Amendment No. 5
to
Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

EQT Midstream Partners, LP
(Exact Name of Registrant as Specified in its Charter)

625 Liberty Avenue
Pittsburgh, Pennsylvania 15222
(412) 553-5700
(Address, including Zip Code, and Telephone Number, including Area Code, of Registrant's Principal Executive Offices)

Philip P. Conti
625 Liberty Avenue
Pittsburgh, Pennsylvania 15222
(412) 553-5700
(Name, Address, including Zip Code, and Telephone Number, including Area Code, of Agent for Service)

Approximate date of commencement of proposed sale to the public:
As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

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

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted

This is the initial public offering of our common units representing limited partner interests. We are offering 12,500,000 common units in this offering. We currently expect that the initial public offering price will be between $19.00 and $21.00 per common unit. Prior to this offering, there has been no public market for our common units. We have been approved to list our common units on the New York Stock Exchange, subject to official notice of issuance, under the symbol "EQM."

As a result of certain FERC rate-making policies, we require an owner of our common units to be an eligible taxable holder. Eligible taxable holders are individuals or entities subject to United States federal income taxation on our income or entities not subject to such taxation so long as all of the entity's owners are subject to such taxation.

We are an "emerging growth company" as defined under the federal securities laws and, as such, may elect to comply with certain reduced public company reporting requirements.

Investing in our common units involves risks. Please read "Risk Factors" beginning on page 22.

Neither the Securities and Exchange Commission nor any other regulatory body has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

To the extent that the underwriters sell more than 12,500,000 common units in this offering, the underwriters have the option to purchase up to an additional 1,875,000 common units from EQT Midstream Partners, LP at the initial public offering price less underwriting discounts.

The underwriters expect to deliver the common units to purchasers on or about , 2012, through the book-entry facilities of The Depository Trust Company.

You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered to you. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications or other published independent sources. Some data is also based on our good faith estimates.

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. It does not contain all of the information that you should consider before investing in the common units. You should read the entire prospectus carefully, including "Risk Factors" beginning on page 22 and the historical and pro forma financial statements and the notes to those financial statements included elsewhere in this prospectus. Unless indicated otherwise, the information presented in this prospectus assumes (1) an initial public offering price of $20.00 per common unit (the midpoint of the price range set forth on the cover page of this prospectus) and (2) that the underwriters do not exercise their option to purchase additional units. We include a glossary of some of the terms used in this prospectus as Appendix B. References in this prospectus to "EQT Midstream," "we," "our," "us" or like terms when used in a historical context refer to the businesses and assets of Equitrans, L.P., which EQT Corporation is contributing to EQT Midstream Partners, LP in connection with this offering. The results of operations of Equitrans, L.P. exclude the results of Big Sandy Pipeline, a FERC-regulated transmission pipeline sold by Equitrans, L.P. to an unrelated party in July 2011 and not reflected in the presentation of our financial statements. When used in the present tense or prospectively, those terms refer to EQT Midstream Partners, LP and its subsidiaries. References in this prospectus to "EQT" refer to EQT Corporation and its controlled affiliates (other than us). Please read "—Formation Transactions and Partnership Structure" on page 9.

EQT Midstream Partners, LP

Overview

We are a growth-oriented limited partnership formed by EQT Corporation (NYSE: EQT) to own, operate, acquire and develop midstream assets in the Appalachian Basin. We provide substantially all of our natural gas transmission, storage and gathering services under contracts with fixed reservation and/or usage fees, with a significant portion of our revenues being generated pursuant to long-term firm contracts. We will initially focus our operations in the Marcellus Shale fairway in southern Pennsylvania and northern West Virginia, a rapidly growing natural gas play and the core operating area of EQT. We believe that our strategically located assets and our relationship with EQT position us as a leading Appalachian Basin midstream energy company serving the Marcellus Shale.

EQT is our largest customer and is one of the largest natural gas producers in the Appalachian Basin. For the year ended December 31, 2011, EQT reported 5.4 Tcfe of proved reserves and total production of 198.8 Bcfe, representing a 44% increase in production as compared to the year ended December 31, 2010. Approximately 42% of EQT's total production in 2011 was from wells in the Marcellus Shale. During the year ended December 31, 2011 and the three-month period ended March 31, 2012, approximately 64% and 65%, respectively, of our total natural gas transmission and gathering volumes were comprised of natural gas produced by EQT. In order to facilitate production growth in its areas of operation, EQT has invested $1.7 billion in midstream infrastructure from January 1, 2007 through March 31, 2012 and currently owns a substantial and growing portfolio of midstream assets, many of which have multiple interconnects into our system. We believe EQT's economic relationship with us incentivizes EQT to provide us with access to additional production growth in and around our existing assets and with acquisitions and organic growth opportunities, although EQT is under no obligation to do so.

We provide midstream services to EQT and third parties in the Appalachian Basin across 22 counties in Pennsylvania and West Virginia through our two primary assets: our transmission and storage system, which serves as a header system transmission pipeline, and our gathering system, which delivers natural gas from wells and other receipt points to transmission pipelines.

Equitrans Transmission and Storage System. Our transmission and storage system includes an approximately 700 mile FERC-regulated interstate pipeline system that connects to five interstate pipelines and multiple distribution companies, and it 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. As of March 31, 2012, our transmission assets had total throughput capacity of approximately 1.0 TBtu per day. Revenues associated with our transmission and storage system represented approximately 85% and 87%, respectively, of our total revenues for the year ended December 31, 2011 and the three-month period ended March 31, 2012. As of March 31, 2012, the weighted average remaining contract life based on total revenues for our firm transmission and storage contracts was approximately 9.5 years.

Our transmission and storage system was initially constructed to receive natural gas from interstate pipelines and local conventional natural gas producers for delivery to local distribution companies, or 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 beginning in 2007 and the resulting excess supply of natural gas in the region, we shifted the focus of our transmission and storage system and reengineered our pipeline to act as a header system receiving natural gas produced in the Marcellus Shale for delivery into interstate pipelines that serve customers throughout the Mid-Atlantic and Northeastern United States in addition to our continued deliveries to LDCs and end-users directly connected to our system.

In 2010, we initiated an expansion of our transmission and storage system, which is now complete, 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, which we refer to as the Equitrans 2010 Marcellus expansion project. The Equitrans 2010 Marcellus expansion project 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 Transmission LP, or 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.

Pursuant to an acreage dedication to us from EQT, we have the right to elect to transport on our 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 drilling program in these areas and is expanding its retained midstream infrastructure, which connects to our transmission and storage system, to meet expected production growth. For additional information on this acreage dedication, please see "Certain Relationships and Related Transactions—Contracts with Affiliates—Acreage Dedication."

Equitrans Gathering System. Our gathering system consists of approximately 2,100 miles of FERC-regulated low-pressure gathering lines that have multiple delivery interconnects with our transmission and storage system and a gathering and interstate pipeline system owned and operated by Dominion Transmission, Inc., or Dominion Transmission. Revenues associated with our gathering system, all of which were generated under interruptible gathering service contracts, represented approximately 15% and 13%, respectively, of our total revenues for the year ended December 31, 2011 and the three-month period ended March 31, 2012.

The following table provides information regarding our transmission, storage and gathering assets as of March 31, 2012 and for the periods indicated:

							Approximate Average Daily Throughput (BBtu/d)

System	Approximate Number of Miles		Approximate Number of Receipt Points		Approximate Compression (Horsepower)		Year Ended December 31, 2011		Three-Month Period Ended March 31, 2012
Transmission and Storage		700		62		17,000		397		462
Gathering		2,100		2,400		23,000		78		75

Business Strategies

Our principal business objective is to increase the quarterly cash distributions that we pay to our unitholders over time while ensuring the ongoing stability of our business. We expect to achieve this objective through the following business strategies:

•: Pursuing accretive acquisitions from EQT. We intend to seek opportunities to expand our existing natural gas transmission, storage and gathering operations primarily through accretive acquisitions from EQT. We believe that EQT's economic relationship with us incentivizes it to offer us acquisition opportunities, although it is under no obligation to do so.
•: Capitalizing on economically attractive organic growth opportunities. EQT's acreage dedication to our assets and EQT's economic relationship with us provide us with a platform for organic growth. We expect to achieve this growth by meeting EQT's midstream needs, which we expect to increase as a result of its anticipated drilling activity in our areas of operation. In addition, we intend 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 with us such knowledge and expertise.
•: Attracting additional third-party volumes to our system. We actively market our midstream services to, and pursue strategic relationships with, third-party producers in order to attract additional volumes and/or expansion opportunities. We believe that our connectivity to interstate pipelines, which is a key feature of a header system transmission pipeline, as well as our position as an early developer of midstream infrastructure within certain areas of the Marcellus Shale, will allow us to capture additional third-party volumes in the future.
•: Focusing on stable, fixed-fee business. We intend to pursue opportunities to provide fixed-fee transmission, storage and gathering services to EQT and third parties. We 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. We are 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. Our transmission and storage system has the flexibility to accommodate significant additional throughput to service new end-user markets and we believe that our access to numerous supply sources, including Marcellus Shale production, five interstate pipelines and our on-system storage facilities, which can be used to balance volatile load swings, make us an attractive option for these end-user delivery markets.

Competitive Strengths

We believe we are well-positioned to successfully execute our business strategies because of the following competitive strengths:

•

Our affiliation with EQT. We believe that EQT, as the owner of our 2.0% general partner interest, all of our incentive distribution rights and a 62.7% limited partner interest in us, is motivated to promote and support the successful execution of our principal business objective through, for example, the following:

—: Acquisition opportunities: EQT owns and operates a large and growing portfolio of Appalachian Basin midstream assets, and we believe EQT will offer us the opportunity to purchase some or all of such assets in the future, although it is not obligated to do so.
—: EQT Production and Marketing: EQT Production Company, which is EQT's production affiliate, is one of the largest natural gas producers in the Appalachian Basin with 5.4 Tcfe of proved reserves as of December 31, 2011, a portion of which is dedicated to our transmission system. EQT Energy, LLC, EQT's marketing affiliate, is one of our largest customers and is an anchor tenant on a number of recently completed and ongoing midstream growth projects.
—: Equitable Gas Company: Equitable Gas Company, LLC, EQT's local distribution company, which serves approximately 275,000 customers in southwestern Pennsylvania and northern West Virginia, has multiple interconnects with our transmission and storage system.
—: Significant industry and management expertise: Through our relationship with EQT, we will have access to a significant pool of management talent, strong commercial relationships throughout the energy industry and the broad operational, commercial, technical, risk management and administrative infrastructure of EQT. We believe this access will, among other things, enhance the efficiency of our operations in areas such as pipeline and gathering expansion projects, an area where EQT has significant experience in the Appalachian Basin.

•

Strategically located asset base. Our assets are strategically located in the fairway of the Marcellus Shale. Moreover, we own a header system transmission pipeline that has multiple connections to major interstate pipelines and provides access to natural gas end-user markets in the region as well as in the Mid-Atlantic and Northeastern United States.

•

Stable cash flows underpinned by long-term, fixed-fee contracts. Substantially all of our revenues are generated under long-term, fixed-fee contracts. In addition, for the year ended December 31, 2011, approximately 64% of our revenues were generated from capacity reservation charges under long-term firm contracts that our customers are required to pay regardless of the actual capacity utilized. This contract structure enhances the stability of our cash flows and minimizes our direct exposure to commodity price risk.

•

Operational flexibility of our transmission and storage system. One of the key strengths of our transmission and storage system is that it is a header system transmission pipeline that contains valuable operational flexibility. This inherent flexibility, derived from our pipeline's multiple receipt and delivery interconnects, numerous pipeline segments and the diverse location of its storage reservoirs, enables us to leverage system pressures to optimize gas flows and expand capacity at a low cost, resulting in increased throughput and maximum system utilization. For these reasons, we believe that our operational flexibility will allow us to continue to attract suppliers and increase the utilization of our assets.

•

Financial flexibility and strong capital structure. At the closing of this offering, we expect to have no outstanding indebtedness and undrawn borrowing capacity of $350 million under our new $350 million revolving credit facility, allowing us to competitively pursue acquisitions and organic growth opportunities.

Our Relationship with EQT

One of our principal attributes is our 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 5.4 Tcfe of proved reserves as of December 31, 2011 across three major plays: Marcellus Shale, Huron Shale and coalbed methane. EQT Midstream provides transmission, storage and gathering services for EQT's produced natural gas and to third parties in the Appalachian Basin. EQT also has a regulated natural gas distribution subsidiary, Equitable Gas Company, LLC, or Equitable Gas Company, which distributes and sells natural gas to residential, commercial and industrial customers in southwestern Pennsylvania and West Virginia.

At the closing of this offering, EQT will own a 2.0% general partner interest in us, all of our incentive distribution rights and a 62.7% limited partner interest in us. Because of its ownership of the incentive distribution rights, EQT is positioned to directly benefit from committing additional natural gas volumes to our systems and facilitating accretive acquisitions and organic growth opportunities. However, EQT is under no obligation to make acquisition opportunities available to us, is not restricted from competing with us and may acquire, construct or dispose of midstream assets without any obligation to offer us the opportunity to purchase or construct these assets. Please read "Certain Relationships and Related Transactions—Omnibus Agreement" beginning on page 169.

We believe that our 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 acres as of December 31, 2011, of which approximately 530,000 acres were located in the Marcellus Shale. A substantial portion of EQT's drilling efforts in 2011 were focused on drilling horizontal wells in Marcellus Shale formations in Pennsylvania and northern West Virginia. For the year ended December 31, 2011, EQT reported total production of 198.8 Bcfe, representing a 44% increase in production as compared to the year ended December 31, 2010. Approximately 42% of EQT's total production in 2011 was from wells in the Marcellus Shale.

