UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 __________________________________________________

FORM 10-Q

 __________________________________________________ 

(Mark One)

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

For the quarterly period ended September 30, 2016

OR

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

For the transition period from to

Commission file number: 001-36635

__________________________________________________

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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  o    Accelerated filer  x    Non-accelerated filer  o    Smaller Reporting Company  o

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 November 4, 2016, CONE Midstream Partners LP had 29,180,217 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 and Nine Months Ended September 30, 2016 and 2015	3
	Consolidated Balance Sheets at September 30, 2016 and December 31, 2015	4
	Consolidated Statement of Partners' Capital for the Nine Months Ended September 30, 2016	5
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2016 and 2015	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	35
ITEM 4.	Controls and Procedures	35
PART II OTHER INFORMATION
ITEM 1.	Legal Proceedings	36
ITEM 1A.	Risk Factors	36
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	36
ITEM 3.	Defaults upon Senior Securities	36
ITEM 4.	Mine Safety Disclosures	36
ITEM 5.	Other Information	36
ITEM 6.	Exhibits	37

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   September 30,				Nine Months Ended   September 30,
	2016		2015		2016		2015
Revenue
Gathering revenue — related party	$	60,729	$	53,753	$	181,384	$	144,638
Total Revenue	60,729		53,753		181,384		144,638
Expenses
Operating expense — third party	7,769		4,736		24,322		22,205
Operating expense — related party	7,209		8,095		22,631		22,079
General and administrative expense — third party	1,049		968		3,196		3,533
General and administrative expense — related party	2,624		2,413		6,521		6,385
Pipe revaluation	—		—		10,083		—
Depreciation expense	5,392		3,769		15,384		10,430
Interest expense	305		158		1,105		270
Total Expense	24,348		20,139		83,242		64,902
Net Income	36,381		33,614		98,142		79,736
Less: Net income attributable to noncontrolling interest	12,750		13,957		26,505		30,954
Net Income Attributable to General and Limited Partner Ownership Interest in CONE Midstream Partners LP	$	23,631	$	19,657	$	71,637	$	48,782
Calculation of Limited Partner Interest in Net Income:
Net Income Attributable to General and Limited Partner Ownership Interest in CONE Midstream Partners LP	$	23,631	$	19,657	$	71,637	$	48,782
Less: General partner interest in net income	473		393		1,433		976
Limited partner interest in net income	$	23,158	$	19,264	$	70,204	$	47,806
Net income per limited partner unit - Basic	$	0.40	$	0.33	$	1.20	$	0.82
Net income per limited partner unit - Diluted	$	0.40	$	0.33	$	1.20	$	0.82
Limited partner units outstanding - Basic	58,343		58,326		58,343		58,326
Limited partner unit outstanding - Diluted	58,431		58,333		58,410		58,331
Cash distributions declared per unit (*)	$	0.2630	$	0.2280	$	0.7620	$	0.6605

(*) Represents the cash distributions declared during the month following the respective quarterly reporting period ends. 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)

	September 30, 2016			December 31, 2015
ASSETS
Current Assets:
Cash	$	4,196		$	217
Receivables — related party (Note 6)	20,287			36,418
Inventory	—			18,916
Other current assets	1,431			2,037
Total Current Assets	25,914			57,588
Property and Equipment:
Property and equipment (Note 7)	922,498			897,918
Less — accumulated depreciation	46,698			31,609
Property and Equipment — Net	875,800			866,309
Other assets (Note 8)	9,001			528
TOTAL ASSETS	$	910,715		$	924,425
LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable	$	19,124		$	46,155
Accounts payable — related party (Note 9)	1,680			1,628
Total Current Liabilities	20,804			47,783
Other Liabilities:
Revolving credit facility (Note 10)	41,000			73,500
Total Liabilities	61,804			121,283
Partners' Capital:
Common units (29,180,217 units issued and outstanding at September 30, 2016 and 29,163,121 units issued and outstanding at December 31, 2015)	413,610			399,399
Subordinated units (29,163,121 units issued and outstanding at September 30, 2016 and December 31, 2015)	(69,248		)	(82,900		)
General partner interest	(2,921		)	(3,389		)
Partners' capital attributable to CONE Midstream Partners LP	341,441			313,110
Noncontrolling interest	507,470			490,032
Total Partners' Capital	848,911			803,142
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$	910,715		$	924,425

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

4

CONE MIDSTREAM PARTNERS LP

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL AND OTHER EQUITY

(in thousands)

	Partners' Capital									Total
										Capital
	Limited Partners						General			Attributable			Noncontrolling
	Common			Subordinated			Partner			to Partners			Interest			Total
Balance at December 31, 2015	$	399,399		$	(82,900	)	$	(3,389	)	$	313,110		$	490,032		$	803,142
(Unaudited)
Net income	35,112			35,092			1,433			71,637			26,505			98,142
Partner and noncontrolling interest holder activity	—			—			3			3			(9,067		)	(9,064		)
Distributions to unitholders	(21,455		)	(21,440		)	(968		)	(43,863		)	—			(43,863		)
Unit-based compensation	577			—			—			577			—			577
Unitholder taxes paid upon vesting of unit-based awards	(23		)	—			—			(23		)	—			(23		)
Balance at September 30, 2016	$	413,610		$	(69,248	)	$	(2,921	)	$	341,441		$	507,470		$	848,911

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

5

CONE MIDSTREAM PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)

	Nine Months Ended   September 30,
	2016			2015
Cash Flows from Operating Activities:
Net income	$	98,142		$	79,736
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation expense and amortization of debt issuance costs	15,507			10,553
Unit-based compensation	577			310
Pipe revaluation	10,083			—
Other	580			—
Changes in assets and liabilities:
Receivables — related party	9,411			(1,102		)
Other current and non-current assets	606			460
Accounts payable	(11,961		)	4,527
Accounts payable — related party	(7		)	4,784
Net Cash Provided by Operating Activities	122,938			99,268
Cash Flows from Investing Activities:
Capital expenditures	(40,466		)	(232,950		)
Proceeds from sale of long-lived assets	237			—
Net Cash Used in Investing Activities	(40,229		)	(232,950		)
Cash Flows from Financing Activities:
Partner and noncontrolling interest holder activity	(2,344		)	144,960
Distributions to unitholders	(43,863		)	(38,525		)
Net (payments) proceeds on revolving credit facility	(32,500		)	25,200
Unitholder taxes paid upon vesting of unit-based awards	(23		)	—
Net Cash (Used In) Provided By Financing Activities	(78,730		)	131,635
Net Increase (Decrease) in Cash	3,979			(2,047		)
Cash at Beginning of Period	217			3,252
Cash at End of Period	$	4,196		$	1,205

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 CONSOLIDATED UNAUDITED FINANCIAL STATEMENTS

NOTE 1—DESCRIPTION OF BUSINESS AND INITIAL PUBLIC OFFERING

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, 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, 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 separate 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 stages of their development.

• Our Anchor Systems include our more developed midstream systems that generate the largest portion of our current cash flows and that we expect to drive our earnings and growth over the near term.

• Our Growth Systems include our gathering systems primarily located in the dry gas regions of our Sponsors' dedicated acreage that are generally in earlier phases of development and require substantial future expansion capital expenditures, which will primarily be funded by our Sponsors in proportion to CONE Gathering's retained ownership interests.

• Our Additional Systems include several gathering systems primarily located in the wet gas regions of our Sponsors' 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 will also be funded by our Sponsors in proportion to CONE Gathering's retained ownership interests.

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.

Initial Public Offering

On September 30, 2014, the Partnership closed its initial public offering ("IPO") of 20,125,000 common units at a price to the public of $22.00 per unit, which included all 2,625,000 common units of the underwriters' over-allotment option. The Partnership’s common units are listed on the New York Stock Exchange under the ticker symbol “CNNX.”

