CNNX 06.30.2015 10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________________________________

FORM 10-Q

__________________________________________________

(Mark One)



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

For the quarterly period ended June 30, 2015



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. (The registrant became subject to such requirements on September 24, 2014, and it has filed all reports so required since that date.)

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 o Non-accelerated filer x 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

CONE Midstream Partners LP had 29,163,121common units, 29,163,121 subordinated units and a 2% general partner interest outstanding at August 5, 2015.

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		Page
PART I FINANCIAL INFORMATION

ITEM 1.	Consolidated Financial Statements
	Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2015 and 2014	3
	Consolidated Balance Sheets at June 30, 2015 and December 31, 2014	4
	Consolidated Statement of Partners' Capital for the Six Months Ended June 30, 2015	5
	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2015 and 2014	6
	Notes to Consolidated Unaudited Financial Statements	7

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	32

ITEM 4.	Controls and Procedures	32

PART II OTHER INFORMATION

ITEM 1.	Legal Proceedings	33

ITEM 1A.	Risk Factors	33

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

ITEM 3.	Defaults upon Senior Securities	34

ITEM 4.	Mine Safety Disclosures	34

ITEM 5.	Other Information	34

ITEM 6.	Exhibits	35

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PART I: FINANCIAL INFORMATION


ITEM 1.	CONSOLIDATED FINANCIAL STATEMENTS

CONE MIDSTREAM PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(unaudited)



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Revenue
Gathering Revenue — Related Party	$	47,717	$	27,811	$	90,885	$	51,917
Total Revenue	47,717		27,811		90,885		51,917
Expenses
Operating Expense — Third Party	8,940		6,082		17,470		11,428
Operating Expense — Related Party	6,940		5,893		13,984		12,523
General and Administrative Expense — Third Party	1,223		8		2,565		829
General and Administrative Expense — Related Party	1,995		1,117		3,972		1,358
Depreciation Expense	3,667		1,679		6,661		3,297
Interest Expense	47		—		112		—
Total Expense	22,812		14,779		44,764		29,435
Net Income	24,905		13,032		46,121		22,482
Less: Net Income Attributable to Noncontrolling Interest	9,993		—		16,997		—
Net Income Attributable to General and Limited Partner Ownership Interest in CONE Midstream Partners LP	$	14,912	$	13,032	$	29,124	$	22,482

Calculation of Limited Partner Interest in Net Income:
Net Income Attributable to General and Limited Partner Ownership Interest in CONE Midstream Partners LP ⁽¹⁾	$	14,912	$	13,032	$	29,124	$	22,482
Less: General Partner Interest in Net Income	298		N/A		582		N/A
Limited Partner Interest in Net Income	$	14,614	N/A		$	28,542	N/A

Net Income per Limited Partner Unit - Basic	$	0.25	N/A		$	0.49	N/A
Net Income per Limited Partner Unit - Diluted	$	0.25	N/A		$	0.49	N/A

Limited Partner Units Outstanding - Basic	58,326		N/A		58,326		N/A
Limited Partner Unit Outstanding - Diluted	58,364		N/A		58,365		N/A

Cash Distributions Declared per Unit ⁽²⁾	$	0.2200	N/A		$	0.4325	N/A


(1)	Reflective of general and limited partner interest in net income since closing of the IPO. See Note 1 - Description of Business, Initial Public Offering and Basis of Presentation


(2)	Represents the cash distributions declared related to the period presented. See Note 15.

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)
	June 30, 2015			December 31, 2014
ASSETS
Current Assets:
Cash	$	161		$	3,252
Receivables — Related Party (Note 6)	26,998			58,749
Inventory	16,632			—
Prepaid Expenses	757			1,280
Other Current Assets	164			164
Total Current Assets	44,712			63,445
Property and Equipment:
Property and Equipment (Note 7)	756,489			639,735
Less — Accumulated Depreciation	23,448			16,989
Property and Equipment — Net	733,041			622,746
Other Non-Current Assets	531			613
TOTAL ASSETS	$	778,284		$	686,804
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	63,955		$	70,635
Accounts Payable — Related Party (Note 8)	2,230			2,106
Total Current Liabilities	66,185			72,741
Other Liabilities:
Revolving Credit Facility (Note 13)	23,000			31,300
Total Liabilities	89,185			104,041
Partners' Capital:
Common Units (29,163,121 Units Issued and Outstanding at June 30, 2015 and December 31, 2014)	391,614			389,612
Subordinated Units (29,163,121 Units Issued and Outstanding at June 30, 2015 and December 31, 2014)	(90,475		)	(92,285		)
General Partner Interest	(3,699		)	(3,772		)
Partners' Capital Attributable to CONE Midstream Partners LP	297,440			293,555
Noncontrolling Interest	391,659			289,208
Total Partners' Capital	689,099			582,763
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$	778,284		$	686,804

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

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CONE MIDSTREAM PARTNERS LP

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

(in thousands)

(unaudited)



	Partners' Capital
	Limited Partners						General			Noncontrolling
	Common			Subordinated			Partner			Interest		Total
Balance at December 31, 2014	$	389,612		$	(92,285	)	$	(3,772	)	$	289,208	$	582,763
Net Income	14,271			14,271			582			16,997		46,121
Investment by Partners and Noncontrolling Interest Holders ⁽¹⁾	—			—			—			85,454		85,454
Distributions to Unitholders	(12,461		)	(12,461		)	(509		)	—		(25,431		)
Unit Based Compensation	192			—			—			—		192
Balance at June 30, 2015	$	391,614		$	(90,475	)	$	(3,699	)	$	391,659	$	689,099

^{(1) Investment includes an outstanding cash call as of}^{June 30, 2015}^{. See Note 6 - Receivables - Related Party.}

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

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CONE MIDSTREAM PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)



	Six Months Ended June 30,
	2015			2014
Cash Flows from Operating Activities:
Net Income	$	46,121		$	22,482
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities:
Depreciation and Amortization	6,743			3,297
Unit Based Compensation	192			—
Changes in Operating Assets:
Receivables — Related Party	9,792			5,162
Inventory	(16,632		)	—
Prepaid Expenses	522			—
Changes in Operating Liabilities:
Accounts Payable	13,307			9,281
Accounts Payable — Related Party	415			(1,590		)
Net Cash Provided by Operating Activities	60,460			38,632
Cash Flows from Investing Activities:
Capital Expenditures	(138,169		)	(118,240		)
Net Cash Used in Investing Activities	(138,169		)	(118,240		)
Cash Flows from Financing Activities:
Partners' Investments	108,349			83,000
Distributions to Unitholders	(25,431		)	—
Payment of Revolver	(8,300		)	—
Net Cash Provided By Financing Activities	74,618			83,000
Net (Decrease) Increase in Cash	(3,091		)	3,392
Cash at Beginning of Period	3,252			5,976
Cash at End of Period	$	161		$	9,368

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

(Dollars in thousands)

NOTE 1—DESCRIPTION OF BUSINESS, INITIAL PUBLIC OFFERING AND BASIS OF PRESENTATION

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.

In order to effectively manage our business we have divided our current midstream assets among three separate categories that we refer to as our “Anchor Systems,” “Growth Systems” and “Additional Systems” based on their relative current cash flows, growth profiles, capital expenditure requirements and the timing of their development.


•	Our Anchor Systems include our midstream systems that generate the substantial majority of our current cash flows and that we expect to drive our growth over the near term as we increase average throughput on these systems from our Sponsors’ growing production.


•	Our Growth Systems include our high-growth, developing gathering systems that will require substantial expansion capital expenditures over the next several years, the substantial majority of which will be funded by our Sponsors in proportion to their retained ownership interest.


•	Our Additional Systems include several gathering systems primarily located in the wet gas regions of our Sponsors' dedicated acreage that we expect will generate stable cash flows and require lower levels of expansion capital investment over the next several years.

On September 30, 2014, the Partnership closed its initial public offering ("IPO") of common units representing limited partner interests. The Partnership's general partner is CONE Midstream GP LLC (the "general partner"), a wholly owned subsidiary of CONE Gathering LLC (“CONE Gathering”). CONE Gathering, a Delaware limited liability company, is a joint venture formed by our Sponsors in September 2011 and represents the predecessor for accounting purposes (the “Predecessor”) of CONE Midstream Partners LP. References in these consolidated financial statements to “our partnership,” “we,” “our,” “us” or like terms, when used for periods prior to the IPO, refer to CONE Gathering. References in these consolidated financial statements to “our partnership,” “we,” “our,” “us” or like terms, when used for periods beginning at or following the IPO, refer collectively to the Partnership and its consolidated subsidiaries. For periods prior to the IPO, the accompanying consolidated financial statements and related notes include the assets, liabilities and results of operations of CONE Gathering.

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 IPO of 20,125,000 common units at a price to the public of $22.00 per unit, which included 2,625,000 common units issued pursuant to the underwriters' exercise in full of their 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 ("IDRs"); and


•	an aggregate cash distribution of $407,971.

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Basis of Presentation:

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

The balance sheet at December 31, 2014 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.

NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES

A summary of the significant accounting policies is included below. These, together with the other notes to the Financial Statements, are an integral part of the Financial Statements.

Under the Jumpstart Our Business Startups Act ("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 will remain an emerging growth company for up to five years from the date of our initial public offering, although we will lose that status sooner if:


•	we have more than one billion dollars 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 one billion dollars 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.

Principles of Consolidation:

The consolidated financial statements include the accounts of CONE Midstream Partners LP and all of its controlled subsidiaries. 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.

Use of Estimates:

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and various disclosures. Actual results could differ from those estimates.

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.

Accounts Receivable:

Accounts receivable are recorded at the invoiced amount and do not bear interest. We reserve for specific accounts receivable when it is probable that all or a part of an outstanding balance will not be collected, such as customer bankruptcies. 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

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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 in the periods presented.

Inventory:

Inventory is stated at the lower of cost or market and consists of pipe purchased for a pipeline project that has been delayed. The cost is determined primarily under the specific identification method. The Partnership expects the pipe will be used in an alternative project or sold to a third party.

Property and Equipment:

Property and equipment is recorded at cost upon acquisition. Expenditures which extend the useful lives of existing property and equipment are capitalized.

Depreciation of property and equipment is calculated on the straight-line method over their estimated useful lives or lease terms.

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 gain or loss. There were no retirements or disposals during the periods presented.

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, such that the asset’s carrying amount is adjusted to its estimated fair value with an offsetting charge to operating expense.

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.

Variable Interest Entities:

The Anchor, Growth and Additional Limited Partnerships (the Limited Partnerships), which are variable interest entities, are consolidated by CONE Midstream Partners LP through its ownership of CONE Midstream Operating Company LLC. CONE Midstream Operating Company LLC, through its general partner ownership interest in each of the Anchor, Growth and Additional Limited Partnerships, has the power to direct all substantive strategic and day-to-day operational decisions of the Limited Partnerships. CONE Midstream Operating Company LLC is considered to be the primary beneficiary for accounting purposes.

