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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2012

or

[   ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM ___________ TO __________

COMMISSION FILE NUMBER 1-35574

EQT Midstream Partners, LP

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code:  (412) 553-5700

Securities registered pursuant to Section 12(b) of the Act:

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  o  No  ý

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  o  No  ý

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  ý  No  o

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  ý  No  o

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.   ý

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes  o  No  ý

The aggregate market value of the Common Units held by non-affiliates of the registrant as of June 30, 2012: $343.9 million

At January 31, 2013, there were 17,339,718 Common Units, 17,339,718 Subordinated Units and 707,744 General Partner Units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None

TABLE OF CONTENTS

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Glossary of Commonly Used Terms, Abbreviations and Measurements

adjusted EBITDA - a supplemental non-GAAP financial measure defined by the Company as net income plus net interest expense, income tax expense, depreciation and amortization expense, non-cash long-term compensation expense and other non-cash adjustments less other income and the Sunrise Pipeline lease payment.

AFUDC – Allowance for Funds Used During Construction - carrying costs for the construction of certain long-term assets are capitalized and amortized over the related assets’ estimated useful lives.  The capitalized amount for construction of regulated assets includes interest cost and a designated cost of equity for financing the construction of these regulated assets.

Appalachian Basin – the area of the United States comprised 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.

distributable cash flow – a supplemental non-GAAP financial measure defined by the Company as adjusted EBITDA less net cash paid for interest expense, maintenance capital expenditures and income taxes.

end-user markets - the ultimate users and consumers of transported energy products.

firm contracts – contracts for transportation services that obligate customers to pay a fixed monthly charge to reserve an agreed upon amount of pipeline capacity regardless of the actual pipeline capacity used by a customer during each month.

gas – all references to “gas” in this report refer to natural gas.

horizontal drilling – drilling that ultimately is horizontal or near horizontal to increase the length of the well bore penetrating the target formation.

HP - horsepower.

local distribution company or LDC - LDCs are companies involved in the delivery of natural gas to consumers within a specific geographic area.

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.

NGA - Natural Gas Act of 1938.

NGPA – Natural Gas Policy Act of 1978.

omnibus agreement - the agreement entered into among the Company, its general partner and EQT Corporation (EQT) in connection with the Company’s initial public offering,  pursuant to which EQT agreed to provide the Company with certain general and administrative services and a license to use the name “EQT” and related marks in connection with the Company’s business. The omnibus agreement also provides for certain indemnification and reimbursement obligations between the Company and EQT.

park and loan services - those services pursuant to which customers receive the right to store natural gas in (park), or borrow gas from (loan), the Company’s facilities on a seasonal basis.

PSIA – Pipeline Safety Improvement Act of 2002.

play - a proven geological formation that contains commercial amounts of hydrocarbons.

receipt point - the point where production is received by or into a gathering system or transportation pipeline.

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Glossary of Commonly Used Terms, Abbreviations and Measurements

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.

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

CBM – Coalbed Methane

DOT – U.S. Department of Transportation

FASB – Financial Accounting Standards Board

FERC – Federal Energy Regulatory Commission

GAAP – Generally Accepted Accounting Principles

IRS – Internal Revenue Service

LDC – Local Distribution Company

NYMEX – New York Mercantile Exchange

NYSE – New York Stock Exchange

PA PUC – Pennsylvania Public Utility Commission

PHMSA – Pipeline and Hazardous Materials Safety Administration

SEC – Securities and Exchange Commission

WV PSC – West Virginia Public Service Commission

Measurements

Bbl    = barrel

Btu = one British thermal unit

BBtu  = billion British thermal units

Bcf    = billion cubic feet

Dth  =  million British thermal units

Mcf    = thousand cubic feet

Mgal   = thousand gallons

MBbl   = thousand barrels

MMBtu  = million British thermal units

MMcf   = million cubic feet

TBtu = trillion British thermal units

Tcf = one trillion cubic feet

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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,” “forecasts,” “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 the Company and its subsidiaries, including guidance regarding transmission and storage and gathering revenue and volume growth; revenue projections; infrastructure programs (including the timing, cost, capacity and sources of funding with respect to such programs); natural gas production growth in the Company’s operating areas for EQT Corporation and third parties; asset acquisitions, including the Company’s ability to complete any asset purchases from EQT Corporation; the consummation of the Equitable Gas Company, LLC transaction, including the commercial arrangements to be entered into by the Company in connection therewith; projected adjusted EBITDA and distributable cash flow; the amount and timing of distributions including expected increases; the effect of the Sunrise Pipeline lease on distributable cash flow; future projected Sunrise Pipeline lease payments; projected operating and capital expenditures including the amount of capital expenditures reimbursable by EQT; liquidity and financing requirements, including sources and availability; the effects of government regulation and tax position. The forward-looking statements included in this Annual Report on Form 10-K are subject to 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.  The Company has based these forward-looking statements on current expectations and assumptions about future events.  While the Company considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company’s control.  With respect to the proposed Equitable Gas Company, LLC transaction, these risks and uncertainties include, among others, the ability of EQT Corporation to obtain regulatory approvals for the transaction on the proposed terms and schedule and that the conditions to closing may not be satisfied. The risks and uncertainties that may affect the operations, performance and results of the Company’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 the Company 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 the Company. The agreements may contain representations and warranties by the Company, 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 of 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 the Company or its affiliates as of the date they were made or at any other time.

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PART I

Item 1. Business

EQT Midstream Partners, LP (the Partnership, EQT Midstream Partners or the Company), which closed its initial public offering (IPO) to become publicly traded on July 2, 2012, is a growth-oriented Delaware limited partnership formed in January 2012.  Equitrans, L.P. (Equitrans) is a Pennsylvania limited partnership and the predecessor for accounting purposes (the Predecessor) of EQT Midstream Partners (the Successor).  References in this Form 10-K to the “Company,” when used for periods prior to the IPO, refer to Equitrans.  References in this Form 10-K to the “Company,” when used for periods beginning at or following the IPO, refer collectively to the Partnership and its consolidated subsidiaries. Immediately prior to the closing of the IPO, EQT Corporation contributed all of the partnership interests in Equitrans to the Partnership. Therefore, the historical financial statements contained in this Form 10-K reflect the assets, liabilities and operations of Equitrans (excluding the results of operations of Big Sandy Pipeline, a FERC-regulated transmission pipeline sold by Equitrans to an unrelated party in July 2011) for periods ending before July 2, 2012 and EQT Midstream Partners for periods beginning at or following July 2, 2012. References in this Form 10-K to ‘‘EQT’’ refer collectively to EQT Corporation and its consolidated subsidiaries.

Overview

EQT Midstream Partners is a growth-oriented limited partnership formed by EQT Corporation (NYSE: EQT) to own, operate, acquire and develop midstream assets in the Appalachian Basin. The Company provides substantially all of its natural gas transmission, storage and gathering services under contracts with fixed reservation and/or usage fees, with a significant portion of its revenues being generated under long-term firm contracts. The Company’s operations are primarily focused in southwestern Pennsylvania and northern West Virginia, a strategic location in the rapidly growing natural gas shale play known as the Marcellus Shale. This same region is also the core operating area of EQT, the general partner and majority equity owner of the Company. The Company provides midstream services to EQT and multiple third parties across 22 counties in Pennsylvania and West Virginia through its two primary assets: the Equitrans Transmission and Storage System, which serves as a header system transmission pipeline, and the Equitrans Gathering System, which delivers natural gas from wells and other receipt points to transmission pipelines. The Company believes that its strategically located assets, combined with its working relationship with EQT, position it as a leading Appalachian Basin midstream energy company serving the Marcellus Shale region.

EQT is the Company’s largest customer and is one of the largest natural gas producers in the Appalachian Basin. For the year ended December 31, 2012, EQT reported 6.0 Tcfe of proved reserves and total production sales volumes of 258.5 Bcfe, representing a 33% increase compared to the year ended December 31, 2011. Approximately 58% of EQT’s total production in 2012 was from Marcellus wells, and overall Marcellus volumes increased 85% compared to the year ended December 31, 2011. During the year ended December 31, 2012, approximately 81% of the Company’s total natural gas transmission and gathering volumes were comprised of natural gas produced by EQT and other affiliated volumes. In order to facilitate production growth in its areas of operation, EQT invested approximately $2.0 billion in midstream infrastructure from January 1, 2007 through December 31, 2012 and currently owns a substantial and growing portfolio of midstream assets, many of which have multiple interconnects into the Company’s system. The Company believes its economic relationship with EQT incentivizes EQT to provide the Company with access to additional production growth in and around its existing assets and with acquisitions and organic growth opportunities, although EQT is under no obligation to do so.

Initial Public Offering

On July 2, 2012, immediately prior to the closing of the IPO, EQT contributed all of the partnership interests in Equitrans to the Partnership. The Company issued 14,375,000 common units in the IPO, which included the full exercise of the underwriters’ over-allotment option, and represented 40.6% of the Company’s outstanding equity. EQT retained a 59.4% equity interest in the Company, including 2,964,718 common units, 17,339,718 subordinated units, and a 2% general partner interest.

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Transmission and Storage System

The Company’s transmission and storage system includes an approximately 700 mile FERC-regulated interstate pipeline that connects to five interstate pipelines and multiple distribution companies. The transmission system is supported by 14 associated natural gas storage reservoirs with approximately 400 MMcf per day of peak withdrawal capability and 32 Bcf of working gas capacity and 21 compressor units. As of December 31, 2012, the transmission assets had total throughput capacity of approximately 1.4 TBtu per day. Revenues associated with the Company’s transmission and storage system represented approximately 88% and 85% of total revenues for the year ended December 31, 2012 and 2011, respectively. As of December 31, 2012, the weighted average remaining contract life based on total revenues for firm transmission and storage contracts was approximately 9.4 years.

The Company’s transmission and storage system was initially constructed to receive natural gas from interstate pipelines and local conventional natural gas producers for delivery to LDCs and industrial end-users located in West Virginia and western Pennsylvania, including the city of Pittsburgh. Prompted by the rapid development of the Marcellus Shale in 2007 and the resulting excess supply of natural gas in the region, the Company shifted the focus of its transmission and storage system and reengineered its pipeline to act as a header system receiving natural gas produced in the Marcellus play. In turn, the system was poised to deliver this Marcellus gas into interstate pipelines that serve customers throughout the Mid-Atlantic and Northeastern United States, as well as to continue delivering to LDCs and end-users directly connected to the system.

In 2010, the Company initiated an expansion of its transmission and storage system, which is now complete, in order to increase its ability to receive gas produced in the Marcellus Shale for delivery to high demand, end-user markets through existing interconnects with several interstate transmission pipelines. The expansion of the Company’s transmission and storage system involved increasing the maximum allowable operating pressure of six miles of pipeline, installing emission controls and increasing horsepower on two engines at the Pratt Compressor Station, installing a delivery point interconnect with Texas Eastern and installing two receipt points with an affiliated Marcellus gathering system located in Greene County, Pennsylvania. The Equitrans 2010 Marcellus expansion project increased off-system capacity by over 200 BBtu per day at a cost of approximately $16 million.

The Company has an acreage dedication from EQT pursuant to which the Company 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 and is expanding its retained midstream infrastructure, which connects to the Company’s transmission and storage system, to meet expected production growth.

On June 18, 2012, the Company transferred ownership of the Sunrise Pipeline, which was under construction at the time and placed into service in the third quarter of 2012, to EQT. Concurrent with this transfer, the Company entered into a capital lease with EQT for the Sunrise Pipeline. Under the lease, the Company operates the pipeline as part of its transmission and storage system under the rates, terms and conditions of its FERC-approved tariff.  The Sunrise Pipeline provides access to liquids-rich Marcellus Shale acreage and consists of 41.5 miles of 24-inch diameter pipeline that parallels and interconnects with the segment of the Company’s transmission and storage system from Wetzel County, West Virginia to Greene County, Pennsylvania. The Sunrise Pipeline provides 314 BBtu per day of additional firm capacity to the system at an estimated construction cost of approximately $225 million.

