EX 99.1 Item 1 Business

EQT Midstream Partners, LP (EQT Midstream Partners or the Partnership) closed its initial public offering (IPO) on July 2, 2012. Equitrans, L.P. (Equitrans) is a Pennsylvania limited partnership and the predecessor for accounting purposes of EQT Midstream Partners. References in this Form 8-K to the “Partnership,” when used for periods prior to the IPO, refer to Equitrans. References in this Form 8-K to the “Partnership,” when used for periods beginning at or following the IPO, refer collectively to the Partnership and its consolidated subsidiaries. Immediately prior to the closing of the IPO, EQT Corporation contributed all of the partnership interests in Equitrans to the Partnership. Therefore, the historical financial statements contained in this Form 8-K reflect the assets, liabilities and operations of Equitrans for periods before July 2, 2012 and EQT Midstream Partners for periods beginning at or following July 2, 2012. Additionally, as discussed below, the Partnership’s combined financial statements have been retrospectively recast for all periods presented to include the historical results of Sunrise Pipeline, LLC (Sunrise), which was merged into the Partnership on July 22, 2013 (Sunrise Merger), the Jupiter natural gas gathering system (Jupiter), which was acquired by the Partnership on May 7, 2014 (Jupiter Acquisition), and the Northern West Virginia Marcellus gathering system (NWV Gathering), which was acquired by the Partnership on March 17, 2015 (NWV Gathering Acquisition) as these were businesses and the transactions were between entities under common control. References in this Form 8-K to ‘‘EQT’’ refer collectively to EQT Corporation and its consolidated subsidiaries.

EQT Midstream Partners, LP (NYSE: EQM) is a growth-oriented limited partnership formed by EQT Corporation (NYSE: EQT) to own, operate, acquire and develop midstream assets in the Appalachian Basin. The Partnership provides substantially all of its natural gas transmission, storage and gathering services under contracts with long-term, firm reservation and/or usage fees. This contract structure enhances the stability of the Partnership's cash flows and limits its direct exposure to commodity price risk. For the year ended December 31, 2014, approximately 50% of the Partnership's revenues were generated from capacity reservation charges under long-term firm contracts, which have a weighted average remaining term of approximately 17 years for firm transmission and storage contracts, and approximately 10 years for firm gathering contracts as of December 31, 2014. The Partnership’s operations are primarily focused in southwestern Pennsylvania and northern West Virginia, a strategic location in the core of the rapidly developing natural gas shale play known as the Marcellus Shale. This same region is also the core operating area of EQT, the Partnership's largest customer. EQT accounted for approximately 69% of the Partnership's revenues generated for the year ended December 31, 2014. The Partnership provides midstream services to EQT and multiple third parties across 21 counties in Pennsylvania and West Virginia through its two primary assets: the transmission and storage system, which serves as a header system transmission pipeline, and the gathering system, which delivers natural gas from wells and other receipt points to transmission pipelines. The Partnership believes that its strategically located assets, combined with its working relationship with EQT, position it as a leading Appalachian Basin midstream energy company.

EQT is one of the largest natural gas producers in the Appalachian Basin. As of December 31, 2014, EQT reported 10.7 Tcfe of proved natural gas, natural gas liquids and crude oil reserves and, for the year ended December 31, 2014, EQT reported total production sales volumes of 476 Bcfe, representing a 26% increase compared to the year ended December 31, 2013. Since 2010, EQT has successfully grown production by 254% through the year ended December 31, 2014, primarily driven by production from the Marcellus Shale, while increasing proved reserves 106% over the same time period. EQT has announced that estimated sales volumes in 2015 are expected to be 575 to 600 Bcfe, an increase of approximately 23% over 2014. EQT has also announced a 2015 capital expenditure forecast of $1.85 billion for well development, which will primarily be focused in the Marcellus Shale. In order to facilitate production growth in its areas of operation, EQT invested approximately $1.6 billion in midstream infrastructure from January 1, 2010 through December 31, 2014. The Partnership believes its economic relationship with EQT incentivizes EQT to provide the Partnership with access to production growth in and around the Partnership's existing assets and with acquisitions and organic growth opportunities, although EQT is under no obligation to make such opportunities available to the Partnership.

