10-K 1 eqm1231201710k.htm 10-K Document
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
 
FORM 10-K
 
[X]
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

[   ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2017
or
 FOR THE TRANSITION PERIOD FROM ___________ TO __________
 
COMMISSION FILE NUMBER 001-35574
 
EQT Midstream Partners, LP
(Exact name of registrant as specified in its charter)
 
DELAWARE
(State or other jurisdiction of incorporation or organization)
 
625 Liberty Avenue, Suite 1700
Pittsburgh, Pennsylvania
(Address of principal executive offices)
37-1661577
(IRS Employer Identification No.)

 
15222
(Zip Code)
 
Registrant's telephone number, including area code:  (412) 553-5700
 
Securities registered pursuant to Section 12(b) of the Act:
 
Title of each class
 
Name of each exchange on which registered
Common Units Representing Limited Partner Interests
 
New York Stock Exchange
 
Securities registered pursuant to Section 12(g) of the Act:  None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes  x  No  ¨
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. 
Yes  ¨  No  x
 
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  x  No  ¨
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, 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  ¨
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   x
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company.  See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer   x
 
 
Accelerated Filer                  ¨
 
Emerging Growth Company       ¨
Non-Accelerated Filer     ¨
(Do not check if a
smaller reporting company)
 
Smaller Reporting Company ¨
 
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ¨

 Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes  ¨  No  x
 
The aggregate market value of the Common Units held by non-affiliates of the registrant as of June 30, 2017: $4.4 billion
 
At January 31, 2018, there were 80,581,758 Common Units and 1,443,015 General Partner Units outstanding.
 
DOCUMENTS INCORPORATED BY REFERENCE
None



EQT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
TABLE OF CONTENTS
 
 
 
PART I
Item 1
Item 1A
Item 1B
Item 2
Item 3
Item 4
PART II
Item 5
Item 6
Item 7
Item 7A
Item 8
Item 9
Item 9A
Item 9B
PART III
Item 10
Item 11
Item 12
Item 13
Item 14
PART IV
Item 15
 


2


Glossary of Commonly Used Terms, Abbreviations and Measurements

adjusted EBITDA – a supplemental non-GAAP (as defined below) financial measure defined by EQT Midstream Partners, LP and subsidiaries (collectively, EQM) as net income plus net interest expense, depreciation and amortization expense, income tax expense (benefit) (if applicable), Preferred Interest payments received post conversion (as defined below) and non-cash long-term compensation expense less equity income, AFUDC – equity (as defined below), pre-acquisition capital lease payments for Allegheny Valley Connector, LLC (AVC) and adjusted EBITDA of assets prior to acquisition.

Allowance for Funds Used During Construction or AFUDC – carrying costs for the construction of certain long-lived regulated assets are capitalized and amortized over the related assets' estimated useful lives. The capitalized amount for construction of regulated assets includes debt cost and a designated cost of equity for financing the construction of these regulated assets.
 
Appalachian Basin – the area of the United States composed of those portions of West Virginia, Pennsylvania, Ohio, Maryland, Kentucky and Virginia that lie in the Appalachian Mountains.

British thermal unit – a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.
 
Disclosure Document – EQT’s 2018 Proxy Statement or amendment to its Annual Report on Form 10-K for the year ended December 31, 2017, as applicable, in each case, as filed or to be filed with the Securities and Exchange Commission (the SEC).

distributable cash flow – a supplemental non-GAAP financial measure defined by EQM as adjusted EBITDA less net interest expense excluding interest income on the Preferred Interest, capitalized interest and AFUDC – debt, and ongoing maintenance capital expenditures net of reimbursements.
 
firm contracts – contracts for gathering, transmission or storage services that obligate customers to pay a fixed monthly charge to reserve an agreed upon amount of pipeline or storage capacity regardless of the actual capacity used by a customer during each month.
 
gas – all references to "gas" refer to natural gas.
 
Jupiter Acquisition – On May 7, 2014, EQT Corporation and subsidiaries (collectively, EQT) contributed the Jupiter natural gas gathering system (Jupiter) to EQM Gathering Opco, LLC (EQM Gathering), an indirect wholly owned subsidiary of EQM.

liquefied natural gas or LNG natural gas that has been cooled to minus 161 degrees celsius for transportation, typically by ship. The cooling process reduces the volume of natural gas by 600 times.

local distribution company or LDC LDCs are companies involved in the delivery of natural gas to consumers within a specific geographic area.
 
MVP Interest Acquisition – On March 30, 2015, EQM assumed from EQT the membership interests in MVP Holdco, LLC (MVP Holdco), the owner of an interest (the MVP Interest) in Mountain Valley Pipeline, LLC (MVP Joint Venture), which at the time was an indirect wholly owned subsidiary of EQT.

NWV Gathering Acquisition – On March 17, 2015, EQT contributed the Northern West Virginia Marcellus gathering system (NWV Gathering) to EQM Gathering.

October 2016 Acquisition On October 13, 2016, EQM acquired from EQT 100% of the outstanding limited liability company interests of AVC and Rager Mountain Storage Company LLC (Rager) and certain gathering assets located in southwestern Pennsylvania and northern West Virginia (the Gathering Assets). The closing of the October 2016 Acquisition was effective as of October 1, 2016.

omnibus agreement the agreement, as amended, entered into among EQM, its general partner and EQT in connection with EQM's initial public offering, pursuant to which EQT agreed to provide EQM with, and EQM agreed to reimburse EQT for, certain general and administrative services and a license to use the name "EQT" and related marks in connection with EQM's business. The omnibus agreement also provides for certain indemnification obligations between EQM and EQT.
 
play a proven geological formation that contains commercial amounts of hydrocarbons.

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Preferred Interest Acquisition – On April 15, 2015, EQM acquired a preferred interest (the Preferred Interest) in EQT Energy Supply, LLC (EES), which at the time was an indirect wholly owned subsidiary of EQT. Concurrent with the October 2016 Acquisition, the operating agreement of EES was amended and the accounting for EQM's Preferred Interest in EES converted from a cost method investment to a note receivable. There were no changes to the cash payment schedule.
 
receipt point the point where production is received by or into a gathering system or transmission pipeline.
 
reservoir a porous and permeable underground formation containing an individual and separate natural accumulation of producible hydrocarbons (crude oil and/or natural gas) which is confined by impermeable rock or water barriers and is characterized by a single natural pressure system.
 
The $750 Million ATM Program – EQM's at-the-market (ATM) common unit offering program, pursuant to which a group of managers, acting as EQM's sales agents, may sell EQM common units having an aggregate offering price of up to $750 million.

Sunrise Merger – On July 22, 2013, Sunrise Pipeline, LLC (Sunrise) merged into Equitrans, L.P. (Equitrans), an indirect wholly owned subsidiary of EQM.
 
throughput the volume of natural gas transported or passing through a pipeline, plant, terminal or other facility during a particular period.
 
wellhead the equipment at the surface of a well used to control the well's pressure and the point at which the hydrocarbons and water exit the ground.
 
working gas – the volume of natural gas in the storage reservoir that can be extracted during the normal operation of the storage facility.
Abbreviations
ASC – Accounting Standards Codification
CERCLA – Comprehensive Environmental Response, Compensation and Liability Act
DOT – U.S. Department of Transportation
FASB  Financial Accounting Standards Board
FERC – Federal Energy Regulatory Commission
GAAP – U.S. Generally Accepted Accounting Principles
IPO – Initial Public Offering
IRS – Internal Revenue Service
NGA  Natural Gas Act of 1938
NGPA – Natural Gas Policy Act of 1978
NYMEX – New York Mercantile Exchange
NYSE – New York Stock Exchange
PHMSA – Pipeline and Hazardous Materials Safety Administration of the DOT
RCRA  Resource Conservation and Recovery Act
SEC – Securities and Exchange Commission
Measurements
Btu  = one British thermal unit
BBtu = billion British thermal units
Bcf   = billion cubic feet
Bcfe = billion cubic feet of natural gas equivalents, with one barrel of natural gas liquids (NGLs) and crude oil being equivalent to 6,000 cubic feet of natural gas
Dth  =  dekatherm or million British thermal units
MMBtu  = million British thermal units
Mcf = thousand cubic feet
MMcf  = million cubic feet
Tcfe = trillion cubic feet of natural gas equivalents, with one barrel of NGLs and crude oil being equivalent to 6,000 cubic feet of natural gas

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Cautionary Statements

Disclosures in this Annual Report on Form 10-K contain certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended.  Statements that do not relate strictly to historical or current facts are forward-looking and usually identified by the use of words such as "anticipate," "estimate," "could," "would," "will," "may," "forecast," "approximate," "expect," "project," "intend," "plan," "believe" and other words of similar meaning in connection with any discussion of future operating or financial matters.  Without limiting the generality of the foregoing, forward-looking statements contained in this Annual Report on Form 10-K include the matters discussed in the sections captioned "Strategy" in Item 1, "Business" and "Outlook" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," and the expectations of plans, strategies, objectives, and growth and anticipated financial and operational performance of EQM and its subsidiaries, including guidance regarding EQM's gathering and transmission and storage revenue and volume growth; the weighted average contract life of gathering, transmission and storage contracts; infrastructure programs (including the timing, cost, capacity and sources of funding with respect to gathering and transmission expansion projects); the cost, capacity, timing of regulatory approvals and anticipated in-service date of the Mountain Valley Pipeline (MVP) project; the ultimate terms, partners and structure of the MVP Joint Venture; expansion projects in EQM's operating areas and in areas that would provide access to new markets; asset acquisitions, including EQM's ability to complete asset acquisitions from EQT or third parties; the expected benefits to EQM of EQT's acquisition of companies that contain midstream assets, including whether EQT will make those assets available to EQM; the expected benefits to EQM of EQT's acquisition of Rice Energy Inc. (Rice), including whether EQT will sell the acquired Ohio midstream assets to EQM and the timing of any transaction; the timing of EQT's announcement of a decision for addressing its sum-of-the-parts discount; the amount and timing of distributions, including expected increases; the timing of the expected redemption of the Preferred Interest; the amounts and timing of projected capital contributions and operating and capital expenditures, including the amount of capital expenditures reimbursable by EQT; the impact of commodity prices on EQM's business; liquidity and financing requirements, including sources and availability; the effects of government regulation and litigation; and tax position, including the effects of changes in tax law. The forward-looking statements included in this Annual Report on Form 10-K involve risks and uncertainties that could cause actual results to differ materially from projected results.  Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results.  EQM has based these forward-looking statements on current expectations and assumptions about future events.  While EQM considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, many of which are difficult to predict and are beyond EQM's control. The risks and uncertainties that may affect the operations, performance and results of EQM's business and forward-looking statements include, but are not limited to, those set forth under Item 1A, "Risk Factors" and elsewhere in this Annual Report on Form 10-K.
 
Any forward-looking statement speaks only as of the date on which such statement is made and EQM does not intend to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.
 
In reviewing any agreements incorporated by reference in or filed with this Annual Report on Form 10-K, please remember that such agreements are included to provide information regarding the terms of such agreements and are not intended to provide any other factual or disclosure information about EQM. The agreements may contain representations and warranties by EQM, which should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to such agreements should those statements prove to be inaccurate. The representations and warranties were made only as of the date of the relevant agreement or such other date or dates as may be specified in such agreement and are subject to more recent developments.  Accordingly, these representations and warranties alone may not describe the actual state of affairs of EQM or its affiliates as of the date they were made or at any other time.

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PART I

Item 1. Business

EQM's consolidated financial statements have been retrospectively recast to include the historical results of AVC, Rager and the Gathering Assets, which were acquired by EQM effective on October 1, 2016, and NWV Gathering, which was acquired by EQM on March 17, 2015, as these were businesses and the transactions were between entities under common control. All references in this Annual Report on Form 10-K to "EQM" refer to EQM in its individual capacity or to EQM and its consolidated subsidiaries, as the context requires. All references in this Annual Report on Form 10-K to "EQT" refer to EQT Corporation in its individual capacity or to EQT and its consolidated subsidiaries, as the context requires.

Overview

EQT Midstream Partners, LP (NYSE: EQM) is a growth-oriented limited partnership formed by EQT Corporation (NYSE: EQT) to own, operate, acquire and develop midstream assets in the Appalachian Basin. EQM provides midstream services to EQT and multiple third parties in Pennsylvania, West Virginia and Ohio through its two primary assets: the gathering system, which delivers natural gas from wells and other receipt points to transmission pipelines, and the transmission and storage system, which delivers gas to local demand users and interstate pipelines for access to demand markets. EQM provides substantially all of its natural gas gathering, transmission and storage services under contracts with long-term, firm reservation and/or usage fees. This contract structure enhances the stability of EQM's cash flows and limits its direct exposure to commodity price risk. For the year ended December 31, 2017, approximately 91% of EQM's revenues were generated from capacity reservation charges under long-term firm contracts. Including contracts associated with expected future capacity from expansion projects that are not yet fully constructed but for which EQM has entered into firm contracts, firm gathering contracts had a weighted average remaining term of approximately 8 years and firm transmission and storage contracts had a weighted average remaining term of approximately 15 years as of December 31, 2017, in each case based on total projected contracted revenues. EQM's operations are primarily focused in southwestern Pennsylvania and northern West Virginia, a strategic location in the natural gas shale plays known as the Marcellus, Upper Devonian and Utica Shales. This same region is also the primary operating area of EQT, EQM's largest customer. EQT accounted for approximately 73% of EQM's revenues generated for the year ended December 31, 2017.

Business Segments

Gathering Business Segment. As of December 31, 2017, EQM's gathering system included approximately 300 miles of high pressure gathering lines with approximately 2.3 Bcf per day of total firm contracted gathering capacity, compression of approximately 189,000 horsepower and multiple interconnect points with EQM's transmission and storage system. EQM's gathering system also included approximately 1,500 miles of FERC-regulated low pressure gathering lines. Gathering revenues represented approximately 54%, 54% and 53% of total revenues for the years ended December 31, 2017, 2016 and 2015, respectively.

In the ordinary course of its business, EQM pursues gathering expansion projects for affiliates and third party producers. EQM invested approximately $197 million on gathering projects in 2017 that added approximately 475 MMcf per day of firm gathering capacity in southwestern Pennsylvania. This included the final phase of the header pipeline for Range Resources Corporation (Range Resources), which was placed in-service during the second quarter of 2017. The system now provides total firm gathering capacity of 600 MMcf per day at a total project cost of approximately $240 million. This and other expansion projects, primarily for affiliates, supported increased gathered volumes of 11% and gathering revenues of 14% in 2017. In 2018, EQM estimates capital expenditures of approximately $300 million on gathering expansion projects, primarily driven by affiliate wellhead and header projects in Pennsylvania and West Virginia, including commencing preliminary construction activities on the Hammerhead project, a 1.2 Bcf per day gathering header pipeline connecting Pennsylvania and West Virginia production to the MVP.

EQM provides gathering services in two manners: firm service and interruptible service. The fixed monthly fee under a firm contract is referred to as a firm reservation fee, which is recognized ratably over the contract period based on the contracted volume regardless of the amount of natural gas that is gathered. If there is available system capacity, customers can flow gas above the firm commitment volumes for a usage charge per unit at a rate that is generally the same or lower than the firm capacity charge per unit. EQM has firm gas gathering agreements in high pressure development areas with approximately 2.3 Bcf per day of total firm contracted gathering capacity as of December 31, 2017. Including expected future capacity from expansion projects that are not yet fully constructed but for which EQM had entered into firm gathering agreements,

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approximately 2.4 Bcf per day of firm gathering capacity was subscribed under firm gathering contracts as of December 31, 2017. On EQM's low pressure regulated gathering system, the typical gathering agreement is interruptible and has a one year term with month-to-month roll over provisions terminable upon at least 30 days notice. The rates for gathering service on the regulated system are based on the maximum posted tariff rate and assessed on actual receipts into the gathering system. EQM generally does not take title to the natural gas gathered for its customers but retains a percentage of wellhead natural gas receipts to recover natural gas used to run its compressor stations and other requirements on all of its gathering systems.

Gathering System
gatheringmap2017.jpg

Transmission Business Segment. As of December 31, 2017, EQM's transmission and storage system included an approximately 950-mile FERC-regulated interstate pipeline that connects to seven interstate pipelines and to LDCs. The transmission system is supported by 18 associated natural gas storage reservoirs with approximately 645 MMcf per day of peak withdrawal capacity, 43 Bcf of working gas capacity and 41 compressor units, with total throughput capacity of approximately 4.4 Bcf per day and compression of approximately 120,000 horsepower as of December 31, 2017. Revenues associated with EQM's transmission and storage system represented approximately 46%, 46% and 47% of its total revenues for the years ended December 31, 2017, 2016 and 2015, respectively.
 
In the ordinary course of its business, EQM pursues transmission projects aimed at profitably increasing system capacity. EQM invested approximately $111 million on transmission and storage system infrastructure in 2017. Revenues in 2017 increased by approximately $41 million or 12% compared to 2016. In 2018, EQM will focus on the following transmission projects:

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Mountain Valley Pipeline. The MVP Joint Venture is a joint venture with affiliates of each of NextEra Energy, Inc., Consolidated Edison, Inc., WGL Holdings, Inc. and RGC Resources, Inc. EQM is the operator of the MVP and owned a 45.5% interest in the MVP Joint Venture as of December 31, 2017. The 42 inch diameter MVP has a targeted capacity of 2.0 Bcf per day and is estimated to span 300 miles extending from EQM's existing transmission and storage system in Wetzel County, West Virginia to Pittsylvania County, Virginia, providing access to the growing Southeast demand markets. As currently designed, the MVP is estimated to cost a total of approximately $3.5 billion, excluding AFUDC, with EQM funding its proportionate share through capital contributions made to the joint venture. In 2018, EQM expects to provide capital contributions of $1.0 billion to $1.2 billion to the MVP Joint Venture. The MVP Joint Venture has secured a total of 2.0 Bcf per day of firm capacity commitments at 20-year terms, including a 1.29 Bcf per day firm capacity commitment by EQT, and is currently in negotiation with additional shippers who have expressed interest in the MVP project. On October 13, 2017, the FERC issued the Certificate of Public Convenience and Necessity for the project. In early 2018, the MVP Joint Venture received limited notice to proceed with certain construction activities from the FERC. The MVP Joint Venture plans to commence construction in the first quarter of 2018. The pipeline is targeted to be placed in-service during the fourth quarter of 2018.

Transmission Expansion. In 2018, EQM estimates capital expenditures of approximately $100 million for other transmission expansion projects, primarily attributable to the Equitrans Expansion project. The Equitrans Expansion project is designed to provide north-to-south capacity on the mainline Equitrans system for deliveries to the MVP.

EQM generally does not take title to the natural gas transported or stored for its customers and provides transmission and storage services in two manners: firm service and interruptible service. The fixed monthly fee under a firm contract is referred to as a capacity reservation fee, which is recognized ratably over the contract period based on the contracted volume regardless of the amount of natural gas that is transported or stored. In addition to capacity reservation fees, EQM may also collect usage fees when a firm transmission customer uses the capacity it has reserved under these firm transmission contracts. Where applicable, the usage fees are assessed on the actual volume of natural gas transported on the system. A firm customer is billed an additional usage fee on volumes in excess of firm capacity when the level of natural gas received for delivery from the customer exceeds its reserved capacity. Customers are not assured capacity or service for volumes in excess of firm capacity on the applicable pipeline as these volumes have the same priority as interruptible service.

Under interruptible service contracts, customers pay usage fees based on their actual utilization of assets. Customers that have executed interruptible contracts are not assured capacity or service on the applicable systems. To the extent that physical capacity that is contracted for firm service is not fully utilized or excess capacity that has not been contracted for service exists, the system can allocate such capacity to interruptible services.

Including expected future capacity from expansion projects that are not yet fully constructed but for which EQM has entered into firm contracts, approximately 5.1 Bcf per day of transmission capacity and 31.3 Bcf of storage capacity, respectively, were subscribed under firm transmission and storage contracts as of December 31, 2017.
 
As of December 31, 2017, approximately 89% of EQM's contracted transmission firm capacity was subscribed by customers under negotiated rate agreements under its tariff. Approximately 9% of EQM's contracted transmission firm capacity was subscribed at the recourse rates under its tariff, which are the maximum rates an interstate pipeline may charge for its services under its tariff. The remaining 2% of EQM's contracted transmission firm capacity was subscribed at discounted rates, which are less than the maximum rates an interstate pipeline may charge for its services under its tariff.

EQM has an acreage dedication from EQT pursuant to which EQM has the right to elect to transport on its transmission and storage system all natural gas produced from wells drilled by EQT under an area covering approximately 60,000 acres in Allegheny, Washington and Greene counties in Pennsylvania and Wetzel, Marion, Taylor, Tyler, Doddridge, Harrison and Lewis counties in West Virginia. EQT has a significant natural gas drilling program in these areas.


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Transmission and Storage System
transmissionmap2017.jpg

     The following table provides a revenue breakdown by EQM business segment for the year ended December 31, 2017:
 
 
 
Revenue Composition %
 
 
Firm Contracts
 
 Interruptible Contracts
 
 
 
 
Capacity
Reservation
 
 Usage
 
Usage
 
 
 
 
Charges
 
Charges
 
 Fees
 
Total
Gathering
 
49%
 
4%
 
1%
 
54%
Transmission
 
42%
 
2%
 
2%
 
46%

For the year ended December 31, 2017, approximately 91% of total revenues were derived from firm reservation fees. As a result, EQM believes that short and medium term declines in volumes of gas produced, gathered, transported or stored on its systems will not have a significant impact on its results of operations, liquidity, financial position or ability to pay distributions because these firm reservation fees are paid regardless of volumes supplied to the system by customers. Longer term price declines could have an impact on customer creditworthiness and related ability to pay firm reservation fees under long-term contracts which could impact EQM's results of operations, liquidity, financial position or ability to pay distributions to its unitholders. Additionally, long term declines in gas production in EQM's areas of operations would limit EQM's growth potential.

9


Strategy
 
EQM's principal business objective is to increase the quarterly cash distributions that it pays to its unitholders over time while ensuring the ongoing stability of its business. EQM expects to achieve its principal business objective through the following business strategies:
 
Capitalizing on economically attractive organic growth opportunities. EQM believes organic growth will be a key driver of growth in the future. EQM expects to grow its systems over time by meeting EQT's and third party customers' midstream service needs that result from their drilling activity in EQM's areas of operations. Further, EQM believes it has a competitive advantage in pursuing economically attractive organic expansion projects in its areas of operations as a result of its strategically located assets which cover portions of the Marcellus, Upper Devonian and Utica Shales that lack substantial natural gas pipeline infrastructure.