The Company generally provides transmission and storage services in two manners: firm service and interruptible service. A significant portion of the Company’s transportation and storage services are provided through firm service agreements. The Company generally does not take title to the natural gas transported or stored for its customers.

Approximately 1.0 TBtu per day of the Company’s transmission capacity and 19.9 TBtu of its storage capacity, respectively, were subscribed under firm transmission and storage contracts with a weighted average remaining contract life based on contracted revenues of approximately 9.7 years for transmission contracts and 3.0 years for storage contracts as of December 31, 2012.

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Transmission and Storage System

Firm transmission contracts obligate the Company’s customers to pay a fixed monthly charge to reserve an agreed upon amount of pipeline capacity regardless of the actual pipeline capacity used by a customer during each month, which is referred to as a monthly reservation charge. In addition to monthly reservation charges, the Company also collects usage charges when a firm transmission customer uses the capacity it has reserved under these firm transmission contracts. These charges are assessed on the actual volume of natural gas transported on the transmission system. Firm transmission customers are charged an interruptible over firm usage charge when the level of natural gas received for delivery from a firm transmission customer exceeds its reserved capacity.

Firm storage contracts obligate customers to pay a fixed monthly charge for the firm right to inject, withdraw and store a specified volume of natural gas regardless of the amount of storage capacity actually utilized by the customer. Firm storage customers are also assessed usage charges on the actual quantities of natural gas injected into or withdrawn from storage. Firm service storage customers are charged an interruptible over firm usage charge when the level of gas withdrawn exceeds the customer’s maximum daily withdrawal limit.

The Company’s transmission and storage system also derives a small portion of its revenues through interruptible service contracts under which its customers pay fees based on their actual utilization of assets for transmission and storage services. Customers who have executed interruptible contracts are not assured capacity or service on the applicable pipeline and storage facilities. To the extent that physical capacity that is contracted for firm service is not being fully utilized or there is excess capacity that has not been contracted for service, the system can allocate such capacity to interruptible services. The Company also provides natural gas “park and loan” services to assist customers in managing short-term gas surpluses or deficits. Under these park and loan service agreements, customers are charged a usage fee based on the quantities of natural gas stored in (park), or borrowed from (loan), the Company’s facilities.

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As of December 31, 2012, approximately 54% of the Company’s contracted transmission firm capacity was subscribed at the maximum recourse rate allowed under the Company’s tariff. The remaining 46% of contracted transmission firm capacity was subscribed by customers under negotiated rate agreements at rates generally above the maximum recourse rate under the tariff, some of which is under contracts pending execution with respect to binding precedent agreements and the remaining contracts have been filed with and accepted by the FERC.

Gathering System

The Company’s gathering system consists of approximately 2,000 miles of FERC-regulated low-pressure gathering lines that have multiple delivery interconnects with transmission and storage systems. Revenues associated with the Company’s gathering system, all of which were generated under interruptible gathering service contracts, represented approximately 12% and 15% of total revenues for the year ended December 31, 2012 and 2011, respectively.

The primary term of a typical gathering agreement is one year with month-to-month roll over provisions terminable upon at least 30 days notice. The rates for gathering service are based on the maximum posted tariff rate and assessed on actual receipts into the gathering system. The Company also retains a fixed percentage of wellhead natural gas receipts to recover natural gas used to run its compressor stations and lost and unaccounted for gas experienced on its gathering system.

Gathering System

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The following table provides information regarding the transmission, storage and gathering assets as of December 31, 2012:

The following table provides a revenue breakdown of the Company’s contracts by business segment for the year ended December 31, 2012:

Strategy

The Company’s principal business objective is to increase the quarterly cash distributions that it pays to unitholders over time while ensuring the ongoing stability of its business. The Company expects to achieve this objective through the following business strategies:

·                   Pursuing accretive acquisitions from EQT.  The Company intends to seek opportunities to expand its existing natural gas transmission, storage and gathering operations primarily through accretive acquisitions from EQT. While the Company will review acquisition opportunities from third parties as they become available, it expects that the majority of its most significant opportunities will be sourced from EQT’s existing portfolio of midstream assets or from expansion projects or acquisitions that EQT undertakes in the future as it builds additional midstream assets to support its production growth.

·                   Capitalizing on economically attractive organic growth opportunities.  EQT’s acreage dedication to the Company’s assets and EQT’s economic relationship with the Company provides a platform for organic growth. The Company expects to achieve this growth by meeting EQT’s midstream needs, which the Company expects to increase as a result of EQT’s anticipated drilling activity in the Company’s areas of operation. In addition, the Company intends to use EQT’s knowledge of, and expertise in, the Marcellus Shale in order to target and efficiently execute economically attractive organic growth projects, although EQT is under no obligation to share such knowledge and expertise with the Company.  The Company will evaluate organic expansion and greenfield construction opportunities in existing and new markets that it believes will increase the volume of transmission, storage and gathering capacity subscribed on its system. The Company is executing on 2013 expansion projects that it believes will increase the capacity of the transmission and storage system by approximately 450 BBtu per day at a total cost of approximately $28 million. These expansion projects are expected to be placed into service by year-end 2013. Additional 2013 expansion capital expenditures of approximately $10 million primarily relate to projects which will be completed in 2014.

·                   Attracting additional third-party volumes.  The Company actively markets its midstream services to, and pursues strategic relationships with, third-party producers in order to attract additional volumes and/or expansion opportunities. The Company believes that its connectivity to interstate pipelines, which is a key feature of a header system transmission pipeline, as well as its position as an early developer of midstream infrastructure within certain areas of the Marcellus Shale, will allow the Company to capture additional third-party volumes in the future. The Company anticipates that organic growth projects that it pursues, or any assets it acquires from EQT, will be constructed in a manner that

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leverages economies of scale to allow for incremental third party volumes in excess of capacity amounts needed by EQT.

·                   Focusing on stable, fixed-fee business.  The Company intends to pursue opportunities to provide fixed-fee transmission, storage and gathering services to EQT and third parties. The Company will focus on obtaining additional long-term firm commitments from customers, which may include reservation-based charges, volume commitments and acreage dedications.

·                   Increasing access to existing and new delivery markets.  The Company 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. The Company’s transmission and storage system has the flexibility to accommodate significant additional throughput to service new end-user markets and it believes that the Company’s access to numerous supply sources, including Marcellus Shale production, five interstate pipelines and its on-system storage facilities, which can be used to balance volatile load swings, make the Company an attractive option for these end-user delivery markets.

The Company’s Relationship with EQT

One of the Company’s principal attributes is its relationship with EQT. Headquartered in Pittsburgh, Pennsylvania, in the heart of the Appalachian Basin, EQT is an integrated energy company, with an emphasis on natural gas production, gathering, transmission, distribution and marketing. EQT conducts its business through three business segments: EQT Production, EQT Midstream and Distribution. EQT Production is one of the largest natural gas producers in the Appalachian Basin with 6.0 Tcfe of proved reserves across 3.5 million gross acres as of December 31, 2012. EQT Midstream provides transmission, storage and gathering services for EQT’s produced gas, as well as to third parties in the Appalachian Basin. EQT also has a regulated natural gas distribution subsidiary, Equitable Gas Company, LLC (Equitable Gas Company), which distributes and sells natural gas to residential, commercial and industrial customers in southwestern Pennsylvania, West Virginia and eastern Kentucky.

EQT owns a 2.0% general partner interest in the Company, all of the Company’s incentive distribution rights and a 57.4% limited partner interest in the Company. Because of its ownership of the incentive distribution rights, EQT is positioned to directly benefit from committing additional natural gas volumes to the Company’s systems and from facilitating accretive acquisitions and organic growth opportunities. However, EQT is under no obligation to make acquisition opportunities available to the Company, is not restricted from competing with the Company and may acquire, construct or dispose of midstream assets without any obligation to offer the Company the opportunity to purchase or construct these assets.

The Company believes that its relationship with EQT is advantageous for the following reasons:

·                  EQT is a leader among exploration and production companies in the Appalachian Basin.  EQT had approximately 3.5 million gross acres as of December 31, 2012, of which approximately 540,000 gross acres were located in the Marcellus Shale. A substantial portion of EQT’s drilling efforts in 2011 and 2012 were focused on drilling horizontal wells in the Marcellus Shale formations of southwestern Pennsylvania and northern West Virginia. For the year ended December 31, 2012, EQT reported total sales volumes of 258.5 Bcfe, representing a 33% increase compared to the year ended December 31, 2011. Approximately 58% of EQT’s total production in 2012 was from wells in the Marcellus Shale. EQT Marcellus sales volumes were 85% higher for the year ended December 31, 2012 as compared to the year ended December 31, 2011.

·                  EQT has a substantial and growing portfolio of midstream assets.  The Company expects to have the opportunity to purchase additional midstream assets from EQT in the future, although EQT is under no obligation to make the opportunities available to the Company. EQT’s retained midstream assets include:

–                 Sunrise Pipeline. On June 18, 2012, the Company transferred ownership of the Sunrise Pipeline, which was under construction at the time and placed into service in the third quarter of 2012, to EQT. The Sunrise Pipeline provides access to liquids-rich Marcellus Shale acreage and consists of 41.5 miles of 24-inch diameter pipeline that parallels and interconnects with the segment of the Company’s transmission and storage system from Wetzel County, West

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Virginia to Greene County, Pennsylvania. In addition, the Sunrise Pipeline project included connecting to a new delivery point with Texas Eastern in Greene County and constructing the Jefferson compressor station. The Sunrise Pipeline project provides 314 BBtu per day of additional firm capacity to the system at an estimated cost of approximately $225 million. Furthermore, the Jefferson compressor station can be expanded to provide in aggregate over 470 BBtu per day of additional firm capacity. Management of EQT has indicated to the Company that EQT currently anticipates that this system will be fully developed over the next several years through the addition of relatively low-cost compression, including the expansion of the Jefferson compressor station. Initially, the Company is operating the Sunrise Pipeline under a lease agreement with EQT by which the Company markets the capacity, enters into all agreements for transportation service with customers and operates the Sunrise Pipeline according to the terms of its tariff. The Company makes lease payments to EQT based on revenues collected and the actual cost to operate the Sunrise Pipeline. As a result, the Sunrise Pipeline lease is not expected to have a net positive or negative impact on distributable cash flow. Upon termination of the lease agreement, the Company will be required to purchase the Sunrise Pipeline at a price to be negotiated between the parties. EQT has the ability to terminate the lease agreement early in its sole discretion.

–                 Other retained midstream assets. EQT’s retained midstream asset base also includes approximately 8,300 miles of gathering pipelines with throughput of approximately 838 BBtu of natural gas per day for the year ended December 31, 2012. These retained assets include approximately 100 miles of high-pressure gathering lines serving both liquids-rich and dry areas in the Marcellus Shale located in Greene, Washington, Armstrong and Tioga counties in Pennsylvania and Doddridge and Taylor counties in West Virginia.

–                 Development of additional midstream assets. As EQT expands its exploration and production operations in the Appalachian Basin, primarily in the Marcellus and Utica Shales, into areas that are currently underserved by midstream infrastructure, the Company expects it will develop, either independently or in partnership with EQT, additional midstream assets to ensure takeaway capacity for EQT’s expected production growth.

While the Company’s relationship with EQT may provide significant benefits, it may also become a source of potential conflicts. For example, EQT is not restricted from competing with the Company. In addition, all of the executive officers and a majority of the directors of the Company’s general partner also serve as officers and/or directors of EQT, and these officers and directors face conflicts of interest, which include the allocation of their time between the Company and EQT. For a description of the Company’s relationships with EQT, please read Item 13, “Certain Relationships and Related Transactions, and Director Independence.”