On May 7, 2014, the Partnership acquired Jupiter from EQT. As of December 31, 2014, this system consists of an approximately 45-mile natural gas gathering system located in Greene and Washington counties, Pennsylvania with three compressor stations, which have approximately 575 MMcf per day of firm gathering capacity. Jupiter has six interconnects with the Partnership’s transmission and storage system and a total of 970 MMcf per day of interconnect capacity. The aggregate consideration paid by the Partnership to EQT for Jupiter was approximately $1,180 million, consisting of a $1,121 million cash payment, 516,050 common units of the Partnership and 262,828 general partner units of the Partnership.

On March 10, 2015, the Partnership entered into a contribution and sale agreement (Contribution Agreement) pursuant to which, on March 17, 2015, EQT contributed NWV Gathering to EQM Gathering Opco, LLC (EQM Gathering). NWV Gathering consists of approximately 70 miles of high pressure natural gas gathering pipeline and nine compressor units with approximately 25,000 horsepower of compression and a wet gas header pipeline, which is an approximately 30-mile high pressure pipeline that receives wet gas from development areas in northern West Virginia and provides delivery to the MarkWest Mobley processing facility. The NWV Gathering assets also interconnect with the transmission and storage assets that the Partnership operates and have firm gathering capacity of approximately 460 MMcf per day. The Partnership paid total consideration of $925.7 million to EQT, consisting of approximately $873.2 million in cash, 511,973 common units of the Partnership and 178,816 general partner units of the Partnership. As NWV Gathering was a business and the acquisition was a transaction between entities under common control, the Partnership's historical combined financial statements have been retrospectively recast to reflect the results attributable to NWV Gathering for all periods presented.

The Contribution Agreement also contemplated the sale to the Partnership of a preferred interest in EQT Energy Supply, LLC, a wholly owned subsidiary of EQT that generates revenue from services provided to a local distribution company. This sale is expected to occur by April 16, 2015 and is subject to customary closing conditions under the Contribution Agreement, in addition to the condition that EQT obtain consent from the requisite note holders under, or pay off all obligations with respect to, an existing note purchase agreement related to approximately $6 million of outstanding indebtedness. The consideration to be paid by the Partnership to EQT in connection with the acquisition of the preferred interest in EQT Energy Supply, LLC is approximately $124.3 million.

On March 17, 2015, the Partnership completed an underwritten public offering of 8,250,000 common units. The Partnership received net proceeds of approximately $605.4 million from the offering after deducting the underwriters' discount and estimated offering expenses. The Partnership used these net proceeds from the offering and borrowings under the Partnership's credit facility of $390.0 million to finance the cash consideration paid to EQT in connection with the NWV Gathering Acquisition. On March 23, 2015, the underwriters exercised their option to purchase additional common units of 1,237,500 on the same terms as the offering. The net proceeds from the sale of these additional common units of approximately $91.0 million after deducting the underwriters' discount were used to reduce the Partnership's outstanding balance on the credit facility. As a result of the sale of these additional common units, EQT purchased 25,255 general partner units to maintain its 2.0% general partner interest. Following the NWV Gathering Acquisition and the equity offering including the full exercise of the underwriters' option to purchase additional common units, EQT owns a 32.2% equity interest in the Partnership, which includes 21,811,643 common units and 1,443,015 general partner units.

On March 30, 2015, the Partnership assumed 100% of the membership interests in MVP Holdco, LLC (MVP Holdco), an wholly owned indirect subsidiary of EQT that owns an approximately 55% interest (the MVP Interest) in Mountain Valley Pipeline, LLC (MVP Joint Venture) for approximately $54.2 million (MVP Interest Acquisition), which represents the Partnership's reimbursement to EQT for 100% of the capital contributions made by EQT to the MVP Joint Venture as of March 30, 2015.

As of December 31, 2014, the Partnership’s transmission and storage system included an approximately 700-mile interstate pipeline regulated by the FERC that connects to five interstate pipelines and multiple distribution companies. The transmission system is supported by 14 associated natural gas storage reservoirs with approximately 400 MMcf per day of peak withdrawal capacity, 32 Bcf of working gas capacity and 27 compressor units with total throughput capacity of approximately 3.0 Bcf per day. Through a lease with EQT, the Partnership also operates the AVC facilities, which include an approximately 200-mile FERC-regulated interstate pipeline that interconnects with the Partnership’s transmission and storage system in the Marcellus Shale region. As of December 31, 2014, the AVC facilities provided 0.45 Bcf per day of additional firm capacity to the Partnership’s system and are supported by four associated natural gas storage reservoirs with approximately 260 MMcf per day of peak withdrawal capacity, approximately 15 Bcf of working gas capacity and 11 compressor units. Revenues associated with the Partnership’s transmission and storage system, including those on AVC, represented approximately 53%, 49% and 51% of its total revenues for the years ended December 31, 2014, 2013 and 2012, respectively. As of December 31, 2014, the weighted average remaining contract life based on total projected contracted revenues for firm transmission and storage contracts, including those on AVC, was approximately 17 years.

