CNX Midstream Partners LP - FORM 10-Q

Attached files

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EX-32.2 - EXHIBIT 32.2 - CNX Midstream Partners LP	cnnx03312017ex322.htm
EX-32.1 - EXHIBIT 32.1 - CNX Midstream Partners LP	cnnx03312017ex321.htm
EX-31.2 - EXHIBIT 31.2 - CNX Midstream Partners LP	cnnx03312017ex312.htm
EX-31.1 - EXHIBIT 31.1 - CNX Midstream Partners LP	cnnx03312017ex311.htm

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 March 31, 2017



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

__________________________________________________

CONE 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 May 4, 2017, CONE Midstream Partners LP had 34,422,212 common units and 29,163,121 subordinated units outstanding.

TABLE OF CONTENTS

		Page
PART I FINANCIAL INFORMATION

ITEM 1.	Consolidated Financial Statements
	Consolidated Statements of Operations for the Three Months Ended March 31, 2017 and 2016	3
	Consolidated Balance Sheets at March 31, 2017 and December 31, 2016	4
	Consolidated Statement of Partners' Capital for the Three Months Ended March 31, 2017	5
	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2017 and 2016	6
	Notes to Consolidated Unaudited Financial Statements	7

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	33

ITEM 4.	Controls and Procedures	33

PART II OTHER INFORMATION

ITEM 1.	Legal Proceedings	34

ITEM 1A.	Risk Factors	34

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34

ITEM 3.	Defaults upon Senior Securities	34

ITEM 4.	Mine Safety Disclosures	34

ITEM 5.	Other Information	34

ITEM 6.	Exhibits	35

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PART I: FINANCIAL INFORMATION


ITEM 1.	CONSOLIDATED FINANCIAL STATEMENTS

CONE MIDSTREAM PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(unaudited)



	Three Months Ended March 31,
	2017		2016
Revenue
Gathering revenue — related party	$	58,958	$	62,248
Total Revenue	58,958		62,248
Expenses
Operating expense — third party	6,633		8,674
Operating expense — related party	7,628		8,344
General and administrative expense — third party	1,139		993
General and administrative expense — related party	2,936		1,684
Pipe revaluation	673		—
Depreciation expense	5,671		4,839
Interest expense	1,038		419
Total Expense	25,718		24,953
Net Income	33,240		37,295
Less: Net income attributable to noncontrolling interest	3,173		12,505
Net Income Attributable to General and Limited Partner Ownership Interest in CONE Midstream Partners LP	$	30,067	$	24,790

Calculation of Limited Partner Interest in Net Income:
Net Income Attributable to General and Limited Partner Ownership Interest in CONE Midstream Partners LP	$	30,067	$	24,790
Less: General partner interest in net income, including incentive distribution rights	1,129		496
Limited partner interest in net income	$	28,938	$	24,294

Net income per limited partner unit - Basic	$	0.46	$	0.42
Net income per limited partner unit - Diluted	$	0.45	$	0.42

Limited partner units outstanding - Basic	63,566		58,343
Limited partner unit outstanding - Diluted	63,617		58,365

Cash distributions declared per unit ^(*)	$	0.2821	$	0.2450


(*)	Represents the cash distributions declared during the month following the end of each respective quarterly period. See Note 16.

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

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CONE MIDSTREAM PARTNERS LP

CONSOLIDATED BALANCE SHEETS

(in thousands, except number of units)

(unaudited)



	March 31, 2017			December 31, 2016
ASSETS
Current Assets:
Cash	$	6,018		$	6,421
Receivables — related party (Note 6)	22,892			22,434
Other current assets	2,408			2,181
Total Current Assets	31,318			31,036
Property and Equipment:
Property and equipment (Note 7)	944,672			930,732
Less — accumulated depreciation	57,990			52,172
Property and Equipment — Net	886,682			878,560
Other assets (Note 8)	8,016			8,961
TOTAL ASSETS	$	926,016		$	918,557

LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable	$	18,109		$	18,007
Accounts payable — related party (Note 9)	5,510			8,289
Total Current Liabilities	23,619			26,296
Other Liabilities:
Revolving credit facility (Note 10)	162,000			167,000
Total Liabilities	185,619			193,296
Partners' Capital:
Common units (34,420,012 units issued and outstanding at March 31, 2017 and 34,363,371 units issued and outstanding at December 31, 2016)	424,526			418,352
Subordinated units (29,163,121 units issued and outstanding at March 31, 2017 and December 31, 2016)	(60,656		)	(65,986		)
General partner interest	(1,852		)	(2,311		)
Partners' capital attributable to CONE Midstream Partners LP	362,018			350,055
Noncontrolling interest	378,379			375,206
Total Partners' Capital	740,397			725,261
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$	926,016		$	918,557

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

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CONE MIDSTREAM PARTNERS LP

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL AND OTHER EQUITY

(in thousands)

(unaudited)



	Partners' Capital									Total
										Capital
	Limited Partners						General			Attributable			Noncontrolling
	Common			Subordinated			Partner			to Partners			Interest		Total

Balance at December 31, 2016	$	418,352		$	(65,986	)	$	(2,311	)	$	350,055		$	375,206	$	725,261

Net income	15,664			13,274			1,129			30,067			3,173		33,240
General partner and noncontrolling interest holder activity	—			—			28			28			—		28
Quarterly distributions to unitholders	(9,362		)	(7,944		)	(698		)	(18,004		)	—		(18,004		)
Unit-based compensation	283			—			—			283			—		283
Vested units withheld for unitholder taxes	(411		)	—			—			(411		)	—		(411		)
Balance at March 31, 2017	$	424,526		$	(60,656	)	$	(1,852	)	$	362,018		$	378,379	$	740,397

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

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CONE MIDSTREAM PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)



	Three Months Ended March 31,
	2017			2016
Cash Flows from Operating Activities:
Net income	$	33,240		$	37,295
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation expense and amortization of debt issuance costs	5,713			4,880
Unit-based compensation	283			136
Pipe revaluation	673			—
Other	83			283
Changes in assets and liabilities:
Receivables — related party	(458		)	7,851
Other current and non-current assets	3			369
Accounts payable	(2,386		)	(9,471		)
Accounts payable — related party	(2,975		)	(163		)
Net Cash Provided by Operating Activities	34,176			41,180

Cash Flows from Investing Activities:
Capital expenditures	(11,192		)	(24,386		)
Net Cash Used in Investing Activities	(11,192		)	(24,386		)

Cash Flows from Financing Activities:
Partner and noncontrolling interest holder activity	28			10,823
Quarterly distributions to unitholders	(18,004		)	(14,061		)
Net (payments on) proceeds from revolving credit facility	(5,000		)	500
Vested units withheld for unitholders taxes	(411		)	—
Net Cash Used In Financing Activities	(23,387		)	(2,738		)

Net (Decrease) Increase in Cash	(403		)	14,056
Cash at Beginning of Period	6,421			217
Cash at End of Period	$	6,018		$	14,273

Refer to Note 11 - Supplemental Cash Flow Information for descriptions of material non-cash transactions.

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

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CONE MIDSTREAM PARTNERS LP

NOTES TO THE CONSOLIDATED UNAUDITED FINANCIAL STATEMENTS

NOTE 1 — DESCRIPTION OF BUSINESS

CONE Midstream Partners LP (the “Partnership") is a master limited partnership formed in May 2014 by CONSOL Energy Inc. (NYSE: CNX) (“CONSOL”) and Noble Energy, Inc. (NYSE: NBL) (“Noble Energy”), whom we refer to collectively as our Sponsors, primarily to own, operate, develop and acquire natural gas gathering and other midstream energy assets to service our Sponsors’ production in the Marcellus 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. The Partnership's general partner is CONE Midstream GP LLC (our “general partner”), a wholly owned subsidiary of CONE Gathering LLC (“CONE Gathering”). CONE Gathering, a Delaware limited liability company, is a joint venture formed by our Sponsors in September 2011.