•

EQT has a substantial and growing portfolio of midstream assets. We expect 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 us. EQT's retained midstream assets include:

—: Sunrise Pipeline project. EQT will retain ownership of the Sunrise Pipeline project, or Sunrise Pipeline, which is currently under construction and is expected to be placed into service in the third quarter of 2012. The Sunrise Pipeline will provide access to liquids-rich Marcellus Shale acreage and will consist of 41.5 miles of 24-inch diameter pipeline that parallels and interconnects with the segment of our transmission and storage system from Wetzel County, West Virginia to Greene County, Pennsylvania. In addition, the Sunrise Pipeline project will include connecting to a new delivery point with Texas Eastern in Greene County and constructing the Jefferson compressor station. The Sunrise Pipeline project will provide 314 BBtu per day of additional firm capacity to the system at an estimated cost of approximately $220 million, approximately $205 million of which is expected to have been expended by June 30, 2012. 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 us 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, we will operate the Sunrise Pipeline under a lease agreement with EQT pursuant to which we will market the capacity, enter into all agreements for transportation service with customers and operate the Sunrise Pipeline pursuant to the terms of our tariff. We will make lease payments to EQT once the pipeline is placed into service 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 cash available for distribution. Upon termination of the lease agreement, we 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. We expect that EQT will terminate the lease once this system is fully developed. For a description of this lease agreement, please read "Certain Relationships and Related Transactions—Contracts with Affiliates—Sunrise Pipeline Lease Agreement."

—: Other retained midstream assets. EQT's retained midstream asset base also includes approximately 8,300 miles of gathering pipelines that gathered approximately 706 BBtu of natural gas per day for the three-month period ended March 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, we expect it will develop, either independently or in partnership with us, additional midstream assets to ensure takeaway capacity for expected production growth.

While our relationship with EQT and its subsidiaries may provide significant benefits, it may also become a source of potential conflicts. For example, EQT is not restricted from competing with us. In addition, all of the executive officers and a majority of the directors of our general partner also serve as officers and/or directors of EQT, and these officers and directors face conflicts of interest, including conflicts of interest regarding the allocation of their time between us and EQT. Please read "Conflicts of Interest and Duties."

Risk Factors

An investment in our common units involves risks associated with our business, our regulatory and legal matters, our limited partnership structure and the tax characteristics of our common units. The following list of risk factors is not exhaustive. You should carefully consider the risks described in "Risk Factors" beginning on page 22 of this prospectus and the other information in this prospectus before deciding whether to invest in our common units.

Risks Inherent in Our Business

•: 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.
•: We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to holders of our common and subordinated units.

•: On a pro forma basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all units for the year ended December 31, 2011 or for the twelve-month period ended March 31, 2012.
•: Our natural gas transmission, 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 and ability to make distributions.
•: Any significant decrease in production of natural gas in our areas of operation could adversely affect our business and operating results and reduce our cash available for distribution to 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.
•: 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.
•: 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.
•: We are subject to numerous hazards and operational risks.

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 and other affiliates of our general partner are not restricted in their ability to compete with us.
•: You will experience immediate and substantial dilution in net tangible book value of $8.02 per common unit.
•: 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.
•: Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.
•: Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

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 cash available for distribution to our unitholders would be substantially reduced.
•: If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.

•: 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.
•: 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.

Management of EQT Midstream Partners, LP

We are managed and operated by the board of directors and executive officers of our general partner, EQT Midstream Services, LLC. EQT will own all of the ownership interests in our general partner and will be entitled to appoint the entire board of directors of our general partner. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operation. All of the officers of our general partner are also officers and/or directors of EQT. For information about the executive officers and directors of our general partner, please read "Management" beginning on page 156.

Under the listing requirements of the New York Stock Exchange, or NYSE, the board of directors of our general partner will be required to have at least three independent directors meeting the NYSE's independence standards. The board of directors of our general partner is comprised of six directors, including two independent directors. EQT will appoint a third independent director within one year following this offering.

In connection with the closing of this offering, we will enter into an omnibus agreement with EQT and our general partner, pursuant to which we will agree upon certain aspects of our relationship with them, including the provision by EQT to us of certain administrative services and employees, our agreement to reimburse EQT for the cost of such services and employees, certain indemnification and reimbursement obligations, the use by us of the name "EQT" and related marks, and other matters. In addition, we will also enter into an operation and management services agreement with EQT, pursuant to which EQT will operate our assets and be reimbursed in accordance with the terms of the omnibus agreement. Neither our general partner nor EQT will receive any management fee or other compensation in connection with our general partner's management of our business. However, prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including EQT, for all expenses they incur and payments they make on our behalf pursuant to the omnibus agreement and the operation and management services agreement. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. Please read "Certain Relationships and Related Transactions—Omnibus Agreement" beginning on page 169.

Our general partner will own 707,744 general partner units representing a 2.0% general partner interest in us, which will entitle it to receive 2.0% of all the distributions we make. Our general partner will also own all of our incentive distribution rights, which will entitle it to increasing percentages, up to a maximum of 48.0%, of the cash we distribute in excess of $0.4025 per unit per quarter after the closing of our initial public offering. In addition, EQT will own 4,839,718 common units and 17,339,718 subordinated units. Please read "Certain Relationships and Related Transactions" beginning on page 168.

Formation Transactions and Partnership Structure

At or prior to the closing of this offering the following transactions, which we refer to as the formation transactions, will occur:

•: Equitrans, L.P. will distribute its interest in the Sunrise Pipeline to EQT;
•: Equitrans, L.P. will assign certain trade and other accounts receivable to EQT;
•: EQT will make a capital contribution to Equitrans, L.P., which Equitrans, L.P. will use to retire all outstanding intercompany indebtedness and certain amounts due to a related party with EQT;
•: EQT will contribute all of the partnership interests in Equitrans, L.P. to us;
•: We will issue to EQT 4,839,718 common units and 17,339,718 subordinated units, representing an aggregate 62.7% limited partner interest in us;
•: We will issue to our general partner 707,744 general partner units representing a 2.0% general partner interest in us and all of our incentive distribution rights;
•: We will issue 12,500,000 common units to the public in this offering, representing a 35.3% limited partner interest in us, and will use the proceeds of this offering as described in "Use of Proceeds" beginning on page 59;
•: We will enter into a new $350 million revolving credit facility, as described in "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—New Credit Facility" beginning on page 111;
•: We will enter into a lease agreement with EQT pursuant to which we will lease and operate the Sunrise Pipeline, as described under "Certain Relationships and Related Transactions" beginning on page 168; and
•: We will enter into an omnibus agreement and an operation and management services agreement with EQT, our general partner and certain of their affiliates, as described under "Certain Relationships and Related Transactions" beginning on page 168.

The number of common units to be issued to EQT includes 1,875,000 common units that will be issued at the expiration of the underwriters' option to purchase additional common units, assuming that the underwriters do not exercise their option. Any exercise of the underwriters' option to purchase additional units would reduce the common units shown as issued to EQT by the number to be purchased by the underwriters in connection with such exercise. If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to any exercise will be sold to the public, and any remaining common units not purchased by the underwriters pursuant to any exercise of the option will be issued to EQT at the expiration of the option period. All of the net proceeds from any exercise of the underwriters' option to purchase additional common units will be used to make an additional cash distribution to EQT.

Ownership of EQT Midstream Partners, LP

The following diagram depicts our simplified organizational and ownership structure after giving effect to the formation transactions and this offering.


Public Common Units	35.3	%
EQT:
Common Units(1)	13.7	%
Subordinated Units	49.0	%
General Partner Units	2.0	%

Total	100.0	%

(1): Assumes no exercise of the underwriters' option to purchase additional common units. Please read "—Formation Transactions and Partnership Structure" on page 9 for a description of the impact of an exercise of the option on the common unit ownership percentages.

Principal Executive Offices and Internet Address

Our principal executive offices are located at 625 Liberty Avenue, Pittsburgh, Pennsylvania 15222, and our telephone number is (412) 553-5700. Our website is located at www.eqtmidstreampartners.com and will be activated immediately following this offering. We expect to make available our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, which we refer to as the SEC, free of charge through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

Summary of Conflicts of Interest and Duties

Our general partner has a duty to manage our partnership in a manner it subjectively believes is in our best interests. However, the officers and directors of our general partner also have duties to manage our general partner in a manner beneficial to its owner, EQT. Additionally, all of our executive officers and a majority of our directors are also officers and/or directors of EQT. As a result, conflicts of interest may arise in the future between us and our common unitholders, on the one hand, and EQT and our general partner, on the other hand. For a more detailed description of the conflicts of interest of our general partner, please read "Risk Factors—Risks Inherent in an Investment in Us" and "Conflicts of Interest and Duties—Conflicts of Interest."

Delaware law provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties owed by the general partner to limited partners and the partnership. Pursuant to these provisions, our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of the general partner and the methods of resolving conflicts of interest. The effect of these provisions is to restrict the remedies available to our common unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. Our partnership agreement also provides that affiliates of our general partner, including EQT and its other subsidiaries and affiliates, are permitted to compete with us. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and each common unitholder is treated as having consented to various actions and potential conflicts of interest contemplated in the partnership agreement that might otherwise be considered a breach of fiduciary or other duties under applicable state law.

For a description of our other relationships with our affiliates, please read "Certain Relationships and Related Transactions" beginning on page 168.

The Offering


Common units offered to the public		12,500,000 common units, or 14,375,000 common units if the underwriters exercise their option to purchase additional common units in full.
Units outstanding after this offering		17,339,718 common units and 17,339,718 subordinated units, representing a 49.0% and 49.0% limited partner interest in us, respectively. If the underwriters do not exercise their option to purchase additional common units, we will issue an additional 1,875,000 common units to EQT at the expiration of the option for no additional consideration. If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to any exercise will be sold to the public, and any remaining common units not purchased by the underwriters pursuant to any exercise of the option will be issued to EQT at the expiration of the option period. Accordingly, the exercise of the underwriters' option will not affect the total number of common units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Our general partner will own 707,744 general partner units, representing a 2.0% general partner interest in us.
Use of proceeds		We intend to use the net proceeds from this offering of approximately $230 million (assuming an initial public offering price of $20.00 per common unit, the midpoint of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts, the structuring fee and offering expenses, to
		• fund a cash distribution of approximately $182 million to EQT, in part for reimbursement of capital expenditures associated with our assets;
		• provide approximately $14 million in working capital to replenish amounts distributed by Equitrans to EQT, in the form of trade and other accounts receivable, in connection with the closing of this offering;
		• pre-fund approximately $32 million of maintenance capital expenditures, the majority of which is expected to be incurred over the next two years, related to two identified regulatory compliance initiatives; and
		• pay approximately $2 million in revolving credit facility origination fees.


		If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds will be approximately $35.1 million. The net proceeds from any exercise of such option will be used to make an additional cash distribution to EQT.
Cash distributions		We intend to pay the minimum quarterly distribution of $0.3500 per unit ($1.40 per unit on an annualized basis) to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We refer to this cash as "available cash," and we define its meaning in our partnership agreement. Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail under the caption "Our Cash Distribution Policy and Restrictions on Distributions" beginning on page 63.
		We will adjust the amount of our distribution for the period from the completion of this offering through September 30, 2012, based on the actual length of that period.
		Our partnership agreement requires us to distribute all of our available cash each quarter in the following manner:
		• first, 98.0% to the holders of common units and 2.0% to our general partner, until each common unit has received the minimum quarterly distribution of $0.3500 plus any arrearages from prior quarters;
		• second, 98.0% to the holders of subordinated units and 2.0% to our general partner, until each subordinated unit has received the minimum quarterly distribution of $0.3500; and
		• third, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unit has received a distribution of $0.4025.


		If cash distributions to our unitholders exceed $0.4025 per unit in any quarter, our general partner will receive, in addition to distributions on its 2.0% general partner interest, increasing percentages, up to 48.0%, of the cash we distribute in excess of that amount. We refer to these distributions as "incentive distributions" because they incentivize our general partner to increase distributions to our unitholders. In certain circumstances, our general partner, as the initial holder of our incentive distribution rights, will have the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages of the cash we distribute to higher levels based on our cash distributions at the time of the exercise of this reset election. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions" beginning on page 79.
		Prior to making distributions, we will reimburse EQT for its provision of certain general and administrative services and any additional services we may request from EQT (including certain incremental costs and expenses we will incur as a result of being a publicly traded partnership) each pursuant to the omnibus agreement. Please read "Certain Relationships and Related Transactions—Omnibus Agreement" beginning on page 169.
		Pro forma cash available for distribution generated during the year ended December 31, 2011 and the twelve-month period ended March 31, 2012 was approximately $44.9 million and $44.8 million, respectively. The amount of available cash we will need to pay the minimum quarterly distribution for four quarters on our common units, subordinated units and general partner units to be outstanding immediately after this offering will be approximately $49.5 million (or an average of approximately $12.4 million per quarter). As a result, we would not have generated available cash sufficient to pay the full minimum quarterly distribution of $0.3500 per unit per quarter ($1.40 per unit on an annualized basis) on all of our common units and subordinated units for the year ended December 31, 2011 or the twelve-month period ended March 31, 2012. Please read "Our Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2011 and the Twelve-Month Period Ended March 31, 2012" beginning on page 66.


		We believe that, based on the financial forecasts and related assumptions included under the caption "Our Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve-Month Period Ending June 30, 2013," we will have sufficient cash available for distribution to make cash distributions for the twelve-month period ending June 30, 2013, at the minimum quarterly distribution rate of $0.3500 per unit per quarter ($1.40 per unit on an annualized basis) on all common units, subordinated units and general partner units.
Subordinated units		EQT will initially indirectly own all of our subordinated units. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution of available cash until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. If we do not pay distributions on our subordinated units, our subordinated units will not accrue arrearages for those unpaid distributions.
Conversion of subordinated units		The subordination period will end on the first business day after we have earned and paid at least (i) $1.40 (the minimum quarterly distribution on an annualized basis) on each outstanding common, subordinated and general partner unit, for each of three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2015, or (ii) $2.10 (150% of the annualized minimum quarterly distribution) on each outstanding common unit, subordinated unit and general partner unit, in addition to any distribution made in respect of the incentive distribution rights, for any four-quarter period ending on or after June 30, 2013, in each case provided that there are no arrearages on our common units at that time. In addition, the subordination period will end upon the removal of our general partner other than for cause if the units held by our general partner and its affiliates are not voted in favor of such removal.
		When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units thereafter will no longer be entitled to arrearages. Please read "Provisions of Our Partnership Agreement Related to Cash Distributions—Subordination Period" beginning on page 83.
Issuance of additional units		Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our unitholders. Please read "Units Eligible for Future Sale" beginning on page 198 and "The Partnership Agreement—Issuance of Additional Partnership Interests" on page 188.