Increasing access to existing and new delivery markets. EQM is actively working to increase delivery interconnects with interstate pipelines, neighboring LDCs, large industrial facilities and electric generation plants in order to increase access to existing and new markets for natural gas consumption. In 2015, EQM began several multi-year transmission projects to support Marcellus, Upper Devonian and Utica Shale development, including the Ohio Valley Connector (OVC), the Equitrans Expansion project and the MVP. The OVC was placed in-service during the fourth quarter of 2016, providing shippers access to the Midwest markets. The Equitrans Expansion project is designed to provide north-to-south capacity on the mainline Equitrans system for deliveries to the MVP. This project and the MVP are expected to be constructed in 2018 and together will further diversify the market access on Equitrans by providing 2 Bcf per day of capacity to the growing Southeast demand markets.  EQM is also executing on the Hammerhead project.

Pursuing accretive acquisitions from EQT and third parties. EQM intends to seek opportunities to expand its existing operations through accretive acquisitions from EQT and third parties. EQT announced that it intends to sell the retained midstream assets it acquired in its acquisition of Rice Energy Inc. (Rice) to EQM through one or more drop-down transactions. See “EQM’s Relationship with EQT” for additional information regarding these assets. However, EQT is under no obligation to offer the acquisition opportunity to EQM. EQM will also evaluate and may pursue acquisition opportunities from third parties as they become available.

Attracting additional third party customers. EQM actively markets its midstream services to, and pursues strategic relationships with, third party producers and demand driven customers in order to attract additional volumes and/or expansion opportunities. EQM believes that its connectivity to interstate pipelines as well as its position as an early developer of midstream infrastructure within certain areas of the Marcellus, Upper Devonian and Utica Shales, will allow EQM to capture additional third party volumes in the future and attract additional demand customers who want access to the Appalachian Basin.

Focusing on stable, fixed-fee business. EQM intends to pursue additional opportunities to provide fixed-fee gathering, transmission and storage services to EQT and third parties. This contract structure enhances the stability of EQM's cash flows and limits its direct exposure to commodity price risk. EQM will focus on obtaining additional long-term firm commitments from customers, which may include reservation-based fees, volume commitments and acreage dedications.

EQM's Relationship with EQT
 
EQT is an integrated energy company, with an emphasis on natural gas production, gathering and transmission. EQT conducts its business through five business segments: EQT Production, EQM Gathering, EQM Transmission, RMP Gathering and RMP Water. EQT Production is the largest natural gas producer in the United States, based on average daily sales volumes, with 21.4 Tcfe of proved natural gas, NGLs and crude oil reserves across approximately 4.0 million gross acres, including approximately 1.1 million gross acres in the Marcellus play, many of which have associated deep Utica and/or Upper Devonian drilling rights, and approximately 0.1 million gross acres in the Ohio Utica play as of December 31, 2017. EQM Gathering and EQM Transmission provide gathering, transmission and storage services for EQT's produced gas, as well as for independent third parties across the Appalachian Basin through EQM. RMP Gathering provides natural gas gathering and compression services primarily to EQT in the dry gas core of the Marcellus Shale in southwestern Pennsylvania through Rice Midstream Partners LP (RMP) (NYSE: RMP). RMP Water provides water services that support well completion activities and collects and recycles or disposes of flowback and produced water for EQT and third parties in Washington and Greene Counties, Pennsylvania and Belmont County, Ohio through RMP.
 

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As of December 31, 2017, EQT GP Holdings, LP (NYSE: EQGP) and its subsidiaries (EQGP) owned a 1.8% general partner interest in EQM, all of the incentive distribution rights (IDRs) in EQM and a 26.6% limited partner interest in EQM. As of December 31, 2017, EQT indirectly held 239,715,000 EQGP common units, representing a 90.1% limited partner interest, and 100% of the non-economic general partner interest in EQGP. Because of the significant interest in EQM that EQT owns through EQGP, EQT is positioned to directly benefit from committing additional natural gas volumes to EQM's systems and from facilitating organic growth opportunities and accretive acquisitions for EQM. Following EQT’s acquisition of Rice, EQM expects to have the opportunity to purchase additional midstream assets from EQT in the future. The opportunities are expected to include certain midstream assets previously owned by Rice that provide gathering services for EQT and third party’s produced gas in Belmont and Monroe Counties, Ohio. However, EQT is under no obligation to make acquisition opportunities available to EQM, is not restricted from competing with EQM and may acquire, construct or dispose of midstream assets without any obligation to offer EQM the opportunity to purchase or construct these assets.

EQM's relationship with EQT is also a source of potential conflicts. For example, EQT is not restricted from competing with EQM, whether directly, through RMP, or otherwise. In addition, all of the executive officers and five of the directors of EQT Midstream Services, LLC, the general partner of EQM (the EQM General Partner), also serve as officers and/or directors of EQT, three of the executive officers and four of the directors of the EQM General Partner also serve as officers and/or directors of EQT GP Services, LLC, the general partner of EQGP, and all of the executive officers and five of the directors of the EQM General Partner also serve as officers and/or directors of Rice Midstream Management LLC, the general partner of RMP. These individuals face conflicts of interest, which include the allocation of their time among EQM, EQT, EQGP and RMP. For a description of EQM's relationships with EQT, please read Item 13, "Certain Relationships and Related Transactions, and Director Independence." In addition, EQT has announced that its board of directors has formed a committee to evaluate options for addressing EQT’s sum-of-the-parts discount. EQT’s board will announce a decision by the end of March 2018, after considering the committee’s recommendation.

 Markets and Customers
 
EQT accounted for approximately 73%, 75% and 73% of EQM's total revenues for the years ended December 31, 2017, 2016 and 2015, respectively. For the years ended December 31, 2017, 2016 and 2015, PNG Companies, LLC and its affiliates, an LDC, accounted for approximately 12%, 12% and 14% of EQM's total revenues, respectively.

Gathering Customers. EQM's gathering system has approximately 2,200 receipt points with natural gas producers. EQT represented approximately 89%, 96% and 96% of EQM's gathering revenues for the years ended December 31, 2017, 2016 and 2015, respectively.

Transmission Customers. EQM provides natural gas transmission and storage services for EQT and third parties, predominantly consisting of LDCs, marketers, producers and commercial and industrial users that EQM believes to be creditworthy. EQM's transmission system provides these customers with access to adjacent markets in Pennsylvania, West Virginia and Ohio and also provides access to the Mid-Atlantic, Northeastern, Midwestern and Gulf Coast markets in the United States through 6.5 Bcf per day of delivery interconnect capacity with major interstate pipelines as of December 31, 2017. EQM provides storage services to a mix of customers, including marketers and LDCs.
 
For the years ended December 31, 2017, 2016 and 2015, EQT and its affiliates accounted for approximately 53%, 51% and 47%, respectively, of EQM's transmission and storage revenues. Additionally, for the years ended December 31, 2017, 2016 and 2015, PNG Companies, LLC and its affiliates accounted for approximately 26%, 27% and 29% of EQM's transmission and storage revenues.
 
Competition
 
Key competitors for new gathering systems include companies that own major natural gas pipelines, independent gas gatherers and integrated energy companies. Some of EQM's competitors have capital resources and control supplies of natural gas greater than it does.

Competition for natural gas transmission and storage volumes is primarily based on rates, customer commitment levels, timing, performance, commercial terms, reliability, service levels, location, reputation and fuel efficiencies. EQM's principal competitors in its natural gas transmission and storage market include companies that own major natural gas pipelines. In addition, EQM competes with companies that are building high pressure gathering facilities that are not subject to FERC jurisdiction to move volumes to interstate pipelines. EQT also owns high pressure gathering facilities and in the future may construct additional high pressure gathering facilities and natural gas transmission pipelines. Major natural gas

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transmission companies that compete with EQM also have existing storage facilities connected to their transmission systems that compete with certain of EQM's storage facilities.

Regulatory Environment

FERC Regulation. EQM's interstate natural gas transmission and storage operations are regulated by the FERC under the NGA, the NGPA and the Energy Policy Act of 2005. EQM's regulated system operates under tariffs approved by the FERC that establish rates, cost recovery mechanisms and the terms and conditions of service to its customers. Generally, the FERC's authority extends to:
 
                   rates and charges for natural gas transmission, storage and FERC-regulated gathering services;
                   certification and construction of new interstate transmission and storage facilities;
                   abandonment of interstate transmission and storage services and facilities;
                   maintenance of accounts and records;
                   relationships between pipelines and certain affiliates;
                   terms and conditions of services and service contracts with customers;
                   depreciation and amortization policies;
                   acquisition and disposition of interstate transmission and storage facilities; and
                   initiation and discontinuation of interstate transmission and storage services.
 
EQM holds certificates of public convenience and necessity for its transmission and storage system issued by the FERC pursuant to Section 7 of the NGA covering rates, facilities, activities and services. These certificates require EQM to provide open-access services on its interstate pipeline and storage facilities on a non-discriminatory basis to all customers that qualify under the FERC gas tariffs. In addition, under Section 8 of the NGA, the FERC has the power to prescribe the accounting treatment of certain items for regulatory purposes. Thus, the books and records of EQM's interstate pipeline and storage facilities may be periodically audited by the FERC.
 
The FERC regulates the rates and charges for transmission and storage in interstate commerce. Under the NGA, rates charged by interstate pipelines must be just and reasonable.
 
The recourse rate that EQM may charge for its services is established through the FERC's cost-of-service ratemaking process. Generally, the maximum filed recourse rates for interstate pipelines are based on the cost of providing that service including recovery of and a return on the pipeline's actual prudent historical cost of investment. Key determinants in the ratemaking process include the depreciated capital costs of the facilities, the costs of providing service, the allowed rate of return and income tax allowance, as well as volume throughput and contractual capacity commitment assumptions. The maximum applicable recourse rates and terms and conditions for service are set forth in the pipeline's FERC-approved tariff. Rate design and the allocation of costs also can impact a pipeline's profitability. While the ratemaking process establishes the maximum rate that can be charged, interstate pipelines such as EQM's transmission and storage system are permitted to discount their firm and interruptible rates without further FERC authorization down to the variable cost of performing service, provided they do not "unduly discriminate." In addition, pipelines are allowed to negotiate different rates with their customers, as described later in this section.
 
Pursuant to the NGA, changes to rates or terms and conditions of service can be proposed by a pipeline company under Section 4 of the NGA, or the existing interstate transmission and storage rates or terms and conditions of service may be challenged by a complaint filed by interested persons including customers, state agencies or the FERC under Section 5 of the NGA. Rate increases proposed by a pipeline may be allowed to become effective subject to refund and/or a period of suspension, while rates or terms and conditions of service which are the subject of a complaint under Section 5 of the NGA are subject to prospective change by the FERC. Rate increases proposed by a regulated interstate pipeline may be challenged and such increases may ultimately be rejected by the FERC. Any successful challenge against existing or proposed rates charged for EQM's transmission and storage services could have a material adverse effect on its business, financial condition, results of operations, liquidity and ability to make distributions to its unitholders.
 
EQM's interstate pipeline may also use negotiated rates which could involve rates above or below the recourse rate or rates that are subject to a different rate structure than the rates specified in EQM's interstate pipeline tariffs, provided that the affected customers are willing to agree to such rates and that the FERC has approved the negotiated rate agreement. A prerequisite for allowing the negotiated rates is that negotiated rate customers must have had the option to take service under the pipeline's recourse rates. As of December 31, 2017, approximately 89% of the system's contracted firm transportation capacity was committed under negotiated rate contracts. Some negotiated rate transactions are designed to fix the negotiated

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rate for the term of the firm transportation agreement and the fixed rate is generally not subject to adjustment for increased or decreased costs occurring during the contract term.
 
FERC regulations also extend to the terms and conditions set forth in agreements for transmission and storage services executed between interstate pipelines and their customers. These service agreements are required to conform, in all material respects, with the form of service agreements set forth in the pipeline's FERC-approved tariff. In the event that the FERC finds that an agreement, in whole or part, is materially non-conforming, it could reject the agreement, require EQM to seek modification of the agreement or require EQM to modify its applicable tariff so that the non-conforming provisions are generally available to all customers.
 
FERC Regulation of Gathering Rates and Terms of Service. While the FERC does not generally regulate the rates and terms of service over facilities determined to be performing a natural gas gathering function, it has traditionally regulated rates charged by interstate pipelines for gathering services performed on the pipeline's own gathering facilities when those gathering services are performed in connection with jurisdictional interstate transmission facilities. EQM maintains rates and terms of service in its tariff for unbundled gathering services performed on its gathering facilities in connection with the transmission service. Just as with rates and terms of service for transmission and storage services, EQM's rates and terms of services for its FERC-regulated low pressure gathering system may be challenged by complaint and are subject to prospective change by the FERC. Rate increases and changes to terms and conditions of service EQM proposes for its FERC-regulated low pressure gathering service may be protested, and such increases or changes can be delayed and may ultimately be rejected by the FERC.

Section 1(b) of the NGA exempts certain natural gas gathering facilities from regulation by the FERC under the NGA. EQM believes that its high pressure gathering systems meet the traditional tests the FERC has used to establish a pipeline's status as an exempt gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is often the subject of litigation in the industry, so the classification and regulation of these systems are subject to change based on future determinations by the FERC, the courts or the U.S. Congress.
 
Pipeline Safety and Maintenance. EQM's interstate natural gas pipeline system is subject to regulation by PHMSA. PHMSA has established safety requirements pertaining to the design, installation, testing, construction, operation and maintenance of gas pipeline facilities, including requirements that pipeline operators develop a written qualification program for individuals performing covered tasks on pipeline facilities and implement pipeline integrity management programs. These integrity management plans require more frequent inspections and other preventive measures to ensure safe operation of oil and natural gas transportation pipelines in "high consequence areas," such as high population areas or facilities that are hard to evacuate and areas of daily concentrations of people.
 
Notwithstanding the investigatory and preventative maintenance costs incurred in EQM's performance of customary pipeline management activities, EQM may incur significant additional expenses if anomalous pipeline conditions are discovered or more stringent pipeline safety requirements are implemented. For example, in April 2016, PHMSA published a notice of proposed rulemaking addressing several integrity management topics and proposing new requirements to address safety issues for natural gas transmission and gathering lines. The proposed rule would strengthen existing integrity management requirements, expand assessment and repair requirements to pipelines in areas with medium population densities and extend regulatory requirements to onshore gas gathering lines that are currently exempt. Further, in June 2016, President Obama signed the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (2016 Pipeline Safety Act), extending PHMSA's statutory mandate under prior legislation through 2019. In addition, the 2016 Pipeline Safety Act empowered PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing and also required PHMSA to develop new safety standards for natural gas storage facilities by June 2018. Pursuant to those provisions of the 2016 Pipeline Safety Act, in October 2016 and December 2016, PHMSA issued two separate Interim Final Rules that expanded the agency's authority to impose emergency restrictions, prohibitions and safety measures and strengthened the rules related to underground natural gas storage facilities, including well integrity, wellbore tubing and casing integrity. The December 2016 Interim Final Rule, relating to underground gas storage facilities, went into effect in January 2017, with a compliance deadline in January 2018. PHMSA determined, however, that it will not issue enforcement citations to any operators for violations of provisions of the December 2016 Interim Final Rule that had previously been non-mandatory provisions of American Petroleum Institute Recommended Practices 1170 and 1171 until one year after PHMSA issues a final rule. In October 2017, PHMSA formally reopened the comment period on the December 2016 Interim Final Rule in response to a petition for reconsideration, with comments due in November 2017. Additionally, in January 2017, PHMSA announced a new final rule regarding hazardous liquid pipelines, which increases the quality and frequency of tests that assess the condition of pipelines, requires operators to annually evaluate the existing protective measures in place for pipeline segments in high consequence areas (HCAs), extends certain leak detection requirements for hazardous liquid pipelines not located in HCAs,

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and expands the list of conditions that require immediate repair. However, it is unclear when or if this rule will go into effect because, on January 20, 2017, the Trump Administration requested that all regulations that had been sent to the Office of the Federal Register, but were not yet published, be immediately withdrawn for further review. Accordingly, this rule has not become effective through publication in the Federal Register. EQM is monitoring and evaluating the effect of these and other emerging requirements on its operations.

States are generally preempted by federal law in the area of pipeline safety, but state agencies may qualify to assume responsibility for enforcing federal regulations over intrastate pipelines. They may also promulgate additive pipeline safety regulations provided that the state standards are at least as stringent as the federal standards. Although many of EQM's natural gas facilities fall within a class that is not subject to integrity management requirements, EQM may incur significant costs and liabilities associated with repair, remediation, preventive or mitigation measures associated with its non-exempt transmission pipelines. The costs, if any, for repair, remediation, preventive or mitigating actions that may be determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down EQM's pipelines during the pendency of such actions, could be material.

Should EQM fail to comply with DOT regulations adopted under authority granted to PHMSA, it could be subject to penalties and fines. PHMSA has the statutory authority to impose civil penalties for pipeline safety violations up to a maximum of approximately $200,000 per day for each violation and approximately $2 million for a related series of violations. This maximum penalty authority established by statute will continue to be adjusted periodically to account for inflation. In addition, EQM may be required to make additional maintenance capital expenditures in the future for similar regulatory compliance initiatives that are not reflected in its forecasted maintenance capital expenditures.

EQM believes that its operations are in substantial compliance with all existing federal, state and local pipeline safety laws and regulations. However, the adoption of new laws and regulations, such as those proposed by PHMSA, could result in significant added costs or delays in service or the termination of projects, which could have a material adverse effect on EQM in the future.
 
Environmental Matters

General. EQM's operations are subject to stringent federal, state and local laws and regulations relating to the protection of the environment. These laws and regulations can restrict or impact EQM's business activities in many ways, such as:

requiring the acquisition of various permits to conduct regulated activities;
requiring the installation of pollution-control equipment or otherwise restricting the way EQM can handle or dispose of its wastes;
limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species; and
requiring investigatory and remedial actions to mitigate or eliminate pollution conditions caused by EQM's operations or attributable to former operations.

In addition, EQM's operations and construction activities are subject to county and local ordinances that restrict the time, place or manner in which those activities may be conducted so as to reduce or mitigate nuisance-type conditions, such as, for example, excessive levels of dust or noise or increased traffic congestion.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of investigatory and remedial obligations and the issuance of orders enjoining future operations or imposing additional compliance requirements. Also, certain environmental statutes impose strict, and in some cases joint and several, liability for the cleanup and restoration of sites where hydrocarbons or wastes have been disposed or otherwise released. Consequently, EQM may be subject to environmental liability at its currently owned or operated facilities for conditions caused by others prior to its involvement.

EQM has implemented programs and policies designed to keep its pipelines and other facilities in compliance with existing environmental laws and regulations, and EQM does not believe that its compliance with such legal requirements will have a material adverse effect on its business, financial condition, results of operations, liquidity or ability to make distributions to its unitholders. Nonetheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be significantly in excess of the amounts EQM currently anticipates. For example, in October 2015, the EPA revised the National Ambient Air Quality Standards (NAAQS)

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for ozone from 75 parts per billion for the current 8 hour primary and secondary ozone standards to 70 parts per billion for both standards. The EPA may designate the areas in which EQM operates as nonattainment areas. States that contain any areas designated as nonattainment areas will be required to develop implementation plans demonstrating how the areas will attain the applicable standard within a prescribed period of time. These plans may require the installation of additional equipment to control emissions. In addition, in May 2016, the EPA finalized rules that impose volatile organic compound and methane emissions limits (and collaterally reduce methane emissions) on certain types of compressors and pneumatic pumps, as well as requiring the development and implementation of leak monitoring plans for compressor stations. The EPA announced its intention to reconsider certain of the rules in April 2017 and has sought to stay their requirements; however, the rules remain in effect. Compliance with these or other new regulations could, among other things, require installation of new emission controls on some of EQM’s equipment, result in longer permitting timelines, and significantly increase EQM’s capital expenditures and operating costs, which could adversely impact EQM’s business. EQM tries to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. While EQM believes that it is in substantial compliance with existing environmental laws and regulations, there is no assurance that the current conditions will continue in the future.

Below is a discussion of several of the material environmental laws and regulations, as amended from time to time, that relate to EQM's business.

Hazardous Substances and Waste. CERCLA and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include current and prior owners or operators of the site where a release of hazardous substances occurred and companies that transported, disposed or arranged for the transportation or disposal of the hazardous substances found at the site. Under CERCLA, these "responsible persons" may be subject to strict and joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. EQM generates materials in the course of its ordinary operations that are regulated as "hazardous substances" under CERCLA or similar state laws and, as a result, may be jointly and severally liable under CERCLA, or such laws, for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

EQM also generates solid wastes, including hazardous wastes, which are subject to the requirements of RCRA, and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. In the ordinary course of EQM's operations, EQM generates wastes constituting solid waste and, in some instances, hazardous wastes. While certain petroleum production wastes are excluded from RCRA's hazardous waste regulations, it is possible that these wastes will in the future be designated as "hazardous wastes" and be subject to more rigorous and costly disposal requirements, which could have a material adverse effect on EQM's maintenance capital expenditures and operating expenses.

EQM owns, leases or operates properties where petroleum hydrocarbons are being or have been handled for many years. EQM has generally utilized operating and disposal practices that were standard in the industry at the time, although petroleum hydrocarbons or other wastes may have been disposed of or released on or under the properties owned, leased or operated by EQM, or on or under the other locations where these petroleum hydrocarbons and wastes have been transported for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and other wastes was not under EQM's control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, EQM could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination.

Air Emissions. The federal Clean Air Act and comparable state laws and regulations restrict the emission of air pollutants from various industrial sources, including EQM's compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that EQM obtain pre-approval for the construction or modification of certain projects or facilities, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. EQM's failure to comply with these requirements could subject it to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. EQM may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining permits and approvals for air emissions. Compliance with these

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requirements may require modifications to certain of EQM's operations, including the installation of new equipment to control emissions from EQM's compressors that could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact EQM's business.

Climate Change. Legislative and regulatory measures to address climate change and greenhouse gas (GHG) emissions are in various phases of discussion or implementation. The EPA regulates GHG emissions from new and modified facilities that are potential major sources of criteria pollutants under the Clean Air Act's Prevention of Significant Deterioration and Title V programs.