Concurrent with the closing of the 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. In exchange for CONE Gathering's contribution of assets and liabilities to the Partnership, CONE Gathering received:

• through its ownership of our general partner, a continuation of a 2% general partner interest in the partnership;

• 9,038,121 common units and 29,163,121 subordinated units, representing an aggregate 64.2% limited partner interest in the Partnership (the common and subordinated units were subsequently distributed to the Sponsors);

• through its ownership of our general partner, all of the Partnerships' incentive distribution rights; and

• an aggregate cash distribution of $408.0 million.

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NOTE 2 — BASIS OF PRESENTATION AND 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"). Accordingly, management makes estimates and assumptions that affect the amounts reported in the consolidated financial statements and the notes thereto. These estimates 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. 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.

The balance sheet at December 31, 2015 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 only has an economic interest in 75% of the Anchor Systems and 5% of the Growth and Additional Systems, each are consolidated fully with the results of the Partnership for periods following the IPO. However, after adjusting for noncontrolling interests, net income attributable to general and limited partner ownership interests in the Partnership reflect less than 100% of the results of the Anchor Systems, Growth Systems and Additional Systems and represents only that portion of net income that is attributable to the Partnership's unitholders.

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.

The Partnership may remain an emerging growth company for up to five years from the date of our IPO, 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; 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 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

Revenues are recognized for the transportation of natural gas and other hydrocarbons based on the delivery of actual volumes transported at a contracted throughput rate. Operating fees received are recorded in gathering revenue — related party in the period the service is performed.

Cash

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

8

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 September 30, 2016 and December 31, 2015.

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. There were no retirements or disposals during the periods presented in the accompanying consolidated financial statements.

The Partnership evaluates whether long-lived assets have been impaired and determines if the carrying amount of its assets may not be recoverable. For such long-lived assets, impairment exists when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying amount of the long-lived asset is not recoverable, based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying amount over its estimated fair value.

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 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 September 30, 2016 and December 31, 2015, we had no material environmental matters that required the recognition of a 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 asset retirement obligations at September 30, 2016 or December 31, 2015.

Variable Interest Entities

The Partnership adopted ASU 2015-02, "Consolidation: Amendments to the Consolidation Analysis" during the 2016 period. ASU 2015-02 changed the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. Based on the criteria outlined in this standard, the Partnership continues to fully consolidate its existing variable interest entities ("VIEs") - the Anchor, Growth and Additional Limited Partnerships (the "Limited Partnerships") through its ownership of CONE Midstream Operating Company LLC. These VIEs correspond with the manner in which we report our segment information in Note 14, 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.

CONE Midstream Operating Company LLC, 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

9

direct all substantive strategic and day-to-day operational decisions of the Limited Partnerships. The adoption of ASU 2015-02 did not impact the Partnership's financial statements.

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 award's vesting term. See Note 15 – Long Term Incentive Plan for further discussion.

Income Taxes

CONE Midstream Partners LP is 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 quarterly period 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. The board of directors of our general partner has considerable discretion to determine the amount of our available cash each quarter as well as the ability to 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.

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 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 there are no arrearages on common units.

			Marginal Percentage Interest in Distributions
Distribution Targets	Total Quarterly Distribution Per Unit Target Amount		Unitholders	General Partner
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%

10

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.

Subordination Period

Except as described below, the subordination period began on the closing date of the IPO and will extend until the first business day following the distribution of available cash in respect of any quarter beginning after September 30, 2017, that each of the following tests are met:

• distributions of available cash from operating surplus on each of the outstanding common units and subordinated units and the corresponding distributions on the 2% general partner interest equaled or exceeded $0.85 (the annualized minimum quarterly distribution), for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

• the adjusted operating surplus (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of $0.85 (the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units and the corresponding distributions on the 2% general partner interest during those periods on a fully diluted basis; and

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

Early Termination of the Subordination Period

The subordination period will automatically terminate on the first business day following the distribution of available cash in respect of any quarter that each of the following tests are met: 

• distributions of available cash from operating surplus on each of the outstanding common units and subordinated units and the corresponding distributions on the 2% general partner interest equaled or exceeded $1.275 (150% of the annualized minimum quarterly distribution), plus the related distributions on the incentive distribution rights, for the four-quarter period immediately preceding that date;

• the adjusted operating surplus (as defined below) generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of (i) $1.275 (150% of the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units and the corresponding distributions on the 2% general partner interest during that period on a fully diluted basis and (ii) the corresponding distributions on the incentive distribution rights; and

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

Expiration of the Subordination Period

When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will thereafter participate pro rata with the other common units in distributions of available cash.

Adjusted Operating Surplus

Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net drawdowns of reserves of cash established in prior periods. Adjusted operating surplus for a period consists of:

• operating surplus generated with respect to that period; less

• any net increase in working capital borrowings with respect to that period; less

• any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

• any net decrease in working capital borrowings with respect to that period; plus

• any net decrease made in subsequent periods to cash reserves for operating expenditures initially established with respect to that period to the extent such decrease results in a reduction in adjusted operating surplus in subsequent periods; plus

• any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

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Incentive Distribution Rights ("IDRs")

All of the IDRs are currently held by CONE Midstream GP LLC, our general partner. Incentive distribution rights represent the right to receive an increasing percentage (13.0%, 23.0% and 48.0%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels described below have been achieved. Our general partner may transfer the IDRs separately from its general partner interest.

The following discussion assumes that our general partner maintains its 2% general partner interest and that our general partner continues to own the IDRs.

If for any quarter:

• we have distributed available cash from operating surplus to the common unitholders and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

• we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:

• first, 98% to all unitholders, pro rata, and 2% to our general partner, until each unitholder receives a total of $0.24438 per unit for that quarter (the “first target distribution”);

• second, 85% to all unitholders, pro rata, and 15% to our general partner, until each unitholder receives a total of $0.26563 per unit for that quarter (the “second target distribution”);

• third, 75% to all unitholders, pro rata, and 25% to our general partner, until each unitholder receives a total of $0.31875 per unit for that quarter (the “third target distribution”); and

• thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.

The second IDR threshold was reached during the nine month period ended September 30, 2016, beginning with the distribution that related to the quarter ended March 31, 2016 and was paid on May 13, 2016. All prior distributions were paid in accordance with the first target distribution.

Reclassifications

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

Recent Accounting Pronouncements

In May 2014, the FASB issued Accounting Standards Update ("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 Update 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 Update 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

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reporting periods beginning after December 15, 2016. We are currently evaluating the method of adoption as it relates to ASU 2014-09 and the impacts that these standards will have on our 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 financial covenants with lenders; however, we do not believe this standard will materially adversely impact our existing credit agreements.

In March 2016, the FASB issued ASU 2016-09, "Compensation—Stock Compensation (Topic 718)." This standard makes several modifications to Topic 718 related to the accounting for forfeitures, employer tax withholding on share-based compensation and the financial statement presentation of excess tax benefits or deficiencies. ASU 2016-09 also clarifies the statement of cash flows presentation for certain components of share-based awards. The standard is effective for interim and annual reporting periods beginning after December 15, 2016, although early adoption is permitted. We do not believe this standard will materially impact the Partnership.

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.

NOTE 3 — NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST

During the nine months ended September 30, 2016, the Partnership adopted ASU 2015-06 "Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions".  ASU 2015-06, which is required to be applied retrospectively, specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings or losses of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. In that circumstance, the previously reported earnings per unit of the limited partners, which is typically the earnings per unit measure presented in the financial statements, would not change as a result of the dropdown transaction. Adoption of this standard did not impact the consolidated presentation of the Partnership's financial statements or related disclosures for the three and nine months ended September 30, 2016 and 2015.

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.

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.