In order to effectively manage our business we have divided our current midstream assets among 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 include our most developed midstream systems that generate the largest portion of our current cash flows, which includes our three primary midstream systems (the McQuay System, the Majorsville System and the Mamont System) and related assets.


•	Our Growth Systems are primarily located in the dry gas regions of our dedicated acreage that are generally in earlier phases of development and require substantial future expansion capital expenditures to materially increase production, which would primarily be funded by our Sponsors in proportion to CONE Gathering's 95% retained ownership interest.

•

Our Additional Systems include several gathering systems primarily located in the wet gas regions of our dedicated acreage 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 primarily be funded by our Sponsors in proportion to CONE Gathering's 95% retained ownership interest.

On September 30, 2014, in connection with the closing of the Partnership's initial public offering (“IPO”), CONE Gathering contributed to the Partnership a 75% controlling interest in the Anchor Systems, a 5% controlling interest in the Growth Systems and a 5% controlling interest in the Additional Systems. On November 16, 2016, the Partnership acquired the remaining 25% noncontrolling interest in the Anchor Systems from CONE Gathering (the “Acquisition”). Accordingly, at December 31, 2016 and March 31, 2017, the Partnership owned a 100% controlling limited partner interest in the Anchor Systems and a 5% controlling limited partner interest in each of the Growth and Additional Systems.

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 personnel employed by our Sponsors or others. All of the personnel that conduct our business are employed or contracted by our general partner and its affiliates, including our Sponsors, but we sometimes refer to these individuals as our employees because they provide services directly to us.

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

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The balance sheet at December 31, 2016 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

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 are consolidated fully with the results of the Partnership for all periods following the IPO. However, after adjusting for noncontrolling interests, net income attributable to general and limited partner ownership interests in the Partnership reflect only that portion of net income that is attributable to the Partnership's unitholders. As a result of the Acquisition, net income attributable to general and limited partner ownership interests in the Partnership includes 100% of the results of the Anchor Systems for periods subsequent to November 16, 2016.

Transactions between the Partnership and its Sponsors have been identified in the consolidated financial statements as transactions between related parties and are discussed in Note 4.

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 these reporting exemptions until we are no longer an emerging growth company. We continue to be an emerging growth company at March 31, 2017.

The Partnership will remain an emerging growth company for up to five years from the date of our IPO (through December 31, 2019), although we will lose that status sooner if:


•	we have more than $1.0 billion of revenues in a fiscal year;


•	the limited partner interests held by non-affiliates have a market value of more than $700 million as of the last business day of our most recently completed second fiscal quarter, which determination shall be made as of the last day of such fiscal year; or


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

The JOBS Act also provides that an emerging growth company can delay adopting new or revised accounting standards until such time as those standards apply to private companies. The Partnership has irrevocably elected to “opt out” of this exemption and, therefore, is and will be subject to the same new or revised accounting standards as other public companies that are not emerging growth companies.

Revenue Recognition

Our revenues primarily consist of fees, which we charge on a per unit basis, for gathering natural gas that is produced by our Sponsors. We recognize revenue when services have been rendered, the prices are fixed or determinable, and collectibility is reasonably assured. All fees we receive are currently recorded in gathering revenue — related party in our consolidated financial statements.

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 uncollectible amounts at March 31, 2017 or December 31, 2016.

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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 on our balance sheet of our current assets and 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 their estimated useful lives or over the lease terms of the assets. 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 March 31, 2017 and December 31, 2016, 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. Accordingly, any retirement obligations associated with such assets cannot be estimated. A liability for asset retirement obligations will be recorded only if and when a future retirement obligation with a determinable life exists and can be estimated. We have not recorded any liabilities for asset retirement obligations at March 31, 2017 or December 31, 2016.

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Variable Interest Entities

Each of the Anchor, Growth and Additional Systems (the “Limited Partnerships”) is also a limited partnership and a variable interest entity (“VIE”). These VIEs correspond with the manner in which we report our segment information in Note 14–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 CONE Midstream Operating Company LLC (the “Operating Company”). The Operating Company, through its general partner ownership interest in each of the Anchor, Growth and Additional 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 Accounting Standards Codification. 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 15–Long Term Incentive Plan, for further discussion.

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.

Cash Distributions

Our partnership agreement requires that we distribute all of our available cash within 45 days after the end of each quarter to unitholders of record on the applicable record date. This requirement forms the basis of our cash distribution policy and reflects a basic judgment that our unitholders will be better served by distributing our available cash rather than retaining it because, among other reasons, we believe we will generally finance any expansion capital expenditures from external financing sources. Under our current cash distribution policy, we intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $0.2125 per unit, or $0.85 per unit on an annualized basis, to the extent we have sufficient available cash after the establishment of cash reserves and the payment of costs and expenses, including the payment of expenses to our general partner. However, other than the requirement in our partnership agreement to distribute all of our available cash each quarter, we have no legal obligation to make quarterly cash distributions in this or any other amount, and the board of directors of our general partner has considerable discretion to determine the amount of our available cash each quarter. In addition, the board of directors of our general partner may change our cash distribution policy at any time, subject to the requirement in our partnership agreement to distribute all of our available cash quarterly.

Generally, our available cash is the sum of (i) all cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (ii) if the board of directors of our general partner so determines, all or any portion of additional cash on hand resulting from working capital borrowings made after the end of the quarter.

Incentive Distribution Rights

Incentive distribution rights (“IDRs”) represent the right to receive an increasing percentage, up to a maximum of 48.0% (which doesn't 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. Our general partner may transfer the IDRs separately from its general partner interest.

See Note 3–Net Income Per Limited Partner Unit for additional details regarding achievement of target distribution levels.

Percentage Allocations of Available Cash from Operating Surplus

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 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.” 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 incentive distribution rights and that there are no arrearages on common units.

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			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%

Subordinated Units

Our partnership agreement provides that, during the subordination period, the common unitholders will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.2125 per unit, which is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that, during the subordination period, there will be available cash to be distributed on the common units. The subordination period will end, and the subordinated units will convert to common units, on a one-for-one basis, when certain distribution requirements, as defined in the partnership agreement, have been met.

Our Sponsors currently own 29,163,121 subordinated units, which represents all of our subordinated units.

Reclassifications

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

Recent Accounting Pronouncements

In January 2017, the FASB issued Accounting Standards Update (“ASU”) 2017-01–Business Combinations (Topic 805): Clarifying the Definition of a Business, which changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities is a business. The updated guidance requires an entity to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets is not a business. ASU 2017-01 is effective for annual reporting periods beginning after December 31, 2017 and interim periods therein. The Partnership does not expect the adoption of this guidance to have a material impact on its consolidated financial statements.

In December 2016, the FASB issued ASU 2016-19–Technical Corrections and Improvements, which covers a wide range of Topics in the ASC. The amendments in this ASU represent changes to clarify, correct errors, or make minor improvements to the ASC, making it easier to understand and apply by eliminating inconsistencies and providing clarifications. The amendments generally fall into one of the following categories: amendments related to differences between original guidance and the ASC, guidance clarification and reference corrections, simplification, or minor improvements. Most of the amendments in ASU 2016-19 do not require transition guidance and are effective immediately.

In August 2016, the FASB issued ASU 2016-15–Classification of Certain Cash Receipts and Cash Payments (Topic 230). ASU 2016-15 addresses the existing diversity in practice of how several specific cash receipts and cash payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash Flows. ASU 2016-15 is effective for annual reporting periods, and interim periods therein, beginning after December 15, 2017. The Partnership does not expect the adoption of this guidance will have a material impact on its consolidated financial statements.