The U.S. Congress, along with federal and state agencies, have considered measures to reduce the emissions of GHGs. Legislation or regulation that restricts carbon emissions could increase EQM's cost of environmental compliance by requiring EQM to install new equipment to reduce emissions from larger facilities and/or purchase emission allowances. Climate change and GHG legislation or regulation could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals with regard to existing and new facilities or impose additional monitoring and reporting requirements. For example, in October 2015, the EPA expanded the petroleum and natural gas system sources for which annual GHG emissions reporting would be required. Additionally, several states are pursuing similar measures to regulate emissions of GHGs from new and existing sources. If implemented, such restrictions may result in additional compliance obligations with respect to, or taxes on the release, capture and use of GHGs that could have an adverse effect on EQM's operations. Conversely, legislation or regulation that sets a price on or otherwise restricts carbon emissions could also benefit EQM by increasing demand for natural gas because the combustion of natural gas results in substantially fewer carbon emissions per Btu of heat generated than other fossil fuels such as coal. The effect on EQM of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.

Water Discharges. The federal Clean Water Act and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants or dredged and fill material into state waters as well as waters of the United States, including adjacent wetlands. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of permits issued by the EPA, the Army Corps of Engineers or an analogous state agency. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws. EQM believes that compliance with existing permits and foreseeable new permit requirements will not have a material adverse effect on its business, financial condition, results of operations, liquidity or ability to make distributions to its unitholders.

National Environmental Policy Act. The construction of interstate natural gas transportation pipelines pursuant to the NGA requires authorization from the FERC. FERC actions are subject to the National Environmental Policy Act (NEPA). NEPA requires federal agencies, such as the FERC, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will either prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project or, if necessary, a more detailed Environmental Impact Statement that may be made available for public review and comment. Any proposed plans for future construction activities that require FERC authorization will be subject to the requirements of NEPA. This process has the potential to significantly delay or limit, and increase the cost of, development of midstream infrastructure.

Endangered Species Act. The federal Endangered Species Act (ESA) restricts activities that may adversely affect endangered and threatened species or their habitats. Federal agencies are required to ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. While some of EQM's facilities are located in areas that are designated as habitats for endangered or threatened species, EQM believes that it is in substantial compliance with the ESA. The designation of previously unprotected species as being endangered or threatened, or the designation of previously unprotected areas as a critical habitat for such species, could cause EQM to incur additional costs, result in delays in construction of pipelines and facilities, or cause EQM to become subject to operating restrictions in areas where the species are known to exist. For example, the U.S. Fish and Wildlife Service continues to receive hundreds of petitions to consider listing additional species as endangered or threatened and is being regularly sued or threatened with lawsuits to address these petitions. Some of these legal actions may result in the listing of species located in areas in which EQM operates.

Employee Health and Safety. EQM is subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (OSHA) and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community "right-to-know" regulations and

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comparable state laws and regulations require that information be maintained concerning hazardous materials used or produced in EQM's operations and that this information be provided to employees, state and local government authorities and citizens. EQM believes that it is in substantial compliance with all applicable laws and regulations relating to worker health and safety.

Seasonality

Weather impacts natural gas demand for power generation and heating purposes. Peak demand for natural gas typically occurs during the winter months as a result of the heating load.

Title to Properties and Rights-of-Way
 
EQM's real property falls into two categories: (i) parcels that it owns in fee and (ii) parcels in which its interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for EQM's operations. Certain lands on which EQM's pipelines and facilities are located are owned by EQM in fee title, and it believes that it has satisfactory title to these lands. The remainder of the lands on which EQM's pipelines and facilities are located are held by EQM pursuant to surface leases or easements between EQM, as lessee or grantee, and the respective fee owners of the lands, as lessors or grantors. EQM has held, leased or owned many of these lands for many years without any material challenge known to EQM relating to the title to the land upon which the assets are located, and EQM believes that it has satisfactory leasehold estates, easement interests or fee ownership to such lands. EQM believes that it has satisfactory title to all of its material leases, easements, rights-of-way, permits and licenses, and EQM has no knowledge of any material challenge to its title to such assets or their underlying fee title.
 
There are, however, certain lands within EQM's storage pools as to which it may not currently have vested real property rights, some of which are subject to ongoing acquisition negotiations or condemnation proceedings. In accordance with EQM's FERC certificates, the geological formations within which its permitted storage facilities are located cannot be used by third parties in any way that would detrimentally affect its storage operations, and EQM has the power of eminent domain with respect to the acquisition of necessary real property rights to use such storage facilities.
 
Insurance
 
EQM generally shares insurance coverage with EQT. EQM reimburses EQT for the cost of the insurance pursuant to the terms of EQM's omnibus agreement with EQT. The insurance program includes excess liability insurance, auto liability insurance, workers' compensation insurance and property insurance. In addition, EQM has procured separate general liability and directors and officers liability policies. All insurance coverage is in amounts management believes to be reasonable and appropriate.

Facilities
 
EQT leases its corporate offices in Pittsburgh, Pennsylvania. Pursuant to the omnibus agreement with EQT, EQM pays a proportionate share of EQT's costs to lease the building.
 
Employees
 
EQM does not have any employees. EQM is managed by the directors and officers of the EQM General Partner. All executive management personnel of the EQM General Partner are officers of EQT and devote the portion of their time to EQM's business and affairs that is required to manage and conduct its operations. The daily business operations of EQM are conducted by employees of EQT and its subsidiaries. Under the terms of the omnibus agreement with EQT, EQM reimburses EQT for the provision of general and administrative services for its benefit, for direct expenses incurred by EQT on EQM's behalf and for expenses allocated to EQM as a result of it being a public entity. Additionally, EQM has a secondment agreement with EQT whereby EQT and its subsidiaries provide seconded employees to perform certain operating and other services with respect to EQM’s business. Prior to the secondment agreement, EQM had an operation and management services agreement with EQT whereby EQT and its subsidiaries provided certain operational and management services with respect to EQM's business.
 

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Availability of Reports
 
EQM makes certain filings with the SEC, including its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments and exhibits to those reports, available free of charge through its website, http://www.eqtmidstreampartners.com, as soon as reasonably practicable after the date they are filed with, or furnished to, the SEC.  The filings are also available at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330.  These filings are also available on the internet at http://www.sec.gov.
 
Composition of Segment Operating Revenues

Presented below are operating revenues by segment as a percentage of total operating revenues of EQM.
 
 
For the year ended December 31,
 
 
2017
 
2016
 
2015
Gathering operating revenues
 
54
%
 
54
%
 
53
%
Transmission operating revenues
 
46
%
 
46
%
 
47
%
 
Financial Information about Segments
 
See Note 4 to the consolidated financial statements for financial information by business segment including, but not limited to, revenues from external customers, operating income and total assets, which information is incorporated herein by reference.
 
Jurisdiction and Year of Formation
 
EQT Midstream Partners, LP is a Delaware limited partnership formed in January 2012.
 
Financial Information about Geographic Areas
 
All of EQM's assets and operations are located in the continental United States.

Item 1A. Risk Factors

In addition to the other information contained in this Annual Report on Form 10-K, the following risk factors should be considered in evaluating our business and future prospects.  Please note that additional risks not presently known to us or that are currently considered immaterial may also have a negative impact on our business and operations.  If any of the events or circumstances described below actually occurs, our business, financial condition, results of operations, liquidity or ability to make distributions could suffer and the trading price of our common units could decline.
 
Risks Inherent in Our Business
 
We depend on EQT for a substantial majority of our revenues and future growth. Therefore, we are indirectly subject to the business risks of EQT. We have no control over EQT's business decisions and operations, and EQT is under no obligation to adopt a business strategy that favors us.
 
Historically, we have provided a substantial percentage of our natural gas gathering, transmission and storage services to EQT. EQT accounted for approximately 73% of our revenues for the year ended December 31, 2017. We expect to derive a substantial majority of our revenues from EQT for the foreseeable future. Therefore, any event, whether in our areas of operations or otherwise, that adversely affects EQT's production, financial condition, leverage, results of operations or cash flows may adversely affect our ability to sustain or increase cash distributions to our unitholders. Accordingly, we are indirectly subject to the business risks of EQT, including the following:
 
natural gas price volatility or a sustained period of lower commodity prices may have an adverse effect on EQT's drilling operations, revenue, profitability, future rate of growth and liquidity;
a reduction in or slowing of EQT's anticipated drilling and production schedule, which would directly and adversely impact demand for our services;
infrastructure capacity constraints and interruptions;
risks associated with the operation of EQT's wells, pipelines and facilities, including potential environmental liabilities;

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the availability of capital on a satisfactory economic basis to fund EQT's operations;
EQT's ability to identify exploration, development and production opportunities based on market conditions;
uncertainties inherent in projecting future rates of production;
EQT's ability to develop additional reserves that are economically recoverable, to optimize existing well production and to sustain production;
adverse effects of governmental and environmental regulation, changes in tax laws and negative public perception regarding EQT's operations;
the loss of key personnel; and
risk associated with cyber security threats.
 
EQT may reduce its capital spending in the future based on commodity prices or other factors. Unless we are successful in attracting significant unaffiliated third party customers, our ability to maintain or increase the capacity subscribed and volumes transported under service arrangements on our gathering and transmission and storage systems will be dependent on receiving consistent or increasing commitments from EQT. While EQT has dedicated certain acreage to, and entered into long-term firm gathering and transmission contracts on, our systems, it may determine in the future that drilling in areas outside of our current areas of operations is strategically more attractive to it and it is under no contractual obligation to maintain its production dedicated to us. EQT also has production assets and acreage that is dedicated to systems owned by RMP, and may in the future acquire production assets or acreage that are dedicated to other third party systems. A reduction in the capacity subscribed or volumes transported or gathered on our systems by EQT could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders. In addition, EQT has announced that its board of directors has formed a committee to evaluate options to address EQT's sum-of-the-parts discount, with the results of such review to be announced by the end of March 2018. There can be no assurance regarding the outcome of this review or how such outcome may involve or affect us.

Please see Item 1A, "Risk Factors" in EQT's Annual Report on Form 10-K for the year ended December 31, 2017 (which is not, and shall not be deemed to be, incorporated by reference herein) for a full discussion of the risks associated with EQT's business.
 
We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to EQT and its affiliates, to enable us to pay quarterly cash distributions to our unitholders.
 
In order to pay the announced fourth quarter 2017 distribution of $1.025 per unit, or $4.100 per unit on an annualized basis, we will require available cash (as defined in Note 7 to the consolidated financial statements) of approximately $125.9 million per quarter, or $503.6 million per year, based on the number of common and general partner units and the incentive distribution rights (IDRs) outstanding at December 31, 2017. We may not have sufficient available cash each quarter to enable us to pay the quarterly cash distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

the rates we charge for our gathering, transmission and storage services;
the level of firm gathering, transmission and storage capacity sold and volumes of natural gas we gather, transport and store for our customers;
regional, domestic and foreign supply and perceptions of supply of natural gas; the level of demand and perceptions of demand in our end-use markets; and actual and anticipated future prices of natural gas and other commodities (and the volatility thereof), which may impact our ability to renew and replace firm gathering, transmission and storage agreements;
the effect of seasonal variations in temperature on the amount of natural gas that we gather, transport and store;
the level of competition from other midstream energy companies in our geographic markets;
the creditworthiness of our customers;
restrictions contained in our joint venture agreements;
the level of our operating, maintenance and general and administrative costs;
regulatory action affecting the supply of, or demand for, natural gas, the rates we can charge on our assets, how we contract for services, our existing contracts, our operating costs or our operating flexibility; and
prevailing economic conditions.
 
In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:
 
the level and timing of capital expenditures we make;

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the level of our operating and general and administrative expenses, including reimbursements to our general partner and its affiliates, including EQT, for services provided to us;
the cost of acquisitions, if any;
our debt service requirements and other liabilities;
fluctuations in our working capital needs;
our ability to borrow funds and access capital markets on satisfactory terms;
restrictions on distributions contained in our debt agreements;
the amount of cash reserves established by our general partner; and
other business risks affecting our cash levels.
 
Our natural gas gathering, transmission and storage services are subject to extensive regulation by federal, state and local regulatory authorities. Changes or additional regulatory measures adopted by such authorities could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make distributions.
 
Our interstate natural gas transmission and storage operations are regulated by the FERC under the NGA, the NGPA and the Energy Policy Act of 2005. Certain portions of our gathering operations are also rate-regulated by the FERC in connection with our interstate transmission operations. Our FERC-regulated systems operate under tariffs approved by the FERC that establish rates, cost recovery mechanisms and terms and conditions of service to our customers. Generally, the FERC's authority extends to:
 
rates and charges for our natural gas transmission and storage and FERC-regulated gathering services;
certification and construction of new interstate transmission and storage facilities;
abandonment of interstate transmission and storage services and facilities;
maintenance of accounts and records;
relationships between pipelines and certain affiliates;
terms and conditions of services and service contracts with customers;
depreciation and amortization policies;
acquisitions and dispositions of interstate transmission and storage facilities; and
initiation and discontinuation of interstate transmission and storage services.
 
Interstate pipelines may not charge rates or impose terms and conditions of service that, upon review by the FERC, are found to be unjust and unreasonable or unduly discriminatory. The recourse rate that may be charged by our interstate pipeline for its transmission and storage services is established through the FERC's ratemaking process. The maximum applicable recourse rate and terms and conditions for service are set forth in our FERC-approved tariffs.

Pursuant to the NGA, existing interstate transmission and storage rates and terms and conditions of service may be challenged by complaint and are subject to prospective change by the FERC. Additionally, rate increases and changes to terms and conditions of service proposed by a regulated interstate pipeline may be protested and such increases or changes can be delayed and may ultimately be rejected by the FERC. We currently hold authority from the FERC to charge and collect (i) "recourse rates," which are the maximum rates an interstate pipeline may charge for its services under its tariff, (ii) "discount rates," which are rates below the "recourse rates" and above a minimum level, provided they do not "unduly discriminate", (iii) "negotiated rates," which involve rates above or below the "recourse rates," provided that the affected customers are willing to agree to such rates and that the FERC has approved the negotiated rate agreement, and (iv) market-based rates for some of our storage services from which we derive a small portion of our revenues. As of December 31, 2017, approximately 89% of our system's contracted firm transmission capacity was committed under such "negotiated rate" contracts, rather than recourse, discount or market rate contracts. There can be no guarantee that we will be allowed to continue to operate under such rate structures for the remainder of those assets' operating lives. Any successful challenge against rates charged for our transmission and storage services could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
 
While the FERC does not generally regulate the rates and terms of service over facilities determined to be performing a natural gas gathering function, the FERC has traditionally regulated rates charged by interstate pipelines for gathering services performed on the pipeline's own gathering facilities when those gathering services are performed in connection with jurisdictional interstate transmission facilities. We maintain rates and terms of service in our tariff for unbundled gathering services performed on a portion of our gathering facilities that are connected to our transmission and storage system. Just as with rates and terms of service for transmission and storage services, our rates and terms of services for our FERC-regulated gathering services may be challenged by complaint and are subject to prospective change by the FERC. Rate increases and

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changes to terms and conditions of service which we propose for our FERC-regulated gathering services may be protested, and such increases or changes can be delayed and may ultimately be rejected by the FERC.
 
The FERC's jurisdiction extends to the certification and construction of interstate transmission and storage facilities, including, but not limited to, acquisitions, facility maintenance, expansions, and abandonment of facilities and services. While the FERC exercises jurisdiction over the rates and terms of service for our FERC-regulated gathering services, these gathering facilities are not subject to the FERC's certification and construction authority. Prior to commencing construction of new or existing interstate transmission and storage facilities, an interstate pipeline must obtain a certificate authorizing the construction, or file to amend its existing certificate, from the FERC. Typically, a significant expansion project requires review by a number of governmental agencies, including state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any agency's delay in the issuance of, or refusal to issue, authorizations or permits for one or more of these projects may mean that we will not be able to pursue these projects or that they will be constructed in a manner or with capital requirements that we did not anticipate. Such delays, refusals or resulting modifications to projects could materially and negatively impact the revenues and costs expected from these projects or cause us to abandon planned projects.
 
FERC regulations also extend to the terms and conditions set forth in agreements for transmission and storage services executed between interstate pipelines and their customers. These service agreements are required to conform, in all material respects, with the forms of service agreements set forth in the pipeline's FERC-approved tariff. Non-conforming agreements must be filed with, and accepted by, the FERC. In the event that the FERC finds that an agreement is materially non-conforming, in whole or in part, it could reject the agreement or require us to seek modification, or alternatively require us to modify our tariff so that the non-conforming provisions are generally available to all customers.
 
Under current policy, the FERC permits interstate pipelines to include an income tax allowance in the cost-of-service used as the basis for calculating their regulated rates. For pipelines owned by partnerships or limited liability companies taxed as partnerships for federal income tax purposes, the tax allowance will reflect the actual or potential income tax liability on the FERC-jurisdictional income attributable to all partnership or limited liability company interests if the ultimate owner of the interest has an actual or potential income tax liability on such income. The FERC could also require a reduction in the allowance to account for the reduced income tax rates enacted on December 22, 2017 by the law known as the Tax Cuts and Jobs Act of 2017. The FERC will determine, on a case-by-case basis, whether the owners of an interstate pipeline have such actual or potential income tax liability. In a future rate case, we may be required to demonstrate the extent to which inclusion of an income tax allowance in the applicable cost-of-service is permitted under the current income tax allowance policy. In addition, the FERC's income tax allowance policy is frequently the subject of challenge, and we cannot predict whether the FERC or a reviewing court will alter the existing policy. In July 2016, in United Airlines, Inc. v. FERC, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated a pair of FERC orders to the extent they permitted an interstate refined petroleum products pipeline owned by a master limited partnership to include an income tax allowance in its cost-of-service-based rates. The D.C. Circuit held that the FERC had failed to demonstrate that the inclusion of an income tax allowance in the pipeline's rates would not lead to an over-recovery of costs attributable to regulated service. The D.C. Circuit instructed the FERC on remand to fashion a remedy to ensure that the pipeline's rates do not allow it to over-recover its costs. In response to the D.C. Circuit's remand, in December 2016, the FERC issued a Notice of Inquiry seeking comments regarding how to address any potential double recovery resulting from the FERC's current income tax allowance and rate of return policies. Initial comments were filed in March 2017 with reply comments filed in April 2017. We cannot currently predict when the FERC will issue an order in the Notice of Inquiry proceeding or what action the FERC may take in any such order. The outcome of the Notice of Inquiry proceeding could affect the FERC's income tax allowance policy for cost-based or recourse rates charged by regulated pipelines on a prospective basis. If the FERC's policy were to change and if the FERC were to disallow all or a substantial portion of our pipelines' income tax allowance, our regulated rates, and therefore our revenues and ability to make quarterly cash distributions to our unitholders, could be materially adversely affected.
 
The FERC may not continue to pursue its approach of pro-competitive policies as it considers matters such as interstate pipeline rates and rules and policies that may affect rights of access to natural gas transmission capacity and transmission and storage facilities.
 
Section 1(b) of the NGA exempts certain natural gas gathering facilities from regulation by the FERC under the NGA. We believe that our high pressure natural gas gathering pipelines meet the traditional tests the FERC has used to establish a pipeline's status as an exempt gatherer not subject to regulation as a natural gas company, although the FERC has not made a formal determination with respect to the jurisdictional status of those facilities. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is often the subject of litigation within the industry, so the classification and regulation of our high pressure gathering systems are subject to change based on future determinations by the FERC, the courts or the U.S. Congress.

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Failure to comply with applicable provisions of the NGA, the NGPA, federal pipeline safety laws and certain other laws, as well as with the regulations, rules, orders, restrictions and conditions associated with these laws, could result in the imposition of administrative and criminal remedies and civil penalties. For example, the FERC is authorized to impose civil penalties of up to approximately $1.2 million per violation, per day for violations of the NGA, the NGPA or the rules, regulations, restrictions, conditions and orders promulgated under those statutes. This maximum penalty authority established by statute will continue to be adjusted periodically for inflation.
 
In addition, future federal, state or local legislation or regulations under which we will operate our natural gas gathering, transmission and storage businesses may have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
 
Any significant decrease in production of natural gas in our areas of operation could adversely affect our business and operating results and reduce our cash available to make distributions.
 
Our business is dependent on the continued availability of natural gas production and reserves in our areas of operation. A sustained low price environment for natural gas or regulatory limitations could adversely affect development of additional reserves and production that is accessible by our pipeline and storage assets. Production from natural gas wells will naturally decline over time. The amount of natural gas reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Additionally, producers may determine in the future that drilling activities in areas outside of our current areas of operations are strategically more attractive to them due to the price environment for natural gas or other reasons. A reduction in the natural gas volumes supplied by EQT or other third party producers could result in reduced throughput on our systems and adversely impact our ability to grow our operations and increase quarterly cash distributions to our unitholders. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas gathered, transported and stored on our systems and cash flows associated therewith, our customers must continually access additional reserves of natural gas.
 
The primary factors affecting our ability to obtain non-dedicated sources of natural gas include the level of successful drilling activity near our systems and our ability to compete for volumes from successful new wells. While EQT has dedicated production from certain of its leased properties to us, we have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our gathering systems or the rate at which production from a well declines. In addition, we have no control over EQT or other producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, prevailing and projected energy prices, demand for hydrocarbons, levels of reserves, the producer's contractual obligations to us and other midstream companies, geological considerations, environmental or other governmental regulations, the availability of drilling permits, the availability of drilling rigs and crews, and other production and development costs.
 
Fluctuations in energy prices can also greatly affect the development of new natural gas reserves. In general terms, the prices of natural gas, oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. For example, the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $3.77 per MMBtu to a low of $1.49 per MMBtu from January 1, 2016 through December 31, 2017. Factors affecting natural gas prices include worldwide economic conditions; weather conditions and seasonal trends; the levels of domestic production and consumer demand; new exploratory finds of natural gas; the availability of imported, and the ability to export, natural gas and LNG; the availability of transportation systems with adequate capacity; the volatility and uncertainty of regional basis differentials and premiums; the price and availability of alternative fuels; the effects of energy conservation measures; the nature and extent of governmental regulation and taxation; and the anticipated future prices of natural gas, oil, LNG and other commodities. Low natural gas prices, particularly in the Appalachian Basin, have had a negative impact on exploration, development and production activity and, if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our systems. Because of these factors, even if new natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. Moreover, EQT may not develop the acreage it has dedicated to us. If reductions in drilling activity result in our inability to maintain levels of contracted capacity and throughput, it could reduce our revenue and impair our ability to make quarterly cash distributions to our unitholders.
 
We do not obtain independent evaluations of natural gas reserves connected to our systems. Accordingly, we do not have independent estimates of total reserves connected to our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our systems are less than we anticipate, or the timeline for the development of reserves is longer than we anticipate, and we are unable to secure additional sources of natural gas, there could

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be a material adverse effect on our business, results of operations, financial condition, liquidity and ability to make quarterly cash distributions to our unitholders.