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

	Three Months Ended   September 30,				Nine Months Ended   September 30,
(in thousands, except per unit information)	2016		2015		2016		2015
Net Income Attributable to General and Limited Partner Ownership Interest in CONE Midstream Partners LP	$	23,631	$	19,657	$	71,637	$	48,782
Less: General partner interest in net income	473		393		1,433		976
Limited partner interest in net income	$	23,158	$	19,264	$	70,204	$	47,806
Net income allocable to common units	$	11,582	$	9,632	$	35,112	$	23,903
Net income allocable to subordinated units	11,576		9,632		35,092		23,903
Limited partner interest in net income	$	23,158	$	19,264	$	70,204	$	47,806
Weighted average limited partner units outstanding — Basic
Common units	29,180		29,163		29,180		29,163
Subordinated units	29,163		29,163		29,163		29,163
Total	58,343		58,326		58,343		58,326
Weighted average limited partner units outstanding — Diluted
Common units	29,268		29,170		29,247		29,168
Subordinated units	29,163		29,163		29,163		29,163
Total	58,431		58,333		58,410		58,331
Net income per limited partner unit — Basic and Diluted
Common units	$	0.40	$	0.33	$	1.20	$	0.82
Subordinated units	$	0.40	$	0.33	$	1.20	$	0.82

NOTE 4 — RELATED PARTY

In the ordinary course of business, the Partnership has transactions with related parties that result in affiliate transactions. Related parties during each of the periods presented included CONSOL and certain of its subsidiaries and Noble Energy, to each of whom we provide natural gas gathering and compression services.

Transactions with related parties, other than certain transactions with CONSOL and Noble Energy related to administrative services, were conducted on terms which management believes are comparable to those with unrelated parties. We believe such costs would not have been materially different had they been calculated on a stand-alone basis.

Operating expenses — related party consisted primarily of $7.2 million and $8.1 million of charges from CONSOL for the three months ended September 30, 2016 and 2015 and $22.6 million and $22.1 million for the nine months ended September 30, 2016 and 2015, respectively. Included within this caption were $4.4 million and $4.3 million of electrically-powered compression, which is reimbursed by the Sponsors pursuant to their respective Gathering Agreements, for the three months ended September 30, 2016 and 2015, respectively. Electrically-powered compression for the nine months ended September 30, 2016 and 2015 totaled $12.6 million and $11.4 million, respectively.

During the nine months ended September 30, 2015, CONSOL purchased $2.2 million of supply inventory from the Partnership.

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Additionally, general and administrative expense - related party consisted of the following charges from each Sponsor:

	Three Months Ended   September 30,				Nine Months Ended   September 30,
(in thousands)	2016		2015		2016		2015
CONSOL	$	2,462	$	2,278	$	6,031	$	5,974
Noble Energy	162		135		490		411
Total General and Administrative Expense — Related Party	$	2,624	$	2,413	$	6,521	$	6,385

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 $0.5 million for the year ending December 31, 2016, for the provision of certain services by CONSOL and its affiliates;

• our payment of an annually-determined administrative support fee, which will total $0.8 million for the year ending December 31, 2016, 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, 2016, 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 under which CONSOL provides certain operational services to us in support of our gathering pipelines and dehydration, treating and compressor stations and facilities. Such services include 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 also reimburse CONSOL for any direct third-party costs incurred by CONSOL in providing these services.

The operational services agreement has an initial term of 20 years and will continue in full force and effect unless terminated by either party at the end of the initial term or any time thereafter by giving not less than six months’ prior notice to the other party of such termination. CONSOL may terminate the operational services agreement if (1) we become insolvent, declare bankruptcy or take any action in furtherance of, or indicating our consent to, approval of, or acquiescence in, a similar proceeding or (2) upon not less than 180 days notice. We may immediately terminate the agreement (1) if CONSOL becomes insolvent, declares bankruptcy or takes any action in furtherance of, or indicating its consent to, approval of, or acquiescence in, a similar proceeding, (2) upon a finding of CONSOL’s willful misconduct or gross negligence that has had a material adverse effect on any of our gathering pipelines and dehydration, treating and compressor stations and facilities or our business or (3) CONSOL is in material breach of the operational services agreement and fails to cure such default within 45 days.

Under the operational services agreement, CONSOL will indemnify us from any claims, losses or liabilities incurred by us, including third-party claims, arising from CONSOL’s performance of the agreement to the extent caused by CONSOL’s gross negligence or willful misconduct. We will indemnify CONSOL from any claims, losses or liabilities incurred by

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CONSOL, including any third-party claims, arising from CONSOL’s performance of the agreement, except to the extent such claims, losses or liabilities are caused by CONSOL’s gross negligence or willful misconduct.

Gathering Agreements

CNX Gas Gathering Agreement

On September 30, 2014, in connection with the closing of the IPO, the Partnership entered into a Gathering Agreement (the “CNX Gas Gathering Agreement”) by and between the Partnership, as gatherer, and CNX Gas Company LLC (“CNX Gas”), a wholly owned subsidiary of CONSOL, as shipper. Under the CNX Gas Gathering Agreement, which has an initial term of 20 years, CNX Gas (i) dedicated to the Partnership for natural gas midstream services all of its existing acres and any acres acquired in the future, in each case, that are jointly owned with Noble Energy to the extent covering the Marcellus Shale in the dedication area and (ii) granted the Partnership a right of first offer to provide natural gas midstream services with respect to all of its existing acres and any acres acquired in the future, in each case, that are jointly owned with Noble Energy to the extent covering the Marcellus Shale in the right of first offer area.

Under the CNX Gas Gathering Agreement, the Partnership charges fees based on the type and scope of midstream services it provides. Each fee is subject to an annual 2.5% increase (beginning on January 1, 2016) and any fee may be recalculated upon the mutual agreement of the Partnership and CNX Gas. For 2016, for the services provided (a) with respect to natural gas that does not require downstream processing, the Partnership's fees are $0.41 per MMBtu, (b) with respect to the natural gas that requires downstream processing, the Partnership's fees are $0.564 per MMBtu, except in the Pittsburgh International Airport and Moundsville (Marshall County, West Virginia) areas, where the fees are $0.282 per MMBtu and (c) with respect to condensate, the Partnership's fees are $5.125 per Bbl in the Majorsville area and $2.56 per Bbl in the Moundsville area. The 2016 rates reflect an increase of 2.5% from the rates that were in effect at the IPO date.

Under the CNX Gas Gathering Agreement, if the Partnership fails to timely complete the construction of the facilities necessary to provide midstream services to CNX Gas’ dedicated acreage or has an uncured default of any of the Partnership’s material obligations that has caused an interruption in the Partnership’s services for more than 90 days, the affected acreage will be permanently released from the Partnership’s dedication. Also, after the fifth anniversary of the CNX Gas Gathering Agreement, if CNX Gas drills a well that is located more than a certain distance from the Partnership’s current gathering system (and not included in the detailed drilling plan provided by CNX Gas and Noble Energy) and a third-party gatherer offers a lower cost of services, then the acreage associated with that well will be permanently released from the Partnership’s dedication.

NBL Gas Gathering Agreement

On September 30, 2014, in connection with the closing of the IPO, the Partnership entered into a Gathering Agreement (the “NBL Gas Gathering Agreement”) by and between the Partnership, as gatherer, and Noble Energy, as shipper. Under the NBL Gas Gathering Agreement, which has an initial term of 20 years, Noble Energy (i) dedicated to the Partnership for natural gas midstream services all of its existing acres and any acres acquired in the future, in each case, that are jointly owned with CNX Gas to the extent covering the Marcellus Shale in the dedication area and (ii) granted the Partnership a right of first offer to provide natural gas midstream services with respect to all of its existing acres and any acres acquired in the future, in each case, that are jointly owned with CNX Gas to the extent covering the Marcellus Shale in the right of first offer area.

