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As filed with the Securities and Exchange Commission on February 13, 2012

Registration No. 333-                  

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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):

CALCULATION OF REGISTRATION FEE

(1)

Includes common units issuable upon exercise of the underwriters' option to purchase additional common units.

(2)

Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

          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.

   

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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

SUBJECT TO COMPLETION, DATED FEBRUARY 13, 2012

PRELIMINARY PROSPECTUS

             Common Units

Representing Limited Partner Interests

EQT Midstream Partners, LP

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          This is the initial public offering of our common units representing limited partner interests. We are offering                common units in this offering. We currently expect that the initial public offering price will be between $        and $        per common unit. Prior to this offering, there has been no public market for our common units. We intend to apply to list our common units on the New York Stock Exchange 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 holder. Eligible 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.

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          Investing in our common units involves risks. Please read "Risk Factors" beginning on page 21.

          These risks include the following:

•

We are dependent on EQT Corporation and its affiliates 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, 2010 or the twelve month period ended September 30, 2011.



•

Our natural gas transmission, storage and gathering services are subject to extensive regulation by federal, state and local regulatory authorities; 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 general partner and its affiliates, including EQT, have conflicts of interest with us and limited fiduciary 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 $        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.



•

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.

          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.

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          To the extent that the underwriters sell more than                common units in this offering, the underwriters have the option to purchase up to an additional                 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.

                        , 2012

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        You should rely only on the information contained in this prospectus. 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.

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RISK FACTORS

        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.

Risks Related to 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.

        Historically, we have provided a substantial percentage of our natural gas transmission, storage and gathering services to EQT. During the nine months ended September 30, 2011, approximately 79% of our revenues were from EQT. We expect to derive a substantial majority of our revenues from EQT for the foreseeable future. Therefore, any event, whether in our area of operations or otherwise, that adversely affects EQT's production, financial condition, leverage, results of operations or cash flows may adversely affect our ability to sustain or increase cash distributions to our unitholders. Accordingly, we are indirectly subject to the business risks of EQT, including the following:

•

natural gas price volatility may have an adverse effect on its drilling operations, revenue, profitability, future rate of growth and liquidity;



•

infrastructure capacity constraints and interruptions;



•

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



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



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its ability to identify production opportunities based on market conditions;



•

uncertainties inherent in projecting future rates of production;



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



•

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



•

the loss of key personnel.

        Unless we are successful in attracting significant unaffiliated third-party customers, our ability to maintain or increase the capacity subscribed and volumes transported under service arrangements on our transmission and storage system as well as the volumes gathered on our gathering system will be dependent on receiving consistent or increasing commitments from EQT. While EQT has dedicated volumes to our systems, it may determine in the future that drilling in areas outside of our current areas of operations are 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, provided notice of termination of a storage agreement for 3.6 Bcf of storage capacity and the associated firm transmission agreement that is set to expire on March 31, 2012. This decision was likely due to lower natural gas price spreads and increased supply of natural

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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 $            per unit, or $            per unit on an annualized basis, we will require available cash of approximately $             million per quarter, or $             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:

•

the rates we charge for our transmission, storage and gathering services;



•

the level of firm transmission and storage capacity sold and volumes of natural gas we transport, store and gather for our customers;



•

regional, domestic and foreign supply and perceptions of supply of natural gas; the level of demand and perceptions of demand in our end-use markets; and actual and anticipated future prices of natural gas and other commodities (and the volatility thereof), which may impact our ability to renew and replace firm transmission and storage agreements;



•

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



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



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the creditworthiness of our customers;



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the level of our operating, maintenance and general and administrative costs;



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regulatory action affecting the supply of, or demand for, natural gas, the rates we can charge on our assets, how we contract for services, our existing contracts, our operating costs or our operating flexibility; and



•

prevailing economic conditions.

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

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the level and timing of capital expenditures we make;



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the level of our operating and general and administrative expenses, including reimbursements to our general partner and its affiliates, including EQT, for services provided to us;



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the cost of acquisitions, if any;



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our debt service requirements and other liabilities;



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fluctuations in our working capital needs;



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our ability to borrow funds and access capital markets;



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restrictions on distributions contained in our debt agreements;

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the amount of cash reserves established by our general partner; and



•

other business risks affecting our cash levels.

        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, 2010 or the twelve month period ended September 30, 2011.

        The amount of pro forma available cash generated during the year ended December 31, 2010 and the twelve month period ended September 30, 2011 would have been sufficient to allow us to pay the full minimum quarterly distribution on all of our common units, but only approximately        % and        %, respectively, of the minimum quarterly distribution on all of our subordinated units for such periods. 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, 2010 and the twelve month period ended September 30, 2011, 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 months ending March 31, 2013. We estimate that our total cash available for distribution for the twelve months ending March 31, 2013 will be approximately $53.5 million, as compared to approximately $42.8 million for the twelve months ended September 30, 2011 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. 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

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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:

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



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certification and construction of new interstate transmission and storage facilities;



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abandonment of interstate transmission and storage services and facilities;



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maintenance of accounts and records;



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relationships between pipelines and certain affiliates;



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terms and conditions of services and service contracts with customers;



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depreciation and amortization policies;



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acquisition and disposition of interstate transmission and storage facilities; and



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initiation and discontinuation of interstate transmission and storage services.

        Interstate pipelines may not charge rates or impose terms and conditions of service that, upon review by the FERC, are found to be unjust and unreasonable or unduly discriminatory. The maximum recourse rate that may be charged by our interstate pipeline for its transmission and storage services is established through the FERC's ratemaking process. The maximum applicable recourse rate and terms and conditions for service are set forth in our FERC-approved tariff.

        Pursuant to the NGA, existing interstate transportation and storage rates and terms and conditions of service may be challenged by complaint and are subject to prospective change by the FERC. Additionally, rate increases and changes to terms and conditions of service proposed by a regulated interstate pipeline may be protested and such increases or changes can be delayed and may ultimately be rejected by the FERC. We currently hold authority from the FERC to charge and collect (i) "recourse rates" (i.e., the maximum rates an interstate pipeline may charge for its services under its tariff) and (ii) "negotiated rates" which generally involve rates above the "recourse rates," provided that the affected customers are willing to agree to such rates and that the FERC has approved the negotiated rate agreement. As of December 31, 2011, approximately 44% 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.

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        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, Equitrans 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.

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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. For example, the five-year NYMEX natural gas futures price ranged from a high of $11.51 per MMbtu in July 2008 to a low of $3.74 per MMbtu in January 2012. As of January 31, 2012, the near month NYMEX natural gas futures price was $2.68 per MMbtu. 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.

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        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 on 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 nine months ended September 30, 2011, EQT accounted for approximately 83% of our transmission revenues, 77% of our storage revenues, 63% of our gathering revenues and 79% 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

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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 Fiduciary 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.

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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 Transmission, 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 December 31, 2011, approximately 44% 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. 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 December 31, 2011, the weighted average remaining contract life based on total revenues for our firm transmission and storage contracts was approximately 10 years. The extension or replacement of existing contracts, including our contracts with EQT, depends on a number of factors beyond our control, including:

•

the level of existing and new competition to provide services to our markets;



•

the macroeconomic factors affecting natural gas economics for our current and potential customers;

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•

the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;



•

the extent to which the customers in our markets are willing to contract on a long-term basis; and



•

the effects of federal, state or local regulations on the contracting practices of our customers.

        Any failure to extend or replace a significant portion of our existing contracts, or extending or replacing them at unfavorable or lower rates, could have a material adverse effect on our business, 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.

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        Any acquisition involves potential risks, including, among other things:

•

mistaken assumptions about volumes, revenue and costs, including synergies and potential growth;



•

an inability to secure adequate customer commitments to use the acquired systems or facilities;



•

an inability to integrate successfully the assets or businesses we acquire;



•

the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;



•

the diversion of management's and employees' attention from other business concerns; and



•

unforeseen difficulties operating in new geographic areas or business lines.

        If any acquisition eventually proves not to be accretive to our distributable cash flow per unit, it could have a material adverse effect on our business, 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 have filed an application with the FERC to transfer ownership of the Sunrise Pipeline project to a wholly-owned subsidiary of EQT. 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 following authorization from the FERC, 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. Such transfer must be approved by the FERC and potentially other regulatory agencies. For a description of this

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lease agreement, please read "Certain Relationships and Related Transactions—Agreements 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 to the approvals requested from the FERC, there may be other 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.

We are subject to numerous hazards and operational risks.

        Our business operations are subject to all of the inherent hazards and risks normally incidental to the gathering, compressing, transportation and storage of natural gas. These operating risks include, but are not limited to:

•

damage to pipelines, facilities, equipment and surrounding properties caused by hurricanes, earthquakes, tornadoes, floods, fires and other natural disasters and acts of terrorism;



•

inadvertent damage from construction, vehicles, farm and utility equipment;



•

uncontrolled releases of natural gas and other hydrocarbons;



•

leaks, migrations or losses of natural gas as a result of the malfunction of equipment or facilities and, with respect to storage assets, as a result of undefined boundaries, geologic anomalies, natural pressure migration and wellbore migration;



•

ruptures, fires and explosions; and



•

other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

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        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. 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 for full limits. Pollution liability coverage 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 maintains coverage for physical damage to assets and resulting business interruption, including damage caused by terrorist acts committed by a U.S. person or interest. Also, 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. 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.

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

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

•

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

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•

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



•

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



•

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



•

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



•

the Endangered Species Act, or ESA; and



•

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

        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.

        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

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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:

•

perform ongoing assessments of pipeline integrity;



•

identify and characterize applicable threats to pipeline segments that could impact a high consequence area;



•

maintain processes for data collection, integration and analysis;



•

repair and remediate pipelines as necessary; and



•

implement preventive and mitigating actions.

        Moreover, changes to pipeline safety laws and regulations that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream

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operators. Only recently, 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 $64 million of the net proceeds from this offering in order to pre-fund certain identified regulatory compliance capital expenditures expected to be incurred over the next five years; however the actual cost of such expenditures may exceed $64 million. Furthermore, we are not restricted from using this approximately $64 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 potential adoption of legislation relating to hydraulic fracturing and the potential enactment of proposed 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, 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.

        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 has recently asserted federal regulatory authority over hydraulic fracturing involving diesel under the federal Safe Drinking Water Act and is developing guidance documents related to this newly asserted regulatory authority. 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. At the state level, 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. In addition, some municipalities in Pennsylvania have adopted or are considering adopting stringent zoning and siting requirements for drilling. Further, in 2011 West Virginia adopted legislation that establishes additional regulatory requirements relating to horizontal drilling and hydraulic fracturing. These initiatives could

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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 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. Although West Virginia currently has a severance tax on oil and gas production, Pennsylvania currently does not. However, the Pennsylvania General Assembly has passed legislation that has been sent to the Governor and is expected to be signed into law that would impose an annual impact fee that ranges between $190,000 and $355,000 per well on unconventional gas wells. If Pennsylvania or its counties or municipalities adopt additional severance taxes or impact fees, growth in drilling and production in Pennsylvania could be reduced, which would adversely impact our results of operations.

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

        A certain amount of natural gas is naturally lost in connection with its transportation across a pipeline system, and under our contractual arrangements with our customers we are entitled to retain a specified volume of natural gas in order to compensate us for such lost and unaccounted for volumes as well as the natural gas used to run our compressor stations, which we refer to as fuel usage. The level of fuel usage and lost and unaccounted for volumes on our transmission and storage system and our gathering system may exceed the natural gas volumes retained from our customers as compensation for our fuel usage and lost and unaccounted for volumes pursuant to our contractual agreements and it will be necessary to purchase natural gas in the market to make up for the difference, which exposes us to commodity price risk. For the years ended December 31, 2008, 2009 and 2010, our actual level of fuel usage and lost and unaccounted for volumes exceeded the amounts recovered from our gathering customers by approximately 400 BBtu, 300 BBtu and 1,500 BBtu, respectively and for which we recognized $2.7 million, $2.0 million and $5.7 million of purchased gas cost as a component of operating and maintenance expense in 2008, 2009 and 2010, respectively. Future exposure to the volatility of natural gas prices as a result of gas imbalances could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

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

        Although we intend to enter into fixed-fee contracts with new customers in the future, our efforts to obtain such contractual terms may not be successful. In addition, we may acquire or develop additional midstream assets in the future that do not provide services primarily based on capacity reservation charges or other fixed fee arrangements and therefore have a greater exposure to fluctuations in commodity price risk than our current operations. Future exposure to the volatility of natural gas prices as a result of our future contracts could have a material adverse effect on our business, financial condition, results of operations 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.

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Any significant and prolonged change in or stabilization of natural gas prices could have a negative impact on our natural gas storage business.

        Historically, natural gas prices have been seasonal and volatile, which has enhanced demand for our storage services. The natural gas storage business has benefited from significant price fluctuations resulting from seasonal price sensitivity, which impacts the level of demand for our services and the rates we are able to charge for such services. On a system-wide basis, natural gas is typically injected into storage between April and October when natural gas prices are generally lower and withdrawn during the winter months of November through March when natural gas prices are typically higher. However, the market for natural gas may not continue to experience volatility and seasonal price sensitivity in the future at the levels previously seen. If volatility and seasonality in the natural gas industry decrease, because of increased production capacity or otherwise, the demand for our storage services and the prices that we will be able to charge for those services may decline. 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 nine months ended September 30, 2011 as compared to the same period in 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. 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.

        We expect to enter into a new credit facility in connection with the closing of this offering. Our new credit facility is likely to limit our ability to, among other things:

•

incur or guarantee additional debt;



•

make distributions on or redeem or repurchase units;



•

make certain investments and acquisitions;



•

incur certain liens or permit them to exist;



•

enter into certain types of transactions with affiliates;



•

merge or consolidate with another company; and



•

transfer, sell or otherwise dispose of assets.

        Our new credit facility also will likely 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.

        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 a default or an event of default that could enable our lenders to declare the 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

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outstanding principal amount in excess of $             million. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."

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 obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;



•

our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;



•

we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and



•

our flexibility in responding to changing business and economic conditions may be limited.

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

The credit and risk profile of our general partner and 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

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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 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

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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.

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.

Risks Inherent in an Investment in Us

Our general partner and its affiliates, including EQT, have conflicts of interest with us and limited fiduciary 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, some of whom will also be officers and/or directors of EQT. Although our general partner has a fiduciary duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to EQT. Conflicts of interest will arise between EQT and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of EQT over our interests and the interests of our unitholders. These conflicts include the following situations, among others:

•

Neither our partnership agreement nor any other agreement requires EQT to pursue a business strategy that favors us, and the directors and officers of EQT have a fiduciary duty to make these decisions in the best interests of the stockholders of EQT, which may be contrary to our interests. EQT may choose to shift the focus of its investment and growth to areas not served by our assets.



•

EQT, as our primary customer, has an economic incentive to cause us not to seek higher tariff rates or gathering fees, even if such higher rates or fees would reflect rates and fees that could be obtained in arm's-length, third party transaction.



•

EQT is not limited in its ability to compete with us and may offer business opportunities or sell midstream assets to third parties without first offering us the right to bid for them.



•

Our general partner is allowed to take into account the interests of parties other than us, such as EQT, in resolving conflicts of interest.



•

Most of the officers and certain of the directors of our general partner are also officers and/or directors of EQT and will owe fiduciary duties to EQT. The officers of our general partner will also devote significant time to the business of EQT and will be compensated by EQT accordingly.



•

Our partnership agreement limits the liability of and reduces the fiduciary duties owed by our general partner, and it also restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty.



•

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

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•

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



•

Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash available for distribution to our unitholders.



•

Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion or investment capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units.



•

Our general partner determines which costs incurred by it are reimbursable by us.



•

Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.



•

Our partnership agreement permits us to classify up to $             million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated or general partner units or to our general partner in respect of the incentive distribution rights.



•

Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.



•

Our general partner intends to limit its liability regarding our contractual and other obligations.



•

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



•

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



•

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



•

Our general partner may transfer its incentive distribution rights without unitholder approval.



•

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner's incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

        Please read "Conflicts of Interest and Fiduciary Duties."

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

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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 Fiduciary 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             publicly traded common units, assuming no exercise of the underwriters' over-allotment option. In addition, EQT will own            common units and            subordinated units, representing an aggregate of approximately        % 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

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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:

•

the level of our quarterly distributions;



•

our quarterly or annual earnings or those of other companies in our industry;



•

the loss of a large customer;



•

announcements by us or our competitors of significant contracts or acquisitions;



•

changes in accounting standards, policies, guidance, interpretations or principles;



•

general economic conditions;



•

the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;



•

future sales of our common units; and



•

other factors described in these "Risk Factors."

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

        The estimated initial public offering price of $            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 $            per unit. Based on the estimated initial public offering price of $            per common unit, you will incur immediate and substantial dilution of $            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 intend to apply to list our common units on the NYSE. 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 holder, you will not be entitled to receive distributions or allocations of income or loss on your common units and your common units will be subject to redemption at a price that may be below the current market price.

        In order to comply with certain FERC rate-making policies applicable to entities that pass through their taxable income to their owners, we have adopted certain requirements regarding those investors who may own our common and subordinated 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 see "Description of the Common Units—Transfer of Common Units." If you are not a person who fits the requirements to be an eligible holder, you will not receive distributions or allocations of income and loss on your units and you run the risk of having your units redeemed by us at the lower of your purchase price cost or the then-current market price.

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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 limits our general partner's fiduciary duties to holders of our common units.

        Our partnership agreement contains provisions that modify and reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. 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 or otherwise, free of contractual or fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

•

how to allocate corporate opportunities among us and its affiliates;



•

whether to exercise its limited call right;



•

how to exercise its voting rights with respect to the units it owns;



•

whether to elect to reset target distribution levels;



•

whether to transfer the incentive distribution rights to a third party; and



•

whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

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

Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

        Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

•

whenever our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the board of directors of our general partner and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in, or not opposed to, the interests of our partnership, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;



•

our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;



•

our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

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•

our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is:



—

approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;



—

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;



—

on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or



—

fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

        In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or the conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the third and fourth bullets above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, 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 months ending March 31, 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.

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

        Unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates, including EQT, 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        % 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 or wanton 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.

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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:

•

our existing unitholders' proportionate ownership interest in us will decrease;



•

the amount of cash available for distribution on each unit may decrease;



•

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



•

because the amount payable to holders of incentive distribution rights is based on a percentage of the total cash available for distribution, the distributions to holders of incentive distribution rights will increase even if the per unit distribution on common units remains the same;



•

the ratio of taxable income to distributions may increase;



•

the relative voting strength of each previously outstanding unit may be diminished; and



•

the market price of the common units may decline.

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

        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            common units and            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 provides that any action taken by our general partner to limit its liability is not a breach of our general partner's fiduciary duties, 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

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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        % 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        % 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 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 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 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 target distribution levels, the holders of the incentive distribution rights will be entitled to receive 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

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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:

•

we were conducting business in a state but had not complied with that particular state's partnership statute; or



•

your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute "control" of our business.

        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.

Tax Risks to Common Unitholders

        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.

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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 distributions (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. Recently, members of the U.S. Congress have considered substantive changes to the existing federal income tax laws that affect certain publicly traded partnerships, which, if enacted, may or may not be applied retroactively. Although we are unable to predict whether any of these changes or any other proposals will ultimately be enacted, any such changes could negatively impact the value of an investment in our common units.

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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 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.

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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.

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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

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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.

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USE OF PROCEEDS

        We intend to use the estimated net proceeds of approximately $             million from this offering, after deducting underwriting discounts, the structuring fee and offering expenses,

•

to fund a $             million cash distribution to EQT, in part for reimbursement of capital expenditures associated with our assets;



•

to pre-fund approximately $64 million of maintenance capital expenditures expected to be incurred over the next five years related to three identified regulatory compliance initiatives; and



•

pay approximately $2 million in revolving credit facility origination fees.

        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            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 $             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 $            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 $             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.

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CAPITALIZATION

        The following table shows:

•

the historical capitalization of our Predecessor as of September 30, 2011; and



•

our pro forma capitalization as of September 30, 2011, after giving effect to this offering and other formation transactions described under "Prospectus Summary—Formation Transactions and Partnership Structure," including the application of the net proceeds of this offering as described under "Use of Proceeds."

        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."

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DILUTION

        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 September 30, 2011, our net tangible book value was $             million, or $             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:

        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:

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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

        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.

General

Rationale for Our Cash Distribution Policy

        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.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

        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:

•

Our cash distribution policy will be subject to restrictions on cash distributions under our revolving credit facility. Should we be unable to satisfy these restrictions included in our revolving credit facility, we would be prohibited from making cash distributions notwithstanding our cash distribution policy. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—New Credit Facility."



•

Our general partner will have the authority to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment or increase of those reserves could result in a reduction in cash distributions to our unitholders from the levels we currently anticipate pursuant to our stated cash distribution policy. Any determination to establish cash reserves made by our general partner in good faith will be binding on our unitholders. Our partnership agreement provides that in order for a determination by our general partner to be considered to have been made in good faith, our general partner must believe that the determination is in, or not opposed to, our interests.



•

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders other than in certain circumstances where no unitholder approval is required. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by EQT)

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after the subordination period has ended. At the closing of this offering, assuming no exercise of the underwriters' over-allotment option, EQT will own our general partner as well as approximately        % of our outstanding common units and all of our outstanding subordinated units, representing an aggregate        % limited partner interest in us. Please read "The Partnership Agreement—Amendment of the Partnership Agreement."

•

Even if our cash distribution policy is not modified or revoked, the amount of cash that we distribute and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.



•

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.



•

We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expense, principal and interest payments on our debt, working capital requirements and anticipated cash needs. Our cash available for distribution to common unitholders is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase.



•

Our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute cash to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations.



•

If and to the extent our cash available for distribution materially declines, we may elect to reduce our quarterly cash distributions in order to service or repay our debt or fund expansion capital expenditures.

        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 $             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.

Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital

        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

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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.

Our Minimum Quarterly Distribution

        Upon the consummation of this offering, our partnership agreement will provide for a minimum quarterly distribution of $             per unit for each complete quarter, or $            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 our first distribution for the period from the closing of this offering through June 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:

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(1)

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

        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 $            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—

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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 believe that the determination is in, or not opposed to, our interests. Please read "Conflicts of Interest and Fiduciary 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 $            per unit for the twelve months ending March 31, 2013. In those sections, we present two tables, consisting of:

•

"Unaudited Pro Forma Cash Available for Distribution," in which we present the amount of cash we would have had available for distribution on a pro forma basis for the year ended December 31, 2010 and the twelve month period ended September 30, 2011, derived from our unaudited pro forma financial data that are included in this prospectus, as adjusted to give pro forma effect to this offering and the related formation transactions; and



•

"Estimated Cash Available for Distribution for the Twelve Months Ending March 31, 2013," in which we demonstrate our ability to generate sufficient cash available for distribution for us to pay the minimum quarterly distribution on all units for the twelve month period ending March 31, 2013.

Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2010 and the Twelve Month Period Ended September 30, 2011

Overview

        If we had completed this offering and related transactions on January 1, 2010, our unaudited pro forma cash available for distribution for the year ended December 31, 2010 would have been approximately $37.5 million. This amount would have been sufficient to pay the minimum quarterly distribution of $            per unit per quarter ($            per unit on an annualized basis) on all of our common units and a cash distribution of $            per unit per quarter ($             per unit on an annualized basis), or approximately        % of the minimum quarterly distribution, on all of our subordinated units for such period.

        If we had completed this offering and related transactions on October 1, 2010, our unaudited pro forma cash available for distribution for the twelve month period ended September 30, 2011 would have been approximately $42.8 million. This amount would have been sufficient to pay the minimum quarterly distribution of $            per unit per quarter ($            per unit on an annualized basis) on all of our common units and a cash distribution of $            per unit per quarter ($            per unit on an annualized basis), or approximately        % of the minimum quarterly distribution, on all of our subordinated units for such period.

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        Our unaudited pro forma available cash for the year ended December 31, 2010 and the twelve month period ended September 30, 2011 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.

Sunrise Pipeline Project

        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, 2010 and the twelve month period ended September 30, 2011 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 March 31, 2013 correspond to the amounts in the column titled "Twelve Months Ending March 31, 2013 (Excluding Sunrise Pipeline)." For more information on this lease agreement, please read "Certain Relationships and Related Transactions—Contracts with Affiliates—Sunrise Pipeline Lease Agreement."

Unaudited Pro Forma Cash Available for Distribution

        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, 2010 and the twelve month period ended September 30, 2011, the amount of cash that would have been available for distribution to our unitholders, assuming that this offering and the related formation transactions

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had been completed on January 1, 2010 and October 1, 2010, respectively. Each of the adjustments reflected or presented below is explained in the footnotes to such adjustments.

EQT Midstream Partners, LP
Unaudited Pro Forma Cash Available for Distribution

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Estimated Cash Available for Distribution for the Twelve Months Ending March 31, 2013

        We forecast that our estimated cash available for distribution during the twelve months ending March 31, 2013 will be approximately $53.5 million. This amount would exceed by $             million the amount needed to pay the minimum quarterly distribution of $            per unit on all of our units for the twelve months ending March 31, 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 months ending March 31, 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 months ending March 31, 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 each quarter through March 31, 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 months ending March 31, 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 Months Ending March 31, 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.

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EQT Midstream Partners, LP
Estimated Cash Available for Distribution

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Assumptions and Considerations

        We believe our estimated available cash for distribution for the twelve months ending March 31, 2013 will not be less than $53.5 million. This amount of estimated minimum available cash for

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distribution is approximately $10.7 million, or approximately 25%, more than the unaudited pro forma available cash for distribution for the twelve months ended September 30, 2011. 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 discussions 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 Months Ending March 31, 2013 (Excluding Sunrise Pipeline)" which we believe presents a more accurate representation since the Sunrise Pipeline project and related lease will have no 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."

Total Revenue

        We estimate that our total revenues for the twelve months ending March 31, 2013 will be approximately $123.1 million, as compared to approximately $106.5 million for the pro forma twelve months ended September 30, 2011. Approximately 61% 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 $108.0 million, of our total revenue will be generated from transmission and storage services for the twelve months ending March 31, 2013. This compares to approximately 85%, or approximately $90.5 million, of our pro forma revenues that were generated from transmission and storage revenues during the twelve months ended September 30, 2011. 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 $17.5 million during the twelve months ending March 31, 2013. Transmission revenues are expected to increase by a total of $22.4 million, primarily consisting of the following:

•

Approximately $17.2 million of the increase is due to increased revenue from continuing firm transmission capacity increases and projected usage fees associated with contracts entered into in support of the Equitrans 2010 Marcellus expansion project.



•

Approximately $4.5 million of the increase is due to firm transmission capacity and projected usage fees associated with the 100 BBtu per day of capacity that is currently contracted for the Blacksville Compressor Station project, which is expected to be placed into service in the third quarter of 2012.



•

Approximately $1.3 million of the increase is due to a gradual increase during the forecast period to 37.5 BBtu per day of firm transmission capacity that we expect to have contracted for the Blacksville Compressor Station project.

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        These expected increases in transmission revenues are partially offset by an expected decrease of $4.9 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 months ending March 31, 2013 discussed above, we expect to receive a total of approximately $9.0 million in incremental annual revenue associated with firm transmission capacity contracts for the Equitrans 2010 Marcellus expansion project and the Blacksville Compressor Station project based on contracts currently in place. We expect approximately $5.5 million of this incremental annual revenue to be received in the twelve month period ending March 31, 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 $15.1 million, of our total revenue will be generated from gathering services. This compares to approximately 15%, or approximately $16.0 million, of our total revenues that were generated from gathering services during the twelve months ended September 30, 2011. We expect our gathering operating revenues to decrease by approximately $0.9 million 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.

Operating and Maintenance Expense

        We estimate that operating and maintenance expense for the twelve months ending March 31, 2013 will be $31.3 million compared to $26.3 million for the pro forma twelve months ended September 30, 2011. The $5.0 million increase in operating and maintenance expense is primarily due to higher

•

costs associated with abandonment initiatives,



•

expected direct labor costs,



•

maintenance and contract service costs,



•

regulatory and compliance costs, and



•

operating costs associated with our internal growth projects.

Selling, General and Administrative Expense

        We estimate that selling, general and administrative expense for the twelve months ending March 31, 2013 will be $22.6 million, compared to $18.5 million for the pro forma twelve months ended September 30, 2011. The forecast period includes an estimated $3.0 million of incremental expenses of being a publicly traded partnership. The remaining $1.1 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 costs during the forecast period.

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Depreciation and Amortization Expense

        We estimate that depreciation and amortization expense for the twelve months ending March 31, 2013 will be $13.7 million compared to $11.3 million for the twelve months ended September 30, 2011. The $2.4 million increase is primarily attributable to depreciation on the new infrastructure built and to be built during 2011 and 2012.

Capital Expenditures

        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:

•

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.



•

Maintenance capital expenditures are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets, and for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity. Examples of maintenance capital expenditures are expenditures for the repair, refurbishment and replacement of 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 pre-funded regulatory compliance capital expenditures described below.



—

Pre-funded regulatory compliance capital expenditures are identified maintenance capital expenditures necessary to comply with certain regulatory and other legal requirements. We have identified three specific regulatory compliance initiatives which will require us to expend approximately $64 million over the next five years. We will retain approximately $64 million from the net proceeds of this offering, which we anticipate will fully fund these expenditures, each of which is described in more detail below.

        We estimate that total capital expenditures for the twelve months ending March 31, 2013, will be $81.7 million compared to $37.4 million for the pro forma twelve months ended September 30, 2011. Our estimate is based on the following assumptions:

•

We estimate that expansion capital expenditures for the twelve months ending March 31, 2013, will be $42.5 million, as compared to expansion capital expenditures for the pro forma twelve months ended September 30, 2011, of $14.1 million. We expect to fund our expansion capital expenditures with borrowings under our revolving credit facility or cash generated by our operations. These expenditures are primarily comprised of the following expansion capital projects that we intend to pursue during the forecast period:



—

Blacksville Compressor Station Project. The Blacksville Compressor Station project involves the construction of a new booster compressor station in Monongalia County, West Virginia, including two compressor units with an aggregate compression of approximately 9,470 horsepower, at an estimated total cost of approximately $29 million, of which we expect approximately $10 million to have been expended by March 31, 2012 and the remaining $19 million to be expended during the forecast period. This project will enable

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us to provide approximately 200 BBtu per day of incremental firm transmission capacity to third parties, 100 BBtu of which is already under contract. This project has received all regulatory approvals, including FERC approval, and we expect it will be completed and placed into service in the third quarter of 2012.

—

Low Pressure East Expansion Project. This project involves uprating or replacing 26 miles of existing Equitrans transmission pipeline in Greene, Washington and Allegheny counties, Pennsylvania, at a cost of approximately $22 million, of which we expect approximately $11 million to be expended during the forecast period and the remaining $11 million to be expended after the forecast period. We expect to complete and place this project into service in the third quarter of 2013. When complete, this project will triple the current maximum allowable operating pressure of the pipeline, thereby creating approximately 150 BBtu per day of incremental firm transmission capacity on the system. We assume that no revenues related to this project will be recognized during the forecast period.



—

New Delivery Interconnect Expansion. The project includes three new interconnects, two with Texas Eastern Transmission and one with Peoples Natural Gas Company. The first Texas Eastern interconnect has daily capacity of over 300 BBtu and was placed into service in the fourth quarter of 2011. The second Texas Eastern interconnect will have 200 BBtu of immediate incremental daily capacity and is expected to be placed into service in the first quarter of 2012. Combined, the interconnects with Texas Eastern will have over 800 BBtu per day of capacity at an estimated cost of approximately $10 million, all of which is expected to be expended by March 31, 2012. The Peoples Natural Gas Company Ginger Hill interconnect is expected to have 250 BBtu per day of interconnect capacity at an estimated cost of approximately $2 million, $1.7 million of which we expect to be expended in the forecast period. We expect this project will be placed into service in the fourth quarter of 2012. We assume that no revenues related to this project will be recognized during the forecast period.



—

Other Growth Initiatives. Approximately $10.5 million of capital expenditures is related to projects that will increase our long-term operating capacity and position us to capitalize on the growth opportunities we anticipate impacting our areas of operations in the near-term.



•

We estimate that ongoing maintenance capital expenditures will be $17.2 million for the twelve months ending March 31, 2013, as compared to pro forma ongoing maintenance capital expenditures of approximately $18.1 million for the pro forma twelve months ended September 30, 2011. We expect to fund these maintenance capital expenditures with cash generated by our operations. We expect ongoing maintenance capital expenditures to be approximately $15 million to $20 million per year in the near term.



•

We estimate that pre-funded regulatory compliance capital expenditures will be $22.0 million for the twelve months ending March 31, 2013, as compared to our pro forma regulatory compliance capital expenditures of approximately $5.2 million for the pro forma twelve months ended September 30, 2011. In order to fund these initiatives over the next five years, we will retain approximately $64 million of the net proceeds from this offering. These pre-funded regulatory compliance capital expenditures include the following:



—

Bare steel pipe replacement program: In 2005, we initiated a plan to replace bare steel pipes within our transmission and storage system over time, including high consequence areas, as defined by the Department of Transportation, or DOT. Storage pipelines were also considered a high replacement priority due to the operating stresses associated with such systems. Over the next five years, we expect to replace approximately 60% of the

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remaining bare steel pipe on our transmission and storage system at a cost of approximately $31 million, of which $6 million is expected to be expended during the forecast period.

—

System segmentation and isolation: Recently enacted federal legislation required us to develop a plan to install remote valve operation and pressure monitoring on our transmission and storage system. We expect to make the required system upgrades over the next four years. We have recently initiated this program and we do not have any comparable historical costs. Over the next four years, we expect to expend approximately $27 million for this program, of which $10 million is expected to be expended during the forecast period.



—

Valve pit remediation: In response to a 2011 Pipeline and Hazardous Materials Safety Administration, or PHMSA, Integrated Audit of our system, we have developed a plan to move our valve operators above ground level and to apply coating and corrosion protection. We expect to expend approximately $6 million for this program, all of which is expected to be expended during the forecast period.

Financing

        We estimate that interest expense will be approximately $1.9 million for the twelve months ending March 31, 2013. Our interest expense for the forecast period is based on the following assumptions:

•

We expect to have average borrowings under our new revolving credit facility of approximately $24 million during the twelve months ending March 31, 2013. We expect to pay approximately $1.0 million in credit facility commitment fees and approximately $0.1 million in administrative agent fees. We have assumed that the new revolving credit facility will bear interest at an average rate of 2.1%. An increase or decrease of 1.0% in the interest rate will result in increased or decreased annual interest expense of $0.2 million.



•

Interest expense also includes the amortization of origination fees of $2.0 million which are assumed to be incurred in connection with our revolving credit facility. These fees are expected to be amortized at a rate of approximately $0.4 million per year.

Regulatory, Industry and Economic Factors

        Our forecast for the twelve months ending March 31, 2013, is based on the following significant assumptions related to regulatory, industry and economic factors:

•

There will not be any new federal, state or local regulation of the midstream energy sector, or any new interpretation of existing regulations, that will be materially adverse to our business.



•

There will not be any major adverse change in the midstream energy sector, commodity prices, capital or insurance markets or general economic conditions.



•

There will not be any material accidents, weather-related incidents, unscheduled downtime or similar unanticipated events with respect to our facilities or those of third parties on which we depend.



•

We will not make any acquisitions or other significant expansion capital expenditures (other than as described above).



•

Market, insurance and overall economic conditions will not change substantially.

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PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

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

Distributions of Available Cash

General

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

Definition of Available Cash

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

•

less, the amount of cash reserves established by our general partner at the date of determination of available cash for that quarter to:



—

provide for the proper conduct of our business (including reserves for our future capital expenditures, anticipated future credit needs and refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing related to FERC rate proceedings or rate proceedings under applicable law subsequent to that quarter);



—

comply with applicable law, any of our debt instruments or other agreements; or



—

provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions on our subordinated units unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter and the next four quarters);



•

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

        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.

Intent to Distribute the Minimum Quarterly Distribution

        We intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $            per unit, or $            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

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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—Our Credit Facility" for a discussion of the restrictions to be included in our new credit facility that may restrict our ability to make distributions.

General Partner Interest and Incentive Distribution Rights

        Initially, our general partner will be entitled to 2.0% of all quarterly distributions since inception that we make prior to our liquidation. This general partner interest will be represented by                        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 $            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.