If new supplies of natural gas are not obtained to replace the natural decline in volumes from existing supply basins in our area of operation, or if natural gas supplies are diverted to serve other markets, the overall volume of natural gas gathered, transported and stored on our systems would decline, which could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
 
We may not be able to increase our third party throughput and resulting revenue due to competition and other factors, which could limit our ability to grow and extend our dependence on EQT.
 
Part of our growth strategy includes diversifying our customer base by identifying opportunities to offer services to third parties other than EQT. For the years ended December 31, 2017, 2016 and 2015, EQT accounted for approximately 89%, 96% and 96%, respectively, of our gathering revenues, 59%, 56% and 53%, respectively, of our transmission revenues, 2%, 1% and 1%, respectively, of our storage revenues, and 73%, 75% and 73%, respectively, of our total operating revenues. Our ability to increase our third party subscribed capacity and throughput and resulting revenue is subject to numerous factors beyond our control, including competition from third parties and the extent to which we have available capacity when third party shippers require it. To the extent that we lack available capacity on our systems for third party volumes, we may not be able to compete effectively with third party systems for additional natural gas production in our areas of operation.
 
We have historically provided gathering, transmission and storage services to third parties on only a limited basis and may not be able to attract material third party service opportunities. Our efforts to attract new unaffiliated customers may be adversely affected by our relationship with EQT and our desire to provide services pursuant to long-term firm contracts. Our potential customers may prefer to obtain services under other forms of contractual arrangements under which we would be required to assume direct commodity exposure. In addition, we must continue to improve our reputation among our potential customer base for providing high quality service to successfully attract unaffiliated third parties.
 
We are exposed to the credit risk of our counterparties in the ordinary course of our business.
 
We are exposed to the risk of loss resulting from the nonpayment and/or nonperformance of our customers, suppliers, joint venture partners and other counterparties. We extend credit to our customers, including EQT as our largest customer, as a normal part of our business. While we have established credit policies, including assessing the creditworthiness of our customers as permitted by our FERC-approved natural gas tariffs, and requiring appropriate terms or credit support from them based on the results of such assessments, we may not have adequately assessed the creditworthiness of our existing or future customers. We cannot predict the extent to which EQT's and our other counterparties' businesses would be impacted if commodity prices decline, commodity prices are depressed for a sustained period of time, or other conditions in the energy industry were to deteriorate, nor can we estimate the impact such conditions would have on our counterparties' abilities to perform under their gathering, transmission and storage agreements with us. The low commodity price environment has negatively impacted natural gas producers causing some producers in the industry significant economic stress including, in certain cases, to file for bankruptcy protection or to renegotiate contracts. To the extent one or more of our customers is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. Any resulting nonpayment and/or nonperformance by our counterparties could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
 
Increased competition from other companies that provide gathering, transmission and storage services, or from alternative fuel sources, could have a negative impact on the demand for our services, which could adversely affect our financial results.

Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. Our systems compete primarily with other interstate and intrastate pipelines and storage facilities in the gathering, transmission and storage of natural gas. Some of our competitors have greater financial resources and may now, or in the future, have access to greater supplies of natural gas than we do. Some of these competitors may expand or construct gathering systems and transmission and storage systems that would create additional competition for the services we provide to our customers. In addition, our customers may develop their own gathering, transmission or storage services instead of using ours. Moreover, none of EQT, EQGP, RMP or any of their respective affiliates is limited in its ability to compete with us, and a portion of EQT's acreage is dedicated to RMP.
 

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The policies of the FERC promoting competition in natural gas markets are having the effect of increasing the natural gas transmission and storage options for our traditional customer base. As a result, we could experience some "turnback" of firm capacity as existing agreements expire. If we are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, we may have to bear the costs associated with the turned back capacity. Increased competition could reduce the volumes of natural gas transported or stored on our system or, in cases where we do not have long-term firm contracts, could force us to lower our transmission or storage rates.
 
Further, natural gas as a fuel competes with other forms of energy available to end-users, including coal, liquid fuels and renewable and alternative energy. Increased demand for such forms of energy at the expense of natural gas could lead to a reduction in demand for natural gas gathering, transmission and storage services.
 
All of these competitive pressures could make it more difficult for us to retain our existing customers and/or attract new customers as we seek to expand our business, which could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders. In addition, competition could intensify the negative impact of factors that decrease demand for natural gas in the markets served by our systems, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.
 
If third party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport or process natural gas, our revenues and cash available to make distributions to our unitholders could be adversely affected.
 
We depend on third party pipelines and other facilities that provide receipt and delivery options to and from our transmission and storage system. For example, our transmission and storage system interconnects with the following interstate pipelines: Texas Eastern, Dominion Transmission, Columbia Gas Transmission, Tennessee Gas Pipeline Company, Rockies Express Pipeline LLC and National Fuel Gas Supply Corporation, as well as multiple distribution companies. Similarly, our gathering systems have multiple delivery interconnects to multiple interstate pipelines. In the event that our access to such systems was impaired, the amount of natural gas that our gathering systems can gather and transport would be adversely affected, which could reduce revenues from our gathering activities. Because we do not own these third party pipelines or facilities, their continuing operation is not within our control. If these or any other pipeline connections or facilities were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to operate efficiently and continue shipping natural gas to end markets could be restricted, thereby reducing our revenues. Any temporary or permanent interruption at any key pipeline interconnect or facility could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
 
Certain of the services we provide on our transmission and storage system are subject to long-term, fixed-price "negotiated rate" contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts.
 
It is possible that costs to perform services under "negotiated rate" contracts will exceed the negotiated rates we have agreed to provide to our customers. If this occurs, it could decrease the cash flow realized by our systems and, therefore, the cash we have available for distribution to our unitholders. Under FERC policy, a regulated service provider and a customer may mutually agree to a "negotiated rate," and that contract must be filed with and accepted by the FERC. As of December 31, 2017, approximately 89% of our contracted transmission firm capacity was subscribed under such "negotiated rate" contracts. Unless the parties to these "negotiated rate" contracts agree otherwise, the contracts generally may not be adjusted to account for increased costs which could be caused by inflation or other factors relating to the specific facilities being used to perform the services.
 
We may not be able to renew or replace expiring contracts at favorable rates or on a long-term basis.
 
Our primary exposure to market risk occurs at the time our existing contracts expire and are subject to renegotiation and renewal. Including contracts associated with expected future capacity from expansion projects that are not yet fully constructed but for which we have entered into firm contracts, our firm gathering contracts had a weighted average remaining term of approximately 8 years and firm transmission and storage contracts had a weighted average remaining term of approximately 15 years as of December 31, 2017. The extension or replacement of existing contracts, including our contracts with EQT, depends on a number of factors beyond our control, including:
 

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the level of existing and new competition to provide services to our markets;
the macroeconomic factors affecting natural gas economics for our current and potential customers;
the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;
the extent to which the customers in our markets are willing to contract on a long-term basis; and
the effects of federal, state or local regulations on the contracting practices of our customers.
 
Any failure to extend or replace a significant portion of our existing contracts, or extending or replacing them at unfavorable or lower rates, could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
 
If the tariffs governing the services we provide are successfully challenged, we could be required to reduce our tariff rates, which could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
 
Rate payers, the FERC or other interested stakeholders, such as state regulatory agencies, may challenge our rates offered to individual customers or the terms and conditions of service included in our tariffs. We do not have an agreement in place that would prohibit customers, including EQT or its affiliates, from challenging our tariffs. If any challenge were successful, among other things, the rates that we charge on our systems could be reduced. Successful challenges could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
 
If we do not complete expansion projects, our future growth may be limited.

A significant component of our growth strategy is to continue to grow the cash distributions on our units by expanding our business. Our ability to grow depends, in part, upon our ability to complete expansion projects that result in an increase in the cash we generate. We may be unable to complete successful, accretive expansion projects for many reasons, including, but not limited to, the following:

an inability to identify attractive expansion projects;
an inability to obtain necessary rights-of-way or permits or other government approvals, including approvals by regulatory agencies;
an inability to successfully integrate the infrastructure we build;
an inability to raise financing for expansion projects on economically acceptable terms;
incorrect assumptions about volumes, revenues and costs, including potential growth; or
an inability to secure adequate customer commitments to use the newly expanded facilities.

Expanding our business by constructing new midstream assets subjects us to risks.
 
Organic and greenfield growth projects are a significant component of our growth strategy. The development and construction of pipelines and storage facilities involves numerous regulatory, environmental, political and legal uncertainties beyond our control and will require the expenditure of significant amounts of capital. The development and construction of pipelines and storage facilities expose us to construction risks such as the failure to meet affiliate and third party contractual requirements, delays caused by landowners or advocacy groups opposed to the oil and gas industry, environmental hazards, the performance of third party contractors, the lack of available skilled labor, equipment and materials and the inability to obtain necessary rights-of-way or approvals and permits from regulatory agencies on a timely basis or at all. These types of projects may not be completed on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase for some time after completion of a particular project. For instance, we will be required to pay construction costs generally as they are incurred but construction will typically occur over an extended period of time, and we will not receive material increases in revenues until the project is placed into service. Moreover, we may construct facilities to capture anticipated future growth in production and/or demand in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
 
Certain of our internal growth projects may require regulatory approval from federal, state and local authorities prior to construction, including any extensions from or additions to our transmission and storage system. The approval process for storage and transportation projects has become increasingly challenging, due in part to state and local concerns related to exploration and production and gathering activities in new production areas, including the Marcellus, Upper Devonian and Utica Shales, and negative public perception regarding the oil and gas industry. Such authorization may not be granted or, if granted, such authorization may include burdensome or expensive conditions.

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If we are unable to make acquisitions on economically acceptable terms, our future growth may be limited, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per unit basis.
     
Our ability to grow depends, in part, on our ability to make acquisitions that increase our cash generated from operations on a per unit basis. The acquisition component of our strategy is based, in large part, on our expectation of ongoing divestitures of midstream energy assets by industry participants. A material decrease in such divestitures would limit our opportunities for future acquisitions and could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
 
If we are unable to make accretive acquisitions, whether because, among other reasons, (i) we are unable to identify attractive acquisition opportunities, (ii) we are unable to negotiate acceptable purchase contracts, (iii) we are unable to obtain financing for acquisitions on economically acceptable terms, (iv) we are outbid by competitors, some of which are substantially larger than us and have greater financial resources or (v) we are unable to obtain necessary governmental or third party consents, then our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis.
 
Any acquisition involves potential risks, including, among other things:

mistaken assumptions about volumes, revenues and costs, including synergies and potential growth;
an inability to secure adequate customer commitments to use the acquired systems or facilities;
an inability to integrate successfully the assets or businesses we acquire;
the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;
the diversion of management's and employees' attention from other business concerns; and
unforeseen difficulties operating in new geographic areas or business lines.

If any acquisition fails to be accretive to our distributable cash flow per unit, it could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.

If we are unable to obtain needed capital or financing on satisfactory terms to fund expansions of our asset base, our ability to make quarterly cash distributions may be diminished or our financial leverage could increase. We do not have any commitment with any of our affiliates to provide any direct or indirect financial assistance to us.
 
In order to expand our asset base and complete our announced expansion projects described in this Annual Report on Form 10-K, including the MVP project, we will need to make significant expansion capital expenditures. If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and may be unable to maintain or raise the level of our quarterly cash distributions.

In order to fund our expansion capital expenditures, we will be required to use cash from our operations, incur borrowings or sell additional common units or other limited partner interests. Using cash from operations will reduce distributable cash flow to our common unitholders. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering, the covenants in our debt agreements, general economic conditions and contingencies and uncertainties that are beyond our control. Even if we are successful in obtaining funds for expansion capital expenditures through equity or debt financings, the terms thereof could limit our ability to pay distributions to our common unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate. If funding is not available to us when needed, or is available only on unfavorable terms, we may be unable to execute our business plans, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders. We do not have any commitment with our general partner or other affiliates, including EQT and EQGP, to provide any direct or indirect financial assistance to us. In October 2016, we entered into a $500 million, 364-day, uncommitted revolving loan agreement with EQT (the 364-Day Facility); however, any loans from EQT under the 364-Day Facility are at the sole discretion of EQT, and EQT is under no obligation, fiduciary or otherwise, to make such funds available to us.
 

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We are subject to numerous hazards and operational risks.
 
Our business operations are subject to all of the inherent hazards and risks normally incidental to the gathering, transmission and storage of natural gas. These operating risks include, but are not limited to:
 
damage to pipelines, facilities, equipment and surrounding properties caused by hurricanes, earthquakes, tornadoes, floods, fires, landslides and other natural disasters and acts of sabotage and terrorism;
inadvertent damage from construction, vehicles, and farm and utility equipment;
uncontrolled releases of natural gas and other hydrocarbons;
leaks, migrations or losses of natural gas as a result of the malfunction of equipment or facilities and, with respect to storage assets, as a result of undefined boundaries, geologic anomalies, natural pressure migration and wellbore migration;
ruptures, fires and explosions;
pipeline freeze offs due to cold weather; and
other hazards that could also result in personal injury and loss of life, pollution to the environment and suspension of operations.
 
These risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations, regulatory investigations and penalties and substantial losses to us. The location of certain segments of our systems in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from these risks. In spite of any precautions taken, an event such as those described above could cause considerable harm to people or property and could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders. Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on segments of our systems. Potential customer impacts arising from service interruptions on segments of our systems could include limitations on our ability to satisfy customer requirements, obligations to provide reservation charge credits to customers in times of constrained capacity, and solicitation of our existing customers by others for potential new projects that would compete directly with our existing services. Such circumstances could adversely impact our ability to meet contractual obligations and retain customers, with a resulting negative impact on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
 
We do not insure against all potential losses and could be seriously harmed by unexpected liabilities.
 
We are not fully insured against all risks inherent in our business, including environmental accidents that might occur. In addition, we do not maintain business interruption insurance of the types and in amounts necessary to cover all possible risks of loss. The occurrence of any operating risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
 
EQT currently maintains excess liability insurance that covers EQT's and its affiliates', including our, legal and contractual liabilities arising out of bodily injury, personal injury or property damage, including resulting loss of use, to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability but excludes: release of pollutants subsequent to their disposal; release of substances arising from the combustion of fuels that result in acidic deposition; and testing, monitoring, clean-up, containment, treatment or removal of pollutants from property owned, occupied by, rented to, used by or in the care, custody or control of EQT and its affiliates, including us.

EQT also maintains coverage for itself and its affiliates, including us, for physical damage to assets and resulting business interruption, including damage caused by terrorist acts.
 
All of EQT's insurance is subject to deductibles. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. We may not be able to maintain or obtain insurance of the types and in the amounts we desire at reasonable rates, and we may elect to self-insure a portion of our asset portfolio. The insurance coverage we do obtain may contain large deductibles or fail to cover certain hazards or cover all potential losses. In addition, we share insurance coverage with EQT, for which we reimburse EQT pursuant to the terms of the omnibus agreement. To the extent EQT experiences covered losses under the insurance policies, the limit of our coverage for potential losses may be reduced.
 

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We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.
 
Our operations are regulated extensively at the federal, state and local levels.  Laws, regulations and other legal requirements have increased the cost to plan, design, install, operate and abandon gathering and transmission systems and pipelines.  Environmental, health and safety legal requirements govern discharges of substances into the air, water and ground; the management and disposal of hazardous substances and wastes; the clean-up of contaminated sites; groundwater quality and availability; plant and wildlife protection; locations available for pipeline construction; environmental impact studies and assessments prior to permitting; restoration of properties after construction or operations are completed; pipeline safety (including replacement requirements); and work practices related to employee health and safety.  Compliance with the laws, regulations and other legal requirements applicable to our business, including delays in obtaining permits or other government approvals, may increase our costs of doing business, result in delays or restrictions in the performance of operations due to the need to obtain additional or more detailed permits or other governmental approvals or even cause us not to pursue a project.  For example, the U.S. Fish and Wildlife Service continues to receive hundreds of petitions to consider listing of additional species as endangered or threatened and is being regularly sued or threatened with lawsuits to address these petitions. Some of these legal actions may result in the listing of species located in areas in which we operate. Such designations of previously unprotected species as being endangered or threatened, or the designation of previously unprotected areas as a critical habitat for such species, can result in increased costs, construction delays, restrictions in our operations or abandonment of projects. In addition, compliance with laws, regulations or other legal requirements could subject us to claims for personal injuries, property damage and other damages.  Our failure to comply with the laws, regulations and other legal requirements applicable to our business, even if as a result of factors beyond our control, could result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties and damages.

Laws, regulations and other legal requirements are constantly changing, and implementation of compliant processes in response to such changes could be costly and time consuming.  For example, in October 2015, the EPA revised the NAAQS for ozone from 75 parts per billion for the current 8 hour primary and secondary ozone standards to 70 parts per billion for both standards. The EPA may designate the areas in which we operate as nonattainment areas. States that contain any areas designated as nonattainment areas will be required to develop implementation plans demonstrating how the areas will attain the applicable standard within a prescribed period of time. These plans may require the installation of additional equipment to control emissions. In addition, in May 2016, the EPA finalized rules that impose volatile organic compound emissions limits (and collaterally reduce methane emissions) on certain types of compressors and pneumatic pumps, as well as requiring the development and implementation of leak monitoring plans for compressor stations. The EPA announced its intention to reconsider certain of the rules in April 2017 and has sought to stay their requirements; however, the rules remain in effect. Compliance with these or other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business. In addition to periodic changes to air, water and waste laws, as well as recent EPA initiatives to impose climate change-based air regulations on industry, the U.S. Congress and various states have been evaluating climate-related legislation and other regulatory initiatives that would further restrict emissions of GHGs, including methane (a primary component of natural gas) and carbon dioxide (a byproduct of burning natural gas). Several states are also pursuing similar measures to regulate emissions of GHGs from new and existing sources. If implemented, such GHG restrictions may result in additional compliance obligations with respect to, or taxes on the release, capture and use of GHGs that could have an adverse effect on our operations.

There is a risk that we may incur costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of wastes and potential emissions and discharges related to our operations. Private parties, including the owners of the properties through which our gathering system or our transmission and storage system pass and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to require remediation of contamination or enforce compliance with environmental requirements as well as to seek damages for personal injury or property damage. In addition, changes in environmental laws occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our business, financial condition, results of operations, liquidity or ability to make quarterly cash distributions to our unitholders. We may not be able to recover all or any of these costs from insurance.

Climate change and related legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the natural gas services we provide.
 
Legislative and regulatory measures to address climate change and GHG emissions are in various phases of discussion or implementation. The EPA regulates GHG emissions from new and modified facilities that are potential major sources of criteria pollutants under the Clean Air Act's Prevention of Significant Deterioration and Title V programs and has adopted

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regulations that require, among other things, preconstruction and operating permits for certain large stationary sources and the monitoring and reporting of GHGs from certain onshore oil and natural gas production sources on an annual basis.

In addition, the U.S. Congress, along with federal and state agencies, have considered measures to reduce the emissions of GHGs. Legislation or regulation that restricts carbon emissions could increase our cost of environmental compliance by requiring us to install new equipment to reduce emissions from larger facilities and/or, depending on any future legislation, purchase emission allowances. Climate change and GHG legislation or regulation could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals for existing and new facilities, impose additional monitoring and reporting requirements or adversely affect demand for the natural gas we gather, transport and store. Conversely, legislation or regulation that sets a price on or otherwise restricts carbon emissions could also benefit us by increasing demand for natural gas because the combustion of natural gas results in substantially fewer carbon emissions per Btu of heat generated than other fossil fuels such as coal. The effect on us of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.

Negative public perception regarding us and/or the midstream industry could have an adverse effect on our operations.

Negative public perception regarding us and/or the midstream industry resulting from, among other things, oil spills, the explosion of natural gas transmission and gathering lines and concerns raised by advocacy groups about hydraulic fracturing and pipeline projects, may lead to increased regulatory scrutiny which may, in turn, lead to new local, state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations.  These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation.  Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed or burdened by requirements that restrict our ability to profitably conduct business.

Significant portions of our pipeline systems have been in service for several decades. There could be unknown events or conditions or increased maintenance or repair expenses and downtime associated with our pipelines that could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make distributions.
 
Significant portions of our transmission and storage system and FERC-regulated gathering system have been in service for several decades. The age and condition of these systems could result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of our systems could adversely affect our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
 
We may incur significant costs and liabilities as a result of increasingly stringent pipeline safety regulation, including pipeline integrity management program testing and related repairs.
 
The DOT, acting through PHMSA, has adopted regulations requiring pipeline operators to develop integrity management programs for transmission pipelines located where a leak or rupture could harm "high consequence areas," including high population areas, unless the operator effectively demonstrates by risk assessment that the pipeline could not affect the area. The regulations require operators, including us, to:

perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
maintain processes for data collection, integration and analysis;
repair and remediate pipelines as necessary; and
implement preventive and mitigating actions.
 
Changes to pipeline safety laws and regulations that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators.  For example, in April 2016, PHMSA published a notice of proposed rulemaking addressing several integrity management topics and proposing new requirements to address safety issues for natural gas transmission and gathering lines.  The proposed rule would strengthen existing integrity management requirements, expand assessment and repair requirements to pipelines in areas with medium population densities and extend regulatory requirements to onshore gas gathering lines that are currently exempt. Further, in June 2016, President Obama signed the 2016 Pipeline Safety Act that extends PHMSA's statutory mandate under prior legislation through 2019. In

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addition, the 2016 Pipeline Safety Act empowered PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing and also required PHMSA to develop new safety standards for natural gas storage facilities by June 2018. Pursuant to those provisions of the 2016 Pipeline Safety Act, in October 2016 and December 2016, PHMSA issued two Interim Final Rules that expanded the agency's authority to impose emergency restrictions, prohibitions and safety measures and strengthened the rules related to underground natural gas storage facilities, including well integrity, wellbore tubing and casing integrity. The December 2016 Interim Final Rule, relating to underground gas storage facilities, went into effect in January 2017, with a compliance deadline in January 2018. PHMSA determined, however, that it will not issue enforcement citations to any operators for violations of provisions of the December 2016 Interim Final Rule that had previously been non-mandatory provisions of American Petroleum Institute Recommended Practices 1170 and 1171 until one year after PHMSA issues a final rule. In October 2017, PHMSA formally reopened the comment period on the December 2016 Interim Final Rule in response to a petition for reconsideration, with comments due in November 2017. Additionally, in January 2017, PHMSA announced a new final rule regarding hazardous liquid pipelines, which increases the quality and frequency of tests that assess the condition of pipelines, requires operators to annually evaluate the existing protective measures in place for pipeline segments in HCAs, extends certain leak detection requirements for hazardous liquid pipelines not located in HCAs, and expands the list of conditions that require immediate repair. However, it is unclear when or if this rule will go into effect because, on January 20, 2017, the Trump Administration requested that all regulations that had been sent to the Office of the Federal Register, but were not yet published, be immediately withdrawn for further review. Accordingly, this rule has not become effective through publication in the Federal Register. We are monitoring and evaluating the effect of these and other emerging requirements on our operations.