Under the NBL Gas Gathering Agreement, the Partnership charges fees based on the type and scope of midstream services it provides. Each fee is subject to an annual 2.5% increase (beginning on January 1, 2016) and any fee may be recalculated upon the mutual agreement of the Partnership and Noble Energy. For 2016, for the services provided (a) with respect to natural gas that does not require downstream processing, the Partnership's fees are $0.41 per MMBtu, (b) with respect to the natural gas that requires downstream processing, the Partnership's fees are $0.564 per MMBtu, except in the Pittsburgh International Airport and Moundsville (Marshall County, West Virginia) areas, where the fees are $0.282 per MMBtu and (c) with respect to condensate, the Partnership's fees are $5.125 per Bbl in the Majorsville area and $2.56 per Bbl in the Moundsville area. The 2016 rates reflect an increase of 2.5% from the rates that were in effect at the IPO date.

Under the NBL Gas Gathering Agreement, if the Partnership fails to timely complete the construction of the facilities necessary to provide midstream services to Noble Energy’s dedicated acreage or has an uncured default of any of the Partnership’s material obligations that has caused an interruption in the Partnership’s services for more than 90 days, the affected acreage will be permanently released from the Partnership’s dedication. Also, after the fifth anniversary of the NBL Gas Gathering Agreement, if Noble Energy drills a well that is located more than a certain distance from the Partnership’s current gathering system (and not included in the detailed drilling plan provided by CNX Gas and Noble Energy) and a third-party gatherer offers a lower cost of services, then the acreage associated with that well will be permanently released from the Partnership’s dedication.

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NOTE 5 — CONCENTRATION OF CREDIT RISK

The Sponsors accounted for all of the Partnership’s revenue during the three and nine months ended September 30, 2016 and 2015. Revenues attributable to each Sponsor were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2016		2015		2016		2015
CONSOL	$	30,892	$	26,985	$	92,516	$	73,746
Noble Energy	29,837		26,768		88,868		70,892
Total Revenue	$	60,729	$	53,753	$	181,384	$	144,638

NOTE 6 — RECEIVABLES - RELATED PARTY

Receivables consisted of the following:

(in thousands)	September 30, 2016		December 31, 2015
Gathering Fees:
CONSOL	$	10,305	$	10,221
Noble Energy	9,976		19,246
Contributions Receivable:
CONSOL	—		3,360
Noble Energy	—		3,360
Other	6		231
Total Receivables — Related Party	$	20,287	$	36,418

NOTE 7 — PROPERTY AND EQUIPMENT

Property and equipment consisted of the following:

(in thousands)	September 30, 2016		December 31, 2015		Estimated Useful Lives in Years
Land	$	72,939	$	76,755	N/A
Gathering equipment	635,311		561,642		25 — 40
Compression equipment	166,457		122,705		30 — 40
Processing equipment	30,979		30,979		40
Assets under construction	16,812		105,837		N/A
Total Property and Equipment	$	922,498	$	897,918
Less: Accumulated depreciation
Gathering	$	33,056	$	21,130
Compression	9,541		6,998
Processing	4,101		3,481
Total Accumulated Depreciation	$	46,698	$	31,609
Property and Equipment, Net	$	875,800	$	866,309

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NOTE 8 — OTHER ASSETS

Other assets consisted of the following:

(in thousands)	September 30, 2016		December 31, 2015
Tygart Valley pipe	$	8,596	$	—
Financing fees	326		449
Deposits	79		79
Total Other Assets	$	9,001	$	528

In June 2016, the Partnership agreed to sell a portion of existing excess pipe supply that was not dedicated to specific capital projects to an unrelated third party for an amount that was below its carrying cost.  Prior to June 30, 2016, management intended to sell the excess pipe or consider alternative capital projects in which the pipe may be used within the next 12 months; accordingly, the pipe was historically classified as a current asset in inventory. Due to the uncertainty that surrounds the use of the remaining pipe and the Partnership’s willingness to liquidate the pipe at a discounted value, the Partnership reclassified the remaining excess pipe to a long-term asset at June 30, 2016 and simultaneously reduced the carrying value of excess pipe to the value that was commensurate with the sale price.  This adjustment, which was recorded in the Partnership’s Growth System segment, is reflected within pipe revaluation in the accompanying consolidated statements of operations for the nine months ended September 30, 2016.

NOTE 9 — ACCOUNTS PAYABLE - RELATED PARTY

Related party payables consisted of the following:

(in thousands)	September 30, 2016		December 31, 2015
Expense reimbursement to CONSOL	$	985	$	1,173
Capital expenditures reimbursement to CONE Gathering LLC	—		2
Capital expenditures reimbursement to CONSOL	61		—
General and administrative services provided by CONSOL	579		402
General and administrative services provided by Noble Energy	55		51
Total Accounts Payable — Related Party	$	1,680	$	1,628

NOTE 10 — REVOLVING CREDIT FACILITY

In connection with the closing of our IPO on September 30, 2014, we entered into a five year agreement which provides for a $250 million unsecured revolving credit facility that can be used 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

• 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.

Our revolving credit facility contains covenants and conditions that, among other things, limit 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

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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. We defined this as our consolidated leverage ratio which is calculated as the total amount outstanding on our credit facility divided by EBITDA Attributable to General and Limited Partner Ownership Interest in the Partnership. The Partnership met the requirements of this financial covenant for the twelve month period ended September 30, 2016.

• 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. We defined this as our consolidated interest coverage ratio which is calculated as EBITDA Attributable to General and Limited Partner Ownership Interest in the Partnership divided by total interest charges. The Partnership met the requirements of this financial covenant for the twelve month period ended September 30, 2016.

The outstanding balance of our revolving credit facility and interest rates on the amounts drawn from our revolver consist of the following:

	September 30, 2016				December 31, 2015
(in thousands, except percentages)	Debt		Interest Rate (1)		Debt		Interest Rate (2)
Credit Facility	$	41,000	2.06	%	$	73,500	2.18	%

⁽¹⁾ Borrowings accrued interest at the LIBOR rate, plus a margin as described above.

⁽²⁾ The weighted average annual interest rate consists of JP Morgan's prime rate and LIBOR rate, plus a margin as described above.

As of September 30, 2016, we had outstanding debt issuance costs of $0.5 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 September 30, 2015, we had a receivable of $3.7 million related to partners' investments from CONSOL and Noble Energy. Additionally, we had capital expenditures due to be reimbursed to CONE Gathering LLC of $3.3 million, in addition to capital expenditures and right of way transfers due to be reimbursed to CONSOL of $3.8 million as of September 30, 2015.

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.

NOTE 13 — LEASES

We have entered into various non-cancellable operating leases, the majority of which relate to compression facilities. Future minimum lease payments under all of our operating leases as of September 30, 2016 are as follows:

(in thousands)	Minimum Lease Payments
remainder of 2016	$	1,239
2017	4,445
2018	1,926
2019	824
	$	8,434

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Rental expense under operating leases was $1.8 million and $2.3 million for the three months ended September 30, 2016 and 2015, respectively, and $5.8 million and $6.7 million for the nine months ended September 30, 2016 and 2015, respectively. These expenses are included within operating expense - third party on our consolidated statements of operations.

NOTE 14—SEGMENT INFORMATION

Operating segments are revenue-producing components of an enterprise 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 its reportable segments - the Anchor Systems, Growth Systems and Additional Systems, each of which does business entirely within the United States. See Note 1 - Description of Business and Initial Public Offering for details.