Environmental Matters:

We are subject to various federal, state and local laws and regulations relating to the protection of the environment. We have established procedures for the ongoing evaluation of our operations, to identify potential environmental exposures and to comply with regulatory policies and procedures, including legislation related to greenhouse gas emissions. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. At this time, we are unable to assess the timing and/or effect of potential liabilities related to greenhouse gas emissions or other environmental issues. As of June 30, 2015, we had no material environmental matters that required specific disclosure or requiring the recognition of a liability.

Asset Retirement Obligation:

We perform an ongoing analysis of asset removal and site restoration costs that we may be required to perform under law or contract once an asset has been permanently taken out of service. We have property and equipment at locations that we own and at sites leased or under right of way agreements. We are under no contractual obligation to remove the assets at locations we own. In evaluating our asset retirement obligation, we review lease agreements, right of way agreements, easements and permits to determine which agreements, if any, require an asset removal and restoration obligation. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including expected settlement dates, future

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retirement costs, future inflation rates and the credit-adjusted-risk-free interest rates. We operate and maintain our midstream systems and intend to do so as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we believe that we cannot reasonably estimate the asset retirement obligations for our midstream system assets as these assets have indeterminate lives.

Income Taxes:

Our operations as a limited partnership, and our Predecessor, as a limited liability company, are treated as partnerships for federal and state income tax purposes, with each partner being separately taxed on its share of the taxable income. Accordingly, no provision for federal or state income taxes has been recorded in the consolidated financial statements.

Net Income per Limited Partners Unit:

We allocate our net income among our general partner and limited partners using the two-class method in accordance with applicable authoritative accounting guidance. Under the two-class method, we allocate our 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 reflected by applying the treasury stock method. Potentially dilutive securities included in the calculation of diluted net income per limited partner unit totaled 33,697 phantom units for the three and six months ended June 30, 2015.

Our partnership agreement requires that, within 45 days after the end of each quarter, the Partnership distribute all of its available cash (described below) to unitholders of record on the applicable record date.

Cash Distributions:

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

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

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.

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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%

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 amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that, during the subordination period, there will be available cash to be distributed on the common units. The subordination period will end, and the subordinated units will convert to common units, on a one-for-one basis, when certain distribution requirements, as defined in the partnership agreement, have been met. The earliest date at which the subordination period may end is September 30, 2015.

Incentive Distribution Rights:

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.

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Reclassifications

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

Recent Accounting Pronouncements

In April 2015, the FASB issued ASU 2015-06 “Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions”. ASU 2015-06 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. This ASU is effective for annual and interim reporting periods beginning after December 15, 2015 and is required to be applied retrospectively. The adoption of this ASU will have no impact on our consolidated statement of operations.

In April 2015, the FASB issued ASU 2015-03 “Interest - Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-3). ASU 2015-3 simplifies the presentation of debt issuance costs by requiring such costs be presented as a deduction from the corresponding debt liability. The guidance is effective for financial statements issued for reporting periods beginning after December 15, 2015 and interim periods within the reporting periods and requires retrospective presentation. We will adopt the standard in the first quarter of 2016. The Partnership believes adoption of this new guidance will not have a material impact on CONE Midstream's financial statements.

In May 2014, the FASB issued 2014-09 "Revenue from Contracts with Customers (Topic 606)". The objective of the amendments in this update is to improve financial reporting by creating common revenue recognition guidance for U.S. GAAP and International Financial Reporting Standards (IFRS). The guidance in this update supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. 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. An entity 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. In July 2015, the FASB approved the deferral of the effective date of this ASU to annual reporting periods beginning after December 15, 2017, with the option to adopt as early as annual reporting periods beginning after December 15, 2016. We are currently evaluating the method of adoption and impact that this new guidance will have on our financial statements.

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

The following table illustrates the Partnership’s calculation of net income per unit for common and subordinated partner units (in thousands, except per unit information):



	June 30, 2015
	Three Months Ended		Six Months Ended
Net Income Attributable to General and Limited Partner Ownership Interest in CONE Midstream Partners LP	$	14,912	$	29,124
Less: General Partner Interest in Net Income	298		582
Limited Partner Interest in Net Income	$	14,614	$	28,542

Net Income Allocable to Common Units	$	7,307	$	14,271
Net Income Allocable to Subordinated Units	7,307		14,271
Limited Partner Interest in Net Income	$	14,614	$	28,542

Weighted Average Limited Partner Units Outstanding — Basic
Common Units	29,163		29,163
Subordinated Units	29,163		29,163
Total	58,326		58,326
Weighted Average Limited Partner Units Outstanding — Diluted
Common Units	29,201		29,202
Subordinated Units	29,163		29,163
Total	58,364		58,365

Net Income Per Limited Partner Unit — Basic and Diluted
Common Units	$	0.25	$	0.49
Subordinated Units	$	0.25	$	0.49

NOTE 4 — RELATED PARTY

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

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.

Charges for services from CONSOL included in operating expenses — related party were $6,940 and $5,893 for the three months ended June 30, 2015 and 2014 and $13,984 and $12,523 for the six months ended June 30, 2015 and 2014, respectively. There were no charges from Noble Energy included in operating expenses — related party for the three and six months ended June 30, 2015 and 2014.

During the three and six months ended June 30, 2015, CONSOL purchased no supply inventory and $2,239 of supply inventory from the Partnership, respectively. Purchases of supply inventory from a CONSOL subsidiary were $1,147 for the three months ended June 30, 2014 and $2,582 for the six months ended June 30, 2014 and were included in operating expenses — related party.

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
CONSOL	$	1,860	$	1,117	$	3,696	$	1,358
Noble Energy	135		—		276		—
Total General and Administrative Expense — Related Party	$	1,995	$	1,117	$	3,972	$	1,358

Omnibus Agreement

Concurrent with closing 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 annual administrative support fee, initially in the amount of $0.6 million (prorated for the first year of service), for the provision of certain services by CONSOL and its affiliates;


•	our payment of an annual administrative support fee, initially in the amount of approximately $0.6 million (pro rated for the first year of service), for the provision of certain executive services by CONSOL and its affiliates;


•	our payment of an annual administrative support fee, initially in the amount of approximately $0.2 million (pro rated for the first year of service), 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 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, including routine and emergency maintenance and repair services, routine operational activities, routine administrative services, construction and related services and such other services as we and CONSOL may mutually agree upon from time to time. CONSOL will prepare and submit for our approval a maintenance, operating and capital budget on an annual basis. CONSOL will submit actual expenditures for reimbursement on a monthly basis and we will reimburse CONSOL for any direct third-party costs actually 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 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.

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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, 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.

The CNX Gas Gathering Agreement commenced on September 30, 2014 and has an initial term of 20 years. 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 such well will be permanently released from the Partnership’s dedication.

Under the CNX Gas Gathering Agreement, the Partnership charges a fee based on the type and scope of midstream services provided. For the services provided (a) with respect to natural gas that does not require downstream processing, the Partnership receives a fee of $0.40 per MMBtu, (b) with respect to the natural gas that requires downstream processing, the Partnership receives a fee of $0.55 per MMBtu, except in the Moundsville area (Marshall County, West Virginia), where the fee is $0.275 per MMBtu and in the Pittsburgh International Airport area where the fee is $0.275 per MMBtu and (c) with respect to condensate, the Partnership receives a fee of $5.00 per Bbl in the Majorsville area and $2.50 per Bbl in the Moundsville area.

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, 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.

The NBL Gas Gathering Agreement commenced on September 30, 2014 and has an initial term of 20 years. 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 such well will be permanently released from the Partnership’s dedication.

Under the NBL Gas Gathering Agreement, the Partnership charges a fee based on the type and scope of midstream services provided. For the services provided (a) with respect to natural gas that does not require downstream processing, the Partnership receives a fee of $0.40 per MMBtu, (b) with respect to the natural gas that requires downstream processing, the Partnership receives a fee of $0.55 per MMBtu, except in the Moundsville area (Marshall County, West Virginia), where the fee is $0.275 per MMBtu and in the Pittsburgh International Airport area where the fee is $0.275 per MMBtu and (c) with respect to condensate, the Partnership receives a fee of $5.00 per Bbl in the Majorsville area and $2.50 per Bbl in the Moundsville area.

Employee Secondment Agreement

We entered into an employee secondment agreement, effective September 8, 2014, with Noble Energy. Pursuant to the employee secondment agreement, an employee of Noble Energy is seconded to us to provide investor relations and similar

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functions. We will reimburse Noble Energy for allocable salary, benefits, insurance, payroll taxes and other employment expenses related to the seconded employee.

NOTE 5 — CONCENTRATION OF CREDIT RISK

The Sponsors accounted for 100% of the Partnership’s revenue for the three and six months ended June 30, 2015 and 2014. Revenues from each Sponsor consisted of the following:



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
CONSOL	$	24,598	$	14,072	$	46,760	$	26,278
Noble Energy	23,119		13,739		44,125		25,639
Total Revenue	$	47,717	$	27,811	$	90,885	$	51,917

NOTE 6 — RECEIVABLES - RELATED PARTY

Receivables are comprised of related party receivables related to gathering fees and contribution activities and consisted of the following:



	June 30, 2015		December 31, 2014
Gathering Fees:
CONSOL	$	8,130	$	7,732
Noble Energy	7,702		13,697
Contributions Receivable:
CONSOL	4,670		16,141
Noble Energy	4,670		18,866
Other:
CONE Gathering LLC	1,826		2,313
Total Receivables — Related Party	$	26,998	$	58,749

NOTE 7 — PROPERTY AND EQUIPMENT



	June 30, 2015		December 31, 2014		Estimated Useful Lives in Years
Land	$	68,011	$	47,701	N/A
Gathering Equipment	405,300		298,897		25 — 40
Compression Equipment	92,538		91,585		30 — 40
Processing Equipment	30,979		30,979		40
Assets Under Construction	159,661		170,573		N/A
Total Property and Equipment	$	756,489	$	639,735
Less: Accumulated Depreciation
Gathering	$	14,739	$	9,848
Compression	5,641		4,486
Processing	3,068		2,655
Total Accumulated Depreciation	$	23,448	$	16,989

Property and Equipment, Net	$	733,041	$	622,746

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NOTE 8 — ACCOUNTS PAYABLE - RELATED PARTY

Related party payables consisted of the following:



	June 30, 2015		December 31, 2014
Accounts Payable — Related Party
Capital Expenditure Reimbursement to CNX Gas ⁽¹⁾	$	432	$	561
Expense Reimbursement to CONSOL	1,221		1,016
General and Administrative Services Provided by CONSOL	531		432
General and Administrative Services Provided by Noble	46		97
Total Accounts Payable — Related Party	$	2,230	$	2,106

(1) CNX Gas is a wholly owned subsidiary of CONSOL

NOTE 9 — SUPPLEMENTAL CASH FLOW INFORMATION

As of June 30, 2015, we had a receivable of $9,340 related to partners' investments from CONSOL and Noble Energy. Additionally, we had a receivable from CONE Gathering LLC related to capital expenditures of $942 and capital expenditures due to be reimbursed to CONSOL of $432 as of June 30, 2015.