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 evaluating the impact that this standard will have on our financial statements and

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financial covenants with lenders; however, we do not believe this standard will materially adversely impact our existing credit agreements.

In May 2014, the FASB issued ASU 2014-09–Revenue from Contracts with Customers (Topic 606), which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. The objective of the amendments in this update is to improve financial reporting by creating common revenue recognition guidance under both U.S. GAAP and International Financial Reporting Standards (“IFRS”). The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services and should disclose sufficient information, both qualitative and quantitative, to enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The following updates to Topic 606 were made during 2016:


•	In March 2016, the FASB updated Topic 606 by issuing ASU 2016-08–Principal versus Agent Considerations (Reporting Revenue Gross versus Net), which clarifies how an entity determines whether it is a principal or an agent for goods or services promised to a customer as well as the nature of the goods or services promised to their customers.


•	In April 2016, the FASB issued ASU 2016-10–Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, which seeks to address implementation issues in the areas of identifying performance obligations and licensing.

•

In May 2016, the FASB issued ASU 2016-12–Revenue from Contracts with Customers (Topic 606): Narrow Scope Improvements and Practical Expedients. The update, which was issued in response to feedback received by the FASB-IASB joint revenue recognition transition resource group, seeks to address implementation issues in the areas of collectibility, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition.

After considering the FASB's issuance of a standard that delayed application of Topic 606 by one year, the new standards are effective for annual reporting periods beginning after December 15, 2017, with the option to adopt as early as annual reporting periods beginning after December 15, 2016. Management continues to evaluate the impacts that these standards will have on the Partnership's financial statements; however, the Partnership anticipates using the modified retrospective approach at adoption as it relates to ASU 2014-09.

NOTE 3 — NET INCOME PER LIMITED PARTNER UNIT

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. The Second and Third Target Distributions were reached for the cash flow quarters ended March 31, 2016 and December 31, 2016, respectively, which were paid within 45 days following the ends of these quarters. All quarterly distributions prior to March 31, 2016 were paid in accordance with the First Target Distribution.

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 50,905 and 11,314 phantom units that were not included in the calculation for the three months ended March 31, 2017 and 2016, respectively, 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:

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	Quarter Ended March 31,
(in thousands, except per unit information)	2017		2016
Net Income Attributable to General and Limited Partner Ownership Interest in CONE Midstream Partners LP	$	30,067	$	24,790
Less: General partner interest in net income, including incentive distribution rights	1,129		496
Limited partner interest in net income	$	28,938	$	24,294

Net income allocable to common units - Basic and Diluted	$	15,664	$	12,151
Net income allocable to subordinated units - Basic and Diluted	13,274		12,143
Limited partner interest in net income - Basic and Diluted	$	28,938	$	24,294

Weighted average limited partner units outstanding — Basic
Common units	34,403		29,180
Subordinated units	29,163		29,163
Total	63,566		58,343

Weighted average limited partner units outstanding — Diluted
Common units	34,454		29,202
Subordinated units	29,163		29,163
Total	63,617		58,365

Net income per limited partner unit — Basic
Common units	$	0.46	$	0.42
Subordinated units	$	0.46	$	0.42
Total	$	0.46	$	0.42

Net income per limited partner unit — Diluted
Common units	$	0.45	$	0.42
Subordinated units	$	0.46	$	0.42
Total	$	0.45	$	0.42

NOTE 4 — RELATED PARTY

In the ordinary course of business, the Partnership has transactions with related parties that result in affiliate transactions. During each of the periods presented, we engaged in related party transactions with each of our Sponsors, CONSOL (and certain of its subsidiaries) and Noble Energy, to whom we provide natural gas gathering and compression services pursuant to the terms of our gas gathering agreements.

Operating expense — related party consisted primarily of $7.6 million and $8.3 million of charges from our Sponsors for the three months ended March 31, 2017 and 2016, respectively. In each period, $4.4 million of operating expense — related party was related to electrically-powered compression, which is reimbursed by the Sponsors pursuant to their respective Gathering Agreements.

Sponsor-related charges within general and administrative expense – related party consisted of the following:



	Three Months Ended March 31,
(in thousands)	2017		2016
CONSOL	$	2,764	$	1,529
Noble Energy	172		155
Total General and Administrative Expense — Related Party	$	2,936	$	1,684

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Omnibus Agreement

Concurrent with the closing of the IPO, we entered into an omnibus agreement with CONSOL, Noble Energy, CONE Gathering and our general partner that addresses the following matters:


•	our payment of an annually-determined administrative support fee, which will total $0.9 million for the year ending December 31, 2017, for the provision of certain services by CONSOL and its affiliates;


•	our payment of an annually-determined administrative support fee, which will total $0.7 million for the year ending December 31, 2017, for the provision of certain executive services by CONSOL and its affiliates;


•	our payment of an annually-determined administrative support fee, which will total $0.3 million for the year ending December 31, 2017, for the provision of certain executive services by Noble Energy and its affiliates;


•	our obligation to reimburse our Sponsors for all other direct or allocated costs and expenses incurred by our Sponsors 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) CONE Gathering’s retained interests in each of our Anchor Systems, Growth Systems and Additional Systems, (ii) CONE Gathering’s other ancillary midstream assets and (iii) any additional midstream assets that CONE Gathering develops; and

•

an indemnity from CONE 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 CONE 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 CONE Gathering controls our general partner, the omnibus agreement will remain in full force and effect. If CONE 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.

Operational Services Agreement

Concurrent with the closing of the IPO, we entered into an operational services agreement with CONSOL. On December 1, 2016, in connection with the consummation of our Sponsors' Exchange Agreement (the “Exchange Agreement”), the operational services agreement was amended and restated. Consistent with the original operational services agreement, under the amended and restated operating agreement, CONSOL provides 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 CONSOL may mutually agree upon from time to time. CONSOL prepares and submits for our approval a maintenance, operating and capital budget on an annual basis. CONSOL submits actual expenditures for reimbursement on a monthly basis, and we reimburse CONSOL for any direct third-party costs incurred by CONSOL in providing these services.

Gathering Agreements

Upon consummation of the Exchange Agreement, we entered into new fixed-fee gathering agreements with each of CNX Gas Company LLC, a wholly owned subsidiary of CONSOL (“CNX Gas”), and Noble Energy that replaced the gathering agreements that had been in place since the IPO. In addition to incorporating changes related to the Sponsors' termination of their upstream joint venture and Joint Development Agreement, the new gathering agreements provide more clarity on each Sponsor's acreage dedication to the Partnership and related releases and allow each Sponsor to independently advance its own development program. We also anticipate that the new gathering agreements will simplify the decision making process relating to the Partnership's ability to gather third party gas.

Under the new gathering agreements, we continue to receive a fee 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 $0.42 per MMBtu in 2017.


•	For the services we provide with respect to the natural gas that requires downstream processing, or wet gas, we will receive in 2017:

•a fee of $0.289 per MMBtu in the Moundsville area (Marshall County, West Virginia);

•a fee of $0.289 per MMBtu in the Pittsburgh International Airport area; and

•a fee of $0.578 per MMBtu for all other areas in the dedication area.

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•	For the services we provide to each of our Sponsors with respect to natural gas from the Utica Shale formation, we will receive a weighted average rate of $0.22 per MMBtu in 2017, which is consistent with the fees charged to date.


•	For 2017, our fee for condensate services will be $5.25 per Bbl in the Majorsville area and $2.627 per Bbl in the Moundsville area.

Each of the foregoing fees will escalate by 2.5% on January 1 of each year, beginning on January 1, 2018. Notwithstanding the foregoing, from time to time, each of our Sponsors 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, by our conflicts committee. No rate reduction arrangements are currently active.