Limited voting rights		Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 66²/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon closing of this offering, EQT and its affiliates will own an aggregate of approximately 64.0% of our common and subordinated units. This will give EQT the ability to prevent the involuntary removal of our general partner. Please read "The Partnership Agreement—Voting Rights" beginning on page 185.
Limited call right		If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner will have the right, but not the obligation, to purchase all, but not less than all, of the remaining common units at a price not less than the then-current market price of the common units, as calculated in accordance with our partnership agreement.
Redemption of ineligible holders		Each transferee of common units, upon becoming the record holder of such common units, will automatically certify, and the general partner at any time can request such unitholder to re-certify, that such transferee is an eligible taxable holder. Eligible taxable holders are: • individuals or entities subject to U.S. federal income taxation on the income generated by us; or • entities not subject to U.S. federal income taxation on the income generated by us, so long as all of the entity's owners are subject to such taxation.
		We will have the right, which we may assign to any of our affiliates, but not the obligation, to redeem all of the common units of any holder that is not an eligible taxable holder or that has failed to certify or has falsely certified that such holder is an eligible taxable holder. The redemption price would be equal to the then-current market price of the common units, as calculated in accordance with our partnership agreement. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. The units will not be entitled to any allocations of income or loss or distributions or voting rights while held by such unitholder.
		Please read "The Partnership Agreement—Redemption of Ineligible Holders" on page 194.


Estimated ratio of taxable income to distributions		We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2014, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed to you with respect to that period. Thereafter, the ratio of allocable taxable income to cash distributions to you could substantially increase. Please read "Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions" on page 203.
Material federal income tax consequences		For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read "Material Federal Income Tax Consequences" on page 200.
Directed Unit Program		At our request, the underwriters have reserved up to 8% of the common units being offered by this prospectus for sale at the initial public offering price to the officers, directors and employees of our general partner and its affiliates and certain other persons associated with us, as designated by us. For further information regarding our directed unit program, please read "Underwriting."
New York Stock Exchange listing		We have been approved to list our common units on the New York Stock Exchange, subject to official notice of issuance, under the symbol "EQM."

Summary Historical and Pro Forma Financial and Operating Data

The following table shows summary historical financial and operating data of Equitrans, L.P., which we refer to as our Predecessor, excluding the results of operations of Big Sandy Pipeline, a FERC-regulated transmission pipeline sold by Equitrans, L.P. to an unrelated party in July 2011, and summary pro forma financial data of EQT Midstream Partners, LP as of and for the year ended December 31, 2011 and the three-month period ended March 31, 2012. The summary historical financial data presented as of December 31, 2010 and 2011 and for the years ended December 31, 2009, 2010 and 2011 are derived from the historical audited financial statements that are included elsewhere in this prospectus. The summary historical financial data of our Predecessor presented as of March 31, 2012 and for the three-month period ended March 31, 2011 and 2012 are derived from the unaudited historical financial statements that are included elsewhere in this prospectus. The following table should be read together with, and is qualified in its entirety by reference to, the historical and unaudited pro forma financial statements and the accompanying notes included elsewhere in this prospectus. The table should also be read together with "Management's Discussion and Analysis of Financial Condition and Results of Operations" beginning on page 97.

The summary pro forma financial data presented as of and for the three-month period ended March 31, 2012 and for the year ended December 31, 2011 was derived from the unaudited and audited financial statements of our Predecessor included elsewhere in this prospectus. Our unaudited pro forma financial statements give pro forma effect to:

•: the distribution of Equitrans, L.P.'s interest in the Sunrise Pipeline to EQT;
•: the retirement by Equitrans, L.P. of all outstanding intercompany indebtedness and certain amounts due to/from related parties with EQT with the proceeds of a capital contribution by EQT;
•: the assignment of trade and other accounts receivable by Equitrans, L.P.;
•: the contribution by EQT of all of the partnership interests in Equitrans, L.P. to us;
•: the issuance to EQT of 4,839,718 common units and 17,339,718 subordinated units, representing an aggregate 62.7% limited partner interest in us;
•: the issuance to our general partner of 707,744 general partner units representing a 2.0% general partner interest in us and all of our incentive distribution rights;
•: the issuance of 12,500,000 common units to the public in this offering, representing a 35.3% limited partner interest in us;
•: our entry into a new $350 million revolving credit facility;
•: the use of proceeds of this offering as described in "Use of Proceeds" beginning on page 59; and
•: our entry into a lease agreement with EQT pursuant to which we will lease and operate the Sunrise Pipeline.

																Pro Forma

										Three-Month Period Ended March 31,						Pro Forma
	Year Ended December 31,									Three-Month Period Ended March 31,						Year Ended December 31, 2011			Three-Month Period Ended March 31, 2012
	2009			2010			2011			2011			2012			Year Ended December 31, 2011			Three-Month Period Ended March 31, 2012
										(unaudited)						(unaudited)
	(In thousands, except per unit and operating data)
Statement of Operations Data:
Total operating revenues	$	80,057		$	91,600		$	109,613		$	26,626		$	31,003		$	109,613		$	31,003
Operating expenses:
Operating and maintenance		18,433			24,300			26,221			4,887			7,024			26,221			7,024
Selling, general and administrative⁽¹⁾		23,268			18,477			17,302			3,802			4,549			17,302			4,549
Depreciation and amortization		9,652			10,886			11,470			2,841			3,038			11,470			3,038

Total operating expenses		51,353			53,663			54,993			11,530			14,611			54,993			14,611

Operating income		28,704			37,937			54,620			15,096			16,392			54,620			16,392
Other income⁽²⁾		1,115			498			3,826			346			2,471			3,826			2,471
Interest expense, net⁽³⁾		(5,187	)		(5,164	)		(5,050	)		(1,294	)		(1,539	)		(1,305	)		(326	)
Income tax expense⁽⁴⁾		(10,601	)		(14,030	)		(20,807	)		(5,513	)		(6,201	)		—			—

Net income	$	14,031		$	19,241		$	32,589		$	8,635		$	11,123		$	57,141		$	18,537

Net income per limited partners' unit
Common units																$	1.61			0.52
Subordinated units																	1.61			0.52
Balance Sheet Data (at period end):
Total assets	$	386,682		$	415,001		$	546,442					$	597,906					$	588,545
Property, plant and equipment, net		320,769			337,218			470,892						521,966						521,966
Long-term debt—affiliate		57,107			135,235			135,235						135,235						—
Total partners' capital		102,656			125,523			173,633						184,756						423,796
Cash Flow Data:
Net cash provided by (used in)
Operating activities	$	48,193		$	28,716		$	47,564		$	13,478		$	11,606
Investing activities		(32,143	)		(36,404	)		(135,831	)		(10,992	)		(51,240	)
Financing activities		3,228			2,751			73,926			(2,420	)		39,634
Other Financial Data: (unaudited)
Adjusted EBITDA⁽⁵⁾	$	39,400		$	50,115		$	68,339		$	18,393		$	20,071		$	68,339		$	20,071
Operating Data: (unaudited)
Transmission pipeline throughput (BBtu per day)		150			204			397			319			462			397			462
Gathered volumes (BBtu per day)		71			83			78			64			75			78			75
Capital expenditures
Expansion capital expenditures⁽⁶⁾	$	18,989		$	22,777		$	108,981		$	8,541		$	47,134
Maintenance capital expenditures⁽⁷⁾
Ongoing maintenance⁽⁸⁾	$	13,093		$	13,339		$	26,636		$	2,351		$	4,106
Regulatory compliance⁽⁹⁾		61			288			214			100			—

Total maintenance capital expenditures	$	13,154		$	13,627		$	26,850		$	2,451		$	4,106

(1): Pro forma selling, general and administrative expenses do not give effect to annual incremental selling, general and administrative expenses of approximately $3.0 million that we expect to incur as a result of being a publicly traded partnership.
(2): Consists of AFUDC equity income. AFUDC, or allowance for funds used during construction, is the amount approved by the FERC for inclusion in our tariff rates as reimbursement for the cost of financing construction projects with investor capital until a project is placed into operation.
(3): Pro forma interest expense is related to commitment fees on, and the amortization of origination fees incurred in connection with, our new revolving credit facility.

(4): Our historical financial statements include U.S. federal and state income tax expense incurred by us. Due to our status as a partnership, we will not be subject to U.S. federal income tax and certain state income taxes in the future.
(5): For a discussion of the non-GAAP financial measure Adjusted EBITDA, please read "—Non-GAAP Financial Measure" below.
(6): Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term.
(7): Maintenance capital expenditures are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long term, our operating capacity or operating income. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines, to connect new wells to maintain throughput, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.
(8): Ongoing maintenance capital expenditures are all maintenance capital expenditures other than the specific regulatory compliance capital expenditures discussed in footnote (9) below.
(9): Regulatory compliance capital expenditures are identified maintenance capital expenditures necessary to comply with regulatory and other legal requirements. We have identified two specific regulatory compliance initiatives which will require us to expend approximately $32 million, the majority of which is expected to be incurred over the next two years. We will retain approximately $32 million from the net proceeds of this offering, which we anticipate will fully fund these expenditures. For a more complete description of these initiatives as well as their anticipated costs, please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Factors and Trends Impacting Our Business—Regulatory Compliance" on page 104.

Non-GAAP Financial Measure

We define Adjusted EBITDA as net income (loss) plus net interest expense, income tax expense, depreciation and amortization expense, and non-cash long-term compensation expense less other income and the Sunrise Pipeline lease payment. There were no Sunrise Pipeline lease payments in the historical periods.

Adjusted EBITDA is a non-GAAP supplemental financial measure that management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:

•: our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis or, financing methods;
•: the ability of our assets to generate sufficient cash flow to make distributions to our unitholders;
•: our ability to incur and service debt and fund capital expenditures; and
•: the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of Adjusted EBITDA in this prospectus provides useful information to investors in assessing our financial condition and results of operations. Adjusted EBITDA should not be considered an alternative to net income, operating income, cash from operations or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income and net cash provided by operating activities. Additionally, because Adjusted EBITDA may be defined differently by other companies in our industry, our definition of

Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

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

																Pro Forma

										Three-Month Period Ended March 31,						Pro Forma
	Year Ended December 31,																		Three-Month Period Ended March 31, 2012
	Year Ended December 31,															Year Ended December 31, 2011
	2009			2010			2011			2011			2012			Year Ended December 31, 2011
	(In thousands)
Reconciliation of Adjusted EBITDA to Net Income
Net income	$	14,031		$	19,241		$	32,589		$	8,635		$	11,123		$	57,141		$	18,537
Add:
Interest expense, net		5,187			5,164			5,050			1,294			1,539			1,305			326
Depreciation and amortization		9,652			10,886			11,470			2,841			3,038			11,470			3,038
Income tax expense		10,601			14,030			20,807			5,513			6,201			—			—
Non-cash long-term compensation expense⁽¹⁾		1,044			1,292			2,249			456			641			2,249			641
Less:
Other income⁽²⁾		(1,115	)		(498	)		(3,826	)		(346	)		(2,471	)		(3,826	)		(2,471	)
Sunrise Pipeline lease payment⁽³⁾		—			—			—			—			—			—			—

Adjusted EBITDA	$	39,400		$	50,115		$	68,339		$	18,393		$	20,071		$	68,339		$	20,071
Reconciliation of Adjusted EBITDA to Net Cash Provided by Operating Activities
Net cash provided by (used in) operating activities	$	48,193		$	28,716		$	47,564		$	13,478		$	11,606
Add:
Interest expense, net		5,187			5,164			5,050			1,294			1,539
Current tax		(2,210	)		2,915			8,301			2,199			(9,978	)
Other, including changes in operating working capital		(11,770	)		13,320			7,424			1,422			16,904

Adjusted EBITDA	$	39,400		$	50,115		$	68,339		$	18,393		$	20,071

(1): Represents non-cash long-term compensation expense associated with EQT's long-term incentive plan.
(2): Consists of AFUDC equity income. AFUDC, or allowance for funds used during construction, is the amount approved by the FERC for inclusion in our tariff rates as reimbursement for the cost of financing construction projects with investor capital until a project is placed into operation.
(3): At the closing of this offering, we will transfer ownership of the Sunrise Pipeline, which is under construction and is expected to be placed into service in the third quarter of 2012, to EQT. We will then enter into a capital lease with EQT for the lease of the Sunrise Pipeline. The lease payment we are required to make to EQT is designed to transfer any revenues in excess of our actual costs of operating the Sunrise Pipeline to EQT. As a result, the Sunrise Pipeline project and related lease is not expected to have net positive or negative impact on our cash available for distribution. For more information on this lease agreement, please read "Certain Relationships and Related Transactions—Contracts with Affiliates—Sunrise Pipeline Lease Agreement."

Limited partner interests are inherently different from shares of capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. We urge you to carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

If any of the following risks were to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment in us.

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, 2011 and the three-month period ended March 31, 2012, approximately 79% and 78%, respectively, 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:

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 or 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 our general partner 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 $0.3500 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 to be outstanding immediately after completion of this offering. We may not have 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:

In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:

For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read "Our Cash Distribution Policy and Restrictions on Distributions."

On a pro forma basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all units for the year ended December 31, 2011 or the twelve-month period ended March 31, 2012.

The amount of pro forma available cash generated during the year ended December 31, 2011 and the twelve-month period ended March 31, 2012 would have been sufficient to allow us to pay the full minimum quarterly distribution on all of our common units, but only approximately 81.1% and 80.7%, respectively, of the minimum quarterly distribution on all of our subordinated units for each such period. For a calculation of our ability to make cash distributions to our unitholders based on our pro forma results for the year ended December 31, 2011 and the twelve-month period ended March 31, 2012, please read "Our Cash Distribution Policy and Restrictions on Distributions."