Markets and Customers

For the years ended December 31, 2012, 2011 and 2010, EQT accounted for approximately 78%, 79% and 81%, respectively, of the Company’s total revenues. No other customers accounted for more than 10% of revenues in 2012, 2011 or 2010.

Transmission and Storage Customers

The Company provides natural gas transmission services for EQT and third parties, predominantly consisting of LDCs, marketers, producers and commercial and industrial users that the Company believes to be creditworthy. The Company’s transmission system serves not only adjacent markets in Pennsylvania and West Virginia but also provides its customers access to high-demand end-user markets in the Mid-Atlantic and Northeastern United States through 1,377 BBtu per day of delivery interconnect capacity with major interstate pipelines. The Company provides storage services to a broad mix of customers, including marketers and LDCs.

The Company’s primary transportation and storage customer is EQT. For the years ended December 31, 2012, 2011 and 2010, EQT and its affiliates accounted for approximately 81%, 83% and 86%, respectively, of transmission revenues and 68%, 77% and 82%, respectively, of storage revenues. Other than EQT, no customer accounted for more than 10% of total transmission and storage revenue for the years ended December 31, 2012,

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2011 or 2010. The Company’s other principal transmission customers include XTO Energy Inc., a wholly-owned subsidiary of ExxonMobil Corporation, and PDC Mountaineer, LLC.

Gathering Customers

The Company’s gathering system currently has approximately 2,500 receipt points with a number of natural gas producers. EQT represented approximately 63% of the 78 BBtu per day of natural gas supplied to the gathering system in 2012, approximately 46% of the 78 BBtu per day of natural gas supplied to the gathering system in 2011, and approximately 45% of the 83 BBtu per day of natural gas supplied to the gathering system in 2010. The Company has gathering agreements conforming to its tariff with marketers and distribution companies that purchase natural gas from receipt points on the system for delivery to the interstate pipeline market, including EQT Energy, Equitable Gas Company and Dominion Field Services.

Dominion Field Services generally provides any necessary processing for the gas gathered by the Company’s gathering system. In connection with the Company’s sale of certain processing plants to Dominion Field Services in 2000, it entered into an agreement with a primary term through December 31, 2014 pursuant to which Dominion Field Services is obligated to process any wet gas the Company delivers to certain processing facilities up to the individual operating capacity of each plant. During the years ended December 31, 2012, 2011 and 2010, 77%, 76% and 75%, respectively, of the natural gas supplied to the Company’s gathering system was processed by Dominion Field Services. The Company’s gathering customers are responsible for the costs associated with treating and processing natural gas in order to meet pipeline specifications, and are required to have processing agreements in place with Dominion Field Services or another processor as a prerequisite to receiving transportation service on its gathering system.

Competition

Competition for natural gas transmission and storage volumes is primarily based on rates, customer commitment levels, timing, performance, commercial terms, reliability, services levels, location, reputation and fuel efficiencies. The Company’s principal competitors in its natural gas transmission and storage market include companies that own major natural gas pipelines. In addition, the Company competes with companies who are building high pressure gathering facilities that are not subject to FERC jurisdiction to move volumes to interstate pipelines. EQT also owns and in the future may construct natural gas transmission pipelines and high-pressure gathering facilities. Major pipeline natural gas transmission companies who compete with the Company also have existing storage facilities connected to their transmission systems that compete with certain of the Company’s storage facilities. Pending and future construction projects, if and when brought on-line, may also compete with the Company’s natural gas transmission and storage services and many of its competitors have capital and other resources far greater than the Company. These projects may include FERC-certificated expansions and greenfield construction projects.

Key competitors for new low-pressure gathering systems include independent gas gatherers and integrated energy companies. Many of the Company’s competitors have capital resources and control supplies of natural gas greater than it. The Company’s major competitors for natural gas supplies and markets in its operating regions include Dominion Transmission, local distribution companies and small producers constructing their own gathering systems.

Regulatory Environment

FERC Regulation

The Company’s interstate natural gas transportation and storage operations are regulated by FERC under the NGA, the NGPA and the Energy Policy Act of 2005. The Company’s system operates under a tariff approved by FERC that establishes rates, cost recovery mechanisms and the terms and conditions of service to its customers. Generally, FERC’s authority extends to:

·                    rates and charges for natural gas transmission, storage and gathering services;

·                    certification and construction of new interstate transportation and storage facilities;

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·                    extension or abandonment of interstate transportation 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 transportation and storage facilities; and

·                    initiation and discontinuation of interstate transportation and storage services.

The Company holds certificates of public convenience and necessity for its transmission and storage system issued by FERC pursuant to Section 7 of the NGA covering rates, facilities, activities and services. These certificates require the Company to provide open-access services on its interstate pipeline and storage facilities on a non-discriminatory basis to all customers who qualify under the FERC gas tariff. In addition, under Section 8 of the NGA, FERC has the power to prescribe the accounting treatment of certain items for regulatory purposes. Thus, the books and records of the Company’s interstate pipeline and storage facilities may be periodically audited by FERC.

FERC regulates the rates and charges for transportation and storage in interstate commerce. Under the NGA, rates charged by interstate pipelines must be just and reasonable. FERC’s cost-of-service regulations generally limit the maximum recourse rates for transportation and storage services to the cost of providing service plus a reasonable rate of return. In each rate case, FERC must approve service costs, the allocation of costs, the allowed rate of return on capital investment, rate design and other rate factors. A negative determination on any of these rate factors could adversely affect the Company’s business, financial condition, results of operations, liquidity and ability to make distributions.

The maximum recourse rate that the Company may charge for its services is established through FERC’s 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 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 the Company’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 below.

Pursuant to the NGA, changes to rates or terms and conditions of service can be proposed by a pipeline company under Section 4, or the existing interstate transportation 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. Rate increases proposed by a pipeline may be allowed to become effective subject to refund, while rates or terms and conditions of service which are the subject of a complaint under Section 5 are subject to prospective change by FERC. Rate increases proposed by a regulated interstate pipeline may be challenged and such increases may ultimately be rejected by FERC. Any successful challenge against rates charged for the Company’s transportation and storage services could have a material adverse effect on its business, financial condition, results of operations, liquidity and ability to make distributions.

The Company’s interstate pipeline may also use “negotiated rates” which, in theory, could involve rates above or below the recourse rate or rates that are subject to a different rate structure, 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 maximum recourse rates. As of December 31, 2012, approximately 46% of the system’s contracted firm transportation capacity was committed under such “negotiated rate” contracts. Each negotiated rate transaction is designed to fix the negotiated 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 transportation 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

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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 the Company to seek modification of the agreement or require the Company to modify its 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 transportation. The Company maintains rates and terms of service in its tariff for unbundled gathering services performed on its gathering facilities in connection with the transportation service. Just as with rates and terms of service for transmission and storage services, the Company’s rates and terms of services for its 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 the Company proposes for its gathering service may be protested and such increases or changes may ultimately be rejected by the FERC.

Pipeline Safety and Maintenance

The Company’s interstate natural gas pipeline system is subject to regulation by the PHMSA office of the DOT. 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 preventative 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 the Company’s performance of customary pipeline management activities, significant additional expenses may be incurred if anomalous pipeline conditions are discovered or more stringent pipeline safety requirements are implemented. For example, on August 25, 2011, PHMSA published an advanced notice of proposed rulemaking in which the agency is seeking public comment on a number of changes to its natural gas transmission pipeline regulations contained in federal regulations including: (i) modifying the definition of high consequence areas; (ii) strengthening integrity management requirements as they apply to existing regulated operators; (iii) strengthening or expanding various non-integrity pipeline management standards relating to such matters as valve spacing, automatic or remotely-controlled valves, corrosion protection and gathering lines; and (iv) adding new regulations to govern the safety of underground natural gas storage facilities including underground storage caverns and injection withdrawal well piping that are not currently regulated under the federal regulations. PHMSA has specifically indicated an intent in this rulemaking to address the need for standards governing the safety of underground natural gas storage facilities. Public comments on these matters were submitted to PHMSA in December 2011, and a final rule from PHMSA is forthcoming.

On January 3, 2012, President Obama signed into law the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011. The Act increases the maximum civil penalties for administrative enforcement actions, requires the DOT to study and report on the sufficiency of existing gathering line regulations to ensure safety and the use of leak detection systems by hazardous liquid pipelines, requires pipeline operators to verify their records on maximum allowable operating pressure and imposes new emergency response and incident notification requirements.

States are largely preempted by federal law from regulating interstate pipeline safety but may assume responsibility for enforcement of federal interstate pipeline safety regulations for certain intrastate facilities. For example, a Pennsylvania statute was enacted in 2012 authorizing the PA PUC to enforce federal regulations applicable to intrastate gathering lines as well as non-FERC certificated transmission lines. In practice, states vary considerably in their authority and capacity to address pipeline safety. The Company does not anticipate any significant problems in complying with any state laws and regulations which are determined to be applicable to its operations. The Company’s natural gas pipelines have inspection and compliance programs designed to maintain compliance with federal and state pipeline safety and pollution control requirements.

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The Company believes that its operations are in substantial compliance with all existing federal, state and local pipeline safety laws and regulations and that its compliance with such laws and regulations will not have a material adverse effect on its business, financial condition, results of operations, liquidity or ability to make distributions, but the Company can provide no assurance that the adoption of new laws and regulations such as those proposed by PHMSA will not result in significant added costs that could have such a material adverse effect in the future.

Pipeline Safety Cost Tracker

The Company’s Pipeline Safety Cost Tracker (PSCT) is a cost recovery mechanism for qualifying costs incurred by the Company under the PSIA. The qualifying costs recoverable through the PSCT include a rate of return, taxes and depreciation associated with capital investments and actual operating and maintenance expenses incurred under the PSIA. The PSCT surcharge is a usage charge expressed in dollars per Dth and is assessed to firm and interruptible transmission service customers. The Company is required to track all expenses and capital investments associated with the PSIA made on and after September 1, 2005. The Company makes annual filings with the FERC to adjust the PSCT surcharge to reconcile actual historic qualifying costs incurred against PSCT revenues collected.

On March 1, 2012, Equitrans made its annual filing with the FERC to recover costs it incurs to comply with the PSIA. The filing provided for the recovery of $10.4 million in qualifying pipeline safety costs. One customer and the Independent Oil and Gas Association filed protests which asserted, among other things, that Equitrans had not included all the appropriate volumes in calculating the level of its surcharge. Equitrans responded to the protests and in an order issued March 30, 2012 the FERC accepted the annual filing and suspended it, allowing the surcharge to become effective on April 1, 2012. Equitrans submitted additional information to the FERC on April 19, 2012 with the expectation that the FERC would subsequently issue an order based on the material Equitrans submitted.

On January 14, 2013, following numerous discussions with its customers, Equitrans filed a Stipulation and Agreement of Settlement (Proposed Settlement) with the FERC. If approved by the FERC, the Proposed Settlement will resolve all issues arising out of Equitrans’ 2012 PSCT annual filing. The Proposed Settlement will eliminate the tracking of PSIA costs and replace the PSCT surcharge with a Pipeline Safety Cost (PSC) rate effective April 1, 2013. The new PSC rate will have both a reservation and a usage component.  The reservation component of the PSC rate applicable to firm transportation service will be set at $0.8108 per Dth of the contract Maximum Daily Quantity (MDQ) applicable to service provided on the mainline system and the usage component will be set at $0.1372 per Dth delivered to the customer. The PSC rate applicable to interruptible over firm service, no-notice firm transportation service nominated on a point to point basis and interruptible service will be $0.1372 per Dth delivered to the customer. Additionally, under the Proposed Settlement, Equitrans will reduce its transmission retainage factor approved in Equitrans’ most recent rate case from 3.72% to 2.72% effective February 1, 2013.  Equitrans will no longer track its continued recovery of base storage gas, and the 7.1 base storage gas recovery limit established in that 2006 rate case settlement will be eliminated. To the extent that Equitrans over-recovers its actual fuel and lost gas, the excess gas could be used to replenish the storage base gas. If approved, the Proposed Settlement PSC rate and transmission retainage factor will be in effect for a minimum of three years.

