder until such time as Gatherer has received Majorsville/Mamont Surcharges totaling $2,800,000 per Well included in the Majorsville/Mamont Minimum Well Deficiency Obligation. Notwithstanding anything to the contrary herein, in no event shall Shipper be obligated to pay Majorsville/Mamont Surcharges on any Day on quantities of Dedicated Gas in excess of the quantities identified on Exhibit T attached hereto for the relevant number of Wells included in the Majorsville/Mamont Minimum Well Deficiency Obligation for which Majorsville/Mamont Surcharges are owed as of such time. For the avoidance of doubt, any Majorsville/Mamont Surcharges paid by Shipper to Gatherer pursuant to this Section 3.2(h) shall, to the maximum extent possible, be made as cost reimbursements (within the meaning of Treasury Regulations Section 1.7704-4(c)(10)(i)) of Majorsville/Mamont Development Costs.

Majorsville/Mamont Minimum Well Period	7/1/2018 to 12/31/2020	1/1/2021 to 12/31/2023
Majorsville/Mamont Minimum Well Requirement	15	25

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(ii)In determining whether a Planned Well has been drilled and completed such that it will be applied towards the Majorsville/Mamont Minimum Well Requirement for a specific Majorsville/Mamont Minimum Well Period, (A) such Planned Well must be drilled and completed, (B) all Shipper’s Facilities connecting such Planned Well to the Receipt Point to be located on or near the Well Pad on which such Planned Well is to be located must be completed such that Shipper’s Facilities are ready to be connected to such Receipt Point(s), (C) no more than five Planned Wells that are drilled and completed in the Utica Formation may be counted towards the Majorsville/Mamont Minimum Well Requirement in the aggregate for both Majorsville/Mamont Minimum Well Periods, and (D) no Planned Well identified on Exhibit M as of the Execution Date that is to receive Gathering Services on either of the McQuay System or the Mamont System may be counted towards any Majorsville/Mamont Minimum Well Requirement. For purposes of this Section 3.2(h), such Planned Well will be deemed to have been “drilled and completed” in the Majorsville/Mamont Minimum Well Period in which the later of (A) and (B) in the immediately preceding sentence occurs with respect to such Planned Well. If during the first Majorsville/Mamont Minimum Well Period, Shipper drills and completes more than 15 Planned Wells in the Majorsville/Mamont Mininum Well Area, all such Planned Wells in excess of such Majorsville/Mamont Minimum Well Requirement will be applied against the second Majorsville/Mamont Minimum Well Period’s Majorsville/Mamont Minimum Well Requirement. If Shipper pays Majorsville/Mamont Surcharges for a Majorsville/Mamont Minimum Well Deficiency Obligation for either Majorsville/Mamont Minimum Well Period, for each Majorsville/Mamont Excess Well drilled and completed prior to December 31, 2024, Shipper shall be entitled to a refund of all Majorsville/Mamont Surcharges paid with respect to one Well included in the Majorsville/Mamont Minimum Well Deficiency Obligation. Such refund shall be applied as a credit in the amount of the Majorsville/Mamont Credit on all Gathering Fees payable with respect to quantities of Dedicated Gas receiving Gathering Services hereunder from and after the first Day of the first Month after such Planned Well satisfies the requirements of the first two sentences of this Section 3.2(h)(ii) until the full amount of Majorsville/Mamont Surcharges paid in respect of the applicable Well included in the Majorsville/Mamont Minimum Well Deficiency Obligations has been so credited, provided that in no event shall Shipper be entitled to Majorsville/Mamont Credits on any Day on quantities of Dedicated Gas in excess of the quantities identified on Exhibit T attached hereto for the relevant number of Majorsville/Mamont Excess Wells then creating Majorsville/Mamont Credits.

(iii)If any of Shipper’s activities required to drill and complete a Planned Well in the Majorsville/Mamont Minimum Well Area are delayed by Force Majeure during any Majorsville/Mamont Minimum Well Period, with respect to such Planned Well only, such Majorsville/Mamont Minimum Well Period will be extended by one Day for each Day of delay in drilling and completing such Planned Well that is attributable to Force Majeure, for purposes of determining any Majorsville/Mamont Minimum Well Deficiency Obligation for such Planned Well for such Majorsville/Mamont Minimum Well Period. As an example only, if, in the first Majorsville/Mamont Minimum Well Period, the Majorsville/Mamont Minimum Well Requirement is 15 Planned Wells, Shipper drills and completes ten Planned Wells in the Majorsville/Mamont Minimum Well Area, and drilling and completion of one

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Planned Well in the Majorsville/Mamont Minimum Well Area is delayed 31 Days by Force Majeure, Shipper would owe Gatherer Majorsville/Mamont Surcharges for four Planned Wells, the first Majorsville/Mamont Minimum Well Period would be extended by 31 Days with respect to one Planned Well delayed by Force Majeure, and Shipper would only owe Gatherer Majorsville/Mamont Surcharges for such delayed Planned Well if Shipper fails to drill and complete such Planned Well prior to expiration of such 31-Day extension; but, if Shipper drills and completes such delayed Planned Well prior to expiration of such 31-Day extension, such delayed Planned Well will count towards the Majorsville/Mamont Minimum Well Requirement with respect to the first Majorsville/Mamont Minimum Well Period, even if drilled and completed during January of 2021.

4. Change to Priority of Service. Section 4.1(c) of the Original Agreement shall be replaced in its entirety with the following:

(c)    For the avoidance of doubt and notwithstanding Section 4.1(a) or anything contained herein to the contrary, all Gas Tendered by Shipper to any applicable Individual System that was produced from the Utica Formation shall be entitled to Priority One Service.     

5. Replacement of Exhibit B-1(a) (Dedication Area (Marcellus)). Exhibit B-1(a) to the Original Agreement shall be replaced in its entirety with Exhibit B-1(a) attached hereto.

6. Replacement of Exhibit B-1(b) (Dedication Area (Utica)). Exhibit B-1(b) to the Original Agreement shall be replaced in its entirety with Exhibit B-1(b) attached hereto.

7. Replacement of Exhibit B-3(b) (ACAA Fees). Exhibit B-3(b) to the Original Agreement shall be replaced in its entirety with Exhibit B-3(b) attached hereto.

8. Replacement of Exhibit B-4 (Big Run Fees). Exhibit B-4 to the Original Agreement shall be replaced in its entirety with Exhibit B-4 attached hereto.

9. Replacement of Exhibit B-5(b) (Crawford Fees). Exhibit B-5(b) to the Original Agreement shall be replaced in its entirety with Exhibit B-5(b) attached hereto.

10. Replacement of Exhibit B-6(b) (Fallowfield Fees). Exhibit B-6(b) to the Original Agreement shall be replaced in its entirety with Exhibit B-6(b) attached hereto.

11. Replacement of Exhibit B-7(b) (Majorsville Fees). Exhibit B-7(b) to the Original Agreement shall be replaced in its entirety with Exhibit B-7(b) attached hereto.

12. Replacement of Exhibit B-8(b) (Mamont Fees). Exhibit B-8(b) to the Original Agreement shall be replaced in its entirety with Exhibit B-8(b) attached hereto.

13. Replacement of Exhibit B-9 (Marchand Fees). Exhibit B-9 to the Original Agreement shall be replaced in its entirety with Exhibit B-9 attached hereto.

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14. Replacement of Exhibit B-10(b) (Marshall Fees). Exhibit B-10(b) to the Original Agreement shall be replaced in its entirety with Exhibit B-10(b) attached hereto.

15. Replacement of Exhibit B-11(b) (McQuay Fees). Exhibit B-11(b) to the Original Agreement shall be replaced in its entirety with Exhibit B-11(b) attached hereto.

16. Insertion of New Exhibit B-18 (Majorsville/Mamont Minimum Well Area). A new Exhibit B-18 shall be inserted into the Original Agreement immediately after Exhibit B-17 with Exhibit B-18 attached hereto.

17. Replacement of Exhibit J-2 (Legacy Wells). Exhibit J-2 to the Original Agreement shall be replaced in its entirety with Exhibit J-2 attached hereto.

18. Replacement of Exhibit P (Compression Curves for Certain Systems). Exhibit P to the Original Agreement shall be replaced in its entirety with Exhibit P attached hereto.

19. Insertion of New Exhibit T (Majorsville/Mamont Surcharge Limitations). A new Exhibit T shall be inserted into the Original Agreement immediately after Exhibit S with Exhibit T attached hereto.

20. Original Agreement. Except as modified herein, the Original Agreement remains in full force and effect in accordance with its terms.

21. Incorporation of Certain Terms. Capitalized terms used but not otherwise defined herein shall have the meanings ascribed to such terms in the Original Agreement. Sections 10.1 and 16.7 of the Original Agreement are incorporated by reference herein, mutatis mutandis.

[signature page follows]

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IN WITNESS WHEREOF, the Parties hereto have executed this Amendment to be effective as of the Execution Date.

“Gatherer”

CNX MIDSTREAM DEVCO I LP

By: CNX Midstream DevCo I GP LLC, its general partner

By: /S/ Donald W. Rush    

Name: Donald W. Rush

Title: Chief Financial Officer

CNX MIDSTREAM DEVCO II LP

By: CNX Midstream DevCo II GP LLC, its general partner

By: /S/ Donald W. Rush    

Name: Donald W. Rush

Title: Chief Financial Officer

CNX MIDSTREAM DEVCO III LP

By: CNX Midstream DevCo III GP LLC, its general partner

By: /S/ Donald W. Rush    

Name: Donald W. Rush

Title: Chief Financial Officer

CNX MIDSTREAM OPERATING COMPANY, LLC

By: /S/ Donald W. Rush    

Name: Donald W. Rush

Title: Chief Financial Officer

Signature Page to Second Amendment to

    Second Amended and Restated Gathering Agreement

“Shipper”

CNX GAS COMPANY LLC

By: /S/ Donald W. Rush    

Name: Donald W. Rush

Title: Senior Vice President and Chief Financial Officer

EXHIBIT A.

Signature Page to Second Amendment to

    Second Amended and Restated Gathering Agreement

ATTACHED TO AND MADE PART OF THAT CERTAIN SECOND AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT BY AND BETWEEN CNX GAS COMPANY, LLC, AS SHIPPER, AND CNX MIDSTREAM DEV CO I, LP, CNX MIDSTREAM DEV CO II, LP, CNX MIDSTREAM DEV CO III, LP, AND CNX MIDSTREAM OPERATING COMPANY, LLC, COLLECTIVELY, AS GATHERER

EXHIBIT B-1(a)

DEDICATION AREA (MARCELLUS)

EXHIBIT B.See attached.

Exhibit B-1(a)

ATTACHED TO AND MADE PART OF THAT CERTAIN SECOND AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT BY AND BETWEEN CNX GAS COMPANY, LLC, AS SHIPPER, AND CNX MIDSTREAM DEV CO I, LP, CNX MIDSTREAM DEV CO II, LP, CNX MIDSTREAM DEV CO III, LP, AND CNX MIDSTREAM OPERATING COMPANY, LLC, COLLECTIVELY, AS GATHERER

EXHIBIT B-1(b)

DEDICATION AREA (UTICA)

EXHIBIT C.See attached.

Exhibit B-1(b)

ATTACHED TO AND MADE PART OF THAT CERTAIN SECOND AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT BY AND BETWEEN CNX GAS COMPANY, LLC, AS SHIPPER, AND CNX MIDSTREAM DEV CO I, LP, CNX MIDSTREAM DEV CO II, LP, CNX MIDSTREAM DEV CO III, LP, AND CNX MIDSTREAM OPERATING COMPANY, LLC, COLLECTIVELY, AS GATHERER

EXHIBIT B-3(b)

ACAA FEES

EXHIBIT D.See attached.

Exhibit B-3(b)

ATTACHED TO AND MADE PART OF THAT CERTAIN SECOND AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT BY AND BETWEEN CNX GAS COMPANY, LLC, AS SHIPPER, AND CNX MIDSTREAM DEV CO I, LP, CNX MIDSTREAM DEV CO II, LP, CNX MIDSTREAM DEV CO III, LP, AND CNX MIDSTREAM OPERATING COMPANY, LLC, COLLECTIVELY, AS GATHERER

EXHIBIT B-4

BIG RUN FEES

EXHIBIT E.See attached.

Exhibit B-4

ATTACHED TO AND MADE PART OF THAT CERTAIN SECOND AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT BY AND BETWEEN CNX GAS COMPANY, LLC, AS SHIPPER, AND CNX MIDSTREAM DEV CO I, LP, CNX MIDSTREAM DEV CO II, LP, CNX MIDSTREAM DEV CO III, LP, AND CNX MIDSTREAM OPERATING COMPANY, LLC, COLLECTIVELY, AS GATHERER

EXHIBIT B-5(b)

CRAWFORD FEES

EXHIBIT F.See attached.

Exhibit B-5(B)

ATTACHED TO AND MADE PART OF THAT CERTAIN SECOND AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT BY AND BETWEEN CNX GAS COMPANY, LLC, AS SHIPPER, AND CNX MIDSTREAM DEV CO I, LP, CNX MIDSTREAM DEV CO II, LP, CNX MIDSTREAM DEV CO III, LP, AND CNX MIDSTREAM OPERATING COMPANY, LLC, COLLECTIVELY, AS GATHERER

EXHIBIT B-6(b)

FALLOWFIELD FEES

EXHIBIT G.See attached.

Exhibit B-6(b)

ATTACHED TO AND MADE PART OF THAT CERTAIN SECOND AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT BY AND BETWEEN CNX GAS COMPANY, LLC, AS SHIPPER, AND CNX MIDSTREAM DEV CO I, LP, CNX MIDSTREAM DEV CO II, LP, CNX MIDSTREAM DEV CO III, LP, AND CNX MIDSTREAM OPERATING COMPANY, LLC, COLLECTIVELY, AS GATHERER

EXHIBIT B-7(b)

MAJORSVILLE FEES

EXHIBIT H.See attached.

Exhibit B-7(b)

ATTACHED TO AND MADE PART OF THAT CERTAIN SECOND AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT BY AND BETWEEN CNX GAS COMPANY, LLC, AS SHIPPER, AND CNX MIDSTREAM DEV CO I, LP, CNX MIDSTREAM DEV CO II, LP, CNX MIDSTREAM DEV CO III, LP, AND CNX MIDSTREAM OPERATING COMPANY, LLC, COLLECTIVELY, AS GATHERER

EXHIBIT B-8(b)

MAMONT FEES

EXHIBIT I.See attached.

Exhibit B-8(b)

ATTACHED TO AND MADE PART OF THAT CERTAIN SECOND AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT BY AND BETWEEN CNX GAS COMPANY, LLC, AS SHIPPER, AND CNX MIDSTREAM DEV CO I, LP, CNX MIDSTREAM DEV CO II, LP, CNX MIDSTREAM DEV CO III, LP, AND CNX MIDSTREAM OPERATING COMPANY, LLC, COLLECTIVELY, AS GATHERER

EXHIBIT B-9

MARCHAND FEES

EXHIBIT J.See attached.

Exhibit B-9

ATTACHED TO AND MADE PART OF THAT CERTAIN SECOND AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT BY AND BETWEEN CNX GAS COMPANY, LLC, AS SHIPPER, AND CNX MIDSTREAM DEV CO I, LP, CNX MIDSTREAM DEV CO II, LP, CNX MIDSTREAM DEV CO III, LP, AND CNX MIDSTREAM OPERATING COMPANY, LLC, COLLECTIVELY, AS GATHERER

EXHIBIT B-10(b)

MARSHALL FEES

EXHIBIT K.See attached.

Exhibit B-10(b)

ATTACHED TO AND MADE PART OF THAT CERTAIN SECOND AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT BY AND BETWEEN CNX GAS COMPANY, LLC, AS SHIPPER, AND CNX MIDSTREAM DEV CO I, LP, CNX MIDSTREAM DEV CO II, LP, CNX MIDSTREAM DEV CO III, LP, AND CNX MIDSTREAM OPERATING COMPANY, LLC, COLLECTIVELY, AS GATHERER

EXHIBIT B-11(b)

MCQUAY FEES

EXHIBIT L.See attached.

Exhibit B-11(b)

ATTACHED TO AND MADE PART OF THAT CERTAIN SECOND AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT BY AND BETWEEN CNX GAS COMPANY, LLC, AS SHIPPER, AND CNX MIDSTREAM DEV CO I, LP, CNX MIDSTREAM DEV CO II, LP, CNX MIDSTREAM DEV CO III, LP, AND CNX MIDSTREAM OPERATING COMPANY, LLC, COLLECTIVELY, AS GATHERER

EXHIBIT B-18

MAJORSVILLE/MAMONT MINIMUM WELL AREA

See attached.

EXHIBIT M.

Exhibit B-18

ATTACHED TO AND MADE PART OF THAT CERTAIN FIRST AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT BY AND BETWEEN CNX GAS COMPANY, LLC, AS SHIPPER, AND CNX MIDSTREAM DEV CO I, LP, CNX MIDSTREAM DEV CO II, LP, CNX MIDSTREAM DEV CO III, LP, AND CNX MIDSTREAM OPERATING COMPANY, LLC, COLLECTIVELY, AS GATHERER

EXHIBIT J-2

LEGACY WELLS

See attached.

ATTACHED TO AND MADE PART OF THAT CERTAIN SECOND AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT BY AND BETWEEN CNX GAS COMPANY, LLC, AS SHIPPER, AND CNX MIDSTREAM DEV CO I, LP, CNX MIDSTREAM DEV CO II, LP, CNX MIDSTREAM DEV CO III, LP, AND CNX MIDSTREAM OPERATING COMPANY, LLC, COLLECTIVELY, AS GATHERER

EXHIBIT P

COMPRESSION CURVES FOR CERTAIN SYSTEMS

See attached.