The assumptions underlying the forecast of cash available for distribution that we include in "Our Cash Distribution Policy and Restrictions On Distributions" are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

The forecast of cash available for distribution set forth in "Our Cash Distribution Policy and Restrictions On Distributions" includes our forecasted results of operations, Adjusted EBITDA and cash available for distribution for the twelve-month period ending June 30, 2013. We estimate that our total cash available for distribution for the twelve-month period ending June 30, 2013 will be approximately $54.5 million, as compared to approximately $44.9 million for the year ended December 31, 2011 and approximately $44.8 million for the twelve-month period ended March 31, 2012, in each case on a pro forma basis. A portion of the expected increase in cash available for distribution is attributable to increased revenues from usage fees from EQT based on current projections of production growth. To the extent this growth is not achieved, our revenues during the forecast period will be adversely affected. In addition, a portion of this expected increase in cash available for distribution is attributable to revenues from additional firm capacity subscriptions associated with the Blacksville Compressor Station project, which is expected to be placed into service in the third quarter of 2012. To the extent the Blacksville Compressor Station is not placed into service in the third quarter of 2012 or we are not able to subscribe additional firm transmission capacity for the project, our revenues during the forecast period will be adversely affected. Furthermore, our forecast assumes that during the forecast period we will recover a portion of costs incurred in 2011 to comply with the Pipeline Safety Improvement Act of 2002; however the amount of such recovery is subject to FERC approval on an annual basis and it has not yet been approved and is subject to two protests. For additional information, please see "Business—Regulatory Environment—Pipeline Safety Tracker." The financial forecast has been prepared by management, and we have not received an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on our common units or subordinated units, in which event the market price of our common units may decline materially.

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 and ability to make distributions.

Our interstate natural gas transportation and storage operations are regulated by the FERC under the Natural Gas Act of 1938, or the NGA, the Natural Gas Policy Act of 1978, or 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:

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 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 March 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 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 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 and ability to make distributions to you.

Any significant decrease in production of natural gas in our areas of operation could adversely affect our business and operating results and reduce our cash available for distribution to unitholders.

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 response to historically low natural gas prices, a number of large natural gas producers have recently 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 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 May 31, 2012, the near month NYMEX natural gas futures price was $2.43 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 has increased from approximately 1.6 Tcf as of March 31, 2011 to approximately 2.5 Tcf as of March 31, 2012, 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 635 as of March 31, 2012 according to Smith Bits (a unit of Schlumberger).

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 and results of operations 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. For the year ended December 31, 2011 and the three-month period ending March 31, 2012, EQT accounted for approximately 83% and 81%, respectively, of our transmission revenues, 77% and 74%, respectively, of our storage revenues, 64% and 64%, respectively, of our gathering revenues and 79% and 78%, 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 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 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. Please read "Conflicts of Interest and Duties."

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 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 you 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, 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, and 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, results of operations, financial condition 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 March 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 incurs 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. To the extent the FERC ultimately agrees with the protestors, the level of the surcharge, and thus the amount of the anticipated cost recovery, could be significantly reduced. For additional information, please see "Business—Regulatory Environment—Pipeline Safety Tracker." 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. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations—Revenues and Contract Mix."

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 March 31, 2012, the weighted average remaining contract life based on total revenues for our firm transmission and storage contracts was approximately 9.5 years. The extension or replacement of existing contracts, including our contracts with EQT, depends on a number of factors beyond our control, including:

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, results of operations, financial condition 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, results of operations, financial condition and ability to make quarterly cash distributions to our unitholders.

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, results of operations, financial condition 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 note elsewhere in this prospectus that 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 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, results of operations, financial condition 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.

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, results of operations, financial condition 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, such as those described under "Business—Our Assets—Internal 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 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 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.

The Sunrise Pipeline project is currently under construction and may not be completed on schedule, at the budgeted cost or at all. In addition, our ability to purchase the Sunrise Pipeline in the future is subject to a number of uncertainties, including the timing and receipt of governmental and third party approvals.

We believe the Sunrise Pipeline will be placed into service in the third quarter of 2012. The construction of the Sunrise Pipeline involves numerous regulatory, environmental, political and legal uncertainties beyond our control and may not be completed on schedule, at the budgeted cost or at all.

After transfer of the Sunrise Pipeline, we will lease and operate the Sunrise Pipeline under a lease agreement with EQT that terminates after 15 years, unless terminated earlier at EQT's sole discretion. Upon termination of the lease agreement, we will be required to purchase the Sunrise Pipeline at a price to be negotiated between the parties. For a description of this lease agreement, please read "Certain Relationships and Related Transactions—Contracts with Affiliates—Sunrise Pipeline Lease Agreement." There can be no assurance that the acquisition of the Sunrise Pipeline will prove accretive to our distributable cash flow.

In addition there may be certain consents, orders, or approvals required from local, state, or federal authorities or other third parties involving the transfer and lease of the Sunrise Pipeline, the financing for the acquisition of the project, and the disposition of any land interests associated with the project. Although our growth strategy includes the acquisition of the Sunrise Pipeline, the parties may not be able to obtain all required governmental or third party approvals for such acquisition on schedule or at all.

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 following the closing of this offering.

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 cash available for distribution 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 following the closing of this offering.

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:

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 financial condition and results of operations. Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on segments of our systems. Potential customer impacts arising from service interruptions on segments of our systems could include limitations on our ability to satisfy customer requirements, obligations to provide reservations charge credits to customers in times of constrained capacity, and solicitation of existing customers by others for potential new projects that would compete directly with 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 and cash flows, 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 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 and cash flows, 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:

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 and results of operations 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 this offering. 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 operations or financial position. We may not be able to recover all or any of these costs from insurance. Please read "Business—Environmental Matters" for more information.

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 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 and results of operations.

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 and results of operations 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:

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 financial position or results of operations.

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 intend to retain approximately $32 million of the net proceeds from this offering in order to pre-fund certain identified regulatory compliance capital expenditures, the majority of which are expected to be incurred over the next two years; however the actual cost of such expenditures may exceed $32 million. Furthermore, we are not 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 forcasted maintenance capital expenditures. For additional information, please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Factors and Trends Impacting our Business—Regulatory Compliance 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, results of operations, financial condition 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. Some industry commentators have predicted that similar rules will 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 is intended to ensure uniformity between statewide environmental protection standards and municipal ordinances. 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.

The counties had sixty days or until April 16th to adopt the fee, and thirty-seven counties had chosen to opt for imposing the fee, as have fourteen counties who as of yet do not have any of these wells within their borders. As Pennsylvania counties adopt impact fees, growth in drilling and production in Pennsylvania could be reduced. If drilling reductions are significant, our operations could be adversely impacted.

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, 2009, 2010 and 2011, our actual level of fuel usage and lost and unaccounted for volumes exceeded the amounts recovered from our gathering customers by approximately 300 BBtu, 1,500 BBtu and 1,300 BBtu, respectively and for which we recognized $2.0 million, $5.7 million and $4.9 million of purchased gas cost as a component of operating and maintenance expense in 2009, 2010 and 2011, 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 and ability to make quarterly cash distributions to our unitholders.

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 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 and cash flows, 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. For example, between 2010 and 2011 the natural gas commodity market pricing spreads between the summer and winter months decreased, resulting in a decrease in our parking service volumes and pricing, and accordingly we experienced a decrease in storage operating revenues for the year ended December 31, 2011 as compared to the prior year.

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. To the extent we need to replace storage base gas in excess of 7.1 Bcf, 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 and ability to make distributions.

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

Upon the closing of the offering, we will enter into a $350 million revolving credit facility. Our new credit facility will contain various covenants and restrictive provisions that will limit our ability to, among other things:

Our new credit facility also will contain 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 you that we will meet those ratios and tests. In addition, our credit facility will contain 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 new 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 new 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 new credit facility will also have cross default provisions that apply to any other indebtedness we may have with an aggregate principal amount in excess of $15.0 million. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—New Credit Facility."

Our future debt levels may limit our flexibility to obtain financing and to pursue other business opportunities.

Following this offering, we will 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 service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.

The credit and risk profile of our general partner and 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 common 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 rate 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 common unitholders.

We rely exclusively on revenues generated from transmission, storage and gathering systems that we own, 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 cash available for distribution to our common unitholders than if we maintained more diverse assets and locations.

If we fail to develop or 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 this offering, we have not been required to file reports with the SEC. Upon the completion of this offering, we will become subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act. We prepare our financial statements in accordance with GAAP, but our internal accounting controls may not currently 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, you 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 or cash flows.

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.

Following this offering, EQT will indirectly own and control our general partner and will appoint all of the officers and directors of our general partner. All of our initial officers and a majority of our initial directors will also be 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:

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. Please read "Conflicts of Interest and Duties."

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 new 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.

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. Following this offering, the market price of our common units may fluctuate significantly, and you could lose all or part of your investment.

Prior to this offering, there has been no public market for our common units. After this offering, there will be only 12,500,000 publicly traded common units, assuming no exercise of the underwriters' over-allotment option. In addition, EQT will own 4,839,718 common units and 17,339,718 subordinated units, representing an aggregate of approximately 62.7% limited partner interest in us. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

You will experience immediate and substantial dilution in net tangible book value of $8.02 per common unit.

The estimated initial public offering price of $20.00 per common unit (the mid-point of the price range set forth on the cover of this prospectus) exceeds our pro forma net tangible book value of $11.98 per unit. Based on the estimated initial public offering price of $20.00 per common unit, you will incur immediate and substantial dilution of $8.02 per common unit. This dilution results primarily because the assets contributed by EQT are recorded in accordance with GAAP at their historical cost, and not their fair value. Please read "Dilution."

The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

We have been approved to list our common units on the NYSE, subject to official notice of issuance. Unlike most corporations, we are not required by NYSE rules to have, and we do not intend to have, a majority of independent directors on our general partner's board of directors or a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE's shareholder approval rules. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read "Management."

If you are not an eligible taxable holder, you will not be entitled to allocations of income or loss or distributions or voting rights on your common units and your 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. Please read "Description of the Common Units—Transfer of Common Units." If you are not a person who fits the requirements to be an eligible taxable holder, you will not receive allocations of income or loss or distributions or voting rights on your units and you run the risk of having your 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. Please see "The Partnership Agreement—Non-Citizen Assignees; Redemption."

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:

By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read "Conflicts of Interest and Duties— Duties of our General Partner."

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:

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 cash available for distribution 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, which we project to be approximately $50 million, excluding reimbursements related to the Sunrise Pipeline lease, for the twelve-month period ending June 30, 2013. Please read "Certain Relationships and Related Transactions—Omnibus Agreement." 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. Please read "Our Cash Distribution Policy and Restrictions on Distributions."

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.

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, will own sufficient units upon the closing of this offering 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. Following the closing of this offering, EQT will indirectly own 64.0% 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 your approval, which would dilute your 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:

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.

After the sale of the common units offered by this prospectus, assuming that the underwriters do not exercise their option to purchase additional common units, EQT will indirectly hold an aggregate of 4,839,718 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 you to sell your 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, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the closing of this offering, and assuming no exercise of the underwriters'

option to purchase additional common units, EQT will indirectly own approximately 27.9% 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 64.0% of our outstanding common units. For additional information about this right, please read "The Partnership Agreement—Limited Call Right."

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 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. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner's Right to Reset Incentive Distribution Levels."

Your 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. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:

For a discussion of the implications of the limitations of liability on a unitholder, please read "The Partnership Agreement—Limited Liability."

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

We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses. In addition, the Sarbanes-Oxley Act of 2002 and related rules subsequently implemented by the SEC and the NYSE have required changes in the corporate governance practices of publicly traded companies. We expect these rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly traded partnership reporting requirements and our general partner will maintain director and officer liability insurance under a separate policy from EQT's corporate director and officer insurance. We have included $3.0 million of estimated annual incremental costs associated with being a publicly traded partnership in our financial forecast included elsewhere in this prospectus. However, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

In addition to reading the following risk factors, you should read "Material Federal Income Tax Consequences" for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

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 cash available for distribution 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 Internal Revenue Service, or IRS, on this or any other tax matter affecting us.

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 cash available for distribution to you would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes there would be 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 cash available for distribution 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 will reduce the cash available for distribution to you. 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. Please read "Material Federal Income Tax Consequences—Partnership Status." 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.

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 cash available for distribution 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 or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this 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 cash available for distribution.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the common units you sell will, in effect, become taxable income to you if you sell such common units at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized on any sale or other disposition of your 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 you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss" for a further discussion of the foregoing.

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 you are a tax-exempt entity or a non-U.S. person, you 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 your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read "Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election" for a further discussion of the effect of the depreciation and amortization positions we will adopt.

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. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Allocations Between Transferors and Transferees."

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.

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. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Constructive Termination" for a discussion of the consequences of our termination for federal income tax purposes.

As a result of investing in our common units, you 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 will initially own property or conduct business in a number of states, most of which currently impose a personal income tax on individuals. Most 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 your 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.

We intend to use the estimated net proceeds of approximately $230 million from this offering (assuming an initial public offering price of $20.00 per common unit, the midpoint of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts, the structuring fee and offering expenses,

If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to such exercise will be issued to the public and the remainder of the 1,875,000 additional common units, if any, will be issued to EQT. Any such units issued to EQT will be issued for no additional consideration. If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds would be approximately $35.1 million. The net proceeds from any exercise of the underwriters' option to purchase additional common units will be distributed to EQT.

A $1.00 increase or decrease in the assumed initial public offering price of $20.00 per common unit would cause the net proceeds from this offering, after deducting the underwriting discounts, the structuring fee and offering expenses, to increase or decrease, respectively, by approximately $11.7 million. If the proceeds increase due to a higher initial public offering price or decrease due to a lower initial public offering price, then the cash distribution to EQT from the proceeds of this offering will increase or decrease, as applicable, by a corresponding amount.