For the six months ended June 30, 2014 we had a receivable of $3,000 related to partners' investments from CONSOL and Noble Energy. In addition, we had capital expenditures due to be reimbursed to CONSOL of $283.

NOTE 10 — 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 11 — LEASES

We have entered into various non-cancellable operating leases primarily related to compression facilities. Future minimum lease payments under operating leases at June 30, 2015 are as follows:



	Minimum Lease Payments
2015 - 2016	$	5,342
2016 - 2017	4,118
2017 - 2018	1,830
2018 - 2019	—
	$	11,290

Rental expense under operating leases was $2,375 and $1,860 for the three months ended June 30, 2015 and 2014, respectively, and $4,447 and $2,875 for the six months ended June 30, 2015 and 2014, respectively. These expenses are included within operating expense - third party on our consolidated statements of operations.

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NOTE 12—SEGMENT INFORMATION

Operating segments are revenue-producing components of the 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.

All of the Partnership’s operating revenues, income from operations and assets are generated or located in the United States.



	Three Months Ended June 30,					Six Months Ended June 30,
	2015		2014			2015		2014
Gathering Revenue - Related Party:
Anchor Systems	$	35,351	$	25,212		$	69,884	$	46,453
Growth Systems	3,913		2,211			6,888		4,730
Additional Systems	8,453		—			14,113		—
Other ^(*)	—		388			—		734
Total Gathering Revenue - Related Party	$	47,717	$	27,811		$	90,885	$	51,917

Net Income (Loss):
Anchor Systems	$	19,524	$	12,345		$	38,311	$	21,092
Growth Systems	933		680			1,734		1,403
Additional Systems	4,448		(171		)	6,076		(333		)
Other ^(*)	—		178			—		320
Total Net Income	$	24,905	$	13,032		$	46,121	$	22,482

Depreciation Expense:
Anchor Systems	$	2,607	$	1,182		$	5,004	$	2,341
Growth Systems	495		477			939		926
Additional Systems	565		—			718		—
Other^(*)	—		20			—		30
Total Depreciation Expense	$	3,667	$	1,679		$	6,661	$	3,297

Capital Expenditures for Segment Assets:
Anchor Systems	$	39,754	$	39,066		$	69,053	$	71,109
Growth Systems	7,333		2,858			18,970		7,434
Additional Systems	29,276		25,965			50,146		32,458
Other ^(*)	—		3,047			—		7,239
Total Capital Expenditures	$	76,363	$	70,936		$	138,169	$	118,240


(*)	Other consists of assets that are retained by our Predecessor, CONE Gathering, and are thus not part of the transactions that occurred in connection with the closing of the IPO. See Note 1 - Description of Business, Initial Public Offering and Basis of Presentation.



	June 30, 2015		December 31, 2014
Segment Assets
Anchor Systems	$	487,953	$	430,350
Growth Systems	104,441		119,550
Additional Systems	185,890		136,904
Total Segment Assets	$	778,284	$	686,804

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NOTE 13 — REVOLVING CREDIT FACILITY

At the closing of our IPO on September 30, 2014, we entered into a credit facility agreement which provides for a $250 million unsecured five year revolving credit facility that matures on September 30, 2019. Our revolving credit facility is available for working capital, capital expenditures, certain acquisitions, distributions, unit repurchases and other lawful partnership purposes. Borrowings under our revolving credit facility will bear interest at our option at either:


•	the base rate, which will be 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 0.1250% to 1.00% depending on our most recent consolidated total leverage ratio; or


•	the LIBOR rate plus a margin varying from 1.1250% 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 will be payable quarterly. Interest on LIBOR loans will be 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 will be 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. For example, we may not permit 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 to exceed (A) at any time other than during a qualified acquisition period (as defined in the agreement governing our revolving credit facility), 5.00 to 1.00 and (B) during a qualified acquisition period, 5.50 to 1.00. In addition, we may not permit 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 to be less than 3.00 to 1.00. We were in compliance with all relevant covenants at June 30, 2015.

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



	June 30, 2015				December 31, 2014
(thousands, except percentages)	Debt		Interest Rate ⁽¹⁾		Debt		Interest Rate ⁽¹⁾
Credit Facility	$	23,000	3.75	%	$	31,300	3.75	%

⁽¹⁾ At June 30, 2015 and December 31, 2014, borrowings accrued interest at the prime rate. The average interest rate for the three and six months period ended June 30, 2015 were 2.98% and 3.36%, respectively.

As of June 30, 2015, we had outstanding debt issuance costs of $694 which were incurred as part of the issuance of this credit facility and are currently being amortized over the term of the credit facility. The Partnership amortized $41 and $82 during the three and six months ended June 30, 2015.

NOTE 14 — LONG-TERM INCENTIVE PLAN

Under the CONE Midstream Partners LP 2014 Long-Term Incentive Plan (our “LTIP”), our general partner may issue long-term equity based awards to directors, officers and employees of our general partner or its affiliates, or to any consultants, affiliates of our general partner or other individuals who perform services for us. These awards will be intended to compensate the recipients thereof based on the performance of our common units and their continued service during the vesting period, as well as to align their long-term interests with those of our unitholders. We will be responsible for the cost of awards granted under our LTIP and all determinations with respect to awards to be made under our LTIP will be made by the board of directors of our general partner or any committee thereof that may be established for such purpose or by any delegate of the board of directors or such committee, subject to applicable law, which we refer to as the plan administrator.

The LTIP 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 exercise prices or tax withholding obligations or otherwise terminated without delivery of the common units will be available for delivery pursuant to other awards.

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On October 3, 2014, we filed a registration statement on Form S-8 under the Securities Act to register all common units issued or reserved for issuance under our LTIP. Common units covered by the registration statement on Form S-8 will be eligible for sale in the public market, subject to applicable vesting requirements and the terms of applicable lock-up agreements.

The Partnership's general partner has granted equity-based phantom units that vest over a period of continued service with the Partnership. The value of the phantom units will be paid in common units or an amount of cash equal to the fair market value of a unit based on the grant date. The Partnership accounted for these awards as equity awards and recorded compensation expense based on the fair value of the awards at the grant date fair value. Based on the vesting requirements, the Partnership amortized $96 for the three months ended June 30, 2015 and $192 for the six months ended June 30, 2015 and is included in general and administrative expense - related party.

As of June 30, 2015, 33,697 units have been issued under our LTIP. The weighted average fair value of these grants, based on the Partnership's common unit price on the grant date was $19.98.

NOTE 15 — SUBSEQUENT EVENTS

On July 14, 2015, the Board of Directors of CONE Midstream GP LLC, the general partner of CONE Midstream Partners LP, declared a cash distribution to the Partnership’s unitholders for the second quarter of 2015 of $0.22 per common and subordinated unit. The cash distribution will be paid on August 14, 2015 to unitholders of record at the close of business on August 5, 2015.

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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, 2014.

Executive Overview

We are a fee-based, growth-oriented master limited partnership formed by CONSOL and Noble Energy, whom we refer to 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.

On September 30, 2014, the Partnership closed its initial public offering ("IPO") of common units representing limited partner interests. References in this report to “our Partnership,” “we,” “our,” “us” or like terms, when used for periods prior to the IPO, refer to CONE Gathering LLC ("CONE Gathering"), our predecessor for accounting purposes. References in this report to “our Partnership,” “we,” “our,” “us” or like terms, when used for periods beginning at or following the IPO, refer collectively to the Partnership and its consolidated subsidiaries. See Note 1 - Description of Business, Initial Public Offering and Basis of Presentation.

We generate all of our revenues under long-term, fixed-fee gathering agreements that we have entered into 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.

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; (iii) distributable cash flow and (iv) operating expenses.

Throughput Volumes

The amount of revenue we generate primarily depends on the volumes of natural gas and condensate that we gather for our Sponsors and 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 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 our gathering agreements with our Sponsors related to new wells drilled on our dedicated acreage, we will be required to incur capital expenditures to extend our gathering systems and facilities to the new wells 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% ownership interests in the Anchor, Growth and Additional Systems, respectively. Since our IPO we have reduced our 2015 anticipated capital expenditures in the Growth and Additional systems due to the deferral of certain pipeline system projects driven by our Sponsors' reduced drilling activity, including the Tygart Valley System. This resulted in a $2 million decrease to the Partnership's anticipated capital expenditures for 2015.

We have secured significant acreage dedications from our Sponsors. Our Sponsors have dedicated to us approximately 516,000 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.

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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 producer activity in the areas served by our gathering systems to pursue new supply opportunities.

EBITDA & Distributable Cash Flow

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

Expenses

Operating Expense

We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating our assets. Electrical compression, direct labor costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operations and maintenance expense. These expenses generally remain relatively 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. We will seek to manage our operating expenditures on our midstream systems by scheduling maintenance over time to avoid significant variability in our maintenance expenditures and minimize their impact on our cash flow.

General and Administrative Expense

Since the completion of the IPO, we incur charges for a combination of direct and allocated charges for general and administrative services. Our Predecessor’s general and administrative expense included direct charges for the management and operation of our assets by CONSOL for general and administrative services, such as information technology, engineering, legal, human resources and other financial and administrative services.

Factors Affecting the Comparability of Our Financial Results

Our results of operations may not be comparable to our Predecessor’s historical results of operations for the reasons described below:

Ownership of Our Assets

Our Predecessor’s historical results of operations include all of the results of operations of CONE Gathering on a 100% basis, which includes 100% of the results of our Anchor Systems, Growth Systems and Additional Systems, as well as 100% of the results of certain ancillary midstream assets that CONE Gathering owns. 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. Consequently, our results of operations after the completion of the IPO reflect less than 100% of the results of our Anchor Systems, Growth Systems and Additional Systems and do not include any results of certain ancillary midstream assets that CONE Gathering owns.

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Revenues

Our Predecessor’s results of operations reflect gathering revenues based on the same fixed fee per unit of throughput of natural gas it gathered, regardless of the liquids-content of the natural gas, as well as reimbursements for electrically-powered compression costs. Under our gathering agreements with our Sponsors, we receive separate fixed fees for wet gas and dry gas that we gather. In addition, our Predecessor’s results of operations reflect the remittance of a net condensate price to our Sponsors for the condensate gathering and handling services provided by our Predecessor. Under our gathering agreements with our Sponsors, we receive a fixed fee per unit of throughput for condensate gathering and handling services at the applicable receipt points.