Partnership funding its proportionate share through capital contributions made to the joint venture. In 2015, the Partnership's capital contributions are expected to be approximately $105 million to $115 million and will be primarily in support of environmental and land assessments, design work and materials. Expenditures are expected to increase substantially as construction commences, with the bulk of the expenditures expected to be made in 2017 and 2018. The joint venture has secured a total of 2.0 Bcf per day of 20 year firm capacity commitments and is currently in negotiation with additional shippers who have expressed interest in the MVP project. As a result, the final project scope and total capacity has not yet been determined; however, the voluntary pre-filing process with the FERC began in October 2014. The pipeline, which is subject to FERC approval, is expected to be in-service during the fourth quarter of 2018.

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

Firm storage contracts obligate customers to pay a fixed monthly charge for the firm right to inject, withdraw and store a specified volume of natural gas regardless of the amount of storage capacity actually utilized by the customer. Firm storage customers are generally assessed usage fees on the actual quantities of natural gas injected into or withdrawn from storage. A firm storage customer is billed an additional usage charge on volumes in excess of firm capacity when the level of gas injected or withdrawn exceeds the customer’s maximum daily injection or withdrawal limit.

Under interruptible service contracts, customers pay fees based on their actual utilization of assets for transmission and storage services. Customers that 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 fully utilized or excess capacity that has not been contracted for service exists, the system can allocate such capacity to interruptible services. The Partnership also provides natural gas “park and loan” services to assist customers in managing gas surpluses or deficits.

Including AVC and expected future capacity from expansion projects that are not yet fully constructed but for which the Partnership has entered into firm transmission and storage agreements, approximately 3.7 Bcf per day of transmission capacity and 31.9 Bcf of storage capacity, respectively, were subscribed under firm transmission and storage contracts as of December 31, 2014. These contracts have a weighted average remaining contract life, based on total projected contracted revenues, of approximately 16 years for transmission contracts and 19 years for storage contracts.

As of December 31, 2014, approximately 87% of the Partnership's contracted transmission firm capacity was subscribed by customers under negotiated rate agreements under its tariff. The remaining 13% of the Partnership’s contracted transmission firm capacity was subscribed at the recourse rates under its tariff (i.e., the maximum rates an interstate pipeline may charge for its services under its tariff).

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

The Partnership’s gathering system consists of approximately 145 miles of high-pressure gathering lines, which have multiple interconnects with the Partnership’s transmission and storage system, as well as approximately 1,500 miles of FERC-regulated low-pressure gathering lines that have multiple delivery interconnects with the Partnership's transmission and storage system. Gathering revenues represented approximately 47%, 51% and 49% of total revenues for the years ended December 31, 2014, 2013 and 2012, respectively.

During 2015, the Partnership intends to complete additional expansion projects on its gathering system. The Partnership expects capital expenditures of approximately $100 million in 2015 related to expansion in the Jupiter development area that will raise total firm gathering capacity in that area to 775 MMcf per day. The Jupiter expansion is fully subscribed and is expected to be in service by year-end 2015. In addition, the Partnership expects to invest a total of approximately $370 million, of which approximately $65 million is expected to be spent during 2015, related to expansion in the NWV Gathering development area. These expenditures are part of an additional fully subscribed expansion project expected to raise total firm gathering capacity in the NWV Gathering development area to 640 MMcf per day by year-end 2017.

The Partnership has various firm gas gathering agreements which provide for firm reservation fees in certain high pressure development areas. Including expected future capacity from expansion projects that are not yet fully constructed but for which the Partnership had entered into firm gathering agreements, approximately 875 MMcf per day of firm gathering capacity was subscribed under firm gathering contracts as of December 31, 2014. Following the execution of the gas gathering agreements associated with the NWV Gathering Acquisition in the first quarter of 2015, subscribed firm capacity increased to

approximately 1,515 MMcf per day. As of December 31, 2014, firm gathering contracts had a weighted average remaining contract life, based on total projected contracted revenues, of approximately 10 years. After the expansion and other capital projects scheduled to be completed by the end of 2018 have been placed into service, revenue from firm gathering agreements is expected to be approximately $360 million annually.