Since the inception of the PSCT surcharge in September 2005 through December 31, 2012, the Company has invested approximately $62 million and recognized approximately $37 million of revenues associated with the PSCT. During the year ended December 31, 2012, the Company recognized approximately $8 million of revenues associated with the PSCT.

Environmental, Health and Safety Regulation

The Company’s natural gas transportation, storage and gathering activities are subject to stringent and complex federal, state and local laws and regulations governing environmental protection, including air emissions, water quality, wastewater discharges and solid waste management. Such laws and regulations generally require the Company to obtain and comply with a wide variety of environmental registrations, licenses, permits and other approvals. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and/or criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations.

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The Company believes that compliance with existing federal, state and local environmental laws and regulations will not have a material adverse effect on its business, financial condition, results of operations, liquidity or ability to make distributions. Nevertheless, environmental regulatory programs continue to evolve and future regulations may place more restrictions and limitations on activities that may affect the environment. As a result, 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 different from the amounts the Company currently anticipates.

The Company has established procedures for ongoing evaluation of its operations to identify potential environmental exposures and to assure compliance with regulatory policies and procedures. Ongoing expenditures for compliance with environmental laws and regulations, including investments in plant and facilities to meet environmental requirements, have not been material to the Company’s business, financial condition, results of operations, liquidity or ability to make distributions.

Climate Change

Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation. Effective January 1, 2011, the EPA began regulating greenhouse gas emissions by subjecting new facilities and major modifications to existing facilities that emit large amounts of greenhouse gases to the permitting requirements of the federal Clean Air Act.  In addition, the U.S. Congress has been considering bills that would establish a cap-and-trade program to reduce emissions of greenhouse gases. Legislation or regulation that restricts carbon emissions could increase the Company’s cost of environmental compliance by requiring the Company to install new equipment to reduce emissions from larger facilities and/or purchase emission allowances. Climate change and greenhouse gas 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. Conversely, legislation or regulation that sets a price on or otherwise restricts carbon emissions could also benefit the Company 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 fuels such as coal. The effect on the Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.

Seasonality

Operating revenues are seasonal and, based on utility customer contracts, are currently expected to be higher in the first and fourth quarters of each year. 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

The Company’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 the Company’s operations. Portions of the land on which the Company’s pipelines and facilities are located are owned by the Company in fee title, and it believes that it has satisfactory title to these lands. The remainder of the land on which the Company’s pipelines and facilities are located are held by the Company pursuant to surface leases between the Company, as lessee, and the fee owner of the lands, as lessors. The Company has leased or owned much of these lands for many years without any material challenge known to the Company relating to the title to the land upon which the assets are located, and it is believed that the Company has satisfactory leasehold estates or fee ownership to such lands. The Company believes that it has satisfactory title to all of its material leases, easements, rights-of-way, permits and licenses, and the Company has no knowledge of any material challenge to its title to such assets or their underlying fee title.

However, there are certain lands within the Company’s storage pools as to which it does not currently have real property rights. The Company has identified the lands as to which it believes it must obtain such rights and is in the midst of a program to acquire such rights. Since the beginning of this program in 2009 through December 31, 2012, the Company has successfully acquired such rights for approximately 14,679 acres out of a total 46,452 acres, and the Company expects to acquire the remainder within the next four years. In accordance with the Company’s FERC license, the geological formations within which its permitted storage facilities are located cannot be used by

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third parties in any way that would detrimentally affect its storage operations and the Company has the power of eminent domain with respect to the acquisition of necessary real property rights to use such storage facilities. The Company believes the cost to acquire such rights will be approximately $7 million over the next four years.

Some of the leases, easements, rights-of-way, permits and licenses which were transferred to the Company at the closing of the IPO in July 2012 require the consent of the grantor of such rights, which in certain instances is a governmental entity. The Company obtained, prior to the closing of the IPO, sufficient third-party consents, permits and authorizations for the transfer of the assets necessary to enable it to operate its business in all material respects.

EQT, the Company or their affiliates may initially continue to hold record title to portions of certain assets until the Company makes the appropriate filings in the jurisdictions in which such assets are located and obtains any consents and approvals that were not obtained prior to transfer. Such consents and approvals would include those required by federal and state agencies or political subdivisions. In some cases, EQT may, where required consents or approvals have not been obtained, temporarily hold record title to property as nominee for the Company’s benefit and in other cases may, on the basis of expense and difficulty associated with the conveyance of title, cause its affiliates to retain title as nominee for the Company’s  benefit until a future date. The Company anticipates that there will be no material change in the tax treatment of its common units resulting from EQT holding the title to any part of such assets subject to future conveyance or as the Company’s nominee.

Insurance

The Company generally shares insurance coverage with EQT, for which it will reimburse EQT pursuant to the terms of the omnibus agreement. The Company’s insurance program includes general liability insurance, auto liability insurance, workers’ compensation insurance and property insurance. The Company’s general partner maintains director and officer liability insurance under a separate policy from EQT’s corporate director and officer insurance. In addition, the Company has procured a separate general liability policy. All insurance coverage is in amounts which management believes are reasonable and appropriate.

Facilities

EQT leases its corporate offices in Pittsburgh, Pennsylvania. Pursuant to the omnibus agreement, the Company pays a proportionate share of EQT’s costs to lease the building.

Employees

The Company does not have any employees. The Company is managed and operated by the directors and officers of its general partner. All of the Company’s executive management personnel are employees of EQT or an affiliate of EQT and devote the portion of their time to the Company’s business and affairs that is required to manage and conduct its operations. Under the terms of the omnibus agreement with EQT, the Company reimburses EQT for the provision of various general and administrative services for its benefit, for direct expenses incurred by EQT on the Company’s behalf and for expenses allocated to the Company as a result of it being a public entity.

Availability of Reports

The Company 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.  The Company’s press releases and recent analyst presentations are also available on the Company’s website.

Composition of Segment Operating Revenues

Presented below are operating revenues by segment as a percentage of total operating revenues of the Company.

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Financial Information about Segments

See Note 2 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 is a Delaware limited partnership formed in January 2012.

Financial Information about Geographic Areas

All of the Company’s assets and operations are located in the continental United States.

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Item 1A.  Risk Factors

Risks Relating to Our Business

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.

We are dependent 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 transmission, storage and gathering services to EQT. During the year ended December 31, 2012, approximately 78% of our revenues were from EQT. We expect to derive a substantial majority of our revenues from EQT for the foreseeable future. Therefore, any event, whether in our area 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 may have an adverse effect on its drilling operations, revenue, profitability, future rate of growth and liquidity;

·                   infrastructure capacity constraints and interruptions;

·                   risks associated with the operation of its wells, pipelines and facilities, including potential environmental liabilities;

·                   the availability of capital on a satisfactory economic basis to fund its operations;

·                   its ability to identify production opportunities based on market conditions;

·                   uncertainties inherent in projecting future rates of production;

·                   its ability to develop additional reserves that are economically recoverable, to optimize existing well production and sustain production;

·                   adverse effects of governmental and environmental regulation and negative public perception regarding its operations; and

·                   the loss of key personnel.

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 transmission and storage system as well as the volumes gathered on our gathering system will be dependent on receiving consistent or increasing commitments from EQT. While EQT has dedicated acreage to, and entered into long-term firm transportation 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. For example, EQT Energy, LLC, or EQT Energy, a wholly-owned marketing affiliate of EQT, allowed a storage agreement with us for 3.6 Bcf of storage capacity and the associated firm transmission agreement to expire on March 31, 2012. This decision was likely due to lower natural gas price spreads and increased supply of natural gas from the Marcellus Shale. A reduction in the capacity subscribed or volumes transported, stored or gathered on our systems by EQT could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

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 the minimum quarterly distribution to holders of our common and subordinated units.

In order to pay the minimum quarterly distribution of $0.35 per unit, or $1.40 per unit on an annualized basis, we will require available cash of approximately $12.4 million per quarter, or $49.5 million per year, based on the number of common, subordinated and general partner units outstanding at December 31, 2012. We may not have

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sufficient available cash each quarter to enable us to pay the minimum quarterly 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 transmission, storage and gathering services;

·                   the level of firm transmission and storage capacity sold and volumes of natural gas we transport, store and gather 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 transmission and storage agreements;

·                   the effect of seasonal variations in temperature on the amount of natural gas that we transport, store and gather;

·                   the level of competition from other midstream energy companies in our geographic markets;

·                   the creditworthiness of our customers;

·                   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;

·                   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;

·                   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 transportation, storage and gathering 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 transportation and storage operations are regulated by the FERC under the NGA, the NGPA, and the Energy Policy Act of 2005. Our gathering operations are also regulated by the FERC in connection with our interstate transportation operations. Our system operates under a tariff approved by the FERC that establishes 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, storage and 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.

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 maximum recourse rate that may be

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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 tariff.

Pursuant to the NGA, existing interstate transportation 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” (i.e., the maximum rates an interstate pipeline may charge for its services under its tariff) and (ii) “negotiated rates” which generally involve rates above 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. As of December 31, 2012, approximately 46% of our system’s contracted firm transportation capacity was committed under such “negotiated rate” contracts, rather than recourse rate or discount 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 transportation and storage services could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make distributions.

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 our gathering facilities, which are connected to our transmission and storage system. Just as with rates and terms of service for transportation and storage services, our rates and terms of services for our gathering may be challenged by complaint and are subject to prospective change by the FERC. Rate increases and changes to terms and conditions of service which we propose for our gathering service 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 transportation 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 rate and terms of service for our gathering operations, our gathering facilities are not subject to the FERC’s certification and construction authority. Prior to commencing construction of new or existing interstate transportation 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 refusal by an agency 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 refusal or modification could materially and negatively impact the additional revenues expected from these projects.

FERC regulations also extend to the terms and conditions set forth in agreements for transportation 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. Non-conforming agreements must be filed with, and accepted by, the FERC. In the event that the FERC finds that an agreement, in whole or part, is materially non-conforming, 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. This policy was upheld on May 29, 2007 by the Court of Appeals for the District of Columbia Circuit. The FERC will determine, on a case-by-case basis, whether the owners of an interstate pipeline have such actual or potential

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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. If the FERC’s policy were to change and if the FERC were to disallow a substantial portion of our pipeline’s income tax allowance, our regulated rates, and therefore our revenues and ability to make distributions, 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 transportation capacity and transportation and storage facilities.

Failure to comply with applicable provisions of the NGA, the NGPA, the Pipeline Safety Act of 1968 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 of up to $1,000,000 per day, per violation.

In addition, future federal, state, or local legislation or regulations under which we will operate our natural gas transportation, storage and gathering businesses may have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make 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 distributable cash flow.

Our business is dependent on the continued availability of natural gas production and reserves in our areas of operation. Low prices 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 existing wells and natural gas supply basins with access to our systems 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, the competition for natural gas supplies to serve other markets could reduce the amount of natural gas supply for our customers or lower natural gas prices could cause producers to determine in the future that drilling activities in areas outside of our current areas of operation are strategically more attractive to them. For example, in 2012 in response to low natural gas prices, a number of large natural gas producers announced their intention to re-evaluate and/or reduce their drilling programs in certain areas, including the Appalachian Basin. 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 cash distributions to our unitholders. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas transported, stored and gathered on our systems and cash flows associated therewith, our customers must continually obtain adequate supplies of natural gas.