General and Administrative Expenses

Financing

There are differences in the way we will finance our operations as compared to the way our Predecessor financed its operations. Historically, our Predecessor’s operations were financed as part of our Sponsors’ midstream joint venture operations, and our Predecessor did not record any separate costs associated with financing its operations. In addition, our Predecessor largely relied on internally generated cash flows and capital contributions from our Sponsors to satisfy its capital expenditure requirements.

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 June 30, 2015, we had an outstanding balance of $23 million and available borrowing capacity of $227 million under our $250 million revolving credit facility.

Other Factors Impacting Our Business

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

Our Sponsors’ Drilling and Development 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. Our Sponsors primarily rely on us to deliver the midstream infrastructure necessary to accommodate their continuing production growth in the Marcellus Shale. However, our Sponsors’ JDA contains certain mechanisms that may cause their production on our dedicated acreage to be less than we anticipate.

Although we anticipate our Sponsors’ continued high levels of exploration and production activities in our areas of operation in the Marcellus Shale, we have no control over this activity. Fluctuations in natural gas prices could affect production rates over time and levels of investment by our Sponsors and third parties in exploration for and development of new natural gas reserves. Persistent low commodity prices may 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 and therefore throughput on our gathering systems.

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Results of Operations

Three Months Ended June 30, 2015 Compared to the Three Months Ended June 30, 2014



	Three Months Ended June 30,
	2015		2014		Variance		Percent Change
	($ in thousands)
Revenue
Gathering Revenue — Related Party	$	47,717	$	27,811	$	19,906	71.6	%
Total Revenue	47,717		27,811		19,906		71.6	%
Expenses
Operating Expense — Third Party	8,940		6,082		2,858		47.0	%
Operating Expense — Related Party	6,940		5,893		1,047		17.8	%
General and Administrative Expense — Third Party	1,223		8		1,215		15,187.5	%
General and Administrative Expense — Related Party	1,995		1,117		878		78.6	%
Depreciation Expense	3,667		1,679		1,988		118.4	%
Interest Expense	47		—		47		100.0	%
Total Expense	22,812		14,779		8,033		54.4	%
Net Income	$	24,905	$	13,032	$	11,873	91.1	%
Less: Net Income Attributable to Noncontrolling Interest	9,993		—		9,993		100.0	%
Net Income Attributable to General and Limited Partner Ownership Interest in CONE Midstream Partners LP	$	14,912	$	13,032	$	1,880	14.4	%

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



	Anchor	Growth	Additional	Other	TOTAL
Dry Gas (BBtu/d)	395	92	8	—	495
Wet Gas (BBtu/d)	334	11	163	—	508
Condensate (MMcfe/d)	9	—	14	—	23
Total Gathered Volumes	738	103	185	—	1,026

Operating Statistics - Gathered Volumes for the Three Months Ended June 30, 2014



	Anchor	Growth	Additional	Other	TOTAL
Dry Gas (BBtu/d)	318	55	—	4	377
Wet Gas (BBtu/d)	214	—	—	5	219
Condensate (MMcfe/d)	—	—	—	—	—
Total Gathered Volumes	532	55	—	9	596

Revenue Gathering revenue — related party was approximately $47.7 million for the three months ended June 30, 2015 compared to approximately $27.8 million for the three months ended June 30, 2014. The approximate $19.9 million increase was primarily due to a 430 BBtu/d increase in throughput volumes. The increase in throughput volumes was due to a 118 BBtu/d increase in natural gas volumes in our Sponsors’ dry gas production areas and 312 BBtu/d increase in natural gas volumes in our Sponsors’ wet gas and condensate production areas, which is primarily contained within our Anchor Systems. Of the dry gas change, 77 BBtu/d was related to the Anchor Systems, 37 BBtu/d was related to the Growth Systems, and 8 BBtu/d was related to the Additional Systems. Of the wet gas and condensate change, 129 BBtu/d was related to the Anchor Systems and 188 BBtu/d was related to our Growth and Additional Systems. The remaining volumes were related to assets retained by our Predecessor. Our Sponsors have established a drilling and development program on our dedicated acreage. As a result, our revenue increases with increases in our Sponsors’ production on our dedicated acreage.

Operating Expense Operating expense is comprised of items directly related to the cost of gathering natural gas at the wellhead and transporting it to interstate pipelines or other local sales points. These costs include items such as electrical compression, repairs and maintenance, supplies, treating and contract services. Total operating expense was approximately $15.9 million for the three months ended June 30, 2015 compared to approximately $12.0 million for the three months ended June 30, 2014. The increase in total operating expense is primarily due to the increase in throughput volumes. Included in

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operating expense was $3.6 million of electrical compression for the three months ended June 30, 2015 and $2.6 million for the three months ended June 30, 2014.

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 $3.2 million for the three months ended June 30, 2015 compared to approximately $1.1 million for the three months ended June 30, 2014. The approximate $2.1 million increase was primarily due to additional legal and professional fees associated with being a public company.

Depreciation Depreciation is recognized on gathering and other equipment that is reflected on straight-line basis with the useful lives ranging from 25-40 years. Total depreciation expense was approximately $3.7 million for the three months ended June 30, 2015 compared to approximately $1.7 million for the three months ended June 30, 2014. The increase of $2.0 million was primarily related to an increase in assets placed into service.

Six Months Ended June 30, 2015 Compared to the Six Months Ended June 30, 2014



	Six Months Ended June 30,
	2015		2014		Variance		Percent Change
	($ in thousands)
Revenue
Gathering Revenue — Related Party	$	90,885	$	51,917	$	38,968	75.1	%
Total Revenue	90,885		51,917		38,968		75.1	%
Expenses
Operating Expense — Third Party	17,470		11,428		6,042		52.9	%
Operating Expense — Related Party	13,984		12,523		1,461		11.7	%
General and Administrative Expense — Third Party	2,565		829		1,736		209.4	%
General and Administrative Expense — Related Party	3,972		1,358		2,614		192.5	%
Depreciation Expense	6,661		3,297		3,364		102.0	%
Interest Expense	112		—		112		100.0	%
Total Expense	44,764		29,435		15,329		52.1	%
Net Income	$	46,121	$	22,482	$	23,639	105.1	%
Less: Net Income Attributable to Noncontrolling Interest	16,997		—		16,997		100.0	%
Net Income Attributable to General and Limited Partner Ownership Interest in CONE Midstream Partners LP	$	29,124	$	22,482	$	6,642	29.5	%

Operating Statistics - Gathered Volumes for the Six Months Ended June 30, 2015



	Anchor	Growth	Additional	Other	TOTAL
Dry Gas (BBtu/d)	388	85	10	—	483
Wet Gas (BBtu/d)	330	7	136	—	473
Condensate (MMcfe/d)	10	—	8	—	18
Total Gathered Volumes	728	92	154	—	974

Operating Statistics - Gathered Volumes for the Six Months Ended June 30, 2014



	Anchor	Growth	Additional	Other	TOTAL
Dry Gas (BBtu/d)	308	50	—	4	362
Wet Gas (BBtu/d)	189	—	—	4	193
Condensate (MMcfe/d)	—	—	—	—	—
Total Gathered Volumes	497	50	—	8	555

Revenue Gathering revenue — related party was approximately $90.9 million for the six months ended June 30, 2015 compared to approximately $51.9 million for the six months ended June 30, 2014. The approximate $39.0 million increase was primarily due to a 419 BBtu/d increase in throughput volumes. The increase in throughput volumes was due to a 121 BBtu/d increase in natural gas volumes in our Sponsors’ dry gas production areas and 298 BBtu/d increase in natural gas volumes in our Sponsors’ wet gas and condensate production areas, which is primarily contained within our Anchor Systems. Of the dry

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gas change, 80 BBtu/d was related to the Anchor Systems, 35 BBtu/d was related to the Growth Systems, and 10 BBtu/d was related to the Additional Systems. Of the wet gas and condensate change, 151 BBtu/d was related to the Anchor Systems and 151 BBtu/d was related to our Growth and Additional Systems. The remaining volumes were related to assets retained by our Predecessor. Our Sponsors have established a drilling and development program on our dedicated acreage. As a result, our revenue increases with increases in our Sponsors’ production on our dedicated acreage.

Operating Expense Operating expense is comprised of items directly related to the cost of gathering natural gas at the wellhead and transporting it to interstate pipelines or other local sales points. These costs include items such as electrical compression, repairs and maintenance, supplies, treating and contract services. Total operating expense was approximately $31.5 million for the six months ended June 30, 2015 compared to approximately $24.0 million for the six months ended June 30, 2014. The increase in total operating expense is primarily due to the increase in throughput volumes. Included in operating expense was $7.1 million of electrical compression for the six months ended June 30, 2015 and $5.7 million for the six months ended June 30, 2014.

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 $6.5 million for the six months ended June 30, 2015 compared to approximately $2.2 million for the six months ended June 30, 2014. The approximate $4.3 million increase was primarily due to additional legal and professional fees associated with being a public company.

Depreciation Depreciation is recognized on gathering and other equipment that is reflected on straight-line basis with the useful lives ranging from 25-40 years. Total depreciation expense was approximately $6.7 million for the six months ended June 30, 2015 compared to approximately $3.3 million for the six months ended June 30, 2014. The increase of $3.4 million was primarily related to an increase in assets placed into service.

Non-GAAP Financial Measures

EBITDA

We define EBITDA as net income (loss) before income taxes, net interest expense, depreciation and amortization. EBITDA 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:


•	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 provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to EBITDA are net income and net cash provided by operating activities. 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 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, EBITDA as presented below may not be comparable to similarly titled measures of other companies.

Distributable Cash Flow

We define distributable cash flow as EBITDA less 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 (used in) operating activities or any other measure of financial performance or liquidity presented

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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.

The following table presents a reconciliation of EBITDA to net income and net cash provided by operating activities, the most directly comparable GAAP financial measures, on a historical basis basis, for each of the periods indicated.