We will continue to gather, compress, dehydrate and deliver all of our Sponsors’ dedicated natural gas in the Marcellus Shale on a first-priority basis and to gather, inject, stabilize and store all of our Sponsors’ dedicated condensate on a first-priority basis, with the exception of the following:


•	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; and


•	until December 1, 2018, Noble Energy will receive first-priority service in our McQuay system with respect to a certain volume of production (revised bi-annually) and any excess production will receive second-priority service.

Each of our Sponsors 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 the following 24 months and a three to ten year plan that includes more general development plans. In addition, we regularly meet with our Sponsors 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 or Noble Energy, as applicable, 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.

In addition to the natural gas and condensate that is produced from the dedicated acreage, each of our Sponsors may elect to dedicate non-Marcellus Shale properties located in the dedication area to us in which the Sponsor has an interest. If a Sponsor elects to dedicate any such property, then that Sponsor will propose a fee for the associated midstream services we would provide. So long as the proposed fee generates a rate of return consistent with the Sponsor’s existing gathering agreement on both incremental capital and operating expense associated with any expenditures necessary to gather gas from such property, any midstream services that we agree to provide will be on a second priority basis; second only to the first priority basis afforded to each of our Sponsors on their respective dedicated production. Throughput that we currently gather from Utica Shale wells operated by either one of our Sponsors is addressed in the new gathering agreements.

While our gathering agreements run with the land and, subject to the exceptions described therein, are binding upon the transferee of any of our dedicated acreage, the agreements provide that each of our Sponsors may divest up to 25,000 net acres of its dedicated acreage (plus or minus the net of acreage acquired or divested within the dedicated area since our IPO) free of the dedication to us. The amount of net acreage that may be divested by each Sponsor free of the dedication will be increased by the amount, if any, of the net acreage acquired (or deemed to be acquired) by such Sponsor in the dedication area that will become automatically dedicated to us. For purposes of determining if acreage can be released free and clear of the dedications under our gathering agreements, the actual net acreage divested or acquired may be adjusted upwards or downwards based on the geographic location of such net acreage, the timing of the respective divestiture or acquisition and certain other conditions in the gas gathering agreements. There are no restrictions under our gathering agreements on a Sponsor’s ability to transfer acreage in the right of first offer (“ROFO”) area, and any transfer of a Sponsor’s acreage in the ROFO area will not be subject to our right of first offer. For additional information on the ROFO area, see Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations–How We Evaluate Our Operations–Throughput Volumes.

Upon completion of its initial term in 2034, each of our gathering agreements will continue in effect from year to year until such time as the agreement is terminated by either us or the Sponsor party to such agreement on or before 180 days prior written notice.

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NOTE 5 — CONCENTRATION OF CREDIT RISK

The Sponsors accounted for all of the Partnership’s revenue in 2017 and 2016. Revenues attributable to each Sponsor were as follows for the periods presented:



	Three Months Ended March 31,
(in thousands)	2017		2016
CONSOL	$	34,386	$	31,799
Noble Energy	24,572		30,449
Total Revenue	$	58,958	$	62,248

NOTE 6 — RECEIVABLES — RELATED PARTY

Receivables consisted of the following:



(in thousands)	March 31, 2017		December 31, 2016
Gathering fees:
CONSOL	$	11,295	$	10,956
Noble Energy	8,368		8,268
Other	3,229		3,210
Total Receivables — Related Party	$	22,892	$	22,434

NOTE 7 — PROPERTY AND EQUIPMENT

Property and equipment consisted of the following:



(in thousands)	March 31, 2017		December 31, 2016		Estimated Useful Lives in Years
Land	$	75,997	$	72,878	N/A
Gathering equipment	643,904		643,422		25 — 40
Compression equipment	170,824		169,681		30 — 40
Processing equipment	30,979		30,979		40
Assets under construction	22,968		13,772		N/A
Total Property and Equipment	$	944,672	$	930,732

Less: Accumulated depreciation
Gathering equipment	$	41,825	$	37,275
Compression equipment	11,651		10,590
Processing equipment	4,514		4,307
Total Accumulated Depreciation	$	57,990	$	52,172

Property and Equipment, Net	$	886,682	$	878,560

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NOTE 8 — OTHER ASSETS

Other assets consisted of the following:



(in thousands)	March 31, 2017		December 31, 2016
Pipe stock	$	7,692	$	8,596
Financing fees	245		286
Deposits	79		79
Total Other Assets	$	8,016	$	8,961

In April 2017, the Partnership agreed to sell approximately $7.1 million of its existing pipe stock that was not dedicated to specific projects to an unrelated third party for an amount that was $0.7 million below its carrying value. Accordingly, we recorded a $0.7 million market value adjustment within the pipe revaluation caption in the accompanying consolidated statements of operations for the quarter ended March 31, 2017. The pipe that will be sold is within the Growth Systems reporting unit.

NOTE 9 — ACCOUNTS PAYABLE — RELATED PARTY

Related party payables consisted of the following:



(in thousands)	March 31, 2017		December 31, 2016
CONSOL:
Expense reimbursements	$	1,134	$	999
Capital expenditures reimbursements	1,343		1,148
General and administrative services	1,044		1,964
Operational expenditures reimbursements	401		395
Other reimbursement	—		1,060
Due to CONSOL total	$	3,922	$	5,566

Noble Energy:
Capital expenditures reimbursements	1,105		1,105
General and administrative services	82		53
Operational expenditures reimbursements	401		401
Other reimbursement	—		1,060
Due to Noble Energy total	$	1,588	$	2,619

CONE Gathering LLC:
Capital expenditures reimbursement to CONE Gathering LLC	—		104
Due to CONE Gathering LLC total	$	—	$	104

Total Accounts Payable — Related Party	$	5,510	$	8,289

NOTE 10 — REVOLVING CREDIT FACILITY

We are party to a credit facility agreement which provides for a $250 million unsecured five year revolving credit facility that matures on September 30, 2019. Our revolving credit facility is available for working capital, capital expenditures, certain acquisitions, distributions, unit repurchases and other lawful partnership purposes. Borrowings under our revolving credit facility bear interest at our option at either:

•

the base rate, which is defined as the highest of (i) the federal funds rate plus 0.50%; (ii) JP Morgan’s prime rate; or (iii) the daily LIBOR rate for a one month interest period plus 1.00%; in each case, plus a margin varying from 0.125% to 1.00%, depending on our most recent consolidated total leverage ratio (as defined in the agreement governing our revolving credit facility) or our credit rating; or

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•	the LIBOR rate plus a margin varying from 1.125% to 2.00%, in each case, depending on our most recent consolidated leverage ratio (as defined in the agreement governing our revolving credit facility) or our credit rating, as the case may be.

Interest on base rate loans is payable quarterly. 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 0.15% to 0.35% per annum depending on our most recent consolidated leverage ratio or our credit rating, as the case may be.

The outstanding balances and LIBOR interest rates in effect (plus applicable margin) on our revolving credit facility are as follows for the dates presented.



	March 31, 2017				December 31, 2016
(in thousands, except percentages)	Debt		Interest Rate		Debt		Interest Rate
Credit facility, due September 30, 2019	$	162,000	2.50	%	$	167,000	2.26	%

In addition, our revolving credit facility contains covenants and conditions that, among other things, limit (subject to certain exceptions) our ability to incur or guarantee additional debt, make cash distributions (though there will be an exception for distributions permitted under the partnership agreement, subject to certain customary conditions), incur certain liens or permit them to exist, make certain investments and acquisitions, enter into certain types of transactions with affiliates, merge or consolidate with another company, and transfer, sell or otherwise dispose of assets. We are also subject to covenants that require us to maintain certain financial ratios, the most important of which are as follows:

•

The ratio of (i) consolidated total funded debt (as defined in the agreement governing our revolving credit facility) as of the last day of each fiscal quarter to (ii) consolidated EBITDA (as defined in the agreement governing our revolving credit facility) for the four consecutive fiscal quarters ending on the last day of such fiscal quarter may not exceed (A) at any time other than during a qualified acquisition period (as defined in the agreement governing our revolving credit facility), 5.0 to 1.0 and (B) during a qualified acquisition period, 5.5 to 1.0. This consolidated leverage ratio is calculated as the total amount outstanding on our credit facility divided by EBITDA Attributable to General and Limited Partner Ownership Interest in the CONE Midstream Partners LP. The Partnership is in compliance with this financial covenant at March 31, 2017.