On the Partnership’s low pressure regulated gathering system, 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 on the regulated system are based on the maximum posted tariff rate and assessed on actual receipts into the gathering system. The Partnership also retains a percentage of wellhead natural gas receipts to recover natural gas used to run its compressor stations and other requirements on all of its gathering systems.

Following the execution of the gas gathering agreements associated with the NWV Gathering Acquisition in the first quarter of 2015, approximately 80% of both transmission and storage and gathering system revenues and revenues in total are derived from firm reservation fees. As a result, the Partnership believes that short or medium term declines in volumes of gas produced, gathered, transported or stored on its systems will not have a significant impact on its results of operations, liquidity,

financial position or ability to pay distributions because these firm reservation fees are paid regardless of volumes supplied to the system by customers. Longer term price declines could have an impact on customer creditworthiness and related ability to pay firm reservation fees under long-term contracts which could impact the Partnership's results of operations, liquidity, financial position or ability to pay distributions.

One of the Partnership’s principal attributes is its relationship with EQT. Headquartered in Pittsburgh, Pennsylvania, in the heart of the Appalachian Basin, EQT is an integrated energy company, with an emphasis on natural gas production, gathering and transmission. EQT conducts its business through two business segments: EQT Production and EQT Midstream. EQT Production is one of the largest natural gas producers in the Appalachian Basin with 10.7 Tcfe of proved natural gas, natural gas liquids and crude oil reserves across 3.4 million gross acres as of December 31, 2014, of which approximately 630,000 gross acres were located in the Marcellus Shale. EQT Midstream provides transmission, storage and gathering services for EQT’s produced gas and to third parties in the Appalachian Basin.

As of December 31, 2014, EQT owned a 2.0% general partner interest in the Partnership, all of the Partnership’s incentive distribution rights and a 34.4% limited partner interest in the Partnership. After giving effect to the March 2015 NWV Gathering Acquisition and equity offering, including the full exercise of the underwriters' option to purchase additional common units, EQT owns a 2.0% general partner interest in the Partnership, all of the Partnership's incentive distribution rights and a 30.2% limited partner interest in the Partnership. Because of its ownership in the Partnership, EQT is positioned to directly benefit from committing additional natural gas volumes to the Partnership’s systems and from facilitating accretive acquisitions and organic growth opportunities. However, EQT is under no obligation to make acquisition opportunities available to the Partnership, is not restricted from competing with the Partnership and may acquire, construct or dispose of midstream assets without any obligation to offer the Partnership the opportunity to purchase or construct these assets.

While the Partnership’s relationship with EQT may provide significant benefits, it may also become a source of potential conflicts. For example, EQT is not restricted from competing with the Partnership. In addition, all of the executive officers and a majority of the directors of the Partnership’s general partner also serve as officers and in one case as a director of EQT, and these individuals face conflicts of interest, which include the allocation of their time between the Partnership and EQT. For a description of the Partnership’s relationships with EQT, please read Item 13, “Certain Relationships and Related Transactions, and Director Independence” included in the Partnership's Form 10-K for the year ended December 31, 2014 previously filed with the SEC.

Reclassifying Equitable Gas Company revenues as discussed below to third party revenues in 2013 and 2012, EQT accounted for approximately 69%, 77% and 71% of the Partnership’s total revenues for the years ended December 31, 2014, 2013 and 2012, respectively. In December 2013, EQT completed the sale of its LDC subsidiary, Equitable Gas Company, LLC (Equitable Gas Company) to PNG Companies LLC, the parent of Peoples Natural Gas Company, LLC. As a result, revenues from Equitable Gas Company were reported as third party revenues in 2014. For the years ended December 31, 2013 and 2012, Equitable Gas Company accounted for approximately 11% and 16%, respectively, of the Partnership’s total revenues.

The Partnership provides natural gas transmission services for EQT and third parties, predominantly consisting of LDCs, marketers, producers and commercial and industrial users that the Partnership believes to be creditworthy. The Partnership’s transmission system serves not only adjacent markets in Pennsylvania and West Virginia but also provides its customers access to high-demand end-user markets in the Mid-Atlantic and Northeastern United States through 3.3 Bcf per day of delivery interconnect capacity with major interstate pipelines. The Partnership provides storage services to a mix of customers, including marketers and LDCs.