	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2015		2014		2015		2014
Net Income	$	24,905	$	13,032	$	46,121	$	22,482
Add:
Interest Expense	47		—		112		—
Depreciation Expense	3,667		1,679		6,661		3,297
EBITDA	28,619		14,711		52,894		25,779
Less: Net Income Attributable to Noncontrolling Interest	9,993		—		16,997		—
Less: Interest Expense Attributable to Noncontrolling Interest	14		—		33		—
Less: Depreciation Expense Attributable to Noncontrolling Interest	1,659		—		2,825		—
EBITDA Attributable to General and Limited Partner Ownership Interest in CONE Midstream Partners LP	$	16,953	$	14,711	$	33,039	$	25,779
Less: Ongoing Maintenance Capital Expenditures, Net of Expected Reimbursements	2,148		1,399		4,139		2,562
Distributable Cash Flow	$	14,805	$	13,312	$	28,900	$	23,217

Net Cash Provided by Operating Activities	$	50,254	$	17,897	$	60,460	$	38,632
Adjustments:
Less: Interest Expense	47		—		112		—
Less: Other, Including Changes in Working Capital	21,588		3,186		7,454		12,853
EBITDA	28,619		14,711		52,894		25,779
Less: Net Income Attributable to Noncontrolling Interest	9,993		—		16,997		—
Less: Interest Expense Attributable to Noncontrolling Interest	14		—		33		—
Less: Depreciation Expense Attributable to Noncontrolling Interest	1,659		—		2,825		—
EBITDA Attributable to General and Limited Partner Ownership Interest in CONE Midstream Partners LP	$	16,953	$	14,711	$	33,039	$	25,779
Less: Ongoing Maintenance Capital Expenditures, Net of Expected Reimbursements	2,148		1,399		4,139		2,562
Distributable Cash Flow	$	14,805	$	13,312	$	28,900	$	23,217

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 we have historically received funding from our Sponsors, we do not have any 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 following the IPO. We expect our ongoing sources of liquidity to 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.

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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 number of common units, subordinated units and the general partner interest outstanding. 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

On September 30, 2014, we entered into a $250 million revolving credit facility. Our revolving credit facility is available for working capital, capital expenditures, certain acquisitions, distributions, unit repurchases and other lawful partnership purposes. Borrowings under our revolving credit facility bear interest at our option at either:


•	the base rate, which will be 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 0.1250% to 1.00% depending on our most recent consolidated total leverage ratio; or


•	the LIBOR rate plus a margin varying from 1.1250% 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 company, and transfer, sell or otherwise dispose of assets. We are also subject to covenants that require us to maintain certain financial ratios. For example, we may not permit 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 to exceed (A) at any time other than during a qualified acquisition period (as defined in the agreement governing our revolving credit facility), 5.00 to 1.00 and (B) during a qualified acquisition period, 5.50 to 1.00. 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 CONE Midstream Partners LP. The leverage ratio was 0.35 to 1.00 at June 30, 2015. Based on this ratio, the Partnership had the maximum amount of revolving credit available for borrowing at June 30, 2015, of which $23.0 million had been drawn. In addition, we may not permit 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 to be less than 3.00 to 1.00. We define this as our consolidated interest coverage ratio which is calculated as EBITDA Attributable to General and Limited Partner Ownership Interest in CONE Midstream Partners LP divided by total interest charges. The interest coverage ratio was 484.42 to 1.0 at June 30, 2015.

Cash Flows

Net cash provided by operating activities, investing activities and financing activities for the six months ended June 30, 2015 and 2014 were as follows:



	Six Months Ended June 30,
	2015			2014			Change
Net cash provided by operating activities:	$	60,460		$	38,632		$	21,828
Net cash used in investing activities:	$	(138,169	)	$	(118,240	)	$	(19,929	)
Net cash provided by financing activities:	$	74,618		$	83,000		$	(8,382	)

Net cash provided by operating activities increased $21.8 million during the six months ended June 30, 2015 compared to the six months ended June 30, 2014. The increase was primarily due to the $23.6 million increase in net income, the $3.4 million increase in depreciation, the $6.0 million increase in accounts payable, and the $4.6 million decrease in receivables - related

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party. These cash flows were offset by the $16.6 million increase in inventory. The remaining change is due to various other working capital adjustments.

Cash used in investing activities increased $19.9 million due to capital expenditures related to the expansion of our midstream systems. The expansion is in direct response to our Sponsors’ growing production on our dedicated acreage in the Marcellus Shale.

Cash provided by financing activities decreased $8.4 million. Additional investments from our Sponsors of $25.3 million were more than offset by cash distributions paid to unitholders of $25.4 million and payments made on our revolving credit facility of $8.3 million.

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.

For the three months ended June 30, 2015, total capital expenditures were $76.4 million on a 100% basis, which includes 100% of the capital expenditures associated with the Anchor Systems, Growth Systems and Additional Systems of which CONE Midstream Partners LP owns a controlling interest of 75%, 5% and 5%, respectively. Total capital expenditures consisted of gathering, compression and processing assets of $66.5 million, land assets of $9.3 million and permitting assets of $0.6 million. The gathering asset expenditures attributable to the Partnership were primarily associated with the construction of new pipeline infrastructure to connect new well pad sites and central receipt points on our Anchor Systems. Approximately $2.1 million of these capital expenditures were maintenance capital expenditures.

For the six months ended June 30, 2015, total capital expenditures were $138.2 million on a 100% basis, which includes 100% of the capital expenditures associated with the Anchor Systems, Growth Systems and Additional Systems of which CONE Midstream Partners LP owns a controlling interest of 75%, 5% and 5%, respectively. Total capital expenditures consisted of gathering, compression and processing assets of $117.1 million, land assets of $18.8 million and permitting assets of $2.3 million. The gathering asset expenditures attributable to the Partnership were primarily associated with the construction of new pipeline infrastructure to connect new well pad sites and central receipt points on our Anchor Systems. Approximately $4.1 million of these capital expenditures were maintenance capital expenditures.

We anticipate that we will continue to make significant 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 our 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 Form 10-Q.

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Contractual Obligations

The following table details the future projected payments associated with our contractual obligations as of June 30, 2015:



	Payments Due by Year
(in thousands)	< 1 year		1-3 years		3-5 years		Total
Land Commitments	$	6,871	$	18,084	$	—	$	24,955
Credit Facility	—		—		23,000		23,000
Operating Lease Obligations⁽¹⁾	5,342		5,948		—		11,290
Total Contractual Obligations	$	12,213	$	24,032	$	23,000	$	59,245

(1) We lease various equipment under non-cancelable operating leases (primarily related to compression facilities) for various periods. See Note 11 - Leases to the unaudited Consolidated Financial Statements included in this report.

Critical Accounting Policies

The Partnership’s critical accounting policies are described in the notes to the Partnership’s Consolidated Financial Statements for the year ended December 31, 2014 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 June 30, 2015. The application of the Partnership’s critical accounting policies may require management to make judgments and estimates about the amounts reflected 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.

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 the Marcellus Shale;


•	our Sponsors’ ability to meet their drilling and development plan in the 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;

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•	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, 2014 and under “Risk Factors” in this Quarterly Report on Form 10-Q, which may cause our actual results, performance or achievements to differ materially from anticipated future results, performance or achievements expressed or implied by such forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changed circumstances or otherwise, unless required by law.

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ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

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 down 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

At the closing of our IPO on September 30, 2014, we entered into a $250 million revolving credit facility. Assuming our outstanding balance on the revolving credit facility of $23.0 million, an increase of one percentage point in the interest rates will result in an increase in annual interest expense of $230 thousand. As a result, our results of operations, cash flows and financial condition and, as a result, our ability to make cash distributions to our unitholders, could be materially adversely affected by significant increases in interest rates.

Seasonality

Demand for natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. These seasonal anomalies can increase demand for natural gas during the summer and winter months and decrease demand for natural gas during the spring and fall months. In respect of our completed midstream systems, we do not expect seasonal conditions to have a material impact on our throughput volumes. Severe or prolonged winters may, however, impact our ability to complete additional well connections or complete construction projects, which may impact the rate of our growth. In addition, severe winter weather may also impact or slow the ability of our Sponsors to execute their planned drilling and development plan.


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 second quarter of 2015 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 10. Commitments and Contingencies,” which is incorporated herein by reference.

ITEM 1A. RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the risks under the heading “Item 1A. Risk Factors” from our Annual Report on Form 10-K for the year ended December 31, 2014, together with the following risks that have been amended and restated from the prior “Risk Factors” disclosed in the Form 10-K. These risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, cash flows or results of operations.

Environmental regulations introduce uncertainty that could adversely impact the market for natural gas with potential short-term and long-term liabilities.

The Federal Endangered Species Act (ESA) and similar state laws protect species threatened with extinction. Protection of endangered and threatened species may cause us to modify gas well pad siting or pipeline right of ways, mining plans, or develop and implement species-specific protection and enhancement plans to avoid or minimize impacts to endangered species or their habitats. A number of species indigenous to the areas where we operate are protected under the ESA. Based on species that have been identified and the current application of endangered species laws and regulations, we do not believe that there are any species protected under the ESA or state laws that would materially and adversely affect our ability to produce gas or mine coal from our properties. However, In April 2015 the US Fish and Wildlife Service (USFWS) announced a Section 4(d) threatened listing final rule for the Northern Long-Eared Bat throughout our operations area. This listing will establish habitat protection for the species but will not prevent the cause of the decline in the population of the Long-Eared bat, which is due to a disease commonly referred to as White Nose Syndrome (WNS). This listing could lead to significant timing and critical path hurdles, ultimately limiting the ability to clear timber for construction activities.

In April 2015 the USFWS also proposed the listing of Big Sandy Crayfish and Guyandotte River Crayfish as endangered under the ESA. USFWS has stated that the primary threats to crayfishes throughout their respective ranges are land-disturbing activities that increase erosion and sedimentation, which degrades the stream habitat required by both species. Identified sources of ongoing erosion and sedimentation that occur throughout the ranges of the species include active surface coal mining, commercial forestry, unpaved roads, gas and oil development, and road construction. This has the potential to disrupt future mining and natural gas activities in Central Appalachia.

In response to a spill by Freedom Industries of crude 4-methylcyclohexanemethanol (MCHM) to the Elk River in January 2014, West Virginia signed into law Senate Bill 373 (also known as the Above Ground Storage Tank Act), which requires that all above ground storage tanks (ASTs) be registered with the West Virginia Department of Environmental Protection (WV DEP) and meet additional requirements. This Act took effect on June 6, 2014. In October 2014, West Virginia (WV) DEP filed a Final Interpretive Rule (47CSR62) addressing initial inspection, certification and spill prevention response plan requirements. On March 14, 2015, the WV Legislature passed Senate Bill 423 to amend the “unintended consequences” of the AST Act on the economy of WV which became effective June 12, 2015. However, with over 4,000 impacted ASTs currently operational in WV and more needed for oil and gas production, this proposed final rule could still have significant cost associated with its requirements. On June 25, 2015 DEP proposed three AST rules to cover establishment of regulatory program, fees, and enforcement authority. DEP plans to issue a final rule to be effective in 2016.