The primary factors affecting our ability to obtain non-dedicated sources of natural gas include (i) the level of successful drilling activity near our systems and (ii) 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 system 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, geological considerations, environmental or other governmental regulations, the availability of drilling permits, the availability of drilling rigs, 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. These factors include worldwide economic conditions; weather conditions and seasonal trends; the levels of domestic production and consumer demand; the availability of imported liquefied natural gas, or LNG; the ability to export LNG; the availability of transportation systems with adequate capacity; the volatility and uncertainty of regional pricing differentials and premiums; the price and availability of alternative fuels; the effect of energy conservation measures; the nature and extent of governmental regulation and taxation; and the anticipated future prices of natural

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gas, LNG and other commodities. Declines in natural gas prices could have 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.

The price of natural gas has been at historically low levels recently, with the five-year NYMEX natural gas futures price at $3.62 per MMbtu in April 2012, compared to a high of $11.51 per MMbtu in July 2008. As of January 31, 2013, the near month NYMEX natural gas futures price was $3.23 per MMbtu. The lower prices of natural gas are due in part to high levels of natural gas in storage, increased production, especially from unconventional sources, like shale plays, and the effects of the economic downturn starting in 2008. According to the U.S. Energy Information Administration, or EIA, the amount of natural gas produced in the continental United States increased 14.1% from 55.3 Bcf/d to 63.0 Bcf/d from 2008 to 2011. Furthermore, the amount of natural gas in storage in the United States increased  to 3.5 Tcf as of December 31, 2012 compared to the five-year average of 3.2 Tcf, due to the unseasonably warm winter of 2011/2012 and to the decisions of many producers to store natural gas based on their expectation of higher prices in the future. In response to lower natural gas prices, the number of land-based natural gas drilling rigs in the continental United States has declined from approximately 1,403 as of December 31, 2008 to approximately 370 as of December 31, 2012 according to Smith Bits (a unit of Schlumberger Limited).

In addition, it may be more difficult to maintain or increase the current volumes on our gathering systems in unconventional resource plays such as the Marcellus Shale, as the basins in those plays generally have higher initial production rates and steeper production decline curves than wells in more conventional basins. Furthermore, our gathering assets were initially constructed as a low-pressure system designed for shallow, vertical wells and Marcellus Shale production is increasingly from horizontal wells at higher pressure than our existing gathering assets were designed to handle. If natural gas prices remain low, production in the area around our low-pressure gathering system may continue to decline. Accordingly, volumes on our gathering system would need to be replaced at a faster rate to maintain or grow the current volumes than may be the case in other regions of production. Should we determine that the economics of our gathering assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, revenues associated with these assets will decline over time.

If new supplies of natural gas are not obtained to replace the natural decline in volumes from existing supply basins, or if natural gas supplies are diverted to serve other markets, the overall volume of natural gas 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 on our 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, 2012, 2011 and 2010, EQT accounted for approximately 81%, 83% and 86%, respectively, of our transmission revenues, 68%, 77% and 82%, respectively, of our storage revenues, 64%, 64% and 64%, respectively, of our gathering revenues and 78%, 79% and 81%, respectively, of our total revenues. Our ability to increase our third-party 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 transmission, storage and gathering services to third parties on only a limited basis, and we 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 fee-based 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, and potential

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customers may desire to contract for gathering services that are not subject to FERC regulation. In addition, we will need to continue to improve our reputation among our potential customer base for providing high quality service in order to continue to successfully attract unaffiliated third parties.

We are exposed to the credit risk of our customers in the ordinary course of our business.

We extend credit to our customers as a normal part of our business. As a result, we are exposed to the risk of loss resulting from the nonpayment and/or nonperformance of our customers. While we have established credit policies, including assessing the creditworthiness of our customers as permitted by our FERC-approved natural gas tariff, 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. Furthermore, unanticipated future events could result in a deterioration of the creditworthiness of our contracted customers, including EQT. Any resulting nonpayment and/or nonperformance by our customers 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 transmission, storage or gathering 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 transportation 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 transportation and storage systems that would create additional competition for the services we provide to our customers. In addition, our customers may develop their own transmission, storage or gathering services instead of using ours. Moreover, EQT and its affiliates are not limited in their ability to compete with us.

The policies of the FERC promoting competition in natural gas markets are having the effect of increasing the natural gas transportation 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 by our systems or, in cases where we do not have long-term fixed rate contracts, could force us to lower our transportation or storage rates.

Further, natural gas as a fuel competes with other forms of energy available to end-users, including electricity, coal and liquid fuels. Increased demand for such forms of energy at the expense of natural gas could lead to a reduction in demand for natural gas storage and transportation 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 natural gas, our revenues and cash available to make distributions to our unitholders could be adversely affected.

We depend upon 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 and National Fuel Gas Supply Corporation, as well as multiple distribution companies. Similarly, our gathering system has multiple delivery interconnects to the Dominion Transmission system. Additionally,

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substantially all of the natural gas that is gathered by our gathering system that requires processing and treating is handled by Dominion Transmission. In the event that our access to such facility was impaired or if we were unable to negotiate a processing and treating contract with another party on like terms, the amount of natural gas that our gathering system can gather and transport onto our transmission and storage system 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. 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 sign a contract for service at a “negotiated rate,” which is generally above the FERC-regulated “recourse rate” for that service, and that contract must be filed with and accepted by the FERC. As of December 31, 2012, approximately 46% of our contracted transmission firm capacity was subscribed under such “negotiated rate” contracts. These “negotiated rate” contracts are not generally subject to adjustment for increased costs which could be caused by inflation or other factors relating to the specific facilities being used to perform the services. For example, on March 1, 2012, Equitrans made an annual filing with the FERC to recover costs it incurred to comply with the Pipeline Safety Improvement Act of 2002; however the amount of such recovery is subject to FERC approval. The 2012 filing has not yet been approved and is the subject of two protests, with respect to which Equitrans has filed the Proposed Settlement intended to resolve the issues raised by the protesting customers. To the extent the FERC does not approve the Proposed Settlement or ultimately agrees with the positions of the protesting customers, the level of the surcharge, and thus the amount of the anticipated cost recovery, could be significantly reduced. If the level of the surcharge is reduced, we will not generally be able to adjust these “negotiated rate” contracts to take into account the increased costs we incur to comply with the Pipeline Safety Improvement Act of 2002. Any shortfall of revenue, representing the difference between “recourse rates” (if higher) and negotiated rates, under current FERC policy is generally not recoverable from other shippers.

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. As of December 31, 2012, the weighted average remaining contract life based on total revenues for our firm transmission and storage contracts was approximately 9.4 years. The extension or replacement of existing contracts, including our contracts with EQT, depends on a number of factors beyond our control, including:

·                   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 tariff governing the services we provide is successfully challenged, we could be required to reduce our tariff rates, which 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.

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Any of our shippers, the FERC, or other interested stakeholders, such as state regulatory agencies, may challenge the maximum recourse rates or the terms and conditions of service included in our tariff. We do not have an agreement in place that would prohibit EQT or its affiliates from challenging our tariff. If any challenge were successful, among other things, the rates that we charge on our systems could be reduced. Successful challenges 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.

If we are unable to make acquisitions on economically acceptable terms from EQT or third parties, our future growth will 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, including EQT. We have no contractual arrangement with EQT that would require it to provide us with an opportunity to offer to purchase midstream assets that it may sell. Accordingly, while we believe EQT will be incentivized pursuant to its economic relationship with us to offer us opportunities to purchase midstream assets, there can be no assurance that any such offer will be made. Furthermore, many factors could impair our access to future midstream assets and the willingness of EQT to offer us acquisition opportunities, including a change in control of EQT or a transfer of the incentive distribution rights by our general partner to a third party. A material decrease in divestitures of midstream energy assets from EQT or otherwise 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 from EQT or third parties, whether because, among other reasons, (i) EQT elects not to sell or contribute additional assets to us or to offer acquisition opportunities to us, (ii) we are unable to identify attractive third-party acquisition opportunities, (iii) we are unable to negotiate acceptable purchase contracts with EQT or third parties, (iv) we are unable to obtain financing for these acquisitions on economically acceptable terms, (v) we are outbid by competitors or (vi) 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, revenue 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 eventually proves not 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.

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 may require the expenditure of significant amounts of capital. These types of projects may not be completed on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new midstream asset, the construction will 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

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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 distributions.

Certain of our internal growth projects may require regulatory approval from federal and state authorities prior to construction, including any extensions from or additions to our transmission and storage system. The approval process for storage and transportation projects located in the Northeast has become increasingly challenging, due in part to state and local concerns related to unregulated exploration and production and gathering activities in new production areas, including the Marcellus Shale play. Such authorization may not be granted or, if granted, such authorization may include burdensome or expensive conditions.

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, we will need to make 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. We will be required to use cash from our operations or incur borrowings or sell additional common units or other limited partner interests in order to fund our expansion capital expenditures. 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 as well as 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.

We do not have any commitment with our general partner or other affiliates, including EQT, to provide any direct or indirect financial assistance to us.

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, compressing, transportation 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 and other natural disasters and acts of terrorism;

·                   inadvertent damage from construction, vehicles, 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; and

·                   other hazards that could also result in personal injury and loss of life, pollution 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 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 distributions. Accidents or other

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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 on our ability to make distributions to you.

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 to our businesses, including environmental accidents that might occur. In addition, we do not maintain business interruption insurance in the type and amount 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 on our ability to make distributions to you.

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.

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 committed by a U.S. person or interest.

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 type and amount 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 will 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 decreased.

We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.

Our natural gas gathering, transportation and storage operations are subject to stringent and complex federal, state and local environmental laws and regulations that govern the discharge of materials into the environment or otherwise relate to environmental protection. Examples of these laws include:

·                   the federal Clean Air Act and analogous state laws that impose obligations related to air emissions;

·                   the federal Comprehensive Environmental Response, Compensation and Liability Act, known as CERCLA or the Superfund law, and analogous state laws that regulate the cleanup of hazardous substances that may be or have been released at properties currently or previously owned or operated by us or at locations to which our wastes are or have been transported for disposal;

·                   the federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws that regulate discharges from our facilities into state and federal waters, including wetlands;

·                   the federal Oil Pollution Act, or OPA, and analogous state laws that establish strict liability for releases of oil into waters of the United States;

·                   the federal Resource Conservation and Recovery Act, or RCRA, and analogous state laws that impose requirements for the storage, treatment and disposal of solid and hazardous waste from our facilities;

·                   the Endangered Species Act, or ESA; and

·                   the Toxic Substances Control Act, or TSCA, and analogous state laws that impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities.

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These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, we may experience a delay in obtaining or be unable to obtain required permits or regulatory authorizations, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue. In addition, future changes in environmental or other laws may result in additional compliance expenditures that have not been pre-funded and which could adversely affect our business, financial condition, results of operations, liquidity and our ability to make cash distributions to our unitholders. For example, on April 7, 2012, the EPA issued final rules that establish new air emission controls for oil and natural gas production, processing, transmission and storage operations. Specifically, EPA’s rule package includes standards to address emissions of sulfur dioxide and volatile organic compounds, or VOC, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The rules establish new or more stringent requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment in addition to leak detection requirements for natural gas processing plants. These rules may require modifications to certain of our operations, which could include the installation of new equipment to control emissions. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely affect our business.

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 transmission and storage system or our gathering 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. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. Pursuant to the terms of the omnibus agreement, EQT will indemnify us for certain potential environmental and toxic tort claims, losses and expenses associated with the operation of the assets retained by us and occurring before the closing date of the IPO. However, the maximum liability of EQT for these indemnification obligations will not exceed $15 million, which may not be sufficient to fully compensate us for such claims, losses and expenses. 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 distributions. We may not be able to recover all or any of these costs from insurance.

Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the natural gas services we provide.