ATTACHED TO AND MADE PART OF THAT CERTAIN SECOND AMENDMENT TO SECOND AMENDED AND RESTATED GATHERING AGREEMENT BY AND BETWEEN CNX GAS COMPANY, LLC, AS SHIPPER, AND CNX MIDSTREAM DEV CO I, LP, CNX MIDSTREAM DEV CO II, LP, CNX MIDSTREAM DEV CO III, LP, AND CNX MIDSTREAM OPERATING COMPANY, LLC, COLLECTIVELY, AS GATHERER

EXHIBIT T

MAJORSVILLE/MAMONT SURCHARGE/CREDIT LIMITATIONS

Number of Wells included in Majorsville/Mamont Minimum Deficiency Obligation / receiving Majorsville/Mamont Credits	Maximum Daily Quantity of Dedicated Gas Subject to Majorsville/Mamont Surcharge / Majorsville/Mamont Credit (In BBtu/Day)
1	38
2	77
3	115
4	153
5	192
6	230
7	268
8	307
9	345
10	384
11	422
12	460
13	499
14	537
15	575
16	614
17	652
18	690
19	729
20	767
21	805
22	844
23	882
24	921
25	959

Exhibit J-2

EX-10.3

Execution Version

THIRD AMENDMENT TO THE SECOND AMENDED AND RESTATED GATHERING AGREEMENT

This Third Amendment (as the same may be amended from time to time in accordance herewith, this “Third Amendment”) is entered into as of the 15th day of May, 2018 (the “Amendment Effective Date”), by and among CNX Gas Company LLC, a Virginia limited liability company (“Shipper”), and Gatherer (as such term is defined in the Gathering Agreement), and is an amendment of that certain Second Amended and Restated Gathering Agreement by and between Shipper and Gatherer dated January 3, 2018 (and such agreement, as amended by that certain First Amendment dated as of March 16, 2018 and Second Amendment dated as of May 2, 2018, the “Gathering Agreement”). Each of Shipper and Gatherer may sometimes be referred to herein individually as a “Party” and together as the “Parties”. Capitalized terms used and not otherwise defined herein have the meanings ascribed to them in the Gathering Agreement.

RECITALS

WHEREAS, Shipper has requested that Gatherer enter into this Third Amendment in order to authorize Gatherer to enroll and participate in the Programs for the benefit of Shipper in order to lower Shipper’s electricity costs related to the services provided by Gatherer pursuant to the Gathering Agreement on certain Individual Systems; and

WHEREAS, subject to and upon the terms set forth herein, Gatherer has agreed to Shipper’s requests.

NOW THEREFORE, for and in consideration of the mutual covenants and agreements herein contained and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows:

Section 1.Amendments as of the Amendment Effective Date. The Gathering Agreement shall be amended effective as of the Amendment Effective Date in the manner provided in this Section 1.

1.1The following terms are hereby added to Section 1.1 of the Gathering Agreementin the appropriate alphabetical order with the existing definitions therein:

“Amendment Effective Date” has the meaning set forth in the Recitals to this Third Amendment.

“Capacity Payment” has the meaning set forth in the applicable Program Agreement.

“Demand Response DowntimeEvent” has the meaning set forth in Section 11.5(b).

“Demand Response Downtime Payment” has the meaning set forth in Section 11.5(d).

“Energy Payment” has the meaning set forth in the applicable Program Agreement.

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“Event” has the meaning set forth in the applicable Program Agreement.

“Flush Gas Difference” has the meaning set forth in Section 11.5(d).

“HG” means HG Energy II Appalachia, LLC, as successor in interest to Noble Energy, Inc.

“Demand Response Provider” means the demand response provider set forth in the applicable Program Agreement.

“Program” means the demand response program provided by the applicable Demand Response Provider for the applicable Individual Systems pursuant to and as further described in the applicable Program Agreement.

“Program Agreement” means the definitive agreements, attached hereto as, and substantially in the form of, Exhibit U, entered into by Gatherer for enrollment and participation in demand response programs for the applicable Individual Systems pursuant to such definitive agreement.

“Program Event” means any curtailments of electricity or tests, including Events and Tests, due in whole or in part to a Program.

“Program Payments” means payments received by Gatherer pursuant to the Program Agreements, including Capacity Payments and Energy Payments.

“Test” has the meaning set forth in the applicable Program Agreement.

1.2The following Section is hereby added to Article 11 of the Gathering Agreement:

Section 11.5 Demand Response Program.

(a) Consent. Shipper hereby authorizes Gatherer to (i) enroll and participate in the Programs, as may be amended from time to time, (ii) enter into the Program Agreements set forth in Exhibit U, as may be amended from time to time, and (iii) execute the Programs exclusively in respect of operations on the Individual Systems set forth in such Program Agreements. Such authorization shall only apply to the Program Agreements set forth in Exhibit U as of the Amendment Effective Date, and to the Individual Systems set forth therein. An instrument in writing executed by the Parties in accordance with Section 16.6 shall be required prior to Gatherer executing any Program Agreements (other than the Program Agreements set forth in Exhibit U as of the Amendment Effective Date).

(b) Program Events Deemed Force Majeure. Gatherer shall, in its sole discretion, have the right to curtail or interrupt receipts and deliveries of Gas and Liquid Condensate and otherwise shutdown or make unavailable the applicable Individual Systems for any reason due in whole or in part to a Program Event or otherwise in accordance with the applicable Program (any curtailment or other interruption to service arising from such events, a “Demand Response Downtime Event”). All shutdowns, unavailability, interruptions and

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curtailments of an Individual System, including curtailments and interruptions of receipts and deliveries of Gas and Liquid Condensate, arising out of or related to a Program Event or Program shall be deemed a Demand Response Downtime Event and, notwithstanding anything to the contrary, shall be deemed events of Force Majeure declared by Gatherer.

(c) Credit of Payments Received Pursuant to the Program. Within 60 Days of receipt by Gatherer of any Program Payment, Gatherer shall pay Shipper its proportional share of such Program Payment. Shipper’s proportional share of a Program Payment shall be calculated by (i) determining the portion of such Program Payment that corresponds to each Program Event, and (ii) allocating such portion to Shipper based on Shipper’s share of the electricity costs on the applicable Individual Systems over the seven Day period prior to (but not including) the Day of such Program Event, which share of electricity costs is allocated to Shipper in accordance with Section 1.8 of Exhibit A to the Gathering Agreement.

(d) Program Event Fees. Shipper shall pay Gatherer (the “Demand Response Downtime Payment”) for each Day of any Program Event (pro-rated for the actual duration of the Program Event during such Day), an amount which shall be equal to 1.05 times the average daily Fees (calculated in accordance with Section 5.1) over the seven Day period prior to (but not including) such Program Event; provided that if the actual Fees due to Gatherer on the Day immediately following the applicable Program Event are greater than the Demand Response Downtime Payment (such difference, the “Flush Gas Difference”), then the Demand Response Downtime Payment due to Gatherer for such Program Event shall be reduced by the Flush Gas Difference. For the avoidance of doubt, the Demand Response Downtime Payment shall never be less than $0. Additionally, Shipper shall reimburse Gatherer for any and all direct costs associated with Gatherer’s compliance with Program requirements, including, without limitation, costs of any new communications equipment, required by such Program.

(e) Notice of Events and Tests. Gatherer shall use commercially reasonable efforts to provide Shipper with verbal notice (promptly followed by written notice) of impending Events or Tests at least 15 minutes prior to such Event or Test (as applicable). Shipper shall provide verbal notice (promptly followed by written confirmation) of approval or disapproval of participation in the applicable Event or Test within 10 minutes of Gatherer’s verbal notice; provided that if HG or Shipper fail to respond within the stipulated time, such failure shall be deemed approval of the applicable Event or Test (as applicable), and provided, further, that if HG’s and Shipper’s notices (or deemed notices) with respect to participation in such Event or Test conflict and such conflict is not resolved within 10 minutes of Gatherer’s verbal notice, then such notices (including failure to provide notice) shall be deemed disapproval of such Event or Test.

(f) Program Agreement Indemnification. NOTWITHSTANDING ANYTHING TO THE CONTRARY, SHIPPER AGREES TO AND SHALL RELEASE, DEFEND, INDEMNIFY AND HOLD HARMLESS GATHERER AND GATHERER GROUP FROM AND AGAINST ANY AND ALL DAMAGES, LOSSES, COSTS AND EXPENSES DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATED TO

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THIS SECTION 11.5, THE PROGRAM AGREEMENTS AND THE PROGRAMS,EXCEPT TO THE EXTENT THAT SUCH DAMAGES, LOSSES, COSTS OR EXPENSES ARE CAUSED BY THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF GATHERER OR A MEMBER OF GATHERER GROUP. The Parties acknowledge and agree that, notwithstanding anything to the contrary, Gatherer has no ability to control the extent or duration of any curtailments attributable to the Program Agreements and Programs and accordingly Shipper acknowledges that Gatherer has no obligation to attempt to minimize the extent or duration of any curtailments arising therefrom or otherwise remedy any such curtailments.

(g) Termination. Subject to Section 11.5(f), Shipper may, at any time with 30 Days’ prior written notice and with the prior written consent of HG, require Gatherer to withdraw from the Program and terminate the Program Agreement; provided that Shipper shall be solely liable, and shall indemnify Gatherer, for any and all costs, expenses and liabilities related to such termination.

1.3The following terms are hereby amended as follows:

“Downtime Event” means, with respect to the Gathering System or any Individual System , a period during which all or a portion of the Gathering System or such Individual System (or any other Individual System impacted thereby) was unavailable to provide Gathering Services, due to reasons other than (a) Force Majeure (including any deemed events of Force Majeure under Sections4.7, 11.3 and 11.5) and/or (b) Gatherer’s failure to provide Compression Services for any Compression Obligation Receipt Point on such Individual System in accordance with this Agreement (for which remedies are provided under Sections 2.5(a)(iv) and 5.2(c)).

“Priority One Service” means with respect to each Individual System, that type of service that has the highest priority call on capacity of all or any relevant portion of such Individual System, which service shall not be subject to interruption or curtailment except by reason of an event of Force Majeure (including any deemed events of Force Majeure under Sections 11.3 and 11.5).

“Priority Two Service” means with respect to each Individual System, that type of service that has the second highest priority call on capacity of all or any relevant portion of such Individual System second only to Priority One Service, which service shall not be subject to interruption or curtailment except by reason of an event of Force Majeure (including any deemed events of Force Majeure under Sections 11.3 and 11.5) and which service in any event has a higher priority than Gathering Services on an Interruptible Basis and any other permissible level of service established by Gatherer pursuant to the terms and conditions of this Agreement (other than Priority One Service).

1.4Section 2.5(b) of the Gathering Agreement is hereby amended as follows:

4

“(including Force Majeure declared by Gatherer, but excluding any deemed events of Force Majeure under Section 4.7 and/or Section 11.5)”

1.5Section(a)(vi) and (a)(viii) of Exhibit S are each hereby amended by inserting the words “or Section 11.5” immediately after “Section 4.7” appearing in the parenthetical in line 6 of each such subsection.

1.6Annex 1 attached hereto is hereby attached to the Gathering Agreement as Exhibit U and “EXHIBIT U PROGRAM AGREEMENTS” is hereby added to the Exhibit list appearing after page (iii) of the Agreement.

Section 2.Miscellaneous.

2.1This Third Amendment is and the legal relations among the parties shall be governed and construed in accordance with the laws of the State of Texas, excluding any conflicts of law rule or principle that might refer construction of such provisions to the laws of another jurisdiction.

2.2This Third Amendment shall inure to the benefit of and be binding upon each of the Parties and each of their respective permitted successors and permitted assigns.

2.3This Third Amendment may be executed in counterparts, each of which is deemed an original, but all of which constitutes one and the same agreement. Delivery of an executed counterpart of this Third Amendment electronically or by facsimile shall be effective as delivery of an original executed counterpart of this Third Amendment.

2.4The Gathering Agreement, as amended by this Third Amendment, constitutes the sole and entire agreement of the Parties with respect to the subject matter contained therein, and supersedes all prior and contemporaneous understandings, agreements, representations and warranties, both written and oral, with respect to such subject matter.

IN WITNESS WHEREOF, the Parties have caused this Third Amendment to be duly executed by their respective authorized officers on the date and year first above written.

[Signature Pages to Follow]

5

“GATHERER”

CNX MIDSTREAM DEVCO I LP

By: CNX MIDSTREAM DEVCO I GP LLC, its general partner

By: /S/ Joseph M. Fink    

Name: Joseph M. Fink

Title: Vice President

CNX MIDSTREAM DEVCO II LP

By: CNX MIDSTREAM DEVCO II GP LLC, its general partner

By: /S/ Joseph M. Fink    

Name: Joseph M. Fink

Title: Vice President

CNX MIDSTREAM DEVCO III LP

By: CNX MIDSTREAM DEVCO III GP LLC, its general partner

By: /S/ Joseph M. Fink    

Name: Joseph M. Fink

Title: Vice President

CNX MIDSTREAM OPERATING COMPANY LLC

By: /S/ Joseph M. Fink    

Name: Joseph M. Fink

Title: Vice President

[Signature Page]

THIRD AMENDMENT TO GATHERING AGREEMENT

“SHIPPER”

CNX GAS COMPANY LLC

By: /S/ Craig W. Neal    

Name: Craig W. Neal

Title: Vice President

[Signature Page]

THIRD AMENDMENT TO GATHERING AGREEMENT

ANNEX 1

EXHIBIT T

PROGRAM AGREEMENTS

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Nicholas J. DeIuliis, certify that:

1. I have reviewed this quarterly report on Form 10-Q of CNX Midstream Partners LP;

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

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

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

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

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

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

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

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

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

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

Date:	August 2, 2018
/S/ Nicholas J. DeIuliis
Nicholas J. DeIuliis
Chief Executive Officer
CNX Midstream GP LLC (the general partner of CNX Midstream Partners LP)
(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Donald W. Rush, certify that:

1. I have reviewed this quarterly report on Form 10-Q of CNX Midstream Partners LP;

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

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

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

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

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

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

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

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

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

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

Date:	August 2, 2018
/S/ Donald W. Rush
Donald W. Rush
Chief Financial Officer
CNX Midstream GP LLC (the general partner of CNX Midstream Partners LP)
(Principal Financial Officer)

EX-32.1

Exhibit 32.1

CERTIFICATION

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002,

18 U.S.C. Section 1350

I, Nicholas J. DeIuliis, Chairman of the Board and Chief Executive Officer (principal executive officer) of CNX Midstream Partners LP (the “Registrant”), certify that to my knowledge, based upon a review of the Quarterly Report on Form 10-Q for the period ended June 30, 2018, of the Registrant (the “Report”):

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

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

Date:	August 2, 2018
/S/ Nicholas J. DeIuliis
Nicholas J. DeIuliis
Chief Executive Officer
CNX Midstream GP LLC (the general partner of CNX Midstream Partners LP)
(Principal Executive Officer)

EX-32.2

Exhibit 32.2

CERTIFICATION

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002,

18 U.S.C. Section 1350

I, Donald W. Rush, Chief Financial Officer and Director (principal financial officer) of CNX Midstream Partners LP (the “Registrant”), certify that to my knowledge, based upon a review of the Quarterly Report on Form 10-Q for the period ended June 30, 2018, of the Registrant (the “Report”):

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

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

Date:	August 2, 2018
/S/ Donald W. Rush
Donald W. Rush
Chief Financial Officer
CNX Midstream GP LLC (the general partner of CNX Midstream Partners LP)
(Principal Financial Officer)

XML

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2018	Aug. 02, 2018
Entity Information [Line Items]
Entity Registrant Name	CNX Midstream Partners LP
Entity Central Index Key	0001610418
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Document Type	10-Q
Document Period End Date	Jun. 30, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		63,638,165

XML

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Thousands, $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Revenue
Gathering revenue — related party		$ 37,576	$ 55,667	$ 75,306	$ 114,625
Gathering revenue — third party		23,438	867	49,577	867
Total Revenue		61,014	56,534	124,883	115,492
Expenses
Operating expense — related party		5,079	7,089	9,514	14,717
Operating expense — third party		7,406	5,957	15,874	12,590
General and administrative expense — related party		3,620	2,663	7,232	5,546
General and administrative expense — third party		2,319	1,033	4,868	2,225
(Gain) loss on asset sales		(254)	3,241	2,501	3,914
Depreciation expense		5,443	5,675	11,299	11,346
Interest expense		7,119	1,124	9,608	2,162
Total Expense		30,732	26,782	60,896	52,500
Net Income		30,282	29,752	63,987	62,992
Less: Net income attributable to noncontrolling interest		277	761	6,135	3,934
Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP		30,005	28,991	57,852	59,058
Calculation of Limited Partner Interest in Net Income:
Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP		30,005	28,991	57,852	59,058
Less: General partner interest in net income, including incentive distribution rights		2,903	1,305	5,055	2,434
Limited partner interest in net income		$ 27,102	$ 27,686	$ 52,797	$ 56,624
Net income per limited partner unit - Basic (in dollars per unit)		$ 0.43	$ 0.44	$ 0.83	$ 0.89
Net income per limited partner unit - Diluted (in dollars per unit)		$ 0.43	$ 0.44	$ 0.83	$ 0.89
Limited partner units outstanding - Basic (in shares)		63,638	63,585	63,630	63,575
Limited partner units outstanding - Diluted (in shares)		63,677	63,644	63,670	63,630
Cash distributions declared per unit (in dollars per share)	[1]	$ 0.3361	$ 0.2922	$ 0.6606	$ 0.5743

[1] Represents the cash distributions declared during the month following the end of each respective quarterly period. See Note 15.