CONSOL Energy, one of our Sponsors, utilizes pipelines extensively for its gas, water, and coal businesses; and as such must obtain permits with associated mitigation from the Army Corps of Engineers (ACOE) for impacts to streams and wetlands that are unavoidable. In 2013, the EPA issued a draft report entitled Connectivity of Streams and Wetlands to Downstream Waters, which affects a proposed rulemaking that would expand the scope of the Clean Water Act (CWA) to include previously non-jurisdictional streams, wetlands, and waters, making these areas jurisdictional inter-coastal Waters of the U.S. On June 29, 2015 EPA published the final WotUS rule which is effective August 28, 2015. This rulemaking will likely cause states that have jurisdiction over their own waters to make regulatory changes to their already robust regulatory programs and add unwarranted delays to the permitting process and extend review times even further for regulatory agencies already under resourced, and lead to additional mitigation cost and severely limit CONSOL’s and CONE Midstream's ability to avoid regulated jurisdictional waters.

In April 2015, the EPA proposed a CWA regulation (Effluent Limitations Guidelines and Standards for the Oil and Gas Extraction Point Source Category) establishing pretreatment standards that would prohibit the indirect discharge of wastewater

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from onshore unconventional oil and gas extraction facilities to publicly owned treatment works (POTWs). While discharges to POTWs are not currently utilized, unconventional oil and gas extraction wastewater can be generated in large quantities. It is unclear how the newly proposed rule could affect future water use and disposal practices.

Federal and state regulations for horizontal well drilling and well site construction have been proposed and are currently being considered. These regulations could negatively affect our Sponsors financial condition and results of operations. On April 4, 2015 PA published an advanced notice of final rulemaking on revisions to the Environmental Protection Performance Standards at Oil and Gas Well Sites (Chapters 78 and 78a) that could have significant impacts on how oil and natural gas companies currently operate in PA. On June 26, 2015 WV proposed amendments to regulations under 35 WVCSR 8 regarding standards for Horizontal Well Development. In May 2015 OH passed Horizontal Well Site Construction Rules which will become effective in July 2015. OH is also in the process of reviewing and possibly adopting additional developing additional horizontal development rules.

Changes in federal or state income tax laws, particularly in the area of percentage depletion and intangible drilling costs, could cause our Sponsors financial position and profitability to deteriorate.

The passage of legislation or any other similar changes in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to natural gas, oil or coal exploration and development. Any such change could negatively affect our Sponsors financial condition and results of operations.

In February 2012, the PA state legislature passed a new natural gas impact fee in PA, where a substantial portion of our acreage in the Marcellus Shale is located. The legislation imposes an annual fee on natural gas and oil operators for each well drilled for a period of fifteen years. The fee is on a sliding scale set by the Public Utility Commission and is based on two factors: changes in the Consumer Price Index and the average New York Mercantile Exchange’s natural gas prices from the last day of each month. The estimated total fees per well based on today’s current natural gas price is $310,000 over the 15 year period. The passage of this legislation increases the financial burden of our Sponsors on their operations in the Marcellus Shale.

Additionally, legislation has been proposed in OH and PA to introduce a new severance tax on the oil and gas industry. The proposed rates have varied from 2.5 - 7.5 percent and would represent a significant increased financial burden to our Sponsors beyond what is already in place.

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: August 5, 2015



	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/ C. KRISTOPHER HAGEDORN
		C. Kristopher Hagedorn
		Chief Accounting Officer (Duly Authorized Officer and Principal Accounting Officer)

Revolving Credit Facility (Details) - Revolving Credit Facility		3 Months Ended	6 Months Ended
	Sep. 30, 2014 USD ($)	Jun. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)
Debt Instrument [Line Items]
Revolving credit facility	$ 250,000,000
Debt Instrument, Term	5 years
Debt Covenant, funded debt to EBITDA ratio, non-acquisition period	5.00
Debt Covenant, funded debt to EBITDA ratio, acquisition period	5.50
Interest expense ratio	3.00
Unamortized debt issuance expense		$ 694,000	$ 694,000
Interest expense		$ 41,000	$ 82,000
Federal Funds Rate
Debt Instrument [Line Items]
Federal funds rate	0.50%
Base Rate, London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Federal funds rate	1.00%
Minimum
Debt Instrument [Line Items]
Commitment fee percentage	0.15%
Minimum \| LIBOR plus 1%
Debt Instrument [Line Items]
Federal funds rate	0.125%
Minimum \| LIBOR
Debt Instrument [Line Items]
Federal funds rate	1.125%
Maximum
Debt Instrument [Line Items]
Commitment fee percentage	0.35%
Maximum \| LIBOR plus 1%
Debt Instrument [Line Items]
Federal funds rate	1.00%
Maximum \| LIBOR
Debt Instrument [Line Items]
Federal funds rate	2.00%

Description of Business, Initial Public Offering and Basis of Presentation (Details) $ / shares in Units, $ in Thousands		6 Months Ended
	Sep. 30, 2014 USD ($) $ / shares shares	Jun. 30, 2015 USD ($) segment	Jun. 30, 2014 USD ($)
Schedule of Equity Method Investments [Line Items]
Number of operating segments \| segment		3
General partner's ownership interest		2.00%
Net proceeds distributed to CONE Gathering from the IPO \| $		$ 25,431	$ 0
Anchor Systems
Schedule of Equity Method Investments [Line Items]
Ownership percentage	75.00%
Growth Systems
Schedule of Equity Method Investments [Line Items]
Ownership percentage	5.00%
Additional Systems
Schedule of Equity Method Investments [Line Items]
Ownership percentage	5.00%
Common Units
Schedule of Equity Method Investments [Line Items]
Units sold in public offering	20,125,000
Price per share sold in IPO \| $ / shares	$ 22.00
Common Units \| Over-Allotment Option
Schedule of Equity Method Investments [Line Items]
Units sold in public offering	2,625,000
CONE Gathering
Schedule of Equity Method Investments [Line Items]
General partner's ownership interest	2.00%
Percentage Interest Received by Company	64.20%
Net proceeds distributed to CONE Gathering from the IPO \| $	$ 407,971
CONE Gathering \| Common Units
Schedule of Equity Method Investments [Line Items]
Limited Partner units distributed to CONE Gathering from the IPO	9,038,121
CONE Gathering \| Subordinated Units
Schedule of Equity Method Investments [Line Items]
Limited Partner units distributed to CONE Gathering from the IPO	29,163,121

Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Related Party Transaction [Line Items]
Due from Related Parties, Current	$ 26,998		$ 58,749
Receivable related to related parties	9,792	$ 5,162
Contribution Receivable \| CONSOL and Noble \| Affiliated Entity
Related Party Transaction [Line Items]
Due from Related Parties, Current	9,340
Receivable related to related parties	3,000
Contribution Receivable \| CONSOL Energy \| Affiliated Entity
Related Party Transaction [Line Items]
Due from Related Parties, Current	4,670		$ 16,141
Capital Expenditures \| CONSOL Energy \| Affiliated Entity
Related Party Transaction [Line Items]
Due to Related Parties	283
Capital Expenditures \| CONE Gathering LLC \| Affiliated Entity
Related Party Transaction [Line Items]
Due from Related Parties, Current	942
Capital Project Reimbursements \| CONSOL Energy \| Affiliated Entity
Related Party Transaction [Line Items]
Due to Related Parties	$ 432

Related Party (Details)	3 Months Ended		6 Months Ended
Related Party (Details)	Jun. 30, 2015 USD ($) $ / bbl $ / MMBTU	Jun. 30, 2014 USD ($)	Jun. 30, 2015 USD ($) $ / bbl $ / MMBTU	Jun. 30, 2014 USD ($)
Related Party Transaction [Line Items]
Purchases of supply inventory			$ 2,239,000
General and Administrative Expense — Related Party	$ 1,995,000	$ 1,117,000	3,972,000	$ 1,358,000
Affiliated Entity
Related Party Transaction [Line Items]
General and administrative expenses	1,995,000	1,117,000	3,972,000	1,358,000
CONSOL Energy \| Affiliated Entity
Related Party Transaction [Line Items]
General and administrative expenses			3,696,000
CONSOL Energy \| Affiliated Entity \| Shared Service Agreement with CONSOL
Related Party Transaction [Line Items]
Charges for services	6,940,000	5,893,000	13,984,000	12,523,000
General and administrative expenses	1,860,000
CONSOL Energy \| Affiliated Entity \| Purchases of Inventory from CONSOL
Related Party Transaction [Line Items]
Purchases of supply inventory	0	1,147,000	0	2,582,000
CONSOL Energy \| Affiliated Entity \| Administrative Services
Related Party Transaction [Line Items]
General and administrative expenses			600,000
CONSOL Energy \| Affiliated Entity \| Executive Administrative Services
Related Party Transaction [Line Items]
General and administrative expenses			$ 600,000
CONSOL Energy \| Affiliated Entity \| Operational Service Agreement
Related Party Transaction [Line Items]
Term of Agreement (in years)			20 years
Termination period to either party			6 months
Termination period			180 days
Maximum period to cure default			45 days
Noble Energy \| Affiliated Entity
Related Party Transaction [Line Items]
General and administrative expenses	135,000	$ 0	$ 276,000	$ 0
Noble Energy \| Affiliated Entity \| Shared Service Agreement with CONSOL
Related Party Transaction [Line Items]
Charges for services	$ 0
Noble Energy \| Affiliated Entity \| Executive Administrative Services
Related Party Transaction [Line Items]
General and administrative expenses			$ 200,000
Noble Energy \| Affiliated Entity \| NBL Gas Gathering Agreement
Related Party Transaction [Line Items]
Term of Agreement (in years)			20 years
Maximum period for uncured default			90 days
Downstream fees receivable (in dollars per MMBtu) \| $ / MMBTU	0.55		0.55
Fees receivable, excluding downstream (in dollars per MMBtu) \| $ / MMBTU	0.40		0.40
CNX Gas \| Affiliated Entity \| CNX Gas Gathering Agreement
Related Party Transaction [Line Items]
Term of Agreement (in years)			20 years
Maximum period for uncured default			90 days
Downstream fees receivable (in dollars per MMBtu) \| $ / MMBTU	0.55		0.55
Fees receivable, excluding downstream (in dollars per MMBtu) \| $ / MMBTU	0.40		0.40
West Virgina \| Noble Energy \| Affiliated Entity \| NBL Gas Gathering Agreement
Related Party Transaction [Line Items]
Downstream fees receivable (in dollars per MMBtu) \| $ / MMBTU	0.275		0.275
Condensate fees receivable (in dollars per Bbl) \| $ / bbl	2.50		2.50
West Virgina \| CNX Gas \| Affiliated Entity \| CNX Gas Gathering Agreement
Related Party Transaction [Line Items]
Downstream fees receivable (in dollars per MMBtu) \| $ / MMBTU	0.275		0.275
Condensate fees receivable (in dollars per Bbl) \| $ / bbl	2.50		2.50
Pennsylvania \| Noble Energy \| Affiliated Entity \| NBL Gas Gathering Agreement
Related Party Transaction [Line Items]
Downstream fees receivable (in dollars per MMBtu) \| $ / MMBTU	0.275		0.275
Condensate fees receivable (in dollars per Bbl) \| $ / bbl	5.00		5.00
Pennsylvania \| CNX Gas \| Affiliated Entity \| CNX Gas Gathering Agreement
Related Party Transaction [Line Items]
Downstream fees receivable (in dollars per MMBtu) \| $ / MMBTU	0.275		0.275
Condensate fees receivable (in dollars per Bbl) \| $ / bbl	5.00		5.00