States are generally preempted by federal law in the area of pipeline safety, but state agencies may qualify to assume responsibility for enforcing federal regulations over intrastate pipelines.  They may also promulgate additive pipeline safety regulations provided that the state standards are at least as stringent as the federal standards. Although many of our natural gas facilities fall within a class that is not subject to integrity management requirements, we may incur significant costs and liabilities associated with repair, remediation, preventive or mitigation measures associated with our non-exempt transmission pipelines. The costs, if any, for repair, remediation, preventive or mitigating actions that may be determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down our pipelines during the pendency of such actions, could be material.

Should we fail to comply with DOT regulations adopted under authority granted to PHMSA, we could be subject to penalties and fines. PHMSA has the authority to impose civil penalties for pipeline safety violations up to a maximum of approximately $200,000 per day for each violation and approximately $2 million for a related series of violations. This maximum penalty authority established by statute will continue to be adjusted periodically to account for inflation. In addition, we may be required to comply with new safety regulations and make additional maintenance capital expenditures in the future for similar regulatory compliance initiatives that are not reflected in our forecasted maintenance capital expenditures.

The adoption of legislation relating to hydraulic fracturing and the enactment of new or increased severance taxes and impact fees on natural gas production could cause our current and potential customers to reduce the number of wells they drill in the Marcellus, Upper Devonian and Utica Shales or curtail production of existing wells. If reductions are significant for those or other reasons, the reductions would have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
 
Our assets are primarily located in the Marcellus Shale fairway in southwestern Pennsylvania and northern West Virginia, and a majority of the production that we receive from customers is produced from wells completed using hydraulic fracturing. Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells, particularly in unconventional resource plays like the Marcellus, Upper Devonian and Utica Shales. Hydraulic fracturing is typically regulated by state oil and gas commissions and similar agencies, but several federal agencies have asserted regulatory authority over aspects of the process, including the EPA, which published proposed effluent limit guidelines in April 2015 for waste water from shale gas extraction operations before being discharged to a treatment plant, and the federal Bureau of Land Management (BLM), which issued a final rule in March 2015 that established more stringent standards for performing hydraulic fracturing on federal and Indian lands. The BLM rule was struck down by a federal court in Wyoming in June 2016, but reinstated on appeal by the Tenth Circuit in September 2017. While this appeal was pending, BLM proposed a rulemaking in July 2017 to rescind these rules in their entirety. Although BLM published a final rule rescinding the 2015 rules in December 2017, other federal or state agencies may look to the BLM rule in developing new regulations that could apply to our operations.

The U.S. Congress has from time to time considered the adoption of legislation to provide for federal regulation of hydraulic fracturing, while a growing number of states, including those in which we operate, have adopted, and other states are

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considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. Some states, such as Pennsylvania, have imposed fees on the drilling of new unconventional oil and gas wells. States could elect to prohibit hydraulic fracturing altogether, as was announced in December 2014 with regard to hydraulic fracturing activities in New York.  Also, local governments may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. In fact, legislation or regulation banning hydraulic fracturing has been adopted in a number of local jurisdictions, including ones in which we have limited operations. Further, several federal governmental agencies are conducting reviews and studies on the environmental aspects of hydraulic fracturing, including the EPA. For example, in December 2016, the EPA issued its final report on a study it had conducted over several years regarding the effects of hydraulic fracturing on drinking water sources. The final report, contrary to several previously published draft reports issued by the EPA, found instances in which impacts to drinking water may occur. However, the report also noted significant data gaps that prevented the EPA from determining the extent or severity of these impacts. The results of such reviews or studies could spur initiatives to further regulate hydraulic fracturing. 

State and federal regulatory agencies recently have focused on a possible connection between the hydraulic fracturing related activities and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. In a few instances, operators of injection disposal wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. Some state regulatory agencies, including those in Colorado, Ohio, Oklahoma and Texas, have modified their regulations to account for induced seismicity. While Pennsylvania is not one of the states where such regulation has been enacted, regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. These developments could result in additional regulation and restrictions on the use of injection disposal wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on our customers.

The adoption of new laws, regulations or ordinances at the federal, state or local levels imposing more stringent restrictions on hydraulic fracturing could make it more difficult for our customers to complete natural gas wells, increase our customers' costs of compliance and doing business, and otherwise adversely affect the hydraulic fracturing services they perform, which could negatively impact demand for our gathering, transmission and storage services.

Furthermore, the tax laws, rules and regulations that affect our customers are subject to change. For example, Pennsylvania's governor and legislature have continued to discuss the imposition of a state severance tax on the extraction of natural resources, including natural gas produced from the Marcellus, Upper Devonian and Utica Shale formations, either in replacement of or in addition to the existing state impact fee. A consensus on the characteristics, such as the effective tax rate, or enactment of a state severance tax has yet to be reached. Any such increase or change could adversely impact the earnings, cash flows and financial position of our customers and cause them to reduce their drilling in the areas in which we operate.
 
Our exposure to direct commodity price risk may increase in the future.
 
Although we intend to enter into long-term firm contracts with new customers in the future, our efforts to obtain such contractual terms may not be successful. In addition, we may acquire or develop additional midstream assets in the future that do not provide services primarily based on capacity reservation charges or other fixed fee arrangements and therefore have a greater exposure to fluctuations in commodity price risk than our current operations, including the Ohio gathering assets EQT announced it intends to offer to us. Future exposure to the volatility of natural gas prices, including regional basis differentials, as a result of our future contracts could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
 
We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.
 
We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way, if such rights-of-way lapse or terminate or if our facilities are not properly located within the boundaries of such rights-of-way. Although many of these rights are perpetual in nature, we occasionally obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. If we were to be unsuccessful in renegotiating rights-of-way, we might have to institute condemnation proceedings on our FERC-regulated assets or relocate our facilities for non-regulated assets. A loss of rights-of-way or a relocation could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
 

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Any significant and prolonged change in or stabilization of natural gas prices could have a negative impact on our natural gas storage business.
 
Historically, natural gas prices have been seasonal and volatile, which has enhanced demand for our storage services. The natural gas storage business has benefited from significant price fluctuations resulting from seasonal price sensitivity, which impacts the level of demand for our services and the rates we are able to charge for such services. On a system-wide basis, natural gas is typically injected into storage between April and October when natural gas prices are generally lower and withdrawn during the winter months of November through March when natural gas prices are typically higher. However, the market for natural gas may not continue to experience volatility and seasonal price sensitivity in the future at the levels previously seen. If volatility and seasonality in the natural gas industry decrease, because of increased production capacity or otherwise, the demand for our storage services and the prices that we will be able to charge for those services may decline.
 
In addition to volatility and seasonality, an extended period of high natural gas prices would increase the cost of acquiring base gas and likely place upward pressure on the costs of associated storage expansion activities. An extended period of low natural gas prices could adversely impact storage values for some period of time until market conditions adjust. These commodity price impacts could have a negative impact on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
 
We have entered into a joint venture, and may in the future enter into additional or modify existing joint ventures, that might restrict our operational and corporate flexibility. In addition, these joint ventures are subject to many of the same operational risks to which we are subject.

We have entered into a joint venture to construct the MVP project and may in the future enter into additional joint venture arrangements with third parties. Joint venture arrangements may restrict our operational and corporate flexibility. For example, because we do not control all of the decisions of the MVP Joint Venture, it may be difficult or impossible for us to cause the joint venture to take actions that we believe would be in our or the joint venture's best interests. Moreover, joint venture arrangements involve various risks and uncertainties, such as committing us to fund operating and/or capital expenditures, the timing and amount of which we may not control, and our joint venture partners may not satisfy their financial obligations to the joint venture.

In addition, the operations of the MVP Joint Venture and any joint ventures we may enter into in the future are subject to many of the same operational risks to which we are subject as described in this Item 1A, "Risk Factors - Risks Inherent in Our Business."

Restrictions under our debt agreements could adversely affect our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
 
Our debt agreements contain various covenants and restrictive provisions that limit our ability to, among other things:
 
incur or guarantee additional debt;
make distributions on or redeem or repurchase units;
incur or permit liens on assets;
enter into certain types of transactions with affiliates;
enter into certain mergers or acquisitions; and
dispose of all or substantially all of our assets.
 
In July 2017, we amended and restated our credit facility to increase the borrowing capacity under the facility from $750 million to $1 billion and extend the maturity date to July 2022. Our $1 billion credit facility contains a covenant requiring us to maintain a consolidated leverage ratio of not more than 5.00 to 1.00 (or not more than 5.50 to 1.00 for certain measurement periods following the consummation of certain acquisitions). Our ability to meet these covenants can be affected by events beyond our control and we cannot assure our unitholders that we will meet these covenants. In addition, our $1 billion credit facility contains events of default customary for such facilities, including the occurrence of a change of control (which will occur, among other things, if EQT or certain permitted transferees fail to control our general partner, we fail to own 100% of Equitrans, L.P., or our general partner fails to be the general partner).

The provisions of our debt agreements may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our debt agreements could result in an event of default, which could enable our lenders to, subject to the terms and conditions of the applicable agreement, declare any outstanding principal of that debt, together with accrued and

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unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment. The $1 billion credit facility also has cross default provisions that apply to any other indebtedness we may have with an aggregate principal amount in excess of $25 million.
 
Our future debt levels may limit our flexibility to obtain financing and to pursue other business opportunities.
 
We have the ability to incur debt, subject to limitations in our $1 billion credit facility. Our level of debt could have important consequences to us, including the following:
 
our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;
we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
our flexibility in responding to changing business and economic conditions may be limited.
 
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.
 
The credit and risk profile of our general partner and EQT could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital.
 
The credit and business risk profiles of our general partner and EQT may be factors considered in credit evaluations of us. This is because our general partner, which is controlled by EQT through EQT's ownership interest in EQGP, controls our business activities, including our cash distribution policy and growth strategy. Due to our relationship with EQT, our ability to access the capital markets, or the pricing or other terms of any capital markets transactions, may be adversely affected by any impairments to EQT's financial condition, including the degree of its financial leverage and its dependence on cash flows from EQGP to service its indebtedness, or adverse changes in its credit ratings, including a downgrade of EQT's investment grade credit rating. A sustained period of low commodity prices could increase the risk of a lower credit rating for EQT and us. Any material limitations on our ability to access capital as a result of adverse changes at EQT could limit our ability to obtain future financing under favorable terms, or at all, or could result in increased financing costs in the future. Similarly, material adverse changes at EQT could negatively impact our unit price, limiting our ability to raise capital through equity issuances or debt financing, could negatively affect our ability to engage in, expand or pursue our business activities, and could also prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.

Please see Item 1A, "Risk Factors" in EQT's Annual Report on Form 10-K for the year ended December 31, 2017 (which is not, and shall not be deemed to be, incorporated by reference herein) for a full discussion of the risks associated with EQT's business.

 A downgrade of our credit ratings, which are determined by independent third parties, could impact our liquidity, our access to capital, and our costs of doing business.

If any credit rating agency downgrades our credit ratings, our access to credit markets may be limited, our borrowing costs could increase, and we may be required to provide additional credit assurances in support of commercial agreements, such as joint venture agreements and construction contracts, the amount of which may be substantial. Our credit ratings by Moody’s Investors Service (Moody’s), Standard & Poor’s Ratings Service (S&P) and Fitch Ratings Service (Fitch) were Ba1, BBB- and BBB-, respectively, as of February 14, 2018. In order to be considered investment grade, we must be rated Baa3 or higher by Moody’s, BBB- or higher by S&P and BBB- or higher by Fitch. Our non-investment grade credit rating by Moody’s and any future downgrade of our S&P and/or Fitch credit ratings to non-investment grade may result in greater borrowing costs and collateral requirements than would be available to us if all our credit ratings were investment grade. Our ability to access capital markets could also be limited by economic, market or other disruptions. An increase in the level of our indebtedness in the future may result in a downgrade in the ratings that are assigned to our debt. See "The credit and risk profile of our general partner and EQT could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital" in the above section.

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Credit rating agencies perform an independent analysis when assigning credit ratings. This analysis includes a number of criteria such as business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are subject to revision or withdrawal at any time by the ratings agencies.

Increases in interest rates could adversely impact demand for our storage capacity, our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
 
There is a financing cost for our customers to store natural gas in our storage facilities. That financing cost is impacted by the cost of capital or interest rates incurred by the customer in addition to the commodity cost of the natural gas in inventory. Absent other factors, a higher financing cost adversely impacts the economics of storing natural gas for future sale. As a result, a significant increase in interest rates could adversely affect the demand for our storage capacity independent of other market factors.
 
In addition, interest rates on our revolving credit facilities, future credit facilities and debt securities could be higher than current levels, causing our financing costs to increase. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
 
The amount of cash we have available for distribution to unitholders depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.
 
The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

The lack of diversification of our assets and geographic locations could adversely affect our ability to make distributions to our unitholders.
 
We rely exclusively on revenues generated from our gathering system and our transmission and storage system, which are primarily located in the Appalachian Basin in Pennsylvania, West Virginia and Ohio. Due to our lack of diversification in assets and geographic location, an adverse development in these businesses or our areas of operations, including adverse developments due to catastrophic events, weather, regulatory action and decreases in demand for natural gas, could have a significantly greater impact on our results of operations and distributable cash flow to our unitholders than if we maintained more diverse assets and locations.

Terrorist or cyber security attacks or threats thereof aimed at our facilities or surrounding areas could adversely affect our business.
 
Our business has become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications, to operate our assets, and the maintenance of our financial and other records has long been dependent upon such technologies. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Deliberate attacks on, or unintentional events affecting, our systems or infrastructure, the systems or infrastructure of third parties or the cloud could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in delivery of natural gas and natural gas liquids, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, personal injury, property damage, other operational disruptions and third party liability.  Further, as cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.
 

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Risks Inherent in an Investment in Us
 
EQT, through its control of EQGP, controls our general partner, which has sole responsibility for conducting our business and managing our operations. Potential conflicts of interest may arise among our general partner, its affiliates and us. Our general partner has limited its state law fiduciary duties to us and our unitholders, which may permit it to favor its own interests to the detriment of us and our unitholders.
 
EQT, through its ownership of EQGP, controls our general partner and has the power to appoint all of the officers and directors of our general partner. EQT also controls RMP's general partner and has the power to appoint all of the officers and directors of RMP's general partner. Conflicts of interest will arise among EQT, RMP, RMP's general partner, EQGP, EQGP's general partner and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of EQT, RMP and EQGP over our interests and the interests of our unitholders. These conflicts include the following situations, among others:
 
Neither our partnership agreement nor any other agreement requires EQT to pursue a business strategy that favors us, and the directors and officers of EQT have a fiduciary duty to make these decisions in the best interests of EQT, which may be contrary to our interests. EQT may choose to shift the focus of its investment and growth to areas not served by our assets.
EQT, as our primary customer, has an economic incentive to cause us not to seek higher gathering fees or tariff rates, even if such higher fees or rates would reflect fees and rates that could be obtained in arm's length, third party transactions.
EQT is not limited in its ability to compete with us and may offer business opportunities and/or sell midstream assets to RMP or third parties without first offering us the right to bid for them.
Our general partner is allowed to take into account the interests of parties other than us, such as EQT, in resolving conflicts of interest, which has the effect of limiting its state law fiduciary duty to our unitholders.
All of the officers and five of the directors of our general partner are also officers and/or directors of EQT and owe fiduciary duties to EQT, and three of the officers and four of the directors of our general partner are also officers and/or directors of EQGP's general partner and owe fiduciary duties to EQGP. Additionally, all of the officers and five of the directors of our general partner are also officers and/or directors of RMP's general partner and owe fiduciary duties to RMP. The officers of our general partner also devote significant time to the business of EQT, EQGP and RMP and are compensated by EQT accordingly.
Our general partner determines whether or not we incur debt and that decision may affect our credit ratings.
Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner's liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty under state law.
Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.
Our general partner controls the enforcement of the obligations that it and its affiliates owe to us, including EQT's obligations under our omnibus agreement with EQT and EQT's commercial agreements with us.
Disputes may arise under our commercial agreements with EQT and its affiliates.
Our partnership agreement gives our general partner broad discretion in establishing financial reserves for the proper conduct of our business. These reserves will affect the amount of cash available for distribution to our unitholders.
Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash available for distribution to our unitholders.
Our general partner determines the amount and timing of any capital expenditures and, in accordance with the terms of our partnership agreement, whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion or investment capital expenditure, which does not reduce operating surplus. These determinations can affect the amount of cash that is distributed to our unitholders.
Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.
Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions.
Our partnership agreement permits us to classify up to $30 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions to our general partner in respect of the general partner interest or the IDRs.

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Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.
Our general partner intends to limit its liability regarding our contractual and other obligations.
Our general partner may exercise its right to call and purchase all of our common units not owned by it and its affiliates if they own more than 80% of the common units.
Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
Our general partner may transfer the IDRs without unitholder approval.
Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner's IDRs without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

Please read Item 13, "Certain Relationships and Related Transactions, and Director Independence" in this Annual Report on Form 10-K.
 
The duties of our general partner's officers and directors may conflict with their duties as officers and/or directors of EQT, EQGP's general partner and/or RMP's general partner.

Our general partner's officers and directors have duties to manage our business in a manner beneficial to us, our unitholders and the owner of our general partner, EQGP, which is controlled by EQT. However, four of our general partner's directors and three of its officers are also officers and/or directors of EQGP's general partner, which has duties to manage the business of EQGP in a manner beneficial to EQGP and EQGP's unitholders, including EQT. Additionally, five of our general partner's directors and all of its officers are also officers and/or directors of EQT, and five of our general partner's directors and all of its officers are also officers and/or directors of RMP's general partner. Consequently, these directors and officers may encounter situations in which their obligations to EQGP, RMP and/or EQT, as applicable, on the one hand, and us, on the other hand, are in conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.

In addition, our general partner's officers, all of whom are also officers of EQT, three of whom are officers of EQGP's general partner and all of whom are officers of RMP's general partner, will have responsibility for overseeing the allocation of their own time and time spent by administrative personnel on our behalf and on behalf of EQGP, RMP and/or EQT. These officers face conflicts regarding these time allocations that may adversely affect our results of operations, cash flows and financial condition.

EQT may compete with us, which could adversely affect our ability to grow and our results of operations and cash available for distribution.
 
Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. Affiliates of our general partner, including EQT and its other subsidiaries, including EQGP and RMP, are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. EQT currently holds interests in entities that own a significant amount of natural gas midstream assets and may make investments in and purchases of entities that acquire, own and operate other natural gas midstream assets. EQT is under no obligation to make any acquisition opportunities available to us. Moreover, while EQT may offer us the opportunity to buy additional assets from it, it is under no contractual obligation to accept any offer we might make with respect to such opportunity.

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors, EQT, EQGP and RMP. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our common unitholders.
 

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Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
 
We expect that we will distribute all of our available cash to our unitholders and will 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. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.
 
In addition, because we intend to distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement, and we do not anticipate there being limitations in our credit facilities, on our ability to issue additional units, including units ranking senior to our common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.
 
The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.
 
Unlike most corporations, we are not required by NYSE rules to have, and we do not intend to have, a majority of independent directors on our general partner's board of directors or a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE's shareholder approval rules. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.
 
If any of our unitholders are not eligible taxable holders, such unitholders will not be entitled to allocations of income or loss or distributions or voting rights on their common units and their common units will be subject to redemption.
 
In order to avoid any material adverse effect on the maximum applicable rates that can be charged to customers by our subsidiaries on assets that are subject to rate regulation by the FERC or an analogous regulatory body, we have adopted certain requirements regarding those investors who may own our common units. Eligible taxable holders are defined in our partnership agreement and generally include any individual or entity (i) whose, or whose owners', U.S. federal income tax status (or lack of proof thereof) does not have or is not reasonably likely to have, as determined by our general partner, a material adverse effect on the rates that can be charged to customers with respect to assets that are subject to regulation by the FERC or similar regulatory body; or (ii) as to whom our general partner cannot make the determination in clause (i) above, if our general partner determines that it is in our best interest to permit such individual or entity to own our partnership interests. If any of our unitholders fails to fit the requirements of an eligible taxable holder or fails to certify or has falsely certified that such holder is an eligible taxable holder, such unitholder will not receive allocations of income or loss or distributions or voting rights on their units and they run the risk of having their units redeemed by us at the market price calculated in accordance with our partnership agreement as of the date of redemption. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.
 
Our partnership agreement replaces our general partner's fiduciary duties to holders of our common units with contractual standards governing its duties.
 
Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replace those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:
 
how to allocate corporate opportunities among us and other affiliates;
whether to exercise its limited call right;

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whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner;
how to exercise its voting rights with respect to the units it owns;
whether to elect to reset target distribution levels;
whether to transfer the IDRs or any units it owns to a third party; and
whether or not to consent to any merger, consolidation or conversion of the partnership or amendment to our partnership agreement.
 
By purchasing a common unit, a common unitholder agrees to become bound by the provisions in our partnership agreement, including the above provisions.
 
Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
 
Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:
 
whenever our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the board of directors of our general partner and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in the best interests of our partnership, and, except as specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;
our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
our general partner will not be in breach of its obligations under our partnership agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:
approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;
approved by the vote of unitholders holding a majority of our outstanding common units, excluding any common units owned by our general partner and its affiliates;
determined by the board of directors of our general partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
determined by the board of directors of our general partner to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or the conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the third and fourth sub-bullets above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
 

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Reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce distributable cash flow to our common unitholders. The amount and timing of such reimbursements will be determined by our general partner.
 
Prior to making any distribution to our common unitholders, we will reimburse our general partner and its affiliates, including EQT, for expenses they incur and payments they make on our behalf. Under the omnibus agreement, we will reimburse our general partner and its affiliates for certain expenses incurred on our behalf, including administrative costs, such as compensation expenses for those persons who provide services necessary to run our business, and insurance expenses. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our common unitholders.
 
Our unitholders do not elect our general partner or vote on our general partner's directors.
 
Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights and, therefore, limited ability to influence management's decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. Rather, the board of directors of our general partner will be appointed by EQGP, which is controlled by EQT. Furthermore, if our public unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
 
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Our unitholders' voting rights are restricted by a provision in our partnership agreement which provides that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of our unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders' ability to influence the manner or direction of our management. As a result, the price at which our common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.
 
Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.
 
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of (i) EQGP to transfer all or a portion of its ownership interest in our general partner to a third party, or (ii) EQT to transfer all or a portion of its ownership interest in EQGP's general partner to a third party. The new owner of our general partner or EQGP's general partner, as the case may be, would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers of our general partner.
 
The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.
 
EQT, through its control of EQGP, controls our general partner. Our general partner may transfer the IDRs to a third party at any time without the consent of our unitholders. If our general partner transfers the IDRs to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly cash distributions to unitholders over time as it would if it had retained ownership of the IDRs.
 
We may issue additional units without unitholder approval, which would dilute our unitholders' existing ownership interests.
 
Our partnership agreement does not limit the number of additional limited partner interests, including limited partner interests that rank senior to our common units, that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
 
our existing unitholders' proportionate ownership interest in us will decrease;
the amount of distributable cash flow on each unit may decrease;

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because the amount payable to holders of IDRs is based on a percentage of the total distributable cash flow, the distributions to holders of IDRs will increase even if the per unit distribution on common units remains the same;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding unit may be diminished; and
the market price of our common units may decline.
 
EQGP may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of our common units.
 
As of February 15, 2018, EQGP held 21,811,643 of our common units, representing a 26.6% limited partner interest in us. In addition, we have agreed to provide our general partner and its affiliates, including EQGP, with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of our common units or on any trading market that may develop.
 
Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement permits our general partner to limit its liability, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
 
Our general partner has a call right that may require our unitholders to sell their common units at an undesirable time or price.
 
If at any time our general partner and its affiliates own more than 80% of our outstanding common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the remaining units held by unaffiliated persons at a price that is not less than the then-current market price of our common units. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Our common unitholders may also incur a tax liability upon a sale of their common units. As of February 15, 2018, affiliates of our general partner owned 27.1% of our outstanding common units.
 
Our general partner, or any transferee holding a majority of the incentive distribution rights, may elect to cause us to issue common units to it in connection with a resetting of the minimum quarterly distribution and the target distribution levels related to the incentive distribution rights, without the approval of the conflicts committee of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
 
The holder or holders of a majority of the IDRs, which is currently our general partner, have the right, at any time when the holders have received incentive distributions at the highest level to which they are entitled (48.0%) for each of the prior four consecutive fiscal quarters (and the amount of each such distribution did not exceed adjusted operating surplus for each such quarter), to reset the minimum quarterly distribution and the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the "reset minimum quarterly distribution"), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution. Our general partner has the right to transfer the IDRs at any time, in whole or in part, and any transferee holding a majority of the IDRs shall have the same rights as our general partner with respect to resetting target distributions.
 
In the event of a reset of the minimum quarterly distribution and the target distribution levels, the holders of the IDRs will be entitled to receive, in the aggregate, the number of common units equal to that number of common units which would have entitled the holders to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions on the IDRs in the prior two quarters. Our general partner will also be issued the number of general partner units necessary to maintain its general partner interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not otherwise be sufficiently accretive to cash distributions per common unit. It is possible, however, that our general partner or a transferee could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash

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distributions it receives related to the IDRs and may therefore desire to be issued common units rather than retain the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. This risk could be elevated if our IDRs have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels.

Our unitholders' liability may not be limited if a court finds that unitholder action constitutes control of our business.
 
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for any and all of our obligations as if that unitholder were a general partner if a court or government agency were to determine that:
 
we were conducting business in a state but had not complied with that particular state's partnership statute; or
such unitholder's right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitutes "control" of our business.
 
Furthermore, under Delaware law, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution under certain circumstances.


Our general partner may mortgage, pledge or grant a security interest in all or substantially all of our assets without prior approval of our unitholders.

Our general partner may mortgage, pledge or grant a security interest in all or substantially all of our assets without prior approval of our unitholders. If our general partner at any time were to decide to incur debt and secure its obligations or indebtedness by all or substantially all of our assets, and if our general partner were to be unable to satisfy such obligations or repay such indebtedness, the lenders could seek to foreclose on our assets. The lenders could also sell all or substantially all of our assets under such foreclosure or other realization upon those encumbrances without prior approval of our unitholders, which would adversely affect the price of our common units.

Unitholders may have liability to repay distributions that were wrongfully distributed to them.
 
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units are liable both for the obligations of the transferor to make contributions to the partnership that were known to the transferee at the time of transfer and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.
 
Tax Risks to Our Common Unitholders
 
Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our distributable cash flow to our unitholders would be substantially reduced.
 
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not currently plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes.
 
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in

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current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
 
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently 21.0%, and would likely pay state and local income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our distributable cash flow to our unitholders would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
 
If we were subjected to a material amount of additional entity-level taxation by individual states or other taxing jurisdictions, it would reduce our distributable cash flow to our unitholders.
 
Changes in current law may subject us to additional entity-level taxation by individual states or other taxing jurisdictions. Because of widespread budget deficits and other reasons, several states and other taxing jurisdictions are evaluating ways to subject partnerships to entity-level taxation through the imposition of income, franchise and other forms of taxation. Imposition of such additional tax on us would reduce the distributable cash flow to our unitholders. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
 
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
 
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of the U.S. Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, the proposals could eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted, but it is possible that a change in law could affect us and may, if enacted, be applied retroactively. Any such changes could negatively impact the value of an investment in our common units.
 
Our unitholders are required to pay income taxes on their share of our taxable income even if they do not receive any cash distributions from us. A unitholder’s share of our taxable income, and its relationship to any distributions we make, may be affected by a variety of factors, including our economic performance, transactions in which we engage or changes in law and may be substantially different from any estimate we make in connection with a unit offering.

A unitholder’s allocable share of our taxable income will be taxable to such unitholder, which may require the unitholder to pay federal income taxes and, in some cases, state and local income taxes, even if the unitholder receives cash distributions from us that are less than the actual tax liability that results from that income or no cash distributions at all.

A unitholder’s share of our taxable income, and its relationship to any distributions we make, may be affected by a variety of factors, including our economic performance, which may be affected by numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control, and certain transactions in which we might engage. For example, we may engage in transactions that produce substantial taxable income allocations to some or all of our unitholders without a corresponding increase in cash distributions to our unitholders, such as a sale or exchange of assets, the proceeds of which are reinvested in our business or used to reduce our debt, or an actual or deemed satisfaction of our indebtedness for an amount less than the adjusted issue price of the debt. A unitholder’s ratio of its share of taxable income to the cash received by it may also be affected by changes in law. For instance, under the recently enacted law known as the Tax Cuts and Jobs Act of 2017, the net interest expense deductions of certain business entities, including us, are limited to 30% of such entity’s “adjusted

42


taxable income,” which is generally taxable income with certain modifications. If the limit applies, a unitholder’s taxable income allocations will be more (or its net loss allocations will be less) than would have been the case absent the limitation.

From time to time, in connection with an offering of our common units, we may state an estimate of the ratio of federal taxable income to cash distributions that a purchaser of our common units in that offering may receive in a given period. These estimates depend in part on factors that are unique to the offering with respect to which the estimate is stated, so the expected ratio applicable to other common units will be different, and in many cases less favorable, than these estimates. Moreover, even in the case of common units purchased in the offering to which the estimate relates, the estimate may be incorrect, due to the uncertainties described above, challenges by the IRS to tax reporting positions which we adopt, or other factors. The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of our common units.
 
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our distributable cash flow to our unitholders.
 
We have not requested, and do not currently plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other tax matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in a prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel's conclusions or the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel's conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our distributable cash flow.
 
If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it (and some states) may assess and collect any resulting taxes (including any applicable penalties and interest) directly from us, in which case we may require our unitholders and former unitholders to reimburse us for such taxes (including any applicable penalties or interest) or, if we are required to bear such payment, our cash available for distribution to our unitholders might be substantially reduced.

Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it (and some states) may assess and collect any resulting taxes (including any applicable interest and penalties) directly from us. We will generally have the ability to shift any such tax liability to our general partner and our unitholders in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so (or will choose to do so) under all circumstances, or that we will be able to (or choose to) effect corresponding shifts in state income or similar tax liability resulting from the IRS adjustment in states in which we do business in the year under audit or in the adjustment year. If we make payments of taxes, penalties and interest resulting from audit adjustments, we may require our unitholders and former unitholders to reimburse us for such taxes (including any applicable penalties or interest) or, if we are required to bear such payment, our cash available for distribution to our unitholders might be substantially reduced.

In the event the IRS makes an audit adjustment to our income tax returns and we do not or cannot shift the liability to our unitholders in accordance with their interests in us during the year under audit, we will generally have the ability to request that the IRS reduce the determined underpayment by reducing the suspended passive loss carryovers of our unitholders (without any compensation from us to such unitholders), to the extent such underpayment is attributable to a net decrease in passive activity losses allocable to certain partners. Such reduction, if approved by the IRS, will be binding on any affected unitholders.

Tax gain or loss on the disposition of our common units could be more or less than expected.
 
If our unitholders sell their common units, our unitholders will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of our unitholders' allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units our unitholders sell will, in effect, become taxable income to our unitholders if they sell such common units at a price greater than their tax basis in those common units, even if the price our unitholders receive is less than their original cost. Furthermore, a substantial portion of the amount realized on any sale or other disposition of our unitholders' common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes our

43


unitholders' share of our nonrecourse liabilities, if our unitholders sell their common units, our unitholders may incur a tax liability in excess of the amount of cash they receive from the sale.
 
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
 
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income.

Under the recently enacted law known as the Tax Cuts and Jobs Act of 2017, if a unitholder sells or otherwise disposes of a common unit, the transferee is required to withhold 10.0% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferee but were not withheld. However, the Department of the Treasury and the IRS have determined that this withholding requirement should not apply to any disposition of a publicly traded interest in a publicly traded partnership (such as us) until regulations or other guidance have been issued clarifying the application of this withholding requirement to dispositions of interests in publicly traded partnerships. Accordingly, while this new withholding requirement does not currently apply to interests in us, there can be no assurance that such requirement will not apply in the future.

Tax-exempt entities and non-U.S. persons should consult a tax advisor before investing in our common units.
 
We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
 
Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from our unitholders' sales of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders' tax returns.
 
We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
 
We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Treasury Regulations allow a similar monthly convention, but such regulations do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. We are authorized to revise our method of allocation between transferee and transferor unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who disposes of units prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deduction attributable to the month of disposition but will not be entitled to receive a cash distribution for that period.
 
A unitholder whose common units are loaned to a "short seller" to cover a short sale of common units may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
 
Because a unitholder whose common units are loaned to a "short seller" to cover a short sale of common units may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income,

44


gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.
 
We have adopted certain valuation methodologies in determining a unitholder's allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders' sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.
 
As a result of investing in our common units, our unitholders may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.
 
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We own property or conduct business in Pennsylvania, West Virginia and Ohio and will be expanding into Virginia with the MVP, each of which currently imposes a personal income tax on individuals. Each of these states also imposes an income or gross receipts tax on corporations and other entities. As we make acquisitions or expand our business, we may own property or conduct business in additional states that impose a personal income tax. It is our unitholders' responsibility to file all U.S. federal, state and local tax returns.
 
Compliance with and changes in tax laws could adversely affect our performance.
 
We are subject to extensive tax laws and regulations, including federal, state and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes as well as interest and penalties.
 
See also Item 7A, "Quantitative and Qualitative Disclosures About Market Risk," for further discussion regarding EQM's exposure to market risks, which is incorporated herein by reference.

Item 1B. Unresolved Staff Comments
 
None.

Item 2. Properties
 
For a description of material properties, see Item 1, "Business," which is incorporated herein by reference.
 
Item 3. Legal Proceedings
 
In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against EQM. While the amounts claimed may be substantial, EQM is unable to predict with certainty the ultimate outcome of such claims and proceedings. EQM accrues legal and other direct costs related to loss contingencies when actually incurred.

45


EQM has established reserves it believes to be appropriate for pending matters and, after consultation with counsel and giving appropriate consideration to available insurance, EQM believes that the ultimate outcome of any matter currently pending against it will not materially affect its business, financial condition, results of operations, liquidity or ability to make distributions.

Environmental Proceedings

Between September 2015 and February 2016, EQM, as the operator of the AVC facilities which at that time were owned by EQT, received eight Notices of Violation (NOVs) from the Pennsylvania Department of Environmental Protection (PADEP).  The NOVs alleged violations of the Pennsylvania Clean Streams Law in connection with inadvertent releases of sediment and bentonite to water that occurred while drilling for a pipeline replacement project in Cambria County, Pennsylvania.  EQT and EQM immediately addressed the releases and fully cooperated with the PADEP. In October 2016, EQM acquired the AVC facilities from EQT, including any future obligations related to these releases. In February 2017, EQM received a proposed consent assessment of civil penalty from the PADEP that proposed a civil penalty related to the NOVs. While the PADEP's claims may result in penalties that exceed $100,000, EQM expects that the resolution of this matter will not have a material impact on its financial condition, results of operations, liquidity or ability to make distributions.

EQM has received a number of other NOVs from environmental agencies in some of the states in which EQM operates alleging various violations of oil and gas, air, water and waste regulations. EQM has responded to these NOVs and has, where applicable, substantially corrected or remediated the activities in question. EQM disputes the facts alleged in a number of the NOVs and cannot predict with certainty whether any or all of these NOVs will result in penalties. If penalties are imposed, an individual penalty or the aggregate of these penalties could result in monetary sanctions in excess of $100,000.

Item 4. Mine Safety Disclosures
 
Not applicable.

PART II

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
EQM's common units are listed on the NYSE under the symbol "EQM." The following table sets forth the high and low sales prices reflected in the NYSE Composite Transactions of the common units, as reported by the NYSE, as well as the amount of cash distributions declared per quarter for 2017 and 2016.
 
Common Unit Data by Quarter
 
 
2017
 
2016
 
 
Unit Price Range
 
Distributions
 
Unit Price Range
 
Distributions
 
 
 
 
 
 
per Common
 
 
 
 
 
per Common
 
 
High
 
Low
 
Unit
 
High
 
Low
 
Unit
1st Quarter
 
$
82.99

 
$
73.76

 
$
0.85

 
$
77.70

 
$
57.88

 
$
0.71

2nd Quarter
 
79.93

 
69.28

 
0.89

 
80.63

 
69.22

 
0.745

3rd Quarter
 
78.75

 
71.75

 
0.935

 
80.58

 
74.49

 
0.78

4th Quarter
 
$
77.42

 
$
64.42

 
$
0.98

 
$
78.78

 
$
69.20

 
$
0.815

 
As of January 31, 2018, there were three unitholders of record of EQM's common units. A cash distribution of $1.025 per common unit was declared on January 18, 2018 and was paid on February 14, 2018 to unitholders of record at the close of business on February 2, 2018.
 
As of December 31, 2017, EQM had also issued 1,443,015 general partner units for which there is no established public trading market. The general partner units are owned by EQGP. See Note 7 to the consolidated financial statements included in Item 8, "Financial Statements and Supplementary Data," of this Form 10-K for information on the significant provisions of EQM's partnership agreement that relate to distributions of available cash, minimum quarterly distributions and IDRs.
 

46


Recent Sales of Unregistered Securities

None.

Market Repurchases
 
EQM did not repurchase any of its common units during 2017.
 
Equity Compensation Plans
 
The information relating to EQM's equity compensation plans required by Item 5 is included in Item 12, "Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters" of this Form 10-K, which is incorporated herein by reference.

Item 6. Selected Financial Data
 
The following selected financial data should be read in conjunction with Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Item 8, "Financial Statements and Supplementary Data" of this Form 10-K.
 
EQM's consolidated financial statements have been retrospectively recast for all periods presented to include the historical results of AVC, Rager, the Gathering Assets, NWV Gathering, Jupiter and Sunrise as these were businesses and the acquisitions were transactions between entities under common control. The selected financial data covering the periods prior to the October 2016 Acquisition, prior to the NWV Gathering Acquisition, prior to the Jupiter Acquisition and prior to the Sunrise Merger may not necessarily be indicative of the actual results of operations had AVC, Rager, the Gathering Assets, NWV Gathering, Jupiter and Sunrise been operated together during those periods.
 
 
As of and for the Years Ended December 31,
 
 
2017
 
2016
 
2015
 
2014
 
2013
Statements of Consolidated Operations
 
 
 
(Thousands, except per share amounts)
 
 
Operating revenues
 
$
834,096

 
$
735,614

 
$
632,936

 
$
489,218

 
$
362,810

Operating income
 
580,708

 
526,949

 
451,036

 
332,595

 
248,628

Net income
 
$
571,904

 
$
537,954

 
$
455,126

 
$
284,816

 
$
191,653

Net income per limited partner unit (a)
 
 

 
 

 
 

 
 

 
 

Basic
 
$
5.19

 
$
5.21

 
$
4.71

 
$
3.53

 
$
2.47

Diluted
 
5.19

 
5.21

 
4.70

 
3.52

 
2.46

Cash distributions paid per limited partner unit
 
$
3.655

 
$
3.05

 
$
2.505

 
$
2.02

 
$
1.55

 
 
 
 
 
 
 
 
 
 
 
Consolidated Balance Sheets
 
 

 
 

 
 

 
 

 
 

Total assets
 
$
3,548,827

 
$
3,075,840

 
$
2,833,358

 
$
1,943,366

 
$
1,437,680

Long-term debt
 
$
1,167,352

 
$
985,732

 
$
493,401

 
$
492,633

 
$


(a) 
Net income attributable to AVC, Rager and the Gathering Assets for periods prior to October 1, 2016, net income attributable to NWV Gathering for periods prior to March 17, 2015, net income attributable to Jupiter for periods prior to May 7, 2014 and net income attributable to Sunrise for periods prior to July 22, 2013 were not allocated to the limited partners for purposes of calculating net income per limited partner unit. See Note 1 to the consolidated financial statements included in Item 8 of this Form 10-K for further discussion.

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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion and analysis of financial condition and results of operations in conjunction with the consolidated financial statements, and the notes thereto, included in Item 8 of this Annual Report on Form 10-K.

Executive Overview

EQM reported net income of $571.9 million in 2017 compared with $538.0 million in 2016. The increase primarily resulted from higher revenues from both gathering and transmission, which were driven mainly by affiliate and third party production development in the Marcellus Shale, and lower income taxes, partly offset by an increase in operating expenses, higher net interest expense and lower other income.

EQM reported net income of $538.0 million in 2016 compared with $455.1 million in 2015. The increase primarily resulted from higher revenues from both gathering and transmission, which were primarily driven by affiliate production development in the Marcellus Shale, higher other income and lower net interest expense. These items were partly offset by higher income taxes and an increase in operating expenses, consistent with the growth of the business.

EQM declared a cash distribution to its unitholders of $1.025 per unit on January 18, 2018, which was 5% higher than the third quarter 2017 distribution of $0.98 per unit and 21% higher than the fourth quarter 2016 distribution of $0.85 per unit. Total distributions related to 2017 were $3.83 per unit compared to $3.19 per unit total distributions related to 2016, a 20% increase.

Business Segment Results
 
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. Other income and net interest expense are managed on a consolidated basis. EQM has presented each segment's operating income and various operational measures in the following sections. Management believes that the presentation of this information provides useful information to management and investors regarding the financial condition, results of operations and trends of segments. EQM has reconciled each segment's operating income to EQM's consolidated operating income and net income in Note 4 to the consolidated financial statements.
 

48


GATHERING RESULTS OF OPERATIONS
 
 
Years Ended December 31,
 
 
2017
 
2016
 
%
change
2017 –
2016
 
2015
 

change
2016 -
2015
FINANCIAL DATA
 
(Thousands, other than per day amounts)
Firm reservation fee revenues
 
$
407,355

 
$
339,237

 
20.1

 
$
267,517

 
26.8

Volumetric based fee revenues:
 
 
 
 
 
 
 
 
 
 
Usage fees under firm contracts(a)
 
32,206

 
38,408

 
(16.1
)
 
33,021

 
16.3

Usage fees under interruptible contracts
 
14,975

 
19,849

 
(24.6
)
 
34,567

 
(42.6
)
Total volumetric based fee revenues
 
47,181

 
58,257

 
(19.0
)
 
67,588

 
(13.8
)
Total operating revenues
 
454,536

 
397,494

 
14.4

 
335,105

 
18.6

Operating expenses:
 
 
 
 
 
 

 
 
 
 

Operating and maintenance
 
43,235

 
38,367

 
12.7

 
37,011

 
3.7

Selling, general and administrative
 
38,942

 
39,678

 
(1.9
)
 
30,477

 
30.2

Depreciation and amortization
 
38,796

 
30,422

 
27.5

 
24,360

 
24.9

Total operating expenses
 
120,973

 
108,467

 
11.5

 
91,848

 
18.1

Operating income
 
$
333,563

 
$
289,027

 
15.4

 
$
243,257

 
18.8

 
 
 
 
 
 
 
 
 
 
 
OPERATIONAL DATA
 
 

 
 

 
 

 
 

 
 

Gathering volumes (BBtu per day)
 
 
 
 
 
 
 
 
 
 
Firm capacity reservation
 
1,826

 
1,553

 
17.6

 
1,140

 
36.2

Volumetric based services(b)
 
361

 
420

 
(14.0
)
 
485

 
(13.4
)
Total gathered volumes
 
2,187

 
1,973

 
10.8

 
1,625

 
21.4

 
 
 
 
 
 
 
 
 
 
 
Capital expenditures
 
$
196,871

 
$
295,315

 
(33.3
)
 
$
225,537

 
30.9


(a)
Includes fees on volumes gathered in excess of firm contracted capacity.

(b)
Includes volumes gathered under interruptible contracts and volumes gathered in excess of firm contracted capacity.

Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

Gathering revenues increased by $57.0 million driven by third party and affiliate production development in the Marcellus Shale. EQM increased firm reservation fee revenues in 2017 compared to 2016 as a result of third parties and affiliates contracting for additional firm gathering capacity, which increased firm gathering capacity by approximately 475 MMcf per day following the completion of the Range Resources header pipeline project and various affiliate wellhead gathering expansion projects. The decrease in usage fees under firm contracts was due to lower affiliate volumes in excess of firm contracted capacity. The decrease in usage fees under interruptible contracts was primarily due to the additional contracts for firm capacity.

                Operating expenses increased by $12.5 million for the year ended December 31, 2017 compared to the year ended December 31, 2016. Operating and maintenance expense increased primarily as a result of higher personnel costs and increased property taxes. Selling, general and administrative expenses decreased primarily due to lower corporate allocations from EQT as a result of EQT’s shift in focus during 2017 from midstream drop-down transactions to upstream asset and corporate acquisition projects partly offset by increased miscellaneous administrative costs. Depreciation and amortization expense increased $8.4 million due to additional assets placed in-service including those associated with the Range Resources header pipeline project and various affiliate wellhead gathering expansion projects.