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CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Current Assets:
Cash	$ 707	$ 3,194
Receivables — related party (Note 6)	12,072	13,104
Receivables — third party (Note 6)	7,546	8,251
Other current assets	2,726	2,169
Total Current Assets	23,051	26,718
Property and Equipment (Note 7):
Property and equipment	864,611	972,841
Less — accumulated depreciation	72,098	73,563
Property and Equipment, Net	792,513	899,278
Other assets (Note 8)	3,494	593
TOTAL ASSETS	819,058	926,589
Current Liabilities:
Accounts payable and other accrued liabilities	38,327	23,602
Accounts payable — related party (Note 9)	3,211	2,376
Total Current Liabilities	41,538	25,978
Other Liabilities:
Revolving credit facility (Note 10)	11,000	149,500
Long-term debt (Note 11)	393,169	0
Total Liabilities	445,707	175,478
Partners’ Capital:
Common units (63,638,165 units issued and outstanding at June 30, 2018 and 63,588,152 units issued and outstanding at December 31, 2017)	295,405	389,427
General partner interest	8,893	4,328
Partners’ capital attributable to CNX Midstream Partners LP	304,298	393,755
Noncontrolling interest	69,053	357,356
Total Partners’ Capital	373,351	751,111
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$ 819,058	$ 926,589

XML

CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - shares	Jun. 30, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Units issued (in shares)	63,638,165	63,588,152
Units outstanding (in shares)	63,638,165	63,588,152

XML

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL AND NONCONTROLLING INTEREST (Unaudited) - 6 months ended Jun. 30, 2018 - USD ($) $ in Thousands	Total	Total Capital Attributable to Partners	Total Capital Attributable to Partners Limited	Total Capital Attributable to Partners General Partner	Noncontrolling Interest
Partners' Capital, beginning balance at Dec. 31, 2017	$ 751,111	$ 393,755	$ 389,427	$ 4,328	$ 357,356
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	63,987	57,852	52,797	5,055	6,135
(Distributions to) contributions from general partner and noncontrolling interest holders, net	(3,505)	20		20	(3,525)
Quarterly distributions to unitholders	(44,189)	(44,189)	(40,574)	(3,615)
Acquisition of Shirley-Penns System	(265,000)	(153,587)	(153,587)		(111,413)
HG Energy Transaction	(133,080)	46,420	46,420		(179,500)
Noncash contribution of assets held by general partner	3,105	3,105		3,105
Unit-based compensation	1,269	1,269	1,269
Vested units withheld for unitholder taxes	(347)	(347)	(347)
Partners' Capital, ending balance at Jun. 30, 2018	$ 373,351	$ 304,298	$ 295,405	$ 8,893	$ 69,053

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Cash Flows from Operating Activities:
Net income	$ 63,987	$ 62,992
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation expense and amortization of debt issuance costs	11,872	11,430
Unit-based compensation	1,269	650
(Gain) loss on asset sales	2,501	3,914
Other	387	167
Changes in assets and liabilities:
Receivables — related party	1,032	4,009
Receivables — third party	705	(867)
Other current and non-current assets	108	3,574
Accounts payable and other accrued liabilities	12,824	(3,645)
Accounts payable — related party	856	(5,790)
Net Cash Provided by Operating Activities	95,541	76,434
Cash Flows from Investing Activities:
Capital expenditures	(41,587)	(23,415)
Proceeds from sale of assets	6,462	14,000
Net Cash Used in Investing Activities	(35,125)	(9,415)
Cash Flows from Financing Activities:
Distributions to general partner and noncontrolling interest holders, net	(3,505)	(25,317)
Vested units withheld for unitholder taxes	(347)	(411)
Quarterly distributions to unitholders	(44,189)	(36,846)
Net payments on unsecured $250.0 million credit facility	(149,500)	(6,000)
Net borrowings on secured $600.0 million credit facility	11,000	0
Proceeds from issuance of long-term debt, net of discount	394,000	0
Debt issuance costs	(5,362)	0
Acquisition of Shirley-Penns System	(265,000)	0
Net Cash Used in Financing Activities	(62,903)	(68,574)
Net Decrease in Cash	(2,487)	(1,555)
Cash at Beginning of Period	3,194	6,421
Cash at End of Period	707	4,866
Cash paid during the period for:
Interest	$ 1,367	$ 2,171

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (Parenthetical) - USD ($)	Mar. 08, 2018	Sep. 30, 2014
Credit Facility
Revolving credit facility	$ 600,000,000	$ 250,000,000.0

XML

DESCRIPTION OF BUSINESS

6 Months Ended

Jun. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

DESCRIPTION OF BUSINESS

DESCRIPTION OF BUSINESS

CNX Midstream Partners LP (the “Partnership”, or “we”, “us”, or “our”) is a growth-oriented master limited partnership focused on the ownership, operation, development and acquisition of natural gas gathering and other midstream energy assets to service our customers’ production in the Marcellus Shale and Utica Shale in Pennsylvania and West Virginia. The Partnership’s assets include natural gas gathering pipelines and compression and dehydration facilities, as well as condensate gathering, collection, separation and stabilization facilities. The Partnership is managed by its general partner, CNX Midstream GP LLC (the “general partner”), a wholly owned subsidiary of CNX Gathering LLC (“CNX Gathering”). As a result of the January 3, 2018 transaction discussed below, CNX Gathering is a wholly owned subsidiary of CNX Resources Corporation (NYSE: CNX) (“CNX”). The Partnership was formed in May 2014 as a joint venture between CNX and Noble Energy, Inc (“Noble Energy”).

On January 3, 2018, CNX Gas Company LLC (“CNX Gas”), a Virginia limited liability company, acquired Noble Energy’s 50% membership interest in CNX Gathering for cash consideration of $305.0 million and the mutual release of all outstanding claims between the parties (the “General Partner Transaction”). As a result of the General Partner Transaction, CNX owns 100% of the membership interest in CNX Gathering and is the sole sponsor of the Partnership. Accordingly, we may refer to CNX as the “Sponsor” throughout this Quarterly Report on Form 10-Q.

Following the General Partner Transaction, Noble Energy owned 21,692,198 common units representing limited partner interests in the Partnership (the “Retained Units”). However, in connection with Noble Energy’s announcement of its intention to divest of the Retained Units over the next few years, Noble Energy executed an underwritten public offering of 7,475,000 of its Retained Units on June 29, 2018. The Partnership did not receive any proceeds as a result of the June 29, 2018 sale of Retained Units. At June 30, 2018, Noble Energy continues to own 14,217,198 common units. See Note 5–Related Party Transactions for additional information.

Description of Business

Prior to May 3, 2018, our midstream operations consisted of three operating segments that we refer to as our “Anchor Systems,” “Growth Systems” and “Additional Systems” based on their relative current cash flows, growth profiles, capital expenditure requirements and the timing of their development.

• Our Anchor Systems, in which the Partnership owns a 100% controlling interest, include our most developed midstream systems that generate the largest portion of our current cash flows, which includes our four primary midstream systems (the McQuay System, the Majorsville System, the Mamont System and the Shirley-Penns System) and related assets.

• Our Growth Systems were primarily located in the dry gas regions of our dedicated acreage in central West Virginia that were generally in earlier phases of development than our other systems and required substantial future expansion capital expenditures to materially increase production. As a result of the HG Energy Transaction described below, the Partnership distributed its ownership interests in the Growth Systems assets to CNX Gathering, which subsequently transferred these assets to HG Energy.

• Our Additional Systems currently include several gathering systems primarily located in the wet gas regions of our dedicated acreage (current activity is primarily located within the Pittsburgh Airport area) that we expect will require lower levels of expansion capital investment relative to our Growth Systems. The substantial majority of capital investment on these systems would be funded by CNX in proportion to CNX Gathering’s 95% retained ownership interest. As a result of the HG Energy Transaction described below, the Partnership distributed its ownership interests in the Moundsville area assets to CNX Gathering, which subsequently transferred these assets to HG Energy.

In order to maintain operational flexibility, our operations are conducted through, and our operating assets are owned by, our operating subsidiaries. However, neither we nor our operating subsidiaries have any employees. Our general partner has the sole responsibility for providing the personnel necessary to conduct our operations, whether through directly hiring employees or by obtaining the services of others, which may include personnel of CNX as provided through contractual relationships with the Partnership. All of the personnel that conduct our business are employed or contracted by our general partner and its affiliates, including our Sponsor, but we sometimes refer to these individuals as our employees because they provide services directly to us. See Note 5–Related Party Transactions for additional information.

Transactions with our Sponsor and HG Energy

On May 3, 2018, we announced the consummation of a strategic transaction and amended our gas gathering agreement (“GGA”) with our Sponsor that provides for the following (collectively, the “CNX Transactions”):

• Dedication to the Partnership of approximately 16,100 additional Utica acres in our Anchor Systems;

• Commitment to develop 40 additional wells in the Anchor Systems by 2023, subject to the terms of the GGA;

• Contribution to the Anchor Systems of a 20” high pressure pipeline in addition to a one-time payment to us of approximately $2.0 million in cash; and

• Distribution of our 5% interest in the Growth Systems and related assets as well as our 5% interest in the Moundsville midstream assets, which were a part of the Additional Systems, to CNX Gathering, which subsequently transferred these assets to HG Energy.

On May 3, 2018, we also announced a strategic transaction with HG Energy II Appalachia, LLC (“HG Energy”), pursuant to which we agreed to amend our GGA with HG Energy to provide for the following (collectively, the “HG Energy Transaction”):

• Release from dedication of approximately 18,000 acres, net to the Partnership, which was comprised of approximately 275,000 acres (or approximately 14,000 acres, net to the Partnership) within the Growth and Additional Systems and approximately 4,200 scattered acres located in the Anchor Systems;

• Removal of our obligation to provide gathering services or make capital investments in the Growth Systems or in the Moundsville area of the Additional Systems; and

• Commitment by HG Energy to develop 12 additional wells in the Anchor Systems by 2021, subject to the terms of the HG Energy GGA.

Following the CNX and HG Energy Transactions, the aggregate number of well commitments in the Anchor Systems to the Partnership by CNX and HG Energy, collectively, increased from 140 wells over the course of the next five years to 192 wells. The non-cash distribution of our interests in these assets to CNX Gathering resulted in a reduction to property and equipment, net of $133.1 million, a reduction in noncontrolling interests of $179.5 million and an increase to partners’ capital of $46.4 million. At June 30, 2018, the Partnership has no remaining interests in the Growth Systems or the Moundsville area assets that were historically included within the Additional Systems.

Acquisition of Shirley-Penns System

At December 31, 2017, CNX Gathering owned a 95% noncontrolling interest, while the Partnership owned the remaining 5% controlling interest, in the Additional Systems, which owned the gathering system and related assets commonly referred to as the Shirley-Penns System (the “Shirley-Penns System”),

On March 16, 2018, the Partnership acquired the remaining 95% interest in the Shirley-Penns System, pursuant to which the Additional Systems transferred its interest in the Shirley-Penns System on a pro rata basis to CNX Gathering and the Partnership in accordance with each transferee’s respective ownership interest in the Additional Systems. Following such transfer, CNX Gathering sold its aggregate interest in the Shirley-Penns System, which now resides in the Anchor Systems, in exchange for cash consideration in the amount of $265.0 million (the “Shirley-Penns Acquisition”). The Partnership funded the Shirley-Penns Acquisition with a portion of the proceeds from the issuance of 6.5% senior notes due 2026 (the “Senior Notes”). See Note 11–Long-Term Debt for additional information.

At June 30, 2018, the Partnership owns a 100% controlling interest in the Shirley-Penns System. The Additional Systems continue to hold gathering systems in which the Partnership owns a 5% controlling interest.

Noble Energy Sale of Upstream Assets

On June 28, 2017, Noble Energy sold its upstream assets in northern West Virginia and southern Pennsylvania to HG Energy, effectively making HG Energy the new shipper on the dedicated acreage that was previously owned by Noble Energy (the “Noble Energy Asset Sale”). The Partnership currently gathers the natural gas and condensate volumes produced by HG Energy on our dedicated acreage under the terms of our GGA with Noble Energy, which was assigned to HG Energy upon consummation of the Noble Energy Asset Sale. In connection with the aforementioned HG Energy Transaction, the GGA was amended and certain acreage was released from dedication to the Partnership.

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SIGNIFICANT ACCOUNTING POLICIES

6 Months Ended

Jun. 30, 2018

Accounting Policies [Abstract]

SIGNIFICANT ACCOUNTING POLICIES

SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Use of Estimates

The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and various disclosures. Actual results could differ from those estimates, which are evaluated on an ongoing basis, utilizing historical experience and other methods considered reasonable under the particular circumstances. Although these estimates are based on management’s best available knowledge at the time, changes in facts and circumstances or discovery of new facts or circumstances may result in revised estimates and actual results may differ from these estimates. Effects on the Partnership’s business, financial position and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revision become known. In the opinion of management, all adjustments considered necessary for a fair presentation of the accompanying consolidated financial statements have been included.

The balance sheet at December 31, 2017 has been derived from the audited financial statements at that date but does not include all of the information and footnotes required by GAAP for complete financial statements.

Principles of Consolidation

During the periods presented in this Quarterly Report on Form 10-Q, the consolidated financial statements include the accounts of the Partnership and all of its controlled subsidiaries, including 100% of each of the Anchor Systems, Growth Systems and Additional Systems. Although the Partnership has less than a 100% economic interest in the Growth and Additional Systems, each was consolidated fully with the results of the Partnership. However, after adjusting for noncontrolling interests, net income attributable to general and limited partner ownership interests in the Partnership reflects only that portion of net income that is attributable to the Partnership’s unitholders. The Partnership distributed its interests in the Growth Systems and the Moundsville area of the Additional Systems in connection with the HG Energy Transaction.

Transactions between the Partnership and CNX have been identified in the consolidated financial statements as transactions between related parties and are disclosed in Note 5–Related Party Transactions.

Jumpstart Our Business Startups Act (“JOBS Act”)

Under the JOBS Act, for as long as the Partnership remains an “emerging growth company” as defined in the JOBS Act, we may take advantage of certain exemptions from the Securities and Exchange Commission’s (“SEC”) reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being required to provide an auditor’s attestation report on management’s assessment of the effectiveness of its system of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in our periodic reports, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and seeking unitholder approval of any golden parachute payments not previously approved.

We may take advantage of the aforementioned reporting exemptions until September 30, 2019 or until we lose our status as an emerging growth company, which would happen if any of the following were to occur:

• we have more than $1.0 billion of revenues in the year ending December 31, 2018;

• the limited partner interests held by non-affiliates have a market value of more than $700 million as of June 30, 2018, which determination shall be made as of December 31, 2018; or

• we issue more than $1.0 billion of non-convertible debt over a three-year period.

Based on the above criteria, we will not be an emerging growth company for the year ending December 31, 2018, as the market value of limited partner interests held by non-affiliates was in excess of $700 million at June 30, 2018. Accordingly, among other things, we will be required to provide an auditor’s attestation report on management’s assessment of the effectiveness of its system of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act in our year ending December 31, 2018 Annual Report on Form 10-K.

Revenue Recognition

On January 1, 2018, the Partnership adopted Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers and all the related amendments (“new revenue standard”) using the modified retrospective method. We did not have a transition adjustment as a result of the adoption of the new revenue standard.

Revenues from contracts with customers

We record revenue when obligations under the terms of the contracts with our shippers are satisfied; generally this occurs on a daily basis as we gather gas at the wellhead. Revenue is measured as the amount of consideration we expect to receive in exchange for providing the natural gas gathering services.

Nature of performance obligations

At contract inception, we assess the services promised in our contracts with customers and identify a performance obligation for each promised service that is distinct. To identify the performance obligations, we consider all of the services promised in the contract, regardless of whether they are explicitly stated or are implied by customary business practices.

Our revenue is generated from natural gas gathering activities. The gas gathering services are interruptible in nature and include charges for the volume of gas actually gathered and do not guarantee access to the system. Volumetric-based fees relate to actual volumes gathered. In general, the interruptible gathering of each unit (MMBtu) of natural gas represents a separate performance obligation. Payment terms for these contracts require payment within 25 days of the end of the calendar month in which the hydrocarbons are gathered.

Transaction price allocated to remaining performance obligations

The new revenue standard requires that we disclose the aggregate amount of transaction price that is allocated to performance obligations that have not yet been satisfied. However, the guidance provides certain practical expedients that limit this requirement.

Substantially all of our revenues are derived from contracts with CNX and HG Energy with terms of greater than one year. Under these contracts, the interruptible gathering of each unit of natural gas represents a separate performance obligation.

For revenue associated with the Shirley-Penns System, our only contract with terms that are greater than one year, the aggregate amount of the transaction price allocated to remaining performance obligations was $422.9 million at June 30, 2018. We expect to recognize revenue of $14.2 million and $28.8 million, respectively during the remainder of the years ending December 31, 2018 and December 31, 2019. The amount of revenue associated with this contract up to the minimum volume commitment (“MVC”) is fixed in nature, and volumes that we may gather above the MVC will be variable in nature. As of June 30, 2018, no future performance obligations exist relative to volumes to be gathered in excess of the MVC as the related volumes have not yet been nominated for gathering. Therefore, we have not disclosed the value of unsatisfied performance obligations for the variable aspect of this agreement, nor have we disclosed the value of other unsatisfied performance obligations that are variable in nature.

Prior-period performance obligations

We record revenue when obligations under the terms of the contracts with our shippers are satisfied; generally this occurs on a daily basis when we gather gas at the wellhead. In some cases, we are required to estimate the amount of natural gas that we have gathered during an accounting period and record any differences between our estimates and the actual units of natural gas that we gathered in the following month. We have existing internal controls for our revenue estimation process and related accruals; historically, any identified differences between our revenue estimates and actual revenue received have not been significant. For the quarters and six months ended June 30, 2018 and 2017, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

Disaggregation of revenue

See Note 13–Segment Information for additional information.

Contract balances

We invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our contracts with customers do not give rise to contract assets or liabilities under the new revenue standard. We also have no contract assets recognized from the costs.

See Note 6–Receivables for additional information.

Classification

The fees we charge our Sponsor and the fees we charged Noble Energy, prior to consummation of the Noble Energy Asset Sale, are recorded in gathering revenue — related party in our consolidated statements of operations. Following consummation of the Noble Energy Asset Sale, fees from midstream services we perform for HG Energy, and any other third party shipper, are recorded in gathering revenue — third party in our consolidated statements of operations.

Cash

Cash includes cash on hand and on deposit at banking institutions.

Receivables

Receivables are recorded at the invoiced amount and do not bear interest. When applicable, we reserve for specific accounts receivable when it is probable that all or a part of an outstanding balance will not be collected. Collectability is determined based on terms of sale, credit status of customers and various other circumstances. We regularly review collectability and establish or adjust the allowance as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.

There were no reserves for uncollectable amounts at June 30, 2018 or December 31, 2017.

Fair Value Measurement

The Financial Accounting Standards Board (the “FASB”) Accounting Standards Codification (“ASC”) Topic 820, Fair Value Measurements and Disclosures, clarifies the definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., the initial recognition of asset retirement obligations and impairments of long‑lived assets). The fair value is the price that we estimate we would receive upon selling an asset or that we would pay to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize input to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1, that are observable for the asset or liability, either directly or indirectly.

The carrying values of our current assets and current liabilities approximate fair values due to their short maturities. The carrying value of our revolving credit facility approximates fair value as the facility bears interest at a variable, market rate that resets periodically.

We estimate the fair value of our long-term debt, which is not actively traded, using a standard industry income approach model that utilizes a discount rate based on market rates for other debt with similar remaining time to maturity and credit risk (Level 2). The estimated fair value of our long-term debt was approximately $388.0 million at June 30, 2018.

Property and Equipment

Property and equipment is recorded at cost upon acquisition and is depreciated on a straight-line basis over the assets’ estimated useful lives or over their lease terms. Expenditures which extend the useful lives of existing property and equipment are capitalized. When properties are retired or otherwise disposed, the related cost and accumulated depreciation are removed from the respective accounts and any profit or loss on disposition is recognized as a gain or loss.

We routinely assess whether impairment indicators arise during any given quarter and have processes in place to ensure that we become aware of such indicators. Impairment indicators include, but are not limited to, sustained decreases in commodity prices, a decline in customer well results and lower throughput forecasts, and increases in construction or operating costs. For such long-lived assets, impairment exists when the carrying amount of an asset or group of assets exceeds our estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset or group of assets. If the carrying amount of the long-lived asset(s) is not recoverable, based on the estimated future undiscounted cash flows, the impairment loss would be measured as the excess of the asset’s carrying amount over its estimated fair value. In the event that impairment indicators exist, we conduct an impairment test.