Long-Term Incentive Plan (Details) - Jun. 30, 2015 - Common Units - 2014 LTIP - USD ($) $ / shares in Units, $ in Thousands	Total	Total
Stock Compensation Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of common units authorized	5,800,000	5,800,000
Number of units issued		33,697
Common unit price on the grant date		$ 19.98
Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unit Based Compensation	$ 96	$ 192


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


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


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


4.	The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and have:


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


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


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


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


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



Date:	August 5, 2015

/S/ JOHN T. LEWIS
John T. Lewis
Chairman of the Board and Chief Executive Officer (Principal Executive Officer)

Receivables - Related Party (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Accounts, Notes, Loans and Financing Receivable [Line Items]
Receivables — Related Party	$ 26,998	$ 58,749
Gathering Fees \| CONSOL Energy \| Affiliated Entity
Accounts, Notes, Loans and Financing Receivable [Line Items]
Receivables — Related Party	8,130	7,732
Gathering Fees \| Noble Energy \| Affiliated Entity
Accounts, Notes, Loans and Financing Receivable [Line Items]
Receivables — Related Party	7,702	13,697
Contribution Receivable \| CONSOL Energy \| Affiliated Entity
Accounts, Notes, Loans and Financing Receivable [Line Items]
Receivables — Related Party	4,670	16,141
Contribution Receivable \| Noble Energy \| Affiliated Entity
Accounts, Notes, Loans and Financing Receivable [Line Items]
Receivables — Related Party	4,670	18,866
Other \| CONE Gathering LLC \| Affiliated Entity
Accounts, Notes, Loans and Financing Receivable [Line Items]
Receivables — Related Party	$ 1,826	$ 2,313

Leases (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
Leases (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Leases, Operating [Abstract]
2015 - 2016	$ 5,342		$ 5,342
2016 - 2017	4,118		4,118
2017 - 2018	1,830		1,830
2018 - 2019	0		0
Total future minimum lease payments	11,290		11,290
Rental expense	$ 2,375	$ 1,860	$ 4,447	$ 2,875

Property and Equipment (Details) - USD ($) $ in Thousands	6 Months Ended
Property and Equipment (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property and Equipment	$ 756,489	$ 639,735
Less — Accumulated Depreciation	23,448	16,989
Property and Equipment — Net	733,041	622,746
Land
Property, Plant and Equipment [Line Items]
Property and Equipment	68,011	47,701
Gathering Equipment
Property, Plant and Equipment [Line Items]
Property and Equipment	405,300	298,897
Less — Accumulated Depreciation	$ 14,739	9,848
Gathering Equipment \| Minimum
Property, Plant and Equipment [Line Items]
Estimated Useful Lives in Years	25 years
Gathering Equipment \| Maximum
Property, Plant and Equipment [Line Items]
Estimated Useful Lives in Years	40 years
Compression Equipment
Property, Plant and Equipment [Line Items]
Property and Equipment	$ 92,538	91,585
Less — Accumulated Depreciation	$ 5,641	4,486
Compression Equipment \| Minimum
Property, Plant and Equipment [Line Items]
Estimated Useful Lives in Years	30 years
Compression Equipment \| Maximum
Property, Plant and Equipment [Line Items]
Estimated Useful Lives in Years	40 years
Processing Equipment
Property, Plant and Equipment [Line Items]
Property and Equipment	$ 30,979	30,979
Less — Accumulated Depreciation	$ 3,068	2,655
Estimated Useful Lives in Years	40 years
Asset Under Construction
Property, Plant and Equipment [Line Items]
Property and Equipment	$ 159,661	$ 170,573

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Cash Flows from Operating Activities:
Net Income	$ 46,121	$ 22,482
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities:
Depreciation and Amortization	6,743	3,297
Unit Based Compensation	192	0
Changes in Operating Assets:
Receivables — Related Party	9,792	5,162
Inventory	(16,632)	0
Prepaid Expenses	522	0
Changes in Operating Liabilities:
Accounts Payable	13,307	9,281
Accounts Payable — Related Party	415	(1,590)
Net Cash Provided by Operating Activities	60,460	38,632
Cash Flows from Investing Activities:
Capital Expenditures	(138,169)	(118,240)
Net Cash Used in Investing Activities	(138,169)	(118,240)
Cash Flows from Financing Activities:
Partners' Investments	108,349	83,000
Distributions to Unitholders	(25,431)	0
Payment of Revolver	(8,300)	0
Net Cash Provided By Financing Activities	74,618	83,000
Net (Decrease) Increase in Cash	(3,091)	3,392
Cash at Beginning of Period	3,252	5,976
Cash at End of Period	$ 161	$ 9,368

Significant Accounting Policies - Schedule of Target Distributions (Details) - 6 months ended Jun. 30, 2015 - $ / shares	Total
Schedule of Target Distributions [Line Items]
Quarterly distribution to limited partner	$ 0.2125
Minimum Quarterly Distribution
Schedule of Target Distributions [Line Items]
Marginal Percentage Interest in Distributions- Unitholders	98.00%
Marginal Percentage Interest in Distributions- General Partner	2.00%
First Target Distribution
Schedule of Target Distributions [Line Items]
Marginal Percentage Interest in Distributions- Unitholders	98.00%
Marginal Percentage Interest in Distributions- General Partner	2.00%
Second Target Distribution
Schedule of Target Distributions [Line Items]
Marginal Percentage Interest in Distributions- Unitholders	85.00%
Marginal Percentage Interest in Distributions- General Partner	15.00%
Third Target Distribution
Schedule of Target Distributions [Line Items]
Marginal Percentage Interest in Distributions- Unitholders	75.00%
Marginal Percentage Interest in Distributions- General Partner	25.00%
Thereafter Distributions
Schedule of Target Distributions [Line Items]
Marginal Percentage Interest in Distributions- Unitholders	50.00%
Marginal Percentage Interest in Distributions- General Partner	50.00%
Minimum \| First Target Distribution
Schedule of Target Distributions [Line Items]
Quarterly distribution to limited partner	$ 0.2125
Minimum \| Second Target Distribution
Schedule of Target Distributions [Line Items]
Quarterly distribution to limited partner	0.24438
Minimum \| Third Target Distribution
Schedule of Target Distributions [Line Items]
Quarterly distribution to limited partner	0.26563
Minimum \| Thereafter Distributions
Schedule of Target Distributions [Line Items]
Quarterly distribution to limited partner	0.31875
Maximum \| First Target Distribution
Schedule of Target Distributions [Line Items]
Quarterly distribution to limited partner	0.24438
Maximum \| Second Target Distribution
Schedule of Target Distributions [Line Items]
Quarterly distribution to limited partner	0.26563
Maximum \| Third Target Distribution
Schedule of Target Distributions [Line Items]
Quarterly distribution to limited partner	$ 0.31875

Significant Accounting Policies (Policies)	6 Months Ended
Significant Accounting Policies (Policies)	Jun. 30, 2015
Accounting Policies [Abstract]
Principles of Consolidation	The consolidated financial statements include the accounts of CONE Midstream Partners LP and all of its controlled subsidiaries. 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.
Use of Estimates	The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and various disclosures. Actual results could differ from those estimates.
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.
Accounts Receivable	Accounts receivable are recorded at the invoiced amount and do not bear interest. We reserve for specific accounts receivable when it is probable that all or a part of an outstanding balance will not be collected, such as customer bankruptcies. 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 in the periods presented.
Inventory	Inventory is stated at the lower of cost or market and consists of pipe purchased for a pipeline project that has been delayed. The cost is determined primarily under the specific identification method. The Partnership expects the pipe will be used in an alternative project or sold to a third party.
Property and Equipment	Property and equipment is recorded at cost upon acquisition. Expenditures which extend the useful lives of existing property and equipment are capitalized. Depreciation of property and equipment is calculated on the straight-line method over their estimated useful lives or lease terms. 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 gain or loss. There were no retirements or disposals during the periods presented. 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, such that the asset’s carrying amount is adjusted to its estimated fair value with an offsetting charge to operating expense. 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.
Variable Interest Entities	The Anchor, Growth and Additional Limited Partnerships (the Limited Partnerships), which are variable interest entities, are consolidated by CONE Midstream Partners LP through its ownership of CONE Midstream Operating Company LLC. CONE Midstream Operating Company LLC, through its general partner ownership interest in each of the Anchor, Growth and Additional Limited Partnerships, has the power to direct all substantive strategic and day-to-day operational decisions of the Limited Partnerships. CONE Midstream Operating Company LLC is considered to be the primary beneficiary for accounting purposes.
Environmental Matters	We are subject to various federal, state and local laws and regulations relating to the protection of the environment. We have established procedures for the ongoing evaluation of our operations, to identify potential environmental exposures and to comply with regulatory policies and procedures, including legislation related to greenhouse gas emissions. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. At this time, we are unable to assess the timing and/or effect of potential liabilities related to greenhouse gas emissions or other environmental issues. As of June 30, 2015, we had no material environmental matters that required specific disclosure or requiring the recognition of a liability.
Asset Retirement Obligations	We perform an ongoing analysis of asset removal and site restoration costs that we may be required to perform under law or contract once an asset has been permanently taken out of service. We have property and equipment at locations that we own and at sites leased or under right of way agreements. We are under no contractual obligation to remove the assets at locations we own. In evaluating our asset retirement obligation, we review lease agreements, right of way agreements, easements and permits to determine which agreements, if any, require an asset removal and restoration obligation. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including expected settlement dates, future retirement costs, future inflation rates and the credit-adjusted-risk-free interest rates. We operate and maintain our midstream systems and intend to do so as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we believe that we cannot reasonably estimate the asset retirement obligations for our midstream system assets as these assets have indeterminate lives.
Income Taxes	Our operations as a limited partnership, and our Predecessor, as a limited liability company, are treated as partnerships for federal and state income tax purposes, with each partner being separately taxed on its share of the taxable income. Accordingly, no provision for federal or state income taxes has been recorded in the consolidated financial statements.
Net Income per Limited Partners Unit	We allocate our net income among our general partner and limited partners using the two-class method in accordance with applicable authoritative accounting guidance. Under the two-class method, we allocate our 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 reflected by applying the treasury stock method. Potentially dilutive securities included in the calculation of diluted net income per limited partner unit totaled 33,697 phantom units for the three and six months ended June 30, 2015. Our partnership agreement requires that, within 45 days after the end of each quarter, the Partnership distribute all of its available cash (described below) to unitholders of record on the applicable record date.
Cash Distribution, Subordinated Units, and Incentive Distribution Rights	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 amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that, during the subordination period, there will be available cash to be distributed on the common units. The subordination period will end, and the subordinated units will convert to common units, on a one-for-one basis, when certain distribution requirements, as defined in the partnership agreement, have been met. The earliest date at which the subordination period may end is September 30, 2015. 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. Our partnership agreement requires that we distribute all of our available cash quarterly. This requirement forms the basis of our cash distribution policy and reflects a basic judgment that our unitholders will be better served by distributing our available cash rather than retaining it because, among other reasons, we believe we will generally finance any expansion capital expenditures from external financing sources. Under our current cash distribution policy, we intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $0.2125 per unit, or $0.85 per unit on an annualized basis, to the extent we have sufficient available cash after the establishment of cash reserves and the payment of costs and expenses, including the payment of expenses to our general partner. However, other than the requirement in our partnership agreement to distribute all of our available cash each quarter, we have no legal obligation to make quarterly cash distributions in this or any other amount, and the board of directors of our general partner has considerable discretion to determine the amount of our available cash each quarter. In addition, the board of directors of our general partner may change our cash distribution policy at any time, subject to the requirement in our partnership agreement to distribute all of our available cash quarterly. Generally, our available cash is the sum of (i) all cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (ii) if the board of directors of our general partner so determines, all or any portion of additional cash on hand resulting from working capital borrowings made after the end of the quarter.
Reclassifications	Certain amounts in prior periods have been reclassified to conform with the current reporting classifications with no effect on previously reported net income or partners' capital.
Recent Accounting Pronouncements	In April 2015, the FASB issued ASU 2015-06 “Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions”. ASU 2015-06 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. This ASU is effective for annual and interim reporting periods beginning after December 15, 2015 and is required to be applied retrospectively. The adoption of this ASU will have no impact on our consolidated statement of operations. In April 2015, the FASB issued ASU 2015-03 “Interest - Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-3). ASU 2015-3 simplifies the presentation of debt issuance costs by requiring such costs be presented as a deduction from the corresponding debt liability. The guidance is effective for financial statements issued for reporting periods beginning after December 15, 2015 and interim periods within the reporting periods and requires retrospective presentation. We will adopt the standard in the first quarter of 2016. The Partnership believes adoption of this new guidance will not have a material impact on CONE Midstream's financial statements. In May 2014, the FASB issued 2014-09 "Revenue from Contracts with Customers (Topic 606)". The objective of the amendments in this update is to improve financial reporting by creating common revenue recognition guidance for U.S. GAAP and International Financial Reporting Standards (IFRS). The guidance in this update supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. 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. An entity 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. In July 2015, the FASB approved the deferral of the effective date of this ASU to annual reporting periods beginning after December 15, 2017, with the option to adopt as early as annual reporting periods beginning after December 15, 2016. We are currently evaluating the method of adoption and impact that this new guidance will have on our financial statements.