Operating Surplus and Capital Surplus

General

        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.

Operating Surplus

        We define operating surplus as:

•

$             million (as described below); plus



•

all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below), provided that cash receipts from the termination of a commodity hedge or interest rate hedge prior to its specified termination date shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such commodity hedge or interest rate hedge; plus



•

working capital borrowings made after the end of a quarter but on or before the date of determination of operating surplus for that quarter; plus



•

cash distributions paid in respect of equity issued (including incremental distributions on incentive distribution rights), other than equity issued in this offering, to finance all or a portion of expansion capital expenditures in respect of the period from such financing until the earlier to occur of the date the capital asset commences commercial service and the date that it is abandoned or disposed of; plus



•

cash distributions paid in respect of equity issued (including incremental distributions on incentive distribution rights), other than equity issued in this offering, to pay interest on debt incurred, or to pay distributions on equity issued, to finance the expansion capital expenditures

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referred to above, in each case, in respect of the period from such financing until the earlier to occur of the date the capital asset commences commercial service and the date that it is abandoned or disposed of; less

•

all of our operating expenditures (as defined below) after the closing of this offering; less



•

the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less



•

all working capital borrowings not repaid within 12 months after having been incurred, or repaid within such 12-month period with the proceeds of additional working capital borrowings; less



•

any cash loss realized on disposition of an investment capital expenditure.

        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 $             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, (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, and (iv) capital contributions received.

        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 officer compensation, interest 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), maintenance capital expenditures (as discussed in further detail below), and repayment of working capital borrowings; provided, however, that operating expenditures will not include:

•

repayments of working capital borrowings where such borrowings have previously been deemed to have been repaid (as described above);



•

payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than working capital borrowings;

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•

expansion capital expenditures;



•

investment capital expenditures;



•

payment of transaction expenses (including taxes) relating to interim capital transactions;



•

distributions to our partners;



•

repurchases of partnership interests (excluding repurchases we make to satisfy obligations under employee benefit plans); or



•

any other payments made in connection with this offering that are described in "Use of Proceeds."

Capital Surplus

        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:

•

borrowings other than working capital borrowings;



•

sales of our equity and debt securities; and



•

sales or other dispositions of assets, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of ordinary course retirement or replacement of assets.

Characterization of Cash Distributions

        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.

Capital Expenditures

        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 the construction, acquisition or development of an improvement to our capital assets and paid in respect of the period beginning on the date of such financing 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 addition or improvement to, or the replacement of, our capital assets, and for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity. Examples of maintenance capital expenditures are expenditures for the repair, refurbishment and replacement of pipelines, to connect new wells to maintain throughput, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.

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Maintenance capital expenditures are included in operating expenditures and thus will reduce operating surplus.

        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.

        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.

Subordination Period

General

        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 $            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.

Subordination Period

        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 after March 31, 2015, that each of the following tests are met:

•

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



•

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



•

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

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Early Termination of Subordination Period

        Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day of any quarter beginning after March 31, 2013, that each of the following tests are met:

•

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



•

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



•

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

Expiration Upon Removal of the General Partner

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

•

the subordinated units held by any person will immediately and automatically convert into common units on a one-for-one basis, provided (i) neither such person nor any of its affiliates voted any of its units in favor of the removal and (ii) such person is not an affiliate of the successor general partner;



•

if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end; and



•

our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Expiration of the Subordination Period

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

Adjusted Operating Surplus

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

•

operating surplus generated with respect to that period (excluding any amounts attributable to the item described in the first bullet point under the caption "—Operating Surplus and Capital Surplus—Operating Surplus" above); less



•

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



•

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



•

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

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•

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



•

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

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:

•

first, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;



•

second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;



•

third, 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and



•

thereafter, in the manner described in "—General Partner Interest and Incentive Distribution Rights" below.

        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:

•

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and



•

thereafter, in the manner described in "—General Partner Interest and Incentive Distribution Rights" below.

        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.

General Partner Interest and Incentive Distribution Rights

        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 over-allotment option in this offering, 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

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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, that there are no arrearages on common units and that our general partner continues to own the incentive distribution rights.

        If for any quarter:

•

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



•

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

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

•

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives a total of $            per unit for that quarter (the "first target distribution");



•

second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives a total of $            per unit for that quarter (the "second target distribution");



•

third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives a total of $            per unit for that quarter (the "third target distribution"); and



•

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

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Percentage Allocations of Available Cash From Operating Surplus

        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.

General Partner's Right to Reset Incentive Distribution Levels

        Our general partner, as the initial holder of our incentive distribution rights, has the right under our partnership agreement 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 and 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. 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

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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 and general partner 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. 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 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 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:

•

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives an amount equal to 115.0% of the reset minimum quarterly distribution for that quarter;



•

second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives an amount per unit equal to 125.0% of the reset minimum quarterly distribution for the quarter;



•

third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives an amount per unit equal to 150.0% of the reset minimum quarterly distribution for the quarter; and



•

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

        The following table illustrates the percentage allocation 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 closing of this offering, as well as (ii) following a hypothetical reset of the minimum quarterly distribution and target distribution levels

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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 $            .

        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, with respect to the quarter in which the reset occurs. The table reflects that, as a result of the reset, there would be                        common units outstanding, our general partner's 2.0% interest has been maintained, and the average distribution to each common unit would be $            . The number of common units to be issued to our general partner upon the reset was calculated by dividing (i) the average of the amounts received by our general partner in respect of its incentive distribution rights for the two quarters prior to the reset as shown in the table above, or $            , by (ii) the average available cash distributed on each common unit for the two quarters prior to the reset as shown in the table above, or $            .

        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 in which the reset occurs. The table reflects that as a result of the reset there are                        common units,                         common units issued as a result of the reset and                        general partner units, outstanding, and that the average distribution to each common unit is $            for the two quarters prior to the reset. The number of common units issued as a result

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of the reset was calculated by dividing (x) $            as the average of the amounts received by the general partner in respect of its incentive distribution rights, or IDRs, for the two quarters prior to the reset as shown in the table above by (y) the $            of available cash from operating surplus distributed to each common unit as the average distributed per common unit for the two quarters prior to the reset.

        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.

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made

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

•

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price in this offering;



•

second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and



•

thereafter, as if they were from operating surplus.

        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.

Effect of a Distribution from Capital Surplus

        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

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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:

•

the minimum quarterly distribution;



•

the number of common units into which a subordinated unit is convertible;



•

target distribution levels;



•

the unrecovered initial unit price;



•

the number of general partner units comprising the general partner interest; and



•

the arrearages in payment of the minimum quarterly distribution on the common units

        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 convertible into two common 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 existing law is modified or interpreted 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) 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) 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 will be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

General

        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

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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.

Manner of Adjustments for Gain

        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:

•

first, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;



•

second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;



•

third, 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;



•

fourth, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98% to the unitholders, pro rata, and 2% to our general partner, for each quarter of our existence;



•

fifth, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to our general partner for each quarter of our existence;



•

sixth, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75.0% to the unitholders, pro rata, and 25.0% to our general partner for each quarter of our existence;



•

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

        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.

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        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.

Manner of Adjustments for Losses

        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:

•

first, 98.0% to the holders of subordinated units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;



•

second, 98.0% to the holders of common units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and



•

thereafter, 100.0% to our general partner.

        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.

Adjustments to Capital Accounts

        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.

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

        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, 2006 and 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, 2009 and 2010 and for the years ended December 31, 2008, 2009 and 2010 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 September 30, 2011 and for the nine months ended September 30, 2010 and 2011 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 nine months ended September 30, 2011 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:

•

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 with EQT with the proceeds of a capital contribution by EQT;



•

the contribution by EQT of all of the partnership interests in Equitrans, L.P. to us;



•

the issuance to EQT of                    common units and                    subordinated units, representing an aggregate         % limited partner interest in us;



•

the issuance to our general partner of                    general partner units representing a 2.0% general partner interest in us and all of our incentive distribution rights;



•

the issuance of                    common units to the public in this offering, representing a        % limited partner interest in us;



•

our entry into a new $       million revolving credit facility;



•

the use of proceeds of this offering as described in "Use of Proceeds;" and



•

our entry into a lease agreement with EQT pursuant to which we will lease and operate the Sunrise Pipeline.

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Non-GAAP Financial Measure

        The following table presents a reconciliation of Adjusted EBITDA to net income and net cash from 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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

        The historical financial statements included in this prospectus reflect the assets, liabilities and operations of Equitrans, L.P. excluding the results of operations of Big Sandy Pipeline, a FERC-regulated transmission pipeline sold by Equitrans to an unrelated party in July 2011, which we refer to as our "Predecessor." In connection with this offering, EQT will contribute to us its partnership interests in our Predecessor. The following discussion analyzes the financial condition and results of operations of our Predecessor. You should read the following discussion and analysis of financial condition and results of operations in conjunction with the historical and pro forma financial statements, and the notes thereto, included elsewhere in this prospectus. For ease of reference, we refer to the historical financial results of our Predecessor as being "our" historical financial results.

Overview

        We are a growth-oriented limited partnership formed by 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 43% 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 nine months ended September 30, 2011, approximately 65% 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 $1.6 billion in midstream infrastructure since January 1, 2007 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 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 December 31, 2011, 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% of our total revenues for the nine months ended September 30, 2011. As of December 31, 2011, the weighted average remaining contract life based on total revenues for our firm transmission and storage contracts was approximately 10 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

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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 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. Revenues associated with our gathering system, all of which were generated under interruptible gathering service contracts, represented approximately 15% of our total revenues for the nine months ended September 30, 2011.

Our Operations

        Our results are driven primarily by the volume of natural gas transmission and storage capacity under firm contracts, the volume of natural gas that we gather and transport, and the fees assessed for such services. We provide both firm and interruptible services on our transmission and storage system. Approximately 1.0 TBtu per day of transmission capacity and 24 TBtu of storage capacity, was subscribed under binding precedent agreements or firm transmission and storage contracts with a weighted average remaining contract life based on contracted revenues of approximately 10.0 years for transmission contracts and 3.9 years for storage contracts as of December 31, 2011. The primary term of a typical gathering agreement is one year with month-to-month roll over provisions terminable upon 30 days' notice.

        We generally do not take title to the natural gas that we transport, store or gather. We currently provide substantially all of our services pursuant to fee-based contracts, which provides us with a relatively steady revenue stream that minimizes our exposure to direct commodity price risk.

        Our primary customer is EQT, which accounted for approximately 79% of our total revenues for the nine months ended September 30, 2011. For the nine months ended September 30, 2011, EQT

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accounted for approximately 83% of our transmission revenues, 77% of our storage revenues and 63% of our gathering revenues.

How We Evaluate Our Operations

        We evaluate our business on the basis of the following key measures:

•

our revenues and contract mix, particularly the level of firm capacity subscribed;



•

our operating expenses;



•

our Adjusted EBITDA; and



•

our distributable cash flow.

Revenues and Contract Mix

        Our results are driven primarily by the volume of natural gas transmission and storage capacity under firm contracts, the volume of natural gas that we gather and transport, and the fees assessed for such services. One of our main operational goals is to maximize the portion of our physical capacity that is contracted under long-term firm contracts in order to enhance the stability and visibility of our revenue stream. We provide a significant portion of our transmission and storage services through firm contracts and derive a small portion of our revenues through interruptible service contracts. To the extent that physical capacity that is contracted by firm service customers is not being fully utilized, we can offer such capacity to interruptible service customers.

        Transmission and Storage.    Firm transmission service requires the reservation of pipeline capacity by a customer between certain receipt and delivery points. Firm transmission contracts obligate our customers to pay a fixed monthly charge to reserve an agreed upon amount of pipeline capacity regardless of the actual pipeline capacity used by a customer during each month, which we refer to as monthly reservation charges. In addition to monthly reservation charges, we also collect usage charges when a firm transmission customer uses the capacity it has reserved under these firm transmission contracts. Usage charges are assessed on the actual volume of natural gas transported on the transmission system. Firm storage contracts also obligate our customers to pay a fixed monthly reservation charge for the right to inject, withdraw and store a specified volume of natural gas regardless of the amount of storage capacity actually utilized by the customer. Firm storage customers are also assessed usage charges for the actual quantities of natural gas injected into or withdrawn from storage. The high percentage of our revenues derived from reservation charges under long-term, fixed-fee contracts mitigates the risk of revenue fluctuations due to changes in near-term supply and demand conditions and commodity prices.

        Interruptible transmission and storage service is typically short term in nature and is generally used by customers that either do not need firm service or have been unable to contract for firm service. These customers are assessed a usage charge for the volume of natural gas actually transported or stored. Interruptible customers and firm customers that overrun their reserved capacity level are not guaranteed capacity or service on the applicable pipeline and storage facilities. To the extent that firm contracted capacity is not being fully utilized or there is excess capacity that has not been contracted for firm service, the system can allocate such excess capacity to interruptible services. FERC-regulated transmission and storage operators are obligated to provide interruptible services only if a shipper is willing to pay the maximum tariff recourse rate. Our interruptible services are competitively priced in order to be in a position to capture short-term market opportunities as they occur. Included in our interruptible transmission and storage services is our natural gas "park and loan" services to assist customers in managing short-term natural gas surpluses or deficits. Under our park and loan service agreements, customers are charged a usage fee based on the quantities of natural gas they store in (park), or borrow from (loan), our storage facilities.

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        Under FERC policy, a regulated service provider and a customer are permitted to mutually agree to sign a contract for service at a "negotiated rate" which is generally above the FERC regulated "recourse rate" for that service. Negotiated rate contracts must be filed with and accepted by the FERC. As of December 31, 2011, approximately 56% of our contracted firm transmission capacity was subscribed at the maximum recourse rate allowed under our tariff. The remaining 44% of contracted firm transmission capacity was subscribed by customers under negotiated rate agreements at rates generally above the maximum recourse rate under the tariff, some of which is under contracts pending execution pursuant to binding precedent agreements with the remainder having been filed with and accepted by the FERC. A principal reason our customers have entered into negotiated rate agreements at rates above the maximum recourse rate has been to ensure their access to capacity with respect to the construction of new facilities. For example, we have recently entered into long-term negotiated rate agreements with two anchor customers for 50 BBtu per day each to support the construction of the Blacksville Compressor Station project.

        Gathering.    We have gathering agreements conforming to our tariff with producers that ship natural gas and marketers and distribution companies that purchase and ship natural gas from receipt points on our system for delivery to the interstate pipeline market. The primary term of a typical gathering agreement is one year with month-to-month roll over provisions terminable upon 30 days' written notice. The rates for gathering service are based on the maximum permitted gathering fee under our tariff and are assessed on actual receipts into the gathering system. We also retain a fixed percentage of wellhead gas receipts to recover the cost of compressor fuel and lost and unaccounted for natural gas experienced on our gathering system.

        The table below sets forth certain information regarding revenue composition for each of our systems, as of and for the nine months ended September 30, 2011:

Operating Expenses

        The primary components of our operating expenses that we evaluate include operating and maintenance expense, selling, general and administrative expense and depreciation and amortization expense. Our operating expenses typically do not vary significantly based upon the amount of natural gas that we transport or store, but rather are driven primarily by expenses related to the maintenance and growth of our asset base.

        Operating and maintenance expense.    Operating and maintenance expense is comprised primarily of operating and maintenance costs, electricity, non-income taxes, direct labor costs, insurance costs, lost and unaccounted for gas and contract services. The timing of maintenance expenditures during a year generally fluctuates with customer demands as we typically endeavor to schedule as much planned maintenance as possible during off-peak periods. Changes in regulation can also impact maintenance requirements and affect the timing and amount of our costs and expenditures. As an example, the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 set new standards for pipelines in assessing the safety and reliability of the pipeline infrastructure and we have incurred and will continue to incur additional costs, as have other pipelines, to meet these standards. For more information read "Business—Regulatory Environment."

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        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. Historically the natural gas volumes retained from our transmission and storage customers as compensation for our fuel usage and lost and unaccounted for volumes pursuant to our transmission and storage agreements have been sufficient to cover our fuel usage and lost and unaccounted for volumes on our transmission and storage system. However, the level of fuel usage and lost and unaccounted for volumes on our gathering system have historically exceeded the natural gas volumes retained from our gathering customers and it has been necessary for us 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, 2008, 2009 and 2010, our actual level of fuel usage and lost and unaccounted for volumes exceeded the amounts recovered from our gathering customers by approximately 400 BBtu, 300 BBtu and 1,500 BBtu, respectively and for which we recognized $2.7 million, $2.0 million and $5.7 million of purchased gas cost as a component of operating and maintenance expense in 2008, 2009 and 2010, respectively. See "—Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk." We do not currently hedge this commodity price risk.

        Selling, general and administrative expense.    In our historical financial statements, selling, general and administrative expense included direct costs incurred by EQT on our behalf and various direct and indirect cost allocations from EQT. In the future, we expect selling, general and administrative expense to be comprised primarily of such amounts we reimburse to EQT pursuant to our omnibus agreement with EQT and expenses attributable to our status as a publicly traded partnership, such as: 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; and registrar and transfer agent fees; director and officer liability insurance expenses and director compensation. Our future selling, general and administrative expense will also include compensation expense associated with the EQT Midstream Services, LLC Long-Term Incentive Plan.

        Depreciation and amortization expense.    Depreciation and amortization expense consists of our estimate of the decrease in value of the assets capitalized in Property, Plant, & Equipment in the Balance Sheet as a result of using the assets throughout the applicable year. Depreciation is recorded using composite rates on a straight-line basis. We estimate our pipelines have useful lives ranging from 37 years to 65 years and our compression equipment has a useful life of 45 years. Depreciation rates are re-evaluated each time we file with the FERC for a change in our transportation and storage rates.

Adjusted EBITDA and Distributable Cash Flow

        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. Although we have not quantified distributable cash flow on a historical basis, after the closing of this offering we intend to use distributable cash flow, which we define as Adjusted EBITDA less net cash paid for interest expense, maintenance capital expenditures and income taxes, to analyze our performance. Distributable cash flow will not reflect changes in working capital balances. Distributable cash flow and Adjusted EBITDA are not presentations made in accordance with GAAP.

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        Adjusted EBITDA and distributable cash flow are non-GAAP supplemental financial measures that management and external users of our combined 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, in the case of Adjusted EBITDA, 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 and distributable cash flow provides useful information to investors in assessing our financial condition and results of operations. Adjusted EBITDA and distributable cash flow should not be considered alternatives to net income, operating income, cash from operations or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and distributable cash flow have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities. Additionally, because Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. For a reconciliation of Adjusted EBITDA to its most directly comparable financial measure calculated and presented in accordance with GAAP, please see "Prospectus Summary—Non-GAAP Financial Measure."

Factors and Trends Impacting Our Business

        We expect to continue to be affected by certain key factors and trends described below. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results. Please read "Risk Factors."

Increasing Regional Natural Gas Supply and Demand

        We believe that the results of our operations will be primarily driven by the growth in natural gas production in the Marcellus Shale as well as in demand for natural gas in the Northeast region of the United States. According to the EIA, natural gas consumption accounted for approximately 25% of all energy used in the United States in 2010. Natural gas consumption is expected to grow 10% from 25 Tcf in 2010 to 27 Tcf by 2035. We believe that the strong economics of the Marcellus Shale play along with the close proximity of our assets to demand in the region and to high-demand end-user markets in the Mid-Atlantic and Northeastern United States, which decreases transportation costs, will drive continued growth in production even in low commodity price environments. We anticipate that the Northeast region will continue to experience a shift towards natural gas consumption, including the conversion from coal-fired power generation and home heating or residual fuel oil to natural gas. In addition, local distribution companies in our areas of operation appear to be growing increasingly comfortable from a reliability standpoint with including a significant component of Marcellus Shale production in their portfolio of natural gas supplies.

        We believe that the combination of increased regional natural gas supply and demand will drive our results of operations both through increasing demand for our firm transmission and storage services as well as by providing opportunities to grow our gathering operations as EQT and third parties increase production in the region. For more information see "Industry Overview—Market Fundamentals."

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Growth Associated with Acquisitions and Expansion Projects

        We believe that we are well-positioned to achieve growth based on the combination of our relationship with EQT and our strategically located assets, including in portions of the Marcellus Shale that lack substantial natural gas pipeline infrastructure. As production increases in our areas of operations, we believe that we will have a competitive advantage in attracting volumes to our transmission and storage system through relatively low-cost capacity expansions. Additionally, we may acquire additional midstream energy assets from EQT or pursue selected asset acquisitions from third parties to the extent such acquisitions complement our or EQT's existing asset base or allow us to capture operational efficiencies from EQT's production. Should EQT choose to pursue midstream asset sales, it is under no contractual obligation to offer assets or business opportunities to us.

        Our financial results for the nine months ended September 30, 2011 reflect capital expenditures for the Sunrise Pipeline project, which is currently under construction and is estimated to be placed into service in the third quarter of 2012. In connection with the closing of this offering, EQT will retain ownership of the Sunrise Pipeline and will be responsible for the remaining costs of construction. Initially, we will operate the Sunrise Pipeline under a lease agreement with EQT. 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.

        In the near term, we expect that the following internal transmission and storage expansion projects, at an estimated aggregate total cost of $71 million, of which approximately $28 million is expected to have been expended through March 31, 2012, will allow us to capitalize on increased drilling activity by EQT and other third-party producers:

•

Blacksville Compressor Station Project.  The Blacksville Compressor Station project involves the construction of a new booster compressor station in Monongalia County, West Virginia, including two compressor units with an aggregate compression of approximately 9,470 horsepower, at an estimated total cost of approximately $29 million, of which we expect approximately $10 million to have been expended by March 31, 2012. This project will enable us to provide approximately 200 BBtu per day of incremental firm transmission capacity to third parties, 100 BBtu of which is already under contract. This project has received all regulatory approvals, including FERC approval, and we expect it will be completed and placed into service in the third quarter of 2012.



•

Low Pressure East Expansion Project.  This project involves uprating or replacing 26 miles of existing Equitrans transmission pipeline in Greene, Washington and Allegheny counties, Pennsylvania, at a cost of approximately $22 million, of which we expect approximately $0.1 million to have been expended by March 31, 2012. We expect to complete and place this project into service in the third quarter of 2013. When complete, this project will triple the current maximum allowable operating pressure of the pipeline, thereby creating approximately 150 BBtu per day of incremental firm transmission capacity on the system.



•

New Delivery Interconnect Expansion.  This project includes three new interconnects, two with Texas Eastern Transmission and one with Peoples Natural Gas Company. The first Texas Eastern interconnect has daily capacity of over 300 BBtu and was placed into service in the fourth quarter of 2011. The second Texas Eastern interconnect will have 200 BBtu of immediate incremental daily capacity and is expected to be placed into service in the first quarter of 2012. Combined, the interconnects with Texas Eastern will have over 800 BBtu per day of capacity at an estimated cost of approximately $10 million, all of which is expected to have been expended by March 31, 2012. The Peoples Natural Gas Company Ginger Hill interconnect is expected to have 250 BBtu per day of interconnect capacity at an estimated cost of approximately $2 million, of which we expect approximately $0.3 million to have been expended by March 31, 2012. We expect this project will be placed into service in the fourth quarter of 2012.

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•

Hartson Compression Upgrade.  In order to provide additional operational flexibility and increase transmission capacity, we are upgrading the existing compression at the Hartson Compressor Station to install emissions reduction technology, and adding 750 horsepower of compression. This project is estimated to cost approximately $8 million, all of which is expected to have been expended by March 31, 2012 and we expect it will be placed into service in the second quarter of 2012.

Increasing Competition

        Our systems compete primarily with other interstate and intrastate pipelines that transport, store and gather natural gas. Some of these competitors may expand or construct transportation systems that would create additional competition for the services we provide to our customers. In addition, future pipeline transmission and storage capacity could be constructed in excess of actual demand, which could reduce the demand for our services and the rates that we receive for our services. As a result of a substantial majority of our capacity being reserved on a long-term, fixed-fee basis, our revenues are not significantly affected by variation in customers' actual usage resulting from increased competition during the near-term.

Regulatory Compliance Capital Expenditures

        Regulation of natural gas transportation by the FERC and other federal and state regulatory agencies, including the Department of Transportation, has a significant impact on our business. For example, the Pipeline and Hazardous Materials Safety Administration, or PHMSA, office of the Department of Transportation has established pipeline integrity management programs that require more frequent inspections of pipeline facilities and other preventative measures, which may increase our compliance costs and increase the time it takes to obtain required permits. FERC regulatory policies govern the rates that each pipeline is permitted to charge customers for interstate transportation and storage of natural gas. Our operations are also impacted by new regulations, which have increased the time that it takes to obtain required permits. Additionally, increased regulation of natural gas producers in our areas of operations, including regulation associated with hydraulic fracturing, could reduce regional supply of natural gas and therefore throughput on our assets. For more information see "Business—Regulatory Environment."

        Our regulatory compliance capital expenditures totaled $3.6 million for the year ended December 31, 2010 and $3.8 million for the nine months ended September 30, 2011. We expect to incur approximately $22.0 million of capital expenditures during the twelve months ended March 31, 2013 for these regulatory compliance initiatives, which include the following:

•

Bare steel pipe replacement program:  In 2005, we initiated a plan to replace bare steel pipes within our transmission and storage system over time, including high consequence areas, as defined by the DOT. Storage pipelines were also considered a high replacement priority due to the operating stresses associated with such systems. Over the next five years, we expect to replace approximately 60% of the remaining bare steel pipe on our transmission and storage system at a cost of approximately $31 million.



•

System segmentation and isolation:  Recently enacted federal legislation required us to develop a plan to install remote valve operation and pressure monitoring on our transmission and storage system. We expect to make the required system upgrades over the next four years at a cost of approximately $27 million.



•

Valve pit remediation:  In response to a 2011 audit of our system by the PHMSA office of the Department of Transportation, we have developed a plan to move our valve operators above ground level and to apply coating and corrosion protection to certain equipment. We expect to expend approximately $6 million for this program, all of which is expected to be expended during 2012.

        In order to fund these initiatives, we intend to retain approximately $64 million of offering proceeds, which is the anticipated aggregate cost of these projects over the next five years.

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Results of Operations

        The following provides a summary of our results of operations for each of the years ended December 31, 2008, 2009 and 2010 and for each of the nine month periods ended September 30, 2010 and 2011.

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(1)

For a discussion of the non-GAAP financial measure Adjusted EBITDA, please read "Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measure."

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

        Revenues.    Total operating revenues were $79.2 million for the nine months ended September 30, 2011 compared to $64.3 million for the nine months ended September 30, 2010. The $14.9 million increase was due to a $16.1 million increase in transmission and storage operating revenues, partially offset by a $1.2 million decrease in gathering operating revenues. The majority of the increase in transmission operating revenues was attributable to an increase in firm transmission service reservation revenues associated with an average daily increase of 186 BBtu of firm transmission service provided during the nine months ended September 30, 2011 when compared to the nine months ended September 30, 2010. This capacity was due to the completion in the fourth quarter of 2010 of a portion of the Equitrans 2010 Marcellus expansion project and the addition of new receipt point interconnects with EQT's gathering systems. The increased firm transmission capacity sold also resulted in higher usage fees based on increased throughput for the period, which also contributed to the increased revenues. These increases were partially offset by a decrease in the recovery of pipeline safety costs as compared to the same period in 2010 as a result of a lower pipeline safety cost recovery rate due to an over collection of $1.0 million in the prior period. The decrease in storage operating revenues was primarily due to a decrease in parking service volumes and pricing due to unfavorable natural gas commodity market pricing spreads between the summer and winter months compared to the nine months ended September 30, 2010.

        Gathering revenues decreased due to fewer volumes gathered for the nine months ended September 30, 2011 when compared to the nine months ended September 30, 2010. The decreased volumes were primarily due to the natural decline in natural gas production from mature wells and limited additional development of some of the shallow, low-pressure formations served by our gathering system.

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        Operating Expenses.    Operating expenses totaled $41.4 million for the nine months ended September 30, 2011 compared to $38.9 million for the nine months ended September 30, 2010. The increase in operating expenses was primarily due to a $2.0 million increase in operating and maintenance expense and a $0.5 million increase in depreciation and amortization expense. Transmission and storage operating and maintenance expense increased $1.7 million, while gathering operating and maintenance expense increased $0.4 million. Both operating and maintenance expense increases were primarily due to a higher indirect operating and maintenance expense allocation from EQT and higher costs to maintain the integrity of and to operate the systems as a result of the rising cost environment and increased assets.

        The increase in depreciation and amortization expense was entirely related to transmission and storage primarily due to the increased investment in transmission infrastructure, which included the Equitrans 2010 Marcellus expansion project and a large compressor station. Selling, general and administrative expenses remained at approximately the same level.

        Other Income.    Other income represents allowance for equity funds used during construction, or AFUDC, which 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. Other income generally increases during periods of increased construction, and decreases during times of less construction. The $1.6 million increase for the nine months ended September 30, 2011 when compared to the nine months ended September 30, 2010 was primarily the result of increased construction expenditures in connection with the Sunrise Pipeline project.

        Interest Expense, Net.    Interest expense, net for the nine months ended September 30, 2011 totaled $4.4 million compared to $3.9 million for the nine months ended September 30, 2010. The $0.5 million increase was primarily driven by increased rates on demand notes with EQT.

        Income Tax Expense.    Income taxes for the nine months ended September 30, 2011 totaled $13.7 million compared to $9.3 million for the nine months ended September 30, 2010. The $4.4 million increase was primarily driven by an increase in pre-tax income. Our historical financial statements include U.S. federal and state income tax expense. 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.

        Net Income.    Net income for the nine months ended September 30, 2011 totaled $22.0 million compared to $12.8 million for the nine months ended September 30, 2010. The $9.2 million increase was primarily driven by higher transmission revenues, which were partially offset by decreases in gathering and storage revenues and an increase in operating expenses.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

        Revenues.    Total operating revenues were $91.6 million for the year ended December 31, 2010 compared to $80.1 million for the year ended December 31, 2009. The $11.5 million increase in total operating revenues was primarily due to an $8.9 million increase in transmission and storage operating revenues and a $2.7 million increase in gathering operating revenues.

        Transmission and storage operating revenues increased primarily due to an increase in firm transmission capacity sold associated with the Equitrans 2010 Marcellus expansion project. In addition, storage revenues increased primarily due to park and loan services provided to affiliates.

        Gathering operating revenues in 2010 increased from the prior year primarily as a result of higher wellhead production volumes from affiliated shippers, including volumes produced from the Marcellus Shale.

        Operating Expenses.    Operating expenses totaled $53.7 million for the year ended December 31, 2010 compared to $51.4 million for the year ended December 31, 2009. The increase in operating expenses was primarily due to increases of $5.9 million in operating and maintenance expense and

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$1.2 million in depreciation and amortization expense. The increase in operating and maintenance expense was entirely related to gathering due to higher electricity and labor-related costs associated with the growth of the business. Transmission and storage operating and maintenance expense remained at approximately the same level. Transmission and storage depreciation and amortization expense increased by $0.8 million while gathering depreciation and amortization expense increased by $0.5 million. Both increases were primarily due to the increased investment in the respective system infrastructure.

        These increases in operating expenses were mostly offset by a $4.8 million decrease in selling, general and administrative expense. Transmission and storage selling, general and administrative expense decreased by $5.2 million, which was partially offset by an increase in gathering selling, general and administrative expense of $0.4 million. Approximately $4.7 million of this decrease is attributable to an allocation of selling, general and administrative expense in 2009 associated with EQT's long-term incentive plan. Gathering selling, general and administrative expense increased due to higher direct labor-related expense.

        Other Income.    Other income decreased $0.6 million for the year ended December 31, 2010 as compared to the year ended December 31, 2009 primarily as a result of having fewer assets under construction on regulated pipeline projects during 2010.

        Income Tax Expense.    Income taxes for the year ended December 31, 2010 totaled $14.0 million compared to $10.6 million for the year ended December 31, 2009. The $3.4 million increase was primarily driven by an increase in pre-tax income. Our historical financial statements include U.S. federal and state income tax expense. 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.

        Net Income.    Net income for the year ended December 31, 2010 totaled $19.2 million compared to $14.0 million for the year ended December 31, 2009. The $5.2 million increase was primarily driven by higher revenues, specifically transmission, while operating expenses increased marginally.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

        Revenues.    Total operating revenues were $80.1 million for the year ended December 31, 2009 compared to $71.9 million for the year ended December 31, 2008. The $8.2 million increase in total operating revenues was driven by an $8.8 million increase in transmission and storage operating revenues, partially offset by a decrease in gathering operating revenues of $0.6 million.

        The increase in transmission and storage revenues was primarily due to increased fees related to park and loan services provided to affiliates. The decrease in gathering revenues was due to the decreased volumes as a result of the natural decline in natural gas production wells and lack of drilling in certain shallow, low-pressure formations served by our gathering system.

        Operating Expenses.    Operating expenses totaled $51.4 million for the year ended December 31, 2009 compared to $51.6 million for the year ended December 31, 2008. The decrease in operating expenses was primarily due to a $3.5 million decrease in operating and maintenance expense, partially offset by increases of $2.0 million in selling, general and administrative expense and $1.2 million in depreciation and amortization expense.

        Transmission and storage operating and maintenance expense decreased $2.9 million, while gathering operating and maintenance expense decreased $0.6 million. The decrease in operating and maintenance expense in transmission and storage was mainly due to a decrease in labor costs and a decrease in non-income taxes due to a reduction of property tax assessments in certain jurisdictions. The gathering operating and maintenance expense decrease was primarily due to a decrease in labor costs.

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        The increase in selling, general and administrative expense for both transmission and storage and gathering was primarily the result of an allocation of compensation expense of EQT associated with its long-term incentive program. Selling, general and administrative expense decreased year over year when excluding this allocation. The decrease for both transmission and storage and gathering were primarily related to a decrease in labor-related costs and a decrease in the indirect selling, general and administrative expense allocation. The increase in depreciation and amortization expense for both transmission and storage and gathering was primarily due to the increased investment in infrastructure during 2008 and 2009.

        Other Income.    Other income decreased $0.3 million for the year ended December 31, 2009 as compared to the year ended December 31, 2008, primarily as a result of decreased AFUDC as a result of having fewer assets under construction on regulated pipeline projects than in the prior period.

        Interest Expense, Net.    Interest expense, net for the year ended December 31, 2009 totaled $5.2 million compared to $5.5 million for the year ended December 31, 2008. The $0.3 million decrease was primarily driven by a decrease in rates on demand notes, partially offset by an increase in our debt balance.

        Income Tax Expense.    Income taxes for the year ended December 31, 2009 totaled $10.6 million compared to $7.8 million for the year ended December 31, 2008. The $2.8 million increase was primarily driven by an increase in pre-tax income. Our historical financial statements include U.S. federal and state income tax expense. 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.

        Net Income.    Net income for the year ended December 31, 2009 totaled $14.0 million compared to $8.3 million for the year ended December 31, 2008. The $5.7 million increase was primarily driven by higher revenues, specifically in storage, while operating expenses remained at approximately the same level.

Liquidity and Capital Resources

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

        Historically, our sources of liquidity included cash generated from operations and intercompany loans from EQT. We also participated in EQT's cash management program, whereby EQT on a periodic basis swept cash balances residing in our bank accounts. Therefore, our historical financial statements reflect little or no cash balances. Unlike our transactions with third parties, which ultimately settle in cash, our affiliate transactions are settled on a net basis through an intercompany receivable/payable with EQT. Due to capital expenditures funded in this manner, these balances have accumulated over time to reflect a net payable to EQT. We have treated these balances as receivables, demand notes and ultimately converted them to long-term debt. The intercompany demand notes, which are current liabilities, have historically been responsible for our working capital deficits. Prior to the completion of this offering, EQT will make a capital contribution to Equitrans, L.P., which we will use to retire all outstanding intercompany indebtedness with EQT.

        Subsequent to this offering, we expect our sources of liquidity to include:

•

cash generated from our operations;



•

$             million available for borrowing under our credit facility;



•

cash on hand of $             million after the application of the net proceeds of this offering, which we will use to fund certain compliance maintenance capital expenditures as described in more detail under "Capital Requirements";

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•

issuances of additional partnership units; and



•

debt offerings.

        We believe that cash on hand, cash generated from operations and availability under our credit facility will be adequate to meet our operating needs, our planned short-term capital and debt service requirements, our cash distribution requirements, and cash required for planned expansion opportunities.