Fair value represents the estimated price between market participants to sell an asset in the principal or most advantageous market for the asset, based on assumptions a market participant would make. When warranted, management assesses the fair value of long-lived assets using commonly accepted techniques and may use more than one source in making such assessments. Sources used to determine fair value include, but are not limited to, recent third-party comparable sales, internally developed discounted cash flow analyses and analyses from outside advisors. Significant changes, such as the condition of an asset or management’s intent to utilize the asset, generally require management to reassess the cash flows related to long-lived assets. No property and equipment impairments were identified during the periods presented in the accompanying consolidated financial statements.

Environmental Matters

We are subject to various federal, state and local laws and regulations relating to the protection of the environment. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. At this time, we are unable to assess the timing and/or effect of potential liabilities related to greenhouse gas emissions or other environmental issues. As of June 30, 2018 and December 31, 2017, we had no material environmental matters that required the recognition of a separate liability or specific disclosure.

Asset Retirement Obligations

Our gathering pipelines and compressor stations have an indeterminate life. If properly maintained, they will operate for an indeterminate period as long as supply and demand for natural gas exists, which we expect for the foreseeable future. We are under no legal or contractual obligation to restore or dismantle our gathering system upon abandonment. Therefore, we have not recorded any liabilities for asset retirement obligations at June 30, 2018 or December 31, 2017.

Variable Interest Entities

Each of the Anchor, Growth and Additional Systems is a limited partnership (the “Limited Partnerships”) and a variable interest entity (“VIE”). These VIEs correspond with the manner in which we report our segment information in Note 13–Segment Information, which also includes information regarding the Partnership’s involvement with each of these VIEs and their relative contributions to our financial position, operating results and cash flows.

The Partnership fully consolidates each of the Limited Partnerships through its ownership of CNX Midstream Operating Company LLC (the “Operating Company”). The Operating Company, through its general partner ownership interest in each of the Limited Partnerships, is considered to be the primary beneficiary for accounting purposes and has the power to direct all substantive strategic and day-to-day operational decisions of the Limited Partnerships.

Equity Compensation

Equity compensation expense for all unit-based compensation awards is based on the grant date fair value estimated in accordance with the provisions of the Stock Compensation Topic of the FASB ASC. We recognize unit-based compensation costs on a straight-line basis over the requisite service period of an award, which is generally the same as the award’s vesting term. See Note 14–Long-Term Incentive Plan for additional information.

Income Taxes

We are treated as a partnership for federal and state income tax purposes, with each partner being separately taxed on its share of the Partnership’s taxable income. Accordingly, no provision for federal or state income taxes has been recorded in the Partnership’s consolidated financial statements for any period presented in the accompanying consolidated financial statements.

Reclassifications

Certain amounts in prior periods have been reclassified to conform to the current reporting classifications with no effect on previously reported net income or partners’ capital.

Recent Accounting Pronouncements

In February 2016, the FASB issued ASU 2016-02–Leases (Topic 842), which is intended to improve financial reporting about leasing transactions. The ASU will require organizations (“lessees”) that lease assets with terms of more than 12 months to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. Organizations that own the assets leased by lessees (“lessors”) will remain largely unchanged from current GAAP. In addition, the ASU will require disclosures to help investors and other financial statement users better understand the amount, timing and uncertainty of cash flows arising from leases. The effective date of this ASU is for fiscal years beginning after December 31, 2018 and interim periods within that year. We are currently finalizing a project plan, reviewing all existing leases and agreements that are covered under the standard, assessing the impact to our financial statements as well as planning for adoption and implementation of this standard, which includes assessing the impact on information systems and internal controls.

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CASH DISTRIBUTIONS

6 Months Ended

Jun. 30, 2018

Equity [Abstract]

CASH DISTRIBUTIONS

CASH DISTRIBUTIONS

Our partnership agreement requires that we distribute all of our available cash from operating surplus within 45 days after the end of each quarter to unitholders of record on the applicable record date, in accordance with the terms below.

Allocations of Available Cash from Operating Surplus and Incentive Distribution Rights

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner, as holder of our Incentive Distribution Rights (“IDRs”), and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit Target Amount.” IDRs represent the right to receive an increasing percentage, up to a maximum of 48% (which does not include the 2% general partner interest), of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels described in the table below have been achieved. All of the IDRs are currently held by our general partner, as defined in Note 1–Description of Business. Our general partner may transfer the IDRs separately from its general partner interest.

The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2% general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its 2% general partner interest, our general partner has not transferred its IDRs and that there are no arrearages on common units.

			Marginal Percentage Interest in Distributions
Distribution Targets	Total Quarterly Distribution Per Unit Target Amount		Unitholders	General Partner (including IDRs)
Minimum Quarterly Distribution		$0.2125	98%	2%
First Target Distribution	Above $0.2125	up to $0.24438	98%	2%
Second Target Distribution	Above $0.24438	up to $0.26563	85%	15%
Third Target Distribution	Above $0.26563	up to $0.31875	75%	25%
Thereafter	Above $0.31875		50%	50%

Beginning with the distribution that was approved by the Board of Directors of the Partnership’s general partner (the “Board of Directors”) for the earnings period ended March 31, 2018, our quarterly distributions have been in excess of the maximum Third Target Distribution, or $0.31875.

Cash Distributions

The Board of Directors declared the following cash distributions to the Partnership’s common and subordinated unitholders (through September 30, 2017) and to the general partner for the periods presented:

(in thousands, except per unit information)
Quarters Ended	Total Quarterly Distribution Per Unit		Total Quarterly Cash Distribution		Date of Distribution
Year ended December 31, 2017
March 31	$	0.2821	$	18,842	May 15, 2017
June 30	0.2922		19,698		August 14, 2017
September 30	0.3025		20,573		November 14, 2017
December 31	0.3133		21,489		February 14, 2018
Year ending December 31, 2018
March 31	$	0.3245	$	22,700	May 15, 2018

See Note 4–Net Income per Limited Partner Unit and General Partner Interest for information regarding the conversion of subordinated units to common units on November 14, 2017. See Note 15–Subsequent Events for information regarding the distribution that was approved by the Board of Directors with respect to the quarter ended June 30, 2018.

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NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST

6 Months Ended

Jun. 30, 2018

Earnings Per Share [Abstract]

NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST

NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST

We allocate net income between our general partner and limited partners using the two-class method, under which we allocate net income to our limited partners, our general partner and the holders of our IDRs in accordance with the terms of our partnership agreement. We also allocate any earnings in excess of distributions to our limited partners, our general partner and the holders of the IDRs in accordance with the terms of our partnership agreement. We allocate any distributions in excess of earnings for the period to our general partner and our limited partners based on their respective proportionate ownership interests in us, after taking into account distributions to be paid with respect to the IDRs, as set forth in our partnership agreement.

Conversion of subordinated units

From its inception through September 30, 2017, the Partnership paid equal distributions on common, subordinated and general partner units, excluding payments on the IDRs, which are paid in accordance with the table above. Upon payment of the cash distribution with respect to the quarter ended September 30, 2017, the financial requirements for the conversion of all subordinated units were satisfied. As a result, on November 15, 2017, all 29,163,121 subordinated units, which were owned entirely by CNX and Noble Energy, converted into common units on a one-for-one basis. The conversion did not impact the amount of the cash distribution paid or the total number of the Partnership’s outstanding units representing limited partner interests.

Historical earnings per unit

The Partnership calculates historical earnings per unit under the two-class method and allocates the earnings or losses of a transferred business before the date of a dropdown transaction entirely to the general partner. If applicable, the previously reported earnings per unit of the limited partners would not change as a result of a dropdown transaction.

Diluted net income per limited partner unit reflects the potential dilution that could occur if securities or agreements to issue common units, such as awards under the long-term incentive plan, were exercised, settled or converted into common units.  When it is determined that potential common units resulting from an award subject to performance or market conditions should be included in the diluted net income per limited partner unit calculation, the impact is calculated by applying the treasury stock method. There were 26,470 and 27,545 phantom units that were not included in the calculation for the three and six months ended June 30, 2018, respectively, because the effect would have been antidilutive. There were also 50,905 phantom units that were not included in the calculation for the three and six months ended June 30, 2017 because the effect would have been antidilutive. The following table illustrates the Partnership’s calculation of net income per unit for common and subordinated partner units:

	Three Months Ended June 30,				Six Months Ended   June 30,
(in thousands, except per unit information)	2018		2017		2018		2017
Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP	$	30,005	$	28,991	$	57,852	$	59,058
Less: General partner interest in net income, including incentive distribution rights	2,903		1,305		5,055		2,434
Limited partner interest in net income	$	27,102	$	27,686	$	52,797	$	56,624
Net income allocable to common units — basic and diluted	$	27,102	$	14,988	$	52,797	$	30,652
Net income allocable to subordinated units — basic and diluted	—		12,698		—		25,972
Limited partner interest in net income — basic and diluted	$	27,102	$	27,686	$	52,797	$	56,624
Weighted average limited partner units outstanding — Basic
Common units	63,638		34,422		63,630		34,412
Subordinated units	—		29,163		—		29,163
Total	63,638		63,585		63,630		63,575
Weighted average limited partner units outstanding — Diluted
Common units	63,677		34,481		63,670		34,467
Subordinated units	—		29,163		—		29,163
Total	63,677		63,644		63,670		63,630
Net income per limited partner unit — Basic
Common units	$	0.43	$	0.44	$	0.83	$	0.89
Subordinated units	—		0.44		—		0.89
Total	$	0.43	$	0.44	$	0.83	$	0.89
Net income per limited partner unit — Diluted
Common units	$	0.43	$	0.43	$	0.83	$	0.89
Subordinated units	—		0.44		—		0.89
Total	$	0.43	$	0.44	$	0.83	$	0.89

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RELATED PARTY TRANSACTIONS

6 Months Ended

Jun. 30, 2018

Related Party Transactions [Abstract]

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS

In the ordinary course of business, we engage in related party transactions with CNX (and certain of its subsidiaries) and CNX Gathering, which include the fees we charge and revenues we receive under a fixed fee gathering agreement (including electrically-powered compression CNX reimburses to us) and our reimbursement of certain expenses to CNX under several agreements, discussed below. Related party revenues and related party expenses are presented as separate captions within our consolidated statements of operations for the three and six months ended June 30, 2018 and 2017. We also engaged in related party transactions with Noble Energy during the three and six months ended June 30, 2017, which primarily included the fees we charged and revenues we received under our fixed fee gathering agreement with Noble Energy.

During the six months ended June 30, 2018, the Partnership closed on the Shirley-Penns Acquisition for cash consideration in the amount of $265.0 million and on the CNX and HG Energy Transactions. See Note 1–Description of Business for additional information.

Operating expense and general and administrative expense – related party are derived from CNX in the three and six months ended June 30, 2018 and from CNX and Noble Energy in the three and six months ended June 30, 2017 and consisted of the following:

	Three Months Ended   June 30,				Six Months Ended   June 30,
(in thousands)	2018		2017		2018		2017
Operational services — CNX	$	3,257	$	2,999	$	6,092	$	6,187
Electrical compression	1,822		4,090		3,422		8,530
Total Operating Expense — Related Party	$	5,079	$	7,089	$	9,514	$	14,717
CNX	$	3,620	$	2,530	$	7,232	$	5,241
Noble Energy	—		133		—		305
Total General and Administrative Expense — Related Party	$	3,620	$	2,663	$	7,232	$	5,546

In addition to the aforementioned transactions, throughout the six months ended June 30, 2018 and 2017, CNX and Noble Energy, through their ownership of CNX Gathering in the applicable periods, also regularly reimbursed the Partnership for capital expenditures, initially funded by the Partnership, in proportion to CNX Gathering's noncontrolling ownership interests in the Growth and Additional Systems. We also distributed to CNX and Noble Energy amounts related to their noncontrolling ownership interest, in the applicable periods, in the earnings of the Growth and Additional Systems as well as proceeds from sales of any assets in which CNX and Noble Energy had ownership interests through their membership in CNX Gathering. This activity is recorded in the caption “Distributions to general partner and noncontrolling interest holders, net” in the consolidated statements of partners' capital and noncontrolling interest and of cash flows.

Operational Services Agreement

On September 30, 2014, the date of the closing of the initial public offering of our common units (our “IPO”), we entered into an operational services agreement with CNX. On December 1, 2016, in connection with a transaction under which CNX and Noble Energy separated their Marcellus Shale area of mutual interest into two separate operating areas, the operational services agreement was amended and restated. Under the amended and restated operational services agreement, CNX continues to provide certain operational services to us in support of our gathering pipelines and dehydration, treating and compressor stations and facilities, including routine and emergency maintenance and repair services, routine operational activities, routine administrative services, construction and related services and such other services as we and CNX may mutually agree upon from time to time. CNX prepares and submits for our approval a maintenance, operating and capital budget on an annual basis. CNX submits actual expenditures for reimbursement on a monthly basis, and we reimburse CNX for any direct third-party costs incurred by CNX in providing these services.

Omnibus Agreement

On September 30, 2014, we entered into an omnibus agreement with CNX, CNX Gathering and our general partner that addresses the following matters:

• our payment of an annually-determined administrative support fee (approximately $1.9 million for the year ending December 31, 2018) for the provision of certain services by CNX and its affiliates, including executive costs;

• our obligation to reimburse CNX for all other direct or allocated costs and expenses incurred by CNX in providing general and administrative services (which reimbursement is in addition to certain expenses of our general partner and its affiliates that are reimbursed under our partnership agreement);

• our right of first offer to acquire (i) CNX Gathering’s retained interests in our Additional Systems, (ii) CNX Gathering’s other ancillary midstream assets and (iii) any additional midstream assets that CNX Gathering develops; and

• an indemnity from CNX Gathering for liabilities associated with the use, ownership or operation of our assets, including environmental liabilities, to the extent relating to the period of time prior to the closing of the IPO; and our obligation to indemnify CNX Gathering for events and conditions associated with the use, ownership or operation of our assets that occur after the closing of the IPO, including environmental liabilities.

So long as CNX Gathering controls our general partner, the omnibus agreement will remain in full force and effect. If CNX Gathering ceases to control our general partner, either party may terminate the omnibus agreement, provided that the indemnification obligations will remain in full force and effect in accordance with their terms.

Gathering Agreements

2018 Gathering Agreements and Amendments

On January 3, 2018, we entered into the Second Amended and Restated GGA, which is a 20-year, fixed-fee gathering agreement with CNX Gas that amended and restated the previous gathering agreement with CNX Gas in its entirety. Although the fees for services we provide in the Marcellus Shale for existing wells that were covered under the prior agreement (discussed below) remain unchanged in the new agreement, the Second Amended and Restated GGA also dedicates an additional 63,000 of acreage in the Utica Shale in and around the McQuay area and Wadestown area and introduces the following gas gathering and compression rates:

• Gas Gathering:

◦ McQuay area Utica - a fee of $0.225 per MMBtu; and

◦ Wadestown Marcellus and Utica - a fee of $0.35 per MMBtu.

• Compression:

◦ For areas not benefitting from system expansion pursuant to the Second Amended and Restated GGA, compression services are included in the base fees; and

◦ In the McQuay and Wadestown areas, for wells turned in line beginning January 1, 2018 and beyond, we will receive additional fees of $0.065 per MMBtu for Tier 1 pressure services (maximum receipt point of pressure of 600 psi) and $0.130 per MMBtu for Tier 2 pressure services (maximum receipt point of pressure of 300 psi).

The Second Amended and Restated GGA also commits CNX Gas to drill the following numbers of wells in the McQuay area within the Anchor Systems, provided that if 125 wells have been drilled and completed in the Marcellus Shale, then the remainder of such planned wells must be drilled in the Utica Shale. To the extent the requisite number of wells are not drilled and completed by CNX Gas in a given period, we will be entitled to a deficiency payment per shortfall well as set out in the parenthetical below:

• January 1, 2018 to December 31, 2018 - 30 wells (deficiency payment of $3.5 million per well)

• January 1, 2019 to April 30, 2020 - 40 wells (deficiency payment of $3.5 million per well)

• May 1, 2020 to April 30, 2021 - 40 wells (deficiency payment of $2.0 million per well)

• May 1, 2021 to April 30, 2022 - 30 wells (deficiency payment of $2.0 million per well)

In the event that CNX Gas drills wells and completes a number of wells in excess of the number of wells required to be drilled and completed in such period, (i) the number of excess wells drilled and completed during such period will be applied to the minimum well requirement in the succeeding period or (ii) to the extent CNX Gas was required to make deficiency payments for shortfalls in the preceding period, CNX Gas may elect to cause the Partnership to pay a refund in an amount equal to (x) the number of excess wells drilled and completed during the period, multiplied by (y) the deficiency payment paid per well during the period in which the shortfall occurred.

On March 16, 2018, in connection with the Shirley-Penns Acquisition, we amended the Second Amended and Restated GGA to add a minimum volume commitment (“MVC”) on volumes associated with the Shirley-Penns System through December 31, 2031. The MVC commits CNX Gas to pay the Partnership the wet gas fee under the gas gathering agreement for all natural gas we gather up to a specified amount per day through December 31, 2031.

We expect to recognize at least the following amounts or revenue throughout the term of the MVC:

	Revenue under MVC (in millions)
Remainder of year ending December 31, 2018	$	14.2
Year ending December 31, 2019	28.8
Year ending December 31, 2020	34.7
Year ending December 31, 2021	40.8
Year ending December 31, 2022	47.8
Remainder of term	256.6
Total revenue to be recognized under Shirley-Penns contract through December 31, 2031	$	422.9

For all natural gas the Partnership gathers in excess of the MVC, the Partnership will receive a fee of $0.35 per MMBtu in 2018, which will escalate by 2.5% on an annual basis beginning January 1, 2019.

On May 2, 2018, we completed a series of transactions with our Sponsor, which we refer to as the CNX Transaction, pursuant to which we amended the Second Amended and Restated GGA. The amended agreement commits CNX Gas to drill and complete an additional 40 wells in the Majorsville/Mamont area within the Anchor Systems through 2023. To the extent the requisite number of wells are not drilled and completed by CNX Gas in a given period, we will be entitled to a deficiency payment per shortfall well as set out in the parenthetical below:

•July 1, 2018 to December 31, 2020 -  15 wells (deficiency payment of $2.8 million per well)

•January 1, 2021 - December 31, 2023 - 25 wells (deficiency payment of $2.8 million per well)

Gathering Agreements Prior to 2018

On December 1, 2016, we entered into new fixed-fee gathering agreements with Noble Energy and CNX Gas that replaced the gathering agreements that had been in place since our IPO. Our gathering agreement with Noble Energy was assigned to HG Energy upon consummation of the Noble Energy Asset Sale effective June 28, 2017. The terms of the agreement remain unchanged following the assignment, except as it relates to HG Energy’s inability to, without the Partnership’s consent, release dedicated acreage in connection with a transfer of such acreage free of the dedication to us, and exercise other initial shipper rights provided under the gathering agreement.