The Partnership’s primary transmission and storage customer is EQT. For the years ended December 31, 2014, 2013 and 2012, EQT and its affiliates, including Equitable Gas Company for the years ended December 31, 2013 and 2012, accounted for approximately 51%, 80% and 81%, respectively, of transmission revenues and 2%, 61% and 68%, respectively, of storage revenues. Additionally, for the year ended December 31, 2014, Peoples Natural Gas Company, LLC accounted for approximately 30% of the Partnership's transmission and storage revenues. Other than EQT, no single customer accounted for more than 10% of total transmission and storage revenue in 2013 or 2012.

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

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

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

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

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

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

The Partnership’s interstate pipeline may also use negotiated rates which could involve rates above or below the recourse rate or rates that are subject to a different rate structure, provided that the affected customers are willing to agree to such rates and that the FERC has approved the negotiated rate agreement. A prerequisite for allowing the negotiated rates is that negotiated rate customers must have had the option to take service under the pipeline’s recourse rates. As of December 31, 2014, approximately 87% of the system’s contracted firm transportation capacity was committed under 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, require the Partnership to seek modification of the agreement or require the Partnership to modify its tariff so that the non-conforming provisions are generally available to all customers.

While the FERC does not generally regulate the rates and terms of service over facilities determined to be performing a natural gas gathering function, it has traditionally regulated rates charged by interstate pipelines for gathering services performed on the pipeline’s own gathering facilities when those gathering services are performed in connection with jurisdictional interstate transportation. The Partnership maintains rates and terms of service in its tariff for unbundled gathering

services performed on its gathering facilities in connection with the transportation service. Just as with rates and terms of service for transmission and storage services, the Partnership’s rates and terms of services for its FERC regulated low pressure gathering system may be challenged by complaint and are subject to prospective change by the FERC. Rate increases and changes to terms and conditions of service the Partnership proposes for its FERC regulated low pressure gathering service may be protested and such increases or changes may ultimately be rejected by the FERC.

The Partnership’s interstate natural gas pipeline system is subject to regulation by PHMSA. PHMSA has established safety requirements pertaining to the design, installation, testing, construction, operation and maintenance of gas pipeline facilities, including requirements that pipeline operators develop a written qualification program for individuals performing covered tasks on pipeline facilities and implement pipeline integrity management programs. These integrity management plans require more frequent inspections and other preventive measures to ensure safe operation of oil and natural gas transportation pipelines in “high consequence areas,” such as high population areas or facilities that are hard to evacuate and areas of daily concentrations of people.

Notwithstanding the investigatory and preventive maintenance costs incurred in the Partnership’s performance of customary pipeline management activities, significant additional expenses may be incurred if anomalous pipeline conditions are discovered or more stringent pipeline safety requirements are implemented. For example, on August 25, 2011, PHMSA published an advance notice of proposed rulemaking in which the agency solicited public comment on a number of changes to the federal natural gas transmission pipeline regulations, including: (i) modifying the definition of high consequence areas; (ii) strengthening integrity management requirements as they apply to existing regulated operators; (iii) strengthening or expanding various non-integrity pipeline management standards relating to such matters as valve spacing, automatic or remotely-controlled valves, corrosion protection and gathering lines; and (iv) adding new regulations to govern the safety of underground natural gas storage facilities including underground storage caverns and injection withdrawal well piping that are not currently regulated under the federal regulations.

In 2012, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was enacted. Among other things, 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. In September 2013, PHMSA released a final rule increasing the civil penalty maximums for pipeline safety violations. The rule increased the maximum penalties from $100,000 to $200,000 per day for each violation and from $1,000,000 to $2,000,000 for a related series of violations. The rule applies safety regulations to certain rural low-stress hazardous liquid pipelines not previously covered by some of its safety regulations. In August 2014, in response to a report to Congress from the U.S. Government Accountability Office, PHMSA stated that it is developing a rulemaking to revise its pipeline safety regulations and is examining the need to adopt safety requirements for gas gathering pipelines that are not currently subject to regulations. PHMSA also published an advisory bulletin providing guidance to natural gas transmission operators of the need to verify records related to the maximum allowable operating pressure for each section of a pipeline system. As required by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, the Partnership verified its records for all applicable pipeline segments and submitted a report to the DOT identifying each pipeline segment for which records were insufficient.