New Credit Facility

        In connection with this offering, we expect to enter into a new $         million revolving credit facility, with a maturity date             years from the closing of this offering. The credit facility will be available to fund working capital and to fund expansion projects, make acquisitions and for general partnership purposes. The credit facility is expected to contain certain customary financial covenants, events of default and restrictions on our ability to take certain actions.

Working Capital

        Working capital is the amount by which current assets exceed current liabilities. As of September 30, 2011, we had a working capital deficiency of $22.2 million compared to a working capital surplus of $11.9 million at December 31, 2010 and a working capital deficiency of $86.4 million at December 31, 2009. The increase in working capital deficiency from December 31, 2010 to September 30, 2011 was primarily due to the increase in intercompany indebtedness resulting from capital expenditures in the nine months ended September 30, 2011. The decrease in working capital deficiency from December 31, 2009 to December 31, 2010 was mainly due to the subsequent refinancing of demand notes to long-term notes, which reduced the current maturities at December 31, 2010.

        Our working capital requirements have been and will continue to be primarily driven by changes in accounts receivable and accounts payable, including transactions with affiliates. These changes are primarily impacted by such factors as the timing of collections from customers and the level of spending for maintenance and expansion activity. Changes in the terms of our transmission and storage agreements have a direct impact on our generation and use of cash from operations due to their impact on cash receipts, along with the related changes in working capital. A material adverse change in operations or available financing may impact our ability to fund our requirements for liquidity and capital resources.

Historical Cash Flow

        The following table and discussion presents a summary of our net cash provided by (used in) operating activities, net cash provided by (used in) investing activities and net cash provided by (used in) financing activities for the years ended December 31, 2008, 2009 and 2010 and the nine months ended September 30, 2010 and 2011.

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        Operating Activities.    The $24.7 million increase in net cash provided by operations for the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010 was primarily due to the increase in revenues as a result of increased firm transmission capacity and higher accounts payable due to increased construction activity.

        The $19.5 million decrease in net cash provided by operations for the year ended December 31, 2010 compared to the year ended December 31, 2009 was primarily related to increased payments to related parties, partially offset by increased revenues from transmission and gathering activities with affiliates due to increased Marcellus Shale activity.

        The $25.0 million increase in net cash provided by operations for the year ended December 31, 2009 compared to the year ended December 31, 2008 was primarily related to increased payments from related parties and increased revenues from transmission and storage activities, primarily with affiliates.

        Investing Activities.    Net cash used in investing activities for the nine months ended September 30, 2011 increased by $44.8 million from net cash used in investing activities for the nine months ended September 30, 2010. The increase was primarily related to capital expenditures related to construction of the Sunrise Pipeline project.

        The $4.3 million increase in net cash used in investing activities for the year ended December 31, 2010 was primarily related to increased capital expenditures for transmission expansion projects offset by decreased spending on gathering assets. See additional discussion in "Capital Requirements" below.

        The $3.8 million decrease in net cash used in investing activities for the year ended December 31, 2009 was primarily related to decreased gathering capital expenditures related to the bare steel pipe replacement program.

        Financing Activities.    EQT historically funded our working capital, maintenance capital and growth capital expansion initiatives. We historically paid EQT all excess cash generated from operations.

        Net cash provided by financing activities for the nine months ended September 30, 2011 increased by $6.9 million as compared to the nine months ended September 30, 2010. The increase in cash provided by financing activities was primarily related to advances from EQT. The net use of this cash was for the capital expenditures discussed in the investing activities section above.

        The net cash provided by financing activities for the year ended December 31, 2010 remained at approximately the same level as the net cash provided by financing activities for the year ended December 31, 2009.

        The $9.5 million decrease in net cash provided by financing activities for the year ended December 31, 2009 was primarily related to a $14.4 million lower EQT investment in that year, partially offset by an $8.9 million decrease in dividends paid to investors.

Capital Requirements

        The transmission, storage and gathering businesses can be capital intensive, requiring significant investment to maintain and upgrade existing operations.

        We categorize our capital expenditures as either:

•

Expansion capital expenditures, which include those 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.

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•

Maintenance capital expenditures, which include those cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets, and for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity. Examples of maintenance capital expenditures are expenditures for the repair, refurbishment and replacement of 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 regulatory compliance capital expenditures described below.



—

Regulatory compliance capital expenditures are identified maintenance capital expenditures necessary to comply with regulatory and other legal requirements. We have identified three specific regulatory compliance initiatives which will require us to expend approximately $64 million over the next five years. We will retain approximately $64 million from the net proceeds of this offering, which we anticipate will fully fund these expenditures.

        Our historical capital expenditures for the years ended December 31, 2008, 2009 and 2010 and for the nine months ended September 30, 2010 and 2011 were as follows:

        The expansion capital expenditures totaled $22.8 million for the year ended December 31, 2010 and $55.0 million for the nine months ended September 30, 2011. The increase in capital expenditures in 2011 was primarily due to the Sunrise Pipeline project. Our future expansion capital expenditures may vary significantly from period to period based on the investment opportunities available to us. We expect to fund future capital expenditures through a combination of funds generated from our operations, cash on hand after the application of the net proceeds of this offering, borrowings under our new credit facility and the issuance of additional partnership units and debt offerings.

        Our historical and continuing maintenance capital expenditures are composed of regulatory compliance initiatives and ongoing maintenance activities. The regulatory compliance initiative capital expenditures totaled $3.6 million for the year ended December 31, 2010 and $3.8 million for the nine months ended September 30, 2011. We expect to incur approximately $22.0 million of maintenance capital expenditures during the twelve months ended March 31, 2013 for these regulatory compliance capital expenditures and approximately $64 million over the next five years, for which we have retained a portion of the offering proceeds. These regulatory compliance capital expenditures include the following:

•

Bare steel pipe replacement program:  In 2005, we initiated a plan to replace bare steel pipes within our transmission and storage system over time, including high consequence areas, as defined by the DOT. Storage pipelines were also considered a high replacement priority due to the operating stresses associated with such systems. Over the next five years, we expect to

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replace approximately 60% of the remaining bare steel pipe on our transmission and storage system at a cost of approximately $31 million.

•

System segmentation and isolation:  Recently enacted federal legislation required us to develop a plan to install remote valve operation and pressure monitoring on our transmission and storage system. We expect to make the required system upgrades over the next four years at a cost of approximately $27 million. We have recently initiated this program and we do not have any comparable historical costs.



•

Valve pit remediation:  In response to a 2011 audit of our system by the PHMSA office of the Department of Transportation, we have developed a plan to move our valve operators above ground level and to apply coating and corrosion protection to certain equipment. We expect to expend approximately $6 million for this program, all of which is expected to be expended during 2012.

        In order to fund these initiatives, we intend to retain approximately $64 million of offering proceeds, which is the anticipated aggregate cost of these projects over the next five years.

        The ongoing maintenance capital expenditures totaled $10.0 million for the year ended December 31, 2010 and $14.6 million for the nine months ended September 30, 2011. The increase in capital expenditures in 2011 was primarily due to upgrades to a measuring and regulating station. We expect ongoing maintenance capital expenditures to be approximately $15 million to $20 million per year in the near term.

Distributions

        Our partnership agreement requires us to distribute 100% of our available cash each quarter to the holders of our units, until each unit has received the minimum quarterly distribution. Generally, our available cash is defined as our cash on hand at the end of the quarter less the establishment of cash reserves. We do not have a legal obligation to pay this distribution. Please read "Our Cash Distributions Policy and Restrictions on Distributions" and "Provisions of Our Partnership Agreement Relating to Cash Distributions."

        Upon completion of this offering, our general partner will establish a minimum quarterly distribution of $            per unit ($            per unit on an annualized basis) to the extent we have sufficient cash after establishment of reserves and payment of fees and expenses, including payments to our general partner and its affiliates. For the first quarter that we are publicly traded, we will pay investors in this offering a prorated distribution covering the period from the completion of this offering through                        , 2012, based on the actual length of that period. Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail under the caption "Cash Distribution Policy and Restrictions on Distributions."

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Contractual Obligations

        The following table details the future projected payments associated with our contractual obligations and other commitments as of December 31, 2010:

        In addition to the obligations existing as of December 31, 2010, at the closing of this offering we will enter into a capital lease with a wholly-owned subsidiary of EQT for the lease of the Sunrise Pipeline and we will operate the facilities as part of our transmission and storage system under the rates, terms, and conditions of our FERC-approved tariff. While this lease agreement will be effective upon the transfer of the Sunrise Pipeline, no lease payments will be due pursuant to this lease agreement until after the in-service date of the Sunrise Pipeline. The lease payment due in any given month will be the lesser of the following alternatives: (1) a revenue-based payment reflecting the revenues generated by the operation of the Sunrise Pipeline minus our actual costs of operating the Sunrise Pipeline and (2) a payment based on depreciation expense and pre-tax return on invested capital for the Sunrise Pipeline. The first alternative is designed to pass through to EQT the revenues we collect for service on the Sunrise Pipeline, including reservation charges and usage charges, net of our costs of operating and maintaining such facilities. This alternative is intended to protect us from adverse economic consequences in the event we do not subscribe all of the available capacity on the Sunrise Pipeline, a possibility that may persist for the first few years following the in-service date of the Sunrise Pipeline until production in the Marcellus Shale region ramps up. The second lease payment alternative is designed to reflect the actual cost of service to operate the Sunrise Pipeline. As a result, the payments we make under the Sunrise Pipeline lease will be variable and are not expected to have a 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."

        The personnel who operate our assets are employees of EQT. EQT directly charges us for the payroll and benefit costs associated with these employees and retirees. EQT carries the obligation for pension and other employee-related benefits in its financial statements.

Off-Balance Sheet Arrangements

        We do not have any off-balance sheet arrangements.

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Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

        Other than the base gas we purchase and use in our natural gas storage facilities, which is necessary to maintain pressure and deliverability in our storage pools, and purchases of a small amount of natural gas for system operations, we generally do not take title to the natural gas that we store or transport for our customers and, accordingly, we are not exposed to commodity price fluctuations on natural gas stored in our facilities or transported through our pipelines by our customers. Base gas purchased and used in natural gas storage facilities, which was purchased more than 30 years ago, is considered a long-term asset and is not re-valued at current market prices. A certain amount of gas is naturally lost in connection with transporting natural gas 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 our fuel usage. Historically the natural gas volumes retained from our transmission and storage customers as compensation for our fuel usage and lost and unaccounted for volumes pursuant to our transmission and storage agreements have been sufficient to cover our fuel usage and lost and unaccounted for volumes on our transmission and storage system. However, the level of fuel usage and lost and unaccounted for volumes on our gathering system have historically exceeded the natural gas volumes retained from our gathering customers as compensation for our fuel usage and lost and unaccounted for volumes pursuant to our gathering agreements and it has been necessary to purchase natural gas in the market to make up for the difference. For the years ended December 31, 2008, 2009 and 2010, our actual level of fuel usage and lost and unaccounted for volumes exceeded the amounts recovered from our gathering customers by approximately 400 BBtu, 300 BBtu and 1,500 BBtu, respectively, for which we recognized $2.7 million, $2.0 million and $5.7 million of purchased gas cost as a component of operating and maintenance expense in 2008, 2009, 2010, respectively. Except for the base gas in our natural gas storage facilities, which we consider to be a long-term asset, and volume and pricing variations related to the volumes of fuel we purchase to make up for line loss, our current business model is designed to minimize our exposure to fluctuations in commodity prices. As a result, absent other market factors that could adversely impact our operations, changes in the price of natural gas over the intermediate term should not materially impact our operations. We have not historically engaged in material commodity hedging activities relating to our assets. However, we may engage in commodity hedging activities in the future, particularly if we undertake growth projects or engage in acquisitions that expose us to direct commodity price risk.

Interest Rate Risk

        Our operating and acquisition activities have historically been funded through intercompany borrowings with EQT and its affiliates at market rates. EQT's debt issuer credit ratings, as determined by S&P, Moody's or Fitch, determine the interest rate charged by the counterparties. The lower the debt credit rating, the higher the borrowing rate.

        As described above, at the closing of this offering, we will enter into a new $         million revolving credit facility. We may or may not hedge portions of our borrowings under the revolving credit facility from time to time in order to manage risks associated with floating interest rates.

Credit Risk

        We are exposed to credit risk. Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. Approximately 59% and 42% of our third party accounts receivable balances of $2.8 million and $4.7 million as of December 31, 2009 and 2010, respectively, represent amounts due from marketers. We manage our exposure to credit risk associated with customers to whom we extend credit through credit analysis, credit approval, credit limits and monitoring procedures. For certain transactions, we may request letters of credit, cash collateral,

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prepayments or guarantees as forms of credit support. Our tariff requires customers that do not meet specified credit standards to provide three months of credit support; however, we are exposed to credit risk beyond this three-month period when our tariff does not require our customers to provide credit support. For some of our more recent long-term contracts associated with system expansions, we have entered into negotiated credit agreements that provide for more stringent forms of credit support if certain credit standards are not met. We have historically experienced only minimal credit losses in connection with our receivables. In connection with the closing of this offering, EQT will enter into a guarantee of EQT Energy's obligations. Please read "Certain Relationships and Related Transactions—Contracts with Affiliates." EQT's public senior debt has an investment grade credit rating.

Recent Accounting Pronouncements

        In May 2011, the Financial Accounting Standards Board, or FASB, issued a standard update intended to enhance the fair value disclosure requirements to result in common fair value measurement in United States generally accepted accounting principles (GAAP) and International Financial Reporting Standards (IFRS). The amendments are to be applied prospectively, and are effective during interim and annual periods beginning after December 15, 2011. We are currently evaluating the impact this standard will have on our financial statement disclosures.

        In June 2011, the Financial Accounting Standards Board (FASB) issued a standard update to improve the comparability, consistency and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. The amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We are currently evaluating the impact this standard will have on our financial statement disclosures.

Critical Accounting Policies and Estimates

        Our significant accounting policies are described in Note 2 to the financial statements included elsewhere in this prospectus. Management's discussion and analysis of financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with U.S. GAAP. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosure of contingent assets and liabilities. The accounting policies discussed below are considered by management to be critical to an understanding of our financial statements as their application places the most significant demands on management's judgment. Due to the inherent uncertainties involved with this type of judgment, actual results could differ significantly from estimates and may have a material adverse impact on our results of operations, equity or cash flows. For additional information concerning our other accounting policies, please read the notes to the financial statements included elsewhere in this prospectus.

        Revenue Recognition.    Revenues relating to the transmission, storage and gathering of natural gas are recognized in the period service is provided. Reservation revenues on firm contracted capacity are recognized ratably over the contract period regardless of the amount of natural gas that is transported. Revenues associated with interruptible services are recognized as physical deliveries of natural gas are made. Revenue is recognized for gathering activities when deliveries of natural gas are made.

        We encounter risks associated with the collection of our accounts receivable. As such, we record a monthly provision for accounts receivable that are considered to be uncollectible. In order to calculate the appropriate monthly provision, we utilize a historical rate of accounts receivable losses as a percentage of total revenue. This historical rate is applied to the current revenues on a monthly basis and is updated periodically based on events that may change the rate, such as a significant change to the natural gas industry or to the economy as a whole. Management reviews the adequacy of the allowance on a quarterly basis using the assumptions that apply at that time.

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        We believe that the accounting estimates related to revenue recognition and the allowance for doubtful accounts receivable are "critical accounting policies" because the underlying assumptions used for the allowance can change from period to period and the changes in the allowance could potentially cause a material impact to the results of operations and to working capital. Actual mix of customers and their ability to pay and economic conditions may vary significantly from management's estimates and may impact the collectability of customer accounts.

        Regulatory Accounting.    Our regulated operations consist of interstate pipeline, intrastate gathering and storage operations subject to regulation by the FERC. Rate regulation provided by the FERC is designed to recover the costs of providing the regulated services. The application of Financial Accounting Standards Topic 980 "Regulated Operations" allows us to defer expenses and income on its combined balance sheet as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the rate setting process in a period different from the period in which they would have been reflected in the statement of operations for a non-regulated company. The deferred regulatory assets and liabilities are then recognized in the statement of operations in the period in which the same amounts are reflected in rates. The amounts deferred are to be recovered over the regulated period. The amounts deferred in the balance sheet relate primarily to the accounting for income taxes and post-retirement benefit costs. We believe that we will continue to be subject to rate regulation that will provide for the recovery of deferred costs.

        We believe that the accounting estimates related to regulatory accounting are "critical accounting policies" because the underlying assumptions regarding the recovery of deferred costs and revenues in future rates can change from period to period and the changes in the recoverability of these amounts could potentially cause a material impact to the results of operations and to working capital. Actual rate recovery amounts and periods may vary significantly from management's estimates and may impact the realization or recovery of regulatory assets and liabilities.

        Property, Plant and Equipment.    Property, plant and equipment are stated at amortized cost. Maintenance projects that do not increase the overall life of the related assets are expensed as incurred. Expenditures that extend the useful life of the underlying asset are capitalized.

        Depreciation is recorded using composite rates on a straight-line basis. The overall rate of depreciation for the years ended December 31, 2008, 2009 and 2010 were approximately 1.7%, 1.9% and 2.1%, respectively. We estimate our pipelines have useful lives ranging from 37 years to 65 years and our compression equipment has a useful life of 45 years. Depreciation rates are re-evaluated each time we file with the FERC for a change in our transportation and storage rates.

        Whenever events or changes in circumstances indicate that the carrying amount of long-lived assets may not be recoverable, we review the long-lived assets for impairment by first comparing the carrying value of the assets to the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the assets. If the carrying value exceeds the sum of the assets' undiscounted cash flows, we estimate an impairment loss by taking the difference between the carrying value and fair value of the assets.

        We believe that the accounting estimate related to asset impairment is a "critical accounting estimate" as it is highly susceptible to change from period to period, because it requires management to make assumptions about cash flows over future years. These assumptions affect the amount of an impairment, which would have an impact on our results of operations and our financial position. Management's assumptions about future cash flows require significant judgment because actual operating levels have fluctuated in the past and are expected to do so in the future.

        Income Taxes.    We recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been included in our financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the differences between the

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financial reporting and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse.

        We have recorded deferred tax assets and liabilities principally resulting from tax depreciation in excess of book depreciation and regulatory temporary differences, including AFUDC. We establish a valuation allowance against any portion of deferred tax for which we believe that it is more likely than not that these deferred tax assets will not all be realized. Any determination to change the valuation allowance would impact our income tax expense and net income in the period in which such a determination is made.

        We estimate the amount of financial statement benefit to record for uncertain tax positions by first determining whether it is more likely than not that a tax position in a tax return will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. If this step is satisfied, then we must measure the tax position. The tax position is measured at the largest amount of benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. See the financial statements for further discussion.

        We believe that accounting estimates related to income taxes are "critical accounting estimates" because we must assess the likelihood that deferred tax assets will be recovered from future taxable income and exercise judgment regarding the amount of financial statement benefit realizable upon ultimate settlement. To the extent we believe it is more likely than not (a likelihood of more than 50%) that some portion or all of deferred tax assets will not be realized, a valuation allowance must be established. Significant management judgment is required in determining any valuation allowance recorded against deferred tax assets and in determining the amount of financial statement benefit to record for uncertain tax positions. We consider all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed. In making this determination, we consider the amounts and probabilities of the outcomes that could be realized upon ultimate settlement of an uncertain tax position using the facts, circumstances and information available at the reporting date to establish the appropriate amount of financial statement benefit. Evidence used for the valuation allowance includes information about our current financial position and results of operations for the current and preceding years, as well as all currently available information about future years, including our anticipated future performance, the reversal of deferred tax assets and liabilities and tax planning strategies available to us. To the extent that an uncertain tax position or valuation allowance is established or increased or decreased during a period, we must include an expense or benefit within tax expense in the income statement.

        Contingencies and Asset Retirement Obligations.    We are involved in various regulatory and legal proceedings that arise in the ordinary course of business. We record a liability for contingencies based upon our assessment that a loss is probable and the amount of the loss can be reasonably estimated. We consider many factors in making these assessments, including history and specifics of each matter. Estimates are developed in consultation with legal counsel and are based upon an analysis of potential results.

        We operate and maintain our transmission and storage system and our gathering system, and we intend to do so as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we believe that we cannot reasonably estimate the asset retirement obligations for our system assets as these assets have indeterminate lives.

        We believe that the accounting estimates related to contingencies and asset retirement obligations are "critical accounting estimates" because we must assess the probability of loss related to contingencies and the expected amount and timing of asset retirement obligations. In addition, we must determine the estimated present value of future liabilities. Future results of operations for any particular quarterly or annual period could be materially affected by changes in our assumptions.

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INDUSTRY OVERVIEW

General

        The midstream natural gas industry provides the link between the exploration and production of natural gas from the wellhead and the delivery of natural gas and its by-products to industrial, commercial and residential end-users. Companies generate revenues at various links within the midstream value chain by gathering, processing, treating, fractionating, transporting, storing and marketing natural gas and natural gas liquids, or NGLs. Our midstream operations currently focus on acting as an interstate pipeline header system by gathering, storing and transporting natural gas to various interconnects with long-haul interstate pipelines and local distribution companies, or LDCs. Revenues associated with our transmission and storage system and our gathering system represented approximately 85% and 15%, respectively, of our total revenues for the nine months ended September 30, 2011.

        The following diagram illustrates the various components of the midstream value chain:

Midstream Services

        The services provided by us and other midstream natural gas companies are generally classified into the categories described below. As indicated above, we do not currently provide all of these services, although we may do so in the future.

        Gathering.    At the initial stages of the midstream value chain, a network of small diameter pipelines known as gathering systems connect to wellheads and other receipt points in the production area. These gathering systems transport natural gas from the wellhead and other receipt points either to treating and processing plants or directly to interstate or intrastate pipelines. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells and other receipt points. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow for additional production and well connections

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without significant incremental capital expenditures. Gathering systems are operated at design pressures that maximize the total throughput from all connected wells. Through a mechanical process known as compression, volumes of natural gas at a given pressure are compressed to a sufficiently higher pressure, thereby allowing those volumes to be delivered into a higher pressure downstream pipeline to be brought to market.

        Processing and Treating.    Once the natural gas has been gathered, it is usually treated to remove impurities such as water, carbon dioxide, nitrogen and hydrogen sulfide. These impurities must be removed for the natural gas to meet the specifications for transportation on interstate and intrastate pipelines. Additionally, natural gas containing significant amounts of NGLs must be processed to remove these heavier hydrocarbon components. NGLs not only interfere with pipeline transportation, but are also valuable commodities once removed from the natural gas stream and fractionated into their key components. Gas processors typically charge for these services under three different types of contracts: (i) fee-based arrangements, in which the service provider receives a fee for each unit of natural gas gathered and compressed at the wellhead and an additional fee per unit of natural gas treated or processed at its facility; (ii) percent-of-proceeds arrangements, in which the service provider typically remits to the producers either a percentage of the proceeds from the sale of residue gas and/or NGLs or a percentage of the actual residue gas and/or NGLs at the outlet of the plant; or (iii) keep-whole arrangements, in which the service provider keeps 100% of the NGLs produced, and the processed natural gas, or value of the gas, is returned to the producer. Since some of the gas is used and removed during processing, the processor compensates the producer for the amount of gas used and removed in processing by supplying additional gas or by paying an agreed-upon value for the gas utilized. Our assets do not currently include processing and treating facilities.

        Fractionation.    NGL fractionation facilities separate mixed NGL streams into discrete components such as ethane, propane, normal butane, isobutane and natural gasoline. Fractionation is accomplished by controlling the temperature and pressure of the stream of mixed NGLs in order to take advantage of the different boiling points of separate components. The discrete NGLs are then marketed to end-users where they are utilized in various industrial processes such as enhanced oil recovery and the fabrication of petroleum and chemical products. Our assets do not currently include fractionation operations.

        Transportation.    The transportation of natural gas involves the movement of pipeline-quality natural gas from gathering systems (and, to the extent necessary, processing and treating facilities) to wholesalers and end-users, including industrial plants and LDCs. The transportation of natural gas may be accomplished through header system transmission pipelines or long-haul transmission pipelines or both.

        Header system transmission pipelines are characterized as networks of medium to large-diameter high pressure pipelines that connect local gathering systems to large-diameter high pressure long-haul transmission pipelines through multiple interconnects. Header system transmission pipelines typically do not transport natural gas long distances. Our transmission and storage system is a header system transmission pipeline.

        Long-haul transmission pipelines generally span considerable distances, consist of large-diameter high pressure pipelines and have few interconnects with other gathering and transmission systems. In fact, many long-haul transmission pipelines are designed to transport natural gas from one receipt point to one delivery point.

        Through compression, header system transmission pipelines and long-haul transmission pipelines are operated at design pressures that maximize the total throughput.

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        The concentration of natural gas production in a few regions of the U.S. generally requires transportation pipelines to cross state borders to meet national demand. These pipelines are referred to as interstate pipelines and are primarily regulated by federal agencies or commissions, including the FERC. Pipelines that transport natural gas produced and consumed wholly within one state are generally referred to as intrastate pipelines. Intrastate pipelines are primarily regulated by state agencies or commissions.

        Storage.    Natural gas storage plays an important role in maintaining the reliability of natural gas supplies needed to meet the demands of consumers. Storage facilities are also utilized by pipelines to manage imbalances caused by LDCs, natural gas producers and independent natural gas marketing and trading companies in connection with the execution of their trading strategies. Storage allows for the warehousing of natural gas and is used to inject excess production during periods of low demand (typically warmer months) and to withdraw natural gas during periods of high demand (typically colder winter months).

Transportation and Storage Services Contractual Arrangements

        There are two basic forms of service provided in the transportation and storage of natural gas, as described below:

        Firm.    Firm transportation service obligates customers to pay a fixed reservation charge for reserving an agreed upon amount of pipeline capacity, regardless of the actual pipeline capacity used, and a usage charge when a customer uses the capacity it has reserved under these firm transmission contracts. In addition, firm service transmission customers are typically charged an overrun usage charge when the level of natural gas they deliver exceeds their reserved capacity. Firm storage contracts involve the reservation of a specific amount of storage capacity, including injection and withdrawal rights, and generally include a capacity reservation charge based on the amount of capacity being reserved plus an injection and/or withdrawal usage charge based on the volumes actually injected or withdrawn relative to their total reserved capacity. In addition, firm service storage customers are typically charged an overrun usage charge when the level of natural gas withdrawn exceeds a customer's maximum daily withdrawal limit.

        Interruptible.    Interruptible transportation and storage service is typically short term in nature and is generally used by customers that either do not need firm service or have been unable to contract for firm service. These customers are assessed a usage fee for the volume of natural gas actually transported or stored. The obligation to provide this service is limited to available capacity not otherwise used by firm service customers. Unlike customers receiving firm services, customers receiving services under interruptible contracts are not guaranteed capacity on the pipeline or at the storage facility.

Market Fundamentals

        Both total energy supply and demand are projected to grow in coming decades. Population is one key determinant of energy consumption through its influence on demand for travel, housing, consumer goods and services. The EIA anticipates the total U.S. population will increase by 25% from 2010 to 2035. The EIA forecasts energy consumption to increase 10% over the same period. A review of other supply and demand elements follows.

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Natural Gas Consumption

        Natural gas is a significant component of energy consumption in the United States. According to the EIA, natural gas consumption accounted for approximately 25% of all energy used in the United States in 2010. Natural gas consumption is expected to grow 10% from 25 Tcf in 2010 to 27 Tcf by 2035. The following charts illustrate expected energy consumption by fuel source in 2035 as compared to 2010.

Energy Consumption by Fuel Source: 2010 and 2035

Source: EIA, Annual Energy Outlook 2012 (January 2012).

        Forecasts published by the EIA and other industry sources anticipate that long-term domestic demand for natural gas will continue to grow, and that the historical trend of growth in natural gas demand from seasonal and weather-sensitive consumption sectors will continue. These forecasts are supported by various factors, including (i) expectations of continued growth in the U.S. gross domestic product, which has a significant influence on long-term growth in natural gas demand; (ii) an increased likelihood that regulatory and legislative initiatives regarding domestic carbon policy will drive greater demand for cleaner burning fuels like natural gas; (iii) increased acceptance of the view that natural gas is a clean and abundant domestic fuel source that can lead to greater energy independence for the United States by reducing its dependence on imported petroleum; (iv) the emergence of low-cost natural gas shale developments, which suggest ample supplies and which are expected to keep natural gas prices low relative to crude oil prices, making the commodity attractive as a feedstock; and (v) continued growth in electricity generation from intermittent renewable energy sources, primarily wind and solar energy, for which natural-gas fired generation is a logical back-up power supply source.

        The majority of fuel switching is occurring in electric power generation where coal-fired plants are being replaced with cleaner burning fuel sources. However, as a result of more rapid increases in generation from natural gas and renewable fuels, coal's share of the total generation mix is projected to

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fall from 45% to 39% from 2010 to 2035. Over the same period, the share of generation from natural gas is projected to increase from 24% in 2010 to 27% in 2035.

Electricity Generation by Fuel Source: 1990-2035

Source: EIA, Annual Energy Outlook 2012 (January 2012).

        In addition to increasing domestic consumption, domestic natural gas consumers will also compete for supply with foreign natural gas consumers. According to the EIA, the U.S. is expected to become a net exporter of LNG starting in 2016 and an overall net exporter of natural gas in 2021. The EIA estimates that LNG capacity of 1.1 Bcfe/d starting in 2016 will double by 2019. This shift from being a net importer of natural gas to a net exporter of natural gas is driven by the increased use of LNG in markets outside North America, strong domestic production, and relatively low U.S. natural gas prices in comparison with other global markets. Additionally, the EIA estimates that imports from Alaska will continue to decrease from 358 Bcf in 2010 to 231 Bcf in 2035 due to high capital costs and low natural gas wellhead prices making it uneconomical to proceed with future Alaskan pipeline projects to the lower 48 states in addition to increased consumption by Alaskan natural gas users. The following chart illustrates the trend of overall domestic natural gas net imports shifting to net exports after 2021.

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Imports and Exports of Natural Gas: 2010-2035

Source: EIA, Annual Energy Outlook 2012 (January 2012).

Natural Gas Production

        In response to increased domestic energy consumption, total domestic energy production is projected to grow significantly over the next 25 years. The EIA estimates that total domestic energy production will increase by 25%, from 75.5 to 94.6 quadrillion Btu, and natural gas production will increase by 29%, from 22.1 to 28.5 quadrillion Btu, between 2010 to 2035. The chart below shows the total production for fuel sources through 2035.

Energy Production by Domestic Fuel Source: 2010-2035

Source: EIA, Annual Energy Outlook 2012 (January 2012).

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        Domestic natural gas consumption today is satisfied primarily by production from conventional and unconventional onshore and offshore production in the lower 48 states, and is supplemented by production from historically declining pipeline imports from Canada, imports of LNG from foreign sources, and some Alaska production. In order to maintain current levels of U.S. natural gas supply and to meet the projected increase in demand, new sources of domestic natural gas must continue to be developed to offset natural depletion associated with existing production.

        Over the past several years, a fundamental shift in production has emerged with the contribution of natural gas from unconventional resources (defined by the EIA as natural gas produced from shale formations and coalbeds) increasing from 9.5% of total U.S. natural gas supply in 2000 to 32% in 2010. According to the EIA, during the three-year period from January 15, 2007 through December 15, 2010 domestic production of natural gas increased by an average of approximately 3.8% per annum, largely due to continued development of shale resources. The emergence of shale plays has resulted primarily from advances in horizontal drilling and hydraulic fracturing technologies, which have allowed producers to extract significant volumes of natural gas from these plays at cost-advantaged per unit economics versus most conventional plays.

        As the depletion of conventional onshore and offshore resources continues, natural gas from unconventional resource plays is forecasted to fill the void and continue to gain market share from higher-cost sources of natural gas. As shown in the graph below, natural gas production from the major shale formations is forecast to provide the majority of the growth in domestically produced natural gas supply, increasing to approximately 49% in 2035 as compared with 23% in 2010. The increase in natural gas production from 2010 to 2035 results primarily from continued exploration and development of shale gas resources. Shale gas is the largest contributor to production growth, while production from tight sands, coalbed methane deposits, and offshore waters remains relatively stable.

Natural Gas Production by Source, 1990-2035

Source: EIA, Annual Energy Outlook 2012 (January 2012).

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        The abundance of natural gas shale production as well as the divergence between U.S. domestic and international prices for natural gas has caused a renewed interest in exporting domestic natural gas through LNG export terminals. While these projects take many years to develop, some domestic producers and foreign consumers view them as attractive opportunities to improve their respective economics and provide for an alternative source of demand for natural gas.

North American Midstream Infrastructure Buildout

        The advent of shale gas is projected to cause a continued build-out of gathering and pipeline infrastructure to support the additional supply. According to ICF International, approximately 43 Bcf per day of incremental natural gas pipeline capacity is needed to accommodate the increasing natural gas supply necessary to meet market demands from 2011 to 2035. Areas with growing shale production, such as the Marcellus Shale in the Northeast, will require significant amounts of new gathering lines. ICF International expects $186 billion of natural gas capital expenditures from 2010 to 2035, and approximately 50% of the total capital is expected to be spent on new transmission lines. The following chart illustrates the cumulative capital expenditures needed from 2010 to 2035.

Annual Infrastructure Capital Expenditures 2010-2035

Source: ICF International, North American Midstream Infrastructure through 2035—A Secure Energy Future (June 2011)

Overview of the Marcellus Shale Region

        The Marcellus Shale is the most expansive natural gas shale play in the United States, spanning six states in the northeastern United States. According to the EIA, dry gas production in the Northeast region (including the Marcellus Shale) is expected to nearly double from 2009 to 2035. The majority of the increase comes from the Marcellus shale gas play, which has an estimated technically recoverable resource base of about 141 trillion cubic feet.

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        As depicted below, the shale play is a Devonian age formation underlying much of the Appalachian region and spanning six states in the northeastern United States. The drilling activity is currently concentrated in two core regions of the Marcellus shale: northeast Pennsylvania which contains mostly dry gas production and southwest Pennsylvania and northern West Virginia, which contains natural gas and some NGLs.

Marcellus Shale Gas Play, Appalachian Basin

Source: U.S. Energy Information Administration (June 2011)

        The Marcellus Shale is a black, organic rich shale formation located at depths between 5,000 and 8,500 feet, covering approximately 54,000 square miles at an average net thickness of 50 feet to 200 feet. The western portion has a higher organic content but is shallower and thinner, while the east section is relatively deeper and thicker, with lower organic content. The shallow depth of the Marcellus, its low permeability and expansive size have made it a top unconventional exploration target. Recent advancements in both horizontal drilling and hydraulic stimulation have produced promising results. These developments have resulted in increased leasing and drilling activity in the area, primarily focusing on natural gas and condensate.

        The first commercial well in the Marcellus Shale was drilled and completed in 2005 in Pennsylvania. According to Drillinginfo's Production Data Platform (HPDI), a service that provides drilling and permitting data, 9,952 wells have been permitted in Pennsylvania and West Virginia in the Marcellus Shale since the beginning of 2005 and 4,255 of the approved wells have been drilled. In 2011, 1,955 wells were drilled in the Marcellus Shale, making it one of the most active and prominent shale gas plays in the United States, and active, widespread drilling in this area is expected to continue. During 2011, there were more than 70 operators active in the play.

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        According to Wood Mackenzie, Marcellus Shale production is expected to more than double from 2011 to 2015. Continued technological advances in drilling will also help contribute to the large expected production growth over the next ten years, as depicted in the below chart.

Marcellus Shale Natural Gas Production

Source: Wood Mackenzie (December 2011)

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BUSINESS

Overview

        We are a growth-oriented limited partnership formed by 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 43% 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 nine months ended September 30, 2011, approximately 65% 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 $1.6 billion in midstream infrastructure since January 1, 2007 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 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 December 31, 2011, 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% of our total revenues for the nine months ended September 30, 2011. As of December 31, 2011, the weighted average remaining contract life based on total revenues for our firm transmission and storage contracts was approximately 10 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.

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        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 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. Revenues associated with our gathering system, all of which were generated under interruptible gathering service contracts, represented approximately 15% of our total revenues for the nine months ended September 30, 2011.