Consolidated Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Current Assets:
Cash	$ 161	$ 3,252
Receivables — Related Party	26,998	58,749
Inventory	16,632	0
Prepaid Expenses	757	1,280
Other Current Assets	164	164
Total Current Assets	44,712	63,445
Property and Equipment:
Property and Equipment	756,489	639,735
Less — Accumulated Depreciation	23,448	16,989
Property and Equipment — Net	733,041	622,746
Other Non-Current Assets	531	613
TOTAL ASSETS	778,284	686,804
Current Liabilities:
Accounts Payable	63,955	70,635
Accounts Payable — Related Party	2,230	2,106
Total Current Liabilities	66,185	72,741
Other Liabilities:
Revolving Credit Facility	23,000	31,300
Total Liabilities	89,185	104,041
Partners' Capital:
Partners' Capital Attributable to CONE Midstream Partners LP	297,440	293,555
Noncontrolling Interest	391,659	289,208
Total Partners' Capital	689,099	582,763
TOTAL LIABILITIES AND PARTNERS' CAPITAL	778,284	686,804
Common Units
Partners' Capital:
Limited partners' capital	391,614	389,612
Subordinated Units
Partners' Capital:
Limited partners' capital	(90,475)	(92,285)
General Partner
Partners' Capital:
General Partner Interest	$ (3,699)	$ (3,772)

Document and Entity Information Document - shares	6 Months Ended
Document and Entity Information Document - shares	Jun. 30, 2015	Aug. 05, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	CONE Midstream Partners LP
Entity Central Index Key	0001610418
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Jun. 30, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		29,163,121

Consolidated Balance Sheets (Parenthetical) - shares	Jun. 30, 2015	Dec. 31, 2014
Common Units
Common units issued	29,163,121	29,163,121
Common units outstanding	29,163,121	29,163,121
Subordinated Units
Common units issued	29,163,121	29,163,121
Common units outstanding	29,163,121	29,163,121

Supplemental Cash Flow Information	6 Months Ended
Supplemental Cash Flow Information	Jun. 30, 2015
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	SUPPLEMENTAL CASH FLOW INFORMATION As of June 30, 2015, we had a receivable of $9,340 related to partners' investments from CONSOL and Noble Energy. Additionally, we had a receivable from CONE Gathering LLC related to capital expenditures of $942 and capital expenditures due to be reimbursed to CONSOL of $432 as of June 30, 2015. For the six months ended June 30, 2014 we had a receivable of $3,000 related to partners' investments from CONSOL and Noble Energy. In addition, we had capital expenditures due to be reimbursed to CONSOL of $283.

Commitments and Contingencies	6 Months Ended
Commitments and Contingencies	Jun. 30, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	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.

Significant Accounting Policies (Details) - Jun. 30, 2015	USD ($) shares	USD ($) $ / shares shares
Schedule of Target Distributions [Line Items]
Emerging Growth Company, Maximum Status Period		5 years
Emerging Growth Company, Termination of Status, Maximum Revenue \| $		$ 1,000,000,000
Emerging Growth Company, Termination of Status, Maximum Market Value of Limited Partner Interest Held by Non-Affiliates \| $	$ 700,000,000	700,000,000
Emerging Growth Company, Termination of Status, Maximum Non-Convertible Debt Issuable \| $	$ 1,000,000,000	$ 1,000,000,000
Emerging Growth Company, Termination of Status, Maximum Non-Convertible Debt Issuable, Period		3 years
Number of potential diluted securities included in the calculation of diluted net income per limited partner unit (in units) \| shares	33,697	33,697
Period to distribute available cash		45 days
Quarterly distribution to limited partner		$ 0.2125
Annual distribution to limited partner		$ 0.85
General partner's ownership interest		2.00%
Incentive Distribution, Distribution Rate One		13.00%
Incentive Distribution, Distribution Rate Two		23.00%
Incentive Distribution, Distribution Rate Three		48.00%
Conversion Of Stock, Conversion Ratio		1
First Target Distribution
Schedule of Target Distributions [Line Items]
Marginal Percentage Interest in Distributions- Unitholders		98.00%
Marginal Percentage Interest in Distributions- General Partner		2.00%
Second Target Distribution
Schedule of Target Distributions [Line Items]
Marginal Percentage Interest in Distributions- Unitholders		85.00%
Marginal Percentage Interest in Distributions- General Partner		15.00%
Third Target Distribution
Schedule of Target Distributions [Line Items]
Marginal Percentage Interest in Distributions- Unitholders		75.00%
Marginal Percentage Interest in Distributions- General Partner		25.00%
Thereafter Distributions
Schedule of Target Distributions [Line Items]
Marginal Percentage Interest in Distributions- Unitholders		50.00%
Marginal Percentage Interest in Distributions- General Partner		50.00%
Maximum \| First Target Distribution
Schedule of Target Distributions [Line Items]
Quarterly distribution to limited partner		$ 0.24438
Maximum \| Second Target Distribution
Schedule of Target Distributions [Line Items]
Quarterly distribution to limited partner		0.26563
Maximum \| Third Target Distribution
Schedule of Target Distributions [Line Items]
Quarterly distribution to limited partner		$ 0.31875

Subsequent Events	6 Months Ended
Subsequent Events	Jun. 30, 2015
Subsequent Events [Abstract]
Subsequent Events	SUBSEQUENT EVENTS On July 14, 2015, the Board of Directors of CONE Midstream GP LLC, the general partner of CONE Midstream Partners LP, declared a cash distribution to the Partnership’s unitholders for the second quarter of 2015 of $0.22 per common and subordinated unit. The cash distribution will be paid on August 14, 2015 to unitholders of record at the close of business on August 5, 2015.

Long-Term Incentive Plan	6 Months Ended
Long-Term Incentive Plan	Jun. 30, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Long-Term Incentive Plan	LONG-TERM INCENTIVE PLAN Under the CONE Midstream Partners LP 2014 Long-Term Incentive Plan (our “LTIP”), our general partner may issue long-term equity based awards to directors, officers and employees of our general partner or its affiliates, or to any consultants, affiliates of our general partner or other individuals who perform services for us. These awards will be intended to compensate the recipients thereof based on the performance of our common units and their continued service during the vesting period, as well as to align their long-term interests with those of our unitholders. We will be responsible for the cost of awards granted under our LTIP and all determinations with respect to awards to be made under our LTIP will be made by the board of directors of our general partner or any committee thereof that may be established for such purpose or by any delegate of the board of directors or such committee, subject to applicable law, which we refer to as the plan administrator. The LTIP 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 exercise prices or tax withholding obligations or otherwise terminated without delivery of the common units will be available for delivery pursuant to other awards. On October 3, 2014, we filed a registration statement on Form S-8 under the Securities Act to register all common units issued or reserved for issuance under our LTIP. Common units covered by the registration statement on Form S-8 will be eligible for sale in the public market, subject to applicable vesting requirements and the terms of applicable lock-up agreements. The Partnership's general partner has granted equity-based phantom units that vest over a period of continued service with the Partnership. The value of the phantom units will be paid in common units or an amount of cash equal to the fair market value of a unit based on the grant date. The Partnership accounted for these awards as equity awards and recorded compensation expense based on the fair value of the awards at the grant date fair value. Based on the vesting requirements, the Partnership amortized $96 for the three months ended June 30, 2015 and $192 for the six months ended June 30, 2015 and is included in general and administrative expense - related party. As of June 30, 2015, 33,697 units have been issued under our LTIP. The weighted average fair value of these grants, based on the Partnership's common unit price on the grant date was $19.98.