Segment results for the periods presented are as follows:

	Three Months Ended   September 30,				Nine Months Ended September 30,
(in thousands)	2016		2015		2016			2015
Gathering Revenue - Related Party:
Anchor systems	$	50,005	$	40,327	$	149,150		$	110,211
Growth systems	2,587		3,467		8,186			10,355
Additional systems	8,137		9,959		24,048			24,072
Total Gathering Revenue - Related Party	$	60,729	$	53,753	$	181,384		$	144,638
Net Income:
Anchor systems	$	31,159	$	25,680	$	95,328		$	63,992
Growth systems	1,112		1,586		(7,204		)	3,320
Additional systems	4,110		6,348		10,018			12,424
Total Net Income	$	36,381	$	33,614	$	98,142		$	79,736
Depreciation Expense:
Anchor systems	$	3,620	$	2,646	$	10,474		$	7,650
Growth systems	530		483		1,590			1,422
Additional systems	1,242		640		3,320			1,358
Total Depreciation Expense	$	5,392	$	3,769	$	15,384		$	10,430
Capital Expenditures for Segment Assets:
Anchor systems	$	4,868	$	48,098	$	27,109		$	117,151
Growth systems	465		2,548		693			21,518
Additional systems	1,409		44,135		12,664			94,281
Total Capital Expenditures	$	6,742	$	94,781	$	40,466		$	232,950

Segment assets were as follows:

(in thousands)	September 30, 2016		December 31, 2015
Segment Assets
Anchor systems	$	562,622	$	567,132
Growth systems	98,371		102,249
Additional systems	249,722		255,044
Total Segment Assets	$	910,715	$	924,425

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NOTE 15 — LONG-TERM INCENTIVE PLAN

Under the CONE Midstream Partners LP 2014 Long-Term Incentive Plan (our “LTIP”), the Partnership's 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 nine months ended September 30, 2016, the Partnership's general partner granted equity-based phantom units, which are provided for under our LTIP and are accounted for under Accounting Standards Codification ("ASC") 718 - Compensation - Stock Compensation. Awards granted to independent directors vest over a period of one year, and awards granted to certain of the Partnership's officers and employees of the general partner vest 33% per year over a period of three years. The current year phantom unit grant was expanded to more employees of the general partner than the prior year grant, which management believes will more fully align employees' interests with those of the Partnership.

	Number of Units	Weighted Average Grant Date Fair Value
Total awarded and unvested at December 31, 2015	32,070	$	19.98
Granted	150,456	9.62
Vested	(19,750)	19.83
Forfeited	(7,346)	11.78
Total awarded and unvested at September 30, 2016	155,430	$	10.36

The Partnership accounts for phantom units as equity awards and records compensation expense on a straight line basis over the vesting periods of the awards based on their grant date fair value. Compensation expense included in general and administrative expense - related party recognized by the Partnership was $0.2 million and $0.1 million for the three months ended September 30, 2016 and 2015 and $0.6 million and $0.3 million for the nine months ended September 30, 2016 and 2015, respectively. At September 30, 2016, the unrecognized compensation related to all outstanding awards was $1.1 million.

NOTE 16 — SUBSEQUENT EVENTS

On October 26, 2016, the Board of Directors of CONE Midstream GP LLC, the Partnership's general partner declared a cash distribution to the Partnership’s unitholders for the third quarter of 2016 of$0.263 per common and subordinated unit. The cash distribution will be paid on November 14, 2016 to unitholders of record at the close of business on November 4, 2016.

On October 31, 2016, our Sponsors jointly announced that they have entered into a definitive agreement to separate their Marcellus Shale 50-50 Joint Venture that was formed in 2011 for the exploration, development, and operation of primarily Marcellus Shale properties in Pennsylvania and West Virginia (the "Exchange Agreement"). Although the Exchange Agreement creates independent ownership interests in the Marcellus Formation acreage and production that the Partnership currently gathers, CONSOL and Noble Energy will continue to remain our Sponsors and retain their respective and limited partner ownership interests in the Partnership, as well as their interests in CONE Gathering, which owns our general partner and noncontrolling interests in the Anchor, Growth and Additional Systems. In addition, the Exchange Agreement does not change the total acreage dedicated to the Partnership by the Sponsors, the gathering rates we receive, or other fundamental terms for the services we provide to the Sponsors.

Completion of the Exchange Agreement is subject to a number of conditions, including expiration of the Hart Scott Rodino Antitrust Improvements Act waiting period and other customary conditions. The closing of the Exchange Agreement is not subject to a financing condition and is expected to close in the fourth quarter of 2016.

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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, 2015. 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. and Noble Energy, Inc. whom we refer to 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, 2014, the Partnership closed an initial public offering ("IPO") of common units representing limited partner interests. For each period since the IPO, we have generated all of our revenues under long-term, fixed-fee gathering agreements with each of our Sponsors that are intended to mitigate our direct commodity price exposure and enhance the stability of our cash flows. Our gathering agreements also include substantial acreage dedications in the Marcellus Shale.

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. Although we have less than a 100% economic interest in these three Systems, we consolidate them fully with our results. Accordingly, before adjusting for noncontrolling interests, all income statement line items reflect the results of all three Systems on a 100% basis. After adjusting for noncontrolling interests, net income attributable to general and limited partner ownership interests in the Partnership reflect less than 100% of the results of our Anchor Systems, Growth Systems and Additional Systems and represents only that portion of net income that is attributable to our unitholders.

Third Quarter 2016 Highlights

The Partnership continued its solid financial performance in the quarter ended September 30, 2016. Compared to the quarter ended September 30, 2015, results attributable to the general partner and limited partner ownership interests in the Partnership were as follows:

• Net income of $23.6 million as compared to $19.7 million

• Average daily throughput volumes of 840 billion Btu per day (BBtu/d) as compared to 642 BBtu/d

• Adjusted EBITDA of $26.8 million as compared to $21.9 million

• Net cash provided by operating activities ("operating cash flows") of $40.0 million as compared to $38.8 million

• Distributable cash flow of $23.3 million as compared to $19.5 million

In addition to demonstrating consistently solid financial results and reducing borrowings under the revolving credit facility since December 31, 2015, the Partnership generated $122.9 million in operating cash flows during the nine month period ended September 30, 2016, which exceeded the operating cash flows generated in the prior year nine month period by approximately $23.7 million. Current year operating cash flows also exceeded the sum of capital expenditures ($40.5 million), distributions to unitholders ($43.9 million) and interest paid ($1.1 million) during the nine month period ended September 30, 2016.

A discussion of why the above metrics are important to management, and how they reconcile to their nearest accounting principles generally accepted in the United States ("GAAP") measures, where appropriate, 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.

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Throughput Volumes

Since the IPO, the amount of revenue we have generated depends entirely on the volumes of natural gas and condensate that we gather for our Sponsors, which is 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 is determined by a number of factors, the most important of which are the prevailing and projected prices of natural gas and natural gas liquids ("NGLs"), the cost to drill and operate a well, the availability and cost of capital and environmental and government regulations. We generally expect the level of drilling to positively correlate with long-term trends in commodity prices. Similarly, production levels nationally and regionally generally tend to positively correlate with drilling activity.

In order to meet our contractual obligations under the gathering agreements with our Sponsors related to new wells drilled on our dedicated acreage, we are required to incur capital expenditures to extend our gathering systems and facilities to the new wells they drill. Our Sponsors will be responsible for their proportionate share of the total capital expenditures associated with the ongoing build-out of our midstream systems representing their 25%, 95% and 95% noncontrolling ownership interests in the Anchor, Growth and Additional Systems, respectively.

We have secured significant acreage dedications from our Sponsors, which have dedicated to us approximately 515,000 net acres of their jointly owned Marcellus Shale acreage for an initial term of 20 years. In addition to our existing dedicated acreage, our gathering agreements provide that any additional acreage covering the Marcellus Shale that is jointly acquired by our Sponsors in a “dedication area” covering over 7,700 square miles in West Virginia and Pennsylvania will be automatically dedicated to us. We also have the right of first offer (“ROFO”) to provide midstream services to our Sponsors on our ROFO acreage, which currently includes approximately 186,000 net acres of our Sponsors’ jointly owned Marcellus Shale acreage and any additional acreage covering the Marcellus Shale that is jointly acquired by our Sponsors in a “ROFO area” covering over 18,300 square miles in West Virginia and Pennsylvania.