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. While we will review acquisition opportunities from third parties as they become available, we expect that the majority of our most significant opportunities will be sourced from EQT's existing portfolio of midstream assets or from expansion projects or acquisitions that EQT undertakes in the future as it builds additional midstream assets in support of its production growth. For a description of EQT's retained midstream asset portfolio, please read "—Our Relationship with EQT."



•

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. We will evaluate organic expansion and greenfield construction opportunities in existing and new markets that we believe will increase the volume of transmission, storage and gathering capacity subscribed on our system. We are currently executing on expansion projects that we believe will increase the

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capacity of our transmission and storage system by approximately 550 BBtu per day at a total cost of approximately $60 million. Please see "—Our Assets—Internal Growth Projects."

•

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. We anticipate that organic growth projects that we pursue, or any assets we acquire from EQT, will be constructed in a manner that leverages economies of scale to allow for incremental third party volumes in excess of capacity amounts needed by EQT Production.



•

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        % 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

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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. According to Wood Mackenzie, Marcellus Shale production is expected to more than double from 2011 to 2015. We believe that our positioning in this area will provide us with significant opportunities to grow organically and through acquisitions.



•

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 nine months ended September 30, 2011, approximately 65% 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. The weighted average remaining contract life based on total revenues for our firm transmission and storage contracts was approximately 10 years as of December 31, 2011.



•

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 and those described below, we believe that our operational flexibility will allow us to continue to attract suppliers and increase the utilization of our assets.



—

Low-cost capacity expansion. We believe that there are a number of projects that could be undertaken to selectively increase capacity on segments of the pipeline with limited capital expenditures in order to service the growth needs of producers and end use customers. For example, we are investing approximately $29 million at our Blacksville Compressor Station to create 200 BBtu of incremental firm transmission capacity.



—

Diversity of delivery options. In addition to the five interconnects with interstate pipelines, our transmission and storage system also services four LDCs through over 130 delivery interconnects. We believe that this diversity of end-user markets and access to on-system storage provides an attractive alternative to natural gas suppliers in the Marcellus Shale.



—

System balancing. The number of storage pools and their location provides us with numerous options to provide balancing services to producers and LDCs. We provide producers with basic balancing service as part of their current service agreements. We believe additional balancing services may become necessary as more natural gas supply enters the system and new delivery markets are added to the system.



•

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

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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.

        In order to facilitate production growth in its areas of operation, EQT has invested $1.6 billion in midstream infrastructure since January 1, 2007. EQT has announced a capital expenditure forecast of $365 million for its midstream segment in 2012, inclusive of our projected capital expenditures. As it expands its exploration and production operations in the Marcellus Shale into areas that are currently underserviced by midstream infrastructure, we expect EQT will develop, either independently or in partnership with us, additional midstream assets to provide takeaway capacity for expected production growth.

        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        % 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."

        We believe that our relationship with EQT is advantageous for the following reasons:

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EQT is a leader among exploration and production companies in the Appalachian Basin.  EQT's reserve base spanned 3.5 million acres as of December 31, 2011, of which approximately 530,000 acres are located in the Marcellus Shale. EQT's total proved reserves have more than doubled over the past five years. 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. In part due to this focus on the Marcellus Shale, EQT's production increased by 43% for the year ended December 31, 2011 to 198.8 Bcfe, 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 Production is focused on continuing its significant organic reserve and production growth through its drilling program.



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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:



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Sunrise Pipeline project.    EQT will retain ownership of the 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

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Greene County, Pennsylvania. In addition, the Sunrise Pipeline project will include connecting to a new delivery point with Texas Eastern Transmission in Greene County and constructing the Jefferson compressor station, which will provide 314 BBtu per day of additional firm capacity to the system at an estimated cost of approximately $220 million, approximately $160 million of which is expected to be expended through March 31, 2012. Furthermore, the Jefferson compressor station can be expanded to provide in aggregate over 470 BBtu per day of additional firm capacity. EQT currently anticipates that this system through the addition of low-cost compression, including the expanded Jefferson compressor station, will be fully developed over the next several years.
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." An application requesting the FERC to grant us the authority to transfer ownership of the Sunrise Pipeline to EQT and to lease the facilities is currently pending.

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Other retained midstream assets.    At the completion of this offering, EQT will retain certain gathering systems in Kentucky, Pennsylvania, Virginia and West Virginia. EQT's retained midstream asset base in these areas consists of approximately 8,300 miles of gathering pipelines that gathered approximately 630 BBtu of natural gas per day for the year ended December 31, 2011. 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.



The following table provides information regarding EQT's retained gathering assets:

The following gathering systems, which will be retained by EQT, provide gathering services to EQT Production acreage located in the Marcellus Shale and interconnect with our transmission and storage system, which is EQT Production's primary outlet for produced natural gas in this area:

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Jupiter gathering system.    The Jupiter gathering system is located in Greene County, Pennsylvania and consists of 32 miles of gathering pipe. The Jupiter system includes the Jupiter and Callisto compressor stations with an aggregate compression of 21,315 HP. This system provides gathering and compression services to EQT Production and delivers gas into our transmission and storage system. As of December 31, 2011, the

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gathering system had approximately 430 MMcf per day of gathering capacity. We believe that EQT plans to expand this system in 2012 by adding 14 miles of gathering pipe and 100 MMcf per day of capacity.

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Saturn gathering system.    The Saturn gathering system is located in a liquids-rich area of the Marcellus Shale in Doddridge County, West Virginia and consists of 24 miles of gathering pipe. The Saturn system includes the Saturn compressor station with 6,080 HP of compression. This system provides gathering and compression services to EQT Production and delivers gas into our transmission and storage and gathering systems. As of December 31, 2011, the Saturn gathering system had approximately 80 MMcf per day of gathering capacity. We believe that EQT plans to expand this system in 2012 by adding 10 miles of gathering pipe, 60 MMcf per day of gathering capacity, and 5,770 HP of compression.



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Pluto gathering system.    The Pluto gathering system is located in Taylor County, West Virginia and consists of 6 miles of gathering pipe. The Pluto system includes the Pluto compressor station with 2,370 HP of compression. This system provides gathering and compression services to EQT Production and delivers gas into our transmission and storage system. As of December 31, 2011, the Pluto gathering system had approximately 60 MMcf per day of gathering capacity.



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Mercury gathering system.    We believe that EQT intends to construct a new gathering system in 2012 called the Mercury gathering system, in a liquids-rich area of the Marcellus Shale in Wetzel County, West Virginia, which we expect will consist of 12 miles of gathering pipe, 100 MMcf per day of gathering capacity, and approximately 9,470 HP of compression. We believe this system will deliver natural gas into our transmission and storage system.



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Future developed 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, most of the executive officers and certain 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 Fiduciary Duties."

Our Assets

        We own and operate a header system transmission pipeline, which we refer to as our transmission and storage system and is comprised of a FERC-regulated interstate pipeline with approximately 700 miles of transmission and storage lines, 14 associated natural gas storage reservoirs and 19 compressor units, and our gathering system, consisting of approximately 2,100 miles of low-pressure gathering lines and 31 compressor units, that has multiple delivery interconnects with our transmission and storage system and Dominion Transmission's interstate pipeline. Our assets are located in southwestern Pennsylvania and northern West Virginia. The following table provides information

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regarding our transmission, storage and gathering assets as of September 30, 2011 and for the periods indicated:

        Our transmission, storage and gathering rates and services are subject to regulation by the FERC, which reviews and approves the tariff that establishes our rates, cost recovery mechanisms and terms and conditions of service. The rates established under our tariff are a function of our costs of providing services to customers, including a reasonable return on invested capital. The authority of the FERC also extends to certification and construction of transmission and storage facilities, including, but not limited to acquisitions, facility maintenance, pipeline extensions such as the Sunrise Pipeline project and abandonment of services and facilities. Our gathering assets are not subject to FERC certification and construction authority.

        The following table provides a revenue breakdown of our contracts by business segment for the nine months ended September 30, 2011:

Transmission and Storage

        Revenues associated with our transmission and storage system represented approximately 85% of our total revenues for the nine months ended September 30, 2011. We operate transmission and storage assets throughout the Appalachian Basin serving western Pennsylvania and northern West Virginia as depicted on the map below, including approximately 700 miles of FERC-regulated transmission pipelines. Our transmission and storage system interconnects with interstate pipelines operated by Texas Eastern Transmission LP, Dominion Transmission, Columbia Gas Transmission, LLC, Tennessee Gas Pipeline Company, L.L.C. and National Fuel Gas Supply Corporation. In addition, we have 14 natural gas storage reservoirs with approximately 400 MMcf per day of peak withdrawal capability and 63 Bcf of storage capacity, of which 32 Bcf is working gas.

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Transmission and Storage Customers

        We provide natural gas transmission services for EQT and third parties, predominantly consisting of creditworthy LDCs, marketers, producers and commercial and industrial users. Our transmission system serves not only adjacent markets in Pennsylvania and West Virginia but also provides our customers access to high-demand end-user markets in the Mid-Atlantic and Northeastern United States through our 854 BBtu per day of delivery interconnect capacity with major interstate pipelines. We provide storage services to a broad mix of customers including marketers and LDCs.

        Our primary transportation and storage customer is EQT. For the nine months ended September 30, 2011, EQT and its affiliates accounted for approximately 83% of transmission revenues and 77% of storage revenues. Other than EQT, no customer accounted for more than 10% of our total transmission and storage revenue for the nine months ended September 30, 2011. Our other principal transmission customers include XTO Energy Inc., a wholly-owned subsidiary of ExxonMobil Corporation and PDC Mountaineer, LLC.

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Transmission and Storage Contracts

        Contract Type.    We generally provide transmission and storage services in two manners: firm service and interruptible service. We provide a significant portion of our transportation and storage services through firm service agreements. We generally do not take title to the natural gas transported or stored for our customers, which mitigates our direct commodity price risk.

        Approximately 1.0 TBtu per day of our transmission capacity and 24 TBtu of our storage capacity, respectively, was subscribed under firm transmission and storage contracts with a weighted average remaining contract life based on contracted revenues of approximately 10.0 years for transmission contracts and 3.9 years for storage contracts as of December 31, 2011.

        Firm Transmission.    Firm transmission contracts obligate our customers to pay a fixed monthly charge to reserve an agreed upon amount of pipeline capacity regardless of the actual pipeline capacity used by a customer during each month, which we refer to as a monthly reservation charge. In addition to monthly reservation charges, we also collect usage charges when a firm transmission customer uses the capacity it has reserved under these firm transmission contracts. These charges are assessed on the actual volume of natural gas transported on the transmission system.

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

        We have several long-term firm transmission and storage contracts with Equitable Gas Company, a local distribution company and wholly-owned subsidiary of EQT. Equitable Gas Company has firm transmission agreements with winter peak firm transmission capacity of 448 BBtu per day and firm storage capacity of 13.5 TBtu, each of which expire in March of 2016. In addition, EQT Energy LLC, or EQT Energy, a wholly-owned marketing subsidiary of EQT, has a binding precedent agreement for firm transmission capacity of up to 450 BBtu per day to transport gas produced by EQT Production Company into the interstate transmission market. In accordance with the binding precedent agreement, we and EQT Energy have entered into a negotiated rate firm transmission agreement for 210 BBtu per day of firm transmission capacity with a primary term through June of 2023. The reserved capacity under this contract will increase periodically to a peak capacity of 450 BBtu pursuant to a binding precedent agreement, however, this peak capacity will be split between service on our transmission and storage system and service on the Sunrise Pipeline, which we will operate under a lease agreement with EQT pursuant to the terms of our tariff, such that 260 BBtu will be provided on our transmission and storage system and 190 BBtu will be provided on the Sunrise Pipeline. In addition to the contracts with affiliates of EQT, we have also entered into binding precedent agreements and associated long-term negotiated rate firm transmission agreements for an aggregate of 166 BBtu per day of firm transmission capacity with our three largest third-party customers, including XTO Energy Inc. and PDC Mountaineer, LLC.

        Interruptible Service.    Our transmission and storage system also derives a small portion of its revenues through interruptible service contracts under which our customers pay fees based on their actual utilization of assets for transmission and storage services. In addition to general interruptible transmission and storage contracts, firm transmission customers are charged an overrun usage charge when the level of natural gas received for delivery from a firm transmission customer exceeds its reserved capacity. Customers who have executed interruptible contracts are not assured capacity or service on the applicable pipeline and storage facilities. To the extent that physical capacity that is contracted for firm service is not being fully utilized or there is excess capacity that has not been contracted for firm service, the system can allocate such capacity to interruptible services. We also

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provide natural gas "park and loan" services to assist customers in managing short-term gas surpluses or deficits. Under our park and loan service agreements, customers are charged a usage fee based on the quantities of natural gas they store in (park), or borrow from (loan), our facilities.

        Contract Rates.    As of December 31, 2011, approximately 56% of our contracted transmission firm capacity was subscribed at the maximum recourse rate allowed under our tariff. The remaining 44% of contracted transmission firm capacity was subscribed by customers under negotiated rate agreements at rates generally above the maximum recourse rate under the tariff, some of which is under contracts pending execution with respect to binding precedent agreements and the remaining contracts have been filed with and accepted by the FERC.

Transmission and Storage Competition

        Competition for natural gas transmission and storage volumes is primarily based on rates, customer commitment levels, timing, performance, commercial terms, reliability, services levels, location, reputation and fuel efficiencies. Our principal competitors in our natural gas transmission and storage market include companies that own major natural gas pipelines, such as Dominion Transmission, Columbia Gas Transmission Corp., National Fuel Gas Company and Texas Eastern Transmission, LP. In addition, we compete with companies such as Caiman Energy, M3 Midstream, LLC, Williams Midstream, Superior Pipeline Company, LLC and MarkWest Energy Partners, who are building high pressure gathering facilities that are not subject to FERC jurisdiction to move volumes to interstate pipelines. EQT also owns and in the future may construct natural gas transmission pipelines and high-pressure gathering facilities. The major pipeline natural gas transmission companies mentioned above also have existing storage facilities connected to their transmission systems that compete with certain of our storage facilities. Pending and future construction projects, if and when brought on line, may also compete with our natural gas transmission and storage services and many of our competitors have capital and other resources far greater than ours. These projects may include FERC-certificated expansions and greenfield construction projects.

Transmission and Storage Natural Gas Supply

        During the nine months ended September 30, 2011, approximately 70% of natural gas supply, excluding storage withdrawals for our transmission and storage system, was produced by EQT. Our transmission and storage system has access to multiple natural gas supply sources in the Marcellus Shale, providing us with opportunities to access newly developed natural gas supplies.

        During the nine months ended September 30, 2011, third party natural gas production volumes on our transmission and storage system were on average approximately 55 BBtu per day, more than double the approximately 21 BBtu per day during the year ended December 31, 2008. Our top third-party producers by volume were XTO Energy Inc. and PDC Mountaineer, LLC. The following table shows the growth of our third-party volumes from 2008 through September 30, 2011:

Gathering

        Revenues associated with our gathering system represented approximately 15% of our total revenues for the nine months ended September 30, 2011. Through a network of approximately

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2,100 miles of gathering pipelines and 31 compressor units with approximately 23,000 horsepower of installed capacity, we gather natural gas from wells located in 15 counties in West Virginia and three counties in Pennsylvania as shown on the map below. Our gathering system is composed of pipelines ranging in diameter from one inch to 20 inches. We currently gather natural gas from approximately 2,400 active receipt points with delivery into our transmission and storage system and Dominion Transmission's gathering and interstate pipeline systems.

        Throughput volume on our gathering system was 30.4 TBtu for the year ended December 31, 2010 and 20.6 TBtu for the nine months ended September 30, 2011.

Gathering Customers

        Our gathering system currently has approximately 2,400 receipt points with a number of natural gas producers, including EQT, EXCO Resources, Inc., XTO Energy Inc., Chevron, Energy Corporation of America, Stone Energy, CONSOL Energy and Waco Oil and Gas. The largest producer of natural gas delivered to our gathering system is EQT, which represented 45% of the 83 BBtu per day of natural gas supplied to the gathering system in 2010 and approximately 45% of the 75 BBtu per day of natural gas supplied to the gathering system for the nine months ended September 30, 2011. We have

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gathering agreements conforming to our tariff with marketers and distribution companies that purchase natural gas from receipt points on our system for delivery to the interstate pipeline market, including EQT Energy, Equitable Gas Company and Dominion Field Services.

        Dominion Field Services generally provides any necessary processing for the gas gathered by our gathering system. In connection with our sale of certain processing plants to Dominion Field Services in 2000, we entered into an agreement with a primary term through December 31, 2014 pursuant to which Dominion Field Services is obligated to process any wet gas we deliver to certain processing facilities up to the individual operating capacity of each plant. During the nine months ending September 30, 2011, 74% of the natural gas supplied to our gathering system was processed by Dominion Field Services. Our gathering customers are responsible for the costs associated with treating and processing natural gas in order to meet pipeline specifications, and are required to have processing agreements in place with Dominion Field Services or another processor as a prerequisite to receiving transportation service on our gathering system.

Gathering Contracts

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

Gathering Competition

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

Internal Growth Projects

        Our internal growth and system upgrade projects include:

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Blacksville Compressor Station Project.  The Blacksville Compressor Station project involves the construction of a new booster compressor station in Monongalia County, West Virginia, including two compressor units with an aggregate compression of approximately 9,470 horsepower, at an estimated total cost of approximately $29 million, of which we expect approximately $10 million to have been expended by March 31, 2012. This project will enable us to provide approximately 200 BBtu per day of incremental firm transmission capacity to third parties, 100 BBtu of which is already under contract. The project has received all regulatory approvals, including FERC approval, and we expect it will be completed and placed into service in the third quarter of 2012.



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Low Pressure East Expansion Project.  This project involves uprating or replacing 26 miles of existing Equitrans transmission pipeline in Greene, Washington and Allegheny counties, Pennsylvania, at a cost of approximately $22 million, of which we expect approximately $0.1 million to have been expended by March 31, 2012. We expect to complete and place this project into service in the third quarter of 2013. When complete, this project will triple the current maximum allowable operating pressure of the pipeline, thereby creating approximately 150 BBtu per day of incremental firm transmission capacity on the system.



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New Delivery Interconnect Expansion.  The project includes three new interconnects, two with Texas Eastern Transmission and one with Peoples Natural Gas Company. The first Texas Eastern

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interconnect has daily capacity of over 300 BBtu and was placed into service in the fourth quarter of 2011. The second Texas Eastern interconnect will have 200 BBtu of immediate incremental daily capacity and is expected to be placed into service in the first quarter of 2012. Combined, the interconnects with Texas Eastern will have over 800 BBtu per day of capacity at an estimated cost of approximately $10 million, all of which is expected to be expended by March 31, 2012. The Peoples Natural Gas Company Ginger Hill interconnect is expected to have 250 BBtu per day of interconnect capacity at an estimated cost of approximately $2 million, of which we expect approximately $0.3 million to have been expended by March 31, 2012. We expect this project will be placed into service in the fourth quarter of 2012.

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Hartson Compression Upgrade.  In order to provide additional operational flexibility and increase transmission capacity, we are upgrading the existing compression at the Hartson Compressor Station to install emissions reduction technology, and adding 750 horsepower of compression. The project is estimated to cost approximately $8 million, all of which is expected to have been expended by March 31, 2012 and we expect it will be placed into service in the second quarter of 2012.

Regulatory Environment

FERC Regulation

        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 system operates under a tariff approved by the FERC that establishes rates, cost recovery mechanisms, and the terms and conditions of service to our customers. Generally, the FERC's authority extends to:

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



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certification and construction of new interstate transportation and storage facilities;



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



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maintenance of accounts and records;



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relationships between pipelines and certain affiliates;



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terms and conditions of services and service contracts with customers;



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depreciation and amortization policies;



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acquisition and disposition of interstate transportation and storage facilities; and



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initiation and discontinuation of interstate transportation and storage services.

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

        FERC regulates the rates and charges for transportation and storage in interstate commerce. Under the NGA, rates charged by interstate pipelines must be just and reasonable. FERC's cost-of-service regulations generally limit the maximum recourse rates for transportation and storage services to the cost of providing service plus a reasonable rate of return. In each rate case, the FERC must approve service costs, the allocation of costs, the allowed rate of return on capital investment,

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rate design, and other rate factors. A negative determination on any of these rate factors could adversely affect our business, financial condition, results of operations and ability to make distributions.

        The maximum recourse rate that we may charge for our services is established through FERC's ratemaking process. Generally, the maximum filed recourse rates for interstate pipelines are based on the cost of providing that service including recovery of and a return on the pipeline's actual prudent historical cost of investment. Key determinants in the ratemaking process include the depreciated capital costs of the facilities, the costs of providing service, the allowed rate of return and volume throughput and contractual capacity commitment assumptions. The maximum applicable recourse rates and terms and conditions for service are set forth in the pipeline's FERC approved tariff. Rate design and the allocation of costs also can impact a pipeline's profitability. While the ratemaking process establishes the maximum rate that can be charged, interstate pipelines such as our transmission and storage system are permitted to discount their firm and interruptible rates without further FERC authorization down to the variable cost of performing service, provided they do not "unduly discriminate." In addition, pipelines are allowed to negotiate different rates with their customers, as described below.

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

        Our interstate pipeline may also use "negotiated rates" which, in theory, could involve rates above or below the "recourse rate" or with a different rate structure, provided that the affected customers are willing to agree to such rates and that the FERC has approved the negotiated rate agreement. A prerequisite for allowing the negotiated rates is that negotiated rate customers must have had the option to take service under the pipeline's maximum recourse rates. As of December 31, 2011 approximately 44% of our system's contracted firm transportation capacity was committed under such "negotiated rate" contracts. Each negotiated rate transaction is designed to fix the negotiated rate for the term of the firm transportation agreement and the fixed rate is generally not subject to adjustment for increased or decreased costs occurring during the contract term.

        FERC regulations also extend to the terms and conditions set forth in agreements for transportation and storage services executed between interstate pipelines and their customers. These service agreements are required to conform, in all material respects, with the form of service agreements set forth in the pipeline's FERC-approved tariff. 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.

FERC Regulation of Gathering Rates and Terms of Service

        While the FERC does not generally regulate the rates and terms of service over facilities determined to be performing a natural gas gathering function, 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 transportation. We maintain rates and terms of service in our tariff for unbundled gathering services performed on our gathering facilities in connection with our transportation service. Just as with rates

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and terms of service for transmission and storage services, our rates and terms of services for our gathering system may be challenged by complaint and are subject to prospective change by the FERC. Rate increases and changes to terms and conditions of service we propose for our gathering service may be protested and such increases or changes may ultimately be rejected by the FERC.

2005 Rate Case

        We filed our most recent rate case with FERC in the first quarter of 2005. A comprehensive settlement supported by all parties was approved by FERC in the second quarter of 2006. The settlement provided for a black box cost of service and rate base settlement with an assumed pre-tax return of fifteen percent. The settlement also included a provision allowing us to recover 7.1 Bcf of storage base gas through our transmission fuel retention percentage and established tariff language to place a Pipeline Safety Tracker into effect. Under the settlement, we agreed not to file for new rates for a period of three years which expired in the second quarter of 2009. The settlement does not require us to file for new rates within any specified time period.

FERC Standards of Conduct for Transmission Providers

        In October 2008, the FERC issued new standards of conduct regulations for transmission providers that conduct transmission transactions with an affiliate engaging in marketing functions. After a series of rehearing orders issued between October 2009 and April 2011, the new regulations are now final. Because it conducts transactions with marketing affiliates, Equitrans is currently subject to FERC's standards of conduct regulations. FERC's standards of conduct require transmission providers to treat all transmission customers, affiliated and non-affiliated, on a not unduly discriminatory basis.

FERC Policy Statement on Income Tax Allowances

        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 taxes 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. 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.

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Energy Policy Act of 2005

        On August 8, 2005, Congress enacted the Energy Policy Act of 2005, or EP Act 2005. Among other matters, EP Act 2005 amends the NGA, to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations prescribed by FERC and provides FERC with additional civil penalty authority. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-manipulation provision of EP Act 2005, and subsequently denied rehearing. The rules make it unlawful: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted "in connection with" gas sales, purchases or transportation subject to FERC jurisdiction. EP Act 2005 also amends the NGA and the NGPA to give FERC authority to impose civil penalties for violations of these statutes up to $1,000,000 per day per violation for violations occurring after August 8, 2005. In connection with this enhanced civil penalty authority, FERC issued a policy statement on enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers, including factors to be considered in determining the appropriate enforcement action to be taken. The anti-manipulation rule and enhanced civil penalty authority reflect an expansion of FERC's NGA enforcement authority. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. The natural gas industry historically has been heavily regulated. Accordingly, we cannot assure you that present policies pursued by FERC and Congress will continue.

Natural Gas Price Transparency

        In April 2007, the FERC issued a notice of proposed rulemaking, or NOPR, regarding price transparency provisions of the NGA and EP Act 2005. In the notice, the FERC proposed to revise its regulations to, among other things, require that buyers and sellers of more than a de minimis volume of natural gas report both annual and daily numbers and volumes of relevant transactions to the FERC. In December 2007, the FERC issued Order No. 704 implementing the annual reporting provisions of the NOPR with minimal changes to the original proposal, except the daily reporting requirement was separated from the annual reporting requirement and proposed in a new NOPR, eventually resulting in Order No. 720, which required certain major non-interstate natural gas pipelines to post daily scheduled volume information and design capacity for certain points. Order No. 704 became effective in February 2008. The FERC issued two orders on rehearing on Order No. 704 in 2008, and following a technical conference in March 2010, the FERC issued an order clarifying the reporting requirements in June 2010. Equitrans is subject to these annual reporting requirements. On October 24, 2011, the United States Court of Appeals for the Fifth Circuit vacated Order No. 720 as applied to non-interstate pipelines on the grounds that they exceeded FERC's authority under the NGA. We do not know whether FERC will seek rehearing of this decision from the Fifth Circuit or petition for writ of certiorari to the United States Supreme Court, or whether it will otherwise modify its regulations relating to natural gas reporting in the future.

Pipeline Safety and Maintenance

        Our interstate natural gas pipeline system is subject to regulation by the Pipeline and Hazardous Materials Safety Administration, or PHMSA, office of the U.S. Department of Transportation, or DOT. PHMSA has established safety requirements pertaining to the design, installation, testing, construction,

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operation and maintenance of gas pipeline facilities, including requirements that pipeline operators develop a written qualification program for individuals performing covered tasks on pipeline facilities and implement pipeline integrity management programs. These integrity management plans require more frequent inspections and other preventative measures to ensure safe operation of oil and natural gas transportation pipelines and some gathering lines in "high consequence areas," such as high population areas or facilities that are hard to evacuate and areas of daily concentrations of people.

        Notwithstanding the investigatory and preventative maintenance costs incurred in our performance of customary pipeline management activities, we may incur significant additional expenses if anomalous pipeline conditions are discovered or more stringent pipeline safety requirements are implemented. For example, on August 25, 2011, PHMSA published an advanced notice of proposed rulemaking in which the agency is seeking public comment on a number of changes to its natural gas transmission pipeline regulations contained in 49 C.F.R. Part 192 including: (i) modifying the definition of high consequence areas; (ii) strengthening integrity management requirements as they apply to existing regulated operators and could be applied to currently exempt operators should the exemptions be removed; (iii) strengthening or expanding various non-integrity pipeline management standards relating to such matters as valve spacing, automatic or remotely-controlled valves, corrosion protection, and gathering lines; and (iv) adding new regulations to govern the safety of underground natural gas storage facilities including underground storage caverns and injection withdrawal wells piping that are not currently regulated under the Part 192 regulations. PHMSA has specifically indicated an intent in this rulemaking to address the need for standards governing the safety of underground natural gas storage facilities. Public comments on these matters were submitted to PHMSA in December 2011, and a final rule from PHMSA is forthcoming.

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

        States are largely preempted by federal law from regulating pipeline safety but may assume responsibility for enforcement of federal interstate pipeline safety regulations and inspection of interstate pipelines. For example, a Pennsylvania statute was enacted in 2012 authorizing the Pennsylvania Public Utilities Commission to enforce federal regulations applicable to intrastate gathering lines. In practice, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant problems in complying with any state laws and regulations which are determined to be applicable to our operations. Our natural gas pipelines have inspection and compliance programs designed to maintain compliance with federal and state pipeline safety and pollution control requirements.

        We believe that our operations are in substantial compliance with all existing federal, state, and local pipeline safety laws and regulations and that our compliance with such laws and regulations will not have a material adverse effect on our business, financial position, or results of operations but we can provide no assurance that the adoption of new laws and regulations such as those proposed by PHMSA on August 25, 2011 will not result in significant added costs that could have such a material adverse effect in the future.

        Our operations are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. The OSHA hazard communication standard, the EPA community "right-to-know" regulations and comparable state laws and regulations require that information be maintained concerning hazardous

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materials used or produced in our operations and that this information be provided to employees, state and local government authorities, and citizens. Our operations are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above specified thresholds, or any process which involves 10,000 pounds or more of a flammable liquid or gas in one location. We believe that our operations are in material compliance with all applicable laws and regulations relating to worker health and safety.

Pipeline Safety Tracker

        Our Pipeline Safety Tracker ("PSCT") is a cost recovery mechanism for the recovery of qualifying costs incurred by us under the Pipeline Safety Improvement Act of 2002 (Pipeline Safety Improvement Act). The qualifying costs recoverable through the PSCT include a rate of return, taxes and depreciation associated with capital investments and actual operating and maintenance expenses incurred under the act. The PSCT surcharge is a usage charge expressed in dollars per MMBtu and is assessed to firm and interruptible transmission service customers. We are required to track all expenses and capital investments associated with the Pipeline Safety Act made on and after September 1, 2005. We make annual filings with the FERC to adjust the PSCT surcharge to reconcile actual historic costs incurred against actual PSCT revenues collected and to include new qualifying costs incurred over the past calendar year.

        Since the inception of the PSCT surcharge in September 2005 through the end of 2011, we have invested approximately $56 million and recognized approximately $29 million of revenues associated with the PSCT. During the nine months ended September 30, 2011, we recognized $6.1 million of revenues associated with the PSCT.

Environmental Matters

General

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

        We believe that compliance with existing federal, state and local environmental laws and regulations will not have a material adverse effect on our business, financial position, or results of operations. Nevertheless, environmental regulatory programs continue to evolve and future regulations may place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. The following is a discussion of some of the environmental laws and regulations that are applicable to our natural gas transportation, storage and gathering activities.

Waste Management

        Some of our operations generate hazardous and non-hazardous solid wastes that are subject to the federal Resource Conservation and Recovery Act, or RCRA, and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and non-hazardous solid wastes. For instance, RCRA imposes on generators of hazardous wastes standards for the accumulation and storage of hazardous wastes, as well as recordkeeping and reporting

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requirements applicable to hazardous waste storage and disposal activities. State laws govern the handling, storage and disposal of non-hazardous wastes.

Site Remediation

        The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as "Superfund," and comparable state laws and regulations impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons considered to be responsible for the release of hazardous substances into the environment. These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the transport or disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the U.S. Environmental Protection Agency, or EPA, and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

        We currently own or lease properties that for many years have been used for the transportation, compression, storage or gathering of natural gas. While we have no knowledge of historical releases or spills at these operations, due to the age of the facilities there may be legacy environmental contamination at one or more of these facilities. Under CERCLA, RCRA and analogous state laws, if contamination is found we could be required to remediate contaminated property, including groundwater contamination, whether from prior owners or operators or other historic activities or spills; or perform corrective actions to prevent future contamination.

Air Emissions

        The Clean Air Act, or CAA, and comparable state laws regulate emissions of air pollutants from various industrial sources, including compressor stations, and also impose various air emission monitoring and reporting requirements. Such laws and regulations may require pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in an increase of existing air emissions; application for, and strict compliance with, air permits containing various emissions and operational limitations; or the utilization of specific emission control technologies to limit emissions. The requirement to obtain a permit before commencing construction on a new or modified source of air emissions must be incorporated into the project schedule and can be subject to permitting delays which may delay the development of the project. Failure to comply with the permitting requirements could result in monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. On occasion, we have received notices of violations and associated fines for alleged non-compliance with air emission permits, none of which have had a material adverse effect on our operating results or financial conditions.

        We may incur expenditures in the future for air pollution control equipment in connection with obtaining or maintaining operating permits and approvals for air emissions. For instance, on July 28, 2011, the EPA proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA's proposed rule package includes standards to address emissions of sulfur dioxide and volatile organic compounds from new sources, and a separate set of emission standards to address hazardous air pollutants from existing oil and natural gas production and processing activities. The proposed rules would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment in addition to leak detection requirements for natural gas processing plants. The EPA has received public

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comment and is expected to take final action on them by April 3, 2012. If adopted as proposed, these rules could require modifications to our operations or the installation of new equipment if we undertake activities subject to the rules. However, we do not believe that any such future requirements will have a material adverse affect on our operations.

Water Discharges

        The Clean Water Act, or CWA, and analogous state laws impose strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including wetlands, unless authorized by permit. Spill prevention, control and countermeasure requirements under federal law and some state laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies may impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. The Equitrans facilities do not discharge wastewater and thus we do not have any CWA discharge permits. Where applicable, Equitrans is in compliance with federal and state spill prevention, control and countermeasure requirements.

        The Oil Pollution Act of 1990, or OPA, which amends and augments the CWA, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the United States. OPA and its associated regulations also impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. For example, operators of certain oil and gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance to cover costs that could be incurred in responding to a spill. The OPA assigns joint and several, strict liability, without regard to fault, to each liable party for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affect by an oil spill.

National Environmental Policy Act

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

Endangered Species Act

        The federal Endangered Species Act, or ESA, restricts activities that may affect endangered and threatened species or their habitats. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unprotected species as being

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endangered or threatened could cause us to incur additional costs or become subject to operating restrictions in areas where the species are known to exist.

Employee Health and Safety

        We are subject to a number of federal and state laws and regulations, including OSHA and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community "right-to-know" regulations and comparable state laws and regulations require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

Climate Change

        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.

        Pursuant to the GHG Reporting Rule, we will submit a GHG emission report from our facilities in 2012. Currently none of our facilities are subject to the permitting requirements for GHGs. In the future, we may be subject to GHG permitting requirements if any new facilities or modifications to existing facilities result in an increase of GHG emissions above the permitting thresholds. If subject to GHG permitting requirements, there could be increased permit times or additional expenses for emission controls. It is not expected that the additional permit times or facility expenses will have a material adverse effect on our operating results or financial conditions.

Seasonality

        Because a high percentage of our revenues are derived from firm capacity reservation fees under long-term contracts, our revenues are not generally seasonal in nature, nor are they typically affected by weather and price volatility during the term of the contracts. Weather impacts natural gas demand for power generation and heating purposes, which in turn influences the value of transmission and storage across our systems. Price volatility also affects gas prices, which in turn influences drilling and production. Peak demand for natural gas typically occurs during the winter months, caused by the heating load.

Title to Properties and Rights-of-Way

        Our real property falls into two categories: (i) parcels that we own in fee and (ii) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or

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governmental authorities, permitting the use of such land for our operations. Portions of the land on which our pipelines and facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our pipelines and facilities are located are held by us pursuant to surface leases between us, as lessee, and the fee owner of the lands, as lessors. We have leased or owned much of these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates or fee ownership to such lands. We believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses, and we have no knowledge of any material challenge to our title to such assets or their underlying fee title.

        However, there are certain lands within our storage pools as to which we do not currently have real property rights. We have identified the lands as to which we believe we must obtain such rights and are in the midst of a program to acquire such rights. Since the beginning of this program in 2009, we have successfully acquired such rights for approximately 12,129 acres out of a total 32,818 acres necessary, and we expect to acquire the remainder within the next five years. In accordance with our FERC license, the geological formations within which our permitted storage facilities are located cannot be used by third parties in any way that would detrimentally affect our storage operations and we have the power of eminent domain with respect to the acquisition of necessary real property rights to use such storage facilities. We believe the cost to acquire such rights will be approximately $6 million over the next five years.

        Some of the leases, easements, rights-of-way, permits and licenses to be transferred to us at the closing of this offering require the consent of the grantor of such rights, which in certain instances is a governmental entity. We expect to obtain, prior to the closing of this offering, sufficient third-party consents, permits and authorizations for the transfer of the assets necessary to enable us to operate our business in all material respects as described in this prospectus.