•

The ratio of (i) consolidated EBITDA for the four consecutive fiscal quarters ending on the last day of each fiscal quarter to (ii) consolidated interest expense (as defined in the agreement governing our revolving credit facility) for such four consecutive fiscal quarters may not be less than 3.0 to 1.0. This consolidated interest coverage ratio is calculated as EBITDA Attributable to General and Limited Partner Ownership Interest in CONE Midstream Partners LP divided by total interest charges. The Partnership is in compliance with this financial covenant at March 31, 2017.

Based on our compliance with the financial covenants, the Partnership had $88.0 million, the maximum amount of revolving credit, available for borrowing at March 31, 2017.

As of March 31, 2017, we had outstanding debt issuance costs of $0.4 million, net of accumulated amortization, which were incurred in connection with the issuance of our credit facility. The debt issuance costs are being amortized in interest expense through September 30, 2019, which is the maturity date of the credit facility.

NOTE 11 — SUPPLEMENTAL CASH FLOW INFORMATION

As of March 31, 2017, we had a receivable of $2.4 million from CONE Gathering related to capital expenditures. Additionally, we had capital expenditures of $1.3 million and $1.1 million due to CONSOL and Noble Energy, respectively. We also paid $1.1 million in interest on our revolving credit facility during the quarter ended March 31, 2017.

As of March 31, 2016, we had $0.1 million in capital expenditures due to be reimbursed to CONSOL.

NOTE 12 — COMMITMENTS AND CONTINGENCIES

We may become involved in claims and other legal matters arising in the ordinary course of business. Although claims are inherently unpredictable, we are not aware of any matters that may have a material adverse effect on our business, financial position, results of operations or cash flows.

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NOTE 13 — LEASES

We have entered into various non-cancelable operating leases, primarily related to compression facilities. Future minimum lease payments under operating leases as of March 31, 2017 are as follows:



(in thousands)	Minimum Lease Payments
remainder of 2017	$	3,791
2018	2,494
2019	1,068
2020	183
	$	7,536

Rental expense under operating leases was $1.9 million and $2.1 million for the three months ended March 31, 2017 and 2016, respectively. These expenses are included within operating expense - third party on our consolidated statement of operations.

NOTE 14—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. The Partnership has three operating segments, which are also 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 details.

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Segment results for the periods presented were as follows:



	Three Months Ended March 31,
(in thousands)	2017			2016
Gathering Revenue - Related Party:
Anchor Systems	$	49,539		$	50,290
Growth Systems	2,225			2,891
Additional Systems	7,194			9,067
Total Gathering Revenue - Related Party	$	58,958		$	62,248

Net Income:
Anchor Systems	$	29,900		$	32,751
Growth Systems	(53		)	937
Additional Systems	3,393			3,607
Total Net Income	$	33,240		$	37,295

Depreciation Expense:
Anchor Systems	$	3,743		$	3,303
Growth Systems	545			529
Additional Systems	1,383			1,007
Total Depreciation Expense	$	5,671		$	4,839

Capital Expenditures for Segment Assets:
Anchor Systems	$	10,153		$	15,171
Growth Systems	439			69
Additional Systems	600			9,146
Total Capital Expenditures	$	11,192		$	24,386

Segment assets as of the dates presented were as follows:



(in thousands)	March 31, 2017		December 31, 2016
Segment Assets
Anchor Systems	$	579,060	$	571,415
Growth Systems	98,231		98,447
Additional Systems	248,725		248,695
Total Segment Assets	$	926,016	$	918,557

NOTE 15 — LONG-TERM INCENTIVE PLAN

Under the CONE 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 5,800,000 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.

During the three months ended March 31, 2017, our general partner granted equity-based phantom units under our LTIP. Awards granted to independent directors vest over a period of one year, and awards granted to certain officers and employees of

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the general partner vest 33% per year over a period of three years. The following table presents activity related to the number of outstanding unvested units from December 31, 2016 to March 31, 2017:



	Number of Units	Weighted Average Grant Date Fair Value
Total awarded and unvested at December 31, 2016	158,117	$	10.57
Granted	62,997	24.00
Vested	(73,534)	10.49
Forfeited	(2,680)	15.04
Total awarded and unvested at March 31, 2017	144,900	$	16.37

The Partnership accounts for phantom units as equity awards and records compensation expense based on the fair value of the awards at their grant date. The Partnership recognized $0.3 million and $0.1 million of compensation expense for the three months ended March 31, 2017 and 2016, respectively, which was included in general and administrative expense - related party in the consolidated statements of operations.

At March 31, 2017, the unrecognized compensation related to all outstanding awards was $2.0 million.

NOTE 16 — SUBSEQUENT EVENTS

On April 20, 2017, the Board of Directors of CONE Midstream GP LLC, the Partnership's general partner, declared a cash distribution to the Partnership’s unitholders with respect to the first quarter of 2017 of $0.2821 per common and subordinated unit. The cash distribution will be paid on May 15, 2017 to unitholders of record at the close of business on May 4, 2017.

On May 2, 2017, Noble Energy announced that it had entered into an agreement providing for the divestiture of all of its upstream natural gas assets in Appalachia. The buyer of these assets will succeed to, and the buyer's production on the acreage that is dedicated to the Partnership will continue to be gathered by us at the fees that are outlined in, our existing gathering agreement with Noble Energy. The transaction is anticipated to close during the quarter ending June 30, 2017.

Noble Energy's interests in the Partnership will not change as a result of this transaction.

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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 CONE 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, 2016. In this Item 2, all references to "we," us," "our," the "Partnership," "CNNX," or similar terms refer to CONE Midstream Partners LP and its subsidiaries.

Executive Overview

We are a master limited partnership formed in May 2014 by CONSOL Energy Inc. (“CONSOL”) and Noble Energy, Inc. (“Noble Energy”), whom we refer to collectively as our Sponsors, primarily to own, operate, develop and acquire natural gas gathering and other midstream energy assets to service our Sponsors’ production in the Marcellus 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.

On September 30, 2011, CONSOL and Noble Energy entered into a Joint Development Agreement (“JDA”) and related ancillary agreements governing their joint exploration and development of their combined acreage in the Marcellus Shale, which comprised an area of mutual interest (“AMI”) that covered portions of 28 counties in West Virginia and 19 counties in Pennsylvania and included over 26,000 square miles (the “Co-Owned Properties”). Pursuant to the JDA, each of our Sponsors owned an undivided 50% working interest in the jointly owned Marcellus Shale acreage, and under the JDA, any other oil and natural gas interests covering the Marcellus Shale within the AMI that became jointly owned by CONSOL and Noble Energy would have automatically become part of the upstream acreage.

On December 1, 2016, our Sponsors consummated an Exchange Agreement (the “Exchange Agreement”), pursuant to which, effective as of October 1, 2016, the JDA was terminated and CONSOL and Noble Energy separated their Marcellus Shale AMI into two separate operating areas. Under the Exchange Agreement, CNX Gas Company LLC, a wholly owned subsidiary of CONSOL (“CNX Gas”), and Noble Energy exchanged certain jointly owned oil and gas properties and related assets that were previously subject to the JDA.