HG Energy is currently not a related party of the Partnership; accordingly, the focus of the following disclosure is on current and historical related party transactions, which do not include transactions with HG Energy. Our fees for gathering services, throughout 2018, are based on the type and scope of the midstream services we provide, summarized as follows:

• For the services we provide with respect to natural gas from the Marcellus Shale formation that does not require downstream processing, or dry gas, we will receive a fee of $0.431 per MMBtu.

• For the services we provide with respect to natural gas from the Marcellus Shale formation that requires downstream processing, or wet gas, we will receive:

◦ a fee of $0.296 per MMBtu in the Moundsville area (Marshall County, West Virginia) and in the Pittsburgh International Airport area; and

◦ a fee of $0.593 per MMBtu for all other areas in the dedication area.

• For the services we provide with respect to natural gas from the Utica Shale formation, we will receive a weighted average rate of $0.16 per MMBtu.

• Our fees for condensate services will be $5.38 per Bbl in the Majorsville area and $2.693 per Bbl in the Moundsville area.

Each of the foregoing fees escalates by 2.5% on January 1 on an annual basis, through and including the final calendar year of the initial term. Commencing on January 1, 2035, and as of January 1 thereafter, each of the applicable fees will be adjusted pursuant to the percentage change in CPI-U, but such fees will never escalate or decrease by more than 3%. Notwithstanding the foregoing, from time to time, CNX Gas and HG Energy may request rate reductions under certain circumstances, which are reviewed by the board of directors of our general partner, with oversight, as our board of directors deems necessary, from our conflicts committee. No rate reduction arrangements were active at June 30, 2018.

We gather, compress, dehydrate and deliver all of CNX Gas’ dedicated natural gas in the Marcellus Shale on a first-priority basis and gather, inject, stabilize and store all of CNX Gas’ dedicated condensate on a first-priority basis, with the exception that until December 1, 2018, CNX Gas will receive first-priority service in our Majorsville system with respect to a certain volume of production (revised bi-annually) and any excess production will receive second-priority service.

CNX Gas provides us with quarterly updates on its drilling and development operations, which include detailed descriptions of the drilling plans, production details and well locations for periods that range from up to 24-48 months, as well as more general development plans that may extend as far as ten years. In addition, we regularly meet with CNX Gas to discuss our current plans to timely construct the necessary facilities to be able to provide midstream services to them on our dedicated acreage. In the event that we do not perform our obligations under a gathering agreement, CNX Gas will be entitled to certain rights and procedural remedies thereunder, including the temporary and/or permanent release from dedication discussed below and indemnification from us.

There are no restrictions under our gathering agreements on the ability of CNX Gas to transfer acreage in the right of first offer (“ROFO”) area, and any such transfer of acreage in the ROFO area will not be subject to our right of first offer. 

Upon completion of its 20-year term in 2037, our gathering agreement with CNX Gas will continue in effect from year to year until such time as the agreement is terminated by either us or CNX Gas on or before 180 days prior written notice.

Registration Rights Agreement

On January 3, 2018, in connection with the closing of the General Partner Transaction, the Partnership entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with Noble Energy relating to the registered resale of common units that Noble Energy acquired in connection with the IPO and upon conversion of subordinated units representing limited partner interests in the Partnership (collectively, the “Registrable Securities”).

Pursuant to the Registration Rights Agreement, the Partnership was required to prepare and file a registration statement, or amend an existing registration statement, for the registered resale of the Registrable Securities. Such registration statement was made effective March 26, 2018.

In certain circumstances, and subject to customary qualifications and limitations, Noble Energy has piggyback registration rights on offerings of common units initiated by the Partnership and other holders of common units. Noble also has the right to request that the Partnership initiate up to four Demand Underwritten Offerings (as defined in the Registration Rights Agreement) of Registrable Securities, subject to certain limitations described in the Registration Rights Agreement. The Registration Rights Agreement will terminate no later than March 26, 2021, which is the third anniversary of the date on which the registration statement became effective.

Under the terms of the Registration Rights Agreement, Noble Energy executed an underwritten public offering of 7,475,000 of its common units in the Partnership on June 29, 2018. See Note 1–Description of Business for additional information.

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RECEIVABLES

6 Months Ended

Jun. 30, 2018

Receivables [Abstract]

RECEIVABLES

RECEIVABLES

Receivables consisted of the following:

(in thousands)	June 30, 2018		December 31, 2017
Receivables - related party
CNX	$	12,072	$	12,801
CNX Gathering	—		303
Receivables - related party	$	12,072	$	13,104
Receivables - third party	7,546		8,251
Total receivables	$	19,618	$	21,355

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PROPERTY AND EQUIPMENT

6 Months Ended

Jun. 30, 2018

Property, Plant and Equipment [Abstract]

PROPERTY AND EQUIPMENT

PROPERTY AND EQUIPMENT

Property and equipment consisted of the following:

(in thousands)	June 30, 2018		December 31, 2017		Estimated Useful Lives in Years
Land	$	47,975	$	76,130	N/A
Gathering equipment	570,603		662,595		25 — 40
Compression equipment	176,652		180,038		30 — 40
Processing equipment	30,979		30,979		40
Assets under construction	38,402		23,099		N/A
Total Property and Equipment	$	864,611	$	972,841
Less: Accumulated depreciation
Gathering equipment	$	50,744	$	53,544
Compression equipment	15,808		14,886
Processing equipment	5,546		5,133
Total Accumulated Depreciation	$	72,098	$	73,563
Property and Equipment, Net	$	792,513	$	899,278

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OTHER ASSETS

6 Months Ended

Jun. 30, 2018

Other Assets [Abstract]

OTHER ASSETS

OTHER ASSETS

Other assets consisted of the following:

(in thousands)	June 30, 2018		December 31, 2017
Pipe stock	$	—	$	392
Financing fees	3,219		122
Other	275		79
Total Other Assets	$	3,494	$	593

On March 8, 2018, the Partnership entered into a $600.0 million secured revolving credit facility. In connection with the new credit facility, the Partnership recorded approximately $4.4 million in deferred financing fees, of which approximately $0.9 million is classified as a current asset. See Note 10–Revolving Credit Facility.

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ACCOUNTS PAYABLE - RELATED PARTY

6 Months Ended

Jun. 30, 2018

Payables and Accruals [Abstract]

ACCOUNTS PAYABLE - RELATED PARTY

ACCOUNTS PAYABLE —RELATED PARTY

Related party payables consisted of the following:

(in thousands)	June 30, 2018		December 31, 2017
CNX Resources:
Expense reimbursements	$	1,148	$	780
Capital expenditures reimbursements	—		83
General and administrative services	2,055		1,458
Total due to CNX Resources	3,203		2,321
Noble Energy:
General and administrative services	—		55
Total due to Noble Energy	—		55
CNX Gathering LLC:
Capital expenditures reimbursement	8		—
Total due to CNX Gathering LLC	8		—
Total Accounts Payable — Related Party	$	3,211	$	2,376

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REVOLVING CREDIT FACILITY

6 Months Ended

Jun. 30, 2018

Debt Disclosure [Abstract]

REVOLVING CREDIT FACILITY

REVOLVING CREDIT FACILITY

On March 8, 2018, we entered into a $600.0 million secured revolving credit facility with an accordion feature that allows, subject to certain terms and conditions, the Partnership to increase the available borrowings under the facility by up to an additional $250.0 million. The new revolving credit facility matures on March 8, 2023 and replaced the prior $250.0 million revolving credit facility, which was unsecured. The available borrowing capacity under the new revolving credit facility is limited by certain financial covenants pertaining to leverage and interest coverage ratios as defined in the revolving credit facility agreement.

Borrowings under the new revolving credit facility bear interest at our option at either:

• the base rate, which is the highest of (i) the federal funds open rate plus 0.50%, (ii) PNC Bank, N.A.’s prime rate, and (iii) the one-month LIBOR rate plus 1.0%, in each case, plus a margin ranging from 0.75% to 1.75%; or

• the LIBOR rate, which is the LIBOR rate plus a margin ranging from 1.75% to 2.75%.

Interest on base rate loans is payable on the first business day of each calendar quarter. Interest on LIBOR loans is payable on the last day of each interest period or, in the case of interest periods longer than three months, every three months. The unused portion of our revolving credit facility is subject to a commitment fee ranging from 0.375% to 0.500% per annum depending on our most recent consolidated leverage ratio.

The facility includes restrictions on the ability of the Partnership, its subsidiary guarantors and certain of its non-guarantor, non-wholly-owned subsidiaries, except in certain circumstances, to: (i) create, incur, assume or suffer to exist indebtedness; (ii) create or permit to exist liens on their properties; (iii) prepay certain indebtedness unless there is no default or event of default under the facility; (iv) make or pay any dividends or distributions in excess of certain amounts; (v) merge with or into another person, liquidate or dissolve; or acquire all or substantially all of the assets of any going concern or going line of business or acquire all or a substantial portion of another person’s assets; (vi) make particular investments and loans; (vii) sell, transfer, convey, assign or dispose of its assets or properties other than in the ordinary course of business and other select instances; (viii) deal with any affiliate except in the ordinary course of business on terms no less favorable to the Partnership than it would otherwise receive in an arm’s length transaction; and (ix) amend in any material manner its certificate of incorporation, bylaws, or other organizational documents without giving prior notice to the lenders and, in some cases, obtaining the consent of the lenders. The agreement also contains customary events of default, including, but not limited to, a cross-default to certain other debt, breaches of representations and warranties, change of control events and breaches of covenants. The obligations under the revolving credit facility agreement are secured by the Partnership’s economic interests in each of the Limited Partnerships and all of the assets of the Anchor Systems.

In addition, the Partnership is obligated to maintain at the end of each fiscal quarter:

• a maximum total leverage ratio of no greater than between 4.75 to 1.00 ranging to no greater than 5.50 to 1.00 in certain circumstances;

• a maximum secured leverage ratio of no greater than 3.50 to 1.00; and

• a minimum interest coverage ratio of no less than 2.50 to 1.00;

The Partnership was in compliance with all financial covenants at June 30, 2018.

On June 30, 2018, the Partnership’s balance on the revolving credit facility was $11.0 million at an interest rate of 4.09%. After giving effect to the limitations on available capacity described in the revolving credit facility agreement, we estimate that the Partnership had approximately $494.0 million available for borrowing at June 30, 2018.

At December 31, 2017, the outstanding balance on the then-effective revolving credit facility was $149.5 million at an interest rate of 3.11%.

LONG-TERM DEBT

On March 16, 2018, the Partnership, together with its wholly owned subsidiary CNX Midstream Finance Corp (“Finance Corp”), (collectively, the “Issuers”), completed a private offering of $400.0 million in 6.5% senior notes due 2026 (the “Senior Notes”), with related guarantees (the “Guarantees”) and received net proceeds of approximately $393.0 million, after deducting the initial purchasers’ discount and commissions and estimated offering expenses, which are recorded in our consolidated balance sheet as a reduction to the principal amount. Proceeds from the Senior Notes offering were primarily used to fund the Shirley-Penns Acquisition and repay existing indebtedness under our prior $250.0 million unsecured revolving credit facility. The Senior Notes mature on March 15, 2026 and accrue interest at a rate of 6.5% per year, which is payable semi-annually in arrears on March 15 and September 15, beginning September 15, 2018. There are no principal payment requirements on the Senior Notes prior to maturity.

As of the dates presented below, the Partnership had long-term debt of:

	June 30, 2018		December 31, 2017
Senior Notes due March 2026 at 6.5%	$	400,000	$	—
Less: Unamortized debt issuance costs	1,081		—
Less: Unamortized bond discount	5,750		—
Long-term debt	$	393,169	$	—

The Senior Notes and Guarantees were issued pursuant to an indenture (the “Indenture”), dated March 16, 2018, among the Partnership, Finance Corp, the guarantors party thereto (the “Guarantors”) and UMB Bank, N.A., as trustee (the “Trustee”). The Senior Notes rank equally in right of payment with all of the Issuers’ existing and future senior indebtedness and senior to any subordinated indebtedness that the Issuers’ may incur. The Guarantees rank equally in right of payment to all of the Guarantors’ existing and future senior indebtedness.

The Issuers may redeem all or part of the Senior Notes at redemption prices ranging from 104.875% beginning March 15, 2021 to 100.0% beginning March 15, 2024. Prior to March 15, 2021, the Issuers may on one or more occasions redeem up to 35.0% of the principal amount of the Senior Notes with an amount of cash not greater than the amount of the net cash proceeds from one or more equity offerings at a redemption price of 106.50%. At any time or from time to time prior to March 15, 2021, the Issuers may also redeem all or a part of the Senior Notes, at a redemption price equal to 100.0% of the principal amount thereof plus the Applicable Premium, as defined in the Indenture, plus accrued and unpaid interest.

If the Partnership experiences certain kinds of changes of control, holders of the Senior Notes will be entitled to require the Partnership to repurchase all or any part of that holder’s Senior Notes pursuant to an offer on the terms set forth in the Indenture. The Partnership will offer to make a cash payment equal to 101.0% of the aggregate principal amount of the Senior Notes repurchased plus accrued and unpaid interest on the Senior Notes repurchased to, but not including, the date of purchase, subject to the rights of holders of the Senior Notes on the relevant record date to receive interest due on the relevant interest payment date.

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LONG-TERM DEBT

6 Months Ended

Jun. 30, 2018

Debt Disclosure [Abstract]

LONG-TERM DEBT

REVOLVING CREDIT FACILITY

On March 8, 2018, we entered into a $600.0 million secured revolving credit facility with an accordion feature that allows, subject to certain terms and conditions, the Partnership to increase the available borrowings under the facility by up to an additional $250.0 million. The new revolving credit facility matures on March 8, 2023 and replaced the prior $250.0 million revolving credit facility, which was unsecured. The available borrowing capacity under the new revolving credit facility is limited by certain financial covenants pertaining to leverage and interest coverage ratios as defined in the revolving credit facility agreement.

Borrowings under the new revolving credit facility bear interest at our option at either:

• the base rate, which is the highest of (i) the federal funds open rate plus 0.50%, (ii) PNC Bank, N.A.’s prime rate, and (iii) the one-month LIBOR rate plus 1.0%, in each case, plus a margin ranging from 0.75% to 1.75%; or

• the LIBOR rate, which is the LIBOR rate plus a margin ranging from 1.75% to 2.75%.

Interest on base rate loans is payable on the first business day of each calendar quarter. Interest on LIBOR loans is payable on the last day of each interest period or, in the case of interest periods longer than three months, every three months. The unused portion of our revolving credit facility is subject to a commitment fee ranging from 0.375% to 0.500% per annum depending on our most recent consolidated leverage ratio.

The facility includes restrictions on the ability of the Partnership, its subsidiary guarantors and certain of its non-guarantor, non-wholly-owned subsidiaries, except in certain circumstances, to: (i) create, incur, assume or suffer to exist indebtedness; (ii) create or permit to exist liens on their properties; (iii) prepay certain indebtedness unless there is no default or event of default under the facility; (iv) make or pay any dividends or distributions in excess of certain amounts; (v) merge with or into another person, liquidate or dissolve; or acquire all or substantially all of the assets of any going concern or going line of business or acquire all or a substantial portion of another person’s assets; (vi) make particular investments and loans; (vii) sell, transfer, convey, assign or dispose of its assets or properties other than in the ordinary course of business and other select instances; (viii) deal with any affiliate except in the ordinary course of business on terms no less favorable to the Partnership than it would otherwise receive in an arm’s length transaction; and (ix) amend in any material manner its certificate of incorporation, bylaws, or other organizational documents without giving prior notice to the lenders and, in some cases, obtaining the consent of the lenders. The agreement also contains customary events of default, including, but not limited to, a cross-default to certain other debt, breaches of representations and warranties, change of control events and breaches of covenants. The obligations under the revolving credit facility agreement are secured by the Partnership’s economic interests in each of the Limited Partnerships and all of the assets of the Anchor Systems.

In addition, the Partnership is obligated to maintain at the end of each fiscal quarter:

• a maximum total leverage ratio of no greater than between 4.75 to 1.00 ranging to no greater than 5.50 to 1.00 in certain circumstances;

• a maximum secured leverage ratio of no greater than 3.50 to 1.00; and

• a minimum interest coverage ratio of no less than 2.50 to 1.00;

The Partnership was in compliance with all financial covenants at June 30, 2018.

On June 30, 2018, the Partnership’s balance on the revolving credit facility was $11.0 million at an interest rate of 4.09%. After giving effect to the limitations on available capacity described in the revolving credit facility agreement, we estimate that the Partnership had approximately $494.0 million available for borrowing at June 30, 2018.

At December 31, 2017, the outstanding balance on the then-effective revolving credit facility was $149.5 million at an interest rate of 3.11%.

LONG-TERM DEBT

On March 16, 2018, the Partnership, together with its wholly owned subsidiary CNX Midstream Finance Corp (“Finance Corp”), (collectively, the “Issuers”), completed a private offering of $400.0 million in 6.5% senior notes due 2026 (the “Senior Notes”), with related guarantees (the “Guarantees”) and received net proceeds of approximately $393.0 million, after deducting the initial purchasers’ discount and commissions and estimated offering expenses, which are recorded in our consolidated balance sheet as a reduction to the principal amount. Proceeds from the Senior Notes offering were primarily used to fund the Shirley-Penns Acquisition and repay existing indebtedness under our prior $250.0 million unsecured revolving credit facility. The Senior Notes mature on March 15, 2026 and accrue interest at a rate of 6.5% per year, which is payable semi-annually in arrears on March 15 and September 15, beginning September 15, 2018. There are no principal payment requirements on the Senior Notes prior to maturity.

As of the dates presented below, the Partnership had long-term debt of:

	June 30, 2018		December 31, 2017
Senior Notes due March 2026 at 6.5%	$	400,000	$	—
Less: Unamortized debt issuance costs	1,081		—
Less: Unamortized bond discount	5,750		—
Long-term debt	$	393,169	$	—

The Senior Notes and Guarantees were issued pursuant to an indenture (the “Indenture”), dated March 16, 2018, among the Partnership, Finance Corp, the guarantors party thereto (the “Guarantors”) and UMB Bank, N.A., as trustee (the “Trustee”). The Senior Notes rank equally in right of payment with all of the Issuers’ existing and future senior indebtedness and senior to any subordinated indebtedness that the Issuers’ may incur. The Guarantees rank equally in right of payment to all of the Guarantors’ existing and future senior indebtedness.