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

Gathering revenues increased by $62.4 million primarily as a result of higher affiliate and third party volumes gathered in 2016 compared to 2015, driven by production development in the Marcellus Shale. EQM increased firm reservation fee

49


revenues in 2016 compared to 2015 as a result of affiliates and third parties contracting for additional capacity under firm contracts, which resulted in increased firm gathering capacity of approximately 300 MMcf per day following the completion of the NWV Gathering and Jupiter expansion projects in the fourth quarter of 2015. The decrease in usage fees under interruptible contracts was primarily due to these additional contracts for firm capacity.

Operating expenses increased by $16.6 million for the year ended December 31, 2016 compared to the year ended December 31, 2015. Selling, general and administrative expenses increased as a result of higher allocations and personnel costs from EQT. The increase in depreciation and amortization expense resulted from additional assets placed in-service, including those associated with the NWV Gathering and Jupiter expansion projects.

TRANSMISSION RESULTS OF OPERATIONS
 
 
Years Ended December 31,
 
 
2017
 
2016
 
%
change
2017 –
2016
 
2015
 

change
2016 -
2015
FINANCIAL DATA
 
(Thousands, other than per day amounts)
Firm reservation fee revenues
 
$
348,193

 
$
277,816

 
25.3

 
$
247,231

 
12.4

Volumetric based fee revenues:
 
 
 
 
 
 
 
 
 
 
Usage fees under firm contracts(a)
 
13,743

 
45,679

 
(69.9
)
 
42,646

 
7.1

Usage fees under interruptible contracts
 
17,624

 
14,625

 
20.5

 
7,954

 
83.9

Total volumetric based fee revenues
 
31,367

 
60,304

 
(48.0
)
 
50,600

 
19.2

Total operating revenues
 
379,560

 
338,120

 
12.3

 
297,831

 
13.5

Operating expenses:
 
 
 
 
 
 

 
 
 
 

Operating and maintenance
 
41,482

 
34,846

 
19.0

 
33,092

 
5.3

Selling, general and administrative
 
32,244

 
33,083

 
(2.5
)
 
31,425

 
5.3

Depreciation and amortization
 
58,689

 
32,269

 
81.9

 
25,535

 
26.4

Total operating expenses
 
132,415

 
100,198

 
32.2

 
90,052

 
11.3

Operating income
 
$
247,145

 
$
237,922

 
3.9

 
$
207,779

 
14.5

 
 


 
 
 
 
 
 
 
 
OPERATIONAL DATA
 
 

 
 

 
 

 
 

 
 

Transmission pipeline throughput (BBtu per day)
 
 
 
 
 
 
 
 
 
 
Firm capacity reservation
 
2,399

 
1,651

 
45.3

 
1,841

 
(10.3
)
Volumetric based services(b)
 
37

 
430

 
(91.4
)
 
281

 
53.0

Total transmission pipeline throughput
 
2,436

 
2,081

 
17.1

 
2,122

 
(1.9
)
 
 
 
 
 
 
 
 
 
 
 
Average contracted firm transmission reservation commitments (BBtu per day)
 
3,627

 
2,814

 
28.9

 
2,624

 
7.2

 
 
 
 
 
 
 
 
 
 
 
Capital expenditures
 
$
111,102

 
$
292,049

 
(62.0
)
 
$
203,706

 
43.4


(a)
Includes commodity charges and fees on all volumes transported under firm contracts as well as transmission fees on volumes in excess of firm contracted capacity.

(b)
Includes volumes transported under interruptible contracts and volumes transported in excess of firm contracted capacity.

Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

Total operating revenues increased by $41.4 million. Firm reservation fee revenues increased due to affiliates and third parties contracting for additional firm capacity, primarily on the OVC, as well as higher contractual rates on existing contracts in the current year. The firm capacity on the OVC resulted in lower affiliate usage fees under firm contracts. The increase in

50


usage fees under interruptible contracts includes increased storage and parking revenue, which does not have pipeline throughput associated with it, partly offset by reduced throughput on interruptible contracts.

Operating expenses increased by $32.2 million for the year ended December 31, 2017 compared to the year ended December 31, 2016Operating and maintenance expense increased primarily due to property taxes on the OVC and higher personnel costs. Selling, general and administrative expenses decreased primarily due to lower corporate allocations from EQT as a result of EQT’s shift in focus during 2017 from midstream drop-down transactions to upstream asset and corporate acquisition projects. The increase in depreciation and amortization expense was the result of the OVC project placed in-service in the fourth quarter of 2016 and a non-cash charge to depreciation and amortization expense of $10.5 million related to the revaluation of differences between the regulatory and tax bases in EQM’s regulated property, plant and equipment. The related regulatory liability will be amortized over the estimated useful life of the underlying property which is 43 years.

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

Total operating revenues increased by $40.3 million. Firm reservation fee revenues increased due to affiliates contracting for additional capacity under firm contracts, primarily on the OVC, as well as higher contractual rates on existing contracts in 2016. Higher usage fees under firm contracts were driven by an increase in affiliate volumes in excess of firm capacity associated with increased production development in the Marcellus Shale, partly offset by lower usage fees from third party producers which is reflected in reduced firm capacity reservation throughput for the year ended December 31, 2016 compared to the year ended December 31, 2015. These volumes also decreased as a result of warmer weather in the first quarter of 2016. This decrease in transported volumes did not have a significant impact on firm reservation fee revenues. Usage fees under interruptible contracts for the year ended December 31, 2016 increased as a result of higher third party volumes transported or stored on an interruptible basis.

Operating expenses increased $10.1 million for the year ended December 31, 2016 compared to the year ended December 31, 2015. The increase in operating and maintenance expense resulted primarily from higher repairs and maintenance expenses associated with increased throughput. Selling, general and administrative expenses increased primarily as a result of higher allocations and personnel costs from EQT. The increase in depreciation and amortization expense was primarily a result of higher depreciation on the increased investment in transmission infrastructure, including those associated with the OVC and the AVC facilities.

Other Income Statement Items
 
In conjunction with the October 2016 Acquisition discussed in Note 2 to the consolidated financial statements, the operating agreement of EES was amended to provide for mandatory redemption of the Preferred Interest at the end of the preference period, which is expected to be December 31, 2034. As a result of this amendment, the accounting for EQM's investment in EES converted from a cost method investment to a note receivable effective October 1, 2016. This conversion did not impact the carrying value of this instrument; however, distributions from EES subsequent to the amendment are recorded partly as interest income and partly as a reduction in the note receivable. This change decreased the amount of other income recognized and increased interest income in 2017.

Other income decreased by $10.5 million for the year ended December 31, 2017 compared to the year ended December 31, 2016 primarily driven by decreased AFUDC - equity of $14.3 million associated with the OVC project placed in-service in the fourth quarter of 2016 and distributions from EES of $8.3 million which were recorded as other income in 2016 prior to the conversion to a note receivable, partly offset by higher equity income related to EQM's portion of the MVP Joint Venture's AFUDC on the MVP. Other income increased by $29.2 million for the year ended December 31, 2016 compared to the year ended December 31, 2015 primarily driven by increased AFUDC - equity of $13.1 million mainly attributable to increased spending on the OVC project, distributions from EES of $8.3 million that were recorded as other income in 2016 and higher equity income related to EQM's portion of the MVP Joint Venture's AFUDC on the MVP.

Net interest expense increased by $19.4 million for the year ended December 31, 2017 compared to the year ended December 31, 2016 primarily driven by higher interest incurred on EQM's long-term debt issued in November 2016 of $17.4 million, lower capitalized interest and AFUDC - debt of $5.3 million associated with decreased spending on capital projects and increased interest on EQM's credit facility borrowings, partly offset by increased interest income recorded on distributions from EES of $5.1 million. Net interest expense decreased by $4.6 million for the year ended December 31, 2016 compared to the year ended December 31, 2015 primarily driven by higher capitalized interest and AFUDC - debt of $3.8 million associated with increased spending primarily on the OVC, decreased interest expense of $2.8 million on lower credit facility borrowings and interest income subsequent to the Preferred Interest conversion to a note receivable. The items which decreased net interest expense were partly offset by interest incurred on the long-term debt issued in November 2016.

51



See Note 11 to the consolidated financial statements included in Item 8 of this Annual Report on Form 10-K for discussion of income tax expense (benefit).

See "Investing Activities" and "Capital Requirements" in the "Capital Resources and Liquidity" section below for a discussion of capital expenditures.

Non-GAAP Financial Measures

Adjusted EBITDA and distributable cash flow are non-GAAP supplemental financial measures that management and external users of EQM's consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, use to assess:

EQM's operating performance as compared to other publicly traded partnerships in the midstream energy industry without regard to historical cost basis or, in the case of adjusted EBITDA, financing methods;
the ability of EQM's assets to generate sufficient cash flow to make distributions to EQM's unitholders;
EQM's 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.

EQM believes that adjusted EBITDA and distributable cash flow provide useful information to investors in assessing its financial condition and results of operations. Adjusted EBITDA and distributable cash flow should not be considered as alternatives to net income, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and distributable cash flow have important limitations as analytical tools because they exclude some, but not all, items that affect net income and net cash provided by operating activities. Additionally, because adjusted EBITDA and distributable cash flow may be defined differently by other companies in its industry, EQM's adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing the utility of the measures. Distributable cash flow should not be viewed as indicative of the actual amount of cash that EQM has available for distributions from operating surplus or that it plans to distribute.


52


Reconciliation of Non-GAAP Financial Measures
 
The following table presents a reconciliation of EQM's non-GAAP financial measures of adjusted EBITDA and distributable cash flow with the most directly comparable EQM GAAP financial measures of net income and net cash provided by operating activities.
 
Years Ended December 31,
 
2017
 
2016
 
2015
 
(Thousands)
Net income
$
571,904

 
$
537,954

 
$
455,126

Add:
 
 
 
 
 
Net interest expense
36,181

 
16,766

 
21,345

Depreciation and amortization expense
97,485

 
62,691

 
49,895

Income tax expense (benefit)

 
10,147

 
(16,741
)
Preferred Interest payments received post conversion (a)
10,984

 
2,764

 

Non-cash long-term compensation expense
225

 
195

 
1,467

Less:
 
 
 
 
 
Equity income
(22,171
)
 
(9,898
)
 
(2,367
)
AFUDC – equity
(5,110
)
 
(19,402
)
 
(6,327
)
Pre-acquisition capital lease payments for AVC (b)

 
(17,186
)
 
(22,059
)
Adjusted EBITDA attributable to NWV Gathering prior to acquisition (c)

 

 
(19,841
)
Adjusted EBITDA attributable to the October 2016 Acquisition prior to acquisition (d)

 
(11,420
)
 
(11,483
)
Adjusted EBITDA
$
689,498

 
$
572,611

 
$
449,015

Less:
 
 
 

 
 

Net interest expense excluding interest income on the Preferred Interest
(42,999
)
 
(18,506
)
 
(22,436
)
Capitalized interest and AFUDC – debt (e)
(4,120
)
 
(9,400
)
 

Ongoing maintenance capital expenditures net of reimbursements (f)
(27,609
)
 
(21,434
)
 
(20,099
)
Distributable cash flow
$
614,770

 
$
523,271

 
$
406,480

 
 
 
 
 
 
Net cash provided by operating activities
$
650,550

 
$
537,904

 
$
489,706

Adjustments:
 
 
 
 
 
Pre-acquisition capital lease payments for AVC (b)

 
(17,186
)
 
(22,059
)
Capitalized interest and AFUDC – debt (e)
(4,120
)
 
(9,400
)
 

Principal payments received on the Preferred Interest
4,166

 
1,024

 

Ongoing maintenance capital expenditures net of reimbursements (f)
(27,609
)
 
(21,434
)
 
(20,099
)
Current tax expense

 
1,373

 
13,945

Adjusted EBITDA attributable to NWV Gathering prior to acquisition (c)

 

 
(19,841
)
Adjusted EBITDA attributable to the October 2016 Acquisition prior to acquisition (d)

 
(11,420
)
 
(11,483
)
Other, including changes in working capital
(8,217
)
 
42,410

 
(23,689
)
Distributable cash flow
$
614,770

 
$
523,271

 
$
406,480


(a)
In conjunction with the October 2016 Acquisition, the operating agreement of EES was amended and the accounting for EQM's Preferred Interest in EES converted from a cost method investment to a note receivable effective October 1, 2016. There were no changes in the cash payments; however, distributions from EES subsequent to this amendment were recorded partly as a reduction in the note receivable and partly as interest income, which is included in net interest expense in the accompanying statements of consolidated operations. Distributions received from EES prior to this amendment in 2016 were included in other income in the accompanying statements of consolidated operations.

(b)
Reflects capital lease payments due under the lease. These lease payments were generally made monthly on a one month lag prior to the October 2016 Acquisition.


53


(c)
Adjusted EBITDA attributable to NWV Gathering prior to acquisition for the periods presented was excluded from EQM's adjusted EBITDA calculations as these amounts were generated by NWV Gathering prior to acquisition by EQM; therefore, the amounts could not have been distributed to EQM's unitholders. Adjusted EBITDA attributable to NWV Gathering prior to acquisition for the year ended December 31, 2015 was calculated as net income of $11.1 million plus depreciation and amortization expense of $2.0 million plus income tax expense of $6.7 million.

(d)
Adjusted EBITDA attributable to the October 2016 Acquisition prior to acquisition for the periods presented was excluded from EQM's adjusted EBITDA calculations as these amounts were generated by AVC, Rager and the Gathering Assets prior to acquisition by EQM; therefore, the amounts could not have been distributed to EQM's unitholders. Adjusted EBITDA attributable to the October 2016 Acquisition prior to acquisition for the years ended December 31, 2016 and 2015 was calculated as net income of $1.3 million and $34.2 million, respectively, plus depreciation and amortization expense of $2.1 million and $2.5 million, respectively, plus income tax expense (benefit) of $10.1 million and $(23.4 million), respectively, less interest income of $0.5 million and $1.1 million, respectively, less AFUDC - equity of $1.6 million and $0.7 million, respectively.

Adjusted EBITDA attributable to AVC, excluding income tax expense and AFUDC - equity, was previously included in EQM's results as a result of the capital lease and was eliminated from adjusted EBITDA by subtracting the capital lease payment; therefore, there is no adjustment for AVC's adjusted EBITDA prior to acquisition other than the capital lease payments, income tax expense and AFUDC - equity. Net income for AVC including decreased depreciation expense related to the 40 year useful life of the pipeline was $20.6 million and $27.5 million for the years ended December 31, 2016 and 2015, respectively (see Note 2 to the consolidated financial statements included in Item 8 of this Annual Report on Form 10-K).

(e)
As a result of increased significance of capitalized interest and AFUDC - debt in 2016, this line item was added as an adjustment to the calculation of distributable cash flow for the year ended December 31, 2016. Had distributable cash flow been calculated on a consistent basis, it would have been $5.6 million lower for the year ended December 31, 2015 than the amount presented herein.

(f)
Ongoing maintenance capital expenditures are 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, EQM's operating capacity or operating income. EQT has reimbursement obligations to EQM for certain maintenance capital expenditures under the terms of the EQM omnibus agreement. For further explanation of these reimbursable maintenance capital expenditures, see "Capital Requirements." For the years ended December 31, 2016 and 2015, ongoing maintenance capital expenditures net of reimbursements excludes ongoing maintenance of $6.5 million and $9.8 million, respectively, attributable to AVC, Rager, the Gathering Assets and NWV Gathering prior to acquisition.

See "Executive Overview" for a discussion of EQM's net income, the GAAP financial measure most directly comparable to adjusted EBITDA. Adjusted EBITDA increased by $116.9 million for the year ended December 31, 2017 compared to the year ended December 31, 2016 and $123.6 million for the year ended December 31, 2016 compared to the year ended December 31, 2015, in each case, primarily as a result of higher operating income on increased revenues driven by production development in the Marcellus Shale and the acquisitions for each period, which resulted in EBITDA subsequent to the transaction being reflected in adjusted EBITDA, including the elimination of the AVC lease payment. For the year ended December 31, 2016 compared to the year ended December 31, 2015, distributions from EES also contributed to the increase.

Net cash provided by operating activities, the GAAP financial measure most directly comparable to distributable cash flow, increased by $112.6 million for the year ended December 31, 2017 compared to the year ended December 31, 2016 and $48.2 million for the year ended December 31, 2016 compared to the year ended December 31, 2015 as discussed in "Capital Resources and Liquidity." Distributable cash flow increased by $91.5 million for the year ended December 31, 2017 compared to the year ended December 31, 2016 and $116.8 million for the year ended December 31, 2016 compared to the year ended December 31, 2015, in each case, mainly attributable to the increase in adjusted EBITDA. For the year ended December 31, 2017 compared to the year ended December 31, 2016, the increase in adjusted EBITDA was partly offset by increased net interest expense excluding interest income on the Preferred Interest and ongoing maintenance capital expenditures net of reimbursements.

Outlook
 
EQM's principal business objective is to increase the quarterly cash distributions that it pays to its unitholders over time while ensuring the ongoing growth of its business. EQM believes that it is well positioned to achieve growth based on its

54


strategically located assets, which cover portions of the Marcellus, Upper Devonian and Utica Shales that lack substantial natural gas pipeline infrastructure. EQM believes it has a competitive advantage in pursuing economically attractive organic expansion projects in its areas of operations, which EQM believes will be a key driver of growth in the future. EQM is also currently pursuing organic growth projects that are expected to provide access to markets in the Gulf Coast and Southeast regions. Additionally, EQM may acquire additional midstream assets from EQT or pursue asset acquisitions from third parties. Should EQT choose to sell midstream assets, it is under no contractual obligation to offer the assets to EQM.

EQM expects that the following expansion projects will allow it to capitalize on drilling activity by EQT and third party producers:

Mountain Valley Pipeline. The MVP Joint Venture is a joint venture with affiliates of each of NextEra Energy, Inc., Consolidated Edison, Inc., WGL Holdings, Inc. and RGC Resources, Inc. EQM is the operator of the MVP and owned a 45.5% interest in the MVP Joint Venture as of December 31, 2017. The 42 inch diameter MVP has a targeted capacity of 2.0 Bcf per day and is estimated to span 300 miles extending from EQM's existing transmission and storage system in Wetzel County, West Virginia to Pittsylvania County, Virginia, providing access to the growing Southeast demand markets. As currently designed, the MVP is estimated to cost a total of approximately $3.5 billion, excluding AFUDC, with EQM funding its proportionate share through capital contributions made to the joint venture. In 2018, EQM expects to provide capital contributions of $1.0 billion to $1.2 billion to the MVP Joint Venture. The MVP Joint Venture has secured a total of 2.0 Bcf per day of firm capacity commitments at 20-year terms, including a 1.29 Bcf per day firm capacity commitment by EQT, and is currently in negotiation with additional shippers who have expressed interest in the MVP project. On October 13, 2017, the FERC issued the Certificate of Public Convenience and Necessity for the project. In early 2018, the MVP Joint Venture received limited notice to proceed with certain construction activities from the FERC. The MVP Joint Venture plans to commence construction in the first quarter of 2018. The pipeline is targeted to be placed in-service during the fourth quarter of 2018.

Affiliate Wellhead Gathering Expansion. In 2018, EQM estimates capital expenditures of approximately $300 million on gathering expansion projects, primarily driven by affiliate wellhead and header projects in Pennsylvania and West Virginia, including commencing preliminary construction activities on the Hammerhead project, a 1.2 Bcf per day gathering header pipeline connecting Pennsylvania and West Virginia production to the MVP.

Transmission Expansion. In 2018, EQM estimates capital expenditures of approximately $100 million for other transmission expansion projects, primarily attributable to the Equitrans Expansion project. The Equitrans Expansion project is designed to provide north-to-south capacity on the mainline Equitrans system for deliveries to the MVP.

See further discussion of capital expenditures in the "Capital Requirements" section below.

Rice Transaction. On November 13, 2017, EQT closed its previously announced transaction to acquire Rice. As part of the transaction, EQT acquired certain midstream assets previously owned by Rice. EQT announced that it intends to sell these midstream assets to EQM through one or more drop-down transactions. In addition to the potential drop-down opportunities, EQM expects to benefit from increased organic growth opportunities due to the combination of the EQT and Rice acreage positions. However, EQT is under no obligation to make such opportunities available to EQM.

Committee to Address Sum-of-the-Parts Discount. EQT has announced that its board of directors has formed a committee to evaluate options for addressing EQT’s sum-of-the-parts discount. EQT’s board will announce a decision by the end of March 2018, after considering the committee’s recommendation.

Capital Resources and Liquidity
 
EQM's principal liquidity requirements are to finance its operations, fund capital expenditures, potential acquisitions and capital contributions to the MVP Joint Venture, make cash distributions and satisfy any indebtedness obligations. EQM's ability to meet these liquidity requirements will depend on its ability to generate cash in the future as well as its ability to raise capital in banking, capital and other markets. EQM's available sources of liquidity include cash generated from operations, borrowing under EQM's credit facilities, cash on hand, debt offerings and issuances of additional EQM partnership units.

    

55


Operating Activities
 
Net cash provided by operating activities was $650.6 million for 2017 as compared to $537.9 million for 2016. The increase was driven by higher operating income for which the contributing factors are discussed in the "Executive Overview" and "Business Segment Results of Operations" sections herein and the timing of payments between the two periods, partly offset by increased interest as discussed in the "Other Income Statement Items" section herein.

Net cash provided by operating activities was $537.9 million for 2016 as compared to $489.7 million for 2015. The increase was driven by higher operating income for which the contributing factors are discussed in the "Executive Overview" and "Business Segment Results of Operations" sections herein, distributions from EES of approximately $11 million and lower net interest expense as discussed in the "Other Income Statement Items" section herein, partly offset by the timing of payments between the two periods.
 
Investing Activities
 
Net cash used in investing activities totaled $457.0 million for 2017 as compared to $732.0 million for 2016. The decrease was primarily attributable to decreased capital expenditures as further described in the "Capital Requirements" section herein and net assets acquired from EQT in 2016 of $62.4 million in 2016, partly offset by increased capital contributions to the MVP Joint Venture in 2017 and sales of interest in the MVP Joint Venture in 2016.
    