In December 2009, the EPA published its findings that emissions of greenhouse gases, or GHGs, present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic conditions. Based on these findings, the EPA adopted two sets of regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act, including one that requires a reduction in emissions of GHGs from motor vehicles and another that regulates GHG emissions from certain large stationary sources under the Clean Air Act Prevention of Significant Deterioration and Title V permitting programs. The stationary source rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. In addition, the EPA expanded its existing GHG emissions reporting rule to include onshore oil and natural gas processing, transmission, storage, and distribution activities, beginning in 2012 for emissions occurring in 2011. Congress has also from time to time considered legislation to reduce emissions of GHGs. The adoption of any legislation or

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regulations that restrict emissions of GHGs from our equipment and operations could require us to incur significant added costs to reduce emissions of GHGs or could adversely affect demand for the natural gas we transport, store and gather.

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 our gathering system have been in service for several decades. The age and condition of our 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 our ability to make cash distributions to our unitholders.

We may incur significant costs and liabilities as a result of pipeline integrity management program testing and related repairs.

Pursuant to the Pipeline Safety Improvement Act of 2002, as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, the U.S. Department of Transportation, or DOT, 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.

Moreover, 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. On January 3, 2012, President Obama signed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which act, among other things, directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas. These safety enhancement requirements and other provisions of this act could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could be significant and have a material adverse effect on our business, financial condition, results of operations, liquidity or ability to make distributions.

In addition, many states have adopted regulations similar to existing DOT regulations for intrastate gathering and transmission lines. Although many of our natural gas facilities fall within a class that is not subject to these requirements, we may incur significant costs and liabilities associated with repair, remediation, preventative or mitigation measures associated with our non-exempt pipelines, particularly our gathering pipelines. This estimate does not include the costs, if any, for repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial. Such costs and liabilities might relate to repair, remediation, preventative 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 repairs. Additionally, should we fail to comply with DOT regulations, we could be subject to penalties and fines. We retained approximately $32 million of the net proceeds from the IPO in order to pre-fund certain identified regulatory compliance capital expenditures, the majority of which are expected to be incurred over the two years following the IPO; however the actual cost of such expenditures may exceed $32 million. Furthermore, we are not

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restricted from using this approximately $32 million for other purposes. In addition, we may be required to 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 severance taxes and impact fees on natural gas wells could cause our current and potential customers to reduce the number of wells they drill in the Marcellus Shale. If drilling reductions are significant, 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 southern 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 Shale. The EPA is developing permitting guidance under the federal Safe Drinking Water Act for hydraulic fracturing activities that use diesel fuels in fracturing fluids. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Any such legislation may provide more opportunities for third parties opposed to hydraulic fracturing to initiate legal proceedings against our customers. In addition, a number of federal agencies, including the EPA and the U.S. Department of Energy, are analyzing, or have been requested to review, a variety of environmental issues associated with shale development, including hydraulic fracturing. On May 4, 2012, the Department of the Interior’s Bureau of Land Management, or BLM, issued a proposed rule to regulate hydraulic fracturing on public and Indian land. The rule would require companies to disclose the chemicals used in hydraulic fracturing operations to the BLM after fracturing operations have been completed, which would then become publicly available, and includes provisions addressing well-bore integrity and flowback water management plans. Currently, the proposed rule is on hold while the BLM reviews the thousands of public comments that it received on the proposal. However, some industry commentators have predicted that similar rules could follow that will impose a national minimum standard on hydraulic fracturing activities. These additional regulatory burdens could make it more costly or uneconomical for our customers to develop wells, thereby limiting future oil and gas production and reducing future demand for our services. In addition, some states and municipalities have adopted, and other states and municipalities are considering adopting, regulations that could prohibit hydraulic fracturing in certain areas or impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. For example, Pennsylvania has adopted a variety of regulations since 2010 governing well drilling and hydraulic fracturing completion practices, including the adoption of upgraded well construction and casing standards, upgraded cement standards and new recordkeeping requirements. Additionally, in 2012 Pennsylvania enacted legislation that authorizes counties to assess a local impact fee for unconventional gas wells, establishes additional regulatory requirements relating to horizontal drilling, and was intended to ensure uniformity between statewide environmental protection standards and municipal ordinances (Act 13). The portion of Act 13 that deals with municipal uniformity was challenged and is currently before the Pennsylvania Supreme Court awaiting a decision. Until a decision is rendered, municipal uniformity remains uncertain. Similarly, in 2011, West Virginia adopted legislation that establishes additional regulatory requirements relating to horizontal drilling and hydraulic fracturing. These initiatives could result in additional levels of regulation and permitting of hydraulic fracturing operations, which could cause our customers to experience operational delays, increased operating and compliance costs, restrictions or bans on drilling new wells, and additional regulatory burdens that could make it more difficult or commercially impracticable for our customers to perform hydraulic fracturing, delaying the development of unconventional gas resources from shale formations which are not commercial without the use of hydraulic fracturing and reducing the volume of natural gas transported through our pipelines.

The results of our operations are affected by natural gas drilling activity which in turn could be affected by the state tax burdens placed on gas production and drilling and completion operations. West Virginia imposes severance tax on oil and gas production. Pennsylvania does not impose a severance tax. In 2012, Pennsylvania enacted legislation authorizing counties to impose an annual impact fee on unconventional gas wells (generally defined as wells using hydraulic fracturing or multilateral well bores) for the first 15 years of each well’s life. Total fees per well over the 15-year term range from $190,000 to $355,000, depending on gas prices and subject to consumer price indexing. As Pennsylvania counties assess impact fees, growth in drilling and production in Pennsylvania could be reduced. If drilling reductions are significant, our operations could be adversely impacted.

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We are exposed to costs associated with lost and unaccounted for volumes.

A certain amount of natural gas is naturally lost in connection with its transportation across a pipeline system, and under our contractual arrangements with our customers we are entitled to retain a specified volume of natural gas in order to compensate us for such lost and unaccounted for volumes as well as the natural gas used to run our compressor stations, which we refer to as fuel usage. The level of fuel usage and lost and unaccounted for volumes on our transmission and storage system and our gathering system may exceed the natural gas volumes retained from our customers as compensation for our fuel usage and lost and unaccounted for volumes pursuant to our contractual agreements and it will be necessary to purchase natural gas in the market to make up for the difference, which exposes us to commodity price risk. For the years ended December 31, 2012, 2011 and 2010, our actual level of fuel usage and lost and unaccounted for volumes exceeded the amounts recovered from our gathering customers by approximately 1,800 Bbtu, 1,300 Bbtu and 1,500 Bbtu, respectively, for which we recognized $4.0 million, $4.9 million and $5.7 million of purchased gas cost as a component of operating and maintenance expense in 2012, 2011 and 2010, respectively. Future exposure to the volatility of natural gas prices as a result of gas imbalances 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.

Our exposure to direct commodity price risk may increase in the future.

Although we intend to enter into fixed-fee 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. Future exposure to the volatility of natural gas prices 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 relocate our facilities. 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 on our ability to make distributions to you.

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. For instance, the settlement approved by the FERC in our most recent rate case included a provision allowing us to recover 7.1 Bcf of storage base gas through our transmission fuel retention percentage. If FERC approves Equitrans’ Proposed Settlement of current protests associated with the PSC, the transmission fuel retention percentage will be

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reduced from the current retention percentage of 3.72% to 2.72%. The Proposed Settlement also eliminates the tracking mechanism that relates to the recovery of 7.1 Bcf of storage base gas. To the extent we need to replace storage base gas under the current terms of our most recent rate case, or the terms of the Proposed Settlement, we may not be able to recover the cost of acquiring such base gas from our customers and will be subject to commodity price risk. 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 distributions.

Restrictions in our credit facility could adversely affect our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.

Concurrent with the closing of the IPO, we entered into a $350 million revolving credit facility. Our credit facility contains 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;

·                   make certain investments and acquisitions;

·                   incur certain liens or permit them to exist;

·                   enter into certain types of transactions with affiliates;

·                   merge or consolidate with another company; and

·                   transfer, sell or otherwise dispose of assets.

Our credit facility also contains covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control and we cannot assure our unitholders that we will meet those ratios and tests. In addition, our credit facility contains events of default customary for transactions of this nature, including the occurrence of a change of control (which will occur if EQT fails to own a majority of the equity interests of our general partner, we fail to own 100% of Equitrans, L.P., or our general partner fails to be our general partner).

The provisions of our credit facility 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 credit facility could result in an event of default, which could enable our lenders to, subject to the terms and conditions of the revolving credit facility, declare any outstanding principal of that debt, together with accrued and 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 credit facility also has cross default provisions that apply to any other indebtedness we may have with an aggregate principal amount in excess of $15.0 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 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

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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 its owner, 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 owned by EQT, controls our business activities, including our cash distribution policy and growth strategy. Any adverse change in the financial condition of EQT, including the degree of its financial leverage and its dependence on cash flow from us to service its indebtedness, or a downgrade of EQT’s investment grade credit rating, may adversely affect our credit ratings and risk profile.

If we were to seek a credit rating in the future, our credit rating may be adversely affected by the leverage of our general partner or EQT, as credit rating agencies such as Standard & Poor’s Ratings Services and Moody’s Investors Service may consider the leverage and credit profile of EQT and its affiliates because of their ownership interest in and control of us. Any adverse effect on our credit rating would increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which would impair our ability to grow our business and make distributions to our unitholders.

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 future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by our 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 transmission, storage and gathering systems, which are exclusively located in the Appalachian Basin in Pennsylvania and West Virginia. 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.

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If we fail to maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.

Prior to the IPO in July 2012, we were not required to file reports with the SEC. Upon the completion of the IPO, we became subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act. We prepare our consolidated financial statements in accordance with GAAP, but prior to the IPO our internal accounting controls were not required to meet all standards applicable to companies with publicly traded securities. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 will require us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. We must comply with Section 404 (except for the requirement for an auditor’s attestation report, as described below) beginning with for our fiscal year ending December 31, 2013. Any failure to develop, implement or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm’s conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

For as long as we are an emerging growth company, we will not be required to comply with certain disclosure requirements that apply to other public companies.

In April 2012, President Obama signed into law the Jumpstart Our Business Startups Act, or the JOBS Act. For as long as we remain an “emerging growth company” as defined in the JOBS Act, we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being required to provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act and reduced disclosure obligations regarding executive compensation in our periodic reports. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues in a fiscal year, have more than $700 million in market value of our limited partner interests held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

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

To the extent that we rely on any of the exemptions available to emerging growth companies, our unitholders will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our common units to be less attractive as a result, there may be a less active trading market for our common units and our trading price may be more volatile.

Terrorist attacks aimed at our facilities or surrounding areas could adversely affect our business.

The U.S. government has issued warnings that energy assets, specifically the nation’s pipeline and terminal infrastructure, may be the future targets of terrorist organizations. Any terrorist attack at our facilities, those of our customers and, in some cases, those of other pipelines, refineries or terminals could materially and adversely affect our business, financial condition, results of operations, liquidity or ability to make distributions.

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Risks Inherent in an Investment in Us

Our general partner and its affiliates, including EQT, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our other common unitholders.

EQT indirectly owns and controls our general partner and appointed all of the officers and directors of our general partner. All of our initial officers and a majority of our initial directors are also officers and/or directors of EQT. Although our general partner has a duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to EQT. Conflicts of interest will arise between EQT 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 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 tariff rates or gathering fees, even if such higher rates or fees would reflect rates and fees that could be obtained in arm’s-length, third party transaction.

·                   EQT is not limited in its ability to compete with us and may offer business opportunities or sell midstream assets to 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.

·                   All of the officers and a majority of the directors of our general partner are also officers and/or directors of EQT and owe fiduciary duties to EQT. The officers of our general partner also devote significant time to the business of EQT and are compensated by EQT accordingly.