States are generally preempted by federal law in the area of pipeline safety, but state agencies may qualify to assume responsibility for enforcing federal regulations over intrastate pipelines. They may also promulgate additive pipeline safety regulations provided that the state standards are at least as stringent as the federal standards. Although many of our natural gas facilities fall within a class that is not subject to integrity management requirements, we may incur significant costs and liabilities associated with repair, remediation, preventive or mitigation measures associated with our non-exempt pipelines, particularly our gathering pipelines. This estimate does not include the costs, if any, for repair, remediation, preventive or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial. Such costs and liabilities might relate to repair, remediation, preventive or mitigating actions that may be determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down our pipelines during the pendency of such repairs. Additionally, should we fail to comply with DOT regulations, we could be subject to penalties and fines. In addition, we may be required to make additional maintenance capital expenditures in the future for similar regulatory compliance initiatives that are not reflected in our forecasted maintenance capital expenditures.

In addition, the Partnership’s operations and construction activities are subject to state, county and local ordinances that restrict the time, place or manner in which those activities may be conducted so as to reduce or mitigate nuisance-type conditions, such as, for example, excessive levels of dust or noise or increased traffic congestion, requiring the Partnership to take curative actions to reduce or mitigate such conditions. However, the performance of such actions has not had a material adverse effect on the Partnership’s results of operations.

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

The Partnership has implemented programs and policies designed to keep its pipelines and other facilities in compliance with existing environmental laws and regulations and the Partnership does not believe that its compliance with such legal requirements will have a material adverse effect on its business, financial condition, results of operations, liquidity or ability to make distributions. Nonetheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be significantly in excess of the amounts the Partnership currently anticipates. The Partnership tries to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. While the Partnership believes that it is in substantial compliance with existing environmental laws and regulations, there is no assurance that the current conditions will continue in the future.

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

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

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

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

Climate Change. Legislative and regulatory measures to address climate change and greenhouse gas (GHG) emissions are in various phases of discussion or implementation. The EPA regulates GHG emissions from new and modified facilities that are potential major sources of criteria pollutants under the Clean Air Act's Prevention of Significant Deterioration and Title V programs. In addition, on January 14, 2015, the federal government announced its goal to significantly reduce methane emissions from oil and gas sources by 2025. As part of this announcement, the EPA announced that it will issue a proposed rule in the summer of 2015 and a final rule in 2016 setting standards for methane and volatile organic compounds (VOC) emissions from new and modified oil and gas production sources and natural gas processing and transmission sources. In addition, PHMSA stated that it will propose natural gas pipeline safety standards in 2015 that are expected to lower methane emissions.

The U. S. Congress, along with federal and state agencies, have considered measures to reduce the emissions of GHGs. Legislation or regulation that restricts carbon emissions could increase the Partnership’s cost of environmental compliance by requiring the Partnership to install new equipment to reduce emissions from larger facilities and/or purchase emission allowances. Climate change and GHG legislation or regulation could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals with regard to existing and new facilities or impose additional monitoring and reporting requirements. For example, while the EPA has had rules in effect since 2011 that require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas sources in the United States, including among others, onshore processing, transmission and storage facilities, only recently, in December 2014, the EPA proposed changes to this reporting rule that would expand the petroleum and natural gas system sources for which annual GHG emissions reporting is currently required to include, beginning in the 2016 reporting year, certain on shore gathering and boosting systems consisting primarily of gathering pipelines, compressors, and processing equipment used to perform natural gas compression, dehydration and acid gas removal activities. Conversely, legislation or regulation that sets a price on or otherwise restricts carbon emissions could also benefit the Partnership by increasing demand for natural gas because the combustion of natural gas results in substantially fewer carbon emissions per Btu of heat generated than other fossil fuels such as coal. The effect on the Partnership of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.

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

National Environmental Policy Act. The construction of interstate natural gas transportation pipelines pursuant to the NGA requires authorization from the FERC. FERC actions are subject to the National Environmental Policy Act (NEPA). NEPA requires federal agencies, such as the FERC, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will 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 will be subject to the requirements of NEPA. This process has the potential to delay or limit, or increase the cost of, development of midstream infrastructure.

Endangered Species Act. The federal Endangered Species Act (ESA) restricts activities that may adversely affect endangered and threatened species or their habitats. Federal agencies are required to ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. While some of the Partnership’s facilities may be located in areas that are designated as habitats for endangered or threatened species, the Partnership believes that it is in substantial compliance with the ESA. However, the designation of previously unprotected species as being endangered or threatened, or the designation of previously unprotected areas as a critical habitat for such species, could cause the Partnership to incur additional costs or become subject to operating restrictions in areas where the species are known to exist.