Following consummation of the Exchange Agreement, each of CNX Gas and Noble Energy now owns 100% of their respective upstream interests in the Marcellus Shale. Accordingly, we entered into new fixed-fee gathering agreements with each of CNX Gas and Noble Energy that replaced the gathering agreements that had been in place since our initial public offering (“IPO”). These new gathering agreements continue to include acreage dedications of approximately 515,000 aggregate net acres, subject to the release provisions set forth therein. In addition, the fees that we receive for gathering services under the new agreements are generally the same as under the prior gathering agreements.

Ownership of Our Assets

On September 30, 2014, in connection with the completion of the IPO, our Sponsors contributed to us a 75% controlling interest in our Anchor Systems, a 5% controlling interest in our Growth Systems and a 5% controlling interest in our Additional Systems. Accordingly, most income statement line items, including net income, reflect the results of the Anchor Systems, Growth Systems and Additional Systems on a 100% basis, with the exception of net income attributable to general and limited partner ownership interests in CONE Midstream Partners LP, which only includes our controlling interests in these Systems.

On November 16, 2016 we acquired the remaining 25% limited partner noncontrolling interest in the Anchor Systems from CONE Gathering (the “Acquisition”).

Our results, net to the Partnership, include 100% of the Anchor Systems following the Acquisition. Accordingly, for the quarter ended March 31, 2017, net income attributable to general and limited partner ownership interests in CONE Midstream Partners LP includes our 100% controlling interest in the Anchor Systems. However, for the quarter ended March 31, 2016, net income attributable to general and limited partner ownership interests in CONE Midstream Partners LP only includes our 75% controlling interest in the Anchor Systems at the time.

First Quarter 2017 Highlights

The Partnership continued its solid financial performance in the quarter ended March 31, 2017. Compared to the quarter ended March 31, 2016, results attributable to the general partner and limited partner ownership interests in the Partnership increased primarily as a result of the Acquisition. Comparative results net to the Partnership, with the exception of operating

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cash flows, which is shown on a gross consolidated basis, were as follows for the quarters ended March 31, 2017 and 2016, respectively:


•	Net income of $30.1 million as compared to $24.8 million;


•	Average daily throughput volumes of 1,060 billion Btu per day (BBtu/d) as compared to 850 BBtu/d;


•	Net cash provided by operating activities of $34.2 million as compared to $41.2 million;


•	Adjusted EBITDA (non-GAAP) of $35.2 million as compared to $27.7 million; and


•	Distributable cash flow (non-GAAP) of $30.3 million as compared to $24.6 million

Consistent with each quarter during the year ended December 31, 2016, the current quarter's net cash provided by operating activities exceeded the sum of capital expenditures ($11.2 million), distributions to unitholders ($18.0 million) and interest paid ($1.0 million).

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”) follows below.

How We Evaluate Our Operations

Our management uses a variety of financial and operating metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include: (i) throughput volumes; (ii) EBITDA and Adjusted EBITDA; (iii) distributable cash flow and (iv) operating expenses.

Throughput Volumes

The amount of revenue we generate primarily depends on the volumes of natural gas and condensate that we gather for our Sponsors, which are primarily affected by upstream development drilling and production volumes from the natural gas wells connected to our gathering pipelines. Our Sponsors’ willingness to engage in new drilling in the Marcellus Shale is determined by a number of factors, which include the prevailing and projected prices of natural gas, natural gas liquids (“NGLs”) and crude oil, the cost to drill and operate a well, the relative economics of alternative drilling opportunities available to each Sponsor, the availability and cost of capital, and environmental and government regulations.

In order to meet our contractual obligations under our gathering agreements with CNX Gas and Noble Energy with respect to new wells drilled on our dedicated acreage, we will be required to incur capital expenditures to extend our gathering systems and facilities to the new wells that each of our Sponsors drill. Our Sponsors, through their ownership interests in CONE Gathering, are responsible for their proportionate share (95%) of the total capital expenditures associated with the ongoing build-out of our midstream systems in each of the Growth and Additional Systems.

We have secured significant acreage dedications from each of CNX Gas and Noble Energy. The gathering agreements with our Sponsors include acreage dedications of approximately 515,000 aggregate net acres, subject to the release provisions set forth therein. In addition to our existing dedicated acreage, our gathering agreements provide that any additional acreage covering the Marcellus Shale that is acquired by CNX Gas or Noble Energy, respectively, in a “dedication area” that covers over 7,700 square miles in West Virginia and Pennsylvania, and that is not subject to a pre-existing third-party commitment, will be automatically dedicated to us. In addition to our existing dedication acreage and any potential future dedicated acreage, we have also been granted rights of first offer ("ROFO") by each of CNX Gas and Noble Energy to provide midstream services on their respective ROFO acreage, which currently includes approximately 186,000 aggregate net acres of CNX Gas’ and Noble Energy’s existing Marcellus Shale acreage that is not currently dedicated to us, along with any future acreage covering the Marcellus Shale formation that is acquired by CNX Gas or Noble Energy, as applicable, in an area that covers over 18,300 square miles in West Virginia and Pennsylvania, which we refer to as the “ROFO area,” and that is not subject to a pre-existing third-party commitment. For information regarding our Sponsors’ ability to release acreage from dedication and transfer acreage in the ROFO area, see Item 1. Consolidated Financial Statements, Note 4–Related Party–Gathering Agreements.

Adjusted EBITDA & Distributable Cash Flow

Adjusted EBITDA and distributable cash flow are non-GAAP measures that we believe provide information useful to investors in assessing our financial condition and results of operations. For a discussion on how we define Adjusted EBITDA and distributable cash flow and the supporting reconciliations to their most directly comparable GAAP financial measures, please read “Non-GAAP Financial Measures” below.

Operating Expense

Operating expense is comprised of costs directly associated with gathering natural gas at the wellhead and transporting it to interstate and intrastate pipelines, natural gas processing facilities or other delivery points. These costs include electrically-

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powered compression, direct labor, repairs and maintenance, supplies, ad valorem and property taxes, utilities and contract services. These expenses generally remain stable across broad ranges of throughput volumes but can fluctuate from period to period depending on the mix of activities performed during that period and the timing of these expenses.

Factors Impacting Our Business

We expect our business to continue to be affected by the following key factors. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.

Our Sponsors’ Drilling and Development Plans

Our operations are primarily dependent upon our Sponsors’ natural gas production on our dedicated acreage in the Marcellus Shale. Following consummation of the Exchange Agreement, each of our Sponsors has established its own drilling and development program on its respective upstream acreage, including on our dedicated acreage, and primarily relies on us to deliver the midstream infrastructure necessary to accommodate its continuing production growth in the Marcellus Shale. However, we have no control over the level or timing of our Sponsors' exploration and production activities in our areas of operation in the Marcellus Shale. For example, while neither of our Sponsors had active drilling activities on our dedicated acreage during 2016, our Sponsors had one active rig running as of March 31, 2017.

Our Sponsors have recently made two announcements that may affect the Partnership in the future. On May 2, 2017, CONSOL announced that it plans to reduce drilling activity on its Marcellus Shale acreage during 2018 while accelerating drilling activity in the Utica Shale. Although the Utica Shale acreage is not dedicated to us, we believe that we are advantageously positioned to be able to gather production from most, if not all, of the planned wells based on the proximity of the proposed wells to our current infrastructure. Also on May 2, 2017, Noble Energy announced its plans to divest of all of its upstream natural gas assets in Appalachia during the quarter ending June 30, 2017. The buyer of these assets will succeed to, and the buyer's production on the acreage that is dedicated to the Partnership will continue to be gathered by us at the fees that are outlined in, our existing gathering agreement with Noble Energy.