·                   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.

·                   Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

·                   Disputes may arise under our commercial agreements with EQT and its affiliates.

·                   Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of distributable cash flow.

·                   Our general partner determines the amount and timing of any capital expenditures and 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. This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units.

·                   Our general partner determines which costs incurred by it 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 a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.

·                   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 on our subordinated or general partner units or to our general partner in respect of the incentive distribution rights.

·                   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.

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·                   Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units.

·                   Our general partner controls the enforcement of the obligations that it and its affiliates owe to us, including EQT’s obligations under the omnibus agreement and its commercial agreements with us.

·                   Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

·                   Our general partner may transfer its incentive distribution rights 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 incentive distribution rights 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.

EQT and other affiliates of our general partner are not restricted in their ability to compete with us.

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, are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. EQT currently holds interests in, and may make investments in and purchases of, entities that acquire, own and operate other natural gas midstream assets. EQT will be 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 and EQT. 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.

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 facility, on our ability to issue additional units, including units ranking senior to the 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,

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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 FERC or analogous regulatory body, we have adopted certain requirements regarding those investors who may own our common units. Eligible holders are individuals or entities subject to United States federal income taxation on the income generated by us or entities not subject to United States federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation. If any of our unitholders are not persons who fit the requirements to be eligible taxable holders, such unitholders 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 its affiliates;

·                   whether to exercise its limited call right;

·                   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 incentive distribution rights 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 the partnership agreement.

By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above.

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

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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 the 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 a majority of the 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 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.

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 on our common units, 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 expense 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.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business 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 EQT. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

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Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

Unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates, including EQT, owns sufficient units to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding common and subordinated units voting together as a single class is required to remove our general partner. EQT indirectly owns 58.5% of our outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of unitholder dissatisfaction with the performance of our general partner in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person 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 vote on any matter.

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 the unitholders. Furthermore, our partnership agreement does not restrict the ability of EQT to transfer all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner 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.

The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights 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 distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights. For example, a transfer of incentive distribution rights by our general partner could reduce the likelihood of EQT selling or contributing additional midstream assets to us, as EQT would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

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 the 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 a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

·                   because the amount payable to holders of incentive distribution rights is based on a percentage of the total distributable cash flow, the distributions to holders of incentive distribution rights 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 the common units may decline.

EQT may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

EQT indirectly holds an aggregate of 2,964,718 common units and 17,339,718 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier under certain circumstances. In addition, we have agreed to provide EQT with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the 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 limited call right that may require our unitholders to sell their units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the 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 common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. 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 unitholders may also incur a tax liability upon a sale of their units. EQT indirectly owns approximately 17.1% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than upon the conversion of the subordinated units), EQT will indirectly own approximately 58.5% 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 incentive distribution rights, which is initially our general partner, have the right, at any time when there are no subordinated units outstanding and 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

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increases above the reset minimum quarterly distribution. Our general partner has the right to transfer the incentive distribution rights at any time, in whole or in part, and any transferee holding a majority of the incentive distribution rights 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 incentive distribution rights 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 incentive distribution rights 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 distributions it receives related to its incentive distribution rights 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 incentive distribution rights 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. Our unitholders could be liable for any and all of our obligations as if our unitholders 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

·                   our unitholders 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 constitute “control” of our business.

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.

We incur increased costs as a result of being a publicly traded partnership.

We had no history operating as a publicly traded partnership prior to the IPO. As a publicly traded partnership, we incur significant legal, accounting and other expenses.

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Tax Risks to 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 the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS regarding our qualification as a partnership for 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 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 a maximum of 35.0%, and would likely pay state and local income tax at varying rates. Distributions 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 you. 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, it would reduce our distributable cash flow to our unitholders.

Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of such additional tax on us by a state 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 interpretation at any time. For example, from time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Currently, one such legislative proposal would eliminate the qualifying income exception 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 any 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’ share of our income will be taxable to them for U.S. federal income tax purposes even if they do not receive any cash distributions from us.

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Because a unitholder will be treated as a partner to whom we will allocate taxable income which could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes on its share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

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 a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the conclusions of our counsel expressed in prospectus or from the positions we take, and the IRS’s positions may ultimately be sustained. 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.

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 a unitholder’s 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. If our unitholders are a tax-exempt entity or a non-U.S. person, our unitholders 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 the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt 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 you. Our counsel is unable to opine as to the validity of such filing positions. It also could affect the timing of these tax benefits or the amount of gain from our unitholders sale 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.

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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 will 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 use of this proration method may not be permitted under existing Treasury Regulations. Recently, however, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Our counsel has not rendered an opinion with respect to whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations.

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, he 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, he 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, 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 counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, 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 will adopt certain valuation methodologies and monthly conventions for U.S. federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable 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.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

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We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

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 and West Virginia, each of which currently impose a personal income tax on individuals. Each of these states also impose an income 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. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

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 the Company’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 connection with its construction of the Big Sandy Pipeline in 2007, Equitrans entered into an agreement related to mining operations on both sides of the Big Sandy Pipeline. The agreement provided that once mining was

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concluded, Equitrans would pay the coal owner, Prater Branch Resources, the fair market value of any recoverable, merchantable coal underlying the Big Sandy Pipeline which could not be recovered because of the existence of the pipeline. The agreement provided that any dispute related to the amount of unrecoverable coal and the value thereof would be submitted to arbitration. In April 2011, Prater Branch submitted a claim to Equitrans. Equitrans did not agree with the amount or the value of the alleged unrecovered coal and commenced an arbitration proceeding with the American Arbitration Association (AAA) pursuant to the terms of the agreement.

In July 2011, Equitrans and Prater Branch agreed to forego an arbitration administered by AAA and to proceed with a private mediation.  The Big Sandy Pipeline was sold to an unrelated third party in 2011, but Equitrans retained the liability under the Prater Branch agreement. In connection with the IPO, EQT agreed to indemnify Equitrans for any liabilities, claims or losses associated with its prior ownership of the Big Sandy Pipeline, including the Prater Branch claim.  The parties settled the claim on November 20, 2012, with Equitrans agreeing to pay $2.7 million.  EQT indemnified Equitrans for the full amount of this payment.

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

Item 4.  Mine Safety and Health Administration Data

Not applicable.

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PART II

Item 5.         Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

The Company’s common units have been listed on the New York Stock Exchange (NYSE) under the symbol “EQM” since June 27, 2012. Prior to that, the Company’s equity securities were not listed on any exchange or traded on any public trading market.  Prior to the IPO, the operations comprising the Company were owned by EQT. 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 from the closing of the IPO through December 31, 2012.

Common Unit Data by Quarter

(a)         Since June 27, 2012, the commencement date of trading.

As of February 1, 2013, there were 3 unitholders of record of the Company’s common units. A cash distribution of $0.35 per common unit was declared on January 22, 2013 and was paid on February 14, 2013. Based on the Company’s current projections, the Company expects its first distribution increase to occur with its next quarterly distribution.

The Company has also issued 17,339,718 subordinated units and 707,744 general partner units, for which there is no established public trading market. All of the subordinated units and general partner units are held by affiliates of the Company’s general partner. The general partner and its affiliates receive quarterly distributions on these units only after sufficient distributions have been paid to the common units. Set forth below under “Distributions of Available Cash” is a summary of the significant provisions of the Company’s partnership agreement that relate to distributions of available cash, minimum quarterly distributions and incentive distribution rights.

Market Repurchases

The Company did not repurchase any of its common units during 2012.

Distributions of Available Cash

General

The Company’s partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ended September 30, 2012, the Company distribute all of its available cash (described below) to unitholders of record on the applicable record date.

Available Cash

Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:

·                  less, the amount of cash reserves established by the Company’s general partner to:

–                 provide for the proper conduct of the Company’s business (including reserves for future capital expenditures, anticipated future debt service requirements and refunds of collected

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rates reasonably likely to be refunded as a result of a settlement or hearing related to FERC rate proceedings or rate proceedings under applicable law subsequent to that quarter);

–                 comply with applicable law, any of the Company’s debt instruments or other agreements; or

–                 provide funds for distributions to the Company’s unitholders and to the Company’s general partner for any one or more of the next four quarters (provided that the Company’s general partner may not establish cash reserves for distributions if the effect of the establishment of such reserves will prevent the Company from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);

·                  plus, if the Company’s general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.

Subordinated Units

All subordinated units are held by EQT. The partnership agreement provides that, during the period of time referred to as the “subordination period,” the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.35 per common unit, which amount is defined in the partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to distribute the minimum quarterly distribution to the common units. The subordination period will end, and the subordinated units will convert to common units, on a one-for-one basis, when certain distribution requirements, as defined in the partnership agreement, have been met. The earliest date at which the subordination period may end is June 30, 2013.

Incentive Distribution Rights

All incentive distribution rights are held by the Company’s general partner. Incentive distribution rights represent the right to receive an increasing percentage (13.0%, 23.0% and 48.0%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels described below have been achieved. The Company’s general partner may transfer the incentive distribution rights separately from its general partner interest, subject to restrictions in the partnership agreement.

The following discussion assumes that the Company’s general partner continues to own both its 2.0% general partner interest and the incentive distribution rights.

If for any quarter:

·                  the Company has distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

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

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

·                  first, 98.0% to all unitholders, pro rata, and 2.0% to the Company’s general partner, until each unitholder receives a total of $0.4025 per unit for that quarter (the “first target distribution”);

·                  second, 85.0% to all unitholders, pro rata, and 15.0% to the Company’s general partner, until each unitholder receives a total of $0.4375 per unit for that quarter (the “second target distribution”);

·                  third, 75.0% to all unitholders, pro rata, and 25.0% to the Company’s general partner, until each unitholder receives a total of $0.5250 per unit for that quarter (the “third target distribution”); and

·                  thereafter, 50.0% to all unitholders, pro rata, and 50.0% to the Company’s general partner.

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Equity Compensation Plans

The information relating to the Company’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” contained herein.

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.”

The Company closed its IPO on July 2, 2012. Equitrans, L.P. (Equitrans) is a Pennsylvania limited partnership and the predecessor for accounting purposes of EQT Midstream Partners. For periods prior to the IPO, the following selected financial data and related notes reflect the assets, liabilities and results of operations of Equitrans presented on a carve-out basis, excluding the financial position and results of operations of the Big Sandy Pipeline (as described in Note 1 to the Consolidated Financial Statements under Item 8, “Financial Statements and Supplementary Data”), prior to the contribution by EQT of all of the partnership interests in Equitrans to EQT Midstream Partners, in connection with the IPO. The selected financial data covering periods prior to the closing of the IPO may not necessarily be indicative of the actual results of operations had those contributed entities been operated separately during those periods.

(a)                Reflective of general and limited partners’ interests in Net Income since the closing of the IPO on July 2, 2012. See Note 1 in Item 8, “Financial Statements and Supplementary Data” for further discussion.

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

EQT Midstream Partners, LP (the Partnership, EQT Midstream Partners or the Company), which closed its initial public offering (IPO) to become publicly traded on July 2, 2012, is a growth-oriented Delaware limited partnership formed in January 2012.  Equitrans, L.P. (Equitrans) is a Pennsylvania limited partnership and the predecessor for accounting purposes (the Predecessor) of EQT Midstream Partners (the Successor).  References in the following discussion to the “Company,” when used for periods prior to the IPO, refer to Equitrans.  References in the following discussion to the “Company,” when used for periods beginning at or following the IPO, refer collectively to the Partnership and its consolidated subsidiaries. Immediately prior to the closing of the IPO, EQT Corporation contributed all of the partnership interests in Equitrans to the Partnership. Therefore, the historical financial statements contained in this report reflect the assets, liabilities and operations of Equitrans (excluding the results of operations of Big Sandy Pipeline, a FERC-regulated transmission pipeline sold to an unrelated party in

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July 2011) for periods ending before July 2, 2012 and EQT Midstream Partners for periods beginning at or following July 2, 2012.