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

Insurance

        We generally share insurance coverage with EQT, for which we will reimburse EQT pursuant to the terms of the omnibus agreement. Our insurance program includes general liability insurance, auto liability insurance, workers' compensation insurance and property insurance. Our general partner will maintain director and officer liability insurance under a separate policy from EQT's corporate director and officer insurance. In addition, we have procured a separate general liability policy. All insurance coverage is in amounts which management believes are reasonable and appropriate.

Facilities

        EQT leases its corporate offices in Pittsburgh, Pennsylvania. We pay a proportionate share of the costs to operate the building to EQT pursuant to the omnibus agreement. Please read "Certain Relationships and Related Transactions—Omnibus Agreement."

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Employees

        We do not have any employees. We are managed and operated by the directors and officers of our general partner. All of our executive management personnel will be employees of our general partner or EQT or an affiliate of EQT and will devote the portion of their time to our business and affairs that is required to manage and conduct our operations. Under the terms of the omnibus agreement, we will reimburse EQT for the provision of various general and administrative services for our benefit, for direct expenses incurred by EQT on our behalf and for expenses allocated to us as a result of our becoming a public entity. Please read "Certain Relationships and Related Transactions—Omnibus Agreement."

Legal Proceedings

        In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against us. While the amounts claimed may be substantial, we are unable to predict with certainty the ultimate outcome of such claims and proceedings. We accrue legal or other direct costs related to loss contingencies when actually incurred. We have established reserves which we believe to be appropriate for pending matters, and after consultation with counsel and giving appropriate consideration to available insurance, we believe that the ultimate outcome of any matter currently pending against us will not, individually or in the aggregate, materially affect our financial position, results of operations or liquidity.

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MANAGEMENT

Management of EQT Midstream Partners, LP

        Our general partner, EQT Midstream Services, LLC, will manage our operations and activities on our behalf through its directors and officers. Our general partner is not elected by our unitholders and will not be subject to re-election in the future. Directors of our general partner will oversee our operations. Unitholders will not be entitled to elect the directors of our general partner, which will all be appointed by EQT, or directly or indirectly participate in our management or operations. However, our general partner owes a fiduciary duty to our unitholders. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly non-recourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are non-recourse to it.

        The directors of our general partner will oversee our operations. Upon the closing of this offering, our general partner will have at least five directors. We intend to increase the size of the board of directors to seven members following the closing of this offering. EQT will appoint all members to the board of directors of our general partner, and, when the size of our board increases to seven directors, we will have at least three directors who are independent as defined under the independence standards established by the NYSE. The NYSE does not require a publicly traded limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation or a nominating and corporate governance committee. We are, however, required to have an audit committee of at least three members within twelve months of the date our common units are first traded on the NYSE, and all of our audit committee members are required to meet the independence and experience tests established by the NYSE and the Exchange Act.

        In compliance with the requirements of the New York Stock Exchange, upon the effective date of this prospectus, EQT will have appointed at least one independent member to the board of directors of our general partner. EQT will appoint a second independent director within 90 days of the date of this prospectus and a third independent director within 12 months of the date of this prospectus. The independent members of the board of directors of our general partner will serve as the initial members of the audit committee of the board of directors of our general partner.

        In identifying and evaluating candidates as possible director-nominees of our general partner, EQT will assess the experience and personal characteristics of the possible nominee against the following individual qualifications, which EQT may modify from time to time:

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Possesses integrity, competence, insight, creativity and dedication together with the ability to work with colleagues while challenging one another to achieve superior performance;



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Has attained prominent position in his or her field of endeavor;



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Possesses broad business experience;



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Has ability to exercise sound business judgment;



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Is able to draw on his or her past experience relative to significant issues facing us;



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Has experience in our industry or in another industry or endeavor with practical application to our needs;



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Has sufficient time and dedication for preparation as well as participation in board and committee deliberations;



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Meets such standards of independence and financial knowledge as may be required or desirable; and



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Possesses attributes deemed appropriate given the then current needs of the board.

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        All of our general partner's executive officers will be employees of EQT and will devote such portion of their productive time to our business and affairs as is required to manage and conduct our operations. Our executive officers will manage the day-to-day affairs of our business and conduct our operations. We will also utilize a significant number of employees of EQT to operate our business and provide us with general and administrative services. We will reimburse EQT for allocated expenses of personnel who perform services for our benefit, and we will reimburse EQT for allocated general and administrative expenses. Please read " Executive Compensation—Reimbursement of Expenses of Our General Partner."

Directors and Executive Officers of Our General Partner

        The following table shows information for the directors and executive officers of our general partner as of February 1, 2012, each of whom has held their position since our inception on January 18, 2012.

        Our directors hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers.

        Mr. Porges is currently the Chairman, President, and Chief Executive Officer of EQT and has held such positions since May 2011. Mr. Porges was President, Chief Executive Officer and Director of EQT from April 2010 through May 2011 and President, Chief Operating Officer and Director of EQT from February 2007 through April 2010. From January 2005 through February 2007, Mr. Porges was the Vice Chairman and Executive Vice President, Finance and Administration of EQT. Mr. Porges has served as a member of EQT's Board since May 2002.

        Mr. Conti is currently the Senior Vice President and Chief Financial Officer of EQT and has held such positions since February 2007. Mr. Conti was Vice President and Chief Financial Officer of EQT from January 2005 to February 2007 and he was also Treasurer of EQT beginning in 2000 until January 2006.

        Mr. Crawford is currently the Senior Vice President and President, Midstream, Commercial and Distribution of EQT and has held such positions since April 2010. Mr. Crawford was Senior Vice President Midstream and Distribution from January 2008 to April 2010. From February 2007 to December 2007, Mr. Crawford was Senior Vice President, and President, Equitable Utilities and from February 2004 to February 2007 he was Vice President, and President, Equitable Utilities.

        Mr. Gardner is currently the General Counsel and Vice President, External Affairs of EQT and has held such positions since April 2008. From January 2008 to March 2008, Mr. Gardner was Managing Director External Affairs and Labor Relations of EQT. Mr. Gardner was also Senior Counsel—Director Employee and Labor Relations from March 2004 to December 2007.

        Ms. Bone is currently the Vice President and Corporate Controller of EQT and has held such positions since July 2007. Ms. Bone was Vice President and Controller of Equitable Utilities from December 2004 until July 2007.

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Board Leadership Structure

        Our chief executive officer currently serves as the chairman of the board. The board of directors of our general partner has no policy with respect to the separation of the offices of chairman of the board of directors and chief executive officer; rather, that relationship is defined and governed by the limited liability company agreement of our general partner, which permits the same person to hold both offices. Directors of the board of directors of our general partner are designated or elected by EQT. Accordingly, unlike holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement.

Board Role in Risk Oversight

        Our corporate governance guidelines will provide that the board of directors of our general partner is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. This responsibility will be largely satisfied by the audit committee, which is responsible for reviewing and discussing with management and our registered public accounting firm our major risk exposures and the policies management has implemented to monitor such exposures, including our financial risk exposures and risk management policies.

Committees of the Board of Directors

Audit Committee

        Our general partner will have an audit committee comprised of at least three directors who meet the independence and experience standards established by the NYSE and the Exchange Act. The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee.

Conflicts Committee

        At least two members of the board of directors of our general partner will serve on our conflicts committee to review specific matters that may involve conflicts of interest in accordance with the terms of our partnership agreement. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. Any matters approved by the conflicts committee in good faith will be conclusively deemed to be approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.

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EXECUTIVE COMPENSATION

        We and our general partner were formed in January 2012. Accordingly, our general partner has not accrued any obligations with respect to management incentive or retirement benefits for its directors and executive officers for the 2011 fiscal year or prior periods. Because the executive officers of our general partner are employed by EQT, compensation of the executive officers, other than the long-term incentive plan benefits described below, will be set by EQT. The executive officers of our general partner will continue to participate in employee benefit plans and arrangements sponsored by EQT, including plans that may be established in the future. Our general partner has not entered into any employment agreements with any of its executive officers. Our board of directors may grant awards to our executive officers, key employees of EQT who support our operations and/or our independent directors pursuant to the long-term incentive plan described below following the closing of this offering; however, the board has not yet made any determination as to the number of awards, the type of awards, the recipients of awards or when the awards would be granted.

Compensation Discussion and Analysis

        We do not directly employ any of the persons responsible for managing our business and we do not have a compensation committee. We are managed by our general partner, the executive officers of which are employees of EQT. The compensation of EQT's employees that perform services on our behalf (other than the long-term incentive plan benefits described below), including our general partner's executive officers, will be approved by EQT. Our reimbursement for the compensation of executive officers is governed by the omnibus agreement and will be based on EQT's methodology used for allocating general and administrative expenses to us. Under the omnibus agreement, none of EQT's long-term incentive compensation expense will be allocated to us. However, we will be responsible for paying the long-term incentive compensation expense associated with our long-term incentive plan described below.

        We were formed in 2012. Accordingly, we are not presenting any compensation for historical periods. Compensation paid or awarded by us in 2012 with respect to our executive officers will reflect only the portion of compensation paid by EQT that is allocated to us pursuant to EQT's allocation methodology and subject to the terms of the omnibus agreement. EQT has ultimate decision making authority with respect to the compensation of our executive officers, other than compensation under our long-term incentive plan. The following discussion relating to compensation paid by EQT is based on information provided by EQT and does not purport to be a complete discussion and analysis of EQT's executive compensation philosophy and practices. The elements of compensation discussed below, other than equity based compensation, and EQT's decisions with respect to determinations on payments, will not be subject to approvals by the board of directors of our general partner. Awards under our long-term incentive plan will be approved by the board of directors of our general partner.

        With respect to compensation objectives and decisions regarding our named executive officers for 2012, EQT will approve the compensation of our named executive officers based on its compensation philosophy, which is to reward performance through a combination of annual and long-term incentives. EQT typically consults with compensation consultants and reviews market data for determining relevant compensation levels and compensation program elements. EQT intends to consult with compensation consultants with respect to determining 2012 compensation for the named executive officers in a manner consistent with its current compensation philosophy. All compensation determinations are discretionary and are, as noted above, subject to EQT's decision-making authority.

        The elements of EQT's compensation program discussed below are intended to provide an incentive package designed to provide competitive compensation opportunities to align and drive employee performance in support of EQT's business strategies as well as our own and to attract, motivate and retain highly talented individuals with the skills and competencies required by EQT and

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us. Generally, the total compensation packages of EQT's executive officers are weighted in favor of performance-based compensation through both annual and long-term incentive pay. Except for any awards made to our executive officers under our long-term incentive plan described below, we expect that compensation for our executive officers in 2012 will continue to be structured under EQT's compensation program.

        The primary elements of EQT's compensation program are a combination of base salary and annual and long-term, incentives. For 2012, elements of compensation for our named executive officers are expected to be the following:

•

annual base salary;



•

annual performance-based incentives;



•

awards under EQT's long-term incentive plans; and



•

EQT's other benefits, including welfare and retirement benefits, perquisites, severance benefits and change of control benefits, plus other benefits on the same basis as other eligible EQT employees.

        In addition, the board of directors of our general partner may grant awards to our executive officers under our long-term incentive plan.

        The annual performance-based incentive payments, in combination with base salaries and long-term incentive awards, are intended to yield competitive total cash compensation levels for the executive officers and drive performance in support of EQT's business strategies as well as our own. The portion of any performance-based annual incentive payments allocable to us will be based on EQT's methodology used for allocating general and administrative expenses.

        For a more detailed summary of EQT's executive compensation program and the benefits provided thereunder, please read "Compensation Discussion and Analysis" in EQT's proxy statement for its annual meeting of shareholders, which was filed with the SEC on March 14, 2011.

Compensation of Directors

        Officers or employees of EQT or its affiliates who also serve as directors of our general partner will not receive additional compensation for such service. Our general partner anticipates that its directors who are not also officers or employees of EQT or its affiliates will receive compensation for attending meetings of the board of directors and committee meetings. The amount of such compensation has not yet been determined. In addition, each non-employee director will be reimbursed for out-of-pocket expenses in connection with attending such meetings. Each director will be fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law pursuant to a director indemnification agreement and our partnership agreement.

Long-Term Incentive Plan

        Our general partner intends to adopt the EQT Midstream Services, LLC Long-Term Incentive Plan for officers, directors and employees of our general partner, and any of its affiliates who perform services for us. We may issue our executive officers long-term equity based awards under the plan, which awards will be intended to compensate the officers based on the performance of our common units and their continued employment during the vesting period, as well as align their long-term interests with those of our unitholders. We will be responsible for the cost of awards granted under the long-term incentive plan to be adopted by us.

        The long-term incentive plan will consist of the following components: unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards

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and unit awards. The purpose of awards under the long-term incentive plan is to provide additional incentive compensation to employees providing services to us, and to align the economic interests of such employees with the interests of our unitholders. The long-term incentive plan will limit the number of units that may be delivered pursuant to vested awards to                         common units. Common units cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The plan will be administered by the board of directors of our general partner or a committee thereof, which we refer to as the plan administrator. We currently expect that the board of directors of our general partner will be designated as the plan administrator.

        The plan administrator may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. The plan administrator also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of the participant without the consent of the participant. The plan will expire on the earliest of (i) the date common units are no longer available under the plan for grants, (ii) termination of the plan by the plan administrator or (iii) the date 10 years following its date of adoption.

Restricted Units

        A restricted unit is a common unit that vests over a period of time and during that time is subject to forfeiture. The plan administrator may make grants of restricted units containing such terms as it shall determine, including the period over which restricted units will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial or other performance objectives. Restricted units will be entitled to receive quarterly distributions during the vesting period.

Phantom Units

        A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the plan administrator, cash equivalent to the value of a common unit. The plan administrator may make grants of phantom units under the plan containing such terms as the plan administrator shall determine, including the period over which phantom units granted will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial objectives.

Unit Options

        The long-term incentive plan will permit the grant of options covering common units. The plan administrator may make grants containing such terms as the plan administrator shall determine. Unit options must have an exercise price that is not less than the fair market value of the common units on the date of the grant. In general, unit options granted will become exercisable over a period determined by the plan administrator.

Unit Appreciation Rights

        The long-term incentive plan will permit the grant of unit appreciation rights. A unit appreciation right is an award that, upon exercise, entitles the participant to receive the excess of the fair market value of a common unit on the exercise date over the exercise price established for the unit appreciation right. Such excess will be paid in cash or common units. The plan administrator may make grants of unit appreciation rights containing such terms as the plan administrator shall determine. Unit

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appreciation rights must have an exercise price that is not less than the fair market value of the common units on the date of grant. In general, unit appreciation rights granted will become exercisable over a period determined by the plan administrator.

Distribution Equivalent Rights

        The long-term incentive plan will permit the grant of distribution equivalent rights, or DERs, as a stand-alone award or with respect to phantom unit awards or other awards under the long-term incentive plan. DERs entitle the participant to receive cash or additional awards equal to the amount of any cash distributions made by us with respect to a common unit during the period the right is outstanding. Payment of a DER issued in connection with another award may be subject to the same vesting terms as the award to which it relates or different vesting terms, in the discretion of the plan administrator.

Other Unit-Based Awards

        The long-term incentive plan will permit the grant of other unit-based awards, which are awards that are based, in whole or in part, on the value or performance of a common unit. Upon vesting, the award may be paid in common units, cash or a combination thereof, as provided in the grant agreement.

Unit Awards

        The long-term incentive plan will permit the grant of common units that are not subject to vesting restrictions. Unit awards may be in lieu of or in addition to other compensation payable to the individual.

Change in Control; Termination of Service

        Awards under the long-term incentive plan will vest and/or become exercisable, as applicable, upon a "change in control" of us or our general partner, unless provided otherwise by the plan administrator at the time of grant. The consequences of the termination of a grantee's employment, consulting arrangement or membership on the board of directors will be determined by the plan administrator in the terms of the relevant award agreement.

Source of Units

        Common units to be delivered pursuant to awards under the long-term incentive plan may be common units acquired by our general partner in the open market, from any other person, directly from us or any combination of the foregoing. If we issue new common units upon the grant, vesting or payment of awards under the long-term incentive plan, the total number of common units outstanding will increase.

Reimbursement of Expenses of Our General Partner

        Our general partner will not receive any management fee or other compensation for its management of our partnership under the omnibus agreement with EQT or otherwise. Under the terms of the omnibus agreement, we will reimburse EQT for the provision of various general and administrative services for our benefit. We will also reimburse EQT for direct expenses incurred on our behalf and expenses allocated to us as a result of our becoming a public entity. The partnership agreement provides that our general partner will determine the expenses that are allocable to us. Please read "Certain Relationships and Related Transactions—Omnibus Agreement."

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

        The following table sets forth the beneficial ownership of our units that will be owned upon the consummation of this offering by:

•

each person known by us to be a beneficial owner of more than 5% of the units;



•

each of the directors of our general partner;



•

each of the named executive officers of our general partner; and



•

all directors and executive officers of our general partner as a group.

        The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a "beneficial owner" of a security if that person has or shares "voting power," which includes the power to vote or to direct the voting of such security, or "investment power," which includes the power to dispose of or to direct the disposition of such security. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

        Percentage of total units to be beneficially owned after this offering is based on            common units outstanding. The table assumes that the underwriters' option to purchase additional units is not exercised.

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        The following table sets forth, as of February 1, 2012, the number of shares of common stock of EQT owned by each of the executive officers and directors of our general partner and all directors and executive officers of our general partner as a group.

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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

        After this offering, EQT will indirectly own                  common units and                  subordinated units representing a         % limited partner interest in us. In addition, our general partner will own a 2.0% general partner interest in us and the incentive distribution rights.

Distributions and Payments to Our General Partner and Its Affiliates

        The following information summarizes the distributions and payments made or to be made by us to our general partner and its affiliates in connection with our formation, ongoing operation and any liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm's-length negotiations.

Formation Stage

        The aggregate consideration received by our general partner and its affiliates for the contribution of certain assets and liabilities to us:

•

common units



•

subordinated units



•

general partner units representing a 2.0% general partner interest;



•

all of the incentive distribution rights; and



•

$             million cash payment from the proceeds of this offering.

Operational Stage

        Distributions of available cash to our general partner and its affiliates.    We will generally make cash distributions 98.0% to unitholders pro rata, including our general partner and its affiliates as holders of an aggregate of                         common units, all of the subordinated units and 2.0% to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our general partner will be entitled to increasing percentages of the distributions, up to 48.0% of the distributions above the highest target level.

        Payments to our general partner and its affiliates.    Our general partner does not receive a management fee or other compensation for managing us. Our general partner and its affiliates are reimbursed, however, for all direct and indirect expenses incurred on our behalf. Our general partner determines the amount of these expenses. In addition we will reimburse EQT and its affiliates for the payment of certain operating expenses and for the provision of various general and administrative services for our benefit.

        Withdrawal or removal of our general partner.    If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read "The Partnership Agreement—Withdrawal or Removal of Our General Partner."

Liquidation Stage

        Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

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Agreements Governing the Transactions

        We have entered into or will enter into various documents and agreements with EQT that will effect the transactions relating to our formation, including the vesting of assets in us and our subsidiaries, and the application of the proceeds of this offering. While we believe our agreements with EQT are on terms no less favorable to either party than those that could have been negotiated with an unaffiliated party, these agreements will not be the result of arm's-length negotiations. All of the transaction expenses incurred in connection with our formation transactions will be paid from the proceeds of this offering.

Omnibus Agreement

        Upon the closing of this offering, we will enter into an omnibus agreement with EQT, our general partner and certain of their affiliates that governs our relationship with them regarding the following matters:

•

our obligation to reimburse EQT and its affiliates for certain direct operating expenses they pay on our behalf;



•

our obligation to reimburse EQT and its affiliates for providing us corporate, general and administrative services and providing us operation and management services pursuant to the operation and management services agreement. Please read "—Operation and Management Services Agreement;"



•

EQT's obligation to indemnify us for losses relating to or arising from (i) certain preclosing environmental liabilities, (ii) certain title and rights-of-way matters, (iii) our failure to have certain necessary governmental consent and permits, (iv) certain preclosing tax liabilities, (v) assets previously owned by us and retained by EQT and its affiliates, including the Sunrise Pipeline, (vi) certain of our indemnification obligations associated with EQT's sale of the Big Sandy Pipeline to a third party, and (vii) certain plugging and abandonment obligations;



•

our obligation to indemnify EQT for losses attributable to the ownership or operation of our assets after the closing of this offering, except to the extent EQT is obligated to indemnify us for such losses pursuant to the Operation and Management Services Agreement with EQT, as described below under "—Operation and Management Services Agreement;" and



•

our use of the name "EQT" and related marks.

Reimbursement of General and Administrative Expense

        Under the omnibus agreement, EQT will, or will cause its affiliates to, perform centralized corporate, general and administrative services for us, such as legal, corporate recordkeeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, taxes and engineering. In exchange, we will reimburse EQT and its affiliates for the expenses incurred by them in providing these services, except for any expenses associated with EQT's long-term incentive programs. The omnibus agreement will further provide that we will reimburse EQT and its affiliates for our allocable portion of the premiums on any insurance policies covering our assets.

        We will also reimburse EQT for any additional state income, franchise or similar tax paid by EQT resulting from the inclusion of us (and our subsidiaries) in a combined state income, franchise or similar tax report with EQT as required by applicable law. The amount of any such reimbursement will be limited to the tax that we (and our subsidiaries) would have paid had we not been included in a combined group with EQT.

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Indemnification

        EQT's indemnification obligations to us will include the following:

•

Environmental.  For a period of three years after the closing of this offering, 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. The maximum liability of EQT for these indemnification obligations will not exceed $15 million and EQT will not have any obligation under these indemnification obligations until our aggregate losses exceed $250,000. EQT will have no indemnification obligations with respect to environmental or toxic tort claims made as a result of additions to, or modifications of, environmental laws promulgated after the closing of this offering.



•

Title.  For a period of three years after the closing of this offering, EQT will indemnify us for losses relating to our failure to have valid and indefeasible easement rights, rights-of-way, leasehold and/or fee ownership interests in and to the lands on which our assets are located, and such failure prevents us from using or operating our assets in substantially the same manner that our assets were used and operated immediately prior to the closing of this offering.



•

Governmental consents and permits.  For a period of three years after the closing of this offering, EQT will indemnify us for losses relating to our failure to have any consent or governmental permit where such failure prevents us from using or operating our assets in substantially the same manner that our assets were used and operated immediately prior to the closing of this offering.



•

Taxes.  Until 60 days after the expiration of any applicable statute of limitations, EQT will indemnify us for any income taxes attributable to operations or ownership of the assets prior to the closing of this offering, including any such income tax liability of EQT and its affiliates that may result from our formation transactions.



•

Plugging and abandonment liabilities.  EQT will assume from us, and indemnify us against, plugging and abandonment liabilities for certain identified wells.



•

Retained liabilities.  EQT will indemnify us for any liabilities, claims or losses relating to or arising from assets owned or previously owned by us and retained by EQT and its affiliates following the closing of this offering.

        In no event will EQT be obligated to indemnify us for any claims, losses or expenses or income taxes referred to in the first four bullets above to the extent either (i) reserved for in our financial statements as of December 31, 2011, or (ii) we recover any such amounts under available insurance coverage, from contractual rights or other recoveries against any third party or in the tariffs paid by the customers of our affected pipeline system.

        We will indemnify EQT for all losses attributable to the post-closing operations of the assets retained by us, to the extent not subject to EQT's indemnification obligations.

Competition

        Neither EQT nor any of its affiliates will be restricted, under either our partnership agreement or the omnibus agreement, from competing with us. EQT and any of its affiliates may acquire, construct or dispose of additional transportation and storage or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.

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Amendment and Termination

        The omnibus agreement can be amended by written agreement of all parties to the agreement. However, we may not agree to any amendment or modification that would, in the determination of our general partner, be adverse in any material respect to the holders of our common units without the prior approval of the conflicts committee. In the event of (i) a "change in control" (as defined in the omnibus agreement) of our general partner or EQT or (ii) the removal of EQT Midstream Services, LLC as our general partner in circumstances where (a) "cause" (as defined in our partnership agreement) does not exist and the common units held by our general partner and its affiliates were not voted in favor of such removal or (b) cause exists, the omnibus agreement (other than the indemnification provisions) will be terminable by EQT, and we will have a 90-day transition period to cease our use of the name "EQT" and related marks.

Operation and Management Services Agreement

        Upon the closing of this offering, we will enter into an operational services agreement with EQT Gathering, LLC, an indirect, wholly owned subsidiary of EQT, under which EQT Gathering, LLC, or EQT Gathering, will provide our pipelines and storage facilities with certain operational and management services, such as operation and maintenance of flow and pressure control, maintenance and repair of our pipeline and storage facilities, conducting routine operational activities, managing transportation and logistics, contract administration, gas control and measurement, engineering support and such other services as we and EQT Gathering may mutually agree upon from time to time. We will reimburse EQT Gathering for such services pursuant to the terms of the omnibus agreement as described above. Please read "—Omnibus Agreement."

        The operation and management services agreement will terminate upon the termination of the omnibus agreement. If a force majeure event prevents a party from performing required services, such party's obligations under the agreement with respect to such services will be suspended during the continuation of the force majeure event. These force majeure events include acts of God, strikes, lockouts or other industrial disturbances, wars, riots, fires, floods, storms, explosions, terrorist acts, breakage or accident to machinery or lines of pipe and inability to obtain or unavoidable delays in obtaining material or equipment and similar events or circumstances, so long as such events or circumstances are beyond the reasonable control of the party claiming force majeure and could not have been prevented by such party's reasonable diligence.

        Under the agreement, EQT Gathering will indemnify us from claims, losses or liabilities incurred by us, including third party claims, arising out of EQT Gathering's willful misconduct. We will indemnify EQT Gathering from any claims, losses or liabilities incurred by EQT Gathering, including any third-party claims, arising from the performance of the agreement, but not to the extent of losses or liabilities for which we will be indemnified by EQT Gathering. Neither party is liable for any consequential, incidental or punitive damages under the agreement, except to the extent such damages are included in a third party claim for which a party is obligated to indemnify the other party pursuant to the agreement. Neither party may assign its rights or obligations under the agreement without the prior written consent of the other party, which shall not be unreasonably withheld.

Contracts with Affiliates

Transportation Service and Precedent Agreements

        Equitable Gas Company and EQT Energy, each of which are wholly-owned subsidiaries of EQT, have contracted for an aggregate peak winter firm transmission capacity of 933 BBtu per day on our transmission and storage system, including the Sunrise Pipeline project, pursuant to firm contracts. All of Equitable Gas Company's agreements have a primary term through March of 2016 and are contracted at the maximum rate specified in our tariff, including two service agreements under our

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no-notice firm transportation rate schedule, which features a higher maximum tariff rate than our customary firm transportation service. EQT Energy has an agreement reserving 450 BBtu per day, which is contracted at a negotiated rate above the maximum rate allowed under our tariff with a primary term through June of 2023. The reserved capacity under this contract is currently 210 BBtu per day and will increase periodically until it reaches its peak capacity of 450 BBtu pursuant to a binding precedent agreement. This peak capacity will be split between service on our transmission and storage system and service on the Sunrise Pipeline, which we will operate under a lease agreement with EQT pursuant to the terms of our tariff, such that 260 BBtu will be provided on our transmission and storage system and 190 BBtu will be provided on the Sunrise Pipeline. These firm transportation agreements will automatically renew for one year periods upon the expiration of the primary term, subject to six months prior written notice by either party to terminate. In addition, we have also entered into an agreement with EQT Energy to provide interruptible transmission service, which is currently renewing automatically for one month periods, subject to 30 days prior written notice by either party to terminate. For the nine months ended September 30, 2011, our transportation agreements with EQT accounted for approximately 79% of the natural gas throughput on our transmission system and 83% of our transmission revenues. We expect that Equitable Gas Company will continue to renew their firm transmission agreements with us because the proximity of our assets to their operations and the current lack of competition in the area make us an economical choice.

Storage Agreements

        We have entered into four agreements with Equitable Gas Company to provide firm storage services. Of these firm storage service agreements, two are contracted under a rate schedule filed with our tariff that limits the maximum daily amount that may be withdrawn from storage by a customer to 1/115th of 110% of such customer's total annual storage quantity as specified in their service agreement. The remaining firm storage service agreements are contracted under a similar rate schedule that limits the maximum daily amount that may be withdrawn from storage by a customer to 1/60th of 110% of such customer's total annual storage quantity as specified in their service agreement. These agreements have a primary term through March of 2016 and will automatically renew for one year periods upon the expiration of the primary term, subject to 12 months prior written notice by either party to terminate. The aggregate annual storage capacity subscribed under these firm storage agreements with EQT is equal to 17 TBtu. In addition, we have also entered into an agreement with Equitable Gas Company to provide interruptible storage services with a primary term of one year, which will automatically renew for one month periods, subject to 30 days prior written notice by either party to terminate. For the nine months ended September 30, 2011, EQT accounted for approximately 77% of our storage revenues.

Gas Gathering Agreements

        We have entered into three gas gathering agreements with Equitable Gas Company and EQT Energy. These agreements have a primary term of one year and renew automatically for one month periods, subject to 30 days prior written notice by either party to terminate. Service provided under these gathering agreements is fee-based at the rate specified in our tariff for Appalachian gathering services. These gathering agreements accounted for approximately 63% of our gathering throughput for the nine months ended September 30, 2011. Approximately 71% of this throughput came from volumes of natural gas owned by EQT and the remainder was comprised of volumes from third parties.

EQT Corporation Guaranty

        EQT has entered into a guaranty agreement to guarantee all payment obligations, plus interest and any other charges, due and payable by EQT Energy to Equitrans pursuant to the agreements discussed

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above, up to an amount of $50 million. This guaranty will terminate on November 30, 2023 unless terminated earlier by EQT by providing 10 days' written notice.

Acreage Dedication

        Pursuant to an acreage dedication to us by EQT, effective as of March 1, 2011, we have the right to elect to transport, at a market or cost of service rate, all natural gas produced from wells drilled by EQT on the dedicated acreage, which is an area covering approximately 60,000 acres surrounding our storage assets in Allegheny, Washington and Greene counties in Pennsylvania and Wetzel, Marion, Taylor, Tyler, Doddridge, Harrison and Lewis counties in West Virginia. The acreage dedication is contained in a sublease agreement in which we granted to EQT all of the oil and gas interests, including the exclusive rights to drill, explore for, produce and market such oil and gas, we had received as part of certain of our oil and gas leasehold estates we use for gas storage and protection. Furthermore, if EQT acquires acreage with natural gas storage rights within the area of mutual interest established by the acreage dedication, then EQT will enter into an agreement with us to permit us to store natural gas on such acreage. Likewise, if we acquire acreage within the area of mutual interest with natural gas or oil production, development, marketing and exploration rights, such acreage will automatically become subject to EQT's rights under the acreage dedication.

Sunrise Pipeline Lease Agreement

        Contemporaneously with our transfer of the Sunrise Pipeline to EQT, we will enter into a lease agreement with EQT for the lease of the Sunrise Pipeline and we will operate the facilities as part of our transmission and storage system under the rates, terms, and conditions of our FERC-approved tariff. While this lease agreement will be effective upon the transfer of the Sunrise Pipeline, no lease payments will be due pursuant to this lease agreement until after the in-service date of the Sunrise Pipeline. The lease payment due in any given month will be the lesser of the following alternatives: (1) a revenue-based payment reflecting the revenues generated by the operation of the Sunrise Pipeline minus our actual costs of operating the Sunrise Pipeline and (2) a payment based on depreciation expense and pre-tax return on invested capital for the Sunrise Pipeline. The first alternative is designed to pass through to EQT the revenues we collect for service, including reservation charges and usage charges, on the Sunrise Pipeline net of our costs of operating and maintaining such facilities. This alternative is intended to protect us from adverse economic consequences in the event we do not subscribe all of the available capacity on the Sunrise Pipeline, a possibility that may persist for the first few years following the in-service date of the Sunrise Pipeline until production in the Marcellus Shale region ramps up. The second lease payment alternative is designed to reflect the actual cost of service to operate the Sunrise Pipeline.

        The lease agreement has a primary term of 15 years from the in-service date of the Sunrise Pipeline, unless EQT requests an early termination at its sole discretion. Upon termination of the lease agreement, we are required to purchase the Sunrise Pipeline at a price to be negotiated between the parties. We have filed an application with the FERC seeking approval for us to transfer the Sunrise Pipeline to EQT and for us to contemporaneously lease those facilities. We have also requested in this application that the FERC pre-grant approval for the termination of the lease agreement and our acquisition of the Sunrise Pipeline at the end of the primary term or such other time as EQT requests, which may be prior to the end of the primary term. In order to facilitate a pre-grant of FERC approval for such transfer and acquisition, the lease agreement requires EQT to transfer ownership of the Sunrise Pipeline to us at a price to be negotiated between the parties. If we cannot come to an agreement with EQT on the terms under which we will acquire the Sunrise Pipeline, the lease agreement will remain in full force and effect, beyond the primary term if necessary, until an agreement can be reached. If the FERC does not issue the pre-granted authority necessary for us to abandon the lease agreement and acquire the Sunrise Pipeline at the termination of the lease, we will

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be required to make a subsequent filing prior to the termination of the lease agreement to request specific authorization from the FERC to undertake these activities.

Review, Approval or Ratification of Transactions with Related Persons

        We expect that the board of directors of our general partner will adopt policies for the review, approval and ratification of transactions with related persons. We also anticipate that the board of directors of our general partner will adopt a written code of business conduct and ethics.

        The policy for the review, approval and ratification of transactions with related persons described above will be adopted in connection with the closing of this offering, and as a result the transactions described above were not reviewed under such policy.

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

        Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including EQT, on the one hand, and us and our limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders. Our partnership agreement contains provisions that specifically define our general partner's fiduciary duties to the unitholders. Our partnership agreement also specifically defines the remedies available to unitholders for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law. The Delaware Revised Uniform Limited Partnership Act, which we refer to as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.

        Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other, our general partner will resolve that conflict. Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of the board of directors of our general partner. An independent third party is not required to evaluate the fairness of the resolution.

        Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:

•

approved by the conflicts committee, although our general partner is not obligated to seek such approval;



•

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;



•

on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or



•

fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

        If our general partner does not seek approval from the conflicts committee and our general partner's board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points 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, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee of our general partner's board of directors may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to subjectively believe that he is acting in, or not opposed to, the interests of the partnership. Please read "Management—Committees of our Board of Directors—Conflicts Committee" for information about the conflicts committee of our general partner's board of directors.

        Conflicts of interest could arise in the situations described below, among others.

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Neither our partnership agreement nor any other agreement requires EQT to pursue a business strategy that favors us or utilizes our assets or dictates what markets to pursue or grow. EQT's directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of EQT, which may be contrary to our interests.

        Because some of the officers and directors of our general partner are also directors and/or officers of EQT, such directors and officers have fiduciary duties to EQT that may cause them to pursue business strategies that disproportionately benefit EQT or which otherwise are not in our best interests.

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not and will not be the result of arm's-length negotiations.

        Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm's-length negotiations. Our partnership agreement generally provides that any affiliated transaction, such as an agreement, contract or arrangement between us and our general partner and its affiliates, must be:

•

on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or



•

"fair and reasonable" to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).

        Our general partner or the conflicts committee determines, in good faith, the terms of any of these transactions.

        Our general partner and its affiliates have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically dealing with that use. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.

Our general partner's affiliates may compete with us and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

        Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than those incidental to its ownership of interests in us. However, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. EQT may acquire, construct or dispose of interstate pipeline, storage or other assets in the future without any obligation to offer us the opportunity to acquire those assets. In addition, under our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to the general partner and its affiliates. As a result, neither the general partner nor any of its affiliates have any obligation to present business opportunities to us.

Our general partner is allowed to take into account the interests of parties other than us, such as EQT, in resolving conflicts of interest.

        Our partnership agreement contains provisions that permissibly modify and reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. 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 or otherwise, free of contractual or fiduciary duties to us and our unitholders. This 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

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any interest of, or factors affecting, us, our affiliates or any limited partner. Examples of decisions that our general partner may make in its individual capacity include the allocation of corporate opportunities among us and our affiliates, the exercise of its limited call right, its voting rights with respect to the units it owns, whether to reset target distribution levels, and its determination whether or not to consent to any merger or consolidation of the partnership.

We do not have any officers or employees and rely solely on officers and employees of our general partner and its affiliates.