Because the production rate of a natural gas well declines over time, we must continually obtain new supplies of natural gas and condensate to maintain or increase the throughput volumes on our midstream systems. Our ability to maintain or increase existing throughput volumes and obtain new supplies of natural gas and condensate are impacted by:

• successful drilling activity by our Sponsors on our dedicated acreage and our ability to fund the capital costs required to connect our gathering systems to new wells;

• our ability to utilize the remaining uncommitted capacity on, or add additional capacity to, our gathering systems;

• the level of work-overs and re-completions of wells on existing pad sites to which our gathering systems are connected;

• our ability to increase throughput volumes on our gathering systems by making outlet connections to existing or new third-party pipelines or other facilities, primarily driven by the anticipated supply of and demand for natural gas;

• the number of new pad sites on our dedicated acreage awaiting lateral connections;

• our ability to identify and execute organic expansion projects to capture incremental volumes from our Sponsors and third parties;

• our ability to compete for volumes from successful new wells in the areas in which we operate outside of our dedicated acreage; and

• our ability to gather natural gas and condensate that has been released from commitments with our competitors.

We actively monitor the activities of producers in the areas served by our gathering systems to pursue new supply opportunities.

EBITDA, Adjusted EBITDA & Distributable Cash Flow

EBITDA, Adjusted EBITDA and distributable cash flow are non-GAAP measures that we believe provide information that is useful to investors in assessing our financial condition and results of operations. For a discussion on how we define EBITDA, 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-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.

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Factors Impacting Our Business

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

Our Sponsors’ Drilling and Development Plan

Our operations are primarily dependent upon our Sponsors’ natural gas production on our dedicated acreage in the Marcellus Shale. Our Sponsors have established a drilling and development program on their upstream acreage, including on our dedicated acreage, and primarily rely on us to deliver the midstream infrastructure necessary to accommodate their continuing production growth in the Marcellus Shale and Utica Shale. Although we anticipate our Sponsors’ continued exploration and production activities in our areas of operation in the Marcellus Shale and Utica Shale over the long term, we have no control over the level or timing of their activity. Furthermore, the Joint Development Agreement ("JDA") with our Sponsors contains certain mechanisms that may cause their production on our dedicated acreage to be less than we anticipate. For example, our Sponsors mutually agreed to a 2016 drilling level of activity that is significantly below the drilling activity per the default plan described in the JDA. Furthermore, our Sponsors were not operating any drilling rigs on our dedicated acreage as of September 30, 2016 or December 31, 2015.

Fluctuations in natural gas and NGL 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. Throughout 2015 and into 2016, 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 our Sponsors delay drilling or temporarily shut in production due to persistently low commodity prices or for any other reason, we are not assured a certain amount of revenue as our 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, which would negatively affect throughput on our gathering systems.

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Results of Operations

Three Months Ended September 30, 2016 Compared to the Three Months Ended September 30, 2015

	Three Months Ended September 30,
	2016		2015		Variance			Percent Change
	($ in thousands)
Revenue
Gathering revenue — related party	$	60,729	$	53,753	$	6,976		13.0	%
Total Revenue	60,729		53,753		6,976			13.0	%
Expenses
Operating expense — third party	7,769		4,736		3,033			64.0	%
Operating expense — related party	7,209		8,095		(886		)	(10.9	)%
General and administrative expense — third party	1,049		968		81			8.4	%
General and administrative expense — related party	2,624		2,413		211			8.7	%
Depreciation expense	5,392		3,769		1,623			43.1	%
Interest expense	305		158		147			93.0	%
Total Expense	24,348		20,139		4,209			20.9	%
Net Income	$	36,381	$	33,614	$	2,767		8.2	%
Less: Net income attributable to noncontrolling interest	12,750		13,957		(1,207		)	(8.6	)%
Net Income Attributable to General and Limited Partner Ownership Interest in CONE Midstream Partners LP	$	23,631	$	19,657	$	3,974		20.2	%

Operating Statistics - Gathered Volumes for the Three Months Ended September 30, 2016

	Anchor	Growth	Additional	TOTAL	NET TOTAL (a)
Dry Gas (BBtu/d) (b)	767	61	14	842	579
Wet Gas (BBtu/d) (b)	331	5	177	513	258
Condensate (MMcfe/d)	4	—	5	9	3
Total Gathered Volumes	1,102	66	196	1,364	840

Operating Statistics - Gathered Volumes for the Three Months Ended September 30, 2015

	Anchor	Growth	Additional	TOTAL	NET TOTAL (a)
Dry Gas (BBtu/d) (b)	480	82	6	568	364
Wet Gas (BBtu/d) (b)	348	10	207	565	272
Condensate (MMcfe/d)	7	—	16	23	6
Total Gathered Volumes	835	92	229	1,156	642

(a)Represents throughput volumes net of the noncontrolling interests owned by the Sponsors.

(b) Classification as dry or wet is based upon the shipping destination of the volumes during each period presented. 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, some volumes classified as "wet" in the 2015 period were classified as "dry" in 2016.

Revenue    

Because our Sponsors have established a drilling and development program on our dedicated acreage, 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, revenue can also be impacted by our Sponsors' choices, in certain parts of our gathering systems, of where to send their production, which may change dynamically depending on the most current commodity prices at the time of shipment.

Gathering revenue — related party was approximately $60.7 million for the three months ended September 30, 2016 compared to approximately $53.8 million for the three months ended September 30, 2015. The increase was primarily due to a

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274 BBtu/d increase in dry natural gas gathered when compared to the prior year quarter, which was partially offset by a 66 BBtu/d throughput reduction in wet gas and condensate volumes. Partially contributing to the increase in dry volumes and the decrease in wet volumes was the Sponsors' change in shipping destinations. In response to the relatively lower NGL prices during the 2016 period, a portion of the gathered volumes that were handled as wet gas in the prior year were shipped to dry gas destinations in the current year period, which contributed to the quarter over quarter volume changes.

From a segment perspective, the dry gas increase during the quarter was primarily related to a 287 BBtu/d increase at our Anchor System, which was partially offset by a 13 BBtu/d decrease related to the Growth and Additional Systems. The wet gas and condensate decrease was primarily driven by a decrease of 41 BBtu/d of throughput in the Additional Systems.

Operating Expense

Total operating expenses increased to approximately $15.0 million from approximately $12.8 million in the prior year quarter. This increase of 16.7% was slightly less than the volume increase quarter over quarter of 18.0%. As such, the increase in operating expenses compared to the prior year quarter was generally consistent with the increase in throughput.

Included in operating expense was electrically-powered compression expense of $4.4 million and $4.3 million in the three months ended September 30, 2016 and 2015, respectively, which were reimbursed by the Sponsors pursuant to their respective Gathering Agreements.

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 $3.7 million for the three months ended September 30, 2016 compared to approximately $3.4 million for the three months ended September 30, 2015. On a percentage basis, this increase is generally in line with the increases in revenues and volumes compared to the prior year quarter.

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 $5.4 million for the three months ended September 30, 2016 compared to approximately $3.8 million for the three months ended September 30, 2015. The increase of $1.6 million was primarily related to our capital spending since the IPO and resulting assets placed into service.