This table is derived from, should be read in conjunction with and is qualified in its entirety by reference to, our historical and unaudited pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations."

Dilution is the amount by which this offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per unit after this offering. On a pro forma basis as of March 31, 2012, our net tangible book value was $423.8 million, or $11.98 per unit. Purchasers of common units in this offering will experience immediate and substantial dilution in pro forma net tangible book value per unit for financial accounting purposes, as illustrated in the following table:

(1): Determined by dividing the number of units (4,839,718 common units, 17,339,718 subordinated units and 707,744 general partner units) to be issued to subsidiaries of EQT for their contribution of assets and liabilities to EQT Midstream Partners, LP into predecessor historical capital.
(2): Determined by dividing the total number of units to be outstanding after this offering (17,339,718 common units, 17,339,718 subordinated units and 707,744 general partner units) and the application of the related net proceeds into our pro forma net tangible book value, after giving effect to the application of the net proceeds of this offering.
(3): If the initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $8.69 and $7.35, respectively.
(4): Because the total number of units outstanding following this offering will not be impacted by any exercise of the underwriters' option to purchase additional common units and any net proceeds from such exercise will not be retained by us, there will be no change to the dilution in net tangible book value per common unit to purchasers in this offering due to any such exercise of the option.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by EQT and by the purchasers of common units in this offering upon completion of the transactions contemplated by this prospectus:

You should read the following discussion of our cash distribution policy in conjunction with the factors and assumptions upon which our cash distribution policy is based, which are included under the heading "—Assumptions and Considerations" below. In addition, please read "Forward-Looking Statements" and "Risk Factors" for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business. For additional information regarding our historical and pro forma operating results, you should refer to our historical and pro forma financial statements and related notes included elsewhere in this prospectus.

Our partnership agreement requires us to distribute all of our available cash quarterly. Our cash distribution policy reflects our belief that our unitholders will be better served if we distribute rather than retain available cash, because, among other reasons, we believe we will generally finance any expansion capital expenditures from external financing sources. Generally, our available cash is the sum of our (i) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (ii) cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to our unitholders than would be the case were we subject to federal income tax.

There is no guarantee that our unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay the minimum quarterly distribution or any other distribution except as provided in our partnership agreement. Our cash distribution policy is subject to certain restrictions and may be changed at any time. The reasons for such uncertainties in our stated cash distribution policy include the following factors:

All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. We anticipate that distributions from operating surplus will generally not represent a return of capital. However, operating surplus, as defined in our partnership agreement, includes certain components, including a $30 million cash basket, that represent non-operating sources of cash. Accordingly, it is possible that return of capital distributions could be made from operating surplus. Any cash distributed by us in excess of operating surplus will be deemed to be capital surplus under our partnership agreement. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. We do not anticipate that we will make any distributions from capital surplus.

Because we will distribute all of our available cash to our unitholders, we expect that we 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. 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 following the closing of this offering. 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 and the incremental distributions on the incentive distribution rights 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 that there will be limitations in our new 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.

Upon the consummation of this offering, our partnership agreement will provide for a minimum quarterly distribution of $0.3500 per unit for each complete quarter, or $1.40 per unit on an annualized basis. Our ability to make cash distributions at the minimum quarterly distribution rate will be subject to the factors described above under "—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy." Quarterly distributions, if any, will be made within 45 days after the end of each quarter, on or about the 15th day of each February, May, August and November to holders of record on or about the first day of each such month. If the distribution date does not fall on a business day, we will make the distribution on the first business day immediately following the indicated distribution date. We will not make distributions for the period that begins on April 1, 2012, and ends on the day prior to the closing of this offering other than the distribution to be made to EQT in connection with the closing of this offering as described in "Prospectus Summary—Formation Transactions and Partnership Structure" and "Use of Proceeds." We will adjust the amount of our distribution for the period from the completion of this offering through September 30, 2012, based on the actual length of the period. The amount of available cash needed to pay the minimum quarterly distribution on all of our common units, subordinated units and general partner units to be outstanding immediately after this offering for one quarter and on an annualized basis is summarized in the table below:

As of the date of this offering, our general partner will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner's initial 2.0% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us in order to maintain its initial 2.0% general partner interest. Our general partner will also hold the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 48.0%, of the cash we distribute in excess of $0.4025 per unit per quarter.

During the subordination period, before we make any quarterly distributions to our subordinated unitholders, our common unitholders are entitled to receive payment of the full minimum quarterly distribution plus any arrearages in distributions of the minimum quarterly distribution from prior quarters. Please read "Provisions of our Partnership Agreement Relating to Cash Distributions—

Subordination Period." We cannot guarantee, however, that we will pay the minimum quarterly distribution on our common units in any quarter.

Although holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above, our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by the Delaware Act or any other law, rule or regulation or at equity. Our partnership agreement provides that, in order for a determination by our general partner to be made in "good faith," our general partner must subjectively believe that the determination is in our best interests. Please read "Conflicts of Interest and Duties."

Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement; however, the actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above.

In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our annualized minimum quarterly distribution of $1.40 per unit for the twelve-month period ending June 30, 2013. In those sections, we present two tables, consisting of:

Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2011 and the Twelve-Month Period Ended March 31, 2012

If we had completed this offering and related transactions on January 1, 2011, our unaudited pro forma cash available for distribution for the year ended December 31, 2011 would have been approximately $44.9 million. This amount would have been sufficient to pay the minimum quarterly distribution of $0.3500 per unit per quarter ($1.40 per unit on an annualized basis) on all of our common units and a cash distribution of $0.28 per unit per quarter ($1.14 per unit on an annualized basis), or approximately 81.1% of the minimum quarterly distribution, on all of our subordinated units for such period.

If we had completed this offering and related transactions on April 1, 2011, our unaudited pro forma cash available for distribution for the twelve-month period ended March 31, 2012 would have been approximately $44.8 million. This amount would have been sufficient to pay the minimum quarterly distribution of $0.3500 per unit per quarter ($1.40 per unit on an annualized basis) on all of our common units and a cash distribution of $0.28 per unit per quarter ($1.13 per unit on an annualized basis), or approximately 80.7% of the minimum quarterly distribution, on all of our subordinated units for such period.

Our unaudited pro forma available cash for the year ended December 31, 2011 and the twelve-month period ended March 31, 2012 includes $3.0 million of estimated incremental general and

administrative expenses that we expect to incur as a result of becoming a publicly traded partnership. Incremental general and administrative expenses related to being a publicly traded partnership include expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance expenses; and director compensation. These expenses are not reflected in historical financial statements of our Predecessor or our unaudited pro forma financial statements included elsewhere in the prospectus.

At the closing of this offering, we will transfer ownership of the Sunrise Pipeline, which is under construction and is expected to be placed into service in the third quarter of 2012, to EQT. We will then enter into a capital lease with EQT for the lease of the Sunrise Pipeline and we will operate the pipeline as part of our transmission and storage system under the rates, terms, and conditions of our FERC-approved tariff. As a result of the transfer of the Sunrise Pipeline to EQT in connection with the closing of this offering, the expansion capital expenditures for the construction completed during the year ended December 31, 2011 and the twelve-month period ended March 31, 2012 are excluded from our calculation of pro forma cash available for distribution for such period. Further, as a result of the way the lease of the Sunrise Pipeline is structured, we will be required to include the revenues received from, and the costs, including depreciation, incurred in, operating the Sunrise Pipeline in our results of operations. However, the lease payment we are required to make to EQT is designed to transfer any revenues in excess of our actual costs of operating the Sunrise Pipeline to EQT. As a result, the Sunrise Pipeline project and related lease are not expected to have a net positive or negative impact on our cash available for distribution. For that reason, discussions below in "—Assumptions and Considerations" regarding our estimated cash available for distribution for the period ended June 30, 2013 correspond to the amounts in the column titled "Twelve-Month Period Ending June 30, 2013 (Excluding Sunrise Pipeline)." For more information regarding this lease agreement, please read "Certain Relationships and Related Transactions—Contracts with Affiliates—Sunrise Pipeline Lease Agreement."

We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had this offering and related formation transactions been completed as of the date indicated. In addition, cash available for distribution is primarily a cash accounting concept, while the historical financial statements of our Predecessor and our unaudited pro forma financial statements included elsewhere in the prospectus have been prepared on an accrual basis. As a result, you should view the amount of pro forma cash available for distribution only as a general indication of the amount of cash available for distributions that we might have generated had we completed this offering on the dates indicated. The pro forma amounts below are presented on a twelve-month basis, and there is no guarantee that we would have had available cash sufficient to pay the full minimum quarterly distribution on all of our outstanding common units and subordinated units for each quarter within the twelve-month periods presented.

The following table illustrates, on a pro forma basis, for the year ended December 31, 2011 and the twelve-month period ended March 31, 2012, the amount of cash that would have been available for distribution to our unitholders, assuming that this offering and the related formation transactions had been completed on January 1, 2011 and April 1, 2011, respectively. Each of the adjustments reflected or presented below is explained in the footnotes to such adjustments.

	Year Ended December 31, 2011			Twelve-Month Period Ended March 31, 2012

	(In millions, except per unit data)
Pro Forma Net Income:	$	57.1		$	60.6
Add:
Depreciation and amortization		11.5			11.7
Interest expense(1)		1.3			1.3
Income tax expense		—			—
Non-cash long-term compensation expense(2)		2.2			2.4

Less:
Other income(3)		(3.8	)		(6.0	)
Sunrise Pipeline lease payment		—			—
Pro Forma Adjusted EBITDA(4)		68.3			70.0

Less:
Cash interest, net(5)		(0.9	)		(0.9	)
Expansion capital expenditures(6)		(23.5	)		(31.9	)
Ongoing maintenance capital expenditures(7)		(20.3	)		(22.1	)
Pre-funded regulatory compliance capital expenditures(8)		(0.2	)		(0.1	)
Incremental general and administrative expense of being a public company		(3.0	)		(3.0	)
Add:
Elimination of compensation expense related to cash incentive payments that would have been paid in common units(9)		0.8			0.8
Borrowings to fund expansion capital expenditures		23.5			31.9
Proceeds retained from this offering to pre-fund regulatory compliance capital expenditures		0.2			0.1

Pro Forma Cash Available for Distribution	$	44.9		$	44.8

Pro Forma Cash Distributions
Distribution per unit (based on a minimum quarterly distribution rate of $0.3500 per unit)	$	1.40			1.40
Annual distributions to:
Public common unitholders	$	17.5			17.5
EQT:
Common units(10)		6.8			6.8
Subordinated units		24.2			24.2
General partner units		1.0			1.0

Total distributions to EQT		32.0			32.0

Total Distributions	$	49.5			49.5

Excess (Shortfall)	$	(4.6	)		(4.7	)

Percent of minimum quarterly distribution payable to common unitholders		100	%		100	%

Percent of minimum quarterly distribution payable to subordinated unitholders		81.1	%		80.7	%

(2): Represents non-cash long-term compensation expense associated with EQT's long-term incentive plan. As discussed in footnote (9) below, EQT's long-term incentive plan has been settled in both cash and equity in historic periods.
(3): Consists of AFUDC equity income. AFUDC, or allowance for funds used during construction, is the amount approved by the FERC for inclusion in our tariff rates as reimbursement for the cost of financing construction projects with investor capital until a project is placed into operation.
(4): We define Adjusted EBITDA as net income (loss) plus net interest expense, income tax expense, depreciation and amortization expense and non-cash long-term compensation expense less other income and the Sunrise Pipeline lease payment. For a reconciliation to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read "Prospectus Summary—Non-GAAP Financial Measure."
(5): Cash interest, net includes commitment fees on our new revolving credit facility.
(6): Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term. Excludes approximately $85.5 million and $115.7 million related to construction of the Sunrise Pipeline for the year ended December 31, 2011 and the twelve-month period ended March 31, 2012, respectively.
(7): Maintenance capital expenditures are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long term, our operating capacity or operating income. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines, to connect new wells to maintain throughput, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations. Ongoing maintenance capital expenditures are all maintenance capital expenditures other than the specific pre-funded regulatory compliance capital expenditures discussed in footnote (8) below. The amount shown as ongoing maintenance capital expenditures for the year ended December 31, 2011 and the twelve-month period ended March 31, 2012 excludes $4.7 million and $4.6 million, respectively, in costs associated with bare steel pipe replacement and $1.6 million and $1.7 million, respectively, in costs associated with plugging and abandonment liabilities, as such amounts would have been reimbursed by EQT pursuant to the omnibus agreement. For a more complete description of the reimbursement obligations, please see "Certain Relationships and Related Transactions—Contracts with Affiliates—Omnibus Agreement."
(8): Pre-funded regulatory compliance capital expenditures are identified maintenance capital expenditures necessary to comply with regulatory and other legal requirements. We have identified two specific regulatory compliance initiatives which will require us to expend approximately $32 million, the majority of which is expected to be incurred over the next two years. We will retain approximately $32 million from the net proceeds of this offering which we anticipate will fully fund these expenditures. For a more complete description of these initiatives as well as their anticipated costs, please see "—Assumptions and Considerations—Capital Expenditures," beginning on page 75.
(9): Represents elimination of compensation expense related to cash incentive payments under EQT's long-term incentive plan, as we expect that the incentive compensation payments made under our long-term incentive plan will consist of grants of phantom and performance units rather than cash.

Estimated Cash Available for Distribution for the Twelve-Month Period Ending June 30, 2013

We forecast that our estimated cash available for distribution during the twelve-month period ending June 30, 2013 will be approximately $54.5 million. This amount would exceed by $5.0 million the amount needed to pay the minimum quarterly distribution of $0.3500 per unit on all of our units for the twelve-month period ending June 30, 2013.

We are providing the forecast of estimated cash available for distribution to supplement the historical financial statements of EQT Midstream Partners' Predecessor and our unaudited pro forma financial statements included elsewhere in the prospectus in support of our belief that we will have sufficient cash available to allow us to pay cash distributions at the minimum quarterly distribution rate on all of our units for the twelve-month period ending June 30, 2013. Please read "—Assumptions and Considerations" for further information as to the assumptions we have made for the forecast. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates" for information as to the accounting policies we have followed for the financial forecast.