        Affiliates of our general partner conduct businesses and activities of their own in which we have no economic interest. There could be material competition for the time and effort of the officers and employees who provide services to our general partner.

        Most of the officers of our general partner are also officers and/or directors of EQT. These officers will devote such portion of their productive time to our business and affairs as is required to manage and conduct our operations. These officers are required to devote time to the affairs of EQT or its affiliates and are compensated by them for the services rendered to them. Our non-executive directors devote as much time as is necessary to prepare for and attend board of directors and committee meetings.

Our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under applicable Delaware law.

        In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might constitute breaches of fiduciary duty under applicable Delaware law. 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. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;



•

provides that the general partner shall not have any liability to us or our unitholders for decisions made in its capacity so long as such decisions are made in good faith;



•

generally provides that in a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner 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 is either on terms no less favorable to us than those generally being provided to or available from unrelated third parties or is "fair and reasonable" to us, considering the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us, then it will be presumed that in making its decision, the general partner or its conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption;



•

provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers or directors, as the cases may be, acted in bad faith or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

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

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

        Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought conflicts committee approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:

•

the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into securities of the partnership, and the incurring of any other obligations;



•

the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets;



•

the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets or the merger or other combination of us with or into another person;



•

the negotiation, execution and performance of any contracts, conveyances or other instruments;



•

the distribution of partnership cash;



•

the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;



•

the maintenance of insurance for our benefit and the benefit of our partners;



•

the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships;



•

the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;



•

the indemnification of any person against liabilities and contingencies to the extent permitted by law;



•

the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities; and



•

the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

        Please read "The Partnership Agreement" for information regarding the voting rights of unitholders.

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Actions taken by our general partner may affect the amount of cash available to pay distributions to unitholders or accelerate the right to convert subordinated units.

        The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

•

amount and timing of asset purchases and sales;



•

cash expenditures;



•

borrowings;



•

issuance of additional units; and



•

the creation, reduction or increase of reserves in any quarter.

        In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:

•

enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or



•

hastening the expiration of the subordination period.

        For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make this distribution on all outstanding units. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordination Period."

        Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may borrow funds from us, our operating company, or its operating subsidiaries.

We reimburse our general partner and its affiliates for expenses.

        We reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith. Please read "Certain Relationships and Related Transactions—Omnibus Agreement."

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 other party has recourse only to our assets and not against our general partner or its assets or any affiliate of our general partner or its assets. Our partnership agreement provides that any action taken by our general partner to limit its or our liability is not a breach of our general partner's fiduciary duties, even if we could have obtained terms that are more favorable without the limitation on liability. Furthermore, at the closing of this offering, our general partner will own the general partner interest in the Partnership and the incentive distribution rights and its liability will generally be limited to such assets.

Common units are subject to our general partner's limited call right.

        Our general partner may exercise its right to call and purchase common units as provided in the partnership agreement or assign this right to one of its affiliates or to us. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. As a

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result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read "The Partnership Agreement—Limited Call Right."

Common unitholders have no right to enforce obligations of our general partner and its affiliates under agreements with us.

        Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

We may not choose to retain separate counsel for ourselves or for the holders of common units.

        The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner's incentive distribution rights without the approval of the conflicts committee of our general partner or our unitholders. This may result in lower distributions to our common unitholders in certain situations.

        Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our general partner, 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 (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 amount. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of 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. 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 new common units to our general partner in connection with resetting the target distribution levels related to our general partner incentive distribution rights. Please read "Provisions of Our Partnership Agreement Related to Cash Distributions—General Partner Interest and Incentive Distribution Rights."

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Fiduciary Duties

        Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.

        Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that otherwise might be prohibited by state-law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has fiduciary duties to manage our general partner in a manner beneficial both to its owner, EQT, as well as to you. Without these modifications, the general partner's ability to make decisions involving conflicts of interests would be restricted. The modifications to the fiduciary standards benefit our general partner by enabling it to take into consideration all parties involved in the proposed action. These modifications also strengthen the ability of our general partner to attract and retain experienced and capable directors. These modifications represent a detriment to the common unitholders because they restrict the remedies available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicted interests. The following is a summary of:

•

the fiduciary duties imposed on our general partner by the Delaware Act;



•

material modifications of these duties contained in our partnership agreement; and



•

certain rights and remedies of unitholders contained in the Delaware Act.

State law fiduciary duty standards

        Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.

Partnership agreement modified standards

        Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in "good faith" and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held under applicable Delaware law.

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        Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders and that are not approved by the conflicts committee of the board of directors of our general partner must be:

•

on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or



•

"fair and reasonable" to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).

        If our general partner does not seek approval from 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 conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held. In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner, its affiliates and their officers and directors will not be liable for monetary damages to us, our limited partners for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct.

Rights and remedies of unitholders

        The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties or of the partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

        In order to become one of our limited partners, a common unitholder is required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above. Please read "Description of the Common Units—Transfer of Common Units." This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign our partnership agreement does not render the partnership agreement unenforceable against that person.

        Under the partnership agreement, we must indemnify our general partner and its officers, directors and managers, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We also must provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the Securities and Exchange Commission such indemnification is contrary to public policy and therefore unenforceable. If you have questions regarding the fiduciary duties of our general partner please read "The Partnership Agreement—Indemnification."

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DESCRIPTION OF THE COMMON UNITS

The Units

        The common units and the subordinated units are separate classes of limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and "Our Cash Distribution Policy and Restrictions on Distributions." For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read "The Partnership Agreement."

Transfer Agent and Registrar

Duties

                                                 will serve as registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following that must be paid by unitholders:

•

surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;



•

special charges for services requested by a common unitholder; and



•

other similar fees or charges.

        There will be no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal

        The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

        The transfer of the common units to persons that purchase directly from the underwriters will be accomplished through the proper completion, execution and delivery of a transfer application by the investor. Any later transfers of a common unit will not be recorded by the transfer agent or recognized by us unless the transferee executes and delivers a properly completed transfer application. By executing and delivering a transfer application, the transferee of common units:

•

becomes the record holder of the common units and is an assignee until admitted into our partnership as a substituted limited partner;



•

automatically requests admission as a substituted limited partner in our partnership;



•

executes and agrees to be bound by the terms and conditions of our partnership agreement;



•

represents that the transferee has the capacity, power and authority to enter into our partnership agreement;

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•

grants powers of attorney to the officers of our general partner and any liquidator of us as specified in our partnership agreement;



•

gives the consents, covenants, representations and approvals contained in our partnership agreement, such as the approval of all transactions and agreements we are entering into in connection with our formation and this offering; and



•

certifies:



—

that the transferee is an individual or is an entity subject to United States federal income taxation on the income generated by us; or



—

that, if the transferee is an entity not subject to United States federal income taxation on the income generated by us, as in the case, for example, of a mutual fund taxed as a regulated investment company or a partnership, all the entity's owners are subject to United States federal income taxation on the income generated by us.

        An assignee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any unrecorded transfers for which a properly completed and duly executed transfer application has been received to be recorded on our books and records no less frequently than quarterly.

        A transferee's broker, agent or nominee may, but is not obligated to, complete, execute and deliver a transfer application. We are entitled to treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder's rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

        Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to request admission as a substituted limited partner in our partnership for the transferred common units. A purchaser or transferee of common units who does not execute and deliver a properly completed transfer application obtains only:

•

the right to assign the common unit to a purchaser or other transferee; and



•

the right to transfer the right to seek admission as a substituted limited partner in our partnership for the transferred common units.

        Thus, a purchaser or transferee of common units who does not execute and deliver a properly completed transfer application:

•

will not receive cash distributions;



•

will not be allocated any of our income, gain, deduction, losses or credits for federal income tax or other tax purposes;



•

may not receive some federal income tax information or reports furnished to record holders of common units; and



•

will not have voting rights;

unless the common units are held in a nominee or "street name" account and the nominee or broker has executed and delivered a transfer application and certification as to itself and any beneficial holders.

        The transferor of common units has a duty to provide the transferee with all information that may be necessary to transfer the common units. The transferor does not have a duty to ensure the execution of the transfer application by the transferee and has no liability or responsibility if the transferee

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neglects or chooses not to execute and deliver a properly completed transfer application to the transfer agent. Please read "The Partnership Agreement—Status as Limited Partner."

        Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

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THE PARTNERSHIP AGREEMENT

        The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

        We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

•

with regard to distributions of available cash, please read "Provisions of Our Partnership Agreement Relating to Cash Distributions";



•

with regard to the fiduciary duties of our general partner, please read "Conflicts of Interest and Fiduciary Duties";



•

with regard to the transfer of common units, please read "Description of the Common Units—Transfer of Common Units"; and



•

with regard to allocations of taxable income and taxable loss, please read "Material Federal Income Tax Consequences."

Organization and Duration

        Our partnership was organized on January 18, 2012 and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

        Our purpose under the partnership agreement is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner shall not cause us to engage, directly or indirectly, in any business activity that our general partner determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

        Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the business of transporting, storing and gathering natural gas, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. Our general partner is authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Power of Attorney

        Each limited partner, and each person who acquires a unit from a unitholder, by accepting the common unit, automatically grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our general partner the authority to amend, and to make consents and waivers under, our partnership agreement.

Capital Contributions

        Unitholders are not obligated to make additional capital contributions, except as described below under "—Limited Liability."

        For a discussion of our general partner's right to contribute capital to maintain its 2.0% general partner interest if we issue additional units, please read "—Issuance of Additional Securities."

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Voting Rights

        The following is a summary of the unitholder vote required for the matters specified below. Matters requiring the approval of a "unit majority" require:

•

during the subordination period, the approval of a majority of the common units, excluding those common units held by our general partner and its affiliates, and a majority of the subordinated units, voting as separate classes; and



•

after the subordination period, the approval of a majority of the common units.

        In voting their common and subordinated units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners.

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Limited Liability

        Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:

•

to remove or replace the general partner;



•

to approve some amendments to the partnership agreement; or



•

to take other action under the partnership agreement;

constituted "participation in the control" of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as the general partner. This liability would extend to persons who transact business with us who reasonably believe that the limited partner is a general partner. Neither the partnership agreement nor the Delaware Act specifically provides for legal recourse against the general partner if a limited partner were to lose limited liability through any fault of the general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

        Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their limited partner interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the non-recourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

        Our subsidiaries conduct business in several states and we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a limited partner of our operating subsidiaries may require compliance with legal requirements in the jurisdictions in which our operating subsidiaries conduct business, including qualifying our subsidiaries to do business there.

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        Limitations on the liability of limited partners for the obligations of a limited partner have not been clearly established in many jurisdictions. If, by virtue of our limited partner interest in our operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace the general partner, to approve some amendments to the partnership agreement, or to take other action under the partnership agreement constituted "participation in the control" of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. We will operate in a manner that the general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Securities

        Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

        It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership securities may dilute the value of the interests of the then-existing holders of common units in our net assets.

        In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to the common units.

        Upon issuance of additional partnership securities (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of common units in connection with a reset of the incentive distribution target levels or the issuance of partnership securities upon conversion of outstanding partnership securities), our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 2.0% general partner interest in us. Our general partner's 2.0% interest in us 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. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common units and subordinated units, that existed immediately prior to each issuance. The other holders of common units will not have preemptive rights to acquire additional common units or other partnership securities.

Amendment of the Partnership Agreement

General

        Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited

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partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

        No amendment may be made that would:

•

enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or



•

enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld at its option.

        The provision of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90.0% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Upon completion of this offering, our general partner and its affiliates will own approximately        % of the outstanding common and subordinated units.

No Unitholder Approval

        Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

•

a change in our name, the location of our principal place of our business, our registered agent or our registered office;



•

the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;



•

a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor any of our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;



•

an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or "plan asset" regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;



•

an amendment that our general partner determines to be necessary or appropriate for the authorization of additional partnership securities or rights to acquire partnership securities, including any amendment that our general partner determines is necessary or appropriate in connection with:



—

the adjustments of the minimum quarterly distribution and target distribution levels in connection with the reset of our general partner's incentive distribution rights as described under "Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner's Right to Reset Incentive Distribution Levels"; or

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—

the implementation of the provisions relating to our general partner's right to reset its incentive distribution rights in exchange for common units;



•

any modification of the incentive distribution rights made in connection with the issuance of additional partnership securities or rights to acquire partnership securities, provided that, any such modifications and related issuance of partnership securities have received approval by a majority of the members of the conflicts committee of our general partner;



•

any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;



•

an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;



•

any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;



•

a change in our fiscal year or taxable year and related changes;



•

conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or



•

any other amendments substantially similar to any of the matters described in the clauses above.

        In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:

•

do not adversely affect in any material respect the limited partners considered as a whole or any particular class of limited partners;



•

are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;



•

are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;



•

are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or



•

are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval

        For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes in connection with any of the amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90.0% of the outstanding units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

        In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units

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will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

        A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interest of us or the limited partners.

        In addition, the partnership agreement generally prohibits our general partner without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement, each of our units will be an identical unit of our partnership following the transaction, and the partnership securities to be issued do not exceed 20.0% of our outstanding partnership securities immediately prior to the transaction.

        If the conditions specified in the partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters, and the governing instruments of the new entity provide the limited partners and the general partner with the same rights and obligations as contained in the partnership agreement. The unitholders are not entitled to dissenters' rights of appraisal under the partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Termination and Dissolution

        We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:

•

the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;



•

there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;



•

the entry of a decree of judicial dissolution of our partnership; or

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•

the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor.

        Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

•

the action would not result in the loss of limited liability of any limited partner; and



•

neither our partnership, our operating company nor any of our other subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

        Upon our dissolution, unless we are continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate to liquidate our assets and apply the proceeds of the liquidation as described in "Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Cash Upon Liquidation." The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of the General Partner

        Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to March 31, 2022 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by the general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after March 31, 2022, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days' written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days' notice to the limited partners if at least 50.0% of the outstanding common units are held or controlled by one person and its affiliates other than the general partner and its affiliates. In addition, the partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read "—Transfer of General Partner Units" and "—Transfer of Incentive Distribution Rights."

        Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority, voting as separate classes, may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read "—Termination and Dissolution."

        Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66²/3% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited

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liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units voting as a separate class, and subordinated units, voting as a separate class. The ownership of more than 33¹/3% of the outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner's removal. At the closing of this offering, our general partner and its affiliates will own        % of the outstanding common and subordinated units.

        Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by the general partner and its affiliates are not voted in favor of that removal:

•

the subordination period will end, and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;



•

any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and



•

our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.

        In the event of removal of a general partner under circumstances where cause exists or withdrawal of a general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where a general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

        If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner's general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

        In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Units

        Except for transfer by our general partner of all, but not less than all, of its general partner units to:

•

an affiliate of our general partner (other than an individual); or



•

another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity,

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our general partner may not transfer all or any of its general partner units to another person prior to March 31, 2022 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume, among other things, the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

        Our general partner and its affiliates may at any time, transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in the General Partner

        At any time, EQT and its affiliates may sell or transfer all or part of their membership interest in our general partner, or their membership interest in EQT Investments Holdings, LLC, the sole member of our general partner, to an affiliate or third party without the approval of our unitholders.

Transfer of Incentive Distribution Rights

        At any time, our general partner may sell or transfer its incentive distribution rights to an affiliate or third party without the approval of our unitholders.

Change of Management Provisions

        Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove EQT Midstream Services, LLC as our general partner or otherwise change our management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20.0% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.

        Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:

•

the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;



•

any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and



•

our general partner will have the right to convert its general partner units and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.

Limited Call Right

        If at any time our general partner and its affiliates own more than 80.0% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons as of a record date to be selected by

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our general partner, on at least 10 but not more than 60 days' notice. The purchase price in the event of this purchase is the greater of:

•

the highest cash price paid by either of our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and



•

the current market price as of the date three days before the date the notice is mailed.

        As a result of our general partner's right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read "Material Federal Income Tax Consequences—Disposition of Common Units."

Non-Taxpaying Assignees; Redemption

        To avoid any adverse effect on the maximum applicable rates chargeable to customers by our subsidiaries that are regulated interstate natural gas pipelines, or in order to reverse an adverse determination that has occurred regarding such maximum rate, transferees (including purchasers from the underwriters in this offering) are required to fill out a properly completed transfer application certifying, and our general partner, acting on our behalf, may at any time require each unitholder to re-certify:

•

that the transferee or unitholder is an individual or an entity subject to United States federal income taxation on the income generated by us; or



•

that, if the transferee unitholder is an entity not subject to United States federal income taxation on the income generated by us, as in the case, for example, of a mutual fund taxed as a regulated investment company or a partnership, all the entity's owners are subject to United States federal income taxation on the income generated by us.

        This certification can be changed in any manner our general partner determines is necessary or appropriate to implement its original purpose.

        If a unitholder fails to furnish:

•

a transfer application containing the required certification;



•

a re-certification containing the required certification within 30 days after request; or



•

provides a false certification; then

we will have the right, which we may assign to any of our affiliates, to acquire all but not less than all of the units held by such unitholder. Further, the units will not be entitled to any allocations of income or loss, distributions or voting rights while held by such unitholder.

        The purchase price in the event of such an acquisition for each unit held by such unitholder will be the lesser of:

(1)

the price paid by such unitholder for the relevant unit; and



(2)

the current market price as of the date three days before the date the notice is mailed.

        The purchase price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 5.0% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.

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Meetings; Voting

        Except as described below regarding a person or group owning 20.0% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

        Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20.0% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called represented in person or by proxy will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

        Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read "—Issuance of Additional Securities." However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20.0% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units as a single class.

        Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

        By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Except as described under "—Limited Liability," the common units will be fully paid, and unitholders will not be required to make additional contributions.

Non-Citizen Assignees; Redemption

        If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, we may redeem the units held by the limited partner at their current market price. In order to avoid any cancellation or forfeiture, our general partner may require each limited partner to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee is entitled to an interest equivalent to that of a limited partner for the right to

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share in allocations and distributions from us, including liquidating distributions. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in-kind upon our liquidation.

Indemnification

        Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

•

our general partner;



•

any departing general partner;



•

any person who is or was an affiliate of a general partner or any departing general partner;



•

any person who is or was a director, officer, member, manager, partner, fiduciary or trustee of any entity set forth in the preceding three bullet points;



•

any person who is or was serving as director, officer, member, manager, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner; and



•

any person designated by our general partner.

        Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

        Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, benefits, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. The general partner is entitled to determine in good faith the expenses that are allocable to us. Please read "Certain Relationships and Related Transactions—Omnibus Agreement."

Books and Reports

        Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

        We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

        We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to

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assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

Right to Inspect Our Books and Records

        Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:

•

a current list of the name and last known address of each record holder;



•

copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed;



•

information regarding the status of our business and financial condition; and



•

any other information regarding our affairs as is just and reasonable.

        Our general partner may, and intends to, keep confidential from the limited partners, trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.

Registration Rights

        Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership securities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of EQT Midstream Services, LLC as general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read "Units Eligible for Future Sale."

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UNITS ELIGIBLE FOR FUTURE SALE

        After the sale of the common units offered hereby and assuming that the underwriters do not exercise their option to purchase additional units, management of our general partner and its affiliates, including EQT, will hold an aggregate of                        common units and                        subordinated units. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.

Rule 144

        The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act. However, any common units owned by an "affiliate" of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

•

1.0% of the total number of the securities outstanding; and



•

the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

        Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the 90 days preceding a sale, and who has beneficially owned his common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell those common units under Rule 144 without regard to the volume limitations, manner of sale provisions and notice requirements of Rule 144.

Our Partnership Agreement and Registration Rights

        Our partnership agreement provides that we may issue an unlimited number of partnership interests of any type without a vote of the unitholders. Any issuance of additional common units or other equity interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. See "The Partnership Agreement—Issuance of Additional Securities."

        Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units or other partnership securities to require registration of any of these units or other partnership securities and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. Our general partner will continue to have these registration rights for two years after it ceases to be our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts. Our general partner and its affiliates also may sell their units or other partnership interests in private transactions at any time, subject to compliance with applicable laws.

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Lock-Up Agreements

        We, EQT, our general partner and the directors and executive officers of our general partner have agreed with the underwriters not to sell or offer to sell any common units for a period of 180 days from the date of this prospectus. For a description of these lock-up provisions, please read "Underwriting."

Registration Statement on Form S-8

        We intend to file a registration statement on Form S-8 under the Securities Act following this offering to register all common units issued or reserved for issuance under our long-term incentive plan. We expect to file this registration statement as soon as practicable after this offering. Common units covered by the registration statement on Form S-8 will be eligible for sale in the public market, subject to applicable vesting requirements and the terms of applicable lock-up agreements described above.

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MATERIAL FEDERAL INCOME TAX CONSEQUENCES

        This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the U.S. and, unless otherwise noted in the following discussion, is the opinion of Baker Botts L.L.P., counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the "Code"), existing and proposed Treasury regulations promulgated under the Code (the "Treasury Regulations") and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to "us" or "we" are references to EQT Midstream Partners, LP and our operating subsidiaries.

        The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the U.S. and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, IRAs, real estate investment trusts (REITs), employee benefit plans or mutual funds. In addition, the discussion only comments, to a limited extent, on state, local, and foreign tax consequences. Accordingly, we encourage each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

        All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Baker Botts L.L.P. and are based on the accuracy of the representations made by us.

        No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Baker Botts L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel's best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

        For the reasons described below, Baker Botts L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues: (i) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read "—Tax Consequences of Unit Ownership—Treatment of Short Sales"); (ii) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read "—Disposition of Common Units—Allocations Between Transferors and Transferees"); and (iii) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read "—Tax Consequences of Unit Ownership—Section 754 Election" and "—Uniformity of Units").

Partnership Status

        A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Pursuant to Code Section 731, distributions by a

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partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner's adjusted basis in his partnership interest.

        Section 7704 of the Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the "Qualifying Income Exception," exists with respect to publicly traded partnerships of which 90.0% or more of the gross income for every taxable year consists of "qualifying income." Qualifying income includes income and gains derived from the transportation, storage, processing and marketing of crude oil, natural gas and other products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than    % of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Baker Botts L.L.P. is of the opinion that at least 90.0% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

        No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes or whether our operations generate "qualifying income" under Section 7704 of the Code. Instead, we will rely on the opinion of Baker Botts L.L.P. on such matters. It is the opinion of Baker Botts L.L.P. that, based upon the Code, its regulations, published revenue rulings and court decisions and the representations described below that:

•

We will be classified as a partnership for federal income tax purposes; and



•

Each of our operating subsidiaries will be disregarded as an entity separate from us or will be treated as a partnership for federal income tax purposes.

        In rendering its opinion, Baker Botts L.L.P. has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Baker Botts L.L.P. has relied are:

•

Neither we nor the operating subsidiaries has elected or will elect to be treated as a corporation; and



•

For every taxable year, more than 90.0% of our gross income has been and will be income of the type that Baker Botts L.L.P. has opined or will opine is "qualifying income" within the meaning of Section 7704(d) of the Code.

        We believe that these representations have been true in the past and expect that these representations will continue to be true in the future.

        If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

        If we were taxed as a corporation for federal income tax purposes in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our

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unitholders, and our net income would be taxed to us at corporate rates. In addition, pursuant to Code Section 301, any distribution made to a unitholder would be treated as taxable dividend income, to the extent of our current and accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder's tax basis in his common units, or taxable capital gain, after the unitholder's tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder's cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

        The discussion below is based on Baker Botts L.L.P.'s opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

        Unitholders who are admitted as limited partners of EQT Midstream Partners, LP will be treated as partners of EQT Midstream Partners, LP for federal income tax purposes. Also, unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of EQT Midstream Partners, LP for federal income tax purposes.

        A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read "—Tax Consequences of Unit Ownership—Treatment of Short Sales."

        Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to the tax consequences of holding common units in EQT Midstream Partners, LP. The references to "unitholders" in the discussion that follows are to persons who are treated as partners in EQT Midstream Partners, LP for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income

        Subject to the discussion below under "—Entity-Level Collections," we will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions

        Pursuant to Code Section 731, distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Cash distributions made by us to a unitholder in an amount in excess of a unitholder's tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under "—Disposition of Common Units" below. Any reduction in a unitholder's share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as "nonrecourse liabilities," will be treated as a distribution by us of cash to that

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unitholder. To the extent our distributions cause a unitholder's "at-risk" amount to be less than zero at the end of any taxable year, Section 465 of the Code requires the recapture of any losses deducted in previous years. Please read "—Limitations on Deductibility of Losses."

        A decrease in a unitholder's percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities under Section 752 of the Code, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder's share of our "unrealized receivables," including depreciation recapture, depletion recapture and/or substantially appreciated "inventory items," each as defined in the Code, and collectively, "Section 751 Assets." To that extent, the unitholder will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder's realization of ordinary income, which will equal the excess of (i) the non-pro rata portion of that distribution over (ii) the unitholder's tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions

        We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2014, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be         % or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that earnings from operations will approximate the amount required to make the initial quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of taxable income to cash distributions to a purchaser of common units in this offering will be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

•

gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, yet we only distribute the minimum quarterly distributions on all units; or



•

we make a future offering of common units and use the proceeds of this offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

Basis of Common Units

        A unitholder's initial tax basis for his common units will be determined under Sections 722, 742 and 752 of the Code and will generally equal the amount he paid for the common units plus his share

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of our nonrecourse liabilities. That basis will be increased under Section 705 of the Code by his share of our income and by any increases in his share of our nonrecourse liabilities and decreased, but not below zero, by distributions from us, by the unitholder's share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner to the extent of the general partner's "net value," as defined in Treasury Regulations under Section 752 of the Code, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read "—Disposition of Common Units—Recognition of Gain or Loss."

Limitations on Deductibility of Losses

        Under Sections 704 and 465 of the Code, the deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust, or corporate unitholder (if more than 50.0% of the value of the corporate unitholder's stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations) to the amount for which the unitholder is considered to be "at risk" with respect to our activities, if that is less than his tax basis. A common unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such common unitholder's tax basis in his common units. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.

        In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to another unitholder or can look only to the units for repayment. A unitholder's at-risk amount will increase or decrease as the tax basis of the unitholder's units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

        In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations of Code Section 469 generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally defined as trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer's income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder's investments in other publicly traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder's share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

        A unitholder's share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

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Limitations on Interest Deductions

        Section 163 of the Code generally limits the deductibility of a non-corporate taxpayer's "investment interest expense" to the amount of that taxpayer's "net investment income." Investment interest expense includes:

•

interest on indebtedness properly allocable to property held for investment;



•

our interest expense attributed to portfolio income; and



•

the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

        The computation of a unitholder's investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or (if applicable) qualified dividend income. The IRS has indicated in Notice 88-75, 1988-2 C.B. 386, that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder's share of our portfolio income will be treated as investment income.

Entity-Level Collections

        If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

        In general, under Section 704 of the Code, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of those distributions. If we have a net loss, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.

        Section 704(c) of the Code requires us to assign each asset contributed to us in connection with this offering a "book" basis equal to the fair market value of the asset at the time of this offering. Purchasers of units in this offering are entitled to calculate tax depreciation and amortization deductions and other relevant tax items with respect to our assets based upon that "book" basis, which effectively puts purchasers in this offering in the same position as if our assets had a tax basis equal to their fair market value at the time of this offering. In this context, we use the term "book" as that term is used in Treasury regulations under Section 704 of the Code. The "book" basis assigned to our assets

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for this purpose may not be the same as the book value of our property for financial reporting purposes.

        Upon any issuance of units by us after this offering, rules similar to those of Section 704(c) described above will apply for the benefit of recipients of units in that later issuance. This may have the effect of decreasing the amount of our tax depreciation or amortization deductions thereafter allocated to purchasers of units in this offering or of requiring purchasers of units in this offering to thereafter recognize "remedial income" rather than depreciation and amortization deductions.

        In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

        An allocation of items of our income, gain, loss or deduction, other than an allocation required under the Section 704(c) principles described above, will generally be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction only if the allocation has "substantial economic effect." In any other case, a partner's share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

•

his relative contributions to us;



•

the interests of all the partners in profits and losses;



•

the interests of all the partners in cash flows; and



•

the rights of all the partners to distributions of capital upon liquidation.

        Baker Botts L.L.P. is of the opinion that, with the exception of the issues described in "—Section 754 Election", "—Disposition of Common Units—Allocations Between Transferors and Transferees," and "Uniformity of Units", allocations under our partnership agreement will be given effect under Section 704 of the Code for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction.

Treatment of Short Sales

        A unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

•

any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;



•

any cash distributions received by the unitholder as to those units would be fully taxable; and



•

all of these distributions would appear to be ordinary income.

        Because there is no direct or indirect controlling authority on the issue relating to partnership interests, Baker Botts L.L.P. has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, 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 modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their units. The IRS has previously announced in the preamble to

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certain temporary regulations, 53 FR 34488-01, 1988-2 C.B. 346, that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read "—Disposition of Common Units—Recognition of Gain or Loss."

Alternative Minimum Tax

        Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26.0% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28.0% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates

        Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35.0% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals is 15.0%. However, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20.0%, respectively. Moreover, these rates are subject to change by new legislation at any time.

        Section 1411 of the Code will impose a 3.8% Medicare tax on certain net investment income earned by individuals, estates and trusts for taxable years beginning after December 31, 2012. For these purposes, net investment income generally includes a unitholder's allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder's net investment income or (ii) the amount by which the unitholder's modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Section 754 Election

        We will make the election permitted by Section 754 of the Code. That election is irrevocable without the consent of the IRS unless there is a constructive termination of the partnership. Please read "—Disposition of Common Units—Constructive Termination." The election will generally permit us to adjust a common unit purchaser's tax basis in our assets, or inside basis, under Section 743(b) of the Code to reflect his purchase price. This election does not apply with respect to a person who purchases common units directly from us, including a purchaser of units in this offering. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, the inside basis in our assets with respect to a unitholder will be considered to have two components: (i) his share of our tax basis in our assets, or common basis, and (ii) his Section 743(b) adjustment to that basis.

        The timing of deductions attributable to a Section 743(b) adjustment to our common basis will depend upon a number of factors, including the nature of the assets to which the adjustment is allocable, the extent to which the adjustment offsets any Section 704(c) type gain or loss with respect to an asset and certain elections we make as to the manner in which we apply Section 704(c) principles with respect to an asset with respect to which the adjustment is allocable. Please read "—Allocation of

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Income, Gain, Loss and Deduction." The timing of these deductions may affect the uniformity of our units. Please read "—Uniformity of Units."

        A Section 754 election is advantageous if the transferee's tax basis in his units is higher than the units' share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee's tax basis in his units is lower than those units' share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a built-in loss or a basis reduction is substantial if it exceeds $250,000.

        The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

        We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read "—Disposition of Common Units—Allocations Between Transferors and Transferees."

Initial Tax Basis, Depreciation and Amortization

        The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. Under Section 704 of the Code, the federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (i) this offering will be borne by our general partner and its affiliates, and (ii) any other offering will be borne by our general partner and all of our unitholders as of that time. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction."

        To the extent allowable, we may elect to use the depreciation and cost recovery methods, including bonus depreciation to the extent available, that will result in the largest deductions being taken in the

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early years after assets subject to these allowances are placed in service. Part or all of the goodwill, going concern value and other intangible assets we acquire in connection with this offering may not produce any amortization deductions because of the application of the anti-churning restrictions of Section 197 of the Code. Please read "—Uniformity of Units." Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Code.

        If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules under Section 1245 or Section 1250 of the Code and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction" and "—Disposition of Common Units—Recognition of Gain or Loss."

        The costs we incur in selling our units (called "syndication expenses") must be capitalized under Section 709 of the Code and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties

        The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss

        Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder's tax basis for the units sold. A unitholder's amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder's share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

        Prior distributions from us that in the aggregate were in excess of cumulative net taxable income for a common unit and, therefore, decreased a unitholder's tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder's tax basis in that common unit, even if the price received is less than his original cost.

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        Except as noted below, gain or loss recognized by a unitholder, other than a "dealer" in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held for more than twelve months will generally be taxed at a maximum U.S. federal income tax rate of 15.0% through December 31, 2012 and 20.0% thereafter (absent new legislation extending or adjusting the current rate). However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to assets giving rise to depreciation recapture or other "unrealized receivables" or to "inventory items" we own. The term "unrealized receivables" includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Capital losses may offset capital gains and no more than $3,000 of ordinary income each year, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

        The IRS ruled in Rev. Rul. 84-53,1984-1 C.B. 159, that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an "equitable apportionment" method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner's tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner's entire interest in the partnership. Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed above, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

        Section 1259 of the Code can affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an "appreciated" partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

•

a short sale;



•

an offsetting notional principal contract; or



•

a futures or forward contract;

in each case, with respect to the partnership interest or substantially identical property.

        Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

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Allocations Between Transferors and Transferees

        In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the "Allocation Date." However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

        Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations as there is no direct or indirect controlling authority on this issue. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations under Section 706 of the Code that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Baker Botts L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders because the issue has not been finally resolved by the IRS or the courts. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder's interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

        A unitholder who disposes of units prior to the record date set for a cash distribution for any quarter will be allocated items of our income, gain, loss and deductions attributable to the month of sale but will not be entitled to receive that cash distribution.

Notification Requirements

        A unitholder who sells any of his units is generally required by regulations under Section 6050K of the Code to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required under Section 743 of the Code to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a sale may lead to the imposition of penalties under Section 6723 of the Code. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the U.S. and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination

        We will be considered under Section 708 of the Code to have terminated our tax partnership for federal income tax purposes upon the sale or exchange of our interests that, in the aggregate, constitute 50.0% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50.0% threshold is reached, multiple sales of the same interest are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending

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December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders could receive two Schedules K-1 if the relief discussed below is not available) for one fiscal year and the cost of the preparation of these returns will be borne by all common unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination. The IRS has recently announced in an Industry Director Communication, LMSB-04-0210-006, a relief procedure whereby if a publicly traded partnership that has technically terminated requests publicly traded partnership technical termination relief and the IRS grants such relief, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

Uniformity of Units

        Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. Any non-uniformity could have an impact upon the value of our units. The timing of deductions attributable to Section 743(b) adjustments to the common basis of our assets with respect to persons purchasing units from another unitholder may affect the uniformity of our units. Please read "—Tax Consequences of Unit Ownership—Section 754 Election."

        For example, some types of depreciable assets are not subject to the typical rules governing depreciation (under Section 168 of the Code) or amortization (under Section 197 of the Code). If we were to acquire any assets of that type, the timing of a unit purchaser's deductions with respect to Section 743(b) adjustments to the common basis of those assets might differ depending upon when and to whom the unit he purchased was originally issued. We do not currently expect to acquire any assets of that type. However, if we were to acquire a material amount of assets of that type, we intend to adopt tax positions as to those assets that will not result in any such lack of uniformity. Any such tax positions taken by us might result in allocations to some unitholders of smaller depreciation deductions than they would otherwise be entitled to receive. Baker Botts L.L.P. has not rendered an opinion with respect to those types of tax positions. Moreover, the IRS might challenge those tax positions. If we took such a tax position and the IRS successfully challenged the position, the uniformity of our units might be affected, and the gain from the sale of our units might be increased without the benefit of additional deductions. Please read "—Disposition of Common Units—Recognition of Gain or Loss."

Tax-Exempt Organizations and Other Investors

        Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below to a limited extent, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

        Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax under Section 511 of the Code on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.

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        Non-resident aliens and foreign corporations, trusts or estates that own units will be considered under Section 875 of the Code to be engaged in business in the U.S. because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold at the highest applicable effective tax rate from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

        In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax under Section 884 of the Code at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation's "U.S. net equity," which is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the U.S. and the country in which the foreign corporate unitholder is a "qualified resident." In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Code.

        A foreign unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under Rev. Rul. 91-32, 1991-1 C.B. 107, interpreting the scope of "effectively connected income," a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that unitholder's gain would be effectively connected with that unitholder's indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign common unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a common unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5.0% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50.0% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the five-year period ending on the date of disposition. Currently, more than 50.0% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

Administrative Matters

Information Returns and Audit Procedures

        We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder's share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Baker Botts L.L.P. can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

        The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year's tax liability, and possibly may result in an

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audit of his return. Any audit of a unitholder's return could result in adjustments not related to our returns as well as those related to our returns.