Net cash used in investing activities totaled $732.0 million for 2016 as compared to $1,043.8 million for 2015. The decrease was primarily attributable to lower net assets acquired from EQT in 2016 as compared to 2015. In 2015, EQM acquired $386.8 million of net assets in the NWV Gathering Acquisition as well as the $124.3 million Preferred Interest from EQT compared to $62.4 million of net assets in the October 2016 Acquisition. This decrease was partly offset by increased capital expenditures as further described in the "Capital Requirements" section herein.

Financing Activities
 
Net cash used in financing activities totaled $251.4 million for 2017 as compared to $106.5 million for 2016. For 2017, the primary use of financing cash flows was distributions paid to unitholders and the primary source of financing cash flows was net borrowings on EQM's credit facilities. For 2016, the primary uses of financing cash flows were distributions paid to unitholders, net repayments on EQM's credit facility and the October 2016 Acquisition. For 2016, the primary sources of financing cash flows were from EQM debt and equity offerings.

Net cash used in financing activities totaled $106.5 million for 2016 as compared to net cash provided by financing activities of $779.5 million for 2015. For 2015, the primary sources of financing cash flows were EQM equity offerings and net borrowings on EQM's credit facility and the primary uses of financing cash flows were the NWV Gathering Acquisition in excess of net assets acquired and distributions paid to unitholders.

Capital Requirements
 
The gathering, transmission and storage businesses are capital intensive, requiring significant investment to develop new facilities and to maintain and upgrade existing operations.
 
 
Years Ended December 31,
 
 
2017
 
2016
 
2015
 
(Thousands)
Expansion capital expenditures (a)
 
$
264,645

 
$
558,071

 
$
388,442

Maintenance capital expenditures:
 
 
 
 
 
 
Ongoing maintenance
 
43,072

 
28,498

 
37,422

Funded regulatory compliance
 
256

 
795

 
3,379

Total maintenance capital expenditures
 
43,328

 
29,293

 
40,801

Total capital expenditures
 
307,973

 
587,364

 
429,243

Plus: accrued capital expenditures at the end of prior period (b)
 
26,678

 
24,133

 
53,016

Less: accrued capital expenditures at the end of current period (b)
 
(33,067
)
 
(26,678
)
 
(24,133
)
Less: other non-cash items (c)
 

 

 
(70
)
Total cash capital expenditures
 
$
301,584

 
$
584,819

 
$
458,056


56


 
(a)
Expansion capital expenditures do not include capital contributions made to the MVP Joint Venture of $159.6 million and $98.4 million for the years ended December 31, 2017 and 2016, respectively. In 2015, EQM paid $84.4 million for its acquisition of EQT's ownership interest in the MVP Joint Venture and subsequent capital contributions to the MVP Joint Venture.

(b)
EQM accrues capital expenditures when work has been completed but the associated bills have not yet been paid. These accrued amounts are excluded from capital expenditures on the consolidated statements of cash flows until they are paid in a subsequent period.

(c)
EQM capitalizes certain labor overhead costs which include a portion of non-cash equity-based compensation.

Expansion capital expenditures are expenditures incurred for capital improvements that EQM expects to increase its operating income or operating capacity over the long term. In 2017, expansion capital expenditures primarily related to the following projects: affiliate wellhead gathering expansion projects, the Range Resources header pipeline project and the AVC expansion project. In 2016, expansion capital expenditures primarily related to the following projects: the OVC, the Range Resources Header Pipeline project, the NWV Gathering expansion and the AVC expansion project. The OVC project was placed in-service during the fourth quarter of 2016 and the Range Resources Header Pipeline project was placed in-service in several phases beginning in the fourth quarter of 2016 with the final phase placed in-service during the second quarter of 2017. In 2015, expansion capital expenditures primarily related to the following projects: the OVC, the Jupiter and NWV Gathering expansions, the Antero Resources Corporation transmission projects and several projects for Range Resources. Significant portions of these projects were completed in the second half of 2015.
 
Maintenance capital expenditures are expenditures made to maintain, over the long term, EQM's operating capacity or operating income. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines, to connect new wells to maintain throughput, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.

Ongoing maintenance capital expenditures are all maintenance capital expenditures other than funded regulatory compliance capital expenditures described in the next paragraph. The period over period changes in ongoing maintenance capital expenditures primarily related to the timing of projects primarily related to bare steel replacement capital expenditures. Included in these amounts for the years ended December 31, 2017, 2016 and 2015 were $15.5 million, $0.6 million and $7.5 million, respectively, of maintenance capital expenditures for which EQM was reimbursed by EQT under the terms of the EQM omnibus agreement. Under the EQM omnibus agreement, for a period of ten years after the closing of EQM's IPO, EQT has agreed to reimburse EQM for plugging and abandonment expenditures for certain identified wells of EQT and third parties. Additionally, EQT has agreed to reimburse EQM for bare steel replacement capital expenditures in the event that ongoing maintenance capital expenditures (other than capital expenditures associated with plugging and abandonment liabilities to be reimbursed by EQT) exceed $17.2 million (with respect to EQM's assets owned at the time of the IPO) in any year. If such ongoing maintenance capital expenditures and bare steel replacement capital expenditures exceed $17.2 million during a year, EQT will reimburse EQM for the lesser of (i) the amount of bare steel replacement capital expenditures during such year and (ii) the amount by which such ongoing capital expenditures and bare steel replacement capital expenditures exceeds $17.2 million. This bare steel replacement reimbursement obligation is capped at an aggregate amount of $31.5 million over the ten years following EQM's IPO. Since EQM's IPO, EQM has been reimbursed approximately $26.9 million for bare steel replacement capital expenditures by EQT. Amounts reimbursed are recorded as capital contributions when received.

Funded regulatory compliance capital expenditures are maintenance capital expenditures necessary to comply with certain regulatory and other legal requirements. Prior to EQM's IPO, EQM identified two specific regulatory compliance initiatives which EQM expected to require it to expend approximately $32 million. EQM retained approximately $32 million from the net proceeds of its IPO to fund these expenditures. The specific initiatives of this program are to install remote valve and pressure monitoring equipment on EQM's transmission and storage lines and to relocate certain valve operators above ground and apply corrosion protection. The period over period changes primarily relate to the timing of projects as these two compliance initiatives are substantially complete. Since EQM's IPO in 2012, funded regulatory compliance capital expenditures have totaled $30.9 million.
    
In 2018, capital contributions to the MVP Joint Venture are expected to be $1.0 billion to $1.2 billion, depending on the timing of the construction of the MVP, expansion capital expenditures are expected to be approximately $400 million and ongoing maintenance capital expenditures are expected to be $35 million to $40 million, net of reimbursements. EQM's future capital investments may vary significantly from period to period based on the available investment opportunities and the timing of construction for the MVP. Maintenance related capital expenditures are also expected to vary quarter to quarter. EQM

57


expects to fund future capital expenditures primarily through cash on hand, cash generated from operations, availability under its credit facilities, debt offerings and issuances of additional EQM partnership units. EQM does not forecast capital expenditures associated with potential projects not committed as of the filing of this Annual Report on Form 10-K.

Credit Facility Borrowings
 
See Note 9 to the consolidated financial statements included in Item 8 of this Annual Report on Form 10-K for discussion of EQM's credit facilities.

Security Ratings

The table below sets forth the credit ratings for debt instruments of EQM at December 31, 2017.
Rating Service
 
Senior Notes
 
Outlook
Moody's Investors Service (Moody's)
 
Ba1
 
Stable
Standard & Poor's Ratings Services (S&P)
 
BBB-
 
Stable
Fitch Ratings (Fitch)
 
BBB-
 
Stable
    
EQM's credit ratings are subject to revision or withdrawal at any time by the assigning rating organization and each rating should be evaluated independently of any other rating. EQM cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a credit rating agency if, in its judgment, circumstances so warrant. If any credit rating agency downgrades EQM's ratings, EQM's access to the capital markets may be limited, borrowing costs could increase, EQM may be required to provide additional credit assurances in support of commercial agreements such as joint venture agreements and construction contracts, the amount of which may be substantial, and the potential pool of investors and funding sources may decrease. In order to be considered investment grade, a company must be rated Baa3 or higher by Moody's, BBB- or higher by S&P, or BBB- or higher by Fitch. Anything below these ratings, including EQM's current credit rating of Ba1 by Moody's, is considered non-investment grade.

$750 Million ATM Program

As of February 15, 2018, EQM had approximately $443 million in remaining capacity under the $750 Million ATM Program.

Distributions
 
See Note 7 to the consolidated financial statements included in Item 8 of this Annual Report on Form 10-K for discussion of distributions.
 
Schedule of Contractual Obligations

The following represents EQM's contractual obligations as of December 31, 2017. Purchase obligations exclude EQM's future capital contributions to the MVP Joint Venture and purchase obligations of the MVP Joint Venture.
 
 
Total
 
2018
 
2019-2020
 
2021-2022
 
2023+
 
 
(Thousands)
Long-term debt
 
$
1,000,000

 
$

 
$

 
$

 
$
1,000,000

Credit facility borrowings (a)
 
180,000

 

 

 
180,000

 

Interest payments on senior notes (b)
 
315,573

 
40,625

 
81,250

 
81,250

 
112,448

Purchase obligations
 
49,504

 
49,504

 

 

 

Total contractual obligations
 
$
1,545,077

 
$
90,129

 
$
81,250

 
$
261,250

 
$
1,112,448

 
(a)
Credit facility borrowings were classified based on the termination date of the amended and restated credit facility agreement.

(b)
Interest payments exclude interest related to the credit facility borrowings as the interest rate on the credit facility agreement is variable.


58


Commitments and Contingencies
 
In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against EQM. While the amounts claimed may be substantial, EQM is unable to predict with certainty the ultimate outcome of such claims and proceedings. EQM accrues legal and other direct costs related to loss contingencies when actually incurred. EQM has established reserves it believes to be appropriate for pending matters, and after consultation with counsel and giving appropriate consideration to available insurance, EQM believes that the ultimate outcome of any matter currently pending against it will not materially affect its business, financial condition, results of operations, liquidity or ability to make distributions.

See Note 13 to the consolidated financial statements included in Item 8 of this Annual Report on Form 10-K for further discussion of EQM's commitments and contingencies.
 
Off-Balance Sheet Arrangements
 
See Note 6 to the consolidated financial statements included in Item 8 of this Annual Report on Form 10-K for discussion of the MVP Joint Venture guarantee.

Recently Issued Accounting Standards

EQM's recently issued accounting standards are described in Note 1 to the consolidated financial statements included in Item 8 of this Annual Report on Form 10-K.

Critical Accounting Policies and Estimates
 
EQM's significant accounting policies are described in Note 1 to the consolidated financial statements included in Item 8 of this Annual Report on Form 10-K. The discussion and analysis of the consolidated financial statements and results of operations are based upon EQM's consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosure of contingent assets and liabilities. The following critical accounting policies, which were reviewed by EQM's Audit Committee, relate to its more significant judgments and estimates used in the preparation of its consolidated financial statements. Actual results could differ from those estimates.
 
Property, Plant and Equipment. Determination of depreciation expense requires judgment regarding the estimated useful lives and salvage values of property, plant and equipment. EQM has not historically experienced material changes in its results of operations from changes in the estimated useful lives or salvage values of property, plant and equipment although these estimates are reviewed periodically, including each time EQM files with the FERC for a change in transmission and storage rates. Determination of internal costs capitalized requires judgment as to the percent of time spent on capitalized projects for the capitalization of costs such as salaries, benefits and other indirect costs. EQM believes that the accounting estimates related to depreciation expense and capitalization of internal costs are "critical accounting estimates" because they are susceptible to change period to period. These assumptions affect the gross property, plant and equipment balances and the amount of depreciation and operating expense and would have an impact on the results of operations and financial position if changed. See Note 1 to the consolidated financial statements for additional information.

Impairments. Any accounting estimate related to impairment of property, plant and equipment or an investment in an unconsolidated entity requires EQM's management to make assumptions about future cash flows, discount rates, fair value of investments and whether losses in the value of its investments are other than temporary. Management's assumptions about future cash flows require significant judgment because actual operating levels have fluctuated in the past and are expected to do so in the future. Additionally, management's assumptions about the fair value of its investment in an unconsolidated entity requires significant judgment because EQM's investment is not traded on an active market. EQM has not historically had indications of impairments. However, EQM believes that the accounting estimates related to impairments are "critical accounting estimates" because they require assumptions that are susceptible to change period to period. Any potential impairment would have an impact on the results of operations and financial position. See Note 1 to the consolidated financial statements for additional information.

Allocated General and Administrative Costs. General and administrative and operating and maintenance costs are allocated to EQT's business units, including EQM's segments, based upon the nature of the expenses. Costs that are directly related to EQM are directly charged to EQM. Other costs are allocated based on operational and financial metrics. Allocations

59


are based on estimates and assumptions that management believes are reasonable; however, EQM believes that the accounting estimates related to allocated costs are "critical accounting estimates" because different estimates and assumptions would change the amounts allocated to EQM and those differences could be material. These assumptions affect the amount of general and administrative and operating expense and would have an impact on the results of operations if changed.

Regulatory Accounting. Determination and application of regulatory accounting requires judgment regarding probability that certain expenses and income will be allowed in the rate setting process in a period different from the period in which they would have been reflected in the statements of consolidated operations for a non-regulated entity. EQM has not historically experienced material changes in its results of operations from changes in regulatory accounting although these estimates are reviewed periodically, including each time EQM files with the FERC for a change in transmission and storage rates. EQM believes that the accounting estimates related to regulatory accounting are "critical accounting estimates" because they are susceptible to change period to period. These assumptions affect the gross regulatory assets and liabilities and the amount of regulated operating revenues and expenses and would have an impact on the results of operations and financial position if changed. See Note 1 and Note 10 to the consolidated financial statements for additional information.

Contingencies. EQM is involved in various regulatory and legal proceedings that arise in the ordinary course of business. A liability is recorded for contingencies based upon EQM's assessment that a loss is probable and that the amount of the loss can be reasonably estimated. EQM considers many factors in making these assessments, including the history and specifics of each matter. Estimates are developed in consultation with legal counsel and are based upon an analysis of potential results. EQM believes that the accounting estimates related to contingencies are "critical accounting estimates" because it must assess the probability and amount of loss related to contingencies. Future results of operations could be materially affected by changes in the assumptions.

Revenue Recognition. Revenue from the gathering of natural gas is generally recognized when the service is provided. Revenue related to gathering services provided but not yet billed is estimated each month. These estimates are generally based on contract data and preliminary throughput and allocation measurements. Final bills for the current month are billed and collected in the following month. See Note 1 to the consolidated financial statements for additional information.

EQM records a monthly provision for accounts receivable that are considered to be uncollectible. In order to calculate the appropriate monthly provision, a historical rate of accounts receivable losses as a percentage of total revenue is utilized. This historical rate is applied to the current revenues on a monthly basis and is updated periodically based on events that may change the rate, such as a significant change to the natural gas industry or to the economy as a whole. Management reviews the adequacy of the allowance on a quarterly basis using the assumptions that apply at that time. While EQM has not historically experienced material bad debt expense, declines in the market price for natural gas combined with the increase in third party customers on EQM's systems may result in a greater exposure to potential losses than management's current estimates. As of December 31, 2017, EQM had third party accounts receivable of $28.8 million, which is net of an allowance for doubtful accounts of $0.4 million.

EQM believes that the accounting estimates related to revenue recognition are "critical accounting estimates" because estimated volumes are subject to change based on actual measurements including prior period adjustments. In addition, EQM believes that the accounting estimates related to the allowance for doubtful accounts receivable are "critical accounting estimates" because the underlying assumptions used for the allowance can change from period to period and the actual mix of customers and their ability to pay may vary significantly from management's estimates which could impact the collectability of customer accounts. These accounting estimates could potentially have a material impact on the results of operations and financial position.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk
 
Interest Rate Risk . Changes in interest rates affect the amount of interest EQM earns on cash, cash equivalents and short-term investments and the interest rates EQM pays on borrowings under its credit facilities. EQM's senior notes are fixed rate and thus do not expose EQM to fluctuations in its results of operations or liquidity from changes in market interest rates. Changes in interest rates do affect the fair value of EQM's fixed rate debt. See Note 9 to the consolidated financial statements for discussion of EQM's borrowings and Note 1 to the consolidated financial statements for a discussion of fair value measurements. EQM may from time to time hedge the interest on portions of its borrowings under the credit facilities in order to manage risks associated with floating interest rates.

Credit Risk. EQM is exposed to credit risk which is the risk that EQM may incur a loss if a counterparty fails to perform under a contract. EQM manages its exposure to credit risk associated with customers through credit analysis, credit approval, credit limits and monitoring procedures. For certain transactions, EQM may request letters of credit, cash collateral,

60


prepayments or guarantees as forms of credit support. EQM's FERC tariffs require tariff customers that do not meet specified credit standards to provide three months of credit support; however, EQM is exposed to credit risk beyond this three month period when its tariffs do not require its customers to provide additional credit support. For some of EQM's more recent long-term contracts associated with system expansions, it has entered into negotiated credit agreements that provide for enhanced forms of credit support if certain credit standards are not met. EQM has historically experienced only minimal credit losses in connection with its receivables. For the year ended December 31, 2017, approximately 85% of revenues were from investment grade counterparties. EQM is exposed to the credit risk of EQT, its largest customer. In connection with EQM's IPO in 2012, EQT guaranteed all payment obligations, up to a maximum of $50 million, due and payable to Equitrans by EQT Energy, LLC, one of Equitrans' largest customers and a wholly owned subsidiary of EQT. The EQT guaranty will terminate on November 30, 2023 unless terminated earlier by EQT upon 10 days written notice. At December 31, 2017, EQT's public senior debt had an investment grade credit rating. See Note 12 to the consolidated financial statements for further discussion regarding EQM's exposure to credit risk.

Commodity Prices. EQM's business is dependent on the continued availability of natural gas production and reserves in its areas of operation. Low prices for natural gas, including those resulting from regional basis differentials, could adversely affect development of additional reserves and production that is accessible by EQM's pipeline and storage assets. Lower regional natural gas prices could cause producers to determine in the future that drilling activities in areas outside of EQM's current areas of operation are strategically more attractive to them. EQT, or third party customers on EQM's systems, may reduce capital spending in the future based on commodity prices or other factors. Unless EQM is successful in attracting and retaining unaffiliated third party customers, which accounted for 47% of transmission and storage revenues and 11% of gathering revenues for the year ended December 31, 2017, its ability to maintain or increase the capacity subscribed and volumes transported under service arrangements on its transmission and storage system as well as the volumes gathered on its gathering systems will be dependent on receiving consistent or increasing commitments from EQT. While EQT has dedicated acreage to EQM and has entered into long-term firm transmission and gathering contracts on EQM's systems, EQT may determine in the future that drilling in EQM's areas of operations is not economical or that drilling in areas outside of EQM's current areas of operations is strategically more attractive to it. EQT is under no contractual obligation to continue to develop its acreage dedicated to EQM.

For the year ended December 31, 2017, approximately 91% of total revenues were derived from firm reservation fees. As a result, EQM believes that short and medium term declines in volumes of gas produced, gathered, transported or stored on its systems will not have a significant impact on its results of operations, liquidity, financial position or ability to pay distributions because these firm reservation fees are paid regardless of volumes supplied to the system by customers. Longer term price declines could have an impact on customer creditworthiness and related ability to pay firm reservation fees under long-term contracts which could impact EQM's results of operations, liquidity, financial position or ability to pay distributions to its unitholders. Additionally, long term declines in gas production in EQM's areas of operations would limit EQM's growth potential.

Other Market Risks. EQM's $1 billion credit facility is underwritten by a syndicate of financial institutions, each of which is obligated to fund its pro-rata portion of any borrowings by EQM. No one lender of the 19 financial institutions in the syndicate holds more than 10% of the facility. EQM's large syndicate group and relatively low percentage of participation by each lender is expected to limit EQM's exposure to problems or consolidation in the banking industry.

Item 8. Financial Statements and Supplementary Data 
 
Page 
Reference
Reports of Independent Registered Public Accounting Firm
Statements of Consolidated Operations for each of the three years in the period ended December 31, 2017
Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 2017
Consolidated Balance Sheets as of December 31, 2017 and 2016
Statements of Consolidated Equity for each of the three years in the period ended December 31, 2017
Notes to Consolidated Financial Statements

61



Report of Independent Registered Public Accounting Firm

To the Unitholders of EQT Midstream Partners, LP and the Board of Directors of EQT Midstream Services, LLC

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of EQT Midstream Partners, LP and subsidiaries (the Partnership) as of December 31, 2017 and 2016, the related statements of consolidated operations, cash flows and equity for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the consolidated financial position of the Partnership at December 31, 2017 and 2016, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 15, 2018 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the Partnership's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.


/s/ Ernst & Young, LLP
 
We have served as the Partnership's auditor since 2012.
 
Pittsburgh, Pennsylvania
 
February 15, 2018
 

62


Report of Independent Registered Public Accounting Firm

To the Unitholders of EQT Midstream Partners, LP and the Board of Directors of EQT Midstream Services, LLC

Opinion on Internal Control over Financial Reporting

We have audited EQT Midstream Partners, LP and subsidiaries' internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, EQT Midstream Partners, LP and subsidiaries (the Partnership) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Partnership as of December 31, 2017 and 2016, the related statements of consolidated operations, cash flows and equity for each of the three years in the period ended December 31, 2017 and the related notes of the Partnership and our report dated February 15, 2018 expressed an unqualified opinion thereon.

Basis for Opinion

The Partnership's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young, LLP
 
Pittsburgh, Pennsylvania
 
February 15, 2018
 

63


EQT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
 STATEMENTS OF CONSOLIDATED OPERATIONS(a) 
 YEARS ENDED DECEMBER 31,
 
2017
 
2016
 
2015
 
(Thousands, except per unit amounts)
Operating revenues (b)
$
834,096

 
$
735,614

 
$
632,936

Operating expenses:
 
 
 

 
 

Operating and maintenance (c)
84,717

 
73,213

 
70,103

Selling, general and administrative (c) 
71,186

 
72,761

 
61,902

Depreciation and amortization
97,485

 
62,691

 
49,895

Total operating expenses
253,388

 
208,665

 
181,900

Operating income
580,708

 
526,949

 
451,036

Other income (d)
27,377

 
37,918

 
8,694

Net interest expense (e)
36,181

 
16,766

 
21,345

Income before income taxes
571,904

 
548,101

 
438,385

Income tax expense (benefit)

 
10,147

 
(16,741
)
Net income
$
571,904

 
$
537,954

 
$
455,126

 
 
 
 
 
 
Calculation of limited partners' interest in net income:
 
 
 

 
 

Net income
$
571,904

 
$
537,954

 
$
455,126

Less pre-acquisition income allocated to parent

 
(21,861