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Nine Months Ended September 30, 2016 Compared to the Nine Months Ended September 30, 2015

	Nine Months Ended September 30,
	2016		2015		Variance			Percent Change
	($ in thousands)
Revenue
Gathering revenue — related party	$	181,384	$	144,638	$	36,746		25.4	%
Total Revenue	181,384		144,638		36,746			25.4	%
Expenses
Operating expense — third party	24,322		22,205		2,117			9.5	%
Operating expense — related party	22,631		22,079		552			2.5	%
General and administrative expense — third party	3,196		3,533		(337		)	(9.5	)%
General and administrative expense — related party	6,521		6,385		136			2.1	%
Pipe revaluation	10,083		—		10,083			n/m
Depreciation expense	15,384		10,430		4,954			47.5	%
Interest expense	1,105		270		835			309.3	%
Total Expense	83,242		64,902		18,340			28.3	%
Net Income	$	98,142	$	79,736	$	18,406		23.1	%
Less: Net income attributable to noncontrolling interest	26,505		30,954		(4,449		)	(14.4	)%
Net Income Attributable to General and Limited Partner Ownership Interest in CONE Midstream Partners LP	$	71,637	$	48,782	$	22,855		46.9	%

Operating Statistics - Gathered Volumes for the Nine Months Ended September 30, 2016

	Anchor	Growth	Additional	TOTAL	NET TOTAL (a)
Dry Gas (BBtu/d) (b)	731	64	18	813	552
Wet Gas (BBtu/d) (b)	378	6	162	546	292
Condensate (MMcfe/d)	5	—	6	11	4
Total Gathered Volumes	1,114	70	186	1,370	848

Operating Statistics - Gathered Volumes for the Nine Months Ended September 30, 2015

	Anchor	Growth	Additional	TOTAL	NET TOTAL (a)
Dry Gas (BBtu/d) (b)	419	84	9	512	319
Wet Gas (BBtu/d) (b)	336	8	160	504	260
Condensate (MMcfe/d)	9	—	11	20	7
Total Gathered Volumes	764	92	180	1,036	586

(a)Represents throughput volumes net of the noncontrolling interests owned by the Sponsors.

(b) Classification as dry or wet is based upon the shipping destination of the volumes during each period presented. Because our Sponsors have the option to ship a portion of its natural gas to destinations associated with either our wet system or our dry system, due to any number of factors, some volumes classified as "wet" in the 2015 period were classified as "dry" in 2016.

Revenue    

Because our Sponsors have established a drilling and development program on our dedicated acreage, 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, revenue can also be impacted by our Sponsors' choice in certain parts of our gathering system of where to send its production, which may change dynamically depending on the most current commodity prices at the time of shipment.

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Gathering revenue — related party was approximately $181.4 million for the nine months ended September 30, 2016 compared to approximately $144.6 million for the nine months ended September 30, 2015. The approximate $36.7 million increase was primarily due to a 301 BBtu/d increase in natural gas gathered in our Sponsors’ dry gas production area and a 33 BBtu/d increase in natural gas volumes in our Sponsors’ wet gas and condensate production areas.

From a segment perspective, the dry gas increase was primarily due to a 312 BBtu/d increase at our Anchor System, which was partially offset by a net 11 BBtu/d production decrease related to the Growth and Additional Systems. The wet gas and condensate increase was primarily the result of increased production of 38 BBtu/d within our Anchor Systems, which was partially offset by a five BBtu/d decrease in production in our Growth and Additional Systems.

Operating Expense

Total operating expense was approximately $47.0 million for the nine months ended September 30, 2016 compared to $44.3 million for the nine months ended September 30, 2015. The modest increase in operating expenses relative to substantial throughput growth was primarily the result of cost control measures implemented by the operations group as they continue to refine their processes and improve facility efficiencies.

Electrically-powered compression expense was $12.6 million and $11.4 million for the nine months ended September 30, 2016 and 2015, respectively, which was reimbursed by the Sponsors pursuant to their respective Gathering Agreements.

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 $9.7 million for the nine months ended September 30, 2016 compared to approximately $9.9 million for the nine months ended September 30, 2015.

Pipe Revaluation

In June 2016, management agreed to sell a portion of existing excess pipe supply that was not dedicated to specific capital projects to an unrelated third party for an amount that was below its carrying cost. Accordingly, we reduced the carrying value of excess pipe to the value that was commensurate with the price agreed to with the third party. The result was a negative impact to consolidated net income of $10.1 million during the nine month period ended September 30, 2016; however, since the value loss was entirely within the Growth System, the net impact to earnings attributable to general and limited partners' ownership interests in the Partnership was $0.5 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 $15.4 million for the nine months ended September 30, 2016 compared to approximately $10.4 million for the nine months ended September 30, 2015. The increase of $5.0 million was primarily related to our capital spending since the IPO and resulting assets placed into service.

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Non-GAAP Financial Measures

EBITDA and Adjusted EBITDA

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

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

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

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

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

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

Distributable Cash Flow

We define distributable cash flow as Adjusted EBITDA less net income attributable to noncontrolling interest, net cash interest paid and maintenance capital expenditures. 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 EBITDA, Adjusted EBITDA and distributable cash flow to the most directly comparable GAAP financial measures of net income and net cash provided by operating activities.

	Three Months Ended   September 30,					Nine Months Ended   September 30,
(in thousands)	2016		2015			2016			2015
Net Income	$	36,381	$	33,614		$	98,142		$	79,736
Depreciation expense	5,392		3,769			15,384			10,430
Interest expense	305		158			1,105			270
EBITDA	42,078		37,541			114,631			90,436
Non-cash unit-based compensation expense	222		118			577			310
Pipe revaluation	—		—			10,083			—
Adjusted EBITDA	42,300		37,659			125,291			90,746
Less:
Net income attributable to noncontrolling interest	12,750		13,957			26,505			30,954
Depreciation expense attributable to noncontrolling interest	2,589		1,728			7,283			4,553
Other expenses attributable to noncontrolling interest	205		63			521			97
Pipe revaluation attributable to noncontrolling interest	—		—			9,579			—
Adjusted EBITDA attributable to General and Limited Partner ownership interest in CONE Midstream Partners LP	$	26,756	$	21,911		$	81,403		$	55,142
Less: cash interest paid, net	198		95			682			173
Less: ongoing maintenance capital expenditures, net of expected reimbursements	3,283		2,291			9,234			6,430
Distributable Cash Flow	$	23,275	$	19,525		$	71,487		$	48,539
Net Cash Provided by Operating Activities	$	39,981	$	38,808		$	122,938		$	99,268
Interest expense	305		158			1,105			270
Pipe revaluation	—		—			10,083			—
Other, including changes in working capital	2,014		(1,307		)	(8,835		)	(8,792		)
Adjusted EBITDA	42,300		37,659			125,291			90,746
Less:
Net income attributable to noncontrolling interest	12,750		13,957			26,505			30,954
Depreciation expense attributable to noncontrolling interest	2,589		1,728			7,283			4,553
Other expenses attributable to noncontrolling interest	205		63			521			97
Pipe revaluation attributable to noncontrolling interest	—		—			9,579			—
Adjusted EBITDA attributable to General and Limited Partner ownership interest in CONE Midstream Partners LP	$	26,756	$	21,911		$	81,403		$	55,142
Less: cash interest paid, net	198		95			682			173
Less: ongoing maintenance capital expenditures, net of expected reimbursements	3,283		2,291			9,234			6,430
Distributable Cash Flow	$	23,275	$	19,525		$	71,487		$	48,539

Distributable cash flow increased by $3.7 million and $22.9 million for the three months and nine months ended September 30, 2016 compared to the three and nine months ended September 30, 2015, which was mainly attributable to the increase in adjusted EBITDA in each of the current year periods compared to the prior year periods. Changes in net cash provided by operating activities are discussed in the “Capital Resources and Liquidity" section below.

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Liquidity and Capital Resources

Liquidity and Financing Arrangements

Our principal liquidity requirements are to finance our operations, fund capital expenditures and acquisitions, make cash distributions and satisfy any indebtedness obligations. Our ability to meet these liquidity requirements will depend on our ability to generate cash in the future.