Fluctuations in natural gas prices could affect production rates over time and levels of investment by our Sponsors and third parties in exploration for and development of new natural gas reserves. Over parts of the last two years, persistent low commodity prices caused and may continue to cause our Sponsors or potential third-party customers to delay drilling or shut in production, which would reduce the volumes of natural gas and condensate available for gathering by our midstream systems. If either of our Sponsors, or any successor in interest to a Sponsor, further reduces or delays drilling or temporarily shuts in production due to persistently low commodity prices or for any other reason, we are not assured a certain amount of revenue, as the gathering agreements with our Sponsors do not contain minimum volume commitments.

Regulatory Compliance

The regulation of natural gas and condensate gathering and transportation activities by federal and state regulatory agencies has a significant impact on our business. For example, the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration has developed regulations that require pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in high-consequence areas. Our operations are also impacted by new regulations, which have increased the time that it takes to obtain required permits.

Additionally, increased regulation of oil and natural gas producers in our areas of operation, including regulation associated with hydraulic fracturing, could reduce regional supply of oil and natural gas and therefore affect throughput on our gathering systems.

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Results of Operations

Quarter Ended March 31, 2017 Compared to the Quarter Ended March 31, 2016



	Quarter Ended March 31,
	2017		2016		Change ($)			Change (%)
	($ in thousands)
Revenue
Gathering revenue — related party	$	58,958	$	62,248	$	(3,290	)	(5.3	)%
Total Revenue	58,958		62,248		(3,290		)	(5.3	)%
Expenses
Operating expense — third party	6,633		8,674		(2,041		)	(23.5	)%
Operating expense — related party	7,628		8,344		(716		)	(8.6	)%
General and administrative expense — third party	1,139		993		146			14.7	%
General and administrative expense — related party	2,936		1,684		1,252			74.3	%
Inventory revaluation	673		—		673			100.0	%
Depreciation expense	5,671		4,839		832			17.2	%
Interest expense	1,038		419		619			147.7	%
Total Expense	25,718		24,953		765			3.1	%
Net Income	$	33,240	$	37,295	$	(4,055	)	(10.9	)%
Less: Net income attributable to noncontrolling interest	3,173		12,505		(9,332		)	(74.6	)%
Net Income Attributable to General and Limited Partner Ownership Interest in CONE Midstream Partners LP (*)	$	30,067	$	24,790	$	5,277		21.3	%

Operating Statistics - Gathered Volumes for the Quarter Ended March 31, 2017



	Anchor	Growth	Additional	TOTAL	NET TOTAL ^(*)
Dry Gas (BBtu/d) (**)	662	52	29	743	666
Wet Gas (BBtu/d) (**)	382	5	156	543	390
Condensate (MMcfe/d)	4	—	4	8	4
Total Gathered Volumes	1,048	57	189	1,294	1,060

Operating Statistics - Gathered Volumes for the Quarter Ended March 31, 2016



	Anchor	Growth	Additional	TOTAL	NET TOTAL ^(*)
Dry Gas (BBtu/d) (**)	650	68	24	742	492
Wet Gas (BBtu/d) (**)	457	6	176	639	352
Condensate (MMcfe/d)	7	—	7	14	6
Total Gathered Volumes	1,114	74	207	1,395	850

(*) On November 16, 2016, the Partnership acquired the remaining 25% noncontrolling interest in the Anchor Systems from CONE Gathering. The Partnership owned a 100% controlling limited partner interest in the Anchor Systems during the quarter ended March 31, 2017 and a 75% controlling interest in the Anchor Systems during the quarter ended March 31, 2016. See "Ownership of Our Assets" above.

(**) Classification as dry or wet is based upon the shipping destination of the related volumes. Because our Sponsors 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 Sponsors’ 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 Sponsors' elections

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

Gathering revenue — related party was approximately $59.0 million for the three months ended March 31, 2017 compared to approximately $62.2 million for the three months ended March 31, 2016. The decrease was primarily due to a 96 BBtu/d decrease in wet natural gas gathered when compared to the prior year quarter, due to well declines exceeding the benefit of new wells being turned in line over the last 12 months. From a segment perspective, the wet gas decrease during the quarter was primarily related to a 75 BBtu/d decrease in our Anchor System and a 21 BBtu/d decrease in our Growth and Additional Systems.

Operating Expense

Total operating expenses was approximately $14.3 million in the current quarter compared to approximately $17.0 million in the prior year quarter. Included in total operating expense was electrically-powered compression expense of $4.4 million in each of the quarters ended March 31, 2017 and 2016, which was reimbursed by the Sponsors pursuant to our gas gathering agreements. After adjusting for the electrically-powered compression expense reimbursement, operating expenses decreased comparatively primarily because of a reduction of nonrecurring environmental and compliance-related expenses that occurred during the first quarter of 2016.

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 $4.1 million in the current quarter compared to approximately $2.7 million in the prior year quarter, due primarily to changes in how the general partner allocated certain personnel-related costs in the current quarter, including incentive compensation.

Pipe Revaluation

In April 2017, we agreed to sell approximately $7.1 million of our existing pipe stock that was not dedicated to specific projects to an unrelated third party for an amount that was $0.7 million below its carrying value. Accordingly, we recorded an adjustment to the carrying value of the pipe stock in the quarter ended March 31, 2017. The pipe that will be sold is within the Growth Systems reporting unit; therefore, the net impact to earnings attributable to general and limited partners' ownership interests in the Partnership is less than $0.1 million.

Depreciation Expense

Depreciation expense is recognized on gathering and other equipment on a straight-line basis, with useful lives ranging from 25-40 years. Total depreciation expense was approximately $5.7 million in the quarter ended March 31, 2017 compared to approximately $4.8 million in the quarter ended March 31, 2016. The increase is the result of additional assets placed into service over time.

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Definition of 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 herein 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 paid 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 report 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 of other companies.

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The following table presents a reconciliation of the non-GAAP measures of 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 March 31,
(in thousands)	2017		2016
Net Income	$	33,240	$	37,295
Depreciation expense	5,671		4,839
Interest expense	1,038		419
EBITDA	39,949		42,553
Non-cash unit-based compensation expense	283		136
Pipe revaluation	673		—
Adjusted EBITDA	40,905		42,689
Less:
Net income attributable to noncontrolling interest	3,173		12,505
Depreciation expense attributable to noncontrolling interest	1,830		2,286
Other expenses attributable to noncontrolling interest	82		189
Pipe revaluation attributable to noncontrolling interest	639		—
Adjusted EBITDA attributable to General and Limited Partner ownership interest in CONE Midstream Partners LP	$	35,181	$	27,709
Less: cash interest paid, net	1,000		230
Less: ongoing maintenance capital expenditures, net of expected reimbursements	3,881		2,839
Distributable Cash Flow	$	30,300	$	24,640

Net Cash Provided by Operating Activities	$	34,176	$	41,180
Interest expense	1,038		419
Pipe revaluation	673		—
Other, including changes in working capital	5,018		1,090
Adjusted EBITDA	40,905		42,689
Less:
Net income attributable to noncontrolling interest	3,173		12,505
Depreciation expense attributable to noncontrolling interest	1,830		2,286
Other expenses attributable to noncontrolling interest	82		189
Pipe revaluation attributable to noncontrolling interest	639		—
Adjusted EBITDA attributable to General and Limited Partner ownership interest in CONE Midstream Partners LP	$	35,181	$	27,709
Less: cash interest paid, net	1,000		230
Less: ongoing maintenance capital expenditures, net of expected reimbursements	3,881		2,839
Distributable Cash Flow	$	30,300	$	24,640

Distributable cash flow is a non-GAAP measure that is net to the Partnership. The current quarter increase of $5.7 million compared to the quarter ended March 31, 2016, or 23%, was primarily attributable to the Acquisition in the fourth quarter of 2016.