The Issuers may redeem all or part of the Senior Notes at redemption prices ranging from 104.875% beginning March 15, 2021 to 100.0% beginning March 15, 2024. Prior to March 15, 2021, the Issuers may on one or more occasions redeem up to 35.0% of the principal amount of the Senior Notes with an amount of cash not greater than the amount of the net cash proceeds from one or more equity offerings at a redemption price of 106.50%. At any time or from time to time prior to March 15, 2021, the Issuers may also redeem all or a part of the Senior Notes, at a redemption price equal to 100.0% of the principal amount thereof plus the Applicable Premium, as defined in the Indenture, plus accrued and unpaid interest.

If the Partnership experiences certain kinds of changes of control, holders of the Senior Notes will be entitled to require the Partnership to repurchase all or any part of that holder’s Senior Notes pursuant to an offer on the terms set forth in the Indenture. The Partnership will offer to make a cash payment equal to 101.0% of the aggregate principal amount of the Senior Notes repurchased plus accrued and unpaid interest on the Senior Notes repurchased to, but not including, the date of purchase, subject to the rights of holders of the Senior Notes on the relevant record date to receive interest due on the relevant interest payment date.

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COMMITMENTS AND CONTINGENCIES

6 Months Ended

Jun. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

Litigation

The Partnership may become involved in certain legal proceedings from time to time, and where appropriate, we have accrued our estimate of the probable costs for the resolution of these claims. The Partnership believes that the ultimate outcome of any matter currently pending against the Partnership will not materially affect the Partnership’s business, financial condition, results of operations, liquidity or ability to make distributions.

Leases

We have entered into various non-cancelable operating leases, primarily related to compression facilities. Future minimum lease payments under operating leases as of June 30, 2018 are as follows:

(in thousands)	Minimum Lease Payments
Period from July 1, 2018 through December 31, 2018	$	1,023
Year ending December 31, 2019	1,627
Year ending December 31, 2020	1,042
	$	3,692

Rental expense under operating leases was $2.0 million and $1.9 million for the three months ended June 30, 2018 and 2017, respectively. Rental expense under operating leases was $4.1 million and $3.8 million for the six months ended June 30, 2018 and 2017, respectively. These expenses are included within operating expense - third party on our consolidated statement of operations.

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SEGMENT INFORMATION

6 Months Ended

Jun. 30, 2018

Segment Reporting [Abstract]

SEGMENT INFORMATION

SEGMENT INFORMATION

Operating segments are the revenue-producing components of a company for which separate financial information is produced internally and is subject to evaluation by the chief operating decision maker in deciding how to allocate resources. Prior to the CNX and HG Energy Transaction, the Partnership had three operating segments, which also represented its reportable segments - the Anchor Systems, Growth Systems and Additional Systems, each of which does business entirely within the United States of America. See Note 1–Description of Business for additional information.

During the first quarter of 2018, the Partnership, through its 100% interest in the Anchor Systems, completed the Shirley-Penns Acquisition. Prior to March 16, 2018, the Partnership held a 5% controlling interest in the earnings and throughput related to the Shirley-Penns System; accordingly, until March 16, 2018, results attributable to limited and general partners of the Partnership reflect a 5% interest in the Shirley-Penns System. Results net to the Partnership include activity related to the Shirley-Penns Acquisition beginning March 16, 2018. However, in accordance with ASC 280 - Segment Reporting, information is reported in the tables below, for comparability purposes, as if the Shirley-Penns Acquisition occurred on January 1, 2017.

In connection with the HG Energy Transaction, the Partnership distributed its 5% interest in the Growth Systems and related assets as well as its 5% interest in the Moundsville midstream assets, which were previously a part of the Additional Systems, to CNX Gathering, which transferred these assets to HG Energy. Because the Growth Systems and Moundsville area of the Additional Systems had activity for all of 2017 and through May 2, 2018, we will continue to present consistent segment information with regards to this transaction throughout the year ending December 31, 2018 for comparative purposes.

Segment results for the periods presented were as follows:

	Three Months Ended June 30,					Six Months Ended June 30,
(in thousands)	2018		2017			2018		2017
Gathering Revenue:
Anchor Systems	$	56,584	$	50,195		$	112,774	$	102,894
Growth Systems	668		2,018			2,572		4,243
Additional Systems	3,762		4,321			9,537		8,355
Total Gathering Revenue	$	61,014	$	56,534		$	124,883	$	115,492
Net Income (Loss):
Anchor Systems	$	29,991	$	30,764		$	63,134	$	62,380
Growth Systems	186		506			379		453
Additional Systems	105		(1,518		)	474		159
Total Net Income	$	30,282	$	29,752		$	63,987	$	62,992
Depreciation Expense:
Anchor Systems	$	4,733	$	4,201		$	9,203	$	8,397
Growth Systems	195		543			748		1,088
Additional Systems	515		931			1,348		1,861
Total Depreciation Expense	$	5,443	$	5,675		$	11,299	$	11,346
Capital Expenditures for Segment Assets:
Anchor Systems	$	24,502	$	11,841		$	38,290	$	22,374
Growth Systems	42		382			120		821
Additional Systems	1,071		—			3,177		220
Total Capital Expenditures	$	25,615	$	12,223		$	41,587	$	23,415

Segment assets as of the dates presented were as follows:

(in thousands)	June 30, 2018		December 31, 2017
Segment Assets
Anchor Systems	$	737,152	$	694,942
Growth Systems	—		92,659
Additional Systems	81,906		138,988
Total Segment Assets	$	819,058	$	926,589

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LONG-TERM INCENTIVE PLAN

6 Months Ended

Jun. 30, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

LONG-TERM INCENTIVE PLAN

LONG-TERM INCENTIVE PLAN

Under the CNX Midstream Partners LP 2014 Long-Term Incentive Plan (our “LTIP”), our general partner may issue long-term equity-based awards to directors, officers and employees of the general partner or its affiliates, or to any consultants, affiliates of our general partner or other individuals who perform services on behalf of the Partnership. The Partnership is responsible for the cost of awards granted under the LTIP, which limits the number of units that may be delivered pursuant to vested awards to 5.8 million common units, subject to proportionate adjustment in the event of unit splits and similar events. Common units subject to awards that are canceled, forfeited, withheld to satisfy tax withholding obligations or otherwise terminated without delivery of the common units will be available for delivery pursuant to other awards.

The following table presents phantom unit activity during the six month period ended June 30, 2018:

	Number of Units	Weighted Average Grant Date Fair Value
Total awarded and unvested at December 31, 2017	134,153	$	16.40
Granted	132,933	19.14
Vested	(70,872)	16.65
Forfeited	(17,639)	16.25
Total awarded and unvested at June 30, 2018	178,575	$	18.30

The Partnership accounts for phantom units as equity awards and records compensation expense on a straight line basis over the vesting period based on the fair value of the awards at their grant dates. Awards granted to independent directors vest over a period of one year, and awards granted to certain officers and employees of the general partner vest 33% per year over a period of three years.

The Partnership recognized $0.7 million and $0.4 million of compensation expense related to phantom units for the three months ended June 30, 2018 and 2017, respectively, and $1.3 million and $0.7 million for the six months ended June 30, 2018 and 2017, respectively, which was included in general and administrative expense - related party in the consolidated statements of operations.

At June 30, 2018, the unrecognized compensation related to all outstanding awards was $2.4 million, which is expected to be recognized over the following two years.

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SUBSEQUENT EVENTS

6 Months Ended

Jun. 30, 2018

Subsequent Events [Abstract]

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS

On July 27, 2018, the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders with respect to the second quarter of 2018 of $0.3361 per common unit. The cash distribution will be paid on August 14, 2018 to unitholders of record at the close of business on August 7, 2018.

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SIGNIFICANT ACCOUNTING POLICIES (Policies)

6 Months Ended

Jun. 30, 2018

Accounting Policies [Abstract]

Basis of Accounting

The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”).

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and various disclosures. Actual results could differ from those estimates, which are evaluated on an ongoing basis, utilizing historical experience and other methods considered reasonable under the particular circumstances. Although these estimates are based on management’s best available knowledge at the time, changes in facts and circumstances or discovery of new facts or circumstances may result in revised estimates and actual results may differ from these estimates. Effects on the Partnership’s business, financial position and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revision become known.

Principles of Consolidation

During the periods presented in this Quarterly Report on Form 10-Q, the consolidated financial statements include the accounts of the Partnership and all of its controlled subsidiaries, including 100% of each of the Anchor Systems, Growth Systems and Additional Systems. Although the Partnership has less than a 100% economic interest in the Growth and Additional Systems, each was consolidated fully with the results of the Partnership. However, after adjusting for noncontrolling interests, net income attributable to general and limited partner ownership interests in the Partnership reflects only that portion of net income that is attributable to the Partnership’s unitholders. The Partnership distributed its interests in the Growth Systems and the Moundsville area of the Additional Systems in connection with the HG Energy Transaction.

Transactions between the Partnership and CNX have been identified in the consolidated financial statements as transactions between related parties and are disclosed in Note 5–Related Party Transactions.

Revenue Recognition

On January 1, 2018, the Partnership adopted Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers and all the related amendments (“new revenue standard”) using the modified retrospective method. We did not have a transition adjustment as a result of the adoption of the new revenue standard.

Revenues from contracts with customers

We record revenue when obligations under the terms of the contracts with our shippers are satisfied; generally this occurs on a daily basis as we gather gas at the wellhead. Revenue is measured as the amount of consideration we expect to receive in exchange for providing the natural gas gathering services.

Nature of performance obligations

At contract inception, we assess the services promised in our contracts with customers and identify a performance obligation for each promised service that is distinct. To identify the performance obligations, we consider all of the services promised in the contract, regardless of whether they are explicitly stated or are implied by customary business practices.

Our revenue is generated from natural gas gathering activities. The gas gathering services are interruptible in nature and include charges for the volume of gas actually gathered and do not guarantee access to the system. Volumetric-based fees relate to actual volumes gathered. In general, the interruptible gathering of each unit (MMBtu) of natural gas represents a separate performance obligation. Payment terms for these contracts require payment within 25 days of the end of the calendar month in which the hydrocarbons are gathered.

Transaction price allocated to remaining performance obligations

The new revenue standard requires that we disclose the aggregate amount of transaction price that is allocated to performance obligations that have not yet been satisfied. However, the guidance provides certain practical expedients that limit this requirement.

Substantially all of our revenues are derived from contracts with CNX and HG Energy with terms of greater than one year. Under these contracts, the interruptible gathering of each unit of natural gas represents a separate performance obligation.

For revenue associated with the Shirley-Penns System, our only contract with terms that are greater than one year, the aggregate amount of the transaction price allocated to remaining performance obligations was $422.9 million at June 30, 2018. We expect to recognize revenue of $14.2 million and $28.8 million, respectively during the remainder of the years ending December 31, 2018 and December 31, 2019. The amount of revenue associated with this contract up to the minimum volume commitment (“MVC”) is fixed in nature, and volumes that we may gather above the MVC will be variable in nature. As of June 30, 2018, no future performance obligations exist relative to volumes to be gathered in excess of the MVC as the related volumes have not yet been nominated for gathering. Therefore, we have not disclosed the value of unsatisfied performance obligations for the variable aspect of this agreement, nor have we disclosed the value of other unsatisfied performance obligations that are variable in nature.

Prior-period performance obligations

We record revenue when obligations under the terms of the contracts with our shippers are satisfied; generally this occurs on a daily basis when we gather gas at the wellhead. In some cases, we are required to estimate the amount of natural gas that we have gathered during an accounting period and record any differences between our estimates and the actual units of natural gas that we gathered in the following month. We have existing internal controls for our revenue estimation process and related accruals; historically, any identified differences between our revenue estimates and actual revenue received have not been significant. For the quarters and six months ended June 30, 2018 and 2017, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

Disaggregation of revenue

See Note 13–Segment Information for additional information.

Contract balances

We invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our contracts with customers do not give rise to contract assets or liabilities under the new revenue standard. We also have no contract assets recognized from the costs.

See Note 6–Receivables for additional information.

Classification

The fees we charge our Sponsor and the fees we charged Noble Energy, prior to consummation of the Noble Energy Asset Sale, are recorded in gathering revenue — related party in our consolidated statements of operations. Following consummation of the Noble Energy Asset Sale, fees from midstream services we perform for HG Energy, and any other third party shipper, are recorded in gathering revenue — third party in our consolidated statements of operations.

Cash

Cash includes cash on hand and on deposit at banking institutions.

Receivables

Receivables are recorded at the invoiced amount and do not bear interest. When applicable, we reserve for specific accounts receivable when it is probable that all or a part of an outstanding balance will not be collected. Collectability is determined based on terms of sale, credit status of customers and various other circumstances. We regularly review collectability and establish or adjust the allowance as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.

Fair Value Measurement

The Financial Accounting Standards Board (the “FASB”) Accounting Standards Codification (“ASC”) Topic 820, Fair Value Measurements and Disclosures, clarifies the definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., the initial recognition of asset retirement obligations and impairments of long‑lived assets). The fair value is the price that we estimate we would receive upon selling an asset or that we would pay to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize input to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1, that are observable for the asset or liability, either directly or indirectly.

The carrying values of our current assets and current liabilities approximate fair values due to their short maturities. The carrying value of our revolving credit facility approximates fair value as the facility bears interest at a variable, market rate that resets periodically.

Property and Equipment

Property and equipment is recorded at cost upon acquisition and is depreciated on a straight-line basis over the assets’ estimated useful lives or over their lease terms. Expenditures which extend the useful lives of existing property and equipment are capitalized. When properties are retired or otherwise disposed, the related cost and accumulated depreciation are removed from the respective accounts and any profit or loss on disposition is recognized as a gain or loss.

We routinely assess whether impairment indicators arise during any given quarter and have processes in place to ensure that we become aware of such indicators. Impairment indicators include, but are not limited to, sustained decreases in commodity prices, a decline in customer well results and lower throughput forecasts, and increases in construction or operating costs. For such long-lived assets, impairment exists when the carrying amount of an asset or group of assets exceeds our estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset or group of assets. If the carrying amount of the long-lived asset(s) is not recoverable, based on the estimated future undiscounted cash flows, the impairment loss would be measured as the excess of the asset’s carrying amount over its estimated fair value. In the event that impairment indicators exist, we conduct an impairment test.

Fair value represents the estimated price between market participants to sell an asset in the principal or most advantageous market for the asset, based on assumptions a market participant would make. When warranted, management assesses the fair value of long-lived assets using commonly accepted techniques and may use more than one source in making such assessments. Sources used to determine fair value include, but are not limited to, recent third-party comparable sales, internally developed discounted cash flow analyses and analyses from outside advisors. Significant changes, such as the condition of an asset or management’s intent to utilize the asset, generally require management to reassess the cash flows related to long-lived assets. No property and equipment impairments were identified during the periods presented in the accompanying consolidated financial statements.

Environmental Matters

We are subject to various federal, state and local laws and regulations relating to the protection of the environment. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. At this time, we are unable to assess the timing and/or effect of potential liabilities related to greenhouse gas emissions or other environmental issues.

Asset Retirement Obligations

Our gathering pipelines and compressor stations have an indeterminate life. If properly maintained, they will operate for an indeterminate period as long as supply and demand for natural gas exists, which we expect for the foreseeable future. We are under no legal or contractual obligation to restore or dismantle our gathering system upon abandonment.

Variable Interest Entities

Each of the Anchor, Growth and Additional Systems is a limited partnership (the “Limited Partnerships”) and a variable interest entity (“VIE”). These VIEs correspond with the manner in which we report our segment information in Note 13–Segment Information, which also includes information regarding the Partnership’s involvement with each of these VIEs and their relative contributions to our financial position, operating results and cash flows.

The Partnership fully consolidates each of the Limited Partnerships through its ownership of CNX Midstream Operating Company LLC (the “Operating Company”). The Operating Company, through its general partner ownership interest in each of the Limited Partnerships, is considered to be the primary beneficiary for accounting purposes and has the power to direct all substantive strategic and day-to-day operational decisions of the Limited Partnerships.

Equity Compensation

Equity compensation expense for all unit-based compensation awards is based on the grant date fair value estimated in accordance with the provisions of the Stock Compensation Topic of the FASB ASC. We recognize unit-based compensation costs on a straight-line basis over the requisite service period of an award, which is generally the same as the award’s vesting term.

Income Taxes

We are treated as a partnership for federal and state income tax purposes, with each partner being separately taxed on its share of the Partnership’s taxable income. Accordingly, no provision for federal or state income taxes has been recorded in the Partnership’s consolidated financial statements for any period presented in the accompanying consolidated financial statements.

Reclassifications

Certain amounts in prior periods have been reclassified to conform to the current reporting classifications with no effect on previously reported net income or partners’ capital.

Recent Accounting Pronouncements

In February 2016, the FASB issued ASU 2016-02–Leases (Topic 842), which is intended to improve financial reporting about leasing transactions. The ASU will require organizations (“lessees”) that lease assets with terms of more than 12 months to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. Organizations that own the assets leased by lessees (“lessors”) will remain largely unchanged from current GAAP. In addition, the ASU will require disclosures to help investors and other financial statement users better understand the amount, timing and uncertainty of cash flows arising from leases. The effective date of this ASU is for fiscal years beginning after December 31, 2018 and interim periods within that year. We are currently finalizing a project plan, reviewing all existing leases and agreements that are covered under the standard, assessing the impact to our financial statements as well as planning for adoption and implementation of this standard, which includes assessing the impact on information systems and internal controls.

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CASH DISTRIBUTIONS (Tables)

6 Months Ended

Jun. 30, 2018

Equity [Abstract]

Schedule of Target Distributions

The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2% general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its 2% general partner interest, our general partner has not transferred its IDRs and that there are no arrearages on common units.