Our forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve-month period ending June 30, 2013. We believe that our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results will be achieved. If our estimates are not achieved, we may not be able to pay the minimum quarterly distribution or any other distribution on our common units. The assumptions and estimates underlying the forecast are inherently uncertain and, though we consider them reasonable as of the date of this prospectus, are subject to a wide variety of significant business, economic and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the forecast, including, among others, risks and uncertainties contained in "Risk Factors." Accordingly, there can be no assurance that the forecast is indicative of our future performance or that actual results will not differ materially from those presented in the forecast. Inclusion of the forecast in this prospectus should not be regarded as a representation by any person that the results contained in the forecast will be achieved.

We have prepared the following forecast to present the estimated cash available for distribution to our common unitholders during the forecasted period. The accompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in our view, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management's knowledge and belief, the expected course of action and our expected future financial performance. However, this information is not necessarily indicative of future results.

Neither our independent registered public accounting firm, nor any other independent accountants, have compiled, examined or performed any procedures with respect to the prospective financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the prospective financial information. The independent registered public accounting firm's report included in this prospectus relates to historical financial information. It does not extend to prospective financial information and should not be read to do so.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast or the assumptions used to prepare the forecast to reflect events or circumstances after the completion of this offering. In light of this, the statement that we believe that we will have sufficient cash available for distribution to allow us to make the full minimum quarterly distribution on all of our outstanding units for the twelve-month period ending June 30, 2013, should not be regarded as a representation by us, the underwriters or any other person that we will make such distribution. Therefore, you are cautioned not to place undue reliance on this information.

The table below presents (i) our projection of operating results for the twelve-month period ending June 30, 2013, (ii) the impact of the Sunrise Pipeline project and related lease on our projected results of operations, and (iii) our adjusted forecast excluding the impact of the Sunrise Pipeline project. The assumptions discussed below correspond to the amounts in the column titled "Twelve-Month Period Ending June 30, 2013 (Excluding Sunrise Pipeline)," which we believe presents a more meaningful representation of our anticipated operating results because the Sunrise Pipeline project and related lease are not expected to have a net positive or negative impact on our cash available for distribution during the forecast period.

	Twelve-Month Period Ending June 30, 2013 (Including Sunrise Pipeline)			Adjustments to Exclude Sunrise Pipeline			Twelve-Month Period Ending June 30, 2013 (Excluding Sunrise Pipeline)

	(In millions, except per unit data)
Operating revenues:
Transmission and storage	$	135.9		$	(27.3	)	$	108.6
Gathering		15.0			—			15.0

Total operating revenues		150.9			(27.3	)		123.6

Operating expenses:
Operating and maintenance		32.3			(1.4	)		30.9
Selling, general and administrative(1)		22.0			(1.6	)		20.4
Depreciation and amortization		28.6			(14.7	)		13.9

Total operating expenses		82.9			(17.7	)		65.2

Operating income		68.0			(9.6	)		58.4
Other income(2)		1.8			(1.0	)		0.8
Interest expense, net(3)		(16.1	)		14.5			(1.6	)

Net income		53.7			3.9			57.6
Add:
Depreciation and amortization		28.6			(14.7	)		13.9
Interest expense, net(3)		16.1			(14.5	)		1.6
Non-cash long-term compensation expense(4)		0.6			—			0.6
Less:
Other income(2)		(1.8	)		1.0			(0.8	)
Sunrise Pipeline lease payment		(24.3	)		24.3			—
Adjusted EBITDA(5)		72.9			—			72.9
Less:
Cash interest, net(6)		(1.2	)		—			(1.2	)
Expansion capital expenditures(7)		(33.4	)		—			(33.4	)
Ongoing maintenance capital expenditures(8)		(17.2	)		—			(17.2	)
Pre-funded regulatory compliance capital expenditures(9)		(15.3	)		—			(15.3	)
Add:
Borrowings to fund expansion capital expenditures		33.4			—			33.4
Proceeds retained from this offering to pre-fund regulatory compliance capital expenditures		15.3			—			15.3

Minimum estimated cash available for distribution	$	54.5		$	—		$	54.5

Distribution per unit (based on a minimum quarterly distribution rate of $0.3500 per unit)	$	1.40		$	—		$	1.40
Annual distributions to:(10)
Public common unitholders	$	17.5		$	—		$	17.5
EQT:
Common units(11)		6.8			—			6.8
Subordinated units		24.2			—			24.2
General partner units		1.0			—			1.0

Total distributions to EQT		32.0			—			32.0

Total distributions to our unitholders and general partner at the minimum distribution rate	$	49.5		$	—		$	49.5

Excess of cash available for distribution over aggregate annualized minimum quarterly cash distributions	$	5.0		$	—		$	5.0

Excludes compensation expense of EQT associated with its long-term incentive program, which will not be allocated to us following the closing of this offering pursuant to the omnibus agreement.

(2): Consists of AFUDC equity income. AFUDC, or allowance for funds used during construction, is the amount approved by the FERC for inclusion in our tariff rates as reimbursement for the cost of financing construction projects with investor capital until a project is placed into operation.
(3): Interest expense, net includes commitment fees on, and the amortization of origination fees incurred in connection with, our new revolving credit facility and interest expense on funds used for expansion capital expenditures.
(4): Eliminates a non-cash charge associated with compensation that is expected to be paid in common units issued pursuant to our new long-term incentive plan. This charge is based on the long-term incentive awards that will be made at the time of this offering. Please see footnote (11) below.
(5): We define Adjusted EBITDA as net income (loss) plus net interest expense, income tax expense, depreciation and amortization expense and non-cash long-term compensation expense less other income and the Sunrise Pipeline lease payment. Adjusted EBITDA should not be considered an alternative to net income, cash flows from operating activities, or any other measure of financial performance calculated in accordance with GAAP as those items are used to measure operating performance, liquidity, and our ability to service debt obligations. Please read "Prospectus Summary—Non-GAAP Financial Measure."
(6): Cash interest, net, includes commitment fees on our new revolving credit facility and interest costs on funds used for expansion capital expenditures.
(7): Excludes all expansion capital expenditures related to the Sunrise Pipeline project as those amounts will be paid by EQT after the closing of this offering and throughout the term of the lease. Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term.
(8): Maintenance capital expenditures are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long term, our operating capacity or operating income. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines, to connect new wells to maintain throughput, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations. Ongoing maintenance capital expenditures are all maintenance capital expenditures other than the specific pre-funded regulatory compliance capital expenditures discussed in footnote (9) below. The amount shown as ongoing maintenance capital expenditures excludes approximately $6 million in costs associated with bare steel pipe replacement and approximately $6 million in costs associated with plugging and abandonment liabilities as we anticipate such amounts will be reimbursed by EQT pursuant to the omnibus agreement. For a more complete description of the reimbursement obligations, please see "Certain Relationships and Related Transactions—Contracts with Affiliates—Omnibus Agreement."
(9): Pre-funded regulatory compliance capital expenditures are identified maintenance capital expenditures necessary to comply with regulatory and other legal requirements. We have identified two specific regulatory compliance initiatives which will require us to expend approximately $32 million, the majority of which are expected to be incurred over the next two years. We will retain approximately $32 million from the net proceeds of this offering which we anticipate will fully fund these expenditures. For a more complete description of these initiatives as well as their anticipated costs, please see "—Assumptions and Considerations—Capital Expenditures."
(10): The table reflects the number of common, subordinated and general partner units that we anticipate will be outstanding immediately following the closing of this offering, and the aggregate distribution amounts payable on those units during the forecast period at our minimum quarterly distribution rate of $0.3500 per unit on an annualized basis assuming that the underwriters' option to purchase additional common units has not been exercised and the additional common units subject to the underwriters' option are issued to EQT.

We believe our estimated available cash for distribution for the twelve-month period ending June 30, 2013 will not be less than $54.5 million. This amount of estimated minimum available cash for distribution is approximately $9.6 million, or approximately 21%, more than the unaudited pro forma available cash for distribution for the year ended December 31, 2011, and approximately $9.7 million, or approximately 22%, more than the unaudited pro forma available cash for distribution for the twelve months ended March 31, 2012. Substantially all of this increase in available cash for distribution is attributable to increased revenues from (i) continuing firm capacity commitments associated with the Equitrans 2010 Marcellus expansion project, (ii) increases in usage fees from EQT associated with projected growth in production resulting from EQT's 2011 drilling and development program as well as the development program EQT has announced for 2012 and (iii) increased capacity revenues associated with the Blacksville Compressor Station Project, which is expected to be placed into service by the third

quarter of 2012. Our estimates do not assume any incremental revenue, expenses or other costs associated with potential future acquisitions.

While the assumptions disclosed in this prospectus are not all-inclusive, the assumptions listed are those that we believe are significant to our forecasted results of operations and any assumptions not discussed below were not deemed significant. We believe our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results, including without limitation, the anticipated in service dates of our growth projects, will be achieved. The assumptions discussed below correspond to the amounts in the column titled "Twelve-Month Period Ending June 30, 2013 (Excluding Sunrise Pipeline)" which we believe presents a more meaningful representation of our anticipated operating results because the Sunrise Pipeline project and related lease are not expected to have a net positive or negative impact on our cash available for distribution during the forecast period. For more information on this lease agreement, please read "Certain Relationships and Related Transactions—Contracts with Affiliates—Sunrise Pipeline Lease Agreement."

We estimate that our total revenues for the twelve-month period ending June 30, 2013 will be approximately $123.6 million, as compared to approximately $109.6 million for the pro forma year ended December 31, 2011 and approximately $114.0 million for the pro forma twelve-month period ended March 31, 2012. Approximately 60% of these revenues are derived from capacity reservation fees, which is consistent with historical periods. Our forecast is based primarily on the following assumptions:

Transmission and Storage. We estimate that approximately 88%, or approximately $108.6 million, of our total revenue will be generated from transmission and storage services for the twelve-month period ending June 30, 2013. This compares to approximately 85%, or approximately $93.7 million, of our pro forma revenues that were generated from transmission and storage revenues during the year ended December 31, 2011, and approximately 85%, or approximately $97.4 million, of our pro forma revenues that were generated from transmission and storage revenues during the twelve-month period ended March 31, 2012. Our historical transmission and storage revenue is primarily attributable to the firm capacity we have contracted to EQT under long-term contracts.

Transmission and storage revenues are expected to increase by $11.2 million during the twelve-month period ending June 30, 2013 as compared to the pro forma twelve-month period ended March 31, 2012. Transmission revenues are expected to increase by a total of $13.7 million, primarily consisting of the following:

Our transmission and storage revenue for the forecast period also assumes that during the forecast period we will recover costs incurred in 2011 to comply with the Pipeline Safety Improvement Act of 2002; however the amount of such recovery is subject to FERC approval on an annual basis and it has not yet been approved and is subject to two protests. If the amount of the surcharge is reduced, it could reduce our revenues. For additional information, please see "Business—Regulatory Environment—Pipeline Safety Tracker." Pursuant to the omnibus agreement, EQT has agreed to reimburse us for the amount by which the qualifying pipeline safety costs included in the applicable

annual pipeline safety cost tracker filings made by Equitrans with the FERC exceed the qualifying pipeline safety costs actually recovered each year. Please read "Certain Relationships and Related Transactions—Omnibus Agreement."

These expected increases in transmission revenues are partially offset by an expected decrease of $2.5 million in storage revenues primarily due to an expiring firm storage and associated firm transmission contract and an expected decrease in park and loan service volumes stored by our affiliates as a result of expected commodity market pricing spreads. During the forecast period, we anticipate that the substantial majority of the cash generated by our transmission and storage operations will be generated by our transportation assets.

In addition to the expected increases in revenue during the twelve-month period ending June 30, 2013 discussed above, we expect to receive a total of approximately $8.7 million in incremental annual revenue associated with firm transmission capacity reservation charges for the Equitrans 2010 Marcellus expansion project and the Blacksville Compressor Station project based on contracts currently in place. We expect approximately $6.8 million of this incremental annual revenue to be received in the twelve-month period ending June 30, 2014.

In addition to the incremental annual revenues discussed above that we expect beyond the forecast period from existing contracts, we expect that we will enter into additional firm capacity commitments with respect to each of the Blacksville Compressor Station project, the Low Pressure East Expansion project, Hartson Compression Upgrade project and the New Delivery Interconnect project described under "Management's Discussion and Analysis of Financial Condition and Results of Operations—Factors and Trends Impacting Our Business—Growth Associated with Acquisitions and Expansion Projects."

Gathering. We estimate that approximately 12%, or approximately $15.0 million, of our total revenue will be generated from gathering services. This compares to approximately 15%, or approximately $15.9 million, of our pro forma revenues that were generated from gathering services during the year ended December 31, 2011, and approximately 15%, or approximately $16.6 million, of our pro forma revenues that were generated from gathering services during the twelve-month period ended March 31, 2012. We expect our gathering operating revenues to decrease by approximately $1.6 million during the twelve-month period ending June 30, 2013, as compared to the pro forma twelve-month period ended March 31, 2012, due to an expected reduction in wellhead volumes due to natural production decline from wells currently connected to our system. We have not assumed any new well connections to our system.

We estimate that operating and maintenance expense for the twelve-month period ending June 30, 2013 will be $30.9 million compared to $26.2 million for the pro forma year ended December 31, 2011 and $28.4 million for the pro forma twelve-month period ended March 31, 2012. The $2.5 million increase in operating and maintenance expense, as compared to the pro forma twelve-month period ended March 31, 2012, is primarily due to higher

We estimate that selling, general and administrative expense for the twelve-month period ending June 30, 2013 will be $20.4 million, compared to $17.3 million for the pro forma year ended December 31, 2011 and $18.0 million for the pro forma twelve-month period ended March 31, 2012. The forecast period includes an estimated $3.0 million of incremental expenses of being a publicly traded partnership, which is partially offset by a reduction of approximately $2.3 million of long-term compensation expense. The remaining $1.7 million increase is primarily due to higher corporate and management services associated with operating our business on a stand alone basis and higher expected labor during the forecast period.