Historically, our principal sources of liquidity have been cash from operations and funding from our Sponsors. While they have historically provided funding to us, we do not have a formal commitment from our Sponsors, CONE Gathering, our general partner or any of their respective affiliates to fund our cash flow deficits or provide other direct or indirect financial assistance to us. We expect our ongoing sources of liquidity will include cash generated from operations, borrowings under our revolving credit facility and, if necessary, the issuance of additional equity or debt securities. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to make quarterly cash distributions.

Our partnership agreement requires that we distribute all of our available cash to our unitholders. As a result, we expect to rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures.

At a minimum, we intend to pay the minimum quarterly distribution of $0.2125 per unit per quarter, which equates to an aggregate distribution of approximately $12.7 million per quarter, or approximately $50.6 million per year, based on the general partner interest and the number of common and subordinated units outstanding as of September 30, 2016. 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.

Revolving Credit Facility

At the closing of the IPO on September 30, 2014, we entered into 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 September 30, 2016, we had an outstanding balance on our credit facility of $41.0 million.

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

• 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.

We incurred $1.1 million of interest expense during the nine months ended September 30, 2016. 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.

Our revolving credit facility contains covenants and conditions that, among other things, limit 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, 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. We define this as our consolidated leverage ratio which is calculated as total funded outstanding on our credit facility divided by EBITDA Attributable to General and Limited Partner Ownership Interest in the Partnership. The consolidated leverage ratio was 0.4 to 1.0 for the twelve months ended September 30, 2016.

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• 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. We define this as our consolidated interest coverage ratio which is calculated as EBITDA Attributable to General and Limited Partner Ownership Interest in the Partnership divided by total interest charges. The interest coverage ratio was 116.4 to 1.0 for the twelve months ended September 30, 2016.

Based on these ratios, the Partnership had the maximum amount of revolving credit available for borrowing at September 30, 2016, or $209.0 million.

Cash Flows

Net cash provided by operating activities, investing activities and financing activities for the nine months ended September 30, 2016 and 2015 were as follows:

	Nine Months Ended September 30,
(in thousands)	2016			2015
Net cash provided by operating activities:	$	122,938		$	99,268
Net cash used in investing activities:	$	(40,229	)	$	(232,950	)
Net cash (used in) provided by financing activities:	$	(78,730	)	$	131,635

Net cash provided by operating activities increased approximately $23.7 million during the nine months ended September 30, 2016 compared to the nine months ended September 30, 2015, which was primarily due to an improvement in the Partnership's consolidated year over year adjusted EBITDA of $34.5 million. The cash flow increase was partially offset by working capital adjustments and the timing of when liabilities were paid between periods.

Net cash used in investing activities decreased $192.7 million in the current period due primarily to a reduction in capital expenditures, as a result of lower commodity prices and their impact on our Sponsors' drilling plans. Our Sponsors had mutually agreed to a 2016 level of activity that is significantly below that which is described in the default plan under their joint development agreement, and which is below the amount spent in 2015.

There was a net use of cash in financing activities in the current period compared to net cash provided by financing activities in the prior year period, primarily due to reduced contributions from our Sponsors and increased repayments on our revolver. Much lower capital spending in all of our Systems in the current year reduced the need for Sponsor contributions, particularly in the Growth and Additional Systems in which the Sponsors own 95% noncontrolling interests.

Capital Expenditures

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

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

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

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Capital Expenditures for the Nine Months Ended September 30, 2016

	Anchor		Growth		Additional		TOTAL
Capital Investment
Maintenance capital	$	12,098	$	693	$	2,522	$	15,313
Expansion capital	15,011		—		10,142		25,153
Total Capital Investment	$	27,109	$	693	$	12,664	$	40,466
Capital Investment Net to the Partnership
Maintenance capital	$	9,073	$	35	$	126	$	9,234
Expansion capital	11,258		—		507		11,765
Total Capital Investment Net to the Partnership	$	20,331	$	35	$	633	$	20,999

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 future expansion capital expenditures will be funded by borrowings under our revolving credit facility and the issuance of debt and equity securities.

Off-Balance Sheet Arrangements

We do not maintain 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.

Critical Accounting Policies

The Partnership’s critical accounting policies are described in the notes to the consolidated financial statements for the year ended December 31, 2015 contained in the Partnership’s Annual Report on Form 10-K.  Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in the notes to the Partnership’s consolidated financial statements included in this Quarterly Report on Form 10-Q for the period ended September 30, 2016.  The application of the Partnership’s critical accounting policies may require management to make judgments and estimates about the amounts recorded in the consolidated financial statements.  Management uses historical experience and all available information to make these estimates and judgments.  Different amounts could be reported using different assumptions and estimates.

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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” and other expressions that are predictions of or indicate future events and trends and that do not relate to historical matters identify forward-looking statements. Our forward-looking statements include statements about our business strategy, our industry, our future profitability, our expected capital expenditures and the impact of such expenditures on our performance, the costs of being a publicly traded partnership and our capital programs.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. You are cautioned not to place undue reliance on any forward-looking statements. 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 our Sponsors’ drilling and development plan on our dedicated acreage and the volumes of natural gas and condensate that are produced on our dedicated acreage;

• changes in our Sponsors’ drilling and development plan in jointly-owned Marcellus Shale;

• our Sponsors’ ability to meet their drilling and development plan in jointly-owned Marcellus Shale;

• the demand for natural gas and condensate gathering services;

• changes in general economic conditions;

• competitive conditions in our industry;

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

• our ability to successfully implement our business plan;

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

• the price and availability of debt and equity financing;

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

• competition from the same and alternative energy sources;

• energy efficiency and technology trends;

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

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

• interest rates;

• labor relations;

• defaults by our 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, 2015, which may cause our actual results, performance or achievements to differ materially from anticipated future results, performance or achievements expressed or implied by such forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changed circumstances or otherwise, unless required by law.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

We currently generate all of our revenues pursuant to fee-based gathering agreements under which 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 have little direct exposure to commodity price risk. However, we are indirectly exposed to commodity price risks if our Sponsors 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 such terms may not be successful.

We may acquire or develop additional midstream assets in a manner that increases our exposure to commodity price risk. Future 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

In connection with the closing of our IPO on September 30, 2014, we entered into a $250.0 million revolving credit facility. Assuming our current outstanding balance on the revolving credit facility of $41.0 million, an increase of one percentage point in the interest rates would result in an annual interest expense increase of $0.4 million. As a result, our results of operations, cash flows and financial condition and, consequently, 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 third quarter of 2016 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. 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, 2015.  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 may incur significant costs and liabilities as a result of pipeline and related facility integrity management program testing and any related pipeline repair or preventative or remedial measures.

On April 8, 2016, the U.S. Department of Transportation ("DOT") Pipeline and Hazardous Materials Safety Administration ("PHMSA") published in the Federal Register a Notice of Proposed Rule Making ("NPRM") that would significantly modify existing regulations related to reporting, impact, design, construction, maintenance, operations and integrity management of gas transmission and gathering pipelines. The proposed rule addresses four congressional mandates and six recommendations by the National Transportation Safety Board to broaden the scope of safety coverage by adding new assessment and repair criteria for gas transmission pipelines, and by expanding these protocols to include pipelines not formerly regulated by the federal standards. This includes extending regulatory requirements to transmission and gathering pipelines of eight inches and greater in rural Class I areas. Compliance with the rule, as proposed, may prove challenging and costly for operators of older pipelines due to the difficulty of locating historic records. As proposed, compliance with the rule could have a material adverse effect on the Partnership's operations. However, the ultimate impact of the rule on the Partnership remains uncertain until the rulemaking is finalized.

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: November 4, 2016

CONE MIDSTREAM PARTNERS LP
By:	/S/ JOHN T. LEWIS
	John T. Lewis
	Chairman of the Board and Chief Executive Officer (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)

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