			Marginal Percentage Interest in Distributions
Distribution Targets	Total Quarterly Distribution Per Unit Target Amount		Unitholders	General Partner (including IDRs)
Minimum Quarterly Distribution		$0.2125	98%	2%
First Target Distribution	Above $0.2125	up to $0.24438	98%	2%
Second Target Distribution	Above $0.24438	up to $0.26563	85%	15%
Third Target Distribution	Above $0.26563	up to $0.31875	75%	25%
Thereafter	Above $0.31875		50%	50%

Cash Distributions

The Board of Directors declared the following cash distributions to the Partnership’s common and subordinated unitholders (through September 30, 2017) and to the general partner for the periods presented:

(in thousands, except per unit information)
Quarters Ended	Total Quarterly Distribution Per Unit		Total Quarterly Cash Distribution		Date of Distribution
Year ended December 31, 2017
March 31	$	0.2821	$	18,842	May 15, 2017
June 30	0.2922		19,698		August 14, 2017
September 30	0.3025		20,573		November 14, 2017
December 31	0.3133		21,489		February 14, 2018
Year ending December 31, 2018
March 31	$	0.3245	$	22,700	May 15, 2018

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NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST (Tables)

6 Months Ended

Jun. 30, 2018

Earnings Per Share [Abstract]

Schedule of Net Income (Loss) Per Unit

The following table illustrates the Partnership’s calculation of net income per unit for common and subordinated partner units:

	Three Months Ended June 30,				Six Months Ended   June 30,
(in thousands, except per unit information)	2018		2017		2018		2017
Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP	$	30,005	$	28,991	$	57,852	$	59,058
Less: General partner interest in net income, including incentive distribution rights	2,903		1,305		5,055		2,434
Limited partner interest in net income	$	27,102	$	27,686	$	52,797	$	56,624
Net income allocable to common units — basic and diluted	$	27,102	$	14,988	$	52,797	$	30,652
Net income allocable to subordinated units — basic and diluted	—		12,698		—		25,972
Limited partner interest in net income — basic and diluted	$	27,102	$	27,686	$	52,797	$	56,624
Weighted average limited partner units outstanding — Basic
Common units	63,638		34,422		63,630		34,412
Subordinated units	—		29,163		—		29,163
Total	63,638		63,585		63,630		63,575
Weighted average limited partner units outstanding — Diluted
Common units	63,677		34,481		63,670		34,467
Subordinated units	—		29,163		—		29,163
Total	63,677		63,644		63,670		63,630
Net income per limited partner unit — Basic
Common units	$	0.43	$	0.44	$	0.83	$	0.89
Subordinated units	—		0.44		—		0.89
Total	$	0.43	$	0.44	$	0.83	$	0.89
Net income per limited partner unit — Diluted
Common units	$	0.43	$	0.43	$	0.83	$	0.89
Subordinated units	—		0.44		—		0.89
Total	$	0.43	$	0.44	$	0.83	$	0.89

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RELATED PARTY TRANSACTIONS (Tables)

6 Months Ended

Jun. 30, 2018

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

Operating expense and general and administrative expense – related party are derived from CNX in the three and six months ended June 30, 2018 and from CNX and Noble Energy in the three and six months ended June 30, 2017 and consisted of the following:

	Three Months Ended   June 30,				Six Months Ended   June 30,
(in thousands)	2018		2017		2018		2017
Operational services — CNX	$	3,257	$	2,999	$	6,092	$	6,187
Electrical compression	1,822		4,090		3,422		8,530
Total Operating Expense — Related Party	$	5,079	$	7,089	$	9,514	$	14,717
CNX	$	3,620	$	2,530	$	7,232	$	5,241
Noble Energy	—		133		—		305
Total General and Administrative Expense — Related Party	$	3,620	$	2,663	$	7,232	$	5,546

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction

We expect to recognize at least the following amounts or revenue throughout the term of the MVC:

	Revenue under MVC (in millions)
Remainder of year ending December 31, 2018	$	14.2
Year ending December 31, 2019	28.8
Year ending December 31, 2020	34.7
Year ending December 31, 2021	40.8
Year ending December 31, 2022	47.8
Remainder of term	256.6
Total revenue to be recognized under Shirley-Penns contract through December 31, 2031	$	422.9

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RECEIVABLES (Tables)

6 Months Ended

Jun. 30, 2018

Receivables [Abstract]

Schedule of Receivables

Receivables consisted of the following:

(in thousands)	June 30, 2018		December 31, 2017
Receivables - related party
CNX	$	12,072	$	12,801
CNX Gathering	—		303
Receivables - related party	$	12,072	$	13,104
Receivables - third party	7,546		8,251
Total receivables	$	19,618	$	21,355

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PROPERTY AND EQUIPMENT (Tables)

6 Months Ended

Jun. 30, 2018

Property, Plant and Equipment [Abstract]

Property and Equipment

Property and equipment consisted of the following:

(in thousands)	June 30, 2018		December 31, 2017		Estimated Useful Lives in Years
Land	$	47,975	$	76,130	N/A
Gathering equipment	570,603		662,595		25 — 40
Compression equipment	176,652		180,038		30 — 40
Processing equipment	30,979		30,979		40
Assets under construction	38,402		23,099		N/A
Total Property and Equipment	$	864,611	$	972,841
Less: Accumulated depreciation
Gathering equipment	$	50,744	$	53,544
Compression equipment	15,808		14,886
Processing equipment	5,546		5,133
Total Accumulated Depreciation	$	72,098	$	73,563
Property and Equipment, Net	$	792,513	$	899,278

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OTHER ASSETS (Tables)

6 Months Ended

Jun. 30, 2018

Other Assets [Abstract]

Schedule of Other Assets

Other assets consisted of the following:

(in thousands)	June 30, 2018		December 31, 2017
Pipe stock	$	—	$	392
Financing fees	3,219		122
Other	275		79
Total Other Assets	$	3,494	$	593

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ACCOUNTS PAYABLE - RELATED PARTY (Tables)

6 Months Ended

Jun. 30, 2018

Payables and Accruals [Abstract]

Schedule of Related Party Payables

Related party payables consisted of the following:

(in thousands)	June 30, 2018		December 31, 2017
CNX Resources:
Expense reimbursements	$	1,148	$	780
Capital expenditures reimbursements	—		83
General and administrative services	2,055		1,458
Total due to CNX Resources	3,203		2,321
Noble Energy:
General and administrative services	—		55
Total due to Noble Energy	—		55
CNX Gathering LLC:
Capital expenditures reimbursement	8		—
Total due to CNX Gathering LLC	8		—
Total Accounts Payable — Related Party	$	3,211	$	2,376

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LONG-TERM DEBT (Tables)

6 Months Ended

Jun. 30, 2018

Debt Disclosure [Abstract]

Schedule of Debt

As of the dates presented below, the Partnership had long-term debt of:

	June 30, 2018		December 31, 2017
Senior Notes due March 2026 at 6.5%	$	400,000	$	—
Less: Unamortized debt issuance costs	1,081		—
Less: Unamortized bond discount	5,750		—
Long-term debt	$	393,169	$	—

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COMMITMENTS AND CONTINGENCIES (Tables)

6 Months Ended

Jun. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

Future minimum lease payments

Future minimum lease payments under operating leases as of June 30, 2018 are as follows:

(in thousands)	Minimum Lease Payments
Period from July 1, 2018 through December 31, 2018	$	1,023
Year ending December 31, 2019	1,627
Year ending December 31, 2020	1,042
	$	3,692

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SEGMENT INFORMATION (Tables)

6 Months Ended

Jun. 30, 2018

Segment Reporting [Abstract]

Schedule of Operating Revenues and Income from Operations

Segment results for the periods presented were as follows:

	Three Months Ended June 30,					Six Months Ended June 30,
(in thousands)	2018		2017			2018		2017
Gathering Revenue:
Anchor Systems	$	56,584	$	50,195		$	112,774	$	102,894
Growth Systems	668		2,018			2,572		4,243
Additional Systems	3,762		4,321			9,537		8,355
Total Gathering Revenue	$	61,014	$	56,534		$	124,883	$	115,492
Net Income (Loss):
Anchor Systems	$	29,991	$	30,764		$	63,134	$	62,380
Growth Systems	186		506			379		453
Additional Systems	105		(1,518		)	474		159
Total Net Income	$	30,282	$	29,752		$	63,987	$	62,992
Depreciation Expense:
Anchor Systems	$	4,733	$	4,201		$	9,203	$	8,397
Growth Systems	195		543			748		1,088
Additional Systems	515		931			1,348		1,861
Total Depreciation Expense	$	5,443	$	5,675		$	11,299	$	11,346
Capital Expenditures for Segment Assets:
Anchor Systems	$	24,502	$	11,841		$	38,290	$	22,374
Growth Systems	42		382			120		821
Additional Systems	1,071		—			3,177		220
Total Capital Expenditures	$	25,615	$	12,223		$	41,587	$	23,415

Reconciliation of Assets from Segment to Consolidated

Segment assets as of the dates presented were as follows:

(in thousands)	June 30, 2018		December 31, 2017
Segment Assets
Anchor Systems	$	737,152	$	694,942
Growth Systems	—		92,659
Additional Systems	81,906		138,988
Total Segment Assets	$	819,058	$	926,589

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LONG-TERM INCENTIVE PLAN (Tables)

6 Months Ended

Jun. 30, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Nonvested Performance-based Units Activity

The following table presents phantom unit activity during the six month period ended June 30, 2018:

	Number of Units	Weighted Average Grant Date Fair Value
Total awarded and unvested at December 31, 2017	134,153	$	16.40
Granted	132,933	19.14
Vested	(70,872)	16.65
Forfeited	(17,639)	16.25
Total awarded and unvested at June 30, 2018	178,575	$	18.30

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DESCRIPTION OF BUSINESS (Details) $ in Millions						3 Months Ended	6 Months Ended
	Jun. 29, 2018 shares	May 03, 2018 USD ($) a well	May 02, 2018 well	Mar. 16, 2018 USD ($)	Jan. 03, 2018 USD ($) shares	Jun. 30, 2018 shares	Jun. 30, 2018 USD ($) segment shares	Mar. 15, 2018	Dec. 31, 2017 shares	Nov. 15, 2017 shares	Sep. 30, 2014
Schedule of Equity Method Investments [Line Items]
Units outstanding (in shares) | shares						63,638,165	63,638,165		63,588,152
Number of operating segments | segment							3
Additional Systems | Devco III LP - Shirley Pennsboro
Schedule of Equity Method Investments [Line Items]
Noncontrolling interest, percent									95.00%
Additional Systems | Shirley-Penns System
Schedule of Equity Method Investments [Line Items]
Cash consideration transferred to purchase limited partner controlling interest				$ 265.0			$ 265.0
Noncontrolling interest, percent								95.00%
Ownership percentage (as a percent)								5.00%
Additional Systems | CONE Gathering
Schedule of Equity Method Investments [Line Items]
Noncontrolling interest, percent						95.00%	95.00%
Anchor Systems | Shirley-Penns System
Schedule of Equity Method Investments [Line Items]
Ownership interest				100.00%
Subordinated Units
Schedule of Equity Method Investments [Line Items]
Units outstanding (in shares) | shares										29,163,121
CNX Gas | NBL Midstream, LLC
Schedule of Equity Method Investments [Line Items]
Cash consideration transferred to purchase limited partner controlling interest					$ 305.0
Noble Energy
Schedule of Equity Method Investments [Line Items]
Units outstanding (in shares) | shares					21,692,198	14,217,198	14,217,198
Sale of retained units (in shares) | shares	7,475,000
CNX Gathering LLC | Additional Systems
Schedule of Equity Method Investments [Line Items]
Ownership percentage (as a percent)											5.00%
Shirley-Penns System | Anchor Systems
Schedule of Equity Method Investments [Line Items]
Ownership interest						100.00%
Shirley-Penns System | CNX Gas
Schedule of Equity Method Investments [Line Items]
Ownership interest				100.00%
CNX Gathering LLC | CNX Gas
Schedule of Equity Method Investments [Line Items]
Ownership interest					100.00%
CNX Gathering LLC | CNX Gas | NBL Midstream, LLC
Schedule of Equity Method Investments [Line Items]
Limited partner controlling interest acquired, percentage					50.00%
Senior Notes
Schedule of Equity Method Investments [Line Items]
Stated rate				6.50%		6.50%	6.50%
Exchange Transaction
Schedule of Equity Method Investments [Line Items]
Reduction in property and equipment, net		$ 133.1
Reduction in noncontrolling interest		179.5
Increase in common units		46.4
Exchange Transaction | CNX Gas
Schedule of Equity Method Investments [Line Items]
Cash contribution to be received		$ 2.0
Exchange Transaction | Anchor Systems
Schedule of Equity Method Investments [Line Items]
Acres divested (in acres) | a		4,200
Exchange Transaction | Anchor Systems | CNX Gas
Schedule of Equity Method Investments [Line Items]
Number of wells committed | well		40
Exchange Transaction | Growth Systems
Schedule of Equity Method Investments [Line Items]
Noncontrolling interest, percent		5.00%
Exchange Transaction | Growth and Additional Systems
Schedule of Equity Method Investments [Line Items]
Acres divested (in acres) | a		275,000
Utica Shale formation | Exchange Transaction | Anchor Systems | CNX Gas
Schedule of Equity Method Investments [Line Items]
Additional acres dedicated (in acres) | a		16,100
Moundsville | Exchange Transaction
Schedule of Equity Method Investments [Line Items]
Noncontrolling interest, percent		5.00%
Affiliated Entity
Schedule of Equity Method Investments [Line Items]
Number of wells committed | well		192	140
Affiliated Entity | Exchange Transaction
Schedule of Equity Method Investments [Line Items]
Acres divested (in acres) | a		18,000
Affiliated Entity | Exchange Transaction | Anchor Systems
Schedule of Equity Method Investments [Line Items]
Number of wells committed | well		12
Affiliated Entity | Exchange Transaction | Growth and Additional Systems
Schedule of Equity Method Investments [Line Items]
Acres divested (in acres) | a		14,000

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SIGNIFICANT ACCOUNTING POLICIES - Performance Obligation (Details) $ in Millions	Jun. 30, 2018 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligations expected to be satisfied	$ 14.2
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligations expected to be satisfied	28.8
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligations expected to be satisfied	34.7
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligations expected to be satisfied	40.8
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligations expected to be satisfied	47.8
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligations expected to be satisfied	256.6
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligations expected to be satisfied	$ 422.9

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SIGNIFICANT ACCOUNTING POLICIES - Additional Information (Details) - USD ($)	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Payment terms	25 days
Reserves for uncollectible amounts	$ 0		$ 0
Fair value of long-term debt	388,000,000
Property and equipment impairments	0	$ 0
Asset retirement obligation	0		$ 0
Provision for federal or state income taxes	$ 0	$ 0

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CASH DISTRIBUTIONS - Narrative (Details)	6 Months Ended
	Jun. 30, 2018
Distribution Made to Limited Partner [Line Items]
Period to distribute available cash (in days)	45 days
General partner's ownership interest (as a percent)	2.00%
Maximum
Distribution Made to Limited Partner [Line Items]
Incentive distribution, rate (as a percent)	48.00%

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CASH DISTRIBUTIONS - Allocations of Available Cash from Operating Surplus and Incentive Distribution Rights (Details)	6 Months Ended
	Jun. 30, 2018 $ / shares
Minimum Quarterly Distribution
Distribution Made to Limited Partner [Line Items]
Intended quarterly distribution to limited partner (in dollars per unit)	$ 0.2125
Marginal percentage interest in distributions, unitholders (as a percent)	98.00%
Marginal percentage interest in distributions, general partner (as a percent)	2.00%
First Target Distribution
Distribution Made to Limited Partner [Line Items]
Marginal percentage interest in distributions, unitholders (as a percent)	98.00%
Marginal percentage interest in distributions, general partner (as a percent)	2.00%
Second Target Distribution
Distribution Made to Limited Partner [Line Items]
Marginal percentage interest in distributions, unitholders (as a percent)	85.00%
Marginal percentage interest in distributions, general partner (as a percent)	15.00%
Third Target Distribution
Distribution Made to Limited Partner [Line Items]
Marginal percentage interest in distributions, unitholders (as a percent)	75.00%
Marginal percentage interest in distributions, general partner (as a percent)	25.00%
Thereafter Distributions
Distribution Made to Limited Partner [Line Items]
Marginal percentage interest in distributions, unitholders (as a percent)	50.00%
Marginal percentage interest in distributions, general partner (as a percent)	50.00%
Minimum | First Target Distribution
Distribution Made to Limited Partner [Line Items]
Intended quarterly distribution to limited partner (in dollars per unit)	$ 0.2125
Minimum | Second Target Distribution
Distribution Made to Limited Partner [Line Items]
Intended quarterly distribution to limited partner (in dollars per unit)	0.24438
Minimum | Third Target Distribution
Distribution Made to Limited Partner [Line Items]
Intended quarterly distribution to limited partner (in dollars per unit)	0.26563
Minimum | Thereafter Distributions
Distribution Made to Limited Partner [Line Items]
Intended quarterly distribution to limited partner (in dollars per unit)	0.31875
Maximum | First Target Distribution
Distribution Made to Limited Partner [Line Items]
Intended quarterly distribution to limited partner (in dollars per unit)	0.24438
Maximum | Second Target Distribution
Distribution Made to Limited Partner [Line Items]
Intended quarterly distribution to limited partner (in dollars per unit)	0.26563
Maximum | Third Target Distribution
Distribution Made to Limited Partner [Line Items]
Intended quarterly distribution to limited partner (in dollars per unit)	$ 0.31875

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CASH DISTRIBUTIONS - Schedule of Cash Distributions (Details) - USD ($) $ / shares in Units, $ in Thousands						6 Months Ended
	May 15, 2018	Feb. 14, 2018	Nov. 14, 2017	Aug. 14, 2017	May 15, 2017	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017
Equity [Abstract]
Total Quarterly Distribution Per Unit (in dollars per share)							$ 0.3245	$ 0.3133	$ 0.3025	$ 0.2922	$ 0.2821
Total Quarterly Cash Distribution	$ 22,700	$ 21,489	$ 20,573	$ 19,698	$ 18,842	$ 44,189

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NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST - Conversion of Subordinated Units (Details) - shares	Jun. 30, 2018	Dec. 31, 2017	Nov. 15, 2017
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Units outstanding (in shares)	63,638,165	63,588,152
Subordinated Units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Units outstanding (in shares)			29,163,121

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NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST - Historical Earnings Per Unit(Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Limited Partners' Capital Account [Line Items]
Antidilutive securities excluded from computation of earnings per share (in units)	26,470	50,905	27,545	50,905
Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP	$ 30,005	$ 28,991	$ 57,852	$ 59,058
Less: General partner interest in net income, including incentive distribution rights	2,903	1,305	5,055	2,434
Limited partner interest in net income	$ 27,102	$ 27,686	$ 52,797	$ 56,624
Weighted average limited partner units outstanding — Basic (in units)	63,638,000	63,585,000	63,630,000	63,575,000
Weighted average limited partner units outstanding — Diluted (in units)	63,677,000	63,644,000	63,670,000	63,630,000
Net income per limited partner unit — Basic (in dollars per unit)	$ 0.43	$ 0.44	$ 0.83	$ 0.89
Net income per limited partner unit - Diluted (in dollars per unit)	$ 0.43	$ 0.44	$ 0.83	$ 0.89
Common Units
Limited Partners' Capital Account [Line Items]
Limited partner interest in net income	$ 27,102	$ 14,988	$ 52,797	$ 30,652
Weighted average limited partner units outstanding — Basic (in units)	63,638,000	34,422,000	63,630,000	34,412,000
Weighted average limited partner units outstanding — Diluted (in units)	63,677,000	34,481,000	63,670,000	34,467,000
Net income per limited partner unit — Basic (in dollars per unit)	$ 0.43	$ 0.44	$ 0.83	$ 0.89
Net income per limited partner unit - Diluted (in dollars per unit)	$ 0.43	$ 0.43	$ 0.83	$ 0.89
Subordinated Units
Limited Partners' Capital Account [Line Items]
Limited partner interest in net income	$ 0	$ 12,698	$ 0	$ 25,972
Weighted average limited partner units outstanding — Basic (in units)	0	29,163,000	0	29,163,000
Weighted average limited partner units outstanding — Diluted (in units)	0	29,163,000	0	29,163,000
Net income per limited partner unit — Basic (in dollars per unit)	$ 0.00	$ 0.44	$ 0.00	$ 0.89
Net income per limited partner unit - Diluted (in dollars per unit)	$ 0.00	$ 0.44	$ 0.00	$ 0.89