Employee Health and Safety. The Partnership is subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (OSHA) and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community “right-to-know” regulations and comparable state laws and regulations require that information be maintained concerning hazardous materials used or produced in the Partnership’s operations and that this information be provided to employees, state and local government authorities and citizens. The Partnership believes that it is in substantial compliance with all applicable laws and regulations relating to worker health and safety.

The Partnership’s real property falls into two categories: (i) parcels that it owns in fee and (ii) parcels in which its interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for the Partnership’s operations. Portions of the land on which the Partnership’s pipelines and facilities are located are owned by the Partnership in fee title, and it believes that it has satisfactory title to these lands. The remainder of the land on which the Partnership’s pipelines and facilities are located are held by the Partnership pursuant to surface leases or easements between the Partnership, as lessee or grantee, and the respective fee owners of the lands, as lessors or grantors. The Partnership has held, leased or owned many of these lands for many years without any material challenge known to the Partnership relating to the title to the land upon which the assets are located, and it is believed that the Partnership has satisfactory leasehold estates, easement interests or fee ownership to such lands. The Partnership believes that it has satisfactory title to all of its material leases, easements, rights-of-way, permits and licenses, and the Partnership has no knowledge of any material challenge to its title to such assets or their underlying fee title.

However, there are certain lands within the Partnership’s storage pools as to which it does not currently have real property rights. The Partnership has identified the lands as to which it believes it must obtain such rights and is in the midst of a program to acquire such rights. Since the beginning of this program in 2009 through December 31, 2014, the Partnership has

successfully acquired such rights for approximately 28,373 acres out of a total 52,036 acres, and the Partnership expects to acquire the remainder within the next three years. In accordance with the Partnership’s FERC certificate, the geological formations within which its permitted storage facilities are located cannot be used by third parties in any way that would detrimentally affect its storage operations and the Partnership has the power of eminent domain with respect to the acquisition of necessary real property rights to use such storage facilities. The Partnership believes the cost to acquire the remaining rights will be approximately $6 million over the next three years.

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

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

The Partnership generally shares insurance coverage with EQT, for which it reimburses EQT pursuant to the terms of the omnibus agreement. The Partnership’s insurance program includes general liability insurance, auto liability insurance, workers’ compensation insurance and property insurance. In addition, the Partnership has procured separate general liability and directors and officers liability policies. All insurance coverage is in amounts which management believes are reasonable and appropriate.

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

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



System	Approximate Number of Miles	Approximate Number of Receipt Points	Approximate Compression (Horsepower)
Transmission and storage	700	80	69,000
AVC (leased transmission and storage)	200	60	13,000
Gathering	1,645	2,400	98,000



	Revenue Composition %
	Firm Contracts
	Capacity Reservation	Usage	Interruptible Contracts
	Charges	Charges	Usage Fees	Total
Transmission and Storage	42%	9%	2%	53%
Gathering	8%	10%	29%	47%


•	Jefferson Compressor Station Expansion Project. The Jefferson compressor station expansion project added approximately 550 MMcf per day of incremental capacity to the Partnership's transmission system at a cost of approximately $30 million. The expansion was placed into service in September 2014.


•	Antero Project. The Partnership expects to invest approximately $25 million to complete a second Antero project, which will add 100 MMcf per day of transmission capacity. The project is expected to be in service by mid-2015.


•	EQT has retained certain midstream assets. The Partnership expects to have the opportunity to purchase additional midstream assets from EQT in the future, although EQT is under no obligation to make the opportunities available to the Partnership. The opportunities are expected to include:


◦	Retained transmission assets. The AVC facilities as previously described.


◦	Retained gathering assets. The retained gathering assets as previously described.


•	requiring the acquisition of various permits to conduct regulated activities;


•	requiring the installation of pollution-control equipment or otherwise restricting the way the Partnership can handle or dispose of its wastes;


•	limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species; and


•	requiring investigatory and remedial actions to mitigate or eliminate pollution conditions caused by the Partnership’s operations or attributable to former operations.



	For the year ended December 31,
	2014		2013		2012
Transmission and storage operating revenues	53	%	49	%	51	%
Gathering operating revenues	47	%	51	%	49	%