        Partnerships generally are treated as separate entities under Section 6221 of the Code for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Code requires that one partner be designated as the "Tax Matters Partner" for these purposes. Our partnership agreement names our general partner as our Tax Matters Partner.

        The Tax Matters Partner has made and will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1.0% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1.0% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

        A unitholder must file a statement with the IRS pursuant to Section 6222 of the Code identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting

        Persons who hold an interest in us as a nominee for another person are required under Section 6031 of the Code to furnish to us:

•

the name, address and taxpayer identification number of the beneficial owner and the nominee;



•

whether the beneficial owner is:



—

a person that is not a U.S. person;



—

a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or



—

a tax-exempt entity;



•

the amount and description of units held, acquired or transferred for the beneficial owner; and



•

specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

        Brokers and financial institutions are required under Section 6031 of the Code to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1.5 million per calendar year, is imposed by Section 6722 of the Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

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Accuracy-Related Penalties

        An additional tax equal to 20.0% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed under Section 6662 of the Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

        For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10.0% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

•

for which there is, or was, "substantial authority"; or



•

as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

        If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an "understatement" of income for which no "substantial authority" exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to "tax shelters," which we do not believe includes us, or any of our investments, plans or arrangements.

        A substantial valuation misstatement exists if (a) the value of any property, or the adjusted basis of any property, claimed on a tax return is 150.0% or more of the amount determined to be the correct amount of the valuation or adjusted basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Section 482 of the Code is 200.0% or more (or 50.0% or less) of the amount determined under Code Section 482 to be the correct amount of such price, or (c) the net Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10.0% of the taxpayer's gross receipts.

        No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200.0% or more than the correct valuation or certain other thresholds are met, the penalty imposed increases to 40.0%. We do not anticipate making any valuation misstatements.

        In addition, the 20.0% accuracy-related penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking economic substance. To the extent that such transactions are not disclosed, the penalty imposed is increased to 40.0%. Additionally, there is no reasonable cause defense to the imposition of this penalty to such transactions.

Reportable Transactions

        If we were to engage in a "reportable transaction," we (and possibly you and others) would be required under Treasury regulations under Section 6011 of the Code and related provisions to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a "listed transaction" or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of 6 successive tax years. Our participation in a reportable transaction

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could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read "—Information Returns and Audit Procedures."

        Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions of the American Jobs Creation Act of 2004:

•

accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at "—Accuracy-Related Penalties";



•

for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and



•

in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any "reportable transactions."

State, Local, Foreign and Other Tax Considerations

        In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. We currently do business or own property in several states, most of which impose personal income taxes on individuals. Most of these states also impose an income tax on corporations and other entities. Moreover, we may also own property or do business in other states in the future that impose income or similar taxes on nonresident individuals. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. A unitholder may be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder's income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read "—Tax Consequences of Unit Ownership—Entity-Level Collections." Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

        It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as U.S. federal tax returns, that may be required of him. Baker Botts L.L.P. has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

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INVESTMENT IN EQT MIDSTREAM PARTNERS, LP BY EMPLOYEE BENEFIT PLANS

        An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and restrictions imposed by Section 4975 of the Code. For these purposes, the term "employee benefit plan" includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:

•

whether the investment is prudent under Section 404(a)(1)(B) of ERISA;



•

whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and



•

whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read "Material Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors."

        The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan or IRA.

        Section 406 of ERISA and Section 4975 of the Code prohibit employee benefit plans, and also IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving "plan assets" with parties that are "parties in interest" under ERISA or "disqualified persons" under the Code with respect to the plan.

        In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Code.

        The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed "plan assets" under some circumstances. Under these regulations, an entity's assets would not be considered to be "plan assets" if, among other things:

(1)

the equity interests acquired by employee benefit plans are publicly offered securities (i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws);



(2)

the entity is an "operating company" (i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority-owned subsidiary or subsidiaries); or



(3)

there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held by the employee benefit plans referred to above, and IRAs that are subject to ERISA or Section 4975 of the Code.

        Our assets should not be considered "plan assets" under these regulations because it is expected that the investment will satisfy the requirements in (1) and (2) above.

        Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA and the Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

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UNDERWRITING

        Citigroup Global Markets Inc. and Barclays Capital Inc. are acting as joint book-running managers of this offering and as representatives of the underwriters named below. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, each underwriter named below has severally agreed to purchase, and we have agreed to sell to that underwriter, the number of common units set forth opposite the underwriter's name.

        The underwriting agreement provides that the obligations of the underwriters to purchase the common units included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all the common units (other than those covered by the underwriters' over-allotment option described below) if they purchase any of the common units.

        Common units sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus. Any common units sold by the underwriters to securities dealers may be sold at a discount from the initial public offering price not to exceed $            per common unit. After the common units are released for sale to the public, if all the common units are not sold at the initial offering price, the underwriters may change the offering price and the other selling terms. The representatives have advised us that the underwriters do not intend to make sales to discretionary accounts.

        If the underwriters sell more common units than the total number set forth in the table above, we have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to                        additional common units at the public offering price less the underwriting discount. The underwriters may exercise the option solely for the purpose of covering over-allotments, if any, in connection with this offering. To the extent the option is exercised, each underwriter must purchase a number of additional common units approximately proportionate to that underwriter's initial purchase commitment. Any common units issued or sold under the option will be issued and sold on the same terms and conditions as the other common units that are the subject of this offering.

        We, EQT, our general partner and the directors and executive officers of our general partner have agreed that, subject to certain exceptions, for a period of 180 days from the date of this prospectus, we and they will not, without the prior written consent of each of Citigroup Global Markets Inc. and Barclays Capital Inc., offer, pledge, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, lend or otherwise transfer or dispose of, directly or indirectly, any common units or any securities convertible into or exercisable or exchangeable for common units, or enter into any swap or other arrangement that transfers to another, in whole or in part, any of the economic consequences of ownership of the common units, whether any such transaction described above is to be settled by delivery of common units or such other securities, in cash or otherwise.

        Citigroup Global Markets Inc. and Barclays Capital Inc., in their sole discretion, may release any of the securities subject to these lock-up agreements at any time, which, in the case of officers and

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directors, shall be with notice. Notwithstanding the foregoing, if (i) during the last 17 days of the 180-day restricted period, we issue an earnings release or material news or a material event relating to our company occurs; or (ii) prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day restricted period, the restrictions described above shall continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the occurrence of the material news or material event. Neither Citigroup Global Markets Inc. nor Barclays Capital Inc. has any present intention or any understandings, implicit or explicit, to release any of the common units or other securities subject to the lock-up agreement prior to the expiration of the 180-day restricted period described above.

        Prior to this offering, there has been no public market for our common units. Consequently, the initial public offering price for the common units was determined by negotiations among us and the representatives. Among the factors considered in determining the initial public offering price were our results of operations, our current financial condition, our future prospects, our markets, the economic conditions in and future prospects for the industry in which we compete, our management, and currently prevailing general conditions in the equity securities markets, including current market valuations of publicly traded companies considered comparable to our company. We cannot assure you, however, that the price at which the common units will sell in the public market after this offering will not be lower than the initial public offering price or that an active trading market in our common units will develop and continue after this offering.

        We intend to apply for listing on the NYSE under the symbol "EQM."

        The following table shows the underwriting discounts that we are to pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters' over-allotment option.

        We will pay Citigroup Global Markets Inc. and Barclays Capital Inc. an aggregate structuring fee equal to        % of the gross proceeds of this offering for the evaluation, analysis and structuring of our partnership.

        We estimate that the expenses of this offering, not including the underwriting discount and structuring fee, will be approximately $             million, all of which will be paid by us.

        In connection with this offering, the underwriters may purchase and sell common units in the open market. Purchases and sales in the open market may include short sales, purchases to cover short positions, which may include purchases pursuant to the underwriters' over-allotment option, and stabilizing purchases.

•

Short sales involve secondary market sales by the underwriters of a greater number of common units than they are required to purchase in this offering.



—

"Covered" short sales are sales of common units in an amount up to the number of common units represented by the underwriters' over-allotment option.



—

"Naked" short sales are sales of common units in an amount in excess of the number of common units represented by the underwriters' over-allotment option.

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•

Covering transactions involve purchases of common units either pursuant to the underwriters' over-allotment option or in the open market after the distribution has been completed in order to cover short positions.



—

To close a naked short position, the underwriters must purchase common units in the open market after the distribution has been completed. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in this offering.



—

To close a covered short position, the underwriters must purchase common units in the open market after the distribution has been completed or must exercise the over-allotment option. In determining the source of common units to close the covered short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through the underwriters' over-allotment option.



•

Stabilizing transactions involve bids to purchase common units so long as the stabilizing bids do not exceed a specified maximum.

        Purchases to cover short positions and stabilizing purchases, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of the common units. They may also cause the price of the common units to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions on the NYSE, in the over-the-counter market or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.

        If you purchase common units offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

Conflicts of Interest

        Certain of the underwriters and their affiliates have engaged, and may in the future engage, in commercial banking, investment banking and advisory services for us, EQT and our respective affiliates from time to time in the ordinary course of their business for which they have received customary fees and reimbursement of expenses. Affiliates of each of the underwriters will be lenders under our new revolving credit facility and will receive a portion of the net proceeds from any exercise of the underwriters' over-allotment option. Certain of the underwriters or their affiliates have performed or will perform commercial banking, investment banking and advisory services for EQT during the 180-day period prior to, or the 90-day period following, the date of this prospectus, for which they have received or will receive customary fees and reimbursement or expenses.

        The underwriters are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, principal investment, hedging, financing and brokerage activities. In the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (which may include bank loans and/or credit default swaps) for their own account and for the accounts of their customers and may at any time hold long and short positions in such securities and instruments. Such investment and securities activities may involve our securities and instruments.

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        Because the Financial Industry Regulatory Authority, Inc., or FINRA, views the common units offered hereby as interests in a direct participation program, there is no conflict of interest between us and the underwriters under Rule 5121 of the FINRA Rules and this offering is being made in compliance with Rule 2310 of the FINRA Rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

        We, our general partner and certain of our affiliates have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make because of any of those liabilities.

Notice to Prospective Investors in the European Economic Area

        In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), other than Germany, with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of securities described in this prospectus may not be made to the public in that relevant member state other than:

•

to any legal entity which is a qualified investor as defined in the Prospectus Directive;



•

to fewer than 100 or, if the relevant member state has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the relevant Dealer or Dealers nominated by the Issuer for any such offer; or



•

in any other circumstances falling within Article 3(2) of the Prospectus Directive

provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

        For purposes of this provision, the expression an "offer of securities to the public" in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe for the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression "Prospectus Directive" means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the relevant member state), and includes any relevant implementing measure in each relevant member state. The expression "2010 PD Amending Directive" means Directive 2010/73/EU.

        We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.

Notice to Prospective Investors in the United Kingdom

        We may constitute a "collective investment scheme" as defined by section 235 of the Financial Services and Markets Act 2000 ("FSMA") that is not a "recognized collective investment scheme" for the purposes of FSMA ("CIS") and that has not been authorized or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except in

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accordance with FSMA. This prospectus is only being distributed in the United Kingdom to, and is only directed at:

(i)

if we are a CIS and are marketed by a person who is an authorized person under FSMA, (a) investment professionals falling within Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) (Exemptions) Order 2001, as amended (the "CIS Promotion Order") or (b) high net worth companies and other persons falling within Article 22(2)(a) to (d) of the CIS Promotion Order; or



(ii)

otherwise, if marketed by a person who is not an authorized person under FSMA, (a) persons who fall within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the "Financial Promotion Order") or (b) Article 49(2)(a) to (d) of the Financial Promotion Order; and



(iii)

in both cases (i) and (ii) to any other person to whom it may otherwise lawfully be made, (all such persons together being referred to as "relevant persons"). The common units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such common units will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this prospectus or any of its contents.

        An invitation or inducement to engage in investment activity (within the meaning of Section 21 of FSMA) in connection with the issue or sale of any common units which are the subject of the offering contemplated by this prospectus will only be communicated or caused to be communicated in circumstances in which Section 21(1) of FSMA does not apply to us.

Notice to Prospective Investors in Germany

        This prospectus has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act (Wertpapierprospektgesetz), the German Sales Prospectus Act (Verkaufsprospektgesetz), or the German Investment Act (Investmentgesetz). Neither the German Federal Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht—BaFin) nor any other German authority has been notified of the intention to distribute the common units in Germany. Consequently, the common units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner and this prospectus and any other document relating to this offering, as well as information or statements contained therein, may not be supplied to the public in Germany or used in connection with any offer for subscription of the common units to the public in Germany or any other means of public marketing. The common units are being offered and sold in Germany only to qualified investors which are referred to in Section 3, paragraph 2 no. 1, in connection with Section 2, no. 6, of the German Securities Prospectus Act, Section 8f paragraph 2 no. 4 of the German Sales Prospectus Act, and in Section 2 paragraph 11 sentence 2 no. 1 of the German Investment Act. This prospectus is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.

        This offering of our common units does not constitute an offer to sell or the solicitation of an offer to buy the common units in any circumstances in which such offer or solicitation is unlawful.

Notice to Prospective Investors in the Netherlands

        The common units may not be offered or sold, directly or indirectly, in the Netherlands, other than to qualified investors (gekwalificeerde beleggers) within the meaning of Article 1:1 of the Dutch Financial Supervision Act (Wet op het financieel toezicht).

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Notice to Prospective Investors in Switzerland

        This prospectus is being communicated in Switzerland to a small number of selected investors only. Each copy of this prospectus is addressed to a specifically named recipient and may not be copied, reproduced, distributed or passed on to third parties. The common units are not being offered to the public in Switzerland, and neither this prospectus, nor any other offering materials relating to the common units may be distributed in connection with any such public offering.

        We have not been registered with the Swiss Financial Market Supervisory Authority FINMA as a foreign collective investment scheme pursuant to Article 120 of the Collective Investment Schemes Act of June 23, 2006 ("CISA"). Accordingly, the common units may not be offered to the public in or from Switzerland, and neither this prospectus, nor any other offering materials relating to the common units may be made available through a public offering in or from Switzerland. The common units may only be offered and this prospectus may only be distributed in or from Switzerland by way of private placement exclusively to qualified investors (as this term is defined in the CISA and its implementing ordinance).

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VALIDITY OF THE COMMON UNITS

        The validity of the common units will be passed upon for us by Baker Botts L.L.P., Houston, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Vinson & Elkins L.L.P., Houston, Texas.

EXPERTS

        The financial statements of EQT Midstream Partners Predecessor at December 31, 2009 and 2010 and for each of the three years in the period ended December 31, 2010 appearing in this prospectus and in the registration statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

        The balance sheet of EQT Midstream Partners, LP as of January 31, 2012 included in this prospectus and in the registration statement has been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and is included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

        We have filed with the Securities and Exchange Commission a registration statement on Form S-l regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330.

        The SEC maintains a web site on the Internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC's web site and can also be inspected and copied at the offices of the New York Stock Exchange, Inc., 20 Broad Street, New York, New York 10005.

        You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized any other person 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 only. Our business, financial condition, results of operations and prospects may have changed since that date.

        Upon completion of this offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC's website as provided above. Our website on the Internet is located at www.                         .com and we make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or

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furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

        We intend to furnish or make available to our unitholders annual reports containing our audited financial statements and furnish or make available to our unitholders quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

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FORWARD-LOOKING STATEMENTS

        Some of the information in this prospectus may contain forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as "could," "will," "may," "assume," "forecast," "position," "predict," "strategy," "expect," "intend," "plan," "estimate," "anticipate," "believe," "project," "budget," "potential," or "continue," and similar expressions are used to identify forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this prospectus include our expectations of plans, strategies, objectives, growth and anticipated financial and operational performance, including guidance regarding our and EQT's infrastructure programs, revenue projections, capital expenditures and tax position. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed.

        A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, when considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

•

changes in general economic conditions;



•

competitive conditions in our industry;



•

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



•

the demand for natural gas storage and transportation services;



•

our ability to successfully implement our business plan;



•

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



•

the price and availability of debt and equity financing;



•

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



•

competition from the same and alternative energy sources;



•

energy efficiency and technology trends;



•

operating hazards and other risks incidental to transporting, storing and gathering natural gas;



•

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



•

interest rates;



•

labor relations;



•

large customer defaults;



•

changes in the availability and cost of capital;



•

changes in tax status;



•

the effects of existing and future laws and governmental regulations;

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•

the effects of future litigation; and



•

certain factors discussed elsewhere in this prospectus.

        Forward-looking statements speak only as of the date on which they are made. We expressly disclaim any obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

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INDEX TO FINANCIAL STATEMENTS

F-1

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EQT MIDSTREAM PARTNERS LP

UNAUDITED PRO FORMA FINANCIAL STATEMENTS

Introduction

        The unaudited pro forma financial statements of EQT Midstream Partners LP (the Partnership) as of September 30, 2011, for the year ended December 31, 2010, and for the nine months ended September 30, 2011 are derived from the historical audited and unaudited financial statements of Equitrans, L.P., our predecessor for accounting purposes (the 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, set forth elsewhere in this prospectus and are qualified in their entirety by reference to such historical financial statements and related notes contained therein. These pro forma financial statements have been prepared to reflect the formation, initial public offering (the Offering) and related transactions of the Partnership.

        In connection with the closing of this Offering, EQT Corporation will contribute all of the partnership interests in Equitrans, L.P. to the Partnership, which contribution will be recorded at historical cost as it is considered to be a reorganization of entities under common control. The pro forma adjustments have been prepared as if the transactions to be effected at the closing of this offering had taken place on September 30, 2011, in the case of the pro forma balance sheet, and as of January 1, 2010, in the case of the pro forma income statements for the year ended December 31, 2010 and for the nine months ended September 30, 2011. The unaudited pro forma financial statements have been prepared on the assumption that the Partnership will be treated as a partnership for federal income tax purposes. The unaudited pro forma financial statements should be read in conjunction with the notes accompanying such unaudited pro forma financial statements and with the historical audited and unaudited financial statements and related notes set forth elsewhere in this prospectus.

        The unaudited pro forma balance sheet and the unaudited pro forma statements of income were derived by adjusting the historical audited and unaudited financial statements of the Predecessor. The adjustments are based upon currently available information and certain estimates and assumptions. Actual effects of these transactions may differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments are factually supportable and give appropriate effect to those assumptions and are properly applied in the unaudited pro forma financial data.

        The 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. or all outstanding intercompany indebtedness with EQT with the proceeds of a capital contribution by EQT;



•

the contribution by EQT of all of the partnership interests in Equitrans, L.P. to us;



•

the issuance to a subsidiary of EQT of                        common units and                        subordinated units, representing an aggregate        % limited partner interest in us;



•

the issuance to our general partner of                        general partner units representing a 2.0% general partner interest in us and all of our incentive distribution rights;



•

the issuance of                        common units to the public in this offering, representing a        % limited partner interest in us;



•

our entry into a new $       million revolving credit facility;



•

the use of proceeds of this offering as described in "Use of Proceeds"; and



•

our entry into a lease agreement with EQT pursuant to which we will lease and operate the Sunrise Pipeline.

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EQT MIDSTREAM PARTNERS LP

UNAUDITED PRO FORMA BALANCE SHEET

September 30, 2011

   

See accompanying notes to unaudited pro forma financial data.

F-3

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EQT MIDSTREAM PARTNERS LP

UNAUDITED PRO FORMA STATEMENT OF OPERATIONS

Year Ended December 31, 2010

   

See accompanying notes to unaudited pro forma financial data.

F-4

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EQT MIDSTREAM PARTNERS LP

UNAUDITED PRO FORMA STATEMENT OF OPERATIONS

Nine Months Ended September 30, 2011

   

See accompanying notes to unaudited pro forma financial data.

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EQT MIDSTREAM PARTNERS, LP

NOTES TO UNAUDITED PRO FORMA FINANCIAL DATA

1. Basis of Presentation, Transactions and this Offering

        The historical financial information is derived from the audited historical and unaudited interim financial statements of the Predecessor. The pro forma adjustments have been prepared as if this offering and the transactions described in this prospectus had taken place on September 30, 2011, in the case of the pro forma balance sheet, and as of January 1, 2010, in the case of the pro forma statements of operations for the year ended December 31, 2010, and for the nine months ended September 30, 2011. The adjustments are based on currently available information and certain estimates and assumptions and therefore the actual effects of these transactions will differ from the pro forma adjustments.

        Upon completion of this offering, the Partnership anticipates incurring incremental selling, general and administrative expenses of approximately $3.0 million per year as a result of becoming a publicly traded partnership, including 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. The unaudited pro forma financial statements do not reflect these incremental selling, general and administrative expenses.

2. Pro Forma Adjustments and Assumptions

        The adjustments are based on currently available information and certain estimates and assumptions and therefore the actual effects of these transactions will differ from the pro forma adjustments. A general description of these transactions and adjustments is provided as follows:

(a)

the gross proceeds of $250.0 million from the issuance and sale of             million common units at an initial public offering price of $            per unit. If the underwriters were to exercise their option to purchase additional common units in full, gross proceeds to the Partnership would equal $             million.



(b)

the payment of estimated underwriting discounts and commissions and structuring fees.



(c)

the payment of offering expenses.



(d)

the payment of an estimated $2.0 million of origination fees on the Partnership's revolving credit facility, which will be amortized over the life of the facility, and an estimated $1.1 million of annual commitment fees. In total, the amortization and commitment fees are estimated to be $1.5 million and $1.1 million for the year ended December 31, 2010 and the nine months ended September 30, 2011, respectively.



(e)

the $164.0 million distribution of net proceeds to EQT.



(f)

the elimination of the impact of federal and state taxes as the Partnership is a non-taxable entity. As of September 30, 2011, $1.5 million adjustment to other current assets eliminates the current deferred tax asset, $17.1 million eliminates the income tax payable to EQT, $106.0 million eliminates the deferred income taxes and investment tax credits, and $2.3 million elimination of unrecognized tax benefits recorded in other long-term liabilities. Income taxes expense of $14.0 million and $13.7 million are eliminated for the year ended December 31, 2010 and the nine months ended September 30, 2011, respectively.

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EQT MIDSTREAM PARTNERS, LP

NOTES TO UNAUDITED PRO FORMA FINANCIAL DATA

2. Pro Forma Adjustments and Assumptions (Continued)

(g)

the transfer of $54.9 million of under construction transmission assets associated with the Sunrise Pipeline project to a wholly owned subsidiary of EQT Corporation, as well as the removal in the nine months ended September 30, 2011 of $1.6 million of related allowance for funds used during construction (AFUDC) equity and $0.4 million of AFUDC debt. There was no AFUDC recorded for these assets for the year ended December 31, 2010, as construction had not yet begun.



(h)

the signing of a capital lease agreement for the Sunrise Pipeline project with EQT. The construction of the property will not be completed until the third quarter of 2012. Lease payments and depreciation of the leased assets will not begin until the construction is complete. The $54.9 million adjustment reflects the current book value of the assets under construction. We currently project the total cost of the Sunrise Pipeline project will be $220 million when complete. The $1.6 million adjustment to other income in the nine months ended September 30, 2011 reflects the reestablishment of the associated AFUDC equity and $0.4 million of AFUDC debt. There was no AFUDC on these assets for the year ended December 31, 2010 as construction had not yet begun.



(i)

the retirement of $135.2 million of long-term debt and $1.4 million of accrued interest at September 30, 2011 and associated interest expense of $5.2 million for the year ended December 31, 2010 and $4.8 million for the nine months ended September 30, 2011 with the proceeds of a capital contribution by EQT prior to the initial public offering.

3. Pro Forma Net Income per Unit

        Pro forma net income per unit is determined by dividing the pro forma net income that would have been allocated, in accordance with the net income and loss allocation provisions of the partnership agreement, to the common and subordinated unitholders under the two-class method, after deducting the general partner's interest of 2% in the pro forma net income, by the number of common and subordinated units expected to be outstanding at the closing of this offering. For purposes of this calculation, we assumed that (1) the initial quarterly distribution was made to all unitholders for each quarter during the periods presented and (2) the number of units outstanding was             million common units and             million subordinated units. The common and subordinated unitholders represent 98% limited partner interests. All units were assumed to have been outstanding since January 1, 2010. Basic and diluted pro forma net income per unit are equivalent as there are no dilutive units at the date of closing of the initial public offering of the common units of EQT Midstream Partners, LP. Pursuant to the partnership agreement, to the extent that the quarterly distributions exceed certain targets, the general partner is entitled to receive certain incentive distributions that will result in more net income proportionately being allocated to the general partner than to the holders of common and subordinated units. The pro forma net income (loss) per unit calculations assume that no incentive distributions were made to the general partner because no such distribution would have been paid based upon the pro forma available cash from operating surplus for the period.

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Report of Independent Registered Public Accounting Firm

The Board of Directors of EQT Corporation

        We have audited the accompanying balance sheets of EQT Midstream Partners Predecessor (the Predecessor) as of December 31, 2010 and 2009 and the related statements of operations, partners' capital, and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Predecessor's management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Predecessor's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Predecessor's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Predecessor at December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the three years ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania
February 9, 2012

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EQT MIDSTREAM PARTNERS PREDECESSOR

BALANCE SHEETS

DECEMBER 31,

   

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

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EQT MIDSTREAM PARTNERS PREDECESSOR

STATEMENTS OF OPERATIONS

YEARS ENDED DECEMBER 31,

   

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

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EQT MIDSTREAM PARTNERS PREDECESSOR

STATEMENTS OF PARTNERS' CAPITAL

   

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

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EQT MIDSTREAM PARTNERS PREDECESSOR

STATEMENTS OF CASH FLOWS

YEARS ENDED DECEMBER 31,

   

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

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EQT MIDSTREAM PARTNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS

1. Description of the Business

Organization

        Equitrans, L.P. (Equitrans or the Company), is a Pennsylvania limited partnership and the predecessor for accounting purposes (the Predecessor) of EQT Midstream Partners LP (the Partnership or EQT Midstream Partners). The accompanying financial statements and related notes include the assets, liabilities and results of operations of Equitrans presented on a carve-out basis, excluding the financial position and results of operations of the Big Sandy Pipeline (as described below), prior to the contribution of all of the partnership interests in Equitrans to EQT Midstream Partners, in connection with the Partnership's proposed initial public offering. The Partnership was formed in January 2012 as a Delaware limited partnership. As used in these financial statements, the terms "we," "our," "us," or like terms refer to the Predecessor. References in these financial statements to "EQT" refer collectively to EQT Corporation and its consolidated subsidiaries, other than the Predecessor.

        As of January 1, 2008, Equitrans was owned 97.25% by EQT Corporation, 2.50% by EQT Gathering, Inc., a subsidiary of EQT Corporation that owns EQT's non-regulated retained midstream assets, and 0.25% by ET Blue Grass, LLC, a subsidiary of EQT Corporation. Effective December 31, 2010, ET Blue Grass, LLC acquired the 2.50% limited partner interest in Equitrans held by EQT Gathering, Inc. for cash.

        Equitrans does not have any employees. Operational support for Equitrans is provided by EQT Gathering, LLC (EQT Gathering), one of EQT Gathering, Inc.'s operating subsidiaries engaged in certain midstream business operations. EQT Gathering's employees manage and conduct Equitrans' daily business operations.

        Prior to July 2011, Equitrans owned an approximately 70-mile FERC-regulated transmission pipeline located in eastern Kentucky (Big Sandy Pipeline). Construction on the Big Sandy Pipeline began in 2006 and was completed in 2008. Equitrans operated the pipeline until April 2011, when it was transferred to an affiliate. Such affiliate was subsequently sold in July 2011 to an unrelated third party pipeline operator. Equitrans has no continuing operations in Kentucky or any retained interest in the Big Sandy Pipeline.

Nature of Business

        We are a growth-oriented limited partnership formed by EQT to own, operate, acquire and develop midstream assets in the Appalachian Basin. 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 and our gathering system. These assets constitute the operations of the Predecessor and are being contributed to EQT Midstream Partners.

        Equitrans Transmission and Storage System.    Our transmission and storage system includes an approximately 700 mile FERC-regulated interstate pipeline system that connects to five long-haul interstate pipelines and multiple distribution companies, and 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. Revenues are primarily driven by our firm transmission and storage contracts.

        Equitrans Gathering System.    Our gathering system consists of approximately 2,100 miles of FERC-regulated low-pressure gathering lines. Substantially all of the revenues associated with our gathering system were generated under interruptible gathering service contracts.

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EQT MIDSTREAM PARTNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS (Continued)

2. Summary of Significant Accounting Policies

Use of Estimates

        We prepare our financial statements in conformity with United States generally accepted accounting principles (GAAP), which requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

Cash and Cash Equivalents

        We consider all highly liquid instruments with an original maturity of three months or less when purchased, to be cash equivalents. Interest earned on cash equivalents is included in interest expense in the accompanying statements of operations.

Trade and Other Receivables

        Trade and other receivables are stated at their historical carrying amount. Judgment is required to assess the ultimate realization of our accounts receivable, including our assessing the probability of collection and the creditworthiness of customers. Based upon management's assessments, allowances for doubtful accounts of approximately $0.1 million were provided at December 31, 2009 and 2010. We also maintain certain receivables due from EQT. Refer to Note 4 for further discussion.

Property, Plant, and Equipment

        Property, plant and equipment are stated at amortized cost. Maintenance projects that do not increase the overall life of the related assets are expensed as incurred. Expenditures that extend the useful life of the underlying asset are capitalized.

        Depreciation is recorded using composite rates on a straight-line basis. The overall rate of depreciation for the years ended December 31, 2008, 2009 and 2010 were approximately 1.7%, 1.9% and 2.1%, respectively. We estimate our pipelines have useful lives ranging from 37 years to 65 years and our compression equipment has a useful life of 45 years. Depreciation rates are re-evaluated each time we file with the FERC for a change in our transportation and storage rates.

        Whenever events or changes in circumstances indicate that the carrying amount of long-lived assets may not be recoverable, we review our long-lived assets for impairment by first comparing the carrying value of the assets to the sum of the undiscounted cash flows expected to result from the use and

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EQT MIDSTREAM PARTNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS (Continued)

2. Summary of Significant Accounting Policies (Continued)

eventual disposition of the assets. If the carrying value exceeds the sum of the assets' undiscounted cash flows, we estimate an impairment loss equal to the difference between the carrying value and fair value of the assets.

Natural Gas Imbalances

        We experience natural gas imbalances when the actual amount of natural gas delivered from a pipeline system or storage facility differs from the amount of natural gas scheduled to be delivered. We value these imbalances due to or from shippers and operators at current index prices. Imbalances are settled in-kind, subject to the terms of our FERC tariff.

        Imbalances as of December 31, 2009 and 2010 were $1.7 million and $6.9 million, respectively, and are reported as natural gas imbalances and other in the accompanying balance sheet. In addition, we classify all imbalances as current as we expect to settle them within a year.

Regulatory Accounting

        Our regulated operations consist of interstate pipeline, intrastate gathering and storage operations subject to regulation by the FERC. Rate regulation provided by the FERC is designed to enable us to recover the costs of providing the regulated services plus an allowed return on invested capital. The application of regulatory accounting allows us to defer expenses and income in our balance sheets as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the rate setting process in a period different from the period in which they would have been reflected in the statements of operations for a non-regulated company. The deferred regulatory assets and liabilities are then recognized in the statements of operations in the period in which the same amounts are reflected in rates. The amounts deferred are to be recovered over the regulated period. The amounts deferred in the balance sheets relate primarily to the accounting for income taxes, allowance for funds used during construction (AFUDC) and post-retirement benefit costs. We believe that we will continue to be subject to rate regulation that will provide for the recovery of deferred costs.

        On April 5, 2006, the FERC approved a settlement to Equitrans' consolidated 2005 and 2004 rate case filings. The settlement became effective on June 1, 2006. This settlement (i) increased our base tariff rates, (ii) implemented an annual surcharge for the tracking and recovery of certain pipeline safety costs among other programs and (iii) implemented a mechanism for recovering migrated base gas.

Revenue Recognition

        Revenues relating to the transmission, storage and gathering of natural gas are recognized in the period service is provided. Reservation revenues on firm contracted capacity are recognized ratably over the contract period regardless of the amount of natural gas that is transported. Revenues associated with interruptible services are recognized as physical deliveries of natural gas are made. Revenue is recognized for gathering activities when deliveries of natural gas are made.

Income Taxes

        Our income is currently reported and included as part of EQT's consolidated federal tax return. Equitrans is a Pennsylvania limited partnership that was a tax partnership through December 31, 2010 at which time as a result of an internal restructuring it was deemed to be solely owned by EQT and

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EQT MIDSTREAM PARTNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS (Continued)

2. Summary of Significant Accounting Policies (Continued)

became a disregarded entity for federal income tax purposes. The current provision for income taxes represents amounts paid or estimated to be payable, net of amounts refunded or estimated to be refundable, by or to EQT as a result of our operations. Current federal income tax balances of all subsidiary companies are settled with EQT, which makes all consolidated tax payments. The consolidated federal income tax is allocated among the groups' members on a separate-return basis with tax credits allocated to those members who generate the credits. Following the initial public offering of the Partnership, our operations will be treated as a partnership for federal income tax purposes, with each partner being separately taxed on its share of the taxable income.

        Deferred income tax assets and liabilities are determined based on differences between financial reporting and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion of the deferred tax asset will not be realized. Where deferred tax liabilities will be passed through to customers in regulated rates, we record a corresponding regulatory asset for the increase in future revenues. Investment tax credits realized in prior years were deferred and are being amortized over the estimated service lives of the related properties where required by ratemaking rules.

        In accounting for uncertainty in income taxes of a tax position taken or expected to be taken in a tax return, we utilize a recognition threshold and measurement attribute for the financial statement recognition and measurement. The recognition threshold requires us to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. If it is more likely than not that a tax position will be sustained, then we must measure the tax position to determine the amount of benefit to recognize in its financial statements. The tax position is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. We recognize interest and penalties accrued related to unrecognized tax benefits in income tax expense.

Allowance for Funds Used During Construction

        We capitalize the carrying costs for the construction of certain regulated long-term assets and amortize the costs over the life of the related assets. The calculated AFUDC includes capitalization of the cost of financing construction of assets subject to regulation by the FERC. A computed interest cost and a designated cost of equity for financing the construction of these regulated assets are recorded in our financial statements. AFUDC applicable to equity funds recorded in other income in the statement of operations for the years ended December 31, 2008, 2009 and 2010, respectively were $1.4 million, $1.1 million and $0.1 million. AFUDC applicable to interest cost is included as a reduction of interest expense in the statement of operations for the years ended December 31, 2008, 2009 and 2010, and was $0.4 million, $0.4 million and $0.1 million, respectively.

Asset Retirement Obligations

        We operate and maintain our transmission and storage system and our gathering system, and we intend to do so as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we believe that we cannot reasonably estimate the asset retirement obligations for our system assets as these assets have indeterminate lives.

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EQT MIDSTREAM PARTNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS (Continued)

2. Summary of Significant Accounting Policies (Continued)

Recently Issued Accounting Standards

        In May 2011, the Financial Accounting Standards Board (FASB) issued a standard update intended to enhance the fair value disclosure requirements to result in common fair value measurement in accordance with GAAP and International Financial Reporting Standards (IFRS). The amendments are to be applied prospectively, and are effective during interim and annual periods beginning after December 15, 2011. We are currently evaluating the impact this standard will have on our financial statements.

        In June 2011, the FASB issued a standard update to improve the comparability, consistency and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. The amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We are currently evaluating the impact this standard will have on our financial statements.

3. Financial Information by Business Segment

        Operating segments are revenue-producing components of the enterprise for which separate financial information is produced internally and is subject to evaluation by the chief operating decision maker in deciding how to allocate resources.

        We report our operations in two segments, which reflect our lines of business. Transmission and Storage includes our FERC-regulated interstate pipeline and storage business. Gathering includes our FERC-regulated low pressure gathering system. The operating segments are evaluated on their contribution to our results based on operating income.

        All of our operating revenues, income from continuing operations and assets are generated or located in the United States.

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EQT MIDSTREAM PARTNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS (Continued)

3. Financial Information by Business Segment (Continued)

 

 

4. Related-Party Transactions

        In the ordinary course of business, we have transactions with affiliated companies.

        Accounts receivable—affiliates represent amounts due from subsidiaries of EQT, primarily related to transmission, storage and gathering services. For the years ended December 31, 2008, 2009 and 2010, we generated revenues of approximately $54.7 million, $62.5 million and $74.0 million, respectively, from services provided to subsidiaries of EQT.