We estimate that depreciation and amortization expense for the twelve-month period ending June 30, 2013 will be $13.9 million compared to $11.5 million for the year ended December 31, 2011 and $11.7 million for the pro forma twelve-month period ended March 31, 2012. The $2.2 million increase, as compared to the pro forma twelve-month period ended March 31, 2012, is primarily attributable to depreciation on the new infrastructure built and to be built during 2011 and 2012.

The transmission, storage and gathering businesses can be capital intensive, requiring significant investment for the maintenance of existing assets or acquisition or development of new systems and facilities. We categorize our capital expenditures as either:

We estimate that total capital expenditures for the twelve-month period ending June 30, 2013, will be $65.9 million compared to $44.0 million for the pro forma year ended December 31, 2011 and

$54.1 million for the pro forma twelve-month period ended March 31, 2012. Our estimate is based on the following assumptions:

We estimate that interest expense will be approximately $1.6 million for the twelve-month period ending June 30, 2013. Our interest expense for the forecast period is based on the following assumptions:

Our forecast for the twelve-month period ending June 30, 2013, is based on the following significant assumptions related to regulatory, industry and economic factors:

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending September 30, 2012, we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the amount of our distribution for the period from the completion of this offering through September 30, 2012, based on the actual length of the period.

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

The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Under our partnership agreement, working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners, and with the intent of the borrower to repay such borrowings within 12 months with funds other than from additional working capital borrowings.

We intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $0.3500 per unit, or $1.40 on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration

the terms of our partnership agreement. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—New Credit Facility" for a discussion of the restrictions to be included in our new credit facility that may restrict our ability to make distributions.

Initially, our general partner will be entitled to 2.0% of all quarterly distributions from inception that we make prior to our liquidation. This general partner interest will be represented by 707,744 general partner units. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. The general partner's initial 2.0% interest in these distributions will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest.

Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 48.0%, of the cash we distribute from operating surplus (as defined below) in excess of $0.4025 per unit per quarter. The maximum distribution of 48.0% does not include any distributions that our general partner or its affiliates may receive on common, subordinated or general partner units that they own. Please read "—General Partner Interest and Incentive Distribution Rights" for additional information.

All cash distributed to unitholders will be characterized as either being paid from "operating surplus" or "capital surplus." We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by operations. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $30 million of cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures (as described below) and thus reduce operating surplus when repayments are made. However, if working capital borrowings, which increase operating surplus, are not repaid during the 12-month period following the borrowing, they will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowings are in fact repaid, they will not be treated as a further reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

We define interim capital transactions as (i) borrowings, refinancings or refundings of indebtedness (other than working capital borrowings and items purchased on open account or for a deferred purchase price in the ordinary course of business) and sales of debt securities, (ii) sales of equity securities, and (iii) sales or other dispositions of assets, other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and sales or other dispositions of assets as part of normal asset retirements or replacements.

We define operating expenditures as all of our cash expenditures, including, but not limited to, taxes, reimbursements of expenses of our general partner and its affiliates, director and employee compensation, debt service payments, payments made in the ordinary course of business under interest rate hedge contracts and commodity hedge contracts (provided that payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its settlement or termination date specified therein will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract or commodity hedge contract and amounts paid in connection with the initial purchase of a rate hedge contract or a commodity hedge contract will be amortized at the life of such rate hedge contract or commodity hedge contract), maintenance capital expenditures (as discussed in further detail below), and repayment of working capital borrowings; provided, however, that operating expenditures will not include:

Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Accordingly, except as described above, capital surplus would generally be generated by:

Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term. Examples of expansion capital expenditures include the acquisition of equipment and the construction, development or acquisition of additional pipeline, storage or gathering capacity to the extent such capital expenditures are expected to expand our operating capacity or our operating income. Expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of expansion capital expenditures in respect of the period from the date that we enter into a binding obligation to commence the construction, development, replacement, improvement or expansion of a capital asset and ending on the earlier to occur of the date that such capital improvement commences commercial service and the date that such capital improvement is abandoned or disposed of.

Maintenance capital expenditures are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long term, our operating capacity or operating income. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines, to connect new wells to maintain throughput, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.

We have identified two specific regulatory compliance initiatives which will require us to expend approximately $32 million, the majority of which are expected to be incurred over the next two years. We will retain approximately $32 million from the net proceeds of this offering, which we anticipate will fully fund these expenditures. Maintenance capital expenditures generally are included in operating expenditures and thus will reduce operating surplus; however, because these $32 million in maintenance capital expenditures will be funded from the net proceeds of this offering, they will not be included in operating expenditures or reduce operating surplus. For a more complete description of these initiatives as well as their anticipated costs, please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Requirements."

Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of facilities that are in excess of the maintenance of our existing operating capacity or operating income, but that are not expected to expand our operating capacity or operating income over the long term.

Capital expenditures that are made in part for maintenance capital purposes, investment capital purposes and/or expansion capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or expansion capital expenditure by our general partner.

Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.3500 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed "subordinated" because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

Except as described below, the subordination period will begin on the closing date of this offering and will extend until the first business day following the distribution of available cash in respect of any quarter beginning with the quarter ending June 30, 2015, that each of the following tests are met:

Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day following the distribution of available cash in respect of any quarter beginning with the quarter ending June 30, 2013, that each of the following tests are met:

In addition, if the unitholders remove our general partner other than for cause:

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

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

Distributions of Available Cash from Operating Surplus during the Subordination Period

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

Distributions of Available Cash from Operating Surplus after the Subordination Period

We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

Our partnership agreement provides that our general partner initially will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest if we issue additional units. Our general partner's 2.0% interest, and the percentage of our cash distributions to which it is entitled from such 2.0% interest, will be proportionately reduced if we issue additional units in the future (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units in this offering or upon expiration of such option, the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the incentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest. Our partnership agreement does not require that our general partner fund its capital contribution with cash. It may instead fund its capital contribution by the contribution to us of common units or other property.

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 have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.

The following discussion assumes that our general partner maintains its 2.0% general partner interest and that our general partner continues to own the incentive distribution rights.

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

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under "Marginal Percentage Interest in Distributions" are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column "Total Quarterly Distribution Per Unit Target Amount." The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2.0% general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its 2.0% general partner interest, our general partner has not transferred its incentive distribution rights and that there are no arrearages on common units.

Our general partner, as the initial holder of our incentive distribution rights, has the right under our partnership agreement, subject to certain conditions, to elect to relinquish the right to receive incentive distribution payments based on the initial target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and target distribution levels upon which the incentive distribution payments to our general partner would be set. If our general partner transfers all or a portion of our incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that our general partner holds all of the incentive distribution rights at the time that a reset election is made. Our general partner's right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the conflicts committee, at any time when there are no subordinated units outstanding, we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the four consecutive fiscal quarters immediately preceding such time and the amount of each such distribution did not exceed adjusted operating surplus for such quarter, respectively. If our general partner and its affiliates are not the holders of a majority of the incentive distribution rights at the time an election is made to reset the minimum quarterly distribution amount and the target distribution levels, then the proposed reset will be subject to the prior written concurrence of the general partner that the conditions described above have been satisfied. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently

accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units based on a predetermined formula described below that takes into account the "cash parity" value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters immediately preceding the reset event as compared to the average cash distributions per common unit during that two-quarter period. In addition, our general partner will be issued the number of general partner units necessary to maintain our general partner's interest in us immediately prior to the reset election.

The number of common units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (x) the average aggregate amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (y) the average of the aggregate amount of cash distributed per common unit during each of these two quarters.

Following a reset election, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (which amount we refer to as the "reset minimum quarterly distribution") and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner at various cash distribution levels (i) pursuant to the cash distribution provisions of our partnership agreement in effect at the completion of this offering, as well as (ii) following a hypothetical reset of the minimum quarterly distribution and target distribution

levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $0.60.

			Marginal Percentage Interest in Distribution

			Marginal Percentage Interest in Distribution						Quarterly Distribution per Unit following Hypothetical Reset
	Quarterly Distribution per Unit Prior to Reset		Unitholders			General Partner
Minimum Quarterly Distribution	$	0.3500		98.0	%		2.0	%	$	0.6000
First Target Distribution	above $	0.3500		98.0	%		2.0	%	above $	0.6000
	up to $	0.4025							up to $	0.6900	(1)
Second Target Distribution	above $	0.4025		85.0	%		15.0	%	above $	0.6900
	up to $	0.4375							up to $	0.7500	(2)
Third Target Distribution	above $	0.4375		75.0	%		25.0	%	above $	0.7500
	up to $	0.5250							up to $	0.9000	(3)
Thereafter	above $	0.5250		50.0	%		50.0	%	above $	0.9000

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights, or IDRs, based on an average of the amounts distributed for the two quarters immediately prior to the reset. The table assumes that immediately prior to the reset there would be 34,679,436 common units outstanding, our general partner's 2.0% interest has been maintained, and the average distribution to each common unit would be $0.60 per quarter for the two consecutive non-overlapping quarters prior to the reset.

	Prior to Reset

					General Partner Cash Distributions
	Quarterly Distribution per Unit		Common Unitholders Cash Distribution		Common Units		2.0% General Partner Interest		IDRs		Total		Total Distribution
Minimum Quarterly Distribution	$	0.3500	$	12,137,803		—	$	247,710		—	$	247,710	$	12,385,513
First Target Distribution	above $	0.3500	$	1,820,670		—	$	37,157		—	$	37,157	$	1,857,827
	up to $	0.4025
Second Target Distribution	above $	0.4025	$	1,213,780		—	$	28,560	$	185,637	$	214,197	$	1,427,977
	up to $	0.4375
Third Target Distribution	above $	0.4375	$	3,034,451		—	$	80,919	$	930,565	$	1,011,484	$	4,045,935
	up to $	0.5250
Thereafter	above $	0.5250	$	2,600,958		—	$	104,038	$	2,496,919	$	2,600,957	$	5,201,915

			$	20,807,662		—	$	498,384	$	3,613,121	$	4,111,505	$	24,919,167

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the general partner, including in respect of IDRs, with respect to the quarter after the reset occurs. The table reflects that as a result of the reset there would be 40,701,305 common units outstanding, our general partner has maintained its 2.0% general partner interest, and that the average distribution to each common unit would be $0.60. The number of common units issued as a result of the reset was calculated by dividing (x) $3,613,121 as the average of the amounts received by the general partner in respect of its IDRs for the two consecutive non-overlapping quarters prior to the reset as shown in the table above, by (y) the average of the cash

distributions made on each common unit per quarter for the two consecutive non-overlapping quarters prior to the reset as shown in the table above, or $0.60.

	After Reset

					General Partner Cash Distributions
	Quarterly Distribution per Unit		Common Unitholders Cash Distribution		Common Units Issued As a Result of the Reset		2.0% General Partner Interest		IDRs		Total		Total Distributions
Minimum Quarterly Distribution	$	0.6000	$	20,807,662	$	3,613,121	$	498,384		—	$	4,111,505	$	24,919,167
First Target Distribution	above $	0.6000		—		—		—		—		—		—
	up to $	0.6900
Second Target Distribution	above $	0.6900		—		—		—		—		—		—
	up to $	0.7500
Third Target Distribution	above $	0.7500		—		—		—		—		—		—
	up to $	0.9000
Thereafter	above $	0.9000		—		—		—		—		—		—

			$	20,807,662	$	3,613,121	$	498,384		—	$	4,111,505	$	24,919,167

Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the immediately preceding four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

We will make distributions of available cash from capital surplus, if any, in the following manner:

The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the "unrecovered initial unit price." Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 50.0% being paid to the unitholders, pro rata, and 2.0% to our general partner and 48% to the holder of our incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50.0% of its initial level, and each subordinated unit would be split into two subordinated units. We will not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if the official interpretation of existing law is modified by a governmental authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter may be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) and the denominator of which is the sum of available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) plus our general partner's estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference may be accounted for in subsequent quarters.

If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and our general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of

common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.

The manner of the adjustment for gain is set forth in our partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to our partners in the following manner:

The percentages set forth above are based on the assumption that our general partner has not transferred its incentive distribution rights and that we do not issue additional classes of equity securities.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the fourth bullet point above will no longer be applicable.

If our liquidation occurs before the end of the subordination period, after making allocations of loss to the general partner and the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, we will generally allocate any loss to our general partner and unitholders in the following manner:

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the partners' capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made. In contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and our general partner based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. If we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders' capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

The following table shows summary historical financial and operating data of our Predecessor, and selected pro forma financial data of EQT Midstream Partners, LP as of the dates and for the periods indicated. The selected historical financial data presented as of December 31, 2007 are derived from our unaudited historical financial statements, which are not included in this prospectus. The selected historical financial data presented as of December 31, 2008 and for the year ended December 31, 2008 are derived from our audited historical financial statements which are not included in this prospectus. The selected historical financial data presented as of December 31, 2009, 2010 and 2011 and for the years ended December 31, 2009, 2010 and 2011 are derived from the historical audited financial statements that are included elsewhere in this prospectus. The selected historical financial data of our Predecessor presented as of March 31, 2012 and for the three-month periods ended March 31, 2011 and 2012 are derived from the unaudited historical financial statements that are included elsewhere in this prospectus. The following table should be read together with, and is qualified in its entirety by reference to, the historical and unaudited pro forma financial statements and the accompanying notes included elsewhere in this prospectus. The table should also be read together with "Management's Discussion and Analysis of Financial Condition and Results of Operations."