The following discussion analyzes, among other things, the financial condition and results of operations of the Predecessor and Successor. 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, “Financial Statements and Supplementary Data.” References in the following discussion and analysis to ‘‘EQT’’ refer collectively to EQT Corporation and its consolidated subsidiaries.

Executive Overview

The Company is a growth-oriented limited partnership formed by EQT Corporation (NYSE: EQT) to own, operate, acquire and develop midstream assets in the Appalachian Basin. The Company provides substantially all of its natural gas transmission, storage and gathering services under contracts with fixed reservation and/or usage fees, with a significant portion of its revenues being generated pursuant to long-term firm contracts.

On July 2, 2012, the Company closed its IPO of 14,375,000 common units at a price of $21.00 per unit, which included the full exercise of the underwriters’ over-allotment option, and represented 40.6% of the Company’s outstanding equity. Immediately prior to the closing of the IPO, EQT contributed all of the partnership interests in Equitrans to the Partnership. EQT retained a 59.4% equity interest in the Company, including 2,964,718 common units, 17,339,718 subordinated units and a 2% general partner interest.

The Company reported net income of $55.3 million in 2012 compared with $32.6 million in 2011. The increase was primarily related to an increase in operating income of $16.1 million and a decrease in income tax expense of $7.7 million.  Transmission and storage revenues increased by $27.1 million primarily due to increased firm transmission service and increased system throughput, which were driven by production development in the Marcellus play. Total operating expenses increased consistent with the overall growth of the transmission system.  The decrease in income tax expense was due to the Company’s limited partnership structure subsequent to the IPO, as the Company is no longer subject to U.S. federal and state income taxes.

Subsequent to the IPO in 2012, net income per limited partner unit was $0.91 and diluted net income per limited partner unit was $0.90. For the six months ended December 31, 2012, adjusted EBTIDA was $40.0 million and distributable cash flow was $26.4 million, which exceeded the $24.8 million of distributable cash flow necessary to meet the minimum quarterly distributions. The Company paid all unitholders a quarterly cash distribution of $0.35 per unit during the year ended December 31, 2012 and declared a cash distribution to unitholders of $0.35 on January 22, 2013. For a discussion of the non-GAAP financial measures adjusted EBITDA and distributable cash flow, please read the discussion below of “Non-GAAP Financial Measures” and “Reconciliation of Non-GAAP Measures.”

The Company reported net income of $32.6 million in 2011 compared with $19.2 million in 2010. The increase was primarily related to an increase in operating income of $16.7 million. Transmission and storage revenues increased by $19.3 million primarily due to the completion of a portion of the Equitrans 2010 Marcellus expansion project in the fourth quarter of 2010 and the addition of new receipt point interconnects with EQT’s gathering system.

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Consolidated Results of Operations

(1)         Presented for the post-IPO period only. For a discussion of the non-GAAP financial measures adjusted EBITDA and distributable cash flow, please read the sections below titled “Non-GAAP Financial Measures” and “Reconciliation of Non-GAAP Measures.”

(2)         For more information regarding funded regulatory compliance and reimbursable maintenance see the discussion in the sections below titled “Capital Requirements.”

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Business Segment Results

Operating segments are evaluated on their contribution to the Company’s consolidated results based on operating income. Interest and other income are managed on a consolidated basis. The Company has presented each segment’s operating income and various operational measures in the sections below. Management believes that presentation of this information provides useful information to management and investors regarding the financial condition, results of operations and trends of segments. In addition, management uses these measures for budget planning purposes. The Company has reconciled each segment’s operating income to the Company’s consolidated operating income and net income in Note 2 to the Consolidated Financial Statements.

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Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Operating revenues and operating expenses related to the Sunrise Pipeline do not have an impact on distributable cash flow as the excess of the Sunrise Pipeline revenues over operating and maintenance and selling, general and administrative operating expenses is paid to EQT as the current monthly lease payment.

Total operating revenues were $136.9 million for the year ended December 31, 2012 compared to $109.6 million for the year ended December 31, 2011. The increase was primarily related to a $27.1 million increase in transmission and storage operating revenues.  Gathering revenues were essentially flat year over year.

Transmission and storage revenues increased as a result of increased firm transmission service and increased system throughput. This includes $12.2 million of reservation fees and usage charges under firm contracts on the Sunrise Pipeline, $11.8 million of fees associated with transported volumes in excess of firm capacity and increased reservation fees and usage charges under other firm contracts, which includes contracts for the Blacksville Compressor Station. These increases primarily resulted from increased production development in the Marcellus play. The average daily transmission throughput increased by 209 BBtu per day during the year ended December 31, 2012 compared to the year ended December 31, 2011. For the year ended December 31, 2012, approximately 62% of the Company’s total operating revenues were generated from firm capacity reservation charges. These increases were partly offset by a decrease in storage and parking services.

Operating expenses totaled $66.2 million for the year ended December 31, 2012 compared to $55.0 million for the year ended December 31, 2011. The increase in operating expenses was due to an $8.8 million increase in depreciation and amortization expense and a $3.2 million increase in operating and maintenance expense, which were slightly offset by a decrease in selling, general and administrative expense.

The increase in depreciation and amortization expense was primarily in transmission and storage as a result of Sunrise Pipeline capital lease depreciation expense of $7.1 million and increased investment in transmission infrastructure. The Sunrise Pipeline capital lease is depreciated over the 15 year life of the lease, resulting in increased depreciation expense compared to the 40 year expected life of the pipeline.

The increase in operating and maintenance expense resulted from a $3.5 million increase in transmission and storage expenses partly offset by a $0.3 million decline in gathering operating and maintenance expense.  Transmission and storage expenses increased primarily as a result of increased amortization of pipeline safety costs of $1.4 million, additional operating costs of $0.9 million associated with operating the Sunrise Pipeline and non-income based taxes of $0.5 million. The decrease in gathering expense primarily resulted from lower purchased gas costs of $0.9 million which was partly offset by increased repairs and maintenance expenses of $0.7 million.  Fuel usage and lost and unaccounted for volumes on the gathering system have historically exceeded the natural gas retained from the Company’s gathering customers as compensation for its fuel usage and lost and unaccounted for volumes.  Purchased gas costs were recorded for the difference. The decline in purchased gas costs during 2012 was primarily the result of lower prices, partly offset by increased lost and unaccounted for volumes due to higher system pressures.

In the transmission and storage segment, selling, general and administrative expenses decreased by $0.7 million primarily due to a $2.5 million reduction of a reserve on the collectability of long-term regulatory assets and a $0.6 million reduction to a legal reserve. The storage reserve was established for the recovery of base storage gas from excess customer retention provided in the Company’s 2006 rate settlement. At December 31, 2012, the majority of the gas has been recovered and the related reserve was reduced. These expense reductions were partly offset by increased expenses associated with being a publicly traded partnership of $1.4 million and $1.0 million due to the additional costs attributable to the Sunrise Pipeline.

Other income primarily represents the equity portion of AFUDC which generally increases during periods of increased construction and decreases during periods of reduced construction. The increase in other income for the year ended December 31, 2012 when compared to the year ended December 31, 2011 primarily resulted from an increase in applicable construction expenditures in connection with the Sunrise Pipeline project, which was placed into service on July 28, 2012.

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Income taxes for the year ended December 31, 2012 totaled $13.1 million compared to $20.8 million for the year ended December 31, 2011. The $7.7 million decrease is primarily attributable to income taxes not being recorded after the IPO and an increased benefit related to equity AFUDC. The Predecessor’s financial statements include U.S. federal and state income tax expense. Due to the Company’s limited partnership structure subsequent to the IPO, the Company is no longer subject to U.S. federal and state income taxes and therefore no income tax expense was recorded for the third and fourth quarters of 2012.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Total operating revenues were $109.6 million for the year ended December 31, 2011 compared to $91.6 million for the year ended December 31, 2010. The $18.0 million increase was due to a $19.3 million increase in transmission and storage operating revenues, partly offset by a $1.3 million decrease in gathering operating revenues.

The majority of the increase in transmission and storage operating revenues was attributable to an increase in firm transmission service reservation revenues associated with an average daily increase of 193 BBtu of firm transmission service provided during the year ended December 31, 2011 when compared to the year ended December 31, 2010. This increased firm transmission capacity sold was due to the completion of a portion of the Equitrans 2010 Marcellus expansion project in the fourth quarter of 2010 and the addition of new receipt point interconnects with EQT’s gathering systems. The increased firm transmission capacity sold also resulted in higher usage fees based on increased throughput for the period, which also contributed to the increased revenues.

Gathering revenues decreased due to fewer volumes gathered for the year ended December 31, 2011 when compared to the year ended December 31, 2010. The decreased volumes were primarily due to the addition of new direct interconnects between EQT’s gathering systems and the Company’s transmission and storage system, resulting in decreased usage by EQT of the Company’s gathering system for connection onto its transmission and storage system. Volumes also decreased as a result of the natural decline in natural gas production from mature wells and limited additional development of some of the shallow, low-pressure formations served by the Company’s gathering system.

Operating expenses totaled $55.0 million for the year ended December 31, 2011 compared to $53.7 million for the year ended December 31, 2010. The increase in operating expenses was primarily due to a $1.9 million increase in operating and maintenance expense partly offset by a $1.2 million decrease in selling, general and administrative expense.

The increase in operating and maintenance expense for both transmission and storage and gathering was primarily due to the increased activity on the expanded system. These increased expenses included costs related to compliance, training and engineering. Selling, general and administrative expense decreased primarily as a result of completing the amortization of previously deferred costs for post-retirement benefits other than pensions in 2010.

Depreciation and amortization expense increased $0.6 million year over year due to the increased investment in transmission infrastructure, which included the Equitrans 2010 Marcellus expansion project and a large compressor station all in the transmission and storage segment.

The $3.3 million increase in other income for the year ended December 31, 2011 compared to the year ended December 31, 2010 was primarily the result of increased construction expenditures in connection with the Sunrise Pipeline project.

Income taxes for the year ended December 31, 2011 totaled $20.8 million compared to $14.0 million for the year ended December 31, 2010. The $6.8 million increase was primarily driven by an increase in pre-tax income offset by a lower effective tax rate in 2011 primarily as a result of an increased benefit related to equity AFUDC.

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Non-GAAP Financial Measures

As used herein, the Company defines adjusted EBITDA as net income plus net interest expense, income tax expense (if applicable), depreciation and amortization expense, non-cash long-term compensation expense and other non-cash adjustments less other income and the Sunrise Pipeline lease payment. As used herein, the Company defines distributable cash flow as adjusted EBITDA less net cash paid for interest expense, maintenance capital expenditures and income taxes (if applicable).  Distributable cash flow should not be viewed as indicative of the actual amount of cash that the Company has available for distributions or that the Company plans to distribute. Adjusted EBITDA and distributable cash flow are non-GAAP supplemental financial measures that management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, use to assess:

·                  the Company’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 the Company’s assets to generate sufficient cash flow to make distributions to the Company’s unitholders;

·                  the Company’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.

The Company believes that adjusted EBITDA and distributable cash flow provide useful information to investors in assessing the Company’s financial condition and results of operations. Adjusted EBITDA and distributable cash flow should not be considered alternatives to net income, operating income, cash flows from 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, the Company’s definition of adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

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Reconciliation of Non-GAAP Measures

The following tables present a reconciliation of adjusted EBITDA and distributable cash flow, which are non-GAAP financial measures, to the most comparable GAAP financial measures of net income and net cash provided by operating activities. The amounts presented reflect the results for the year ended December 31, 2012 as presented in this Annual Report on Form 10-K less the results for the six months ended June 30, 2012 as presented in the Company’s Form 10-Q for the second quarter of 2012.