        The accompanying balance sheets include amounts due from related parties as of December 31, 2009 and 2010 of $15.1 million and $23.3 million, respectively. Amounts due to related parties as of December 31, 2009 and 2010 totaled $10.1 million and $10.3 million, respectively. These amounts represent transactions with subsidiaries of EQT outside of transmission, storage and gathering services.

        As discussed in Note 7, EQT provides financing directly or indirectly through EQT Capital, predominantly through intercompany term and demand loans. In addition, operating and administrative expenses and capital expenditures incurred on our behalf by EQT Corporation result in intercompany advances recorded as amounts due to or due from EQT Corporation on our balance sheet. These advances are related to changes in working capital as well as our cash flow needs. We view these as financing transactions as we would have otherwise obtained demand notes or term loans from EQT Capital to fund these transactions. Of the total due to and due from related parties in the accompanying balance sheets discussed above, $(0.3) million and $0.6 million are due to and due from EQT Corporation at December 31, 2009 and 2010, respectively.

        The personnel who operate our assets are employees of EQT. EQT directly charges us for the payroll and benefit costs associated with employees and carries the obligations for other employee-

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EQT MIDSTREAM PARTNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS (Continued)

4. Related-Party Transactions (Continued)

related benefits in its financial statements. We are allocated a portion of EQT's defined benefit pension plan liability for the retirees of Equitrans based on an actuarial assessment of that liability. Our share of those costs is charged through due to related parties and reflected in operations and maintenance expense in the accompanying statement of operations. See Note 8.

        We are allocated a portion of the indirect operating and maintenance expense incurred by EQT Gathering, a subsidiary of EQT that incurs certain costs that are shared by us. For the years ended December 31, 2009 and 2010 operating and maintenance expenses allocated to us were approximately $0.5 million and $0.4 million, respectively. There were no operating and maintenance expenses allocated for the year ended December 31, 2008. The allocation is based on our percentage of labor hours for certain operations and maintenance departments.

        For the years ended December 31, 2008, 2009 and 2010 selling, general and administrative expenses allocated to us were approximately $4.7 million, $4.5 million and $3.9 million, respectively. We are allocated a portion of the selling, general and administrative expense incurred by EQT Gathering. The allocation is based on our percentage of a calculation based upon net plant, revenue and headcount.

        Included in the accompanying statements of operations operating expenses is stock-based compensation of $(2.1) million, $7.6 million and $2.9 million during the years ended December 31, 2008, 2009 and 2010, respectively. EQT's stock-based compensation programs consist of restricted stock and stock options issued to employees. To the extent compensation cost relates to employees directly involved in transmission and storage or gathering operations, such amounts are charged to us by EQT and are reflected as operating expenses. To the extent compensation cost relates to employees indirectly involved in transmission and storage or gathering operations, such amounts are charged to us from EQT and reflected as general and administrative expenses.

        As discussed further in Note 7, we had demand and term notes due to EQT Capital Corporation of approximately $135.2 million at December 31, 2009 and 2010.

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EQT MIDSTREAM PARTNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS (Continued)

5. Income Taxes

        The components of the federal income tax expense (benefit) for the years ended December 31, 2008, 2009 and 2010 are as follows:

        Current federal tax obligations are settled with EQT. EQT's consolidated federal income tax is allocated among the group's members on a separate return basis with tax credits allocated to the members generating the credits.

        Income tax expense differs from amounts computed at the federal statutory rate of 35% on pre-tax book income from continuing operations as follows:

        Our effective tax rate for the year ended December 31, 2010 was 42.2% compared to 43.0% for the year ended December 31, 2009. The lower tax rate in 2010 is primarily the result of lower reserves required for uncertain tax position. Our effective tax rate for the year ended December 31, 2009 was 43.0% compared to 48.3% for the year ended December 31, 2008. The higher rate in 2008 is primarily the result of higher state taxes in 2008 due to changes in state apportionment factors.

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EQT MIDSTREAM PARTNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS (Continued)

5. Income Taxes (Continued)

        The following table reconciles the beginning and ending amount of reserve for uncertain tax positions (excluding interest and penalties):

        In accounting for uncertainty in income taxes, EQT utilizes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. Included in the tabular reconciliation above at December 31, 2009 and December 31, 2010 are $1.8 million and $1.9 million, respectively, for tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. The Company recognized interest and penalties accrued related to unrecognized tax benefits in income tax expense. Interest of $0.2 million and $0.3 million is included in unrecognized tax benefits at December 31, 2009 and 2010, respectively. The total amount of unrecognized tax benefits, inclusive of interest, was $0.2 million, $2.2 million and $2.4 million as of December 31, 2008, 2009 and 2010, respectively, and is included in other long-term liabilities on the balance sheet. The total amount of unrecognized tax benefits (excluding interest and penalties) that, if recognized, would affect the effective tax rate was $0.1 million, $0.1 million and $0.1 million as of December 31, 2008, 2009 and 2010. As of December 31, 2010, it is reasonably possible that the total amount of unrecognized tax benefits could decrease by up to $2.0 million within the next 12 months due to potential settlements, legal or administrative guidance by relevant taxing authorities or the lapse of applicable statutes of limitations. There were no material changes to the Company's methodology for unrecognized tax benefits during 2009 and 2010.

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EQT MIDSTREAM PARTNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS (Continued)

5. Income Taxes (Continued)

        The following table summarizes the source and tax effects of temporary differences between financial reporting and tax basis of assets and liabilities.

        There is no valuation allowance relating to deferred tax assets as the entire balance is expected to be realized. The deferred tax liabilities principally consist of temporary differences between financial and tax reporting for the Company's property, plant and equipment (PP&E) and regulatory assets. Included in the deferred income taxes and investment tax credits on the balance sheet are investment tax credits of $1.3 million and $1.0 million at December 31, 2009 and December 31, 2010, respectively.

        The IRS has completed its audit of EQT Corporation and Subsidiaries' federal income tax filings through 2005. The IRS began its audit and review of EQT's federal income tax filings for the 2006 through 2009 years during the second quarter of 2010. Equitrans, LP is also under audit by the IRS for the 2008 and 2009 tax years. EQT also is the subject of various state income tax examinations.

6. Regulatory Assets

        The table below summarizes our regulatory assets, net of amortization, as of December 31, 2009 and 2010. The regulatory assets are recoverable or reimbursable over various periods. We believe that we will continue to be subject to rate regulation that will provide for the recovery of our regulatory assets.

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EQT MIDSTREAM PARTNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS (Continued)

6. Regulatory Assets (Continued)

        Deferred taxes:    The regulatory asset associated with deferred taxes primarily represents deferred income taxes recoverable through future rates once the taxes become current. The Company expects to recover the amortization of this asset through rates.

        Post-retirement benefits other than pensions:    The actuarially determined cost of post-retirement benefits is recovered through rates that are set through periodic rate filings. Any differences between the annual actuarially determined costs and amounts currently being recovered in rates are recorded as regulatory assets or liabilities and collected or refunded through future rate adjustments. The Company amortizes post-retirement benefits other than pensions previously deferred and recognizes expenses for ongoing post-retirement benefits other than pensions, which are subject to recovery in approved rates. The reduction in the Company's regulatory asset for amortization of post-retirement benefits other than pensions previously deferred was approximately $1.4 million, $1.4 million and $0.7 million for each of the years ended December 31, 2008, 2009 and 2010, respectively.

        AFUDC:    The regulatory asset associated with AFUDC represents the offset to the deferred taxes associated with the equity component of the allowance for funds used during the construction of long-lived assets. Taxes on capitalized funds used during construction and the offsetting deferred income taxes are included in the rate base and are recovered over the depreciable lives of the long-lived assets to which they relate.

        Other recoverable costs:    Other recoverable costs primarily represent the recovery of storage base gas. We are entitled to recover certain migrated storage base gas. A regulatory asset was established by multiplying the recoverable volume of migrated base gas by the average cost of the base gas. The regulatory asset is reduced by the volumes of base gas recovered through a component of the transmission system retention factor assessed to transmission service customers.

        The following regulatory assets do not earn a return on investment: deferred taxes, other post-retirement benefits and base gas migration.

7. Notes Payable Affiliate

        EQT provides financing to its affiliates directly or indirectly through EQT Capital Corporation (EQT Capital), EQT's subsidiary finance company. Such financing is generally provided through intercompany term and demand loans that are entered into between EQT Capital and EQT's subsidiaries. We have notes payable due to EQT Capital of approximately $135.2 million as of

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EQT MIDSTREAM PARTNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS (Continued)

7. Notes Payable Affiliate (Continued)

December 31, 2009 and 2010. The interest rate on the demand notes is equal to a commercial rate plus 100 basis points.

        There are no maturities of long-term debt scheduled through 2015. Demand notes were payable on notification from EQT Capital prior to being refinanced subsequent to December 31, 2011.

        Interest expense on long-term debt and demand loans amounted to $5.9 million, $5.5 million and $5.2 million for the years ended December 31, 2008, 2009 and 2010, respectively.

8. Pension and Other Postretirement Benefit Plans

        The personnel who operate our assets are employees of EQT. EQT directly charges us for the payroll and benefit costs associated with these employees and retirees. EQT carries the obligations for pension and other employee-related benefits in its financial statements.

        Equitrans' retirees participate in a defined benefit pension plan that is sponsored by EQT. For the years ended December 31, 2009 and 2010, we reimbursed approximately $0.6 million and $0.1 million, respectively, to the plan sponsor in order to meet certain funding targets. No reimbursement was made for the year ended December 31, 2008. We expect to make cash payments to EQT Corporation of approximately $0.3 million in both 2011 and 2012 to reimburse for defined benefit pension plan funding. Pension plan contributions are designed to meet minimum funding requirements and keep plan assets at least equal to 80% of projected liabilities. Our reimbursements to EQT are based on the proportion of the plan's total liabilities allocable to Equitrans retirees. We received positive adjustments of $0.1 million, $0.1 million in 2008 and 2009, respectively, of the expenses associated with the plan. We were allocated $0.1 million of the expenses associated with the plan in 2010. The dollar amount of a cash reimbursement to the plan sponsor in any particular year will vary as a result of gains or losses sustained by the pension plan assets during the year due to market conditions. We do not expect the variability of contribution requirements to have a significant effect on our financial position, results of operations or liquidity.

        We contribute to a defined contribution plan sponsored by EQT. The contribution amount is a percentage of each employee's base salary to an individual investment account for such employee. The amount of such contributions was $0.3 million, $0.1 million, and $0.1 million in 2008, 2009 and 2010, respectively.

        The employees who operate our assets and Equitrans retirees participate in certain other post-employment benefit plans sponsored by EQT. We were allocated $0.7 million, $0.2 million and

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EQT MIDSTREAM PARTNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS (Continued)

8. Pension and Other Postretirement Benefit Plans (Continued)

$0.4 million in 2008, 2009 and 2010, respectively, of the expenses associated with these plans. Under the Equitrans rate case settlement, Equitrans began amortization of post-retirement benefits other than pensions previously deferred as well as recognizing expenses for ongoing post-retirement benefits other than pensions, which are now subject to recovery from July 1, 2005 forward in the approved rates. Expenses recognized by us for the years ended December 31, 2008, 2009 and 2010 for amortization of post-retirement benefits other than pensions previously deferred were approximately $1.4 million, $1.4 million and $0.7 million, respectively. Expenses recognized by us for the years ended December 31, 2008, 2009 and 2010 for ongoing post-retirement benefits other than pensions were approximately $1.2 million per year.

9. Fair Value of Financial Instruments

        The carrying value of cash equivalents and demand notes approximates fair value due to the short maturity of the instruments. The estimated fair values of the notes payable—affiliate on the accompanying balance sheets at December 31, 2009 and 2010 were approximately $63 million and $145 million, respectively. The fair value was estimated based on market rates reflective of the remaining maturity and risk.

10. Commitments and Contingencies

        We are subject to federal, state and local environmental laws and regulations. These laws and regulations, which are constantly changing, can require expenditures for remediation and in certain instances result in assessment of fines. We have established procedures for ongoing evaluation of our operations to identify potential environmental exposures and assure compliance with regulatory policies and procedures. The estimated costs associated with identified situations that require remedial action are accrued. However, when recoverable through regulated rates, certain of these costs are deferred as regulatory assets. Ongoing expenditures for compliance with environmental law and regulations, including investments in plant and facilities to meet environmental requirements, have not been material. Management believes that any such required expenditures will not be significantly different in either nature or amount in the future and does not know of any environmental liabilities that will have a material effect on our financial position or results of operations.

        We are involved in legal proceedings that arise in the ordinary course of business. We record a liability for contingencies based upon our assessment that a loss is probable and the amount of the loss can be reasonably estimated. We consider many factors in making these assessments, including history and specifics of each matter. Estimates are developed in consultation with legal counsel and are based upon an analysis of potential results. There are no individual matters, or the aggregate thereof, that management believes are reasonably possible of causing material loss based on presently known facts or circumstances.

        Equitrans had no operating or capital leases as of December 31, 2010.

11. Concentrations of Credit Risk

        Our transmission and storage and gathering operations include FERC regulated interstate pipelines and storage service for Equitable Gas, a subsidiary of EQT Corporation, as well as other utility and end users customers located in the northeastern United States. We also provide service to customers

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EQT MIDSTREAM PARTNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS (Continued)

11. Concentrations of Credit Risk (Continued)

engaged in commodity procurement and delivery, including large industrial, utility, commercial, institutional customers and certain marketers primarily in the Appalachian and mid-Atlantic regions.

        Approximately 59% and 42% of third party accounts receivable balances of $2.8 million and $4.7 million as of December 31, 2009 and 2010, respectively, represent amounts due from marketers. We manage the credit risk of sales to marketers by limiting our dealings to those marketers who meet specified criteria for credit and liquidity strength and by actively monitoring these accounts. We may require letters of credit, guarantees, performance bonds or other credit enhancements from a marketer in order for that marketer to meet these credit criteria. We did not experience any significant defaults on accounts receivable during the years ended December 31, 2008, 2009 and 2010.

12. Subsequent Event Disclosure

        Subsequent events have been evaluated through February 9, 2012, the date our financial statements were available to be issued.

        On September 8, 2011, Equitrans received approval from the Federal Energy Regulatory Commission (FERC) to proceed with construction of the Sunrise Pipeline project. The Sunrise Pipeline project consists 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 Transmission in Greene County and constructing a new compressor station.

        On December 16, 2011, Equitrans filed with the FERC an application under Section 7 of the Natural Gas Act (NGA) requesting an order from the FERC: (1) amending the certificate of public convenience and necessity issued to Equitrans by order of the FERC on July 21, 2011 (Equitrans, L.P., 136 FERC ¶ 61,046 (2011)) for the Sunrise Pipeline to permit Equitrans to transfer a passive ownership interest in the facilities that have yet to be constructed to a wholly owned subsidiary of EQT and a non-jurisdictional entity; (2) authorizing the abandonment of the Sunrise Pipeline facilities that have already been constructed and placed into service by transfer of a passive ownership of the facilities to EQT; (3) granting to Equitrans certificate authority to lease all of the Sunrise Pipeline facilities from EQT and to operate the facilities; and (4) issuing pre-granted abandonment and certificate authority to allow the termination of the lease and the acquisition of the Sunrise Pipeline facilities upon the expiration of the term of the lease arrangement.

        On February 3, 2012, we refinanced with EQT Capital our intercompany term debt and our demand loans into a 10 year term note maturing on February 1, 2022 at an interest rate of 6.01%. Accordingly, since we intended and arranged to finance such amounts on a long-term basis, the related obligations are reflected as long-term debt at December 31, 2010 in the accompanying balance sheet.

        Effective March 1, 2011, pursuant to a sublease of mineral rights from us to EQT Production Company, an oil and gas exploration subsidiary of EQT, and an acreage dedication to us by EQT Production, we have the right to transport on our transmission and storage system, all natural gas produced from wells drilled by EQT on the dedicated acreage, which is an area covering approximately 60,000 acres in Pennsylvania and West Virginia. EQT has gathering systems that service this acreage and interconnect with our transmission and storage system.

        Subsequent to December 31, 2010, in connection with construction of the Sunrise Pipeline project and Blacksville Compressor Station project, we entered into agreements with pipeline construction and other contractors to provide services to us. These obligations total approximately $250 million. Both projects are expected to be completed in the third quarter 2012.

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EQT MIDSTREAM PARTNERS PREDECESSOR

BALANCE SHEETS

   

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

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EQT MIDSTREAM PARTNERS PREDECESSOR

STATEMENTS OF OPERATIONS

(UNAUDITED)

EQT MIDSTREAM PARTNERS PREDECESSOR

STATEMENT OF PARTNERS' CAPITAL

(UNAUDITED)

   

The accompanying notes are an integral part of these financial statements

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EQT MIDSTREAM PARTNERS PREDECESSOR

STATEMENTS OF CASH FLOWS

(UNAUDITED)

   

The accompanying notes are an integral part of these financial statements

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EQT MIDSTREAM PARTNERS PREDECESSOR

NOTES TO THE FINANCIAL STATEMENTS (UNAUDITED)

1. Financial Statements

        The accompanying unaudited financial statements have been prepared in accordance with United States generally accepted accounting principles for interim financial information. Accordingly, they do not include all of the information and footnotes required by United States general accepted accounting principles for complete financial statements. In our opinion, these statements include all adjustments (consisting of only normal recurring accruals, unless otherwise disclosed) necessary for a fair presentation of the financial position of the EQT Midstream Partners Predecessor as of September 30, 2011, and the results of its operations and cash flows for the nine month periods ended September 30, 2010 and 2011.

2. Description of the Business

Organization

        Equitrans, LP (Equitrans or the Company), is a Pennsylvania limited partnership and the predecessor for accounting purposes (the Predecessor) of EQT Midstream Partners LP (the Partnership or EQT Midstream Partners). The accompanying financial statements and related notes include the assets, liabilities and results of operations of Equitrans presented on a carve-out basis, excluding the financial position and results of operations of the Big Sandy Pipeline (as described below), prior to the contribution of all of the partnership interests in Equitrans to EQT Midstream Partners, in connection with the Partnerships proposed initial public offering. The Partnership was formed in January 2012 as a Delaware limited partnership. As used in these financial statements, the terms "we," "our," "us," or like terms refer to the Predecessor. References in these financial statements to "EQT" refer collectively to EQT Corporation and its consolidated subsidiaries, other than the Predecessor.

        As of January 1, 2008, Equitrans was owned 97.25% by EQT Corporation, 2.50% by EQT Gathering, Inc., a subsidiary of EQT Corporation that owns EQT's non-regulated retained midstream assets, and 0.25% by ET Blue Grass, LLC, a subsidiary of EQT Corporation. Effective December 31, 2010, ET Blue Grass, LLC acquired the 2.50% limited partnership interest in Equitrans held by EQT Gathering, Inc. for cash.

        Equitrans does not have any employees. Operational support for Equitrans is provided by EQT Gathering, LLC (EQT Gathering), one of EQT's operating subsidiaries engaged in certain midstream business operations. EQT Gathering's employees manage and conduct Equitrans' daily business operations.

        Prior to July 2011, Equitrans owned an approximately 70 mile FERC-regulated transmission pipeline located in eastern Kentucky (Big Sandy Pipeline). Construction on the Big Sandy Pipeline began in 2006 and was completed in 2008. Equitrans operated the pipeline until April 2011, when it was transferred to an affiliate. Such affiliate was subsequently sold in July 2011 to an unrelated third party pipeline operator. Equitrans has no continuing operations in Kentucky or any retained interest in the Big Sandy Pipeline.

Nature of Business

        We are a growth-oriented limited partnership formed by EQT to own, operate, acquire and develop midstream assets in the Appalachian Basin. 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 and our gathering system.

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EQT MIDSTREAM PARTNERS PREDECESSOR

NOTES TO THE FINANCIAL STATEMENTS (UNAUDITED) (Continued)

2. Description of the Business (Continued)

        Equitrans Transmission and Storage System.    Our transmission and storage system includes an approximately 700 mile FERC-regulated interstate pipeline system that connects to five long-haul interstate pipelines and multiple distribution companies, and 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. Revenues are primarily driven by our firm transmission and storage contracts.

        Equitrans Gathering System.    Our gathering system consists of approximately 2,100 miles of FERC-regulated low-pressure gathering lines. Substantially all of the revenues associated with our gathering system were generated under interruptible gathering service contracts.

3. Financial Information by Business Segment

        Operating segments are revenue-producing components of the enterprise for which separate financial information is produced internally and are subject to evaluation by our chief operating decision maker in deciding how to allocate resources.

        The Predecessor reports its operations in two segments, which reflect its lines of business. Transmission and Storage includes our FERC regulated interstate pipeline and storage business. Gathering includes our FERC regulated low pressure gathering system. The operating segments are evaluated on their contribution to our results based on operating income.

        Substantially all of the Company's operating revenues, income from continuing operations and assets are generated or located in the United States.

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EQT MIDSTREAM PARTNERS PREDECESSOR

NOTES TO THE FINANCIAL STATEMENTS (UNAUDITED) (Continued)

3. Financial Information by Business Segment (Continued)

 

 

4. Related-Party Transactions

        In the ordinary course of business, we have transactions with affiliated companies.

        Accounts receivable—affiliate at September 30, 2011 and December 31, 2010 represents amounts due from subsidiaries of EQT, primarily related to transmission services provided to subsidiaries of EQT. For the nine months ended September 30, 2010 and 2011, we generated revenues of approximately $51.6 million and $62.6 million, respectively, from services provided to subsidiaries of EQT.

        The accompanying balance sheets include amounts due from related parties of $23.3 million as of December 31, 2010 and $27.2 million as of September 30, 2011. Amounts due to related parties as of December 31, 2010 totaled $10.3 million and $22.2 million as of September 30, 2011. These amounts represent transactions with subsidiaries of EQT outside of transmission, storage and gathering services.

        As discussed in Note 6, EQT provides financing directly or indirectly through EQT Capital, predominantly through intercompany term and demand loans. In addition, operating and administrative expenses and capital expenditures incurred on our behalf by EQT Corporation result in intercompany advances recorded as amounts due to or due from EQT Corporation on our balance sheet. These advances are related to changes in working capital as well as our cash flow needs. We view these as financing transactions as we would have otherwise obtained demand notes or term loans from EQT Capital to fund these transactions. Of the total due from and due to related parties in the accompanying balance sheets discussed above, $0.6 million and $(14.6) million are due from and due to EQT Corporation at December 31, 2010 and September 30, 2011, respectively.

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EQT MIDSTREAM PARTNERS PREDECESSOR

NOTES TO THE FINANCIAL STATEMENTS (UNAUDITED) (Continued)

4. Related-Party Transactions (Continued)

        The personnel who operate our assets are employees of EQT. EQT directly charges us for the payroll and benefit costs associated with employees and carries the obligations for other employee-related benefits in its financial statements. We are allocated a portion of EQT's defined benefit pension plan liability for the retirees of Equitrans based on an actuarial assessment of that liability. Our share of those costs is charged through due to related parties and reflected in operations and maintenance expense in the accompanying statement of operations.

        We are allocated a portion of the indirect operating and maintenance expense incurred by EQT Gathering, a subsidiary of EQT that incurs certain costs that are shared by us. For the nine months ended September 30, 2010 and 2011 operating and maintenance expenses allocated to us were approximately $0.3 million and $1.8 million, respectively.

        For the nine months ended September 30, 2010 and 2011 selling, general and administrative expenses allocated to us were approximately $2.9 million and $2.8 million, respectively. We are allocated a portion of the selling, general and administrative expense incurred by EQT Gathering. The allocation is based on a calculation of our percentage of net plant, revenue and headcount.

        Included in the accompanying combined statements of operations operating expenses is stock based compensation of $2.6 million and $2.7 million during the nine months ended September 30, 2010 and 2011, respectively. EQT's stock-based compensation programs consist of restricted stock and stock options issued to employees. To the extent compensation cost relates to employees directly involved in transmission and storage or gathering operations, such amounts are charged to us by EQT and are reflected as operating expenses. To the extent compensation cost relates to employees indirectly involved in transmission and storage or gathering operations, such amounts are charged to us from EQT and reflected as general and administrative expenses.

        As discussed further in Note 6, we had demand and term notes due to EQT Capital Corporation, a subsidiary of EQT, of approximately $135.2 million at December 31, 2010 and September 30, 2011.

5. Income Taxes

        We estimate an annual effective income tax rate based on projected results for the year and apply this rate to income before taxes to calculate income tax expense. Any refinements made due to subsequent information that affects the estimated annual effective income tax rate are reflected as adjustments in the current period. Separate effective income tax rates are calculated for net income from continuing operations and any other separately reported net income items, such as discontinued operations.

        Current federal tax obligations of all subsidiary companies are settled with EQT. The consolidated federal income tax is allocated among the group's members on a separate return basis with tax credits allocated to the members generating the credits.

        Our effective tax rate for the nine months ended September 30, 2010 and 2011 was 42.2% and 38.4%, respectively. It was higher than the federal statutory rate primarily as a result of state income taxes. The 2011 rate was lower than 2010 primarily as a result of higher book tax differences related to allowance for funds used during construction in 2011.

        There were no material changes to our methodology or amount of unrecognized tax benefits during the nine months ended September 30, 2011.

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EQT MIDSTREAM PARTNERS PREDECESSOR

NOTES TO THE FINANCIAL STATEMENTS (UNAUDITED) (Continued)

5. Income Taxes (Continued)

        The IRS has completed its audit of EQT and Subsidiaries' federal income tax filings through 2005. The IRS began its audit and review of EQT's federal income tax filings for the 2006 through 2009 years during the second quarter of 2010. Equitrans, L.P. is also under audit by the IRS for the 2008 and 2009 tax years. EQT also is the subject of various state income tax examinations.

6. Notes Payable Affiliate / Long-Term Debt

        EQT provides financing to its affiliates directly or indirectly through EQT Capital Corporation (EQT Capital), EQT's subsidiary finance company. Such financing is generally provided through intercompany term and demand loans that are entered into between EQT Capital and EQT's subsidiaries. We have notes payable due to EQT Capital of approximately $135.2 million as of December 31, 2010 and as of September 30, 2011. The interest rate on the demand notes is equal to a commercial rate plus 100 basis points.

        Pursuant to the February 2012 refinancing, there are no maturities of long-term debt scheduled in 2011, 2012, 2013, 2014 and 2015. Demand notes were payable upon notification from EQT Capital prior to being refinanced subsequent to December 31, 2011.

        Interest expense on long-term debt and demand loans amounted to $3.9 million and $4.8 million for the nine months ended September 30, 2010 and 2011, respectively.

7. Fair Value of Financial Instruments

        The carrying value of cash equivalents and short-term loans approximates fair value due to the short maturity of the instruments.

        The estimated fair value of Notes payable—affiliate on the balance sheets September 30, 2011 was approximately $154 million. The fair value was estimated using our established fair value methodology based on quoted rates reflective of the remaining maturity.

8. Commitments

        Effective March 2011, pursuant to a sublease of mineral rights from us to EQT Production Company, an oil and gas exploration subsidiary of EQT, and an acreage dedication to us by EQT Production, we have the right to transport on our transmission and storage system, all natural gas produced from wells drilled by EQT on the dedicated acreage, which is an area covering approximately

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EQT MIDSTREAM PARTNERS PREDECESSOR

NOTES TO THE FINANCIAL STATEMENTS (UNAUDITED) (Continued)

8. Commitments (Continued)

60,000 acres in Pennsylvania and West Virginia. EQT has gathering systems that service this acreage and interconnect with our transmission and storage system.

        In connection with construction of the Sunrise Pipeline project and Blacksville Compressor Station project, we entered into agreements with pipeline construction and other contractors to provide services to us. These obligations total approximately $250 million. Both projects are expected to be completed in the third quarter 2012.

9. Subsequent Event Disclosure

        On December 16, 2011, Equitrans filed with the Federal Energy Regulatory Commission (FERC) an application under Section 7 of the Natural Gas Act (NGA) requesting an order from the FERC: (1) amending the certificate of public convenience and necessity issued to Equitrans by order of the FERC on July 21, 2011 (Equitrans, L.P., 136 FERC ¶ 61,046 (2011)) for certain natural gas pipeline facilities located in Pennsylvania and West Virginia (Sunrise Pipeline) to permit Equitrans to transfer a passive ownership interest in the facilities that have yet to be constructed to a wholly owned subsidiary of EQT and a non-jurisdictional entity; (2) authorizing the abandonment of the Sunrise Pipeline that have already been constructed and placed into service by transfer of a passive ownership of the facilities to EQT; (3) granting to Equitrans certificate authority to lease all of the Sunrise Pipeline facilities from EQT and to operate the facilities; and (4) issuing pre-granted abandonment and certificate authority to allow the termination of the lease and the acquisition by Equitrans of the Sunrise Pipeline upon the expiration of the term of the lease arrangement.

        On February 3, 2012, we refinanced with EQT Capital our intercompany term debt and our demand loans into a 10 year term note maturing on February 1, 2022 at an interest rate 6.01%. Accordingly, since we intended and arranged to finance such amounts on a long-term basis, the related obligations are reflected as long-term debt as of December 31, 2010 and September 30, 2011 in the accompanying balance sheets.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of EQT Midstream Services, LLC

        We have audited the accompanying balance sheet of EQT Midstream Partners, LP (the Partnership) as of January 31, 2012. This balance sheet is the responsibility of the Partnership's management. Our responsibility is to express an opinion on this balance sheet based on our audit.

        We conducted our audit in accordance with the standards of the Public Company Oversight Accounting Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. We were not engaged to perform an audit of the Partnership's internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

        In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of EQT Midstream Partners, LP at January 31, 2012 in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania
February 9, 2012

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EQT MIDSTREAM PARTNERS, LP

BALANCE SHEET

January 31, 2012

   

The accompanying note is an integral part of this balance sheet.

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EQT MIDSTREAM PARTNERS, LP

NOTE TO BALANCE SHEET

1. Nature of Operations

        EQT Midstream Partners, LP (the Partnership) is a Delaware limited partnership formed on January 18, 2012 to acquire certain assets of EQT Corporation (EQT).

        The Partnership intends to offer common units, representing limited partner interests, pursuant to a public offering and to concurrently issue common units and subordinated units, representing additional limited partner interests in the Partnership to EQT Midstream Investments, LLC, an indirect wholly owned subsidiary of EQT, and general partner units representing an aggregate 2% general partner interest in the Partnership to EQT Midstream Services, LLC, an indirect wholly owned subsidiary of EQT.

        EQT Midstream Services LLC, as general partner, contributed $20 and EQT Midstream Investments, LLC, as the organizational limited partner, contributed $980, all in the form of cash, to the Partnership on January 31, 2012. There have been no other transactions involving the Partnership as of January 31, 2012.

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APPENDIX A—FORM OF AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF EQT MIDSTREAM PARTNERS, LP

[To Be Filed By Amendment]

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APPENDIX B—GLOSSARY OF TERMS

        Adjusted EBITDA:    A supplemental non-GAAP financial measure defined by us 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.

        BBtu:    One billion British Thermal Units.

        Bcf:    One billion cubic feet.

        condensate:    A natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.

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

        FERC:    Federal Energy Regulatory Commission.

        GAAP:    Generally accepted accounting principles.

        HP:    Horsepower.

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

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

        Mcf:    One thousand cubic feet.

        MMcf:    One million cubic feet.

        NGA:    Natural Gas Act of 1938.

        NGLs:    Those hydrocarbons in natural gas that are separated from the natural gas as liquids through the process of absorption, condensation, adsorption or other methods in natural gas processing or cycling plants. Generally such liquids consist of propane and heavier hydrocarbons and are commonly referred to as lease condensate, natural gasoline and liquefied petroleum gases. Natural gas liquids include natural gas plant liquids (primarily ethane, propane, butane and isobutane) and lease condensate (primarily pentanes produced from natural gas at lease separators and field facilities).

        park and loan services:    Those services pursuant to which customers receive the right to store natural gas in (park), or borrow gas from (loan), our facilities on a seasonal basis.

        play:    A proven geological formation that contains commercial amounts of hydrocarbons.

        receipt point:    The point where production is received by or into a gathering system or transportation pipeline.

        reservoir:    A porous and permeable underground formation containing an individual and separate natural accumulation of producible hydrocarbons (crude oil and/or natural gas) which is confined by impermeable rock or water barriers and is characterized by a single natural pressure system.

        shale gas:    Natural gas produced from organic (black) shale formations.

        TBtu:    One trillion British Thermal Units.

        Tcf:    One trillion cubic feet.

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        throughput:    The volume of natural gas transported or passing through a pipeline, plant, terminal or other facility during a particular period.

        wellhead:    The equipment at the surface of a well used to control the well's pressure; also, the point at which the hydrocarbons and water exit the ground.

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                        Common Units

Representing Limited Partner Interests

EQT Midstream Partners, LP

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PROSPECTUS

                        , 2012

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Citigroup

Barclays Capital

        Through and including                        , 2012 (the 25th day after the date of this prospectus), all dealers effecting transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to a dealers' obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

   

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PART II
INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13.    Other Expenses of Issuance and Distribution.

        Set forth below are the expenses (other than underwriting discounts and the structuring fee) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, the FINRA filing fee and the NYSE listing fee, the amounts set forth below are estimates.

Item 14.    Indemnification of Directors and Officers.

EQT Midstream Partners, LP

        Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against any and all claims and demands whatsoever. The section of the prospectus entitled "The Partnership Agreement—Indemnification" discloses that we will generally indemnify officers, directors and affiliates of our general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by reference.

        The underwriting agreement to be entered into in connection with the sale of the securities offered pursuant to this registration statement, the form of which will be filed as an exhibit to this registration statement, provides for indemnification of EQT Midstream Partners, LP and our general partner, their officers and directors, and any person who controls our general partner, including indemnification for liabilities under the Securities Act.

EQT Midstream Services, LLC

        Subject to any terms, conditions or restrictions set forth in the limited liability company agreement, Section 18-108 of the Delaware Limited Liability Company Act empowers a Delaware limited liability company to indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever.

        Under the limited liability agreement of our general partner, in most circumstances, our general partner will indemnify the following persons, to the fullest extent permitted by law, from and against any and all losses, claims, damages, liabilities (joint or several), expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings (whether civil, criminal, administrative or investigative):

•

any person who is or was an affiliate of our general partner (other than us and our subsidiaries);

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•

any person who is or was a member, partner, officer, director, employee, agent or trustee of our general partner or any affiliate of our general partner;



•

any person who is or was serving at the request of our general partner or any affiliate of our general partner as an officer, director, employee, member, partner, agent, fiduciary or trustee of another person; and



•

any person designated by our general partner.

        Our general partner will purchase insurance covering its officers and directors against liabilities asserted and expenses incurred in connection with their activities as officers and directors of our general partner or any of its direct or indirect subsidiaries.

Item 15.    Recent Sales of Unregistered Securities.

        On January 18, 2012, in connection with our formation, we issued to (i) our general partner a 2.0% general partner interest in us in exchange for $20 and (ii) EQT Midstream Investments, LLC a 98.0% limited partner interest in us in exchange for $980. These transactions were exempt from registration under Section 4(2) of the Securities Act.

Item 16.    Exhibits and Financial Statement Schedules.

        The following documents are filed as exhibits to this registration statement:

Item 17.    Undertakings.

        The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

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        Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

        The undersigned registrant hereby undertakes that, for the purpose of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of the securities, in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(i)

Any preliminary prospectus or prospectus of the undersigned registrant relating to this offering required to be filed pursuant to Rule 424;



(ii)

Any free writing prospectus relating to this offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;



(iii)

The portion of any other free writing prospectus relating to this offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and



(iv)

Any other communication that is an offer in this offering made by the undersigned registrant to the purchaser.

        The undersigned registrant hereby undertakes that:

(1)

For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.



(2)

For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

        The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with EQT, our general partner, or any of their affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to EQT, our general partner, or any of their affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

        The registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the registrant.

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SIGNATURES

        Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Pittsburgh, State of Pennsylvania, on February 13, 2012.

        Each person whose signature appears below appoints David L. Porges, Philip P. Conti and Lewis B. Gardner, and each of them, any of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their or his substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

        Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed by the following persons in the capacities and the dates indicated.

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INDEX TO EXHIBIT

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