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Liquidity and Capital Resources

Liquidity and Financing Arrangements

We satisfy our working capital requirements, fund capital expenditures and acquisitions and make 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 satisfy future growth. We believe that cash generated from these sources will continue to be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to make quarterly cash distributions.

Revolving Credit Facility

We maintain a $250.0 million revolving credit facility, which is available for working capital, capital expenditures, certain acquisitions, distributions, unit repurchases and other lawful partnership purposes. As of March 31, 2017, we had an outstanding balance on our revolving credit facility of $162.0 million. We incurred $1.0 million of cash interest expense on the revolving credit facility (not including amortization of revolver fees) during the quarter ended March 31, 2017.

Based on our compliance with the financial covenants governed by the revolving credit facility, we had $88.0 million, the maximum amount of revolving credit, available for borrowing at March 31, 2017.

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.

Cash Flows

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



	Quarter Ended March 31,
(in thousands)	2017			2016			Change
Net cash provided by operating activities	$	34,176		$	41,180		$	(7,004	)
Net cash used in investing activities	$	(11,192	)	$	(24,386	)	$	13,194
Net cash used in financing activities	$	(23,387	)	$	(2,738	)	$	(20,649	)

Net cash provided by operating activities decreased approximately $7.0 million during the current quarter compared to the prior year quarter, which was primarily due to a reduction in the Partnership's consolidated year over year net income of $4.1 million. The remaining change is due to several other working capital adjustments, none of which were individually significant.

Net cash used in investing activities decreased $13.2 million in the current quarter due primarily to a reduction in capital expenditures compared to the prior year quarter.

Cash used in financing activities during the quarter ended March 31, 2017 compared to the quarter ended March 31, 2016 increased approximately $20.6 million primarily due to lower capital spending during the quarter ended December 31, 2016 compared to the quarter ended December 31, 2015, which reduced the Sponsors' required payments (on which there is a two month delay) for capital in those Systems in which they have an economic interest. The Sponsors owned 95% noncontrolling interests in the Growth and Additional Systems in both periods, a 25% noncontrolling interest in the Anchor Systems during the quarter ended December 31, 2015 and no interests in the Anchor Systems for half of the quarter ended December 31, 2016. Also contributing to the increase in cash used in financing activities was increased net payments on the revolving credit facility and our payment of approximately $4.0 million more quarterly distributions in the quarter ended March 31, 2017 compared to the quarter ended March 31, 2016.

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

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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 Quarter Ended March 31, 2017



	Anchor		Growth		Additional			TOTAL
Capital Investment
Maintenance capital	$	3,838	$	227	$	633		$	4,698
Expansion capital	6,315		212		(33		)	6,494
Total Capital Investment	$	10,153	$	439	$	600		$	11,192

Capital Investment Net to the Partnership
Maintenance capital	$	3,838	$	11	$	32		$	3,881
Expansion capital	6,315		11		(2		)	6,324
Total Capital Investment Net to the Partnership	$	10,153	$	22	$	30		$	10,205

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. 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.

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.

Cash Distributions

Under our current cash distribution policy, we intend to pay a minimum quarterly distribution of $0.2125 per unit per quarter, which equates to an aggregate distribution of approximately $13.8 million per quarter, or approximately $55.1 million per year, based on the general partner interest and the number of common and subordinated units outstanding as of March 31, 2017. 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. The amount of distributions paid under our cash distribution policy and the decision to make any distribution will be determined by our general partner, taking into consideration the terms of the partnership agreement.

On April 20, 2017, the board of directors of our general partner declared a cash distribution to our unitholders with respect to the first quarter of 2017 of $0.2821 per common and subordinated unit. The cash distribution will be paid on May 15, 2017 to unitholders of record as of the close of business on May 4, 2017.

For additional information on our cash distribution policy, see Item 1. Consolidated Financial Statements, Note 2–Significant Accounting Policies–Cash Distributions, which is incorporated herein by reference.

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, which is incorporated herein by reference.

Critical Accounting Policies

For a description of the Partnership’s accounting policies and any new accounting 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 March 31, 2017, 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, our capital programs and our Sponsors.

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. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:


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


•	changes in the drilling and development plans of our Sponsors, or their successors in interest, in the Marcellus Shale and Utica Shale;


•	the ability of our Sponsors, or their successors in interest, to meet their drilling and development plans in the Marcellus Shale and Utica Shale;


•	the release of acreage from dedication by our Sponsors, or their successors in interest;


•	transfers of acreage by our Sponsors in the right of first offer area, which are not subject to our right of first offer;


•	non-performance or non-payment by the counterparties to our gathering agreements;


•	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;

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


•	interest rates;


•	labor relations;


•	defaults by our Sponsors 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


•	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, 2016 and in Part II. Item 1A. “Risk Factors” of this Quarterly Report on 10-Q, 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

To date, we have generated all of our revenues pursuant to fee-based gathering agreements with our Sponsors based on acreage dedications and do not have minimum volume commitments. We are paid based on the volumes of natural gas and condensate that we gather and handle, 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, we are indirectly exposed to commodity price risks through our Sponsors, who may reduce or shut in production due to depressed commodity prices. Although we intend to enter into similar fee-based gathering agreements with new customers in the future, our efforts to negotiate terms with third parties 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 $250.0 million revolving credit facility. Assuming the March 31, 2017 outstanding balance on our revolving credit facility of $162.0 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 $1.6 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.


ITEM 4.	CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of management of the Partnership’s general partner, including the general partner’s Principal Executive Officer and Principal Financial Officer, 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 report. Based upon this evaluation, the Chief Executive Officer and Chief Financial Officer of the Partnership’s general partner have concluded that the Partnership’s disclosure controls and procedures were effective as of the end of the period covered by this report.

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 first quarter of 2017 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, 2016. With the exception of the update below, there have been no material changes from the risk factors previously disclosed in the Partnership’s Annual Report on Form 10-K.

We cannot currently determine what impact, if any, Noble Energy’s divestiture of its upstream assets in the Marcellus Shale will have on the Partnership.

On May 2, 2017, Noble Energy announced that it had entered into an agreement providing for the divestiture of all of its upstream Appalachia natural gas assets. The transaction is anticipated to close during the quarter ending June 30, 2017. We currently derive a significant portion of our revenue from our existing gathering agreement with Noble Energy, and following consummation of the transaction, the buyer will succeed to, and the buyer’s production on the acreage that is dedicated to the Partnership will continue to be gathered by the Partnership at the fees that are outlined in, our gathering agreement with Noble Energy. We do not yet know the buyer’s drilling plans with respect to the Marcellus acreage, and the buyer of these assets will be under no obligation to pursue business strategies that are favorable to us. Additionally, we will be subject to fluctuations in the buyer’s creditworthiness and overall financial condition, which following consummation of the transaction, may subject us to the risk of non-payment or non-performance by the buyer under our gathering agreement, which could materially adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.

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

Not applicable.

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ITEM 6.	EXHIBITS



		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number	Exhibit	Filing Date
3.1*	Certificate of Limited Partnership of CONE Midstream Partners LP	S-1	333-198352	3.1	08/25/2014
3.2*	First Amended and Restated Agreement of Limited Partnership of CONE Midstream Partners LP, dated as of September 30, 2014	8-K	001-36635	3.1	10/03/2014
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.

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SIGNATURES

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

Dated: May 4, 2017



	CONE MIDSTREAM PARTNERS LP
	By:	CONE MIDSTREAM GP, LLC, its general partner

	By:	/S/ JOHN T. LEWIS
		John T. Lewis
		Chief Executive Officer and Director (Duly Authorized Officer and Principal Executive Officer)

	By:	/S/ DAVID M. KHANI
		David M. Khani
		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)

CNX Midstream Partners LP - FORM 10-Q - May 4, 2017

Attached files

CNX Midstream Partners LP Reports