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RELATED PARTY TRANSACTIONS - Related Party Transactions (Details) - USD ($) $ in Millions		6 Months Ended
	Mar. 16, 2018	Jun. 30, 2018
Additional Systems | Shirley-Penns System
Related Party Transaction [Line Items]
Cash consideration transferred to purchase limited partner controlling interest	$ 265.0	$ 265.0

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RELATED PARTY TRANSACTIONS - Schedule of Related Party Transactions (Details) - Affiliated Entity - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Operating Expense
Related Party Transaction [Line Items]
Charges for services	$ 5,079	$ 7,089	$ 9,514	$ 14,717
Operating Expense | CNX | Shared Service Agreement
Related Party Transaction [Line Items]
Charges for services	3,257	2,999	6,092	6,187
Operating Expense | CNX and Noble | Electrically-Powered Compression Reimbursement
Related Party Transaction [Line Items]
Charges for services	1,822	4,090	3,422	8,530
General and administrative services
Related Party Transaction [Line Items]
General and administrative expenses	3,620	2,663	7,232	5,546
General and administrative services | CNX | Shared Service Agreement
Related Party Transaction [Line Items]
General and administrative expenses	3,620	2,530	7,232	5,241
General and administrative services | Noble Energy
Related Party Transaction [Line Items]
General and administrative expenses	$ 0	$ 133	$ 0	$ 305

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RELATED PARTY TRANSACTIONS - Omnibus Agreement (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)
Scenario, Forecast | CNX | Affiliated Entity | Administrative Services
Related Party Transaction [Line Items]
General and administrative expenses	$ 1.9

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RELATED PARTY TRANSACTIONS - Gathering Agreements (Details) a in Thousands, $ in Millions			6 Months Ended	12 Months Ended				16 Months Ended	30 Months Ended	36 Months Ended
	May 02, 2018 well	Jan. 03, 2018 a well $ / MMBTU	Jun. 30, 2018 $ / MMBTU	Apr. 30, 2022 USD ($) well	Apr. 30, 2021 USD ($) well	Dec. 31, 2018 USD ($) well	Dec. 31, 2017 $ / bbl $ / MMBTU	Apr. 30, 2020 USD ($) well	Dec. 31, 2020 USD ($) well	Dec. 31, 2023 USD ($) well	Jan. 01, 2018 $ / MMBTU
Related Party Transaction [Line Items]
MVC, gas gathering fee (in dollars per MMBtu)			0.35
Conditional increase, percent			2.50%
Downstream fees receivable (in dollars per MMBtu)			0.593
Maximum change in fees, commencing January 1, 2035, percent							3.00%
CNX Gas | Affiliated Entity | Gas Gathering Agreements
Related Party Transaction [Line Items]
Term of agreement		20 years
Additional acres dedicated (in acres) | a		63
Termination period to either party		180 days
Utica Shale, McQuay Area | CNX Gas | Affiliated Entity | Gas Gathering Agreements
Related Party Transaction [Line Items]
Gas gathering fee (in dollars per MMBtu)		0.225
Marcellus and Utical Shale, Wadestown Area | CNX Gas | Affiliated Entity | Gas Gathering Agreements
Related Party Transaction [Line Items]
Gas gathering fee (in dollars per MMBtu)		0.35
McQuay And Wadestown Areas | CNX Gas | Affiliated Entity | Gas Gathering Agreements
Related Party Transaction [Line Items]
Compression fee, tier 1 pressure services, maximum of 600 psi (in dollars per MMBtu)											0.065
Compression fee, tier 2 pressure services, maximum of 300 psi (in dollars per MMBtu											0.130
Marcellus Shale formation
Related Party Transaction [Line Items]
Fees receivable, excluding downstream (in dollars per MMBtu)			0.431
Marcellus Shale formation | CNX Gas | Affiliated Entity | Gas Gathering Agreements
Related Party Transaction [Line Items]
Number of wells drilled and completed (in wells) | well		125
Majorsville And Mamont Areas | CNX Gas | Affiliated Entity | Gas Gathering Agreements
Related Party Transaction [Line Items]
Number of wells drilled and completed (in wells) | well	40
Moundsville And Pittsburgh International Airport Areas
Related Party Transaction [Line Items]
Downstream fees receivable (in dollars per MMBtu)			0.296
Utica Shale formation | Gas Gathering Agreements
Related Party Transaction [Line Items]
Downstream fees receivable, weighted average (in dollars per MMBtu)							0.16
PENNSYLVANIA
Related Party Transaction [Line Items]
Condensate fees receivable (in dollars per Bbl) | $ / bbl							5.38
WEST VIRGINIA
Related Party Transaction [Line Items]
Condensate fees receivable (in dollars per Bbl) | $ / bbl							2.693
Subsequent Event | Marcellus Shale formation | CNX Gas | Affiliated Entity | Gas Gathering Agreements
Related Party Transaction [Line Items]
Number of wells drilled and completed (in wells) | well				30	40	30		40
Deficiency payment, per well | $				$ 2.0	$ 2.0	$ 3.5		$ 3.5
Subsequent Event | Majorsville And Mamont Areas | CNX Gas | Affiliated Entity | Gas Gathering Agreements
Related Party Transaction [Line Items]
Number of wells drilled and completed (in wells) | well									15	25
Deficiency payment, per well | $									$ 2.8	$ 2.8
Minimum | CNX Gas | Affiliated Entity | Gas Gathering Agreements
Related Party Transaction [Line Items]
Quarterly update, historical period		24 months
Maximum | CNX Gas | Affiliated Entity | Gas Gathering Agreements
Related Party Transaction [Line Items]
Quarterly update, historical period		48 months
Quarterly update, future outlook period		10 years

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RELATED PARTY TRANSACTIONS - Schedule of MVC per Gathering Agreements (Details) $ in Millions	Jun. 30, 2018 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligations expected to be satisfied	$ 14.2
Performance obligations expected to be satisfied, expected timing	6 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligations expected to be satisfied	$ 28.8
Performance obligations expected to be satisfied, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligations expected to be satisfied	$ 34.7
Performance obligations expected to be satisfied, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligations expected to be satisfied	$ 40.8
Performance obligations expected to be satisfied, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligations expected to be satisfied	$ 47.8
Performance obligations expected to be satisfied, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligations expected to be satisfied	$ 422.9
Performance obligations expected to be satisfied, expected timing

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RELATED PARTY TRANSACTIONS - Registration Rights Agreement (Details)	Jun. 29, 2018 shares	Jan. 03, 2018 offering
CNX Gas | Affiliated Entity | Gas Gathering Agreements
Related Party Transaction [Line Items]
Number of demand underwritten offerings of registrable securities | offering		4
Noble Energy
Related Party Transaction [Line Items]
Sale of retained units (in shares) | shares	7,475,000

XML

RECEIVABLES (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Accounts, Notes, Loans and Financing Receivable [Line Items]
Receivables - related party	$ 12,072	$ 13,104
Receivables - third party	7,546	8,251
Total receivables	19,618	21,355
Affiliated Entity | CNX
Accounts, Notes, Loans and Financing Receivable [Line Items]
Receivables - related party	12,072	12,801
Affiliated Entity | CNX Gathering
Accounts, Notes, Loans and Financing Receivable [Line Items]
Receivables - related party	$ 0	$ 303

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PROPERTY AND EQUIPMENT (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Total Property and Equipment	$ 864,611	$ 972,841
Less — accumulated depreciation	72,098	73,563
Property and Equipment, Net	792,513	899,278
Land
Property, Plant and Equipment [Line Items]
Total Property and Equipment	47,975	76,130
Gathering equipment
Property, Plant and Equipment [Line Items]
Total Property and Equipment	570,603	662,595
Less — accumulated depreciation	$ 50,744	53,544
Gathering equipment | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life	25 years
Gathering equipment | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life	40 years
Compression equipment
Property, Plant and Equipment [Line Items]
Total Property and Equipment	$ 176,652	180,038
Less — accumulated depreciation	$ 15,808	14,886
Compression equipment | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life	30 years
Compression equipment | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life	40 years
Processing equipment
Property, Plant and Equipment [Line Items]
Total Property and Equipment	$ 30,979	30,979
Less — accumulated depreciation	$ 5,546	5,133
Estimated useful life	40 years
Assets under construction
Property, Plant and Equipment [Line Items]
Total Property and Equipment	$ 38,402	$ 23,099

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OTHER ASSETS - Schedule of Other Assets(Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Other Assets [Abstract]
Pipe stock	$ 0	$ 392
Financing fees	3,219	122
Other	275	79
Total Other Assets	$ 3,494	$ 593

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OTHER ASSETS - Narrative (Details) - Credit Facility - USD ($)	Mar. 08, 2018	Sep. 30, 2014
Debt Instrument [Line Items]
Revolving credit facility	$ 600,000,000	$ 250,000,000.0
Debt issuance costs	4,400,000
Current Assets
Debt Instrument [Line Items]
Debt issuance costs	$ 900,000

XML

ACCOUNTS PAYABLE - RELATED PARTY (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Total Accounts Payable — Related Party	$ 3,211	$ 2,376
Affiliated Entity | CNX
Related Party Transaction [Line Items]
Total Accounts Payable — Related Party	3,203	2,321
Affiliated Entity | CNX | Expense reimbursements
Related Party Transaction [Line Items]
Total Accounts Payable — Related Party	1,148	780
Affiliated Entity | CNX | Capital expenditures reimbursements
Related Party Transaction [Line Items]
Total Accounts Payable — Related Party	0	83
Affiliated Entity | CNX | General and administrative services
Related Party Transaction [Line Items]
Total Accounts Payable — Related Party	2,055	1,458
Affiliated Entity | CNX Gathering
Related Party Transaction [Line Items]
Total Accounts Payable — Related Party	8	0
Affiliated Entity | CNX Gathering | Capital expenditures reimbursements
Related Party Transaction [Line Items]
Total Accounts Payable — Related Party	8	0
Noble Energy
Related Party Transaction [Line Items]
Total Accounts Payable — Related Party	0	55
Noble Energy | General and administrative services
Related Party Transaction [Line Items]
Total Accounts Payable — Related Party	$ 0	$ 55

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REVOLVING CREDIT FACILITY - ADDITIONAL INFORMATION (Details) - Credit Facility		6 Months Ended
	Mar. 08, 2018 USD ($)	Jun. 30, 2018 USD ($)	Dec. 31, 2017 USD ($)	Sep. 30, 2014 USD ($)
Debt Instrument [Line Items]
Revolving credit facility	$ 600,000,000			$ 250,000,000.0
Additional borrowing capacity available	$ 250,000,000.0
Debt covenant, maximum secured leverage ratio		3.50
Debt covenant, minimum interest coverage ratio		2.50
Long term line of credit		$ 11,000,000	$ 149,500,000
Credit facility interest rate		4.09%	3.11%
Remaining borrowing capacity		$ 494,000,000
Minimum
Debt Instrument [Line Items]
Commitment fee percentage		0.375%
Deb covenant, maximum total leverage ratio		4.75
Maximum
Debt Instrument [Line Items]
Commitment fee percentage		0.50%
Deb covenant, maximum total leverage ratio		5.50
Federal Funds Rate
Debt Instrument [Line Items]
Basis spread on variable rate	0.50%
Base Rate, London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Basis spread on variable rate	1.00%
LIBOR plus 1% | Minimum
Debt Instrument [Line Items]
Basis spread on variable rate	0.75%
LIBOR plus 1% | Maximum
Debt Instrument [Line Items]
Basis spread on variable rate	1.75%
LIBOR | Minimum
Debt Instrument [Line Items]
Basis spread on variable rate	1.75%
LIBOR | Maximum
Debt Instrument [Line Items]
Basis spread on variable rate	2.75%

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LONG-TERM DEBT - Narrative (Details) - USD ($) $ in Thousands	Mar. 15, 2024	Mar. 15, 2021	Mar. 16, 2018	Jun. 30, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Long-term debt				$ 393,169	$ 0
Senior Notes
Debt Instrument [Line Items]
Long-term debt, gross			$ 400,000	$ 400,000	0
Stated rate			6.50%	6.50%
Long-term debt			$ 393,000	$ 393,169	$ 0
Percent of principal amount able to be redeemed			35.00%
Redemption price including premium, percent			106.50%
Redemption price of principal, percent			100.00%
Change of control, cash payment of aggregate principal amount repurchased, percentage			101.00%
Scenario, Forecast | Senior Notes
Debt Instrument [Line Items]
Redemption price including premium, percent	100.00%	104.875%
Credit Facility
Debt Instrument [Line Items]
Repayments of debt			$ 250,000

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LONG-TERM DEBT - Schedule of Debt (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Mar. 16, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Long-term debt	$ 393,169		$ 0
Senior Notes
Debt Instrument [Line Items]
Stated rate	6.50%	6.50%
Long-term debt, gross	$ 400,000	$ 400,000	0
Less: Unamortized debt issuance costs	1,081		0
Less: Unamortized bond discount	5,750		0
Long-term debt	$ 393,169	$ 393,000	$ 0

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COMMITMENTS AND CONTINGENCIES - Future Minimum Lease Payments (Details) $ in Thousands	Jun. 30, 2018 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Period from July 1, 2018 through December 31, 2018	$ 1,023
Year ending December 31, 2019	1,627
Year ending December 31, 2020	1,042
Total future minimum lease payments	$ 3,692

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COMMITMENTS AND CONTINGENCIES - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Commitments and Contingencies Disclosure [Abstract]
Rental expense	$ 2.0	$ 4.1	$ 1.9	$ 3.8

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SEGMENT INFORMATION - Narrative (Details) - segment		6 Months Ended
	Mar. 16, 2018	Jun. 30, 2018	May 03, 2018	Mar. 15, 2018
Segment Reporting Information [Line Items]
Number of operating segments		3
Shirley-Penns System | Anchor Systems
Segment Reporting Information [Line Items]
Ownership interest	100.00%
Shirley-Penns System | Additional Systems
Segment Reporting Information [Line Items]
Ownership percentage (as a percent)				5.00%
Noncontrolling interest, percent				95.00%
Exchange Transaction | Growth Systems
Segment Reporting Information [Line Items]
Noncontrolling interest, percent			5.00%
Moundsville | Exchange Transaction
Segment Reporting Information [Line Items]
Noncontrolling interest, percent			5.00%

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SEGMENT INFORMATION - Schedule of Segment Results (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Segment Reporting Information [Line Items]
Gathering Revenue:	$ 61,014	$ 56,534	$ 124,883	$ 115,492
Net Income (Loss):	30,282	29,752	63,987	62,992
Depreciation Expense:	5,443	5,675	11,299	11,346
Capital Expenditures for Segment Assets:	25,615	12,223	41,587	23,415
Segment Assets	819,058		819,058		$ 926,589
Anchor Systems
Segment Reporting Information [Line Items]
Gathering Revenue:	56,584	50,195	112,774	102,894
Net Income (Loss):	29,991	30,764	63,134	62,380
Depreciation Expense:	4,733	4,201	9,203	8,397
Capital Expenditures for Segment Assets:	24,502	11,841	38,290	22,374
Segment Assets	737,152		737,152		694,942
Growth Systems
Segment Reporting Information [Line Items]
Gathering Revenue:	668	2,018	2,572	4,243
Net Income (Loss):	186	506	379	453
Depreciation Expense:	195	543	748	1,088
Capital Expenditures for Segment Assets:	42	382	120	821
Segment Assets	0		0		92,659
Additional Systems
Segment Reporting Information [Line Items]
Gathering Revenue:	3,762	4,321	9,537	8,355
Net Income (Loss):	105	(1,518)	474	159
Depreciation Expense:	515	931	1,348	1,861
Capital Expenditures for Segment Assets:	1,071	$ 0	3,177	$ 220
Segment Assets	$ 81,906		$ 81,906		$ 138,988

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LONG-TERM INCENTIVE PLAN - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period			2 years
Unrecognized compensation costs	$ 2.4		$ 2.4
Common Units | 2014 LTIP | Stock Compensation Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of common units authorized (in units)	5,800,000		5,800,000
Common Units | 2014 LTIP | Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unit based compensation	$ 0.7	$ 1.3	$ 0.4	$ 0.7
Employee | 2014 LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period			3 years
Annual award vesting percentage			33.00%
Director | 2014 LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period			1 year
Officer | 2014 LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period			3 years
Annual award vesting percentage			33.00%

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LONG-TERM INCENTIVE PLAN - Schedule of Nonvested Performance-based Units Activity (Details) - Phantom Share Units (PSUs)	6 Months Ended
	Jun. 30, 2018 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Total awarded and unvested, beginning balance (in shares) | shares	134,153
Granted (in shares) | shares	132,933
Vested (in shares) | shares	(70,872)
Forfeited (in shares) | shares	(17,639)
Total awarded and unvested, ending balance (in shares) | shares	178,575
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Total awarded and unvested, beginning balance (in shares) | $ / shares	$ 16.40
Granted (in dollars per share) | $ / shares	19.14
Vested (in dollars per share) | $ / shares	16.65
Forfeited (in dollars per share) | $ / shares	16.25
Total awarded and unvested, ending balance (in shares) | $ / shares	$ 18.30

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SUBSEQUENT EVENTS (Details) - $ / shares			3 Months Ended		6 Months Ended
		Jul. 27, 2018	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Subsequent Event [Line Items]
Cash distributions declared per unit (in dollars per share)	[1]		$ 0.3361	$ 0.2922	$ 0.6606	$ 0.5743
Subsequent Event
Subsequent Event [Line Items]
Cash distributions declared per unit (in dollars per share)		$ 0.3361

[1] Represents the cash distributions declared during the month following the end of each respective quarterly period. See Note 15.