The selected pro forma financial data presented for the year ended December 31, 2011 and the three-month period ended March 31, 2012 are derived from the unaudited pro forma financial statements of Equitrans, L.P. included elsewhere in this prospectus. Our unaudited pro forma financial statements give pro forma effect to:

																						Pro Forma

																Three-Month Period Ended March 31,						Pro Forma
																									Three-Month Period Ended March 31, 2012
	Year Ended December 31,																					Year Ended December 31, 2011
	2007			2008			2009			2010			2011			2011			2012			Year Ended December 31, 2011
	(unaudited)															(unaudited)						(unaudited)
	(In thousands, except per unit and operating data)
Statement of Operations Data:
Total operating revenues	$	68,820		$	71,862		$	80,057		$	91,600		$	109,613		$	26,626		$	31,003		$	109,613		$	31,003
Operating expenses:
Operating and maintenance		16,210			21,905			18,433			24,300			26,221			4,887			7,024			26,221			7,024
Selling, general and administrative⁽¹⁾		19,755			21,316			23,268			18,477			17,302			3,802			4,549			17,302			4,549
Depreciation and amortization		8,487			8,410			9,652			10,886			11,470			2,841			3,038			11,470			3,038

Total operating expenses		44,452			51,631			51,353			53,663			54,993			11,530			14,611			54,993			14,611

Operating income		24,368			20,231			28,704			37,937			54,620			15,096			16,392			54,620			16,392
Other income, net		785			1,414			1,115			498			3,826			346			2,471			3,826			2,471
Interest expense, net⁽²⁾		(5,587	)		(5,489	)		(5,187	)		(5,164	)		(5,050	)		(1,294	)		(1,539	)		(1,305	)		(326	)
Income taxes⁽³⁾		(5,104	)		(7,809	)		(10,601	)		(14,030	)		(20,807	)		(5,513	)		(6,201	)		—			—

Net income	$	14,462		$	8,347		$	14,031		$	19,241		$	32,589			8,635			11,123		$	57,141		$	18,537

Net income per limited partners' unit
Common units																						$	1.61			0.52
Subordinated units																							1.61			0.52
Balance Sheet Data (at period end):
Total assets	$	307,106		$	349,352		$	386,682		$	415,001		$	546,442					$	597,906					$	588,545
Property, plant and equipment, net		246,508			297,071			320,769			337,218			470,892						521,966						521,966
Long-term debt—affiliate		57,107			57,107			57,107			135,235			135,235						135,235						—
Total partners' capital		80,737			91,585			102,656			125,523			173,633						184,756						423,796
Cash Flow Data:
Net cash provided by (used in)
Operating activities	$	57,234		$	23,234		$	48,193		$	28,716		$	47,564		$	13,478		$	11,606
Investing activities		(45,994	)		(35,951	)		(32,143	)		(36,404	)		(135,831	)		(10,992	)		(51,240	)
Financing activities		(57,953	)		12,717			3,228			2,751			73,926			(2,420	)		39,634
Other Financial Data: (unaudited)
Adjusted EBITDA⁽⁴⁾				$	28,997		$	39,400		$	50,115		$	68,339		$	18,393		$	20,071		$	68,339		$	20,071
Operating Data: (unaudited)
Transmission pipeline throughput (BBtu/d)		152			159			150			204			397			319			462			397			462
Gathered volumes (BBtu/d)		67			73			71			83			78			64			75			78			75
Capital expenditures
Expansion capital expenditures⁽⁵⁾				$	14,035		$	18,989		$	22,777		$	108,981		$	8,541		$	47,134
Maintenance capital expenditures⁽⁶⁾
Ongoing maintenance⁽⁷⁾					21,916			13,093			13,339			26,636			2,351			4,106
Regulatory compliance⁽⁸⁾					—			61			288			214			100			—

Total maintenance capital expenditures					21,916			13,154			13,627			26,850			2,451			4,106

(3): Our historical financial statements include U.S. federal and state income tax expense incurred by us. Due to our status as a partnership, we will not be subject to U.S. federal income tax and certain state income taxes in the future.
(4): For a discussion of the non-GAAP financial measure Adjusted EBITDA, please read "—Non-GAAP Financial Measure" below.
(5): Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term.
(6): Maintenance capital expenditures are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long term, our operating capacity or operating income. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines, to connect new wells to maintain throughput, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.
(7): Ongoing maintenance capital expenditures are all maintenance capital expenditures other than the specific regulatory compliance capital expenditures discussed in footnote (8) below.
(8): Regulatory compliance capital expenditures are identified maintenance capital expenditures necessary to comply with regulatory and other legal requirements. We have identified two specific regulatory compliance initiatives which will require us to expend approximately $32 million, the majority of which is expected to be incurred over the two years. We will retain approximately $32 million from the net proceeds of this offering, which we anticipate will fully fund these expenditures. For a more complete description of these initiatives as well as their anticipated costs, please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Factors and Trends Impacting Our Business—Regulatory Compliance Capital Expenditures."


Large accelerated filer o		Accelerated filer o		Non-accelerated filer ý (Do not check if a smaller reporting company)		Smaller reporting company o

	Per Common Unit	Total

Public Offering Price	$	$
Underwriting Discount(1)	$	$
Proceeds to EQT Midstream Partners, LP (Before Expenses)	$	$


Citigroup		Barclays
BofA Merrill Lynch	Credit Suisse	J.P. Morgan	Wells Fargo Securities



MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		97
Overview		97
Our Operations		98
How We Evaluate Our Operations		99
Factors and Trends Impacting Our Business		102
Results of Operations		106
Liquidity and Capital Resources		110
Capital Requirements		114
Off-Balance Sheet Arrangements		117
Quantitative and Qualitative Disclosures About Market Risk		117
Recent Accounting Pronouncements		118
Critical Accounting Policies and Estimates		118
INDUSTRY OVERVIEW		121
General		121
Midstream Services		121
Transportation and Storage Services Contractual Arrangements		123
Market Fundamentals		123
Overview of the Marcellus Shale Region		128
BUSINESS		131
Overview		131
Business Strategies		132
Competitive Strengths		133
Our Relationship with EQT		135
Our Assets		138
Regulatory Environment		144
Environmental Matters		149
Seasonality		153
Title to Properties and Rights-of-Way		153
Insurance		154
Facilities		154
Employees		154
Legal Proceedings		154
MANAGEMENT		156
Management of EQT Midstream Partners, LP		156
Directors and Executive Officers of Our General Partner		157
Board Leadership Structure		159
Board Role in Risk Oversight		159
Committees of the Board of Directors		160
Executive Compensation		161
Compensation of Directors		161
Long-Term Incentive Plan		161
Reimbursement of Expenses of Our General Partner		165
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		166
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS		168
Distributions and Payments to Our General Partner and Its Affiliates		168
Agreements Governing the Transactions		168
Omnibus Agreement		169
Operation and Management Services Agreement		171
Contracts with Affiliates		172
Review, Approval or Ratification of Transactions with Related Persons		174



CONFLICTS OF INTEREST AND DUTIES		175
Conflicts of Interest		175
Duties of the General Partner		181
DESCRIPTION OF THE COMMON UNITS		183
The Units		183
Transfer Agent and Registrar		183
Transfer of Common Units		183
THE PARTNERSHIP AGREEMENT		185
Organization and Duration		185
Purpose		185
Capital Contributions		185
Voting Rights		185
Limited Liability		187
Issuance of Additional Partnership Interests		188
Amendment of the Partnership Agreement		188
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets		190
Termination and Dissolution		191
Liquidation and Distribution of Proceeds		191
Withdrawal or Removal of the General Partner		192
Transfer of General Partner Units		193
Transfer of Ownership Interests in the General Partner		193
Transfer of Incentive Distribution Rights		193
Change of Management Provisions		193
Limited Call Right		194
Redemption of Ineligible Holders		194
Meetings; Voting		195
Status as Limited Partner		196
Indemnification		196
Reimbursement of Expenses		196
Books and Reports		196
Right to Inspect Our Books and Records		197
Registration Rights		197
UNITS ELIGIBLE FOR FUTURE SALE		198
Rule 144		198
Our Partnership Agreement and Registration Rights		198
Lock-Up Agreements		199
Registration Statement on Form S-8		199
MATERIAL FEDERAL INCOME TAX CONSEQUENCES		200
Partnership Status		200
Limited Partner Status		202
Tax Consequences of Unit Ownership		202
Tax Treatment of Operations		208
Disposition of Common Units		209
Uniformity of Units		212
Tax-Exempt Organizations and Other Investors		212
Administrative Matters		213
State, Local, Foreign and Other Tax Considerations		216
INVESTMENT IN EQT MIDSTREAM PARTNERS, LP BY EMPLOYEE BENEFIT PLANS		218
UNDERWRITING		219


Delaware (State or other Jurisdiction of Incorporation or Organization)		4922 (Primary Standard Industrial Classification Code Number)		37-1661577 (IRS Employer Identification Number)


Copies to:
Joshua Davidson Laura Lanza Tyson Baker Botts L.L.P. One Shell Plaza 910 Louisiana Street Houston, Texas 77002-4995 (713) 229-1234		David P. Oelman Matthew R. Pacey Vinson & Elkins L.L.P. First City Tower 1001 Fannin, Suite 2500 Houston, Texas 77002-6760 (713) 758-2222


Deutsche Bank Securities
Goldman, Sachs & Co.
		RBC Capital Markets



PROSPECTUS SUMMARY		1
EQT Midstream Partners, LP		1
Overview		1
Business Strategies		3
Competitive Strengths		4
Our Relationship with EQT		5
Risk Factors		6
Management of EQT Midstream Partners, LP		8
Formation Transactions and Partnership Structure		9
Ownership of EQT Midstream Partners, LP		10
Principal Executive Offices and Internet Address		11
Summary of Conflicts of Interest and Duties		11
The Offering		12
Summary Historical and Pro Forma Financial and Operating Data		18
Non-GAAP Financial Measure		20
RISK FACTORS		22
Risks Related to our Business		22
Risks Inherent in an Investment in Us		44
Tax Risks to Common Unitholders		53
USE OF PROCEEDS		59
CAPITALIZATION		60
DILUTION		61
OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS		63
General		63
Our Minimum Quarterly Distribution		65
Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2011 and the Twelve-Month Period Ended March 31, 2012		66
Estimated Cash Available for Distribution for the Twelve-Month Period Ending June 30, 2013		69
Assumptions and Considerations		72
PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS		79
Distributions of Available Cash		79
Operating Surplus and Capital Surplus		80
Capital Expenditures		82
Subordination Period		83
Distributions of Available Cash from Operating Surplus during the Subordination Period		85
Distributions of Available Cash from Operating Surplus after the Subordination Period		85
General Partner Interest and Incentive Distribution Rights		86
Percentage Allocations of Available Cash From Operating Surplus		87
General Partner's Right to Reset Incentive Distribution Levels		87
Distributions from Capital Surplus		90
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels		91
Distributions of Cash Upon Liquidation		91
SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA		94



VALIDITY OF THE COMMON UNITS		225
EXPERTS		225
WHERE YOU CAN FIND MORE INFORMATION		225
FORWARD-LOOKING STATEMENTS		227
INDEX TO FINANCIAL STATEMENTS		F-1
APPENDIX A—FORM OF AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF EQT MIDSTREAM PARTNERS, LP		A-1
APPENDIX B—GLOSSARY OF TERMS		B-1

	As of March 31, 2012

	Predecessor Historical		Partnership Pro Forma(1)
	(In thousands)
Cash and cash equivalents	$	—	$	45,800

Intercompany notes payable	$	135,235	$	—	(2)
Partners' capital:
Predecessor partners' capital	$	184,756	$	—
Common units—public(3)				229,750
Common units—EQT(3)				41,033
Subordinated units—EQT				147,013
General partner units—EQT				6,000

Total partners' capital		184,756		423,796

Total capitalization	$	319,991	$	423,796


Assumed initial public offering price per common unit			$	20.00
Pro forma net tangible book value per unit before this offering(1)	$	8.07
Increase in pro forma net tangible book value per unit attributable to purchasers in this offering		3.91

Less: Pro forma net tangible book value per unit after this offering(2)				11.98

Immediate dilution in pro forma net tangible book value per unit attributable to purchasers in this offering(3)(4)			$	8.02

	Units Acquired					Total Consideration ($ in thousands)

	Number		Percent			Amount		Percent
Units owned by EQT and its affiliates(1)(2)(3)		22,887,180		64.7	%	$	196,446		44.0	%
Public Common Units		12,500,000		35.3	%	$	250,000		56.0	%

Total		35,387,180		100.0	%	$	446,446		100.0	%

	(In thousands)

Book value of net assets contributed	$	378,496
Less: Distribution to EQT from net proceeds of this offering		(182,050	)

Total consideration	$	196,446

			Minimum Quarterly Distributions

			(in millions)
	Number of Units		One Quarter		Annualized
Publicly held common units		12,500,000	$	4.4	$	17.5
Common Units held by EQT and its affiliates⁽¹⁾		4,839,718	$	1.7	$	6.8
Subordinated Units held by EQT		17,339,718	$	6.1	$	24.2
General Partner Units		707,744	$	0.2	$	1.0

Total		35,387,180	$	12.4	$	49.5

			Marginal Percentage Interest in Distributions

	Total Quarterly Distribution per Unit Target Amount		Unitholders			General Partner
Minimum Quarterly Distribution	$	0.3500		98.0	%		2.0	%
First Target Distribution	above $	0.3500		98.0	%		2.0	%
	up to $	0.4025
Second Target Distribution	above $	0.4025		85.0	%		15.0	%
	up to $	0.4375
Third Target Distribution	above $	0.4375		75.0	%		25.0	%
	up to $	0.5250
Thereafter	above $	0.5250		50.0	%		50.0	%

									Three-Month Period Ended March 31,				Pro Forma

	Year Ended December 31,														Three-Month Period Ended March 31, 2012
	Year Ended December 31,												Year Ended December 31, 2011
	2008		2009		2010		2011		2011		2012		Year Ended December 31, 2011
									(unaudited)				(unaudited)
	(in thousands)
Reconciliation of Adjusted EBITDA to Net Income
Net income	$	8,347	$	14,031	$	19,241	$	32,589	$	8,635	$	11,123	$	57,141	$	18,537
Add:
Interest expense, net		5,489		5,187		5,164		5,050		1,294		1